# Standards of Performance for Petroleum Refineries Background Information for Final Amendments

Summary of Public Comments and Responses (Revised)ii This page intentionally left blank.iii Standards of Performance for
Petroleum Refineries Background Information for Final Amendments

Summary of Public Comments and Responses (Revised)

Contract No. EP-D-11-084 Work Assignment No. 0-11

Project No. 06/09 (438)

U.S. Environmental Protection Agency Office of Air Quality Planning and Standards Sector Policies and Programs Division Research Triangle Park, North Carolina 27711

December 2011 (Revised August 2012)iv Disclaimer

This report has been reviewed by the Sector Polici es and Programs Division of the Office of Air Quality Planning and Standards, EPA, and approv ed for publication. Mention of trade names or commercial products is not intended to constitu te endorsement or recommendation for use.v TABLE OF CONTENTS

1.0 Introduction .................................................................................................................. ...........1 2.0 Applicability ................................................................................................................. ..........4 2.1 Applicability of Subpart Ja ............................................................................................4 2.1.1 Gasification ........................................................................................................4 2.1.2 Crude Oil from Oil Shale and Tar Sands ...........................................................8 2.1.3 Flares ................................................................................................................10 2.1.4 Other Units .......................................................................................................12 2.2 Applicability Date ........................................................................................................13 2.3 Flare Modification .......................................................................................................19 2.4 Notification Schedule ...................................................................................................33 2.5 Overlap with and Effect on Other Subparts .................................................................34 2.6 Equivalence with State and Local Rules ......................................................................36 3.0 Definitions.................................................................................................................... .........41 3.1 Air Preheat ................................................................................................................... 41 3.2 Co-Fired Process Heater ..............................................................................................41 3.3 Corrective Action Analysis ..........................................................................................42 3.4 Delayed Coking Unit ...................................................................................................43 3.5 Flare ......................................................................................................................... ....44 3.6 Fuel Gas ...................................................................................................................... .46 3.7 Fuel Gas Combustion Device ......................................................................................49 3.8 Natural Draft and Forced Draft Process Heaters .........................................................50 3.9 Process Upset Gas ........................................................................................................52 3.10 Refinery Process Unit ..................................................................................................54 3.11 Sulfur Recovery Plant ..................................................................................................57 4.0 Fuel Gas Combustion Devices and Flares ............................................................................58 4.1 Emissions Limits ..........................................................................................................58 4.1.1 Long-Term H 2 S Concentration Limit for Fuel Gas Combusted in Flares .......58 4.1.2 Alternative Compliance Options ......................................................................61 4.2 Elimination of Routine Flaring ....................................................................................62 4.3 Flare Flow Rate Limit ..................................................................................................66 4.4 Other Standards for Flares ...........................................................................................66 4.4.1 General Comments on Othe r Flare Standards .................................................66 4.4.2 Flare Management Plan Requirements ............................................................68 4.4.3 Root Cause Analysis and Corrective Action Analysis ....................................70 4.5 Monitoring Fuel Gas Combustion Devices..................................................................78 4.6 Flow Monitoring for Flares ..........................................................................................78 4.7 Sulfur Monitoring for Flares ........................................................................................81 4.8 Compliance Schedule ...................................................................................................88 4.9 Startup, Shutdown and Malfunction ............................................................................93 5.0 Process Heaters ............................................................................................................... ....101 5.1 Emissions Limits ........................................................................................................101 5.1.1 Equivalence of Emissions Limit Units ..........................................................101 5.1.2 Limits for New, Modified and Reconstructed Forced Draft Process Heaters ...........................................................................................................102vi 5.1.3 Turndown .......................................................................................................104 5.1.4 Site-Specific Emissions Limit Clarifications .................................................108 5.1.5 Co-Fired Process Heaters ...............................................................................111 5.2 Monitoring of Process Heaters ...................................................................................114 5.3 Other Clarifications ....................................................................................................118 6.0 Compliance Requirements and General Moni toring, Recordkeeping and Reporting ........119 6.1 Rolling Averages .......................................................................................................119 6.2 Excess Emissions .......................................................................................................120 6.3 Monitoring Methods ..................................................................................................121 6.4 Reporting Requirements ............................................................................................121 6.5 Impacts on Small Refineries ......................................................................................1211 

## 1.0 INTRODUCTION

On June 24, 2008 (73 FR 35838), the U.S. Environmental Protection Agency (EPA) issued: (1) final amendments to the existing refineries new sour ce performance standards (NSPS) in 40 CFR part 60, subpart J (“subpart J”); and (2) new petroleum refinery NSPS in 40 CFR part 60, subpart Ja (“subpart Ja”). On September 26, 2008 (73 FR 55751), the effective date of the NSPS in 40 CFR part 60, subpart Ja, the EPA published a notice granting the request for reconsideration and a 90-day st ay of the following provisions of 40 CFR part 60, subpart Ja: (1) the flare modification provision; (2) the defi nition of “flare”; (3) the fuel gas combustion device sulfur limits; (4) the flow limit for flare systems; (5) the total reduced sulfur (TRS) and flow monitoring requirements for fl ares; and (6) the nitrogen oxides (NO X ) emissions limit for process heaters. On December 22, 2008, the EPA pr oposed to extend the original 90-day stay until the agency has reached a final decision on all of the issues for which reconsideration was granted (73 FR 78260, 73 FR 78546, 73 FR 78549). Also on December 22, 2008 (73 FR 78522), the EPA proposed amendments to the NSPS in 40 CFR part 60, subparts J and Ja to address the reconsidered issues as well as technical corrections. The proposal provided a 45-day comment period, ending February 5, 2009. The EPA received 20 comments on the proposed amendments from refiners, industry trade associations and consultants, state environmental departments, environmental groups and other interested parties during the comment period. Fo llowing the close of the public comment period,
two additional comment letters were received. Al l 22 of these comments have been placed in the docket for this rulemaking (Docket No. EPA- HQ-OAR-2007-0011). Table 1 lists the names and affiliation of each comment and the assigned docket number.2 Table 1. List of Commenters on the Proposed Amendments to 40 CFR part 60, subpart Ja

Docket Item No. EPA-HQ-OAR-2007- 0011- Commenter and Affiliation 0295 B. Lane, Environmental Consultant 0296 R.A. Cade, Marathon Petroleum Company LLC 0297 M. Resh, Linde North America, Inc. 0298 D. Copeland, P.E., Praxair Inc. 0299 B. Lane, Environmental Consultant

0300 C.M. Campbell, RTP Environmental Associates Inc., on behalf of Hyperion Refining, LLC 0301 C. Feerick, ExxonMobil Company 0302 S.L. Sherk, American Refining Group, Inc 0303 M.E. Pugh, Flint Hills Resources, LP (FHR) 0304 R.W. Hermanson, BP America, Inc. 0305 D.F. Hunter, ConocoPhillips Company 0306 L.B. Barry, Chevron Corporation 0307 (Attachments

posted as 0317) J.S. Peterson, Environmental Integrity Pr oject (EIP), also on behalf of Natural Resources Defense Council (NRDC) and Sierra Club 0308 C.S. Colman, HESS Corporation, on behalf of HOVENSA LLC 0309 T.K. Metrose, Tesoro Corporation 0310 K.A. Saffell, Valero Energy Corporation

0311 R. Chittim, American Petroleum Institute (API), National Petrochemical and Refiners Association (NPRA) and Western States Petroleum Association (WSPA) 0312 A. Pasquale, Thermo Fisher Scientific 0313 B.F. Bateman, Bay Area Air Quality Management District (BAAQMD) 0314 H.A. Green, CITGO Petroleum Corporation 0315 R. Chittim, API, NPRA and WSPA 0316 B.F. Bateman, BAAQMD

Several commenters, in addition to providing specific comments, also expressed support for comments provided by other commenters (generally, individua l companies indicating support for comments submitted by their trade orga nization). Specifically, Commenters 0295, 0301, 0302, 0304, 0305, 0306, 0308 and 0310 supported comments submitted by Commenter 0311 (API, NPRA and WSPA). By convention, the co mmenter numbers presented in the comment3 summaries throughout the rest of this document indicate the commenter(s) that specifically provided those comments and not the commenters who supported that comment. All of the comments and the EPA’s responses to the comments are summarized in this document or the preamble to the final amendments. The EPA’s responses to these comments form part of the basis for the EPA’s final decisions.4 

## 2.0 APPLICABILITY

2.1 Applicability of Subpart Ja 2.1.1 Gasification

Comment : Commenter 0300 stated that the EP A should exempt entrained flow gasification processes from subpart Ja. The comm enter cited a recent applicability determination provided by the South Dakota Department of En vironmental Resources that indicated syngas produced from coke gasification was not fuel gas subject to subpart Ja and questioned how the gasification process would be cons idered a refinery process unit a nd the associated flare a fuel gas combustion device under the proposed ame ndments. The commenter stated that the best system of emission reduction (BSER) 1 determination did not addre ss entrained flow gasification processes or consider that gas with a low energy content (also referred to as low British thermal unit [Btu] content) is not suitable for recovery as fuel gas. The commenter noted that both 40 CFR part 60, subpart Da and s ubpart Ja would apply to thei r gasification facility, causing redundant requirements, but the commenter’s only specific objection was to the requirement to conduct a root cause analysis ( RCA) for planned startup and shut down events when there is no outlet for the low Btu gas other than the flare. The commenter did not express concern with the fuel gas sulfur limits because, according to the commenter, the syngas is desulfurized prior to combustion under normal operations. Commenters 0310 and 0311 objected to the proposed amendments to the definition of “fuel gas” and “refinery proce ss unit” to include coke gasifi cation. The commenters cited a Delaware court case that an adjacent coke gasifi cation plant was not part of the refinery, largely because coke gasification was not an integral refinery process operation, according to the commenters. Furthermore, the commenters contende d that coke gasificati on was not considered in the original NSPS (40 CFR part 60, subpart J) because the technology was not developed until

1 The level of control prescribed by CAA section 111 hi storically 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. Therefore, while commenters referred to “BDT” in their comment letters, we use “BSER” throughout this document.5 the mid-1980s, and the subpart Ja rulemaking docket contains no BSER analysis specific to coke gasification. As such, the commente rs asserted that the revision is more than a “clarification,” the rulemaking record failed to satisfy applicable procedural standards for establishing BSER and the EPA failed to afford interested parties with a meaningful opportunity to comment. According to Commenters 0310 and 0311, the inclusion of coke gasification under subpart Ja places unreasonable operational limitations and costs on these sources.
Commenter 0310 noted that much of the sulfur from the coke gasifier is in the form of carbonyl sulfide (COS) and provided a cost for systems to meet a TR S limit of 50 parts per million by volume (ppmv) that would comply with the 60 ppmv hydrogen sulfide (H 2 S) concentration limit determined daily on a 365 su ccessive calendar day rolling average basis (hereafter referred to as the long-term 60 ppmv H 2 S concentration limit). The commenter stated that the control system is not BSER because th e cost effectiveness of the system is roughly $20,000/ton of sulfur dioxide (SO 2 ) reduced. The commenter also contended that flexicoking units are “materially different” than coke gasi fiers by focusing on the upstream coking processes associated with a flexicoking unit rather the pr oduction and treatment of low energy gas from the flexicoking gasifier. The comment er noted that FLEXSORB amine treatment units achieve <10 ppmv H 2 S on flexicoking gas but suggested that this performance is not applicable or representative of the performance achievable fr om coke gasification units because flexicoking gasifiers use air while coke gasification units use oxygen (so the flexicoking gas is diluted with nitrogen). According to Commenters 0310 and 0311, the proposed rule would discourage use of gasification technology, contrary to established national s ecurity objectives. Response : The key issues here are: (1) whether the clarifications to the definition of “fuel gas” and “refinery process units” altered the historic applicability of the refinery fuel gas standards for coke gasifiers; a nd (2) whether low-Btu gas produced from coke gasification units should be subject to the fuel gas standards. With respect to the inclusion of “other gasifiers” in the definition of fuel gas, we reaffirm our position that this is a clarification rather than a new requirement. We note that the definition of “f uel gas” at 40 CFR 60.101a is “any gas which is generated at a petroleum refinery and which is combusted,” and th e amendments do not alter that language. The definition does not re quire the gas to be generated by a “refinery process unit” but more broadly applies to any gas generated at a petroleum refinery. We also note that the definition of “petroleum refine ry” at 40 CFR 60.101a is “any fa cility engaged in producing6 gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, as phalt (bitumen) or other products through distillation of petroleum or through redistilla tion, cracking, or reforming of unfinished petroleum derivatives.” The pr imary subject in this definition is “ any facility .” It is not “the group of refinery process units” orsimilarly limiting phrases. The definition of petroleum refinery includes the entire facility. If a coke gasifier is locate d at a facility “engaged in producing gasoline, kerosene, distillate fuel oils , residual fuel oils, lubricants, asphalt (bitumen) or other products thr ough distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives ,” then the coke gasifier is located at a petroleum refinery. As such, the gas produced from the coke gasification process would be considered “fuel gas” regardless of whether the ga sification process itself is considered a refinery process unit (see next paragraph fo r discussion on this issue). C onsequently, prior to the newly proposed clarification to the defini tion of “fuel gas” in subpart Ja, it appears that a flare or other unit that combusts gas for a coke gasifier would be an affected facility under subpart J or Ja, provided that the gasifier is located at a pe troleum refinery. Based on the background provided by Commenter 0300 (“the planned refinery is a 400,000 barrel per day, highly complex, full conversion refinery that will produce clean, green transportation fuels such as ultra-low sulfur gasoline and ultra-low sulfur diesel”), the coke gasi fier is located at a pe troleum refinery and the gas generated by the gasifier meets the defini tion of “fuel gas” regardless of the proposed clarifications to subpart Ja. Consequently, we find that the coke gasification unit described by Commenter 0300 is located at a petroleum refiner y, the syngas produced by the unit is “fuel gas” and the flare combusting the fuel gas is an aff ected source subject to s ubpart Ja. (See letter to Preston Phillips, Vice President, Hyperion Re fining LLC, from Cynthia J. Reynolds, Director, Technical Enforcement Program, U.S. EPA, Region 8, dated November 20, 2008 (Applicability Determination Control Number: 0800090) for furthe r detail on this determination.) In addition,
we note that in Star Enterprise v. EPA , 235 F.3d 139, 151 (3 rd Cir. 2001), the decision referenced by Commenters 0310 and 0311, the reason the Court held that the coke gasification plant was not part of the refinery was because of the physic al location of the coke gasification plant, i.e. , it was located next door to the refinery rather than “in” the refinery (“[I]n dete rmining what facilities
are ‘affected facilities’ that can be regulated under Subpart J, and, specifically, in determining
what facilities are ‘in petroleum refineries,’ the touchstone of such a determination is the physical location of the facilities in question.”). The Court did not address the factual situation in7 which a coke gasifier and turbines are physic ally located “in” th e petroleum refinery. See 40 CFR 60.100a(a); Star Enterprise , 235 F.3d at 151-152. With respect to the proposed clarification of “refinery process unit,” the original
definition read as follows: “ Refinery process unit means any segment of the petroleum refinery in which a specific processing operation is cond ucted.” As stated previously, the petroleum refinery includes the entire faci lity. Thus, to be considered a refinery process unit, only two criteria are needed: (1) the unit mu st be located at a petroleum refi nery; and (2) the unit must be used to conduct “a specific processing operati on.” The definition does not directly limit the scope of “processing operations.” That is, the definition of refinery process unit does not limit process operations to distillati on, re-distillation, cracking or re forming, and it does not limit it to only those processes used to produce gasoline, kero sene, fuel oils, etc. As coke gasification is easily construed as a “specific processing operation,” this unit meets the definition of a refinery process unit if the unit is locat ed at a petroleum refinery. C onsequently, we considered the proposed inclusion of coke gasification (as we ll as product loading, sulfur recovery and wastewater treatment) as an example of a refinery process unit to be a clar ification of the existing definition rather than an expansion of the de finition. (See Section 3.10 for additional discussion on the definition of “refinery process unit.”) The more overarching issue is whether or not low-Btu gas produced from coke gasification units should be subj ect to the fuel gas standards. The commenters suggest that a separate analysis of the BSER is needed for c oke gasification units and that the requirements of subpart Ja are not cost effective for coke gasi fiers. We find that both the long-term 60 ppmv H 2 S concentration limit and the 162 ppmv H 2 S concentration limit determined hourly on a 3-hour rolling average basis (hereafter referr ed to as the short-term 162 ppmv H 2 S concentration limit)
are achievable based on the information provided by Commenter 0300, as well as the performance of other integrated gasification co mbined cycle (IGCC) units. Gasification systems have received support from the EPA and the U.S. Department of Energy (DOE) largely because they are considered “clean technologies” because su lfur can be efficiently removed prior to final combustion. Commenter 0300 only expressed concer n regarding the flare flow RCA, simply stating that the syngas is desulfurized before being flared. Additionally, while we acknowledge that higher H 2 S concentrations can be expected from a gasification system using pure oxygen rather than air, the fact that the FLEXSO RB amine treatment units achieves <10 ppmv H 2 S on8 flexicoking gas appears to support the case that, correcting for the diluting nitrogen, oxygen-fired gasification systems should be able to achieve H 2 S concentrations below 60 ppmv, and this information was included in the rulemaking record. Although Commenter 0310 provided cost estimates to support their claim that the longterm 60 ppmv H 2 S concentration limit and the short-term 162 ppmv H 2 S concentration limit in subpart Ja are not cost effective for gasificati on, the commenter focused on COS removal rather
than on H 2 S removal and, as such, mischaracterized the subpart Ja requirements. The limits on sulfur content of fuel gas are based on the H 2 S concentration of the fuel gas. While we evaluated limiting the concentration of othe r reduced sulfur compounds in fu el gas when we originally proposed subpart Ja, we did not finalize those standards as BSER due to the high costs of the technologies needed to reduce the total sulfur co ntent of the fuel gas. Although we encourage the
use of these COS removal technol ogies, we fail to see how the subpart Ja requirements mandate them. The commenter provided no evidence that amine scrubbing cannot be used to meet the
H 2 S concentration limits. Based on our analysis of the costs for amine scrubbing systems already in the docket, we conclude that amine scrubbing of the syngas from coke gasification to meet the long-term 60 ppmv H 2 S concentration limit and the short-term 162 ppmv H 2 S concentration limit
is achievable and cost effectiv e and therefore BSER. In additi on, this information supports our decision to finalize the proposed clarification that fuel gas includes “gases from flexicoking unit gasifiers and other gasifiers .” Regarding flares associated with coke gasifi cation units, we note that as described in more detail in Section 4.4.3, we agree that a RCA is unnecessary for planned startups and shutdowns that are already subject to and fo llowing minimization requirements of the flare management plan (FMP) under 40 CFR 60.103a(a)(5). Eliminating the RCA requirement for planned startups and shutdowns of units followi ng their FMP appears to adequately address Commenter 0300’s primary concern.


### 2.1.2 Crude Oil from Oil Shale and Tar Sands

Comment : Commenter 0307 stated that the EPA s hould regulate faci lities that only produce crude oil from oil shale and tar sands. The commenter acknowledged that these facilities do not appear to fall within the regulatory defi nitions for “petroleum refinery” and “refinery process unit,” but it is important for the EPA to set strict emissions limits and monitoring9 requirements to regulate emissions from these f acilities. The commenter noted that extraction of oil from tar sands and oil shale are energy intens ive processes, resulting in nearly three times more greenhouse gas emissions than extraction of conventional crude oil. 2 The commenter also
noted that oil shale extraction releases emissions of SO 2 and other sulfur compounds, particulate matter (PM), carbon monoxide (CO), carbon dioxide (CO 2 ), ozone (O 3 ), NO X , lead, silica, metals, ammonia (NH 3 ), trace organics and trace elements. 3 Commenter 0305 supported the change to the definition of “petroleum refinery” to exclude oil shale and tar sands-derived crude but requested that the definition sp ecifically exclude oil production as well, either by referring to
Standard Industrial Classificati on (SIC) 2911 or adding, “nor is th e extraction or production of
crude oil” to the end of the definition. Response : The definition of “petroleum refine ry” does not include, and could not be reasonably construed to include, conventional oi l production facilities. Wh ile we also do not believe oil shale and tar sand processing faciliti es fall within the regulatory definitions for “petroleum refinery,” the presence of a distillati on or separation unit at these oil shale and tar sands processing facilities led to ambiguities, which is why the cl arification was included in the definition. It may be reasonable to apply certain subpart Ja standards, such as FMP, to these types of facilities, but we have not completed a BSER analysis specific to these processes, especially when they are isolated from a refine ry. As in the previous discussion regarding coke gasification, we do consider oil shale and tar sand-processing units that are co-located at a petroleum refinery facility to be part of the petroleum refinery and subject to the FMP, RCA and fuel gas and process heater emi ssions standards. However, more information is needed on the operations and emissions from these oil production facilities. We are continuing to look at these processes to determine if regul ation of these emission source s is needed. We do note that upgrading units that employ coking units to proce ss tar sands into a synthetic crude oil do not meet the exclusion from the definition of a petr oleum refinery because these facilities do more than simply remove diluent from the heavy oil th at was added to effect extraction or to improve
flow characteristics for pipeline transport.

2 Wakefield, Ben, and Matt Price, Environmental Integrity Project. Tar Sands: Feeding U.S. Refinery Expansions with Dirty Fuel. June 2008. 3 Bordetsky, Ann, et al., Natural Res. Def. Council et al. Driving it Home: Choosing the Right Path for Fueling North America’s Transportation Future. June 2007. Available at http://www.nrdc.org/energy/dri vingithome/drivingithome.pdf

.10 

### 2.1.3 Flares

Comment : Commenters 0305 and 0311 objected to th e reference to the expanded subpart
Ja definition of “flare” in s ubpart J and stated that it expand s the applicability of subpart J retroactively. According to Comm enter 0311, since subpart J does not specifically define “flare,” the cross-reference to the subpart Ja definition could be construed as the definition that should have been applied histor ically under subpart J. Response : As stated previously, we do not cons ider the reference in subpart J to the definition of flare in subpart Ja as changing the de finition of flare under s ubpart J, regardless of there being no formal definition included in that subpart. After again reviewing the available information, we maintain that the cross-referenc e in subpart J to the definition of “flare” in subpart Ja only changes the applicability date for flares; however, to avoid confusion, we have removed the specific reference to 40 CFR 60.101a (the subpart Ja definition of “flare”) from 40 CFR 60.100(b) of subpart J.
Comment : Commenter 0311 stated that temporary flar es (those placed in service for less than 6 months) should be excluded from subpart Ja . These temporary flares are needed for flare maintenance as well as for tank cleanings or sim ilar activities in remote areas of the refinery.
Commenter 0315 clarified that te mporary flares might be need ed to handle emergency flows while the main flare is off-line for purposes of in stalling equipment needed for that main flare to comply with subpart Ja. According to the comme nter, the EPA should encourage maintenance of existing flares, but these activities would be discour aged if the temporary flares were subject to the rule. Also, the commenter stated that the EPA did not consider th e costs of subjecting temporary flares to subpart Ja. Response : With respect to flare maintenance, if the flare being maintained is already subject to subpart Ja, it appears that the temporary flare shoul d be able to comply with subpart Ja. If the temporary flare is considered a “new” flare, then routine maintenance of a flare not currently subject to subpart Ja would effectivel y trigger the rule. We can see that this could create an unnecessary barrier to properly maintaining the flare. Gi ven the importance of flares in the safe operation of the facility and in the destru ction of flammable gases in the case of an upset or malfunction, we agree that a temporary fl are installed for the purposes of conducting maintenance on an existing flare must meet the app licable limits of the flare that it is temporarily replacing and does not, in itself, tr igger applicability to subpart Ja.11 For tank cleaning operations, we believe that the gases generated can be considered process upset gases (produced as a result of star tup or shutdown). Thus, the rule specifically
allows the use of a flare to combust th ese gases without subjecting them to H 2 S concentration requirements for fuel gas. As such, for tank cl eaning operations, these flares would only be subject to RCA and FMP requirements. As disc ussed in Section 4.4.3, we have modified the requirements in 40 CFR 60.103a(d)(3) to exclude RCA for planned startups and shutdowns that follow the flare minimization procedures in 40 CFR 60.103a(a)(5). We have also modified the text in 40 CFR 60.103a(a)(5) regarding flare minimiza tion to clarify that th e provisions apply to “planned startup and shutdown of the refinery process units and ancillary equipmentthat are connected to the affected flare.” We interpret “a ncillary equipment” to include storage vessels. After considering the options, we determined that including this phrase would best clarify our intent. Provided that the refinery owner or ope rator prepares FMP for tank cleaning operations and follows those plans, then the temporary flar e would be compliant withthe requirements of subpart Ja. Consequently, the question become s whether preparing a FMP is necessary and appropriate ( i.e. , BSER) for storage vessel cleaning operation s. The additional cost is minimal, as one flare management protocol can cover multiple storage vessels. While adequate purging of the storage vessels is necessa ry, protocols to minimize unnece ssary purges to the flare are expected to reduce both SO 2 and NO X emissions and minimize auxiliary natural gas use (needed
to maintain Btu content of the high nitrogen content purge gas) . As such, we find that it is reasonable to require temporary flares used for pl anned startup and shutdown of process units to comply with subpart Ja by preparing and followi ng a FMP. Consequentl y, we are not providing a general exclusion for temporary flares. While ther e may be a myriad of reasons why a temporary flare may be used, given the examples provided by the commenter, we find that only the flares installed for routine maintenance of an existing flare warrants an exclusion from the applicability of subpart Ja.
Comment : Commenter 0296 stated that the EPA ignor ed hydrogen flares in their analysis
and stated that no volatile or ganic compound (VOC) emissions o ccur as a result of flaring hydrogen. Response : While evaluating the impacts of the rule, we found that reducing flaring, whether it is a hydrogen flare or hydrocarbon flare, reduces NO X emissions. Hydrogen typically has value to the refinery ( e.g. , used in hydrotreating and hydr ocracking units), and if the12 hydrogen is nearly pure, recovery and use of this stream has environmental benefits. If the hydrogen stream is not pure, then flaring reducti ons can also lead to emission reductions of SO 2 and VOC. As such, the final requirements for flar es do not specifically exclude hydrogen flares.



### 2.1.4 Other Units

Comment : Commenter 0311 stated that fluid ca talytic cracking unit (FCCU) startup heaters should be excluded from the process heat er definition. These in-line heaters are used for
100 to 125 hours to heat air that then heats the catalyst and cat alyst vessel during FCCU startup. The commenter believes these are not process heater s as they do not “transfe r heat indirectly to process stream materials” and requested that the EPA clarify the point by specifically excluding such heaters from the process heater definition. Response : Based on the limited description of th e startup FCCU heater provided by the commenter, it does appear that this type of unit do es not meet the definition of process heater and would not be subject to the NO X emissions limits. Additional in formation obtained on an FCCU
heater at the ConocoPhi llips Trainer Refinery 4 indicates that for at l east one of these types of units, there is no process feed during the FCCU st artup process, so there are no “process stream materials” to receive any heat . However, with respect to SO 2 limits, if these in-line heaters use fuel gas to heat the air, they are unequivocally fuel gas combustion devices and would have to
meet either the SO 2 emissions limits or the H 2 S concentration limits. We are not making any changes to the final rule to addres s these types of units. The owner or operator should use the definitions of “process heater” and “fuel gas combustion
device” in 40 CFR 60.101a to determine whether th e unit is an affected source and what actions are needed to meet the requirements of subpart Ja. If there is any question about whether a specific unit meets the definition of “process heat er” in subpart Ja, the owner or operator should contact their permitting authority or the EPA for assistance.
Comment : Commenter 0299 requested clarification as to whether the gas generated when degassing and cleaning a tank is cons idered fuel gas if it is combus ted in an internal combustion engine or thermal oxidizer. The commenter r ecommended that subparts J and Ja not apply to these temporary controls.

4 Wallwork, James F. ConocoPhillips Trainer Refinery Additional Co mments on Proposed Plan Approval 23- 0003P . Letter to Sachin Shankar, P.E., Pennsylvania Department of Environmental Protection. October 15, 2009.13 Response : Based on the current definition of “fuel gas” in subpart J and Ja, these gases would be considered fuel gas and the internal combustion engine or ther mal oxidizer would be a fuel gas combustion device. However, we believe that these gases can be considered process upset gases (produced as a result of startup or shutdown). Thus, the rule specifically allows the use of a flare to combust these gases, but the us e of an internal combustion engine or thermal oxidizer would appear to be pr ohibited without monitoring the H 2 S concentration of the fuel gas and possibly treating the fuel gas to reduce the H 2 S concentration. The different treatment of these control systems is difficult to justify. We agr ee that it is preferable that these tank cleaning
emissions be combusted rather than released di rectly to the atmosphere. We also find that internal combustion engines would provide a comp arable level of contro l as a flare with the added advantage of producing useful work, whic h can further reduce emissions elsewhere in the refinery by reducing energy consumption de mand. A thermal oxidizer, while providing a comparable level of control, has the disadvantag e that it would require significant excess fuel to maintain proper temperature in the incinerator, so we find that the thermal oxidizer is a less advantageous control option. Finall y, we agree that, for most tanks, based on distance to a fuel gas line and the frequency of degassing and cleaning (typically once every 5 to 10 years), it would not be cost effective to have to capture an d treat the relatively small quantities of gas that are produced infrequently due to tank degassi ng and cleaning. As such, we have added a provision to 40 CFR 60.102a(g)(1)( iii) to specifically exem pt “combustion in a portable generator of fuel gas released as a result of tank degassing and/or cleaning.”



### 2.2 Applicability Date
Comment : Commenters 0296, 0306, 0310, 0311 and 0314 s uggested that December 22, 2008 (the proposal date of the ame ndments to subpart Ja), should be the applicability date for the
flare. The commenters stated that the December 22, 2008, proposal date is the date that industry was provided adequate notice of the new re quirements. Commenters 0310 and 0311 further
asserted that the EPA has the discretion and au thority to extend the applicability date to December 22, 2008. Commenter 0306 and 0311 stated that the June 24, 2008, trigger date for flares is inappropriate because the term “m odification” was altered and would result in retroactive application of the rule. Commenter 0310 also stated that the June 24, 2008, trigger
date for flares would be inc onsistent with and interfere with consent decree obligations.14 Commenter 0314 stated that setting an applicability date before the date the regulations were first published is “an arbitrary and capricious Agency action.” Commenters 0296, 0311 and 0314 also suggested that the Decemb er 22, 2008, proposal date should be the applicability date for pro cess heater provisions. The commenters stated that the original proposal date is inappropriate because the final standards were more stringent than those originally proposed on May 14, 2007. Comm enter 0296 noted that the June 24, 2008, final
rule notice included NO X limits of 40 ppmv but suggested that December 22, 2008, is the proper applicability date, as the NO X provisions in the final rule were stayed. Commenters 0311 and 0314 suggested that the December 22, 2008, proposal date is appropriate because the proposed standards are fundamentally different than the promulgated standards ( e.g. , establishment of different classes of process heaters). Of particular concern for Commenters 0296 a nd 0314 is that they began construction on a new process heater after the original proposal date that was designed and permitted to meet 50 ppmv NO X , as they expected the standard to be 80 ppmv NO X . Commenter 0296 cited an erroneous statement in the Regulatory Impact Analysis suggesting that80 ppmv would be allowed for process heaters that commenced co nstruction after May 14, 2007, but prior to June 24, 2008. Although the unit has not started up yet, based on the design of the process heater, Commenter 0296 does not expect the unit to meet the 40 ppmv emissions limit. Similarly, Commenter 0314 noted that the only way for their process heater currentl y under construction to meet the 40 ppmv emissions limit is to install se lective catalytic reduc tion (SCR), so they are making provisions to install SCR even though th e EPA already determined that SCR is not BSER. According to both commenters, either cha nging the effective date of the requirement or changing the emissions limit for newly constructed forced draft process heaters would eliminate this “retroactive noncompliance” issue. Commenters 0310 and 0311 stated that, if the EPA imposes standards on syngas produced by coke gasification, then the applicab ility date of those requirements should be no earlier than the December 22, 2008, proposal date . Commenter 0311 also indicated that the trigger date for other newly de fined refinery process units ( e.g. , wastewater treatment) should be the December 22, 2008, proposal date. Response : Commenters raise two basic questions: (1) What date applies for determining whether a flare or a process heat er is a “new source” and subject to subpart Ja? (2) When must15 that “new” flare or process heater be in complia nce with the applicable requirements in subpart
Ja? Section 111(a)(2) of the CAA defines a “new source” as “any stationary source, the
construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) pr escribing a standard of performance under this section which will be applicable to such source.” An important aspect of this definition is the “notice” it provides that NSPS will be prospectively appl icable after construc tion, reconstruction or
modification of an affected source. For NSPS su bpart Ja, a “new” proce ss heater is one that commences construction, reconstruction or modi fication after May 14, 2007, which is the date of the “proposed regulations.” For the reasons expl ained in the final rule preamble at 73 FR 35856- 35857, a “new” flare is one that commences cons truction, reconstruction or modification after June 24, 2008, which is the date of the “publicati on of regulations.” Therefore, in compliance with CAA section 111(a)(2), refine ries are on “notice” that afte r these respective dates, “new” process heaters and “new” flares will be subject to subpart Ja. See 40 CFR 60.100a(b). Commenters, however, are essentially asserting that refineries were not on “notice” and cannot now be required to “retroactively” comply with subpart Ja. They assert several legal arguments for this position, but th eir basic position boils down to a lack of “notice,” which they assert requires the EPA to move the “trigger date” for subpart Ja appli cability to December 22, 2008, the proposal date for the proposed amendments. With respect to flares, we find no validity in the arguments that the June 24, 2008, applicability date is inappropriate. The limited changes in the flare modification provision proposed on December 22, 2008, only identified cer tain connections that are not considered modifications of a flare. As such, we see no scenario where the revised flare modification provision would trigger retroact ive application of the rule. For process heaters, while we recognize th at the emissions limits and form of the standard have changed based on the informati on gathered during the rulemaking process, the regulated community was notified that NO X standards were being considered for process heaters on May 14, 2007. The best system of emission reduction should be implemented at this time. We recognize that refinery owners and operators desire maximum operating flexibility, but the proposed rule clearly indicatedthat controlling excess oxygen amounts is part of BSER, and process heater design and opera tion at high excess oxygen conten t was not considered BSER.16 While we acknowledge that the ini tially promulgated 40 ppmv 24-hour NO X emissions limit and even the final amendments to these standards may limit operator flexibility to a greater extent than the originally proposed emissions limits, we find that the emissions limits in the final amendments are achievable and appropriate for newly constructed process heaters. As discussed in greater detail in Section 2.1.1, the proposed clarificati ons of fuel gas and refinery process units in no way im pacted the applicability of subpart Ja standards to the units in question. As such, we see no reason to sp ecify applicability dates for syngas ( i.e. , fuel gas) produced by coke gasification. The limitations on sulfur in fuel gas apply to the fuel gas
combustion device or flare as the affected source , not the unit producing the fuel gas. In other words, if a fuel gas combustion device or flare is an affected source based on the date that construction, reconstruction or modification comm enced, then all the fuel gas combusted by that device must meet the sulfur standards, regardless of its origin, so an app licability date for coke gasification is irrelevant. Similarly, we see no basis or need to specify applicability dates for wastewater treatment systems or loading opera tions. Gases generated from these units were always considered to be fuel gas (unless they meet the newl y established exemption from the definition of fuel gas for combustion of vapor s in a flare or thermal oxidizer to control emissions). If these gases were not already consider ed fuel gas, than this exemption would have been unnecessary and the industry would not ha ve provided so many comments to expand the exemptions for different types of fuel gases. Furthermore, as we did not specify any specific regulations for wastewater treatment units or loading racks under subpart Ja, we do not understand the commenters’ request to change the applicability date.
Comment : Commenter 0305 recommended that 40 CF R 60.100a(c) clarify that: “For the purpose of this subpart, all projects committed to and subject to compliance with a Consent Decree filed with the Department of Justic e prior to May 14, 2007 are deemed to have commenced prior to May 14, 2007.” The commenter st ated that this clar ification is needed because subpart Ja could significantly impact (or create uncertainty in) some projects which have been long planned and committed to in or der to comply with a consent decree. Response : We decline to make this change, whic h equates to a request that the EPA find that the filing date of a consent decree is equiva lent or should be deemed equivalent to the date construction “commences” for all refinery proj ects covered under cons ent decrees. Instead,17 sources should continue to use the following definitions from 40 CFR 60.2 in making this
determination:

Commenced means, with respect to the definition of new source in section 111(a)(2) of the Act, that an owner or operator has undert aken a continuous program of construction or m odification or that an owne r or operator has entered into a contractual obligati on to undertake and complete, within a reasonable time, a continuous program of cons truction or modification.

Construction means fabrication, erection, or inst allation of an affected facility.

Modification 5 means any physical change in, or change in the method of operation of, an existing fac ility which increases the am ount of any air pollutant (to which a standard applies) emitted into the atmosphere by that facility or which results in the emission of any air pollutan t (to which a standard applies) into the atmosphere not previously emitted.
The definitions provide a reason able set of criteria for determining when construction or
modification commenced and should be applied on a project-specifi c basis. Sources that have any questions regarding how the final amendments to subpart Ja may im pact their compliance
with their consent decree shoul d contact the EPA personnel within EPA’s Office of Enforcement and Compliance Assurance (OECA) with wh om they negotiated the consent decree. However, we have provided additional co mpliance time for owners and operators of certain flares. Owners and operators of modified flares that are have accepted applicability of subpart J under a federal consent decree shall comply with the subpart J requirements as specified in the consent decree, but must meet the short-term 162 ppmv H 2 S concentration limit no later than 3 years after the eff ective date of the final amendments. In addition, modified flares that are already subject to the short-term H 2 S concentration limit but that have an approved monitoring alternative under subpart J and do not have the monitoring equipment in-place that is required under subpart Ja shall be given up to 3 year s from the effective date of this final rule to install the monitors required by subpart Ja (or to obtain an ap proved monitoring alternative under subpart Ja). In this interim period, owners and operators of these modified flares shall demonstrate compliance with the short-term H 2 S concentration limit using the monitoring alternative approved under subpart J.

5 Sources should also reference CAA section 111(a)(4) and 40 CFR 60.14 when determining whether a “modification” has occurred.18 Comment : Commenter 0315 requested clarificati on regarding the ti ming of potential modifications. The proposed rule te xt, read literally, could be inte rpreted to mean that the date the new piping is connected to the flare header is the date an owner or operator should use to
determine if that connection is a modification. Ho wever, in most cases, most of the work on the project has occurred before the actual connect ion is made, partly because accomplishing the connection and allowing flare h eader hydrocarbon to flow into new equipment poses a major safety risk. The commenter also not ed that this literal interpretati on of the date of a modification
is inconsistent with the NSPS General Provisions at 40 CFR 60.2, which states: “Commenced means... that an owner or operator has undertak en a continuous program of construction or modification or that an owner or operator has en tered into a contractual obligation to undertake and complete, within a reasonable time, a conti nuous program of construction or modification.” The commenter requested that the final rule cl early specify that, for projects where a flare connection is part of an entire project, the po tential flare modification is considered to have begun upon the commencement or contracting of the project ( i.e. , a continuous program of construction or modification that happens to include a new connection to a flare). Response : It is not our intention to apply a definition of “comm enced” to subpart Ja that is inconsistent with that term as it is defined in the General Provisions. As explained in the previous response above, sources should contin ue using the definitions of “commenced,”
“construction” and “modification” 6 from the General Provisions for determining when a particular project “commences.” Us ing those definitions, it already appears that the date a source would use for evaluating whether a new connection to a flare is a “modification” of that flare would be the date that the entire project “comm ences,” not necessarily the date the piping is physically connected to the flare header. Howeve r, we recognize that the “new connection” language in the flare modification provision could be misconstrued in this context; therefore, we have added a sentence to 40 CFR 60.100a(b) that states: “For the purpose s of this subpart, a modification to a flare commences when a proj ect that includes any of the activities in paragraphs (c)(1) or (2) of this section is commenced.”

6 See footnote 4.19 

### 2.3 Flare Modification
Comment : Commenter 0308 objected to the special modification provision for flares in subpart Ja. The commenter stated that the pr ovisions in 40 CFR 60.14 can and should apply to flares. Specifically, the EPA s hould consider the “...hourly emi ssion rate, at maximum physical capacity, before and after an operational cha nge” (57 FR 32316). Because the maximum physical capacity of the flare, even when considering the head er system as part of th e flare, is not changed by additional tie-ins, new tie-ins should not constitute a modification, according to Commenters 0308 and 0311. Furthermore, the comme nters asserted that the NSPS program was never intended to apply across an entire industry based on minor cha nges of an affected facility.
Commenter 0310 stated that the flare modifi cation provision is unlaw ful because routine connections generally do not resu lt in an emissions increase an d may be seen as having the primary purpose of reducing emissions, which ha s been excluded under 40 CFR 60.14(e)(5), a paragraph that is not limited to pollutants “to which the standard is applicable.” Commenter 0311 suggested a narrower flare modifica tion provision stating that only connections that “result in a
net increase in the amount of VOC or SO 2 emitted during normal operations” are considered modifications. Commenter 0308 noted that a single project may remove some tie-ins and add some tie-ins, so that the net emissions could actu ally be reduced, and reque sted clarification if it was the EPA’s intent for such projects to constitute a flare modification.
Commenter 0310 stated that the flare modi fication provision in 40 CFR 60.100a(c)(2) should specify that the in crease in flow capacity is an incr ease in the total volume of gas under
standard conditions that could reach the flare and th at it is specific to flow increases of VOC or sulfur compounds. Commenter 0309 suggested that most of the exemptions could be reduced down by focusing the rule on SO 2 emissions and exempting any conn ection of fuel gas that has a
H 2 S concentration of less than 162 ppmv. Commente r 0305 stated that “flow” is not a regulated pollutant, so an increase in flow should notbe considered a m odification. Commenter 0314 agreed that examining what is a flare modification is warranted and agreed that projects that increase production through new pr ocess vents to flares or proj ects that increase process vent flow rates to flares should be subject to s ubpart Ja. Commenter 0309 stated that the proposed flare modification provision is too broad and suggested that the EPA should focus the flare modification provision on connections that provide a primary/routine flow from a process unit to the flare, such as delayed coking unit offgas.20 Response : The agency made a conscious decision to promulgate a separate provision for a flare modification in 40 CFR part 60, subpa rt Ja (see 40 CFR 60.14(f)) because flares are operated differently from other refinery pr ocess units, making it difficult to apply the modification provision in the Ge neral Provisions (40 CFR 60.14) to them. The physical capacity
of a flare is based on the amount of gas potentially discharg ed to a flare as a result of emergency relief. Refiners frequently make connections to ex isting flares that result in emissions increases at the flares, but may never approach the physic al capacity of the flare system. Contrary to commenters’ assertions, the fl are modification provision in 40 CFR 60.100a(c) does meet the statutory definition of “modification” in CAA s ection 111(a)(4), which is “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which re sults in the emission of any air pollutant not previously emitted.” It is axiomatic that the connections to the flare described in 40 CFR 60.100a(c) qualify as physical or operational changes to the flare. Additionally, we explained in the proposed rule how these connections also resu lted in emissions increa ses from the flare (see 73 FR 78529). Thus, these types of new connect ions of refinery process units (including ancillary equipment) and fuel gas systems to the flare qualify as a “modification” of the flare and trigger subpart Ja applicability for the flare.
Those connections we identifie d that do not increase emi ssions from the flare were specifically excluded from triggering 40 CFR part60, subpart Ja applicability under this same provision (see 40 CFR 60.100a(c)(1) ). Specifically, we proposed on December 22, 2008, that the following types of connections to a flare would no t 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 (FGR) system; (3) connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valv e has a set point opening pressure no lower and an internal diameter no gr eater 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 th e new pipe diameter is less than or equal to the diameter of the pipe/connection being repl aced/moved. While we agree that there may be
other connections to a flare that would not result in an emissions increase from the flare (see response to the next comment for specific detail s), we disagree with the commenters that the21 flare modification provision shoul d be further limited beyond what is already provided in the provision. We disagree with commenters that we must consider the “net” emissions from the process unit and the flare when determining whether a flare is modified. The affected facility is the flare and does not include the process units that are tied into the flare header system. See
Asarco v. EPA , 578 F.2d 319, 325(D.C. Cir. 1978) (holding that emission increases had to be
determined based on emissions from the affected facility). We also disagree that a modification
determination should be limited to emissions increases of VOC or SO 2 . Flares are known to emit VOC, SO 2 , CO, PM and NO X , as well as other air pollutants, all of which are relevant when determining whether a flare has b een modified. See CAA section 111( a)(4). That is, we consider the standards for flares to be emission standards for VOC, SO 2 , CO, PM and NO X . See, generally, 73 FR 35838, 35842, 35854-35856 (June 24, 2008); 73 FR 78522, 78533 (December 22, 2008), as well as Table 4 of the preamble to th e final amendments. Using the flare to control
VOC emissions at other re finery process units will increase CO, PM and NO X emissions from the flare and are, therefore, considered modificati ons of the flare, even if there is a net reduction in VOC emissions at the refinery. In evaluating whether a flare has been modified, we consider increases in flow to the flare to be directly indicative of incr eased emissions from the flare. While we agree that “flow” is not a pollutant, we evaluated flow limits as a means to reduce SO 2 , VOC, CO, NO X and other
emissions from the flare. The emissions from the flare are very difficult, if not impossible, to measure accurately, but flow to the flare can be measured, and the flow to the flare generates
SO 2 , VOC, CO, PM, NO X and other emissions. Therefore, a physical or operational change to a
flare that causes an increase of flow to the flare will increase emissions of at least one of these pollutants and is considered a modification of the flare.
Comment : Commenters 0298, 0301, 0302, 0303, 0305, 0306, 0309, 0311 and 0314 suggested that the EPA should sp ecifically exempt the followi ng situations from the flare modification provision: (1) connections made to upgrade or enhan ce (not just to install) a FGR system (Commenters 0301 and 0311); (2) new flare header interconnect lines, sin ce the connection is be tween flares and not from a process unit or fuel gas system to a flare (Commenters 0308, 0310 and 0311);22 (3) connections made for flare gas sulf ur removal (Commenter 0311; these reduce emissions); (4) connections made to install back- up equipment (Commenter 0311; no impact on emissions); (5) all emergency pressure relief valve (P RV) connections from existing equipment because the rule may create a disincen tive to improving safety (Commenter 0298, 0305 and 0311) and the upset gases released by these valves are exempt from the emissions standard (Commenter 0301); (6) connections of monitoring system purge gases and analyzer exhausts (Commenters 0298 and 0301) or closed vent samp ling systems (Commenter 0314); (7) purge and clearing vapors, block and bl eeder vents and other uncombusted vapors where the flare is the control device (Commenter 0301 and 0306); (8) connections made to comply with other fede ral, state or local ru les where the flare is the control device (Commenters 0301 and 0314); (9) connections of “unregulated gases” su ch as hydrogen, nitrogen, ammonia, other nonhydrocarbon gases or natural gas” (Commenters 0301, 0305, 0309 and 0311) or any connection that is not “fue l gas” (Commenter 0311); (10) new connections upstream of an existing FGR system (Commenters 0301, 0303, 0305 and 0314), provided the new connections do not compromise or exceed the FGR system’s capacity (Commenter 0301); (11) any new, moved or replacedpiping connections that do not result in a ne t increase in emissions (Commenter 0311 specifically indicated increases in VOC or SO 2 emissions) from the flare, regardle ss of piping size (Commenter 0301, 0305, 0306, 0311 and 0314); Commenter 0301 suggested a larger PRV is such an example, stating that the larger PRV does not change the s ource or mass emissions, it just allows the pressure to relieve more quickly; (12) vapors from tanks used to store sw eet or treated products (Commenter 0309); (13) temporary connections for purging ex isting equipment (Commenters 0311 and 0314; these are essentially “exis ting” connections); and (14) connections of safety instrumentati on systems (SIS) described under Occupational Safety and Health Administration (OSHA) process safety standards at 29 CFR 1910.119, the EPA’s risk management progr am at 49 CFR 68 and/or American National Standards Institute (ANSI)/Inte rnational Society of Automation (ISA)- 84.00.01-2004 (Commenter 0314; the purpose of th ese systems is for safety and can often minimize process upset s when they do happen).

Commenter 0315 stated that for existing flar es with sufficient FGR capacity, the EPA
should make clear that sites are allowed to make new connections, tie-in s and other changes to their FGR systems as long as the new connections will not compromise or exceed the system's capacity to recover the new fl ow without triggering a flare modification. Commenter 0301 noted23 that a safety project to add a ne w pressure relief valv e cannot carry the costs of a FGR system or additional amine treatment. According to the commenters, the EPA should encourage venting these gases to the flare rather than venting them to the atmosphere or compromising safety. Response : We carefully reviewed the commente rs’ suggested changes to the flare modification provision to determine whether there are additional c onnections that should not be considered modifications to the flare. We agree th at the first four connect ions in the commenters’
list should not be considered modifications of a flare. Projects to upgrad e or enhance components of a FGR system ( e.g. , addition of compressors or recycle lines) will improve the operation of the FGR system, and connections to these addition al components will not result in increased
emissions. Connections made for removal of sulfur from flare gas (Item 2 above) will generally result in a slight decrease in volumetric fl ow and a large decrease in emissions of SO 2 . Connections made to install back-up or redundant equipment (Item 3 above), such as a back-up compressor, will result in fewer released emissions if there is a malfunction in the main equipment. The request to exclude flare interconnections (Item 4 above) is a complicated issue because interconnecting two separate flares alters what we cons ider to be the affected facility. The definition of “flare” specifica lly includes the flare gas header system as part of the flare. Prior to interconnecting the flares, presumably each flare header system is independent, and there would be two separate “flares,” each of which coul d potentially be an affect ed facility subject to 40 CFR part 60, subpart Ja. However, because the flare includes the flare header system, we consider that an interconnected flare system is a single affected facility, and we have amended
the definition of “flare” for clarity. We agree that interconnections between flares will not alter the cumulative amount of gas being flared ( i.e. , interconnecting tw o flares does not result in an emissions increase relative to the two single flares prior to interconnectio n). We also see cases where the emissions from a single flare tip will likely be reduced due to the flare interconnect. For example, when a large release event occu rs, this gas will now flow to both of the interconnected flares rather than a single flar e. The maximum emission rate for the original single flare actually decreases, while the combin ed emissions from both flares is the same quantity as prior to the interc onnection. Considering this, we ag ree that the in terconnection of two flares does not necessarily result in a modi fication of the flare and we have specifically
excluded flare interconnections fr om the modification provisions.24 However, we also clarify in this response thatwhen a flare that is subject to 40 CFR part 60, subpart Ja is interconnected wi th a flare that is not subject to subpart Ja, then the resulting interconnected flare is subject to subpart Ja. That is, the only ca se in which an interconnection between two (or more) flares results in a combin ed, interconnected flare th at is not subject to subpart Ja is when none of the original individua l flares were subject to subpart Ja. Additionally,
we note that if a new connection is made to th e interconnected flare, th en the flare (including each individual flare tip within the interconnected flare header system) is modified and becomes an affected facility subject to subpart Ja. While we agree that connections that do not in crease the emissions from the flare should not trigger a modification, we disagree with the commenter that their other suggested
connections do not increase the flare’s emissions at the time ga ses are discharged via the new connection. Each of the commenters’ suggestions is discussed in the following paragraphs. We previously proposed an exemption for em ergency pressure reli ef valve connections from existing equipment (Item 5 above) if they replace or upgrade existing equipment and do not increase the instantaneous release rate to the flare ( i.e. , the new pressure relief valve has a pressure set point and diameter no greater than the equipment being replaced). As stated previously in this document, we are finalizi ng that amendment, as proposed. However, new connections, even if they are made to “existing eq uipment,” will result in an increase in flow to the flare during periods of process upset that cause the pressure relief valve to open. Connections of monitoring syst em purge gases and analyzer exhausts or closed vent sampling systems (Item 6 above) will increase the emissions from the flare. Similarly, connections of purge and clearing vapors and bl ock and bleeder vents (Item 7 above), also trigger a modification of the flare because the increase of gas flow to the flare will increase the
emissions from the flare. We recognize that connections to a flare may be made to comp ly with other federal, state
or local rules where the flare is an emissions control device (Item 8 above). In fact, nearly all
flares could be considered “contro l devices.” We agree that using a flare as an emissions control device is preferable to venting the process unit to the atmosphere . However, while using the flare
as an emissions control device does decrease emissions from th e process unit being controlled, the increase of gas flow to the flare will increas e the emissions from the flare. Therefore, a25 connection from a process unit to a flare for us e as an emissions control device results in a
modification of that flare. Comments suggesting that c onnections of “unregulated gases” such as hydrogen, nitrogen, ammonia, other non-hydroc arbon gases or natural gas or c onnections that are not “fuel gas,” should not be considered a modification of th e flare (Item 9 above) are in conflict with the statutory definition of “modification.” Each of the streams mentioned by the commenter, when directed to a flare, will incr ease emissions of at least one pollutant (either PM, CO or NO X ) from the flare (all of which the standardis intended to reduce). That is, we reiterate that we consider the standards for flares to be emission standards for VOC, SO 2 , CO, PM and NO X . As such, we do not agree that the types of gas streams sugge sted by the commenters should be exempt from
the modification determination. New connections upstream of an existing FGR system (Item 10 above) will increase the
likelihood of an event that would cause an exceedance of the FGR system’s capacity (even if the new connections “do not exceed the FGR system ’s capacity” under normal conditions), and the amount of gases sent to the flar e would increase as a result of such an event, thereby increasing
the emissions from the flare. We reiterate that we proposed an exemption for any moved or replaced piping or pressure
relief valve connections of the same size. However, we disagree with the commenter’s suggestion that any “new, moved, or replaced piping or pressure relief va lve connections that do
not result in a net increase in emissions from th e flare regardless of pipi ng or pressure relief valve size” should be exempted (Item 11 above). The premise of the suggested amendment is that new or larger connections somehow will not increase emissions from the flare. We have discussed new connections previously, so we w ill concentrate on the “regardless of piping or pressure relief valve size” comment in this paragr aph. First, the size of th e pressure relief valve or piping does correlate to the discharge rate to the flare, with larger pr essure relief valves or larger diameter piping allowing hi gher discharge rates to the flare at a given pressure. In fact, larger pressure relief valves and larger diamet er pipes are specifically designed to allow higher flow rates to the flare. Second, higher flow rates will lead to higher emission rates. For a pressure relief event that occurs for several hours, the flow rate to the flare during the first hour of relief using the larger pressure relief valve or larger di ameter piping will be larger than the flow rate experienced using the smaller pressu re relief valve or smaller diam eter piping and will result in26 higher emissions from the flare. Therefore, we re ject the notion that larger diameter pipes and larger pressure relief valves do not increase the emissions rate from the flare during a release event. We are finalizing the proposed exemptions for moved or replaced pipi ng or pressure relief valves with the size and design restrictions for the new piping or pressure relief valves as proposed on December 22, 2008. Commenters suggested that c onnections of vapors from tanks used to store sweet or treated products (Item 12 above) should not be m odifications because those gas streams have less than 162 ppmv H 2 S. We reiterate that SO 2 is not the only pollutant emitted from flares and that the additional flow of sweet gases will increase th e emissions of at least one pollutant from the flare, so we are not exempting these types of connections to th e flare from the 40 CFR part 60, subpart Ja flare modification provision. Howeve r, we have amended the sulfur monitoring requirements for flares to exempt vapors from tanks used to store sweet ortreated products from the flare sulfur monitoring requirements. This m onitoring exemption is justified because it is not needed for the purposes of a RCA or other complia nce purpose. For these sweet vapors, the flow
rate RCA threshold will be exceeded well before the SO 2 RCA threshold. We carefully considered temporary connec tions for purging existing equipment (Item 13 above), but we failed to see how these temporary connections are essentially “existing connections.” According to the commenters, “maint enance gases have been routed in some form or other to the flare for years, and the temporary tie-in to accomplis h that is not a change and is
not an increase in emissions when viewed fr om a before and after perspective.” If the connections already exist, then opening an existing valve to allow for this type of purging would not trigger a flare modification. If the connection is being reloca ted and the piping used is the same diameter as the pre-existi ng connection, then this scenario is adequately covered by the proposed exclusion for relocated connections. Howe ver, if a new connection is made specifically to purge an existing piece of equipment, this purge gas unequivocally represents additional gas
flow sent to the flare that di d not exist and could not exist pr ior to the connection being made. Again, we consider that the increase in gas flow to the flare will result in an increase in emissions of at least one pollutant from the fl are. As such, no exemption is provided for new connections to existing equipment, regardless if these connections are temporary or permanent. We also find that these types of flows should be expressly consider ed in the FMP and that flaring from these “temporary” connections should be minimized to the extent practicable.27 The impact of connections of SIS describe d under OSHA process sa fety standards at 29 CFR 1910.119, the EPA’s risk managementprogram at 49 CFR 68 and ANSI/ISA-84.00.01- 2004 (Item 14 above) should be evaluated on a case -by-case basis to determine whether these connections result in a flare modification. We exp ect that, if these connections are made for flare monitoring purposes, these connections are al ready excluded in the exemption for flare monitoring systems. If the “SIS ” are process unit analyzers and the new connections are being made to connect the analyzer exhaust to the fl are, these connections would be considered a modification, as previously discussed. The comme nter may also be referring to new connections for additional pressure relief valves identified in the safety reviews required by the cited rules,
which we would consider to be a modification of the flare. Following all of the above review and analysis, we are finaliz ing three of the connections as proposed, adding three of the connections re quested by commenters and revising one of the proposed connections as requested by comment ers in 40 CFR 60.100a(c)(1). Thus, the following seven types of connections are not considered a modification of the flare: (1) Connections made to install monitoring systems to the flare. (2) Connections made to install a FGR syst em or connections made to upgrade or enhance components of a FGR system ( e.g. , addition of compressors or recycle lines). (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 exis ting equipment being replaced or upgraded. (4) Connections that interconnect two or more flares. (5) Connections made for fl are gas sulfur removal. (6) Connections made to install back-up (re dundant) equipment associated with the flare (such as a back-up compressor) that does not increase the capacity of the flare. (7) Replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the ne w pipe diameter is less than or equal to the diameter of the pipe/conn ection being replaced/moved.
Comment : Commenter 0309 stated that the flare modification provision in 40 CFR 60.100a(c)(2) should explic itly exclude the following physical changes made to the flare: (1) change in flare pilot and igniter system s (including larger pilot lines or those that use more gas); (2) installation of sw eep or purge gas reduction device ( e.g. , an internal ring or28 molecular seal); (3) increase in steam capacity (to limit smoke); (4) alteration of flare seal drum level or control scheme; and (5) connections to increase sweep or purge gas rates provided the sweep or purge gas has an H 2 S concentration of le ss than 162 ppmv on a 3-hour rolling average
basis. Response : Under 40 CFR 60.100a(c)(2), a flare is modi fied when it “is physically altered to increase the flow capacity of the flare.” We did not propose to revise this provision, nor do we think revisions are necessary. We do clarify in this response that the “flow capacity of the flare”
is intended to refer to th e capacity of flare gas ( i.e. , gas from the “flare gas header system,” which is defined in the amended rule) that can be safely discharged to the flare because this kind of change most likely results in an emissions increase from the flare. This is consistent with the definition of “modification” in CAA section 111( a)(4), which is “any physical change in, or change in the method of operati on of, a stationary source which increases the amount of any air pollutant emitted by such source or which resu lts in the emission of any air pollutant not previously emitted.” Alterations of the pilot and igniter systems or the steam system would not typically constitute a “modification” of the fl are because these alterations do not typically increase the flare gas flow capacity of the flar e. However, if these physical alterations do increase the flow capacity of the flare ( e.g. , larger pilots or increased steam ducts installed to allow higher flare gas flow rates to be handled by the flare, thereby increasing the flow capacity of the flare), which results in an emissions incr ease, then these alterations would be deemed a
“modification” of the flare under 40 CFR 60.100a(c)(2). Similarly, in stallation of sweep or purge gas reduction devices or flare seal drum controls are not expected to increase the flare gas flow capacity of the flare and would not generally be a “modification” of the flare. However, if these physical changes do increase the flare gas flow capacity of the flare, which results in an emissions increase, then these alterati ons are “modifications” of the flare. While the exemptions specified by the commenter may not be flare modifications under 40 CFR 60.100a(c)(2), a few of these examples may be considered flare modifications under 40 CFR 60.100a(c)(1). Specifically, Item 5, connections to increase sweep or purge gas rates,
would be considered a modificati on of the flare if these gases originate from a process unit or fuel gas system. However, if these connections ar e from a separate, independent natural gas line, for example, these connections would not be considered a flare modification under 40 CFR 60.100a(c)(1). As noted in this response, we disagree that a blanket exemption of the29 modifications requested by the commenter is ap propriate. This response, while clarifying the intent of the rule’s language, also indicates th e need to evaluate poten tial modifications on a case-by-case basis. If there is any question abou t whether an alteration of the flare should be
considered a modification of the flare based on the subpart Ja flare m odification provision, the owner or operator should contact their permitting authority or the EPA for assistance.
Comment : Commenters 0298, 0301, 0302, 0309, 0311 and 0314 suggested that the EPA should specifically state that de minimis emission increases (or net emission decreases) resulting
from new connections to a flare made to contro l and combust fugitive emissions such as leaks from compressor seals, valves or pumps, are not flare modifications. Commenter 0302 suggested allowing site-specific exemptions for connections that do not increase emissi ons or that result in

a de minimis emissions increase. Conversely, Co mmenter 0313 objected to setting a de minimis
emissions increase below which a modification w ould not trigger subpart Ja applicability. The commenter noted that the specific exclusions pr oposed by the EPA are acceptable because they arguably cause no emission increases. However, emi ssions from a flare are difficult to determine, particularly at low flow rates, and allowing a de minimis approach would cause confusion over the applicability of subpart Ja. Response : In the preamble to our proposed amendments, the EPA specifically requested comment on using the de minimis exception in the flare m odification provision. 73 FR 78522, 78529. Industry Petitioners had suggested some type of de minimis emissions increase should be allowed without triggering 40 CFR pa rt 60, subpart Ja applicability. Id . The EPA acknowledged that these exceptions are “permissible but not re quired” under the modification provision in the
CAA. Id . The EPA also stated: “We request comments on a de minimis approach and on specific changes that may occur to flares that will result in de minimis increases in emissions. We also request comments on the type, number and amount of emissions that would be considered de
minimis .” Id

. Industry Petitioners continue to recommend th at any emissions increases resulting from
“routine connections” to th e flare system “will be de minimis ” and should not trigger 40 CFR part 60, subpart Ja applicability at the flare, but they have not provided the comments or data requested in the proposal preamble that the EPA c ould consider to evaluate the impacts of such an approach. Docket Item No. EPA-HQ- OAR-2007-0011-0311 (second attachment), pg 20. Industry Petitioners again suggest that the EPA ex ercise its authority and “authorize exceptions30 from otherwise clear statut ory mandates” by promulgating de minimis exemptions for the flare modification provision. Id .; Alabama Power Co. v. Costle , 636 F.2d 323, 360 (D.C. Cir. 1979). As explained in Alabama Power , the de minimis exception allows agency flexibility in interpreting a statute to prevent “ pointless expenditure s of effort.” Id . However, as Industry Petitioners recognize, nothing mandates that the EPA use its de minimis authority in any given instance, and courts especially recognize the si gnificant deference due an agency’s use of a de
minimis exception. Id . at 400; Shays v. Federal Election Com’n , 414 F.3d 76, 113 (D.C. Cir. 2005); Environmental Defense Fund, Inc. v. EPA , 82 F.3d 451, 466 (D.C. Cir. 1996); Ass’n of Admin. Law Judges v. Fed. Labor Relations Auth. , 397 F.3d 957, 961 (D.C. Cir. 2005). In exercising that discretion, the EPA must consider the cautionary advice it received
from the Alabama Court regarding its use of the de minimis exception: “EPA must take into account in any action... that this exemption author ity is narrow in reach and tightly bounded by
the need to show that th e situation is genuinely de minimis .” Id . at 361. The Court also noted that exemptions from “the clear commands of a regulatory statute, though sometimes permitted, are
not favored.” Id . at 358. The EPA must exercise this au thority cautiously, and only in those circumstances that truly warrant its application. The EPA has found no basis for promulgating a de minimis exception to the flare modification provision. Despite its a ssertions, Industry Petitioners ha ve still provided no data to support a finding that the emissions increases resulting from the alleged “routine connections” to a flare system are truly “tri vial or [of] no value.” Docket Item No. EPA-HQ-OAR-2007-0011- 0311 (second attachment), pg 20. Without the reques ted information showing that “the situation is genuinely de minimis ,” Alabama Power , 636 F.2d at 361 and, therefor e, warrants this kind of exception, we believe such an exem ption would be inappropriate. Additionally, Industry Petitione rs’ example that “venting a new small storage tank to a flare system... easily would cost a typical refine ry tens of millions of dollars” since “the entire flare system” (emphasis in origin al) would be subject to subpart Ja is unavailing for its argument that the EPA should promulgate a de minimis exception for the flare modification provision. Docket Item No. EPA-HQ-OAR-2007-0011-0311 (sec ond attachment), pg 21. As the District of Columbia Circuit specifically states in Shays , authority for promulgating a de minimis exception
“does notextend to a situation where the regulatory function does provide benefits, in the sense of furthering regulatory objectives, but the agency concludes the acknowledged benefits are31 exceeded by the costs .” Shays , 414 F.3d 76, 114 (emphasis added). By focusing solely on cost, Industry Petitioners are effectively asking the ag ency to engage in the type of cost-benefit analysis prohibited by the Shays Court. Such cost analyses are improper in these types of decisions. Industry Petitioners generally focus th eir discussion on VOC e missions and effectively admit that connecting the small storage tank to the flare system increases emissions from the flare ( e.g. , “uncontrolled tank emissions would be essentially eliminated by combustion in a flare” (Docket Item No. EPA-HQ-OAR-2007- 0011-0311 (second attachment), pg 21, emphasis added)). Furthermore, they disr egard additional emissions of NO X and CO resulting from the combustion of these gases at the flare. Industry Pe titioners also provide no data quantifying these emissions increases and, therefore, cannot demonstrate that they ar e “trivial or [of] no value” or, in other words, that the emi ssions increases are, in fact, de minimis . As releases to the flare are often event driven, one can envisi on situations where the release from even a small storage tank could be significant. On the other hand, the EP A sees a substantial environmental benefit in requiring controls that will reduce the cumulative emissions from a flare that becomes subject to 40 CFR part 60, subpart Ja because of any of th ese alleged “routine connections.” Thus, given
the nature of releases to the flare, we determined that a de minimis exemption from the modification provisions for flares is unworkable and unwarranted.
Comment : Commenter 0315 expanded on their orig inal comments (0311) and addressed the comparison between the flare modification pr ovision in subpart Ja and modification of a municipal solid waste (MSW) landfill in the di rect final amendments to Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills (63 FR 32743, June 16, 1998). The commenter noted that the preamble to that rule explains that the modification provision “is specific to landfills but is
consistent with the intent of section 60.14 of the NSPS General Provisions.” “Production” is considered to be the amount of waste placed in th e landfill, and “total ‘production’ for the entire life of the facility is controlled through the am ount of design capacity sp ecified in the permit.” The commenter noted that according to the preamb le, only “physical or operational changes that increase the size of the landfill beyond its permitted capacity” are considered modifications for purposes of NSPS. The preamble also stated that “operational changes” at a landfill are typically accomplished without capital expenditure; therefor e, they are not included in the modification provision. Finally, the commenter not ed that the preamble to the pr oposal stated that “if an MSW32 landfill increased its waste acceptance rate, such a change would be analogous to an increase in production rate at a manufacturing facility” which is excluded under 40 CFR 60.14. Therefore, the commenter asserted, the MS W modification provision is cons istent with 40 CFR 60.14, while the subpart Ja flare modification prov ision is a departur e from 40 CFR 60.14. The commenter made several points in comparing the MSW landfill modification provision to their recommendations for the flare m odification provision in s ubpart Ja. First, the commenter stated that the provision that a modifi cation occurs only if th e design capacity of the landfill is changed is consistent with the suggest ion that a new connection to a flare is only a modification if other changes are made to the flar e system that would increase the capacity of the flare. Second, using the landfill in its intended function and continually adding new waste is not considered a series of physical changes, each adding a small increment to the potential emissions of the landfill; ther efore, incremental additions to a flare system should not constitute modifications to the flare system for purposes of subpart Ja. Third, since the longstanding
exclusions to the 40 CFR 60.14 definition of modification, such as excluding operational changes that do not require capital expenditure, were included in the MSW landfill modification provision, they should be available for the s ubpart Ja flare modification provision. (The
commenter noted that the MSW landfill rule actually goes beyond the 40 CFR 60.14 exclusion by allowing any operational ch anges to be excluded whether or not they actually have a capital expenditure.) The commenter concluded that the EPA’s rationale for the MSW landfill modification provisions provides support for their suggested modifications to the flare modification provisi on in subpart Ja. Response : In developing the modification provisions for MSW landfills, we evaluated the special circumstances associated with landfills and developed a modifica tion provision specific to landfills. In exactly the same manner, we eval uated the special circumstances associated with flares and developed a modificati on provision specific to flares. In both cases, we considered the same underlying principles of what constitutes a “modification” based on the provisions in CAA section 111(a)(4), 40 CFR 60.2 and 40 CFR 60.14. We arrived at different modification provisions for MSW landfills and flares because of the many factual and operational differences for these two very different sources. We theref ore do not consider it appropriate to make the changes to the flare modification provisi on that are suggested by the commenter.33 Comment : Commenter 0308 requested clarificati on with respect to how the flare modification provision applies to flare interconnects, which are us ed to direct flow from one flare to another flare if one flare is tempor arily out of service. The commenter requested
concurrence that a new connection to “flare header system A” only modifies “flare A” and not to the interconnected “flare B” since the sy stems are generally operated independently. Response : We disagree that only the first or pr imary flare in an interconnected flare system should be subject to subpart Ja when a new connection to a process unit or fuel gas system is made. New connections to the inte rconnected flare system would suggest that additional gas could be sent to any of the flares in the interconnected system. In a cascaded system, the new connection increases the likelihood that gas will be sent to the secondary flare. As such, a new connection to the flare gas system would trigger the appli cability of subpart Ja for both (or all) interconnected flares. For flares that are used only for back-up or redundant systems to the primary flare ( i.e. , for staged flares that are only triggered when th e flare gas pressure at the primary flare exceeds a certain pressure), the final amendments provide a simplified water seal monitoring approach under 40 CFR 60.107a(g) to ensure gas is not sent to the secondary flare. Itis anticipated that any event that causes a release so large as to trig ger gas flow to subsequent flares in the series would trigger a RCA on the primary flare. The ro ot cause of the flaring event for the back-up flares would be the same as the primary flare, so it would be redundant to require additional RCA for the back-up flares. Therefore, the fina l amendments do not requ ire duplicative RCA for the secondary flare if a RCA is triggered for the prim ary flare. However, if fl are gas is sent to the secondary flare (as detected by the water seal monitoring) prior to triggering a RCA on the primary flare, then the indication of flow to th e secondary flare automatic ally triggers a RCA for the primary flare. If the interconn ection does not have a water seal or other device that prevents flow to the interconnected flare during nor mal operation, then a new connection to an interconnected flare header system would requi re flow and sulfur monitoring for each flare within the interconnected header system.



### 2.4 Notification Schedule
Comment : Commenter 0295 requested clarification that the 40 CFR 60.7 notifications for construction or startup are not due until the stay is lifted, even if these activities occur during the34 stay. Similarly, Commenter 0311 requested that the 40 CFR 60.108a and 40 CFR 60.7
notifications for construction or st artup be due 60 days after the stay is lifted and the final rule published. Response : Notification for construction and startup should be provided at the time of construction or startup, as applicable. These requ irements existed under subpart J and there is no reason to delay these notifications.



### 2.5 Overlap with and Eff ect on Other Subparts
Comment : Commenter 0311 noted that 40 CFR part 63, subpart UUU (Refinery MACT 2) often references specifi c subpart J requirements, result ing in a refinery potentially having to meet both subparts J and Ja for many sources. Commenter 0311 suggested adding the following sentence to 40 CFR 60.100a(e) of subpart Ja: “Owners or operators may also choose to comply with the applicable provis ions of Subpart Ja of this part to satisfy the requirements of Part 63 Subpart UUU of this chapter, where Subpart UUU references this subpart J or individual sections of this subpart.” Response : While we understand the desire to allo w compliance with subpart Ja to fulfill the requirements of Refinery MACT 2, it is in appropriate to effectively put the suggested Refinery MACT 2 alternative in subpart Ja. It is much more appropr iate to include this alternative directly in subpart UUU. Refinery MACT 2 is currently unde r review, and we intend to include subpart Ja as a compliance option fo r subpart UUU (where appropriate) in future amendments to subpart UUU.
Comment : Commenters 0304 and 0311 supported the EPA’s proposal at 40 CFR 60.100(e) of subpart J to a llow affected sources subject to subpart J to elect to comply with the corresponding provisions of subpart Ja. However, Commenter 0304 requested
clarification as to whether the “election” is only available on a “whole refinery” basis or if the
election can be made on an “affected source” basis. Response : The election would be made on an indivi dual affected facili ty basis, not the entire refinery. For example, if a facility has two FCCU subjectto subpart J requirements, the owner or operator may elect to comply with s ubpart J requirements for on e FCCU and subpart Ja requirements for the second FCCU.35 Comment : Commenter 0309 recommended that the EPA explicitly include in subpart J the fuel gas H 2 S concentration limit in units of ppmv that is equivalent to 230 milligrams per dry standard cubic meter (mg/dscm) (as it did in subpar t Ja), since concentration is measured in units of ppmv and the proper conversion has been a source of significant debate. Response : We specified the fuel gas combustion device H 2 S concentration limit in subpart Ja in units of ppmv because the continuous monitors used to demonstrate compliance generally output the H 2 S concentration in ppmv. We expect th at the inclusion of the short-term 162 ppmv H 2 S concentration limit in subpart Ja should help to resolve debates about the proper conversion. However, we decided not to specifica lly include this limit in subpart J because many permits specify the H 2 S concentration limit in terms of ppmv and the concentration limits in these existing permits may range from 160 to 164 ppmv. We did not want to require repermitting of these facilities, reprogramming of monitoring equipment and/or potential retroactive non-compliance issues that could occur with this “new” emissions limit if we had specified the H 2 S concentration limit as 162 ppmv in subpart J.
Comment : Commenter 0311 stated that 40 CFR part 63, subpart LLLLL indicates at 40 CFR 63.8681(e) that subpart J do es not apply for asphalt blowi ng stills subject to subpart LLLLL. The commenter requested similar clarifica tion for subpart Ja by exempting this process
in 40 CFR 60.100a. Response : We reviewed the requirement in 40 CFR part 63, subpart LLLLL. Due to the oxygen (O 2 ) content of this process gas, we agree that it is not suitable for recovery as fuel gas and subsequent amine treatment; therefore, it is not BSER for combustion controls used on asphalt blowing stills to meet the H 2 S concentration limits (or alternative SO 2 emissions limits). We reviewed 40 CFR 60.100a, but we feel a blanket exemption from 40 CFR part 60, subpart Ja is not necessary. Instead, we have included an exem ption within the definition of fuel gas similar to the exemptions included for combustion cont rols on vapors collected and combusted from
wastewater treatment and marine vessel load ing operations. Specifically, we amended the definition of fuel gas in 40 CFR 60.101a to clarify that fuel gas does not include vapors that are
collected and combusted to control em issions from asphalt processing units ( i.e. , asphalt blowing stills).36 

### 2.6 Equivalence with State and Local Rules
Comment : Several commenters addressed the EPA’s request for comment on “the equivalency of the subpart Ja requirements as proposed to be amended today and the [South Coast Air Quality Management District (SCA QMD) Rule 1118]” and “whether the EPA could deem a facility in compliance with subpart Ja as proposed to be amended today if that facility was found to be in compliance with SCAQMD Ru le 1118, or other equivalent State or local rules” (73 FR 78532, December 22, 2008). Commente r 0307 disagreed with the EPA’s position, alleging that the “EPA’s suggestion that it can waive compliance with the NSPS in this manner is contrary to the Clean Air Act.” The commenter stated that the EPA’s suggestion “that existing state and local requirements render the federal re quirements irrelevant only confirms that EPA’s proposed flaring requirements do not reflect the besttechnological system of continuous emission reduction.” 42 U.S.C. §7411(h)(1) (empha sis added). The commenter also stated that the CAA already provides a mechanism for im plementation of alternative work practice standards in narrowly defined ci rcumstances (42 U.S.C. §7411(h)(3 )); an owner or operator may
demonstrate to the Administrator that an alternat ive means of emissions limitation is equivalent to the federal standard and request permission to comply with the alternative method in lieu of the federal standard. Therefore, the commenter a sserted, the CAA clearly states that the “EPA’s authority to waive federal work practice standards is case specific.” Finally, the commenter stated that the EPA did not explain how emi ssions reductions achieved through compliance with SCAQMD Rule 1118 are equivalent to subpart Ja. Further, the commenter asserted that the EPA
neither identified other state ru les that could be considered eq uivalent, nor e xplained how the EPA would determine that a specific state or local rule is equivalent to subpart Ja. Therefore, the commenter stated, it is impossible to fully a ssess the merit of the EPA’s idea and provide meaningful comments. Commenter 0315 responded to Commenter 0307’s comments. Commenter 0315 noted that it appears that Commenter 0307 argues that if state regulations are more stringent than the proposed requirements for subpart Ja, then the subpart Ja proposed requirements cannot be “best” demonstrated technology. The commenter st ated that the existen ce of more stringent control measures is not per se fatal to an EP A BSER determination because “most stringent” is not the criteria that must be applied under the law to determine BSER. In response to Commenter 0307’s statement that the EPA must grant permi ssion to use alternative methodologies on a case-37 by-case basis, Commenter 0315 stated that the EP A has full authority to establish alternative regulatory standards that are determined to be as stringent as or more stringent than BSER. The commenter noted that CAA section 111(h)(3) gene rally applies after the EPA has completed a national rulemaking and an owner or operator requests approval for a site-specific alternative at a later date. In this instance, it is logical that, if an alternat ive method is identified during the rulemaking process, “...the law would allow EPA to establish a site-specific alternative [in the rule itself] (especially, as under [CAA section 11 1], where the alternative would have to be determined through notice and comment rulemaking – which, in essence, requires EPA to amend the regulation to accomplish the site-specific a lternative).” Finally, Commenter 0315 noted that
Commenter 0307 did not consider the documents on record for the original proposal of subpart Ja, which demonstrate that the subpart Ja flare requirements are based on and almost entirely consistent with SCAQMD Rule 1118. The commenter noted that the EPA determined that SCAQMD Rule 1118 constituted BSER fo r flares and designed subpart Ja so that affected flares would be subject to similar requirements. Commenters 0304, 0306 and 0311 recommended th at refineries complying with California flare rules, speci fically SCAQMD Rule 1118 (Commenters 0304 and 0311) and Bay Area Air Quality Management Distri ct (BAAQMD) Regulation 12-12 and 12-11 (Commenter 0311) be deemed in compliance with subparts J and Ja. According to Commenter 0304, SCAQMD Rule 1118 is “in all respects equivalent to ormore stringent than the corresponding requirements” of subparts J a nd Ja. Although Commenter 0311 did note that the FMP in SCAQMD Rule 1118 is only required for f acilities that fail to achieve sulfur oxides (SO X ) emission reduction targets, the commenter asserted the subpartJa FMP provided no greater emission reduction incentive or mechanism than the SCAQMD Rule 1118. Commenter 0311 recommended that the EPA add a paragraph (e ) to 40 CFR 60.103a that states: “Local rules that are equivalent to these work practice sta ndards (Section 60.103a) sati sfy the requirements of this section, including South Coast AQMD Ru le 1118 and Bay Area AQMD rules 12-11 and 12- 12.” The commenter also requested a similar paragraph be added to 40 CFR 60.107a(e) to allow the monitoring methods used in SCAQMD Ru le 1118 and BAAQMD Regulation 12-12 and 12- 11 to be acceptable under subpart Ja. Commenter 0315 provided a table comparing eac h of the six proposed FMP requirements in 40 CFR 60.103a(a) to the SCAQMD and BAAQ MD regulations. The commenter’s table38 identified sections of BAAQM D Regulation 12-12 and 12-11 thatare equivalent to the six subpart Ja FMP requirements, but the commen ter also noted that SCAQMD Rule 1118 is only equivalent to five of the proposed requirement s; it does not require an owner or operator to identify procedures to reduce flaring in cases of fuel gas imbalance (although Commenter 0311 noted that SCAQMD Rule 1118 requires minimi zation of all flaring, including fuel gas imbalance). Based on this information, the comment er stated that facili ties already complying with SCAQMD Rule 1118 or BAAQMD Regula tion 12-12 and 12-11 are already meeting requirements equivalent to or mo re stringent than BSER, so thes e facilities should not have to meet different requirements under subpart Ja. Commenter 0315 also noted that BAAQMD Re gulation 12-11 allows periodic sampling,
and the commenter stated that for flares used mostly for startup, shutdown and upset/malfunction (SSM) events, a sampling system accurately calcul ates the total sulfur emissions, is relatively cost effective and is more reliable than the continuous composition monitors in use for this purpose. Therefore, the commenter requested that the EPA consider BAAQMD Regulation 12- 11 to be equivalent to total su lfur monitoring for SSM flares. Response : First, we note that th ere seems to be some mis understanding regarding how a determination that SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 are equivalent to 40 CFR part 60, subpart Ja would actually be implemented in subpart Ja. The EPA will not “waiv e” the obligation to comply with subpart Ja if the source is complying with SCAQMD Ru le 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12. In other words, the EP A will not allow the owner or operator to “choose” to comply with SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 instead of subpart Ja. Rather, the source must always demonstrate compliance with subpart Ja. If SCAQMD Ru le 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 are determined to be equi valent to subpart Ja, then these requirements would be provided as an alternat ive within subpart Ja for the s ource to demonstrate that it is meeting the requirements of subpart Ja. To assess the comments, we reviewed SCAQMD Rule 1118, BAAQMD Regulation 12, Rule 11, and BAAQMD Regulation 12, Rule 12 and compared these rules to the 40 CFR part 60, subpart Ja requirements we are finalizing. We ha ve included documentati on of this review in Docket ID No. EPA-HQ-OAR-2007- 0011 that shows the sections of each of those rules that we39 consider are equivalent to the subpart Ja re quirements. We determined that SCAQMD Rule 1118 and BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 will result in equivalent to or greater than the emissions reduc tions resulting from the subpartJa FMP requirements. As a result of our analysis, we have amended subpart Ja, as described in the following paragraphs. We determined that SCAQMD Rule 1118 is eq uivalent to the flare requirements and monitoring, recordkeeping and re porting provisions for determin ing compliance with the flare requirements in 40 CFR part 60, subpart Ja. We also determined that the combined provisions of BAAQMD Regulation 12, Rule 11 and BAAQMD Re gulation 12, Rule 12 are equivalent to the flare requirements and monitoring, recordkeep ing and reporting provisions for determining compliance with the flare requirements in subpa rt Ja. Therefore, we have added specific compliance options for flares that are located in the SCAQMD and are in compliance with SCAQMD Rule 1118, as well as for flares that are located in the BAAQMD and are in compliance with both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12. Flares that are in compliance with these alternative compliance options are in compliance with the flare standards in subpart Ja. Specifically, 40 CFR 60.103a(g) specifies that flares that are located in the SCAQMD may elect to comply with SCAQMD Rule 1118 and flares that are located in the BAAQMD may elect to comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulati on 12, Rule 12 to comply with the FMP requirements of 40 CFR 60.103a(a) and (b) and the RCA and correctiv e action analysis requirements of 40 CFR 60.103a(c) though (e). In addition, 40 CFR 60.107a (h) indicates that
flares that are located in the SCAQMD may elect to comply with the monitoring requirements of SCAQMD Rule 1118 and flares that are located in the BAAQMD may elect to comply with the combined monitoring requirements of both BAAQMD Regulation 12, Ru le 11 and BAAQMD Regulation 12, Rule 12 to comply with the m onitoring requirements of 40 CFR 60.107a(e) and (f). The owner or operator must notify the Administrator, as specified in 40 CFR 60.103a(g), that the flare is in compliance with SC AQMD Rule 1118 or both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12. The owner or operator must also submit a copy of the existing FMP (if applicable), as specified in 40 CFR 60.103a(g). We note that, as pointed out by commenters, an owner or operator maintains the ability under CAA section 111(h)(3) to submit a request to establish, on a case-by-case basis, that “an
alternative means of emission limitation will achieve a reduction in emissions... at least40 equivalent to the reduction in emissions” achie ved under the flare standards of 40 CFR part 60, subpart Ja. Pursuant to CAA section 111(h)(3), we also included specific provisions within 40 CFR 60.103a for owners or operators to su bmit a request for “an alternative means of
emission limitation” that will achie ve a reduction in emissions at l east equivalent to the reduction
in emissions achieved under the final standards in subpart Ja.41 

## 3.0 DEFINITIONS

3.1 Air Preheat
Comment : Commenter 0311 stated that the definition of “air preheat” is not used in the
rule and should be deleted. Response : The term “air preheat” is used within the definition of “forced draft process
heater” so we have retained the definition in the final amendments.



### 3.2 Co-Fired Process Heater
Comment : Commenters 0308 and 0311 stated that the definition of “co-fired process
heater” should be revised to remove the referen ce to “burners that are designed” to be supplied by both gaseous and liquid fuels because co-fired process heaters almost always use different burner tips. The commenters recomme nded: “Co-fired process heater means a process heater designed to be supplied by bot h gaseous and liquid fuels.” Response : It appears that there is some confus ion regarding what is meant by “burners”
within this definition. We intended that a “burner” refers to each locati on in the process heater designed to produce a flame to impart heat to the system. A single bu rner that is designed to be supplied with both gaseous and liquid fuels is exp ected to have separate burner tips within the burner, but both burner tips are pa rt of the single burner location. If a process heater has some burners that can only be fired with gaseous fuels and other bur ners that can only be fired by liquid fuels, these process heaters are not considered co-fired pro cess heaters. The gas burners in such a process heater can employ ultra-low NO X burners capable of meeting the emissions limit in the same manner as conventional gas-fired pr ocess heaters, and these process heaters should demonstrate compliance with the rule when firi ng only with the gas burne rs. Burners that are designed with multiple tips (so that the single bu rner can be supplied by both gaseous and liquid fuels) have different de sign considerations, because staged fu el is generally needed for reducing
NO X in gas-fired burners, where stag ed air is used to reduce NO X in oil-fired burners. These burners ( i.e. , those with both types of burner tips in th e same burner) cannot be designed to stage both air and fuel. As such, these burners can be either designed for staged air to limit NO X while42 firing oil but will have conventiona l gas-fired burners, or the burne rs can be designed for staged
fuel to limit NO X when firing gaseous fuels but will have conventional burners for fuel oil. If a process heater has completely separate burners , some dedicated for gaseous fuels and some dedicated for liquid fuels, each individual burner could be designed and optimized for its fuel type. As such, we determined that it is inappropr iate to revise the defini tion of co-fired process heater as requested by the commenter. Furthermor e, we find that gas-fire d process heaters that have emergency oil back-up burners in the even t of a natural gas curt ailment should employ gas burners that are optimized for firing gas using staged fuel ultra-low NO X burners because they do not routinely fire oil. Therefore, we revised the definition of co-f ired process heaters to clarify that co-fired process heaters are process heaters that are designed to be supplied by both gaseous and liquid fuels on a routine basis. We further clar ify in the definition thatprocess heaters that have gas burners with emergency oil back-up burner s are not considered co-fired process heaters. We clarify in this response that a process heat er that contains gas bur ners with emergency oil back-up burners must comply with the NO X limits for conventional ga s-fired process heaters.



### 3.3 Corrective Action Analysis
Comment : Commenter 0305 stated that the definition of “corrective action analysis”
should not include the word “all” because it places unnecessary burden on the facility to document “all” potential corrective actions (and subjects the facility to liability if it does not include all possible actions) rather than focusing on the most promising. Response : We disagree that the proposed de finition of “corrective action analysis” requires the facility to describe “all” potential corrective actions or otherwise puts undue burden on the refinery owner or operato r. The actual definition requires “a description of all reasonable interim and long-term measures.” The inclusion of the word “reasonable” modifies and limits the term “all.” The phrase “all reasonable” clarifie s the requirements to pe rform a comprehensive analysis while limiting the need to document unreasonable measures. Deleting the word “all” is unlikely to alter the agency’s interpretation of the requirement, and only acts to make the requirement less clear. Therefore, we respectfully disagree with the commenter and retain this portion of the definition of “corrective action analysis” as proposed.43 

### 3.4 Delayed Coking Unit
Comment : Commenters 0305 and 0311 supported the revised definition of “delayed coking unit” but stated that, since subpart Ja only sets standards for the coke drums, the definition should just include the coke drums associated w ith a single fractionator. The
commenters stated that the defi nition should not include the fr actionator itself because VOC emissions from the fractionator are covered by NSPS for equipment leaks. Response : The proposed amendments to the de finition of “delayed coking unit” specifically listed the primary components of the delayed coking unit. In particular, based on the operation of the delayed coking unit, we find that the fractionator is an integral part of the delayed coking unit. The fresh feed to the dela yed coking unit is genera lly introduced in the fractionator tower bottoms receiver. This integral use of the fractionator is different than the use
of fractionators used for other units defined in 40 CFR part 60, subpart Ja, such as the FCCU. For the FCCU, fresh feed is introduced in the rise r, which is part of th e affected facility in subpart Ja. As the feed to the delayed coking unit is to the fractiona tor, we find that the fractionator is an integral part of the delayed coking unit, so we sp ecifically include it as part of the affected facility. While ourproposed amendments covered only the major components of the delayed coking unit, upon our review of the de finition based on the comments received, we note that there are several other components of the delayed coking unit that are integral to the operation of the delayed coking uni t. Additionally, even though the standards are specific to the coke drum, many of these integr al components are interconnected and necessary for the delayed coking unit to meet the applicable standards. Based on our review of the operation of a delayed coking unit, we also include coke cutting a nd blowdown recovery equipment in the final definition because this equipment is also integral to the overall cyclical operation of the process unit. The definition of “delayed coking unit” has been amended in the final rule to read as
follows:

Delayed coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally crackedand petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit includes but is not limited to all of the coke drums associ ated with a single fractionator; the fractionator, including bottoms receiver and overhead condenser; the coke drum cutting water and quench system, includi ng the jet pump and coker quench water tank; process piping and associated equipment such as pumps, valves and connectors; and the coke drum blow down recovery compressor system.44 Since this definition is more specific than the definition included in the amendments proposed on December 22, 2008, it could affect which delayed coking units are subject to subpart Ja. For example, an owner or operator ma y have made a change to a delayed coking unit
that would not be considered a modificati on under the December 22, 2008, definition, but that same change could make the delayed coking unit a modified facility subject to subpart Ja using the definition of “delayed coking unit” above. In other words, in cha nging the definition of “delayed coking unit” in the final rule, some delayed coking units that would not have been affected sources under the proposed requirements might now be covered by the final rule. Under CAA section 111(a)(2), a “new source” is defined from the date of proposal only if there is a standard “which will be applicable to such s ource;” otherwise, a “new source” is defined based upon the final rule date. In this circumstance, us ing the proposal date as the new source date for determining applicability for this group of delayed coking units w ould be inappropriate, as such
units would not have been on noti ce that subpart Ja could apply to them. Accordingly, we moved the “new source” date for this group of delayed c oking units so that delayed coking units that are only defined as such under the final rule are covered by the final rule only if they commence construction, reconstruction or modification after the promulgation date of these final
amendments. The “new source” date for other de layed coking units will depend on the previous
definitions and when the activities involvi ng the delayed coking unit occurred. See 40 CFR 60.100a(b) for determining applicability of subpart Ja for delayed coking units.



### 3.5 Flare
Comment : Commenter 0308 and 0311 recommended deleting “knock-out pots, piping and header system” from the de finition of “flare” because pipi ng and header systems are not “equipment used to combust fuel gas” and should not be part of a fuel gas combustion device. Commenter 0308 stated that, if the EPA retains this expanded definition, then the EPA should clarify that the other fuel gas combustion devices are limited to just the “equipment used tocombust fuel gas” and do not include the fuel gas lines. Commenter 0311 stated that if “knockout pots, piping and header systems” are include d, the flare’s knock-out pot, piping and header system must be clarified since numerous process un its have knock-out pots and nearly all will be connected either directly or indire ctly (via the fuel gas system) to a flare. As such, the entire fuel gas system could be considered part of the fl are header system. The commenter also requested45 that the definition include a primary use clause so as to clarify the affected facility in cases of interconnected flare systems. Commenter 0311 recommended: “Flare means an open-flame fuel gas combustion device used for burning off unwa nted gas or flammable gas and liquids. The flare includes the foundation, flare ti p, structural support, burner, ign iter, flare controls including air injection or steam injection systems, flam e arrestors, and knockout pots, piping and header systems from process units, fuel gas systems or FGR systems to a flare tip. Knockout pots, piping and headers shared among multiple flar es are assigned on a primary use basis.”
Commenter 0315 also stated that the flare s hould not include the pi ping within process units and fuel gas systems. The commenter reco mmended that the EPA cl early differentiate the boundary between the refinery proc ess unit, the fuel gas system and the flare. The commenter
noted that main lines from indi vidual refinery process units and fuel gas systems to flares are generally equipped with battery limit isolation valves, and thes e valves define the “battery limits” of the process unit or fuel gas system. The commenter recommended that the EPA revise
the flare definition to state that : (1) a “flare” includes only th e knockout pots, piping and headers outside of a process unit’s or fuel gas system’s battery li mits; and (2) any new piping or connections that are made inside the process un it's or fuel gas system’s battery limits are not
modifications to the flare. The commenter noted that new piping that is added outside of the process unit’s battery limits or the fuel gas syst em that either results in a new connection from the process unit or fuel gas system to the flar e or increases the capacity of an existing flare system to handle more flow ( e.g. increasing the size of a flare h eader or a knock out pot) would
be a modification to the flare. The commenter provided a diagram of an example refinery to illustrate their points. Response : We agree that a clarification is neededto distinguish between the flare header system and the fuel gas system. We have added a definition of “flare gas header system” to clarify this issue; see the respons e to the next comment for further details. We have also listed flares as a completely separate affected facili ty, so we do not believe a clarification to the definition of fuel gas combustion device is needed to specifically state that the fuel gas system is not part of the fuel gas combustion device. With respect to interconnected flare systems, we disagree that a primary use clause is needed because we determined that each flare in an interconnected flare system is modified when a connection meeting those defined for a flare modification is made to such a system. Please see Section 2.3 of this docum ent for more details.46 Comment : Commenter 0313 requested that the de finition of “flare” include the FGR system. The commenter noted that in the BAAQMD , the flare header collects both the episodic gas that needs to be sent to the flare device for safe disposal as well as the routine gas that is sent back to the refinery fuel gas system. The comme nter noted that refine rs in the BAAQMD are submitting permit applications asserting that all fl are header systems upstream of the seal pot are separate from the flare because during normal operation, these flare headers serve to collect the gas that is redirected to the fuel gas system by the FGR system. The commenter noted that this interpretation seems inconsistent with the EPA’s stated intention in the preamble to the proposed amendments to include the flare gas header syst em in the definition of “flare.” The commenter stated that the EPA should explicitly include th e FGR system in the definition to eliminate any confusion and clarify the agency’s intent. Response : We have added a definition to clarify wh at is included in the flare gas header system. We specify that all piping used to transport gas to a flare either directly from a process unit or directly from a pressure relief valve from the fuel gas system is part of the flare gas header system, regardless of whether or not th e flare gas header system includes a FGR system ( i.e. , regardless of whether or not a FGR system draws gas from the flare gas header system).
Consistent with this defini tion, we note that if a FGR system is pr esent, it is considered to be part of the flare gas header system.



### 3.6 Fuel Gas
Comment : Commenters 0304, 0305 and 0311 supported the amended definition of “fuel gas” as it pertains to coke calciners. Commenter 0304 suggested the same amendment be made to the definition of fuel gas in subpart J. Commenters 0305 and 0311 suggested that the definition be clarified to list all types of premium coke (specifically re carburizer coke, needle coke and metallurgical coke) in addition to anode grade coke. Response : We agree that the final disposition of the premium grade coke is not important and have generalized the parenthe tical to simply read “used to make premium grade coke.” As any new, modified or reconstructed fuel gas combustion device will be subject to subpart Ja rather than subpart J going forwar d, there is no need to revise the definition of fuel gas in subpart J at this point in time.47 Comment : Commenter 0309 suggested that the exclus ion in the definition of “fuel gas” be extended to vapors combusted to comply w ith the storage vessel requirements in 40 CFR 60, subparts K, Ka, Kb (NSPS for storage vesse ls) and 40 CFR part 63, subpart CC (Refinery MACT 1) because these are low pressure vapor st reams and most have low sulfur content. The commenter stated that at least certain storage vessels (reformate, alkyla te, gasoline) should be exempt due to low sulfur content. Response : We disagree that the definition of fuel gas should exclude vapors from storage vessels. While some storage vessels may be remo tely located, many of these storage vessels are located near refinery process units or each othe r so that combined collection and, if necessary, treatment of the gases can be acco mplished cost effectively. The cu rrent provisions in subpart Ja (and subpart J) contain an exemption from the continuous H 2 S monitoring requirements for gases that are inherently low sulfur or can be dete rmined to be low sulfur. As such, the current provisions for low sulfur fuel gas adequately ad dress the commenter’s issue without needing to exempt certain types of storage vessel s from the definition of fuel gas.
Comment : Commenter 0311 recommended that the ex clusion from the definition of “fuel gas” be extended to vapors “from marine vesse l loading operations or waste management units
that are collected and co mbusted” without any reference to a federal requirement. At a minimum,
Commenter 0311 stated that marine benzene loading under 40 CFR part 61, subpart BB; the wastewater provisions of 40 CFR part 63, subpart G; reme diation efforts regulated under Resource Conservation and Recovery Act (RCR A) corrective action; and RCRA 7003 orders
should be added to the exclusion. Response : We were originally concerned that removing the reference to a federal standard may inadvertently exempt the use of these vapors when used in process heaters or
boilers. We determined that it was not BSER to require thermal oxidizers used to comply with the cited federal standards to comply with the H 2 S concentration limits due to the typically
remote location of the combustion so urces (control devices) relative to refinery process units (see
technical memorandum entitled Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment Unit Off-gas , in Docket ID No. EPA-HQ-OAR- 2007-0011). However, if these gases are currently routed to a fuel gas system or directly to a process h eater or boiler, treatment of the fuel gas to meet the SO 2 emissions limits or the H 2 S concentration limits is expected to be economically viable. Additionally, these gases are e xpected to be only a small portion of the fuel48 gas combusted in these units, and the refinery has an option to over-treat the primary fuel gas so that gases from the wastewater treatment system or marine vessel loading operation can remain untreated while the fuel gas combustion device itself can comply with the SO 2 emissions limits
or the H 2 S concentration limits, based on the mixt ure of fuels used in the device. In reviewing the rules suggested by the commente r, as well as those we originally listed, we noted that acceptable “control devices” or “co mbustion units” in these rules include process
heaters and boilers. We did not intend to excl ude vapors that are colle cted and routed to a process heater or boiler to be exempt from the definition of fuel gas. In other words, when developing this exclusion, we speci fically considered the combusti on of these gases via a thermal
oxidizer or flare currentl y located at the marine vessel loadin g or wastewater treatment location. These remote combustion devices were really the s ubject of the analysis, but we did not want to
exclude these combustion units themselves because other fuel gas is often fed to these units to ensure adequate combustion of the vapors being c ontrolled. It is clear from our rationale and the description of the exemp tion included in the preamble of th e proposed rule that the exemption was intended “to exempt vapors that are collected and combusted in an air pollution control
device installed to comply with” specific wastewater or marine vessel loading emissions standards. (72 FR 27180 and also at 27183; emphasis added.) Pro cess heaters or boilers would not be “installed” to comply with these provisi ons, and it was not our intent to exclude vapors sent to these types of combustion units. Howeve r, the regulatory text is more ambiguous and appears to exclude any vapors collected and comb usted, regardless of where they are combusted. As such, we are amending this exclusion to better represent our original intent. Additionally, with the added clarity in the re gulatory text, it seems appropriate to extend
this exclusion to contro l devices used at these locations regardless of why the emission controls were installed. That is, while we originally co nsidered air pollution control devices that were mandated by the EPA, we see no reason to discrimi nate against air pollution control devices that were installed voluntarily to reduce the emissions from these sources. Further, we intend to clarify that gases off the sour water system, including the sour water stripper, would likely contain higher amounts of reduced sulfur and woul d be economically viable to treat. Therefore, we are also clarifying that the exemption does not extend to the s our water system. Therefore, the amended definition of “fuel gas” in both 40 CFR pa rt 60, subparts J and Ja states that fuel gas “does not include vapors that ar e collected and combusted in a th ermal oxidizer or flare installed49 to control emissions from wastewater treatment units other than those processing sour water, marine tank vessel loading operati ons or asphalt processing units ( i.e. , asphalt blowing stills).” With respect to remediation efforts conduc ted under RCRA corrective actions, we are unwilling to grant such an exclusion from the definition of “fuel gas” in 40 CFR part 60, subpart Ja. First, we anticipate that most vapors from remediation efforts would be low in sulfur and, if so, the owner or operator could apply fo r the alternative monitoring methods provided in the rule. Also, although some remediation efforts may occur in remote locations, many of the
remediation efforts are conducted in reasonable proximity to exis ting process units. Finally, the range of activities included in RCRA remediation e fforts is broad, and we have little information regarding the number and types of RCRA remedi ation activities that are being conducted. The commenter provided no description of such activities, nor did they provide a reasonable rationale as to why the vapors from these activities should be exempted.
Comment : Commenter 0311 noted that the refe rence to 40 CFR 60.692 was missing in the revised definition of “fuel gas” and that “through” was misspelled. Response : We appreciate the comment and acknowle dge that the proposed definition did
include an inadvertent error. We have removed th e section that contained the error from the final
definition.



### 3.7 Fuel Gas Combustion Device
Comment : Commenter 0308 recommended that the EP A delete flares from the definition of “fuel gas combustion devices” an d create a separate affected f acility covering only flares so that flares can be regulated in a targ eted, coherent and consistent fashion. Response : We agree. Due to the numerous special definitions and standards that apply to flares, we determined that the requirements for flares and for fuel gas combustion devices would be clarified if fuel gas combustion devices and flar es were defined as separate affected facilities. Therefore, the final rule defines a flare as an affected facility rather than including flares as a type of fuel gas combustion device.
Comment : Commenter 0305 suggested clarifying th e definition of “fuel gas combustion device” to clarify that the fuel gas combustion device is located at the petroleum refinery. Response : We do not agree that the requested cl arification is nece ssary. A fuel gas combustion device is defined as “any equipment, such as process heater s and boilers, used to50 combust fuel gas.” Section 60.100a(a) states that “the provisions of this subpart apply to” fuel gas combustion devices (including process heaters) “ in petroleum refineries ” (emphasis added). Therefore, the final rule already specifies that a fuel gas combustion device must be located at a petroleum refinery to be an aff ected source subject to subpart Ja. We do note that the definition of “fuel gas” is “any gas which is generated at a petroleum refinery and which is combusted.” The definiti on does not specify that fuel gas must be combusted at a petroleum refinery, and it is not our intention for th at definition to be interpreted
as such.



### 3.8 Natural Draft and Forced Draft Process Heaters
Comment : Commenter 0296 indicated that there are four classes of pr ocess heaters and it
is unclear whether balanced draft or induced draft process heaters are considered natural draft or forced draft process heaters. Th e commenter suggested that the EP A should clarify the definition of “forced draft process heater ” to include these c onfigurations. Commenter 0305 also requested
clarification that induced draft process heaters are considered forced draft process heaters. Commenter 0311 noted that in general, induced draft fans do not affect process heater NO X controls, but for process heaters with downwardly firing burners, the induced draft fan is used to move the combustion gases through the entire process heater, not just the convection section, and those process heaters experience NO X control issues similar to forced draft process heaters. As such, Commenter 0311 recommended that “process heaters with downward firing burners that are equipped with an induced draft fan” be incl uded in the definition of “forced draft process
heater.” Commenter 0311 also re quested that the definition be clarified based on the design rather than the operation. The commenter noted that operators of some forced draft process heaters may shut down the fan to perform mainte nance on the fan or preheat system while still operating the process heater and requested clarification on whethe r the process heater is still subject to the forced draft process heater NO X limits during those periods. Response : There are essentially four types of pr ocess heaters: (1) na tural draft process heaters with no fans; (2) induced draft process heaters with a fan on the exhaust line; (3) supplied draft process heaters with a fan on the inlet ai r (more commonly referred to as forced draft process heaters); and (4) balanced draft process heaters with fans on both the inlet air and on the exhaust air (typically used for air preheat). The de finition of forced draft process heater clearly51 includes both “supplied draft” and “balanced draft” process heaters as these systems have fans in the inlet air line prior to the air entering the process heater or air preheat. The definition of forced draft process heater just as cl early excludes induced draft process heaters because these process
heaters do not have a fan in the inlet air line. The definition of natural draft process heaters includes induced draft process he aters because induced draft proc ess heaters do not have a fan on the inlet air ( i.e. , they are not “forced draf t” process heaters). Nonetheless, the definitions are somewhat confusing given the inclusion of “unde r positive pressure” for forced draft systems and “under ambient pressure” for natural draft syst ems. We have clarified these definitions to more clearly indicate that, for the purposes of s ubpart Ja, balanced draft systems are considered forced draft process heaters a nd induced draft systems are considered natural draft process
heaters. The commenters provided no direct data on “d ownwardly firing burners ” or specifics as to why these units could not meet the 40 ppmv NO X emissions limit. Based on the operations of these burners, we think that they can meet the sa me limits as natural draft units, but given the lack of data for this argument, we have includ ed downwardly firing induced draft burners in the list of process heaters that thatmay apply for a site-specific NO X emissions limit. If a process heater equipped with downwardly firing burners is modified or reconstructed, the owner or operator of the process heater should strive to meet the 40 ppmv emissions limit but may apply for a site-specific emissions limit if the process heater cannot meet that limit.
We intended the emissions limits and the defini tions of the process he aters to be based on the operation of the heater (except for co-fired pr ocess heaters, the definition of which is design based). According to comments received, incl uding design performance levels from low-NO X burner vendors for process heaters that are design ed to operate in both natural draft mode and forced draft mode, the burners can achiev e the 40 ppmv (or 0.040 pounds per million British thermal unit [lb/MMBtu]) NO X emissions limit while operating under natural draft conditions even though it cannot meet this limit while operating in the fo rced draft mode, specifically because of the higher inlet air temperatures when using air preheat. Based on the available information, we conclude that the natural draf t emissions limit is appropriate and BSER when the process heater is operating in natural draft mode even if the un it is “designed” to operate as a forced draft process heater. Ther efore, we made no changes to th e definitions of “forced draft process heater” and “natural draft process heater” as a result of this comment.52 

### 3.9 Process Upset Gas
Comment : Commenter 0303, 0305, 0306, 0308 and 0311 supported the amended definition of “process upset gas” to include star tup and shutdown and stated that the FMP is effective in reducing SSM emissions. Commente r 0315 provided specific examples of planned startups and shutdowns in which flaring is nece ssary for the proper operation of the unit and the process train. Commenter 0302 requested that the definition of “process upset gas” include “gas generated during periods when the fuel gas desu lfurization system is down for maintenance in
accordance with the manufacturer’s recommendations and good ope rating practices” as it is unclear if these maintenance periods can be consid ered “malfunctions.” If this provision in not provided, the EPA should revise it s cost analysis to include b ack-up desulfurization systems,
which would be needed if thes e periods cannot be excluded. On the other hand, Commenter 0313 requested th at the EPA not finalize the addition of planned startups and shutdowns to the definiti on of “process upset gas. ” The commenter stated that planned startups and shutdowns are a majo r cause of flare emissions, and unlike emergency situations, refineries have the ability and res ources to mitigate flare emissions during a planned event. If the EPA adds startup and shutdown to the definition, then a large amount of the
emission reductions associated with subpart Ja will not be re alized. In a subsequent letter (Comment 0316), the commenter clar ified this comment, noting that while many refineries in the BAAQMD have found alte rnatives to flaring during pla nned startups and shutdowns by modifying the design of new flares, it may not be possible for all new flares to be designed to avoid flaring during all startups and shutdowns. The comment er also noted that BAAQMD Regulation 12-12 is based on a FMP approach. The commenter stated that if the EPA concludes that it is not reasonable to prom ulgate the fuel gas combustion device sulfur standards for new flares as originally proposed ( i.e. , if startup and shutdown gases ar e included in the definition of process upset gas), then the FMP approach woul d be an alternative way to address flaring emissions from startups and shutdowns th at would provide significant benefits. Response : The only impact of including startup and shutdown gases within the definition of process upset gas is to ex clude these gases from the H 2 S concentration requirement. As an example, the planned shutdown of a reactor ve ssel usually involves purging the vessel with nitrogen. After the first few purge sequences, the purge gas may have very little Btu content, so that the gas cannot be recovered in the fuel gas system, but the ga s may contain concentrations of53 H 2 S that exceed 162 ppmv, depending on the reactor ve ssel contents. Flaring this gas to destroy
H 2 S is the best environmental practice, and it is notfeasible to recover this gas, nor is it cost effective to treat this gas separately to reduce its H 2 S concentration to below 162 ppmv. Therefore, we cannot conclude that requiring refiners to limit the short-term fuel gas concentration to 162 ppmv H 2 S determined hourly on a 3-hour ro lling average basi s is BSER for planned startup or shutdown for all refinery proc ess units at a petroleum refinery. However, we have placed requirements on the flares to addr ess releases during star tups and shutdowns. The FMP effectively addresses flare flow from planned startup and s hutdowns as it requires minimization of the amount of gas dischargedto a flare under 40 CFR 60.103a(a)(5). The rule also requires RCA to be performed if more th an 500 pounds (lb) of SO 2 are discharged from a flare in a 24-hour period under 40 CFR 60.103a(c), a nd this requirement applies to process upset gas (including planned startup a nd shutdowns that do not follow the procedures in the FMP). 7 These requirements effectively limit discharges of planned startup and shutdown gases to the flare, and these provisions in subpart Ja are e xpected to yield signifi cant emission reductions compared to the requirements in subpart J. C onsequently, we conclude that the inclusion of startup and shutdown gases in the definition of “p rocess upset gas” is nece ssary and aligned with our BSER assessment for flares, a nd that the BSER for startup and shutdown events is a standard for flares that requires the owner or operator to have and follow a FMP and to perform root cause and corrective action analyses when these procedures are not followed. With respect to maintenance of fuel gas desu lfurization units, we fi nd that the fuel gas
desulfurization unit is a control de vice used to meet the fuel gas standards. Continuing to operate fuel gas combustion devices unabated when the control system for fuel gas is down for any reason, including maintenance, startup, shutdown, malfunction or upset, is inconsistent with good air pollution control practices. The requested maintenance exemptions are not in subpart J, which is the baseline case for the cost analysis . Additional treatment capacity needed for these cases is expected to exist under subpart Ja; our cost analysis c onsidered the additional costs of complying with subpart Ja ( i.e. , the additional long-term 60 ppmv H 2 S concentration limit) that were in addition to those costs already imposed due to subpart J requirements. In our cost analysis, we did assume some units would not have enough existing excess capacity to meet the

7 While we expect that most process upset gas will be combusted in flares, it is important to note that the rule also requires RCA to be performed if SO 2 emissions exceed the short-term 162 ppmv H 2 S concentration limit for a fuel gas combustion device by more than 500 pounds.54 long-term 60 ppmv H 2 S concentration limit, and would have to install additional amine treatment systems. We conclude that the cost analys is conducted for fuel gas combustion devices adequately reflects the incremental costs of s ubpart Ja. Therefore, the final amendments to subpart Ja do not include the requested maintenance exemption.
Comment : Commenter 0308 suggested that “startup” be used in the definition of “process upset gas” (rather than “start -up”) to conform with the term “startup” in 40 CFR 60.2. Response : We agree that “startup” is consistent with the General Pr ovisions of 40 CFR part 60, and it appears more frequently than “s tart-up” throughout subpa rt Ja. For consistency,
we have revised the occurrences of “start-up” to read “startup.”



### 3.10 Refinery Process Unit
Comment : Commenters 0305 and 0311 objected to the change to the definition of “refinery process unit” to include coke gasification, loading and wa stewater treatment, stating the change makes the term more expansive. The comme nters stated that the EPA did not evaluate the impacts or explain the consequen ces of the revised definition. Commenter 0311 also stated that product loading is generally consider ed part of the refinery proce ss unit to which it is associated and wastewater treatment is a utility. Commente r 0305 suggested that the definition specify SIC 2911 (as in Refinery MACT 1). Response : The original definition of “refinery pr ocess unit” in 40 CFR part 60, subpart J and the definition of “refinery process unit” promulgated in 40 CFR pa rt 60, subpart Ja in
June 2008 read as follows: “Refin ery process unit means any segmen t of the petroleum refinery in which a specific processing operation is conducted.” Thus, to be considered a refinery process unit, only two criteria are needed: (1) the unit must be located at a petroleum refine ry; and (2) the unit must be used to conduct “a specific proce ssing operation.” The definition does not directly limit the scope of “processing operations.” That is , the definition of refinery process unit does not limit process operations to distillation, re-dis tillation, cracking or reforming, and it is not limited to only those processes used to produce gaso line, kerosene, fuel oils , etc. In the proposed amendment to this definition, we listed “operatio ns” that we construed as conducting a “specific processing operation” when these operations are located at a petroleum refinery. Consequently, we considered the proposed inclusion of examples of refinery process units to be a clarification of the existing definition rather than an expansion of the original definition.55 We reviewed the impact of the proposed re vision of this definition on 40 CFR part 60, subpart Ja as well as its histor ic use in 40 CFR part 60, subpart J. The term “refinery process unit” is used primarily in the de finitions of certain affected fac ilities, “process gas” and “process upset gas” in subparts J and Ja. Th e term is also used in the flar e provisions in subpart Ja. With respect to the definitional terms, there can be no issue with including the designation of “refinery process unit” within the definitions for specific process units. “Process gas” is not used at all in either rule, although it was revised between propos al and promulgation of subpart J. In response to a comment that the definition of “process gas” “should have included the non-hydrocarbon gases produced by various process units in a refi nery,” the EPA responded: “The definition has been revised to include all gases produced by pr ocess units in a refinery except fuel gas and process upset gas.” (See page 127 of Background Information For New Source Performance
Standards , Volume 3, Promulgated Standards (B ID Vol. 3), EPA 450/2-74-003 (Feb. 1974), Docket Item No. EPA-HQ-OAR-2007-0011-0082). Th e definition had actually been revised to include “any gas generated by a pe troleum refinery process unit. ” The response in BID Vol. 3 suggests that the EPA considered “refinery proc ess units” and “process units in a refinery” to have the same meaning, and there is no mention of limiting what is considered to be a “refinery process unit” or “process units in a refinery.” “Process upset gas” is used only to provide an exemption to the H 2 S concentration limit for process upset gas sent to a flare. See 40 CFR 60.104(a)(1), 60.103a(h). Therefore, a narrow definition of “refinery process unit” would only limit those gases sent to a flare that would qualify as “process upset gas.” For example, if a coke gasifier is not a refi nery process unit, then gases generated during the startup, shutdown or malfunction of a c oke gasifier located at the refinery would not be “process upset gas” and woul d be required to comply with the requirement
to limit short-term H 2 S concentration in fuel gas to 162 ppmv if sent to a flare. We find that the historical application of the “p rocess upset gas” exclusion has c onsidered a broad definition of what constitutes a “refinery process unit.” For 40 CFR part 60, subpart Ja, the definition of “refinery process unit” also impacts the flare provisions. Based on the proposed revisions of “refinery process un it,” it was clearly our
intent that a broad definition of “refinery process unit” should apply to the flare requirements. Specifically, we intended that a flare modification occurs when a wide range of equipment at the petroleum refinery is newly connected to the flare. It was also our intent that the FMP consider56 flare minimization methods for this broadly defi ned range of equipment referred to collectively as “refinery process units.” Based on our review of the impacts of cha nges to the definition of “refinery process unit,” and considering all of the comments receive d, we maintain that the existing definition of “refinery process unit” is broad and should be broadly interpreted. Fo r consistency between 40 CFR part 60, subparts J and Ja, we have electe d to maintain the existing definition and not include an example list of refinery process units within the definition. However, to clarify that a modification to a flare occurs when these types of equipment are connect ed to the flare, we revised the language in the flar ing provisions to refer to “ref inery process units, including ancillary equipment.” This revision is made to cl arify our original intent that coke gasification units, storage tanks, product loading operations a nd wastewater treatment systems, as well as pressure relief valves, pumps, sampling vents, continuous analyzer ve nts and other similar equipment, are units from which a connection to a flare would trigger a flare modification and generate gas streams that should be considered in the FMP. We have included in the final
amendments a definition of “anc illary equipment.” Specifically:

Ancillary equipment means equipment used in conj unction with or that serve a refinery process unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading operations, wastew ater treatment systems, steam- or electricity-producing units (i ncluding coke gasification units), pressure relief valves, pumps, sampling vents and continuous analyzer vents.
Sulfur recovery plants are also units from which a connection to a flare would trigger a flare modification and generate gas streams that should be considered in the FMP. We recognize that on-site sulfur recovery plants are cons idered refinery process units, and we proposed amendments to the definitions of “refinery proces s unit” and “sulfur recove ry plant” to clarify
that we consider a sulfur recove ry plant to be “a segment of th e petroleum refinery in which a specific processing operation is c onducted.” However, the strict definition of “refinery process unit” would only apply to sulfur recovery plants physically locat ed at the refinery. As 40 CFR part 60, subpart Ja also applies to off-site sulfur recovery plants (see 40 CFR 60.100(a) and 40 CFR 60.100a(a)), we found it potentially contradi ctory to define a sulfur recovery plant located outside the refinery as a “refinery pr ocess unit,” so we are also not finalizing the proposed amendment to include the term “all refine ry process units” in th e definition of “sulfur57 recovery plant.” However, while connections to a re finery flare from an off-site sulfur recovery plant are not expected to be comm on, off-site sulfur recovery plan ts are subject to subpart Ja. We clarify in this response that we would consider such a connection to a flare to be from a “refinery process unit, including ancillary equipment,” such that connecting an off-site sulfur recovery plant that is subject to subpart Jato a flare at a refinery would cau se that flare to be a modified flare subject to subpart Ja. Further, in reviewing the defi nition of “sulfur recovery plan t,” we noticed an inadvertent error that also suggests that the sulfur recovery plant must be located at a petroleum refinery,
which is not consistent with the applicability pr ovisions in 40 CFR 60.100(a) and 40 CFR 60.100a(a). Specifically, we inadvertently omitted the word “produced” in this first sentence, so we are amending the definition of “sulfur recovery plant” to clarify that a sulfur recovery plant recovers sulfur from sour gase s “produced at the petroleum refi nery.” Thus, we are amending the definition of “sulfur recovery plant” to correct inadvertent errors a nd to clarify that off-site sulfur recovery plants are included in the definition of “sulfur recovery plant,” as these plants are expressly considered to be affected f acilities in 40 CFR part 60, subpart Ja.



### 3.11 Sulfur Recovery Plant
Comment : Commenter 0305 requested a clarification in the definition of “sulfur recovery plant” to exclude loading facilities (in addition to secondary storage vessels). Response : We agree and have revised the fina l definition. We also corrected an inadvertent omission of the word “produced” in th e definition. The “sulfur recovery plant” need not be located at a petroleum refinery, but, for th e purposes of subpart Ja, is limited to units that recover sulfur from sour gases “ produced at a petroleum refinery.”58 

## 4.0 FUEL GAS COMBUSTION DEVICES AND FLARES

4.1 Emissions Limits
4.1.1 Long-Term H 2 

### S Concentration Limit for Fuel Gas Combusted in Flares

Comment : Commenters 0296, 0301, 0305, 0310 and 0311 as serted that the EPA did not properly demonstrate that the long-term 60 ppmv H 2 S fuel gas concentration limit is BSER for flares as fuel gas combustion devices because the EPA underestimated the cost of treating the flare gas and overstated emissions reductions. Ac cording to Commenter 0296, flare gas treatment would require a compressor system for each flare header and would be mo re likely to require additional amine treatment systems and/or sulfur recovery units than the EPA estimated. The commenters also suggested that the EPA overest imated the value of the recovered flare gas
because the Btu content of flare gas is highly variable and generally lower than that used by the
EPA. Commenter 0311 stated that many refinery streams currently sent to the flare contain H 2 S concentrations between 60 and 162 ppmv, and requi ring fuel gas to meet a long-term 60 ppmv
H 2 S concentration limit would result in significant re-piping and capital i nvestment for minimal emission reductions, which the EPA’s impact analysis did not consider. Commenter 0311 also asserted that the emission reductions were overstated ( i.e. , the EPA should not use 162 ppmv as current long-term performance at baseline) and that the model analysis was oversimplified and neglected to account for the range of costs th at are incurred by i ndividual refineries.
Commenter 0301 asserted that the long-term 60 ppmv fuel gas H 2 S concentration limit for flares
does not meet the BSER cost effectiveness test as required by the CAA, particularly when evaluating the SO 2 reductions incremental to th ose achieved by consent decrees. Commenter 0301 suggested that a long-term 60 ppmv fuel gas H 2 S concentration limit for flares would cost $360-460 million and only reduce SO 2 emissions by 190 tons per year (tons/yr), which the commenter estimated to be a cost effectiveness of $326,000 per ton of SO 2 reduced. Commenter 0310 provided costs estimates for: (1) additional am ine systems of actual projects showing cost effectiv eness of $44,000 to $63,000 per ton of SO 2 reduced; (2) FGR systems with cost effectivene ss of $25,000 to $65,000 per ton of SO 2 reduced (details of the59 commenter’s estimate are confidential); and (3 ) FGR system expansions, which included an additional compressor, surge storage capacit y, and amine scrubber capacity, showing cost effectiveness of recovery system expa nsions to be $300,000 to $400,000 per ton of SO 2 reduced.
While most of their comments focused on flares , Commenter 0310 also stated that a long-term 60 ppmv fuel gas H 2 S concentration limit is improper for fu el gas combustion devices in general because it could preclude some refineries fr om processing high-sulfur crude oils, thereby limiting refining production capacity.
Commenter 0296 noted that the flare will receive both “fuel gas” and exempt gas streams (“process upset gas” as well as gas from pressure relief valve leakage), so it is impossible to determine if any emissions limit exceedance is caused by the regulated “fuel gas” or by the exempt gas. Commenter 0296 recommended that the EPA allow Alternative Monitoring Plans to demonstrate compliance with the fuel gas emissions limits for non-exempt gas streams upstream of the flare header. Alternatively, Commente r 0296 recommended that the long-term 60 ppmv
H 2 S fuel gas concentration limit be applicable only to the refinery fuel gas system and not to the refinery flare system. Response : We acknowledge that, at proposal, we determined that a long-term 60 ppmv
H 2 S fuel gas concentration limit was cost effectiv e primarily for process heaters, boilers and other fuel gas combustion devices that are fed by the refinery’s fuel gas system. Based on the typical configuration at a refi nery, adding one new fuel gas co mbustion device to the fuel gas system would essentially require the owner or op erator to limit the long- term concentration of
H 2 S in the entire fuel gas system to 60 ppmv, so emission reductions would result from all fuel gas combustion devices tied to that fuel ga s system. Upon review of the BSER analysis conducted at proposal for fuel gas combustion devi ces, we now realize that the analysis is not applicable to flares (See DocketItem No. EPA- HQ-OAR-2007-0011-0289). Moreover, since we are regulat ing flares separately from other fuel gas combustion
devices in this final rule , we should separately cons ider whether a long-term H 2 S concentration limit is appropriate for fuel gas sent to flares. In developing the suite of CAA section 111( h) standards for flares, we considered whether refineries should be required to optimi ze management of their fuel gas by limiting the long-term H 2 S concentration to 60 ppmv in addition to the short-term H 2 S concentration of 162 ppmv during normal operating conditions. We dete rmined that, for refineries to demonstrate60 that their fuel gas comp lies with a long-term H 2 S concentration of 60 pp mv, refineries would have to install a FGR system (which was not ne eded for other fuel ga s combustion devices) and then upgrade the fuel gas desulfur ization system. Alternatively, refi neries would have to treat the recovered fuel gas to limit the long-term concentration of H 2 S to 60 ppmv with new amine
treatment units on each flare. While some of the costs provided by the comm enters did not include the value of the recovered gas and appeared, at times, to incl ude equipment not necessarily required by the regulation, we generally agree with the commen ters, based on our own cost estimates, that optimizing management of the fuel gas system to limit the long-term concentration of H 2 S to 60 ppmv is not cost effective for flares (see Table 2 below). We note that the costs provided by
the commenters and the costs and emissions reducti ons in our analysis are the incremental costs and emissions reductions of going from the short-term 162 ppmv H 2 S concentration to a combined short-term 162 ppmv H 2 S concentration and long-term 60 ppmv H 2 S concentration.
While we are aware that some consent decrees re quire refineries to limit the concentration of
H 2 S in the fuel gas to levels lo wer than the short-term 162 ppmv H 2 S concentration, our baseline when evaluating the impacts of a national standard(in this case, 40 CFR part 60, subpart Ja) is the national set of requirements to which an aff ected flare would be subj ect in the absence of subpart Ja ( i.e. , the short-term 162 ppmv H 2 S concentration limit in 40 CFR part 60, subpart J).

Table 2. National Fifth Year Impact s of Meeting a Long-Term 60 ppmv H 2 S Concentration for Flares Subject to 40 CFR part 60, subpart Ja

Capital

cost ($1,000) Total annual

cost ($1000/

yr) a Emission reduction (tons SO 2 /yr) b Emission reduction (tons NO X/yr) b Emission reduction (tons VOC/yr) b Cost effectiveness ($/ton)
New 80,000 15,000 6 34 130 84,000

Modified / Reconstructed 860,000 160,000 53 310 1,200 100,000

aBecause of the heat content of recovered gas, each scf of recovered gas is assumed to o ffset one scf of natural gas;

a value of $5/10,000 scf of natural gas was used to estimate recovery credit.

b These emission reductions are based on flares already meeting the short-term 162 ppmv H 2 S fuel gas concentration

limit in 40 CFR part 60, subpart J ( i.e. , these are the incremental emission redu ctions achieved from a baseline of optimizing management of the fuel gas system to limit the short-term H 2 S concentration in the fuel gas to 162 ppmv to the originally proposed combined short-term 162 ppmv H 2 S concentration and long-term 60 ppmv H 2 S concentration in the fuel gas).61 

### 4.1.2 Alternative Compliance Options

Comment : Commenter 0301 requested that the EPA specifically allow alternative means of compliance included in consent decrees as acc eptable compliance alternatives for subpart Ja. Specifically, certain flares have an al ternative 500 pounds per day (lb/day) SO 2 emissions limit in lieu of a requirement to limit the short-term c oncentration of H 2 S in fuel gas combusted in a flare to 162 ppmv, and the commenter requested assu rance that this altern ative is sufficient to demonstrate compliance with subpart Ja. Response : The requirements in consent decrees are negotiated settle ments and are not based on an analysis of BSER, as several comm enters have pointed ou t (although typically to argue why certain consent decree requirement s should not be the basis of subpart Ja requirements). The BSER analysis conducted for this final rule package supports the requirements in this national rulemaking. As wi th any national standard, there will be units
where the costs to reduce a ton of pollutant emissions (in this case SO 2 ) will be less than the average costs projected for the industry and there will be units where the costs are higher than the average costs projected for the industry. While we try to consider and, if appropriate, minimize the impact of the less cost effectiv e units, we generally base our decision on the
nationwide costs and emissions re ductions achieved. As such, we do not feel compelled to loosen the national standard based on the poor cost effe ctiveness of a very limited number (less than 1 percent) of flares. We have conducted specific analyses that consid er flares as separate and distinct affected facilities from fuel gas combustion devices. While we concluded that a long-term 60 ppmv fuel gas H 2 S concentration limit is not cost effective for flares, we maintain that the requirement to optimize management of the fuel gas by lim iting the short-term concentration of H 2 S to 162 ppmv H 2 S during normal operating conditions is cost e ffective for flares. We also find that the 500 lb/day SO 2 limit is not, in any way, equivalent to the long-standing short-term 162 ppmv
H 2 S concentration requirement for these units in subpart J. At 500,000 standa rd cubic feet (scf) in a 24-hour period, the threshold at which a RCA is triggered for flare flow, the fuel gas could contain 6,000 ppmv H 2 S. With a 500 lb/day standard, flares with flow rates below the RCA threshold of 500,000 scf in any 24-hour peri od could exceed the short-term 162 ppmv H 2 S62 concentration requirement by a factor of 40 without exceeding the 500 lb/day SO 2 emissions limit requested by the commenters. We do not see this to be, in any way, equivalent to the existing limit contained in subpart J, and we are not including this significant exemption from the short-term 162 ppmv H 2 S concentration requirement in subpart Ja.



### 4.2 Elimination of Routine Flaring
Comment : Commenter 0307 stated that the EPA’s proposed amendments for flares are illegal and arbitrary. The commenter noted that when the EPA originally proposed subpart Ja for petroleum refineries (see 72 FR 27178, May 14, 2007), the EPA determined that elimination of routine flaring through the use of available techno logies such as FGR is technologically feasible,
cost effective and BSER under CA A section 111. However, the fi nal rule (see 73 FR 35838, June 24, 2008) did not include those requirements, and the commenter asserted that the EPA did not adequately explain why the BSER determina tion for the final rule changed (see 73 FR 35838, June 24, 2008). The commenter stated that the EPA did not provide ra tionale for dismissing technology that the agency determin ed was demonstrated and cost e ffective in favor of standards such as the FMP to manage flare emissions. Th e commenter also noted that in the June 2008 final rule, the EPA stated that the prohibition on routine flaring was removed because the EPA
“could not determine how to define ‘routine’ even ts.” However, the same final rule included a limit on flow to the flare applicable to “normal” operations ( i.e. , excluding SSM). The commenter asserted that “all of these concepts in the final rule require distinguishing between routine and exceptional events,” so the EPA’s explanation for the change is “internally
inconsistent.”
Commenter 0307 asserted that th ere is no question that FGR is demonstrated technology; FGR is commonly used in existi ng refineries to capture and r ecycle process gases. Existing refineries have been able to significantly redu ce or eliminate routine fl aring through the use of FGR, and other refineries are planning installations, so FGR “may fairly be projected for the regulated future.” 8 Further, recovery technology can signifi cantly reduce air pollution as well as save owners and operators money through recove ry of useful flare gas components such as hydrocarbons that a refinery can burn as fuel and hydrogen, which is used in several processes

8 Lignite Energy Council v. USEPA , 198 F.3d 930,934 (D.C. Cir. 1999) (citing Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973))63 and expensive to make. 9 In addition, demand for steam ge neration is reduced when steamassisted flaring is reduced. The commenter stated that the EPA, the DOE, the Valero refinery in Texas and the SCAQMD have found FGR systems to be cost effective. The commenter noted that the revised emission estimates presented in the preamble to the proposed amendments do more accurately represent emissions from flares than the estimates in the preamble to the final standards, but given that increase in emissi on reductions, the EPA di d not explain why both eliminating routine flaring and re ducing flaring via a limit on flar e flow rate are suddenly not
cost effective. The commenter stated that the EPA should revise the rule to return to the originally proposed standard prohibiting all routine flari ng because the CAA section 111
standards must reflect the best technology capable of capturing a nd eliminating the pollutants of concern. At the least, the EPA must provide a new analysis to clearly demonstrate why a prohibition on routine flaring using FGR and other technologies is not feasible or cost effective when considering the revi sed emissions reductions. Commenter 0307 also noted that in the preambl e to the final standards, the EPA stated that FGR is not technically feasible if a refinery produces more fuel gas than it needs to operate, but the commenter stated that the EPA provided no data or rationale to support that claim. The commenter also stated that even if the refinery produces more fuel gas than needed, there are alternatives to flaring that the EPA did not consider, such as th e possibilities of building on-site storage for excess gas or selling the gas to third parties; in fact, the EPA stated in the preamble to the original proposed rule that the agency believed “other opti ons exist, such as building an electric co-generating unit.” Response : We note that our original proposal (see 72 FR 27178, May 14, 2007) did not eliminate all routine flaring, only routine flar ing from new “fuel gas producing units.” The affected facility in the original proposal was not the flare, but the fuel gas producing unit. For a new fuel gas producing unit, the proposed require ments were to minimize releases to the flare during startup and shutdown and to eliminate routine flaring of ga ses from the fuel gas producing unit during normal operation. For units that produce significant quan tities of fuel gas, refinery owners and operators routinely in stall FGR systems to recover the gas for use as fuel gas in the

9 John Zink Company. “Environmental Control With Serious Payback.” Printed February 4, 2009, and included as Attachment A to Comment 0307 (Docket Item No. EPA-HQ-OAR-2007-0011-0317).64 refinery, so a gas recovery system (compressor) at the fuel gas producing unit was the expected method of compliance for an affected fuel gas pr oducing unit at the time of the original proposal. The problems with the initial proposal were th at there were ambiguities in the definition of a fuel gas producing unit and in what was mean t by “no routine flaring.” As we evaluated the proposed rule based on the comments receive d, we determined that it would be more straightforward to make the flar e the affected facility in the fi nal rule (see 73 FR 35838, June 24, 2008). By regulating the flare, gi ven the specific flare modificati on provision in subpart Ja, we actually increased the projected emission reductions of the rule as compared to the reductions achieved by regulating only new fuel gas produci ng units. In other words, the initial proposal affected only a portion of the gas sentto a flare, while the final rule affects all of the gas sent to a flare. As such, we find that the “flare as the a ffected facility” paradigm being finalized today is environmentally superior to the “no routine flar ing from new fuel gas pr oducing units” paradigm we originally proposed (see 72 FR 27178, May 14, 2007). The evaluation of FGR systems included in the docket demonstrates that FGR below certain flow rates is not cost effective; ther efore, a complete ban on “routine” flaring is not BSER (see the “Flare Options Calculator” included as an attachment to Docket Item No. EPAHQ-OAR-2007-0011-0223 and the flare impact memoranda included as Docket Item No. EPAHQ-OAR-2007-0011-0223 and Docket Item No . EPA-HQ-OAR-2007-0011-0289). We do agree with the commenter that FGR systems are techni cally effective at reducing flare emissions. We
also maintain that it is cost effective to inst all FGR systems when the flow rate of flare gas exceeds a certain threshold. However, the flow threshold at which FGR becomes cost effective is dependent on a number of factors, many of which are variable (such as the Btu content of the flare gas). The flare gas options ca lculator was developed to evaluate a range of flow rates, flare gas Btu content and other factors to determine the likely range of flows above which FGR would
be cost effective. Based on the data available at the time, a recoverable flare gas flow rate of between 250,000 and 500,000 standard cubic feet pe r day (scfd) was determined to be the
threshold at which FGR would be cost effec tive. In the proposed am endments (see 73 FR 78522, December 22, 2008), we proposed to remove the 250,000 scfd flow limit, but we also proposed to expand the applicability of the flare flow RCA requirement to routine flaring discharges in an
effort to address uncertainties on how to defi ne “normal operations” and to account for high65 daily flow rates that might cause exceedances of the 30-day lim it even though “routine” flow is
low. The cost effectiveness analysis provided in the docket is not really applicable to fuel gas
rich facilities because it assumes that the recovered flare gas can be combusted on-site in existing process heaters. When we consider the flare as th e affected facility, it is necessary to provide provisions for flaring during peri ods when the facility produces more fuel gas than it needs ( i.e. , is fuel gas rich). If a refinery has no place to use the recovered gas, the recovery compressors will only re-circulate the gas back to the flare. To eliminate flaring during times when the facility is fuel gas rich, the owner or operator would ha ve to find somewhere else to send the fuel gas besides the flare. The owner or operator may be ab le to store the fuel gas until it is needed, which would require additional storage ta nks, but this alternative has many drawbacks, such as strict limitations on excess storage capacity and safety hazards associated with storing the explosive gases. Alternatively, the owner or operator coul d purchase additional boilers, turbines or other electric co-generation equipment to extract useful work when combusting the excess gas. In this alternative, the excess fuel gas can be turned into steam or electricity thatcould either be used on-site or sent off-site ( e.g. , electricity supplied to the electri c power grid). The additional costs associated with the steam- or electricity-gener ating equipment greatly increases the amount of flare gas that would need to be recovered for a FGR/co-generation system to be cost effective, and this additional gas would be needed on a routin e basis. However, a refi nery is not typically fuel gas rich consistently all ye ar long. Consequently, it is no t cost effective to require FGR during periods when the refinery is fuel gas ri ch because of the limited time periods when this excess gas is available and the costs associated with purchasing steam or electricity generating equipment needed to utilize the excess fuel ga s. Furthermore, the few facilities that are consistently fuel gas rich typi cally have made arrangements to sell their excess fuel gas, have already installed co-generation uni ts or have made other arrangem ents to utilize this economic asset. We did not fully evaluate a maximum flow rate or other criteria limiting the applicability of the fuel gas rich exemption, both because we di d not have the data to do so and because we did not consider this a likely situation. Additionally, there are a significant number of variables to consider when determining the cost and cost effectiveness of a co-generation unit or other type of potential control sy stem, making the development of a single national standard highly problematic. The agency collected additional data from the petroleum refinery industry through66 an information collection reque st during the course of 2011 (s ee Docket ID No. EPA-HQ-OAR2010-0682), and we are in the process of analyzing th e collected data. If fuel gas rich situations are found to be more common than we anticipate, we will consider additional emission reduction opportunities for these situations at that time . However, based on the information currently available, when we considered the flare as the af fected source (rather than the fuel gas producing unit) and the technology needs to eliminate “routin e flaring” during period s when a refinery is fuel gas rich, we determined that a “no routine fl aring” requirement is not BSER because it is not cost effective. Rather, we determined that the development and adherence to a FMP that minimizes flaring during periods when the refinery is fuel gas rich is costeffective and therefore
BSER for occasional times when a refinery is fuel gas rich.



### 4.3 Flare Flow Rate Limit
Comment : Commenter 0303, 0306, 0308 and 0311 supported the removal of the flow rate limit for flares because the FMP and other require ments will reduce flare flow, and flexibility is needed in order to accommodate sweep ga s requirements for different flares and
weather/seasonal conditions. Response : We appreciate these comments; however, as seen by the comments received on the flare flow RCA requirements, there remain issues regardi ng sweep gas requirements, flare configurations and weathe r/seasonal conditions that still need to be addressed with respect to the
flow RCA. These issues are discussed in detail in Section 4.4.3 of this document.



### 4.4 Other Standards for Flares

4.4.1 General Comments on Other Flare Standards

Comment : Commenters 0305 and 0311 were critical of the impact analysis performed for the flare standards, stating that : (1) the 2002 National Emissions Inventory (NEI) CO data are not representative of process flow (Commenter 0305); (2) the flows or recovery rates were not adjusted to consider upsets that would not be recovered and continuous sweep gas flows (Commenter 0305); (3) the heating value of th e waste gas was too high (Commenters 0305 and 0311); (4) the EPA did not c onsider net costs when no offset is possible ( e.g. , when the refinery is long on fuel gas or flare gas is poor quality) (Commenters 0305 and 0311); (5) the EPA underestimated capital costs for recovery systems (Commenter 0311); (6) the EPA67 underestimated capital costs for monitoring sy stems (Commenter 0311); (7) the EPA did not consider that for certain types of flares , no sulfur emission re ductions are possible ( e.g. , liquefied petroleum gas (LPG) tank, hydrogen or emergency- only flares), but owners and operators still incur the cost of installing su lfur monitors on those flares (Commenter 0305); and (8) limited
data were used to assess emission redu ctions from RCA (Commenters 0305 and 0311). Response : We generally disagree with these criticis ms of the impact analysis for the flare standards. As stated in the preamble to the final amendments, we recognized that the flow
threshold at which FGR becomes cost effective is dependent on a number of factors, many of which are variable (such as the Btu content and fl ow rate of the flare ga s). The flare gas options calculator was developed to evaluate a range of flow rates, flare gas Btu content and other factors to determine the likely range of flows above whic h FGR would be cost eff ective. The costs of the systems and monitors came from vendor-reported co sts. These costs agree well with or tend to be slightly higher than costs for FGR system s collected by the BAAQMD, many of which came from refinery industry representatives to support their flare management requirements. We have acknowledged that cost credits were used predicated on the ab ility to productively use the recovered flare gas, but we have provided spec ific exemptions from the flow RCA for periods when the refinery may be fuel gas rich. We did apply an 80-percent flare gas recovery efficiency to account for upsets that could not be reduce d. We have also amended the flare flow RCA threshold in 40 CFR 60.103a(c)(1)(i i) to be 500,000 scf above a de fined baseline in any 24-hour period to account for sweep and purge gas flow. The flare requirements were established to reduce SO 2 , VOC, CO and NO X emissions, so the analysis was not limited to just sulfur-cont aining streams. The analysis assumed that the average H 2 S concentration of the recovered flare gas was 60 ppmv, which is well below the
short-term H 2 S concentration of 162 ppmv that we are fi nalizing for fuel gas combusted in flares, so this assumption adequately accounts for recovery of gases with very low sulfur content, such as LPG. Based on the BAAQMD experience with requiring flare flow monitoring, as well as recent Differential Absorption LIDAR (DIAL) obser vations, it appears that the flare flow rates extrapolated from the NEI data may seriously un derestimate actual flare usage. While this does not impact the threshold flow rate at which FGR becomes cost effective, it does impact the number of flares and the quant ity of emissions reduced as a result of the rule. Based on our review of the impact analyses, we find no merit in the criticism suggested by the commenters. If68 anything, we find that the flare standards may achie ve more emission reductions than previously projected. We uphold our analysis and the conclusion that the flar e standards are cost effective
and BSER.


### 4.4.2 Flare Management Plan Requirements

Comment : Commenter 0309 suggested that the EPA’s intention in promulgating a different definition of “affected facility” in subp art Ja than the existing definition in subpart J was to indicate that existing pr ocess units are not subject to the flare standards. The commenter suggested that the EPA should furthe r clarify this point so that it is clear that existing affected facilities are exempt from the flare standards. Response : The affected facility discussion is different primarily because the flare provisions were first published at a different date than the other ru le requirements, not to denote
that the FMP does not cover exis ting sources connected to a newly modified flare. The FMP covers all refinery process units and ancillary emission sources (e xisting and new units) that are
connected to an affected flare.
Comment : Commenters 0308 and 0311 suggested th at the requirement to minimize discharges to the flare in proposed 40 CFR 60.1 03a(a)(1) should specifi cally address routine discharges and include a clause to limit the minimization of flaring to those that: (1) are “consistent with good engineering practices” and (2) c onsider “the cost of achieving such emission reduction, and any non-air quality h ealth and environmental impact and energy requirements.” These revisions are needed, according to Commenter 0308, because non-routine discharges are covered under the RCA and so that the requirement is compliant with the need to
consider cost under section 111 of the CAA. Response : We agree that the language in pr oposed 40 CFR 60.103a(a)(1) appears to require an assessment of flare minimization irrespec tive of cost or other re levant considerations, as contained in CAA section 111, which was not our intent. We are clarifying, through this response, that cost, safety and emissions reduc tions may be considered when evaluating what actions should be taken to minimize discharges to a flare, but we disagree that the flare
minimization assessment should be limited to “r outine discharges.” We have revised the FMP requirements in 40 CFR 60.103a(a) to more fully desc ribe the types of information that must be evaluated and included in the plan.69 As noted in section III.C of the preamble to the final amendments (summary of the rule), we are finalizing our proposed withdrawal of the 250,000 scfd 30-day rolling average flow limit for flares. This limitation does not adequately acc ount for site-specific fact ors regarding flare gas Btu content, ability to offset natural gas purch ase and other consideratio ns. We find that these
factors need to be addressed in a site-specific basis and are mo re appropriately addressed through the FMP. In the absence of the specific fl ow limitation, we have included additional requirements in the FMP to prompt a thorough review of the flare system so that, as an example, FGR systems are installed and used where these systems are warrant ed. We have also revised the flare minimization requirements to require th e FMP to be submitted to the Administrator (40 CFR 60.103a(b)). As part of the development of the FMP, refinery owners and operators can provide rationale and supporting evidence regarding the fl are reduction options cons idered, the costs of each option, the quantity of flare gas that would be recovered or prevented by the option, the Btu content of the flare gas and the ab ility or inability of the reduc tion option to offset natural gas purchases. The plan will also include the rati onale for the selected reduction option, including consideration of safety concerns. The owner or operator must comply with the plan, as submitted to the Administrator. Major revisions to the plan, such as the addition of an alternative baseline (see next section for further detail on baselines), must also be submitted to the Administrator. In summary, although we did not incorporat e the commenter’s suggested language for limiting the scope of the minimization requirement s to actions that are “consistent with good engineering practices” and that “c onsider costs and other health and environmental impacts,” we acknowledge that these are valid co nsiderations in the selection of the minimization alternatives available for a given affected fl are. We find that the process of developing and submitting the
FMP will ensure that these factors are considered consistent with CAA section 111 and that the requirement to minimize discharges to the flare is implemented consistently across all affected

sources. Comment : Commenter 0308 requested confirmation that the requirement to include procedures to reduce flaring during periods of fuel imbalance in 40 CFR 60.103a(a)(6) does not require curtailed production of ke y fuel gas producing units, which would not be cost effective, even though it may be the only means of reducing flaring.70 Response : We agree that the procedures to reduce flaring in cases of fuel gas imbalance are not intended to require refine ries to curtail production of key fuel gas producing units such as the atmospheric distillation column, the FCCU, coki ng unit or similar processes. We expect that refinery owners and operators will consider pl ans such as procedures for reducing overhead condenser temperatures (by in creased cooling water recircul ation or using refrigerated condensers) to minimize the amount of C3 or C4 hydrocarbons that are introduced to the fuel gas system, procedures for temporary fuel gas storag e if appropriate storage vessels are available onsite or agreements to sell excess fuel gas to ne ighboring industrial plants . Owners or operators of affected flares should document the viable flaring reduction alternatives in their FMP. It is also recommended that the owner or operator keep re cords of the alternativ es evaluated, including why certain options were not considered vi able options for inclusion in the FMP.


### 4.4.3 Root Cause Analysis and Corrective Action Analysis

Comment : Commenter 0296 supported the RCA requi rements but noted that 45 days, while reasonable, is a short time period for many complex events and this time period should not be shortened. Commenters 0301, 0305 and 0311 request ed clarification that the RCA was to be conducted within 45 days but that not all of the corrective actions would have to be completed within 45 days. Commenter 0301 recommended repl acing the word “implement” with the word “identify” in proposed 40 CFR 60.103a(a)(5), sugges ting that this appears to be the EPA’s intent based on the implementation schedule describe d in proposed 40 CFR 60.103a(c). Commenter 0311 also requested that a provisi on be added for up to a 6-month extension, with approval, to perform RCA evaluations for comp licated events or disasters. Response : We consider the 45-day time period to complete the RCA to be appropriate,
and we do not believe that an effective RCA can be conducted 6 months after the event. We do agree with commenters that some corrective actions may require more time to fully implement. It is our intent, however, that the corrective actions that can be implemented within the 45-day period be implemented within that timeframe. Ther efore, simply replacing the word “implement” with the word “identify” in 40 CFR 60.103a(e ) (formerly part of 40 CFR 60.103a(a)(5)) does not comport with our intent. Instead, we have added 40 CFR 60.103a(e)(2) to cover corrective actions that cannot be implemented within 45 days as follows: “For corrective actions that cannot be fully implemented within 45 days following the discharge for which the root cause and71 corrective action analyses were required, the ow ner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable.”
Comment : Commenter 0311 stated that the SO 2 and flow RCA should not be triggered on a per flare basis, but rather a per upset even t basis. The commenter contended that flares complying with the short-term 162 ppmv H 2 S concentration requirement for fuel gas could exceed or approach 500 lb SO 2 during 24 hours of normal use, and that the per-flare limit penalizes facilities with consolid ated flare systems (larger indivi dual flares). The commenter also noted that the proposed language for flow RCA c ould be interpreted to require a RCA for every
minute when a 24-hour accumulation exceeds a threshol d and suggested that if the trigger is not changed to an event, then it should be evaluated on a calendar day basis, which is much easier to implement. Response : As the flare is the affect ed facility, triggering the RCA on a per flare basis is an obvious and rational approach. With respect to the SO 2 RCA, we found that the consent decree requirements for a RCA did not consider the allowable SO 2 emissions from the flare but rather the direct mass emissions (uncorrected for “allowable” emissions). Furthermore, the expected “allowable” mass emissi on correction based on 162 ppmv H 2 S will be negligible for events that trigger the SO 2 RCA but not the flow RCA. We di sagree with the commenter that fuel gas compliant with the requirement to limit the short-term H 2 S concentration of fuel gas to 162 ppmv would exceed or approach 500 lb SO 2 in any 24-hour period during normal operating conditions. The flare gas flow rate would have to be 20 million scfd at 162 ppmv H 2 S to exceed
500 lb SO 2 in any 24-hour period, and in that case, th e flare would have already triggered a RCA
based on the flow rate. We do note that the final rule provides for the establishment of a base flow rate per flare under 40 CFR 60. 103a(a)(4), which we expect to be higher for larger flares. In this manner, the flare flow RCA considers flow above the baseline, effectively considering “flaring events” and, to the extentpossible, eliminating disincentiv es for large individual flares. However, we see no reason why flare gas flow ra tes of the magnitude de scribed above would be considered normal operation or baseline flow ra tes compliant with the FMP requirements in the final rule, as amended. We do clarify in the rule under 40 CFR 60.103a(d ) that multiple RCA are not required for a single event. This includes both events that la st for more than 24 hours or events that exceed
both the flow and SO 2 RCA thresholds. Although not notedby the commenter, the per event72 method would seem to require accounting for the emissions across all affected flares at the refinery. We considered this approach, but we concluded that the allowance to develop a flarespecific baseline flow adequately addresses the disincentives for large individual flares with respect to the flow limit. However, the final ru le does continue to requ ire evaluation of the SO 2 and flow RCA thresholds on a 24-hour basis rath er than a calendar day to more accurately consider the emissions from a single discharg e that lasts less than 24 hours but occurs over 2 calendar days. For all of the a bove reasons, we conclude that th e final rule requirements (as amended) appropriately consider different refinery configurations with re spect to the number and size of flares and, although the RCA is evaluated on a per flare basi s, the final rule, as amended, effectively considers the emissi ons “event” from that flare.
Comment : Commenters 0304 and 0305 stated that th e flare flow rate threshold for RCA of 500,000 scf in any 24-hour period is arbitrary and cannot be fairly applied to all refineries. The commenters suggested that the flow threshol d should be either deleted (Commenter 0304) or replaced with a site-specific limit which appropri ately reflects the size and complexity of the individual flare system (Commenters 0304 a nd 0305). Commenter 0304 cite d an ultracracker flare that cycles from 5 million to 25 million sc fd. According to the commenter, this would result in meaningless daily RCA, and the commenter aske d if this was the EPA’s intent. If the flow threshold remains, Commenter 0304 suggested that the following gases should be excluded from the calculation of 500,000 scf: (1) hydrogen and nitrogen ( i.e. , compounds that are not hydrocarbons); (2) purge and sweep gas; (3) natural gas added to increase the Btu content of the flare gas; and (4) gases regulat ed by other rules (where the fl are is the control device). Commenter 0315 added that pilot gas should be ex cluded from the calculation of 500,000 scf gas flow. Commenters 0308 and 0311 request ed that the EPA clarify that the flow RCA be restricted to upsets and malfunctions as initially promul gated on June 24, 2008, because pilot gas, sweep gas, purge gas and other routine flows would tr igger a RCA automatically or with a nominal release event and because a RCA can only eff ectively reduce non-routine flows. Commenters 0308 and 0311 also noted that the requirement s in proposed 40 CFR 60.103a(a)(1) and (4) should not be duplicative; proposed 40 CFR 60. 103a(a)(1) should focus on routine flows and proposed 40 CFR 60.103a(a)(4) should focus on non-routine events. Commenter 0311 suggested the flow meters require d in the rule could be used to identify step changes caused by an event from routin e flow. Commenter 0315 re commended that the73 EPA adopt the approach used in the refinery consent decrees to address RCA for recurring events. For each “flaring device,” sites may pr epare and submit a single RCA for one or more root causes found by that analysis to routinely occur. The consent decrees include a provision that the owner or operator must in form the EPA that it is electing to report only once on that root cause, and unless the EPA objects within 30 days of receipt of the RCA, such election is effective. Examples cited by the commenter include routine maintenance activities such as purging vessels or clearing equipment, maintenan ce of a FGR system, flow from alkylation units which cannot be recycled due to contaminati on issues, fuel gas imbalance issues and high concentrations of hydrogen or nitrogen (either w ith or without FGR since these streams would not be suitable for fuel gas). Response : We proposed the flare flow RCA threshold of 500,000 scf in any 24-hour period because we projected that FGR would be a cost effective emission reduction technique for flares with fuel gas flows that routinely ex ceed 500,000 scfd, although we acknowledge that the
threshold at which FGR becomes cost effective is strongly (inversely) corr elated to the average Btu content of the flare gas ( i.e. , a relatively small reduction in the Btu content of the gas makes the recovery system significantly less cost effect ive). Although we did not specifically exclude sweep or purge gas from the flow, we expected that the flow rates of sweep or purge gas ( i.e. , gases needed to ensure the readiness of the flare and the safety of the flare gas system) would be negligible when compared to the RCA threshol d of 500,000 scf in any 24-hour period. In fact, in our original analysis of the appropriate flow rate RCA thre shold (Docket Item No. EPA-HQOAR-2007-0011-0246), we essentially assumed that the sweep and purge gas flow rates were zero, and we estimated costs and emissions re ductions of the 500,000 scf in any 24-hour period threshold, based on recovering that amount of gas or eliminating recurrin g events of that size (rather than 500,000 scf minus the sweep or purge gas flow). However, while we do not believe that 5 million scfd 10 is a reasonable base flow for a flare, we do acknowledge that the si ze of the flare, as well as the flare header system, will greatly

10 Regarding commenter’s cited ultracracker flare example, it is difficult to belie ve that sweep gas alone accounts for

5 million scfd of flare gas flow. Additionally, a compositiona l analysis of the base flare gas from the normal flow, based on data provided from a DIAL study of this refinery, suggests that the base flare gas is of sufficient quality to recover. It also appears, based on the data provid ed by the commenter, that the hydrogen stream recycle compressor was off-line approximately half the year. For su ch huge gas flows, considering the cost of purchasing or producing additional hydrogen and the emissions associatedwith that process, it is reasonable to expect that the facility would have a back-up compressor if the primary compressor is unreliable.74 impact the required flow needed to maintain th e readiness of the flare. Although we can derive suitable flare flow thresholds for average cond itions, these thresholds are not necessarily reasonable when applied to all flows, and we did not intend for on-going RCA to be conducted on account of sweep or purge gas. Therefore, rather than specifying a one-size-f its-all threshold, the final rule requires facilities to develop thei r own base flare flow rates as part of their FMP. A flow-based RCA is triggered if flows measured by the flow monito r exceed 500,000 scf greater than the base flare flow rate in any 24-hour period. Evaluating the flow rate thre shold above a baseline better reflects our original analysis of the impacts of flow-based RCA when the sweep or purge gas flow rates are not negligible. We also note th at 40 CFR 60.103a(d) allows a single RCA to be conducted for any single continuou s discharge that causes the flar e to exceed ei ther the RCA
threshold for SO 2 or flow for two or more consecutive 24-hour periods. The final rule does not limit RCA to upsets and malfunctions of re finery process units and ancillary equipment connected to the flare, no r does it explicitly allow owners or operators to use one RCA report for an event that occurs routinely. When we decided to eliminate the
numerical limit on flare flow rate , we specifically increased the scope of the flare flow RCA to cover more than just upsets and malfunctions. We also decided not to explicitly allow owners or operators to use one RCA report fo r an event that occurs routinely as a means to discourage routine flaring of recoverable gas. However, we recognize that there may be recurring discharges
to the flare that are not recoverable for various reasons. Therefore, the final rule does allow for several base cases, which could include recurring maintenance; this provision will avoid multiple RCA for a recurring event. As described above, th e FMP (as well as significant revisions to the plan to include alternative baselines) must be submitted to the Administrator. The Administrator or delegated authority ( e.g. , the state) may review the plan, although formal approval of the plan is not required. Not specifying a formal approva l process is intended to minimize the burden associated with reviewing FMP. Rather, the rule sp ecifies elements of the plan that need to be addressed in order for the plan to be consid ered adequate and provi des an opportunity for a delegated authority to find the plan not adequate if they choose to do so. We expect that a final FMP in compliance with 40 CFR part 60, subpart Ja will possess the following characteristics: (1) completeness (all gas streams are considered, all required elements are included and all appropriate flare re duction measures are evaluated); (2) accuracy75 (the emission reductions and cost estimates for the different options are accurate); and (3) reasonableness (the selection of reduction options is correct and the baseline flow value is reasonable). If the Administrator identifies deficiencies in the plan ( e.g. , the plan does not contain all the required elements, alternative flare reduction options we re not evaluated or selected when reasonable, the baseline or al ternative baseline flow rates are considered unreasonable), the Administrator will notify the owne r or operator of the apparent deficiencies. The owner or operator must eith er revise the plan to addres s the deficiencies or provide
additional information to document the reasonableness of the plan.
Comment : Commenters 0298, 0300 and 0304 requested th at an exemption from the flare flow RCA requirement be provide d for planned startup and shutdow n events that are consistent with the facility’s FMP because it is redundant and unnecessary. Response : We agree. There will be some units w hose startup and/or shutdown gas flow to
the flare will exceed the flow RCA threshold ev en though the gas flow to the flare has been minimized to the extent possible. For example, a hydrotreater may receive most or all of its hydrogen from a catalytic reforming unit. If this hydrotreater is shut down, the refinery will be producing significant quantities of hydrogen. While some of this hydrogen may be used in the fuel gas system, the amount of hydrogen that can be effectively redir ected is limited by the heating value needs of the fuel gas combustion units (hydrogen has a low higher heating value compared to hydrocarbons; too much hydrogen may adversely affect performance of the process heaters due to low heat input rate s) and the amount of fuel gas th at is needed by the refinery (if the refinery has a fuel gas balance ( i.e. , limited or no natural gas needs prior to the unit shutdown), the excess hydrogen caused by the shut down cannot be used to reduce natural gas purchases and some amount of hydroge n and/or fuel gas would then have to be flared). As long as planned startup and shutdowns are performe d according to the FMP requirements, a RCA is not required, and we have revi sed the regulatory language to exclude these circumstances.
Comment : Commenter 0311 requested clarificati on regarding the RCA and corrective action analysis requirements for sulfur recovery plants. The commenter asked the EPA to specify
if the 500 lb of SO 2 above the emission limit are to be calc ulated per calendar day or per 24 hour period. In addition, the commenter noted that su lfur recovery plants with reduction control systems emit reduced sulfur and not SO 2 , so a RCA threshold based on mass of SO 2 is not logical. Instead, the commenter recommended that the RCA threshold for these systems be set at76 500 lb reduced sulfur or total su lfur (depending on the type of CMS used for monitoring the emissions) above the emission limit. Response : As stated previously, we elected to evaluate the SO 2 RCA threshold on a 24-
hour basis rather than a calendar day to more accurately consid er the emissions from a single discharge that lasts less than 24 hours but occurs over 2 calend ar days. However, we agree that the description of the threshold for conducting RCA for sulfur recovery plants was confusing as proposed, particularly when the RCA threshold for sulfur recovery plants was compared to the RCA threshold for fuel gas combustion devices. The proposed RCA threshold for both types of process units was 500 lb above the emission limit , but the proposed ame ndments directed the owner or operator to compare the SO 2 emissions to “the period of the exceedance” for fuel gas
combustion devices and “the entir e 24-hour period” for sulfur recovery plants. Upon further consideration, we see no reason for these requirem ents to be different for fuel gas combustion devices and sulfur recovery plants. In addition, “period of the exceedance” was intended to have the same meaning as “period of ex cess emissions” under 40 CFR 60.105a(i) and 40 CFR 60.106a(b); to avoid confus ion, we have decided to use th e already-defined term “period of excess emissions.” Therefore, under 40 CFR 60.103a(c)(3) of the final amendments, the owner or operator is required to conduct RCA as described in 40 CFR 60.103a(d) “any time the
SO 2 emissions are more than [500 lb] greater than the amount that would have been emitted if
the SO 2 or reduced sulfur concentration was e qual to the applicable emissions limit in 40 CFR 60.102a(f)(1) or (2) during one or more c onsecutive periods of excess emissions or any 24 hour period, whichever is shorter.” This clarif ying amendment is needed to ensure that the magnitude of the emission limit exceedance is pr operly compared to what would have been emitted if the emissions were equivalent to the emissions limit based on the averaging time
allowed for that emissions limit. In other word s, if the owner or operator calculates four
consecutive 3- or 12- hour aver ages (as applicable) that are above the applicable emission limit, the owner or operator should comp are the total emissions from t hose four averages with the
amount that would have been emitted if the applicable emissions limit had been met over the duration of those four averages. The following is an example application of this provision. Consider a sulfur recovery plant with an emission limit of 250 ppmv SO 2 on a 12-hour rolling average basis. The emissions are constant such that the hourly averages and the 12-hour rolling averag es are typically about77 175 ppmv. Something then causes the hourly emissions to reach 1,000 ppmv SO 2 for two consecutive hours. When the operator calculates the 12-hour averages to determine compliance, he finds that the high concentrations caused a total of 11 12-hour averages to be above the 250 ppmv SO 2 emissions limit. To determine whether a RCA is required, the operator must compare the mass emissions from those 11 averages with the mass that would have been emitted if the 12-hour average for each of those 11 periods had been 250 ppmv SO 2 . If the difference is 500 lb, then RCA is required. With respect to sulfur recovery plants w ith reductive control sy stems, we acknowledge
that the SO 2 RCA threshold is somewhat contrived for these systems; however, we conclude that it is appropriate so that the magn itude of the event that triggers a RCA is essentially the same regardless of whether an oxidative or reducti ve control system is used. Specifically, the
concentration measurement for the reduced sulfur compounds is determined as ppm SO 2 by
volume. To convert the concentration into mass emissions, the molecular weights of the pollutants are needed. Most reduced sulf ur compound monitors do not determine the
concentration of individual reduced sulfur compounds; they determine the amount of SO 2 produced when the reduced sulfur compounds are oxidized. The mass of reduced sulfur compounds emitted cannot be directly determined from the monitored values. One must either
calculate the mass of sulfur emitted in the re duced sulfur compounds and/or calculate the equivalent mass of SO 2 emitted. The molecular weight for sulfur is half that of SO 2 . If units with reductive control systems were allowed to calcul ate the excess emissions in terms of pounds of sulfur per day rather than pounds of SO 2 (equivalents) per day, an ev ent would have to be twice as large to exceed a 500 lb SO 2 RCA threshold as compared to units with an oxidative systems. Such a discrepancy is not appropr iate considering that the emission limits for both systems are based on the same overall sulfur recovery efficien cy. Consequently, we are not revising the RCA threshold for sulfur recovery plants that employ reductive control systems. Through this response, we clarify that the SO 2 RCA threshold must be determ ined considering the mass of
SO 2 equivalent emissions above the applicable em issions limit for all sulfur recovery plants, including those with reductive control systems.78 

### 4.5 Monitoring Fuel Gas Combustion Devices
Comment : Commenter 0305 recommended that the EPA allow alternative monitoring plans for fuel gas combustion devices approved u nder subpart J to be deemed compliant with subpart Ja. Response : The alternative monitoring plan criteria in subpart Jawere developed based on the alternative monitoring plan requirements in subpart J, but with the additional intent to ensure compliance with the long-term 60 ppmv H 2 S concentration limit. For flares, which are not required to meet the long-term 60 ppmv H 2 S concentration limit, alternative monitoring plans approved under subpart J are deemed compliant with subpart Ja. However, for fuel gas combustion devices, which are required to meet the long-term 60 ppmv H 2 S concentration limit, the subpart Ja criteria must be used to develop a new alternative monitoring plan.



### 4.6 Flow Monitoring for Flares
Comment : Commenters 0305 and 0311 stated that“emergency only” or “SSM only” flares should be exempt from flow mon itoring requirements, a nd Commenter 0311 also requested clarification that sec ondary and “malfunction only” flar es are exempt from the flow meter requirement. Commenter 0311 stated that fl are flow meters are costly and unnecessary because engineering calculations, which are curren tly used, are sufficient to evaluate whether the
flare flow rate exceeds the RCA threshold of 500,000 scf in any 24-hour period. At a minimum, flares that are designed to handle flows less th an 500,000 scfd should be ex cluded from the flow monitoring requirements, as there is no justification for flow mon itors in this case. Commenter
0315 also noted that flow monitors are unnecessary for pilot gas, which has no significant increase or decrease potential and which does no t flow through the main flare header and thus would require a separate flow monitor. Commenter 0303 stated that, for flares with FGR systems, the pressure drop across the flare seal drum can be used to calcul ate flow rate and this
method is a cost effective alternative to c ontinuous flow monito rs for these flares. Response : In the final rule, flow monitoring is used to determine whether a RCA is required rather than to ensure compliance with a specific flow limit. We have reviewed the commenters’ suggestions and agree that, in cert ain specific cases, monitoring is not necessary and should not be required. However, as a general rule, we believe flow monitors are needed, not only to provide a verifiable measure of exceed ances of the flow RCA threshold, but also79 exceedances of the RCA threshold of 500 lb SO 2 in any 24-hour period. In addition, when we evaluated local rules, such as the initial BAAQMD rule for flare monitoring, we saw that the measured flare flow rates were several times great er than previously proj ected by the facilities. Consequently, we find great value in the flow monitoring requirements for flares. These monitoring requirements will great ly improve the accuracy of emissions estimates from these flares. The resulting improved accuracy of flare emissions estimates will also lead to better decision-making as we conduct future reviews of ru les applicable to petroleum refineries. We did consider each of the commenters’ suggested exem ptions in light of th is fact; our specific
considerations follow. We did not specifically consider that some flares would not be capable of exceeding the flow RCA threshold ( i.e. , designed to handle less than 500,000 scfd of gas). However, these
small flares could still exceed the RCA threshold of 500 lb SO 2 in any 24-hour period. As such, we did not provide an exemption from the m onitoring requirements for these small flares. We agree that the monitoring of pilot gas flow is not needed. In the final rule, a RCA is required if the gas flow to the flare exceeds 500,000 scf above the baseline in any 24-hour period. The flow of pilot gas is considered to be part of the baseline flow and is assumed to be constant. As such, monitoring of pilot gas would not be necessary to determine whether a flare has exceeded 500,000 scf above the baseline in any 24-hour period. In practice, the actual baseline flow set for the flare may or may not expressly include the pilot gas flow rate. Generally, the configuration of the flare header is such that the flare flow monitor would not measure pilot gas flow. In this case, the base line flow determined for the flare would not expressly include the pilot gas flow rate. If the flare flow monitor is c onfigured in such a way that it does measure pilot gas, th en pilot gas would be considered part of the baseline conditions
for that flare. We agree with commenters that flares w ith FGR systems do have unique conditions and these warrant alternative monitoring options. Ad ditionally, we recognize that the monitoring requirements may be burdensome for flar es that are truly “emergency only” ( i.e. , flares that flare gas rarely, if at all, during a typical year) or for secondary fl ares in a cascaded flare system. These flares are expected to have a water seal that prevents flare use during normal operations and ensures that the pressure ups tream of the water seal (expresse d in inches of water) does not exceed the water seal height during normal opera tions (hereafter referred to as “properly80 maintain a water seal”). We find that, for these sele ct types of flares, water seal monitoring as an alternative to the flow (and sulfur) monitoring provisions is appropriate. For flares with a FGR system and other em ergency or secondary flares that properly maintain a water seal, the final rule states that an owner or operator may elect to monitor the pressure in the gas header just before the water seal and monitor the wate r seal liquid height to verify that the flare header pressure is less than the water seal, which is an indication that no flow of gas occurs. If the flare header pressure exceed s the water seal liquid level, a RCA is triggered unless the pressure exceedance is attributable to staging of comp ressors. This alternative reduces the costs associated with installing sulfur and fl ow monitoring systems fo r flares that rarely receive fuel gas. Engineering calc ulations can be used to estimate the emissions during the event, but not for determining whethe r or not a RCA is required. To ensure that this option is only used for fl ares that are truly emergency flares and not for flares that are used for routine discharges , the final rule contains a limit on the number of pressure exceedances requiring RCA that can occu r in one year. Followi ng the fifth reportable pressure exceedance in any consecutive 365 days, the owner or operator must comply with the sulfur and flow monitoring requirements of 40 CFR 60.107a(e) and (f). Based on a review of available flaring data, we expect that gas may be sent to an emer gency flare three to four times per year, on average. Consistent with this information, we are pr oviding in these final amendments that an “emergency flare” may receive up to four releases to the flare in any consecutive 365-day period to account for year-to- year variability. However, a flare receiving more than four discharges in a consecutive 365-day period can no longer be considered an “emergency flare” and must install the required sulfur and flow monitors.
Comment : Commenter 0305 expressed concern re garding the flow meter range for emergency-only flares and suggested that for ex isting monitors, the flow range currently being used should be deemed acceptable, even if it means additional engineering and process information must supplement the readings to es timate emissions. The commenter also suggested that the range for new meters should be determined as approp riate for the specific flare. Commenter 0311 suggested that the flow meter range requirements should be clarified to accommodate an average flow rate of 500,000 scfd, and multiple flow meters should not be required to measure very high or very low flows.81 Response : Flow meters for flares are consid ered continuous parameter monitoring systems (CPMS) and no specific span is specified in the rule. Th e rule requires that the flow monitor be placed in a position to provide a repres entative measurement of the total gas flow rate and it specifies a minimum sensitivity and calibration requirements. We agree that the flow meter should accommodate an average flow rate of 500,000 scfd and we did not intend to require multiple flow monitors to measure exceedingly lo w or high flow rates. It is our understanding that ultrasonic flow monitoring systems are typically used for fl ares and that these devices can accurately measure flow rates over a large span ( e.g. , velocities from 1 to 3,000 feet per second [ft/s]). As such, we anticipate that a single flow me ter installed for flares will be able to measure a wide range of flow rates accurately and that the range measured by a single flow meter device
will be sufficient to assess both the su lfur and flow rate RCA thresholds.
Comment : Commenter 0311 noted that the newly proposed Appendix F QA/QC procedure (P-4) for CPMS will likely result in significant periods of monitor outages if applicable to fuel gas flow meters. Response : This comment lacks any detail supporting the commenter’s position. Presumably, if this is a legitimate concern, th e comment should have al so provided direct and more substantive comments on the proposed Pro cedure 4 to Appendix F. We defer to the supporting material and responses to comment document for that action; please see Docket No. EPA-HQ-OAR-2006-0640 for more details regarding that particular rulemaking.



### 4.7 Sulfur Monitoring for Flares
Comment : Commenter 0301 stated that flares that handle only exempt gases, specifically flares with FGR systems, should be exempt from H 2 S monitoring. According to Commenter 0301, process knowledge and engineer ing calculations are sufficie nt to determine if the SO 2 RCA threshold of 500 lb in any 24-hour period is exceeded. If H 2 S monitoring is required, Commenter 0301 requested that the rule allo w engineering estimates of the TRS-to-H 2 S correction factor due to safety concerns and in ability to collect samples for “emergency only” flares. Commenter 0314 agreed that monitoring is unnecessary for flares with adequately designed and operated FGR systems and that there ar e data at the flare gas source to calculate the
amount of SO 2 emitted and determine if RCA is needed. Commenter 0303 stated that continuous sulfur monitoring is unreasonable for flares thatgenerally see little or no gas flow, and sulfur82 emissions can be calculated based on sampling th e flare gas (although the co mmenter also stated that 42 percent of their flaring events were less than 10 minutes in duration). Commenter 0303 requested that 40 CFR 60.107a(e) and (f) and 40 CFR 60.108a(6)(iii), (i v) and (v) be modified to allow owners or operators to submit and use an alternative monitoring plan to demonstrate that the FGR system is operating within its capacity and to calculate SO 2 emissions from engineering calculations and flare gas samp ling. Commenters 0305 and 0311 agreed that “emergency only” or “SSM only” flares should be exempt from sulfur monitoring requirements. Commenter 0315 noted that it is common practice to configure flare systems such that one flare handles normal loads and another flare receives gas only when th e primary flare is overloaded during periods of SSM. The commenter noted that, in this situatio n, the continuous sulfur monitor on the primary flare would often provide data on the sulfur content of the fl ared gas (depending on the exact configuration). The commenter asserted that the burdens related to a cont inuous sulfur analyzer are not justified for flares where flows are very intermittent and event-related and where sulfur data is easily available by other means ( e.g. , grab samples, process data). Commenters 0301, 0305 and 0311 recommended that monitoring exempti ons be provided for flares in low sulfur service (less than 5 ppmv or sulfur-intolerant st reams), similar to the exemptions provided in 40 CFR 60.107a(a)(3). Commenter 0296 stated that properly designed FGR systems should exempt a flare from
the H 2 S concentration requirements in subpart Jaas only exempt gas streams would be combusted by the flares. Commenter 0296 also stated that the EPA should provide incentives for refineries to install costly FGR systems. For example, the EPA should eliminate the TRS monitoring requirements for flares with FGR syst ems, allow the use of an existing fuel gas continuous monitoring system (CMS) if the refinery is long on fuel gas and subsequently must flare some of the recovered gas and allow 5 years for installation of a FGR system. Commenter 0305 requested clarification that wh en sweep gas is routed to an emergencyonly flare, it is not required to be monitored if it meets one of the defini tions of streams that do not require monitoring or is monitored elsewher e (for example within the fuel gas system). Similarly, Commenter 0305 requested clarification th at flare pilot gas is not required to be
monitored for sulfur or flow if it is routed from natural gas or from refinery fuel gas monitored elsewhere for compliance with subpart J or Ja, nor is it required to be included in the flare flow for the purposes of RCA.83 Commenter 0314 noted that, to meet the perfor mance test requirements on flare sulfur monitors as proposed at 40 CFR 60.107a(e)(1)(ii) or (e)(2)(ii), th e owner or operator of a flare with FGR may have to intentiona lly flare sour gas. The commenter also noted that the relative accuracy test audit (RATA) may be enough to trigger RCA. Therefore, the commenter recommended revising the performance test requir ements for flares with FGR to require only a Cylinder Gas Audit. Commenter 0311 also noted that flares with occasional flows, such as flares handling only SSM events, would have to flar e intentionally to pe rform required testing. Response : We have amended the final rule so that gases that are exempt from H 2 S monitoring due to low sulfur cont ent are also exempt from sulf ur monitoring requirements for flares. For low-sulfur gases, the flare RCA will al ways be triggered by an exceedance of the flow
rate threshold well before the SO 2 threshold is exceeded, so no sulfur monitoring is required. However, this exemption can only be used for flares that are configured to receive only fuel gas streams that are inherently low in sulfur conten t, as described in 40 CFR 60.107a(a)(3), such as flares used for pressure relief of propane or butane product spheres (f uel gas streams meeting commercial grade product specificati ons for sulfur content of 30 ppmv or less) or flares used to combust fuel gas streams produced in process units that are intolerant to sulfur contamination ( e.g. , hydrogen plant, catalytic reforming unit, is omerization unit, hydrogen fluoride alkylation unit). We already clarified that flare pilot gas is not required to be m onitored (see Section 4.6). Also, 40 CFR part 60, subpart Ja already allows for H 2 S monitoring at a central location, such as the fuel mix drum, for all fuel gas combustion devices (and we are finalizing amendments to
ensure it is clear that H 2 S monitoring at a central location is al lowed for flares as well). Thus, we agree that if a flare only burns na tural gas, fuel gas monitored else where or fuel gas streams that are inherently low in sulfur content (as defined in 40 CFR 60.107a (a)(3)), then no H 2 S monitor is
needed. The remaining issue is whether or not sulf ur monitoring is necessary for “emergency only” flares. (An emergency flare is defined as a flare that combusts gas exclusively released as a result of malfunctions (and not startup, shutdown, routine operations or an y other cause) on four or fewer occasions in a rolling 365-day period. For purposes of the rule, a flare cannot be categorized as an “emergency flar e” unless it maintains a water se al.) We acknowledge that there
are difficulties and costs with in stalling monitors on flares that rarely operate. However, we are concerned about how the owner or operatorwill detect emissions above 500 lb SO 2 in any 24-84 hour period during an upset or malfunction of a refinery process unit or ancillary equipment connected to the flare. Commenters appear to ha ve conflicting opinions regarding the ability to sample the flare gas to determine the sulfur content (or total sulfur-to-H 2 S ratio) during a flaring event. If samples could be taken during the flar ing events, then that w ould be a potential option. However, during a process upset or malfuncti on, focus should be on alleviating the problem rather than taking a special samp le. Also, given the duration of so me of these events, it appears unlikely that representative sa mples can be manually collected. Taking the difficulties discussed above into account, we have developed an alternative monitoring option for emergency flares. As noted in the previous response, emergency flares are expected to properly maintain a water seal. We provide pressure and water seal liquid level monitoring, as previously described as an alte rnative to the sulfur and flow monitors. As
described in more detail above , any fuel gas pressure exceed ing the water s eal liquid level triggers a RCA and there is a limit to the numbe r of exceedances in one year. Under this option, a RCA is triggered based on the monitored pressure and water seal height, so accurate
measurements of flow rate and sulfur concentrati ons are less critical than for flares that must evaluate these parameters to determine if a RCA is needed. Consequently, for these flares, engineering calculations can be us ed to estimate the reported emi ssions during the flaring event, but the RCA must be performed regardless of the magnitude of these engineering estimates. Using this alternative monitoring option, emergency flares are not requiredto install continuous sulfur monitoring systems. Flares that do not meet the conditions of an emergency flare are required to install continuous sulfur monitoring systems and cannot elect this alternative monitoring option. We also agree that flaring solely for the purpose of a RATA or other performance test is not desirable. The “cylinder gas audit” procedur es requested by the commenter are described as alternative relative accuracy procedures in section 16.0 of Perfor mance Specification 2 (referenced from Performance Specification 5). We reviewed the alternative relative accuracy procedures and considered how they may apply to flares, and we have determined that the alternative relative accuracy procedures are appropriate for flares. We expect that, for most affected flares, the variability in flow (includi ng no flow conditions) and sulfur content of the gases discharged to the flare create significant ba rriers to the normally required relative accuracy assessments, particularly if those assessments need to be made over a range of sulfur85 concentrations potentially seen by the m onitor. Therefore, we are amending 40 CFR 60.107a(e)(1)(ii) and 40 CFR 60.107a(e)( 2)(ii) to specify that the owner or operator of a flare may elect to use the alternative relative accuracy procedures in section 16.0 of Performance Specification 2 of Appendix B to part 60. As required by 40 CFR 60.108a(b), the owner or operator shall notify the Ad ministrator of their in tent to use the alternative relative accuracy procedures.
Comment : Commenter 0312 requested that the EP A clarify whether the additionally proposed sulfur monitoring options for flares ar e for TRS or total sulf ur. The commenter noted that measuring total sulfur is the simplest and most inclusive measurement of SO 2 emissions and it is the method included in SCAQMD Rule 1118. The commenter also requested that methods for measuring total sulfur in ga seous fuels be included as acc eptable options to perform the relative accuracy evaluations of the CMS. Commenter 0311 requested that provisions be made in 40 CFR 60.107a(e)(2) to develop
a total sulfur-to-H 2 S (or TRS-to-H 2 S) ratio so that the total sulf ur monitor can be used for both the RCA and for compliance with the requirement to limit the short-term H 2 S concentration in fuel gas sent to a flare to 162 ppmv without the need for a duplicative H 2 S CMS. Commenter 0313 supported the addition of altern ative monitoring methods for the sulfur content of flare gas but noted that since the compositi on of flare gas is highly variable , the alternative methods must meet continuous monitoring requirements. Response : We have clarified and consolidated the monitoring requirements to allow TRS monitoring for flares. For the purposes of evaluating the SO 2 RCA threshold, total sulfur monitoring provides the most accurate assessment. However, in most cases, the vast majority of sulfur contained in gases discharged to the flare is expected to be in the form of TRS compounds, which include carbon disulfide, COS and H 2 S. Our test method for measuring TRS includes the use of EPA Method 15A as a reference method, and because EPA Method 15A measures total sulfur, the TRS monitoring requirement is equi valent to a total su lfur monitoring method. As discussed previously, we are relying on the suite of flare requirements we are promulgating to limit SO 2 emissions at the flare. These in clude optimizing management of the fuel gas by limiting the shor t-term concentration of H 2 S to 162 ppmv during normal operating conditions. We expected most refi neries would already have the H 2 S monitor and did not
consider the use of a total sulf ur monitor for use in complying with the short-term 162 ppmv H 2 S86 concentration in the fuel gas. As the H 2 S concentration will always be less than the TRS concentration, it is acceptable to us e the TRS monitor to verify that the fuel gas does not exceed
the short-term H 2 S concentration of 162 ppmv. Therefore, we have provided for the use of TRS monitors, provided the monitor can also meet the 300 ppmv span requirement. However, we have not provide d a correction factor to scal e down the TRS concentration
to H 2 S. The owner or operator using this method mu st essentially be able to demonstrate they can achieve a 162 ppmv TRS concentration in the fu el gas. The concentration ratio was provided for the purposes of the RCA because of the cost s of adding a total sulf ur monitoring system when a dual range H 2 S monitor was already in-place, as we ll as the expected accuracy needed for the system to assess the SO 2 RCA threshold. As few cases would exist where the flaring event would be right at the SO 2 RCA threshold of 500 lb in any 24-hour period, inaccuracies associated with the average total sulfur-to-H 2 S ratio were not expect ed to be significant. On the other hand, the short-term 162 ppmv H 2 S concentration in the fuel gas must be continuously maintained, a nd the total sulfur-to-H 2 S ratio at these low concentrations is expected to be highly variable, depending on the efficiency of the amine scrubber systems. As the amine scrubber systems, according to previous industry comments, are not effective for reduced sulfur compounds other than H 2 S, the non-H 2 S reduced sulfur concentration is expected to be fairly constant, with most of the fluctuations in total su lfur content being attribut able to fluctuations in
H 2 S concentrations. Consequently, we have dete rmined that the inaccuracies of the ratio approach are not acceptable for continuously demons trating that the short- term concentration in the fuel gas does not exceed 162 ppmv H 2 S. Therefore, owners or ope rators of affected flares may use the direct output of a TRS monitor to assess compliance with the short-term 162 ppmv
H 2 S concentration in the fuel gas, or they must install a continuous H 2 S monitor.
Comment : Commenter 0311 supported the proposed amendment revising the span value for fuel gas H 2 S analyzers to match the span requirements in subpart J, stating this will save time and money. However, Commenter 0301 stated that the span value for the flare H 2 S monitoring option is too restrictive and suggested that the Appendix F requirements provide sufficient quality assurance/quality control (QA/QC) without the need for the rule to specify the span

range. Commenter 0311 requested clarification of the sulfur monitor span for flares, suggesting that it should be based on the 162 ppmv H 2 S concentration requirementand that engineering87 calculations can be used to assess exceedances of the SO 2 RCA threshold of 500 lb in any 24- hour period. Response : The H 2 S span value is at 300 ppmv to verify compliance with the H 2 S concentration requirement for the fuel gas; the span of the total sulfur monitor needs to be much greater than that to be able to quantify the su lfur content in streams containing several percent
sulfur. For units that use the H 2 S analyzers both to assess compliance with the short-term 162 ppmv H 2 S concentration requirement for the fuel gas and to assess exceedances of the SO 2 RCA threshold of 500 lb in any 24-hour period, a dua l range monitor will be necessary. For the purposes of the SO 2 RCA threshold of 500 lb in any 24-hour period, we intended that the monitor be capable of accurately determini ng the sulfur concentration for the range of concentrations expected to be s een at the flare. We are particul arly interested in quantifying the concentrations of high sulfur-c ontaining streams as these would be the streams most likely to trigger a RCA at low flows. We proposed that the span for the flare sulfur monitor be selected from a range of 1 to 5 percent. We agree with th e commenter that this may be too restrictive, and we have revised the span requirements to be de termined based on the maximum sulfur content of gas that can be discharged to the flare ( e.g. , roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but no le ss than 5,000 ppmv. A single dual range monitor may be used to comply with the short-term 162 ppmv H 2 S concentration requirement for the fuel gas and the
SO 2 RCA threshold monitoring requirement provided th e applicable span specifications are met. In reviewing the span specifications, we noted th at span requirements were inadvertently omitted from the TRS compound monitoring a lternative. The purpose of these monitors is identical to the
H 2 S monitoring alternative, and the same span considerations apply for these monitors. We disagree that the QA/QC procedures in Appendix F to part 60 are sufficient without specifying the span values. Procedure 1 of Appendi x F to part 60 defines “span value” as: “The upper limit of a gas concentration measurement range that is specified for affected source categories in the applicable subpart of the regulation.” The con centrations used for calibration are based on the span value. Several of the QA/QC procedures in Appendix F are undefined if the span value is not defined in the rule.88 

### 4.8 Compliance Schedule
Comment : Commenters 0296, 0301, 0304, 0306, 0310 and 0311 stated that compliance with a long-term 60 ppmv H 2 S concentration limit on fuel gas combusted in flares would require a much longer time period than 2 years. The co mmenters suggested that 3 to 5 years would be needed to install a FGR system and/or addi tional amine treatment needed for compliance. Commenter 0310 further stated that the complia nce schedule in subpart Ja for installing additional sulfur removal equipment should be c onsistent with (or allow) established consent
decree schedules. Both Commenters 0310 and 0311 objected to phasing out the additional time
after the rule has been in place for 5 years.
Commenter 0311 stated that all flares should be given 3 years from the date of final promulgation and lifting of the stay to comply wi th the flare standards (regardless of whether new amine or FGR systems are being installed) to allow time for plan ning, re-piping and other necessary activities, and the EPA should provide an optional additiona l 2 years for capital installation projects ( e.g. , for permitting, equipment installation). Commenter 0305 stated that any capital project (not just amine treatment) re quired to meet any of the subpart Ja flare standards (not just th e long-term 60 ppmv H 2 S concentration) should trigger a compliance deadline of up to 3 years after th e effective date of the rule, with an allowance provided for refineries to request an additional 2 years if needed to correspond with an affected-unit turnaround because of the huge operating costs and product disruptions associated with
unscheduled turnarounds. Commenter 0301 recomme nded that the extra time to begin RCA provided to refiners committing to install FGR systems in proposed 40 CFR 60.103a(a)(4) and (b)(1) should also be provided to refiners committing to expand an existing FGR system. Commenter 0315 agreed that additional time is n eeded since a number of the flare requirements will require shutdowns. The commenter also stated that since not all flares are currently subject to subpart J, additional time woul d be needed for all fuel gas combusted in those flares to meet
the short-term H 2 S concentration requirement of 162 ppmv. Commenter 0304 stated that the 18-month comp liance deadline for sulfur CMS for flares is not adequate for large refineries with multiple flares because the installation of the CMS will typically need to be staggered (based on availability of CMS equipment and crew). Commenter 0310 similarly asserted that 3 ye ars would be needed to insta ll monitors due to design and installation considerations together with the constraints on manufactur ers by the sudden demand89 for several hundred flow and sulfur monitors. Both commenters cited delays experienced in obtaining monitors to comp ly with SCAQMD Rule 1118. Commenter 0295 requested clarification regarding the trigger date from which the additional time to comply w ith the flare provisions ( e.g. , 2 years when installing a FGR system) begins. The commenter asked whether the trigger da te is when construction starts, at startup or when the stay is removed (or whichever is la ter). Commenter 0315 agreed that the EPA should set the compliance time based on the initial star tup of the modification. The commenter noted that the EPA should follow the 40 CFR part 60 General Provisions for performance test timing and the 40 CFR part 63 General Pr ovisions for compliance timing. Response : As we are no longer applying the long-term 60 ppmv H 2 S fuel gas concentration limit to flares, the comments relate d to the amount of time n eeded to comply with a long-term 60 ppmv H 2 S fuel gas concentration limit are moot. We do, however, recognize that a flare modification can occur much more quickly than modifications of traditional processrelated emission sources. Therefore, we evalua ted the comments regarding the amount of time needed to meet the various requirements for flar es while keeping the 40 CFR part 60, subpart Ja flare modification provision in mind. We discuss each requirement and the time for demonstrating compliance with that re quirement in the following paragraphs. We find it appropriate to require modified flares that alrea dy have adequate treatment and monitoring equipment in place to achieve a short-term H 2 S concentration of 162 ppmv (resulting from compliance with 40 CFR part 60, subpart J) to continue to meet that concentration upon startup of the affected flare or th e effective date of this final rule, whichever is later. However,
some flares are not affected f acilities subject to 40 CFR part 60, subpart J, and others are complying with subpart J requirements as spec ified in consent decrees or have received alternative monitoring plans by which to demonstrate compliance with the short-term H 2 S concentration limit. In these cases, we find it appropr iate to allow more time to comply with the
short-term H 2 S concentration limit and/or the associated monitoring requirements because additional amine treatment and/or monitoring systems will be required to comply with the rule. Therefore, the final rule require s all modified flares that ar e newly subject to 40 CFR part 60, subpart Ja (but were not prev iously subject to 40 CFR part 60, subpart J) to comply with the
short-term H 2 S concentration limit and applicable monito ring requirements no later than 3 years
after the effective date of this fi nal rule or upon startup of the aff ected flare, whichever is later.90 Modified flares that have accepted applicability of subpart J under a federal consent decree shall comply with the subpart J requirements as specifie d in the consent decree but shall comply with
the short-term H 2 S concentration limit and applicable monitoring requirements no later than 3 years after the effective date of this final rule . Modified flares that ar e already subject to the 162 ppmv short-term H 2 S concentration limit under subpart J must meet the short-term H 2 S concentration limit under subpart Ja upon startup of the affected flare or the effective date of this final rule, whichever is later. Finally, modified flares that are already s ubject to the short-term
H 2 S concentration limit but that have an approve d monitoring alternative under subpart J and do not have the monitoring equipment in -place that is required under subpart Ja shall be given up to 3 years from the effective date of this final rule to install the m onitors required by subpart Ja (or to obtain an approved monitoring alternative under subpart Ja). As we noted in the preamble to the proposed amendments, many of the connections that would trigger applicability to 40 CFR part 60, subp art Ja are critical to the safe and efficient operation of the refinery. These connections can, and often must, be installed quickly. At the same time, nearly all refineri es will need time for planning, de signing, purchasing and installing (including any necessary re-piping) sulfur and flow monitors th at are newly required by subpart
Ja. Some refineries will elect to add FGR and/or sulfur treatment equipment to minimize their emissions as part of the evaluations conducte d as required by the new FMP requirements, and time will be needed for planning, designing, purchas ing and installing these components as well. Given that many flares will become modified a ffected sources relatively quickly, owners and operators will be competing with one another for the services and products of a finite number of vendors who provide the necessary monitors and other equipment. Several commenters specifically noted availability of monitors as an issue when complying with SCAQMD Rule 1118. As such, we find that immediate compliance w ith the requirements for flares, such as the planning, designing, purchasing and in stallation of (including any n ecessary re-piping) sulfur and flow monitors, may be difficult for operators to meet, especially in situations where quick connections to the flare are made. A phased co mpliance schedule allows for the operators to comply with some requirements associated with flares, such as continuing to achieve a shortterm H 2 S concentration of 162 ppmv, if the flares are already subject to 40 CFR part 60, subpart J and have adequate monitoring in place to comply with this final rule, while allowing91 time to install treatment and processing equipment and monitoring equipment to comply with the standards where necessary. A phased compliance schedule will also allow owners and operators to minimize process interruption by coordinating the in stallation of monitoring equipmen t with process shutdowns or turnarounds. In addition to providing operating flex ibility to the refinery, we are taking into consideration the fact that a pr ocess shutdown and subsequent st artup can generate significant emissions, even if the refinery is taking care to minimize those emissions. We consider a phased compliance schedule that allows owners and operato rs to avoid startups and shutdowns that are not necessary to maintain the equipment and process to be environmentally beneficial overall and the best system of emissions reduction for a quickly modified flare. Considering the time needed to complete engineering specifications , order and install the required monitoring equipment, and considering the need to coordinate this installation with process unit shutdown or turnarounds, we determined that completion of these activities with in 3 years is consistent with the best system of emissions reduc tions for quickly modified flares. We note, however, that this phased complian ce schedule for the flare requirements in 40 CFR part 60, subpart Ja is intended for those situations when a flar e modification occurs quickly and the owner or operato r does not have significant pla nning opportunities to install the required monitors or implement the selected flare minimization options without significant process interruptions. For a future large projec t on a schedule that includes time for planning, designing, purchasing and installi ng equipment and monitors, we expect that the owner and operator will have time to assess whether or not the refinery flares will become affected sources through modification. If a project will result in th e modification of a flare, we expect that the owner or operator will then plan how to meet th e standards in subpart Ja as part of the project itself, including the installation of the mon itoring systems and the development of a FMP. Because of the ability to plan ah ead, flares that are modified as part of a large project will not have all of the difficulties meeting the subpart Ja flare requirements upon completion of the
modification as those flares that are modified quickly. Therefore, we find that compliance with the flare requirements upon startup of the modifiedflare is appropriate a nd consistent with the best system of emissions reduction for large projects resulting in a modification of a flare. Thus, we determined that the appropriate time period fo r compliance with the flare standards is either: (1) 3 years from the effective date of these amendments or (2) upon startup of the modified flare,92 whichever is later. 11 In this manner, flares that become subject to subpart Ja quickly, based on a small safety-related connection (or have alrea dy become subject to subpart Ja based on a modification prior to the effective date of thes e amendments) will have up to 3 years from the effective date of these amendments to comply fully with the flare standard s, but flares that are modified as the result of a signifi cant project, such as the insta llation of a new process unit that will be tied into an existing flare, will effectivel y be required to comply with the flare standards at the startup of th e new process unit. Therefore, for the reasons described above, we are providing flares that become affected facilities subject to 40 CFR pa rt 60, subpart Ja through modifi cation with a phased compliance schedule for the flare standards, as described in this paragraph. The fina l rule requires owners and operators of modified flares to meet the short-term 162 ppmv H 2 S concentration requirement by the effective date of these amendments or upon startup of the affectedflare (whichever is later) only if they ar e already subject to the short-term 162 ppmv H 2 S concentration limit in 40 CFR part 60, subpart J. Modified flares that were not affected flares under subpart J prior to being modified facilities under subpart Ja mu st comply with the short-term 162 ppmv H 2 S concentration requirement within 3 years of the effective date of these amendments or upon startup of the modified flare, wh ichever is later. Owners and opera tors of modified flares that have accepted applicability of subpart J under a federal consent decree shall comply with the subpart J requirements as specified in the consen t decree, but must meet the short-term 162 ppmv
H 2 S concentration limit no later than 3 years after the effective date of this final rule. Owners and operators of modified flares that are already su bject to subpart J and that have an approved monitoring alternative a nd are unable to meet the applicable subpart Ja monitoring requirements
for the short-term H 2 S concentration limit must meet the short-term H 2 S concentration requirement upon startup of the affect ed flare or the effective date of this final rule, whichever is later, but shall be given up to 3 years from the e ffective date of this final rule to install the monitors required by subpart Ja. In this interi m period, owners and operato rs of these modified flares shall demonstrate compliance with the short-term H 2 S concentration limit using the monitoring alternative approved under subpart J.

11 For the purposes of this subpart, startup of the modi fied flare occurs when any of the activities in 40 CFR 60.100a(c)(1) or (2) is completed ( e.g. , when a new connection is made to a flare such that flow from a refinery process unit or ancillary equipment can flow to the flare via that new connection).93 Additionally, we are requiring owners and opera tors of modified flares to complete and implement the FMP under 40 CFR 60.103a(a) by 3 y ears from the effective date of these amendments or upon startup of the modified flare, whichever is later. We are requiring owners and operators of modified flares to begin c onducting root cause and co rrective action analyses under 40 CFR 60.103a(c) and (d) no later than 3 y ears from the effective date of these
amendments or the date of the startup of the modified flare, whicheve r is later, so that the facility can complete the FMP and establish baseline flow rates prior to performing the root cause and corrective action analyses. We are also requiring owners and operators of modified flares to install and begin operating the monitors neces sary to demonstrate compliance with these provisions, as required under 40 CFR 60.107a(e) th rough (g) within 3 years from the effective date of these amendments or by the startup date of the modified flare, whichever is later, when the monitors are not already in place. Compliance with th e phased compliance schedule constitutes compliance with the flare standards as of the effective date. We note that the final rule does not provide a phased compliance schedule for new and reconstructed flares. The final rule requires owners and operators of new and reconstructed flares to meet all the flare requirements , including the short-term 162 ppmv H 2 S concentration requirement, upon the effective date of the require ments or upon startup of the affected flare,
whichever is later.



### 4.9 Startup, Shutdown and Malfunction
Comment : Commenter 0307 stated that exempting flares 12 from the H 2 S concentration limits during SSM events is illegal because the CAA requires continuous compliance with
standards issued under CAA section 111. See CAA s ections 111(a)(1), 30 2(k). Therefore, the
commenter asserted that it is not BSER to allow startup and shutdown events to be exempt from compliance, and these emissions may not be re gulated through work practice standards. For support, the commenter cited Sierra Club v. EPA , 551 F.3d 1019 (D.C. Cir. 2008), in which the Court stated: “When sections 112 and 302(k) are r ead together, then, Congress has required that there must be continuous section 112-compliant standards.” The commenter noted that the Court

12 The comments submitted referenced “fuel gas combustion devices” as the affected source when describing the exemption during SSM events. However, the exemption only applies to flares. See 40 CFR 60.103a(h). The discussion in this document is therefore focused on flares as distinguished from other types of fuel gas combustion devices that are required to comply at a ll times with the limits in 40 CFR 60.102a(g)(1).94 found that the exemption from compliance withCAA section 112 standards during SSM events violates the CAA because the section 111 ge neral duty to minimize emissions during SSM events (see 40 CFR 60.11(d)) is not a CAA s ection 112-complaint standard. The commenter asserted that the CAA also requires that a se ction 111-compliant standard that reflects BSER 13 be
in effect at all times for flares.
Commenter 0307 further asserted that work practice standards for flares are not CAA section 111-compliant standards because this is not one of those “limite d instances” in which CAA section 111(h) authorizes su ch standards. The commenter st ated that the EPA must show that a standard of performance for flares is “not feasible to prescribe or enforce” because “(A) a pollutant... cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant, or that any requi rement for, or use of, such a conveyance would be inconsistent with any Federal, State, or lo cal law, or (B) ...the applicatio n of measurement methodology to a particular class of sources is not practicable due to technological or economic limitations.” See CAA section 111(h)(2). The commenterstated that neither of these exemptions appear to apply
and the EPA cannot claim that it is infeasible to promulgate a standard of performance for flares, 14 so the EPA cannot set a work practice standa rd for flares. Thus, the commenter asserted that a CAA section 111-compliant standard does notcontinuously apply to flares since both the exemption from the H 2 S concentration limits during SSM ev ents and the flare work practice
standards are not lawful under the CAA. Commenter 0315 disagreed and provided severa l reasons why they believe the EPA may lawfully exempt flares from the H 2 S concentration limits duri ng SSM events. First, the commenter noted that 40 CFR part 60, subpart Ja was promulgated as part of the mandatory periodic review of 40 CFR part60, subpart J required by CAA sect ion 111(b)(1)(B), which states that “the Administrator need not review any su ch [existing] standard if the Administrator

13 The commenter asserted, without providing support, th at it is not BSER to exempt flares from the H 2 S concentration limits during startup and shutdown events. The commenter also stated that the EPA, at a minimum, must demonstrate how the exemption from the H 2 S concentration limits during SSM events does in fact represent BSER, but the commenter stated that the EPA has failed to make this demonstration. 14 The commenter cited the EPA’s rationale for proposing work practice standards for flaring in which we state: “It is not feasible to prescribe or enfo rce a standard of performance for thes e sources because either the pollution prevention measures eliminate the emission source, so that there are no emissions to capture and convey, or the emissions are so transient, and in some cases, occur so randomly, that the app lication of a measurement methodology to these sources is not technically and ec onomically practical.” 72 FR 27178, 27194-27195 (May 14, 2007). In response, the commenter states: “[T]he plain language of the Act recognizes that standards of performance leading to the ‘capture’ of emissions are no t infeasible [citation omitted], and EPA has proposed to apply measurement methodologies to flares in spite of the transience of their emissions.”95 determines that such review is not appropriate in light of readily available information on the efficacy of such [existing] standard.” The comm enter noted that subpart J exempts a flare from
the H 2 S concentration limits when combusting cert ain gases generated during SSM events (see 40 CFR 60.104(a)(1), 60.101(e )) and stated that the record c ontains “ample evid ence” to support maintaining that provision in subpart Ja. The commenter assert ed that including these same provisions in subpart Ja is “an ap propriate exercise of the EPA’s authority to ‘not review’ this aspect of the existing standard in light of the efficacy of the existing standard.” See CAA section 111(b)(1)(B). Second, Commenter 0315 noted that the Sierra Club decision was largely grounded in the
Court’s determination that C ongress amended CAA section 112 outof concern “about the slow pace of EPA’s regulation of HAPs” (551 F.3d at 1028), eliminating much of the EPA’s discretion and requiring sources to “meet the strictest standard s” without variance “based on different time periods.” The comme nter further explained that th e Court pointed to CAA section 112(d)(1) regarding the EPA’s authority to “distinguish among cl asses, types, and sizes of sources” when promulgating CAA section 112 standa rds as further eviden ce for constraining the EPA’s ability to adopt different standards applicable during SSM events. In contrast, the commenter asserted that “Congress has expres sed no such concern about EPA’s efforts to implement section 111” of th e CAA despite revisions to CAA section 111 in 1977 and 1990. Therefore, the commenter asserted, Congress has “effectively ratified EPA’s longstanding approach to SSM under the NSPS program,” which includes the exemption for flares from the
H 2 S concentration requirements during SSM events. Commenter 0315 also asserted that, regardless of the above and despite the similar nature of the provisions in CAA sections 111 and 112, the EPA has the discretion to implement them differently “under the markedly differently context of the NSPS program v. the MACT program.” See Environmental Defense v. Duke Energy Corp. , 549 U.S. 561, 575-576 (2007). For example, the commenter asserted that the word“continuous” as used in the NSPS program could be interpreted and applied differen tly, as acknowledged by the Court in National Lime Ass’n v.
EPA , 627 F.2d 416, 434 (D.C. Cir. 1980) (deferring to agency regarding th e effect of “the perplexing implications of Congr ess’ new requirement of systems of continuous emission reduction” on the agency’s longstanding “regulations permitting flexibility to account for startups, shutdowns, and malfunctions”). The co mmenter urged the EPA to exercise this96 discretion and “reassert the ma ny practical, technical and econo mic factors” that justify promulgating separate standards fo r SSM events in the NSPS program. Third, Commenter 0315 asserted that requiring flares to meet the H 2 S concentration limits during SSM events does not represent BS ER for this time period. According to the commenter, “startup and shutdown ga ses are intermittent streams that cannot be cost-effectively
treated for sulfur removal because of their in frequent occurrence, their scattered points of generation and their variabilit y.” Therefore, for all of the above reasons, Commenter 0315 asserted that exempting a flare from the H 2 S concentration limits when combusting certain gases generated during SSM events is lawful under CAA section 111. Alternatively, Commenter 0315 stated that if a standard must apply during SSM events, the flare work practice standards are appropriate in lieu of the H 2 S concentration limit. Response : Regardless of whether or how the Sierra Club decision under CAA section 112 applies to NSPS promulgated under CAA section 111, we are promulgating final
amendments for flares that include a suite of st andards that apply at all times and are aimed at reducing SO 2 emissions from flares. As described prev iously, this suite of standards requires refineries to: (1) develop and implement a FM P; (2) conduct RCA and take corrective action when waste gas sent to the flare exceeds a flow rate of 500,000 scf above the baseline; (3) conduct RCA and take corrective action when SO 2 emissions exceed 500 lb in a 24-hour period; and (4) optimize management of the fuel gas by limiting the short-term concentration of
H 2 S to 162 ppmv during normal operating conditions. Additionally, refineries must install and operate monitors for measuring sulfur and flow at the inlet of all of their flares. Together, these requirements provide CAA section 111-compliant st andards that collectiv ely cover all operating
conditions of the flare. As the commenter notes, CAA section 111(h)(1 ) allows the EPA to promulgate a design, equipment, work practice or operational standardor “combination thereof,” when “it is not feasible to prescribe or enforce a standard of performance” which reflects BSER for the particular affected source. CAA section 111(h)(2) de fines the phrase “not feas ible to prescribe or enforce a standard of performance” as follows:

[A]ny situation in which the Administrato r determines that (A) a pollutant or pollutants cannot be emitted through a c onveyance designed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a97 conveyance would be inconsistent with any Fe deral, State, or local law, or (B) the application of measurement methodology to a particular class of sources is not practicable due to technol ogical or economic limitations.

We have determined that flares meet the criteria set forth in CAA section 111(h)(2)(A)
because emissions from a flare do not occur “thr ough a conveyance designed and constructed to emit or capture such pollutant.” Gases are conve yed to the flare for destruction and combustion products, such as SO 2, are not created until combustion occurs, which happens in the flame that
burns outside of the flare tip. In other words, the SO 2 , NO X , PM, CO, VOC and other pollutants generated from burning the gases are only created once the gases pass through the flare and come into contact with the flame burning on the outsi de of the flare. The flare itself is not a “conveyance” that is “emitting” or “capturing” these pollutants; instead, it is a structure designed to combust the gases in the open air. Thus , setting a standard of performance for SO 2 (and other pollutants) is not “feasible,” allowing the EPA to instead promulgate standards under CAA section 111(h), which will collectively limit emissi ons from the flare. The EPA previously promulgated a standard of performance for SO 2 emissions for fuel gas combustion devices which also applied to flares. 39 FR 9308, 9315 (March 8, 1974). The standard is expressed as an H 2 S concentration limit because it was developed as an alternative to measuring the SO 2 concentration in the stack gases exi ting fuel gas combustion devices other than flares ( i.e. , boilers and process heaters). That approach is appropriate for fuel gas combustion devices other than flares because measuring the H 2 S in the fuel gas combusted in
those devices is direc tly indicative of the SO 2 emitted from the exhaust stacks of those other devices. As explained in section II I of the preamble to the final amendments, we are, for the first time, designating flares as their own affected f acility. As such, in finalizing these amendments for flares, we considered whether we could also apply a standard of performance for SO 2 emissions, expressed as an H 2 S concentration limit or a total sulfur limit at the inlet to the flare. However, as explained above, flar es are substantially different from other fuel gas combustion devices so that this approach is no t workable for flares. For example, SO 2 emissions from a flare are dependent on many factors, incl uding the flow rates of all gases sent to the flare, the total sulfur content of all gases sent to the flare and the combustion efficiency at the flare. Each of these factors is also dependent on many variable s. For example, combustion efficiency at the flare is dependent upon the flammability of the ga ses entering the flare, the turbulence at the98 flare, 15 the wind speed and wind direction and the pres ence of other pollutant s in the gases that
can react with the sulfur to form su lfur-containing pollutants other than SO 2 . Since so many factors affect the potential formation of SO 2 emissions outside the flare tip, we realized that we could not properly derive an H 2 S concentration limit or a total sulfur limit at the flare inlet that would directly correlate with those SO 2 emissions. Thus, we determined that we cannot set a standard of performance for SO 2 emissions at the flare. However, we still recognize that reducing the am ount of sulfur that is sent to a flare will
reduce the SO 2 emissions at the flare. Even with th e uncertainty described above, we understand the importance of refineries managing the fuel gas se nt to their flares in a way that minimizes the sulfur content so as to ultimately minimize the SO 2 emissions. Rather than eliminate the H 2 S concentration limit altogether, we are instead requ iring under CAA section 111(h) that refineries
limit the short-term concentration of H 2 S to 162 ppmv in the fuel gas sent to flares during normal operating conditions. Refineries re ly on various methods for optimiz ing the management of fuel gas, including the use of amine treatment a nd FGR systems. Amine treatment removes the H 2 S from the flare gas that generates the pollutants be fore the gas is sent to the flare. Flare gas recovery systems remove the flare gas altogether a nd instead treat this gas in a fuel gas treatment system to be used elsewhere as fuel gas in the refinery. Requiring refineries to meet this
concentration limit at the flare ensures that the fu el gas has been adequately treated and managed such that it can be used as fuel gas in the fuel gas system elsewhere in the refinery. We are not requiring refineries to meet this limit during other periods of operation because FGR systems that capture gases prior to amine treatment can be quickly overwhelmed duri ng high fuel gas flows. Thus, requiring that flares meet this H 2 S concentration limit during periods when high fuel gas flows would likely overwhelm these FGR system s would not fully address the circumstances refineries face in managing these high flow pe riods. Designing FGR systems to capture the full range of gas flows to the flare would not only require the ability to predict the full range of gas flows in the flare headers, but also would requir e refiners to install recovery compressors in a staged fashion such that all events causing high gas flows could be captured and managed, neither of which are practical. Therefore, promulgating flare requirement s that include the H 2 S fuel gas concentration limit during normal opera ting conditions, coupled with requirements for

15 Turbulence is needed to insure good mi xing at the flare, but is affected by wh ether the flare is assisted with air or steam or non-assisted.99 refineries to develop and implement a FMP a nd conduct RCA and take corrective action when waste gas sent to the flare ex ceeds a flow rate of 500,000 scf above the baseline or 500 lb of SO 2 in a 24-hour period, recognizes thes e unique circumstances while sti ll requiring the refinery to
take all reasonable measures for reducing or eliminating the flow and sulfur content of gases being sent to the flares.
We are aware that numeric SO 2 emission limits for flares have been established under state law and in Federal Implementation Plan (FIP) regulatory requirements. Those sourcespecific circumstances differ markedly from this nationally applicable rulemaking, necessitating
different decisions in two very different circumstances. For example, the EPA’s SO 2 FIP for the Billings/Laurel Montana area includes a SO 2 emission limit of 150 lb of SO 2 per 3 hours for four sources that apply to the flares at all times. See 40 CFR 52.1392(d )(2)(i), (e)(2)(i), (f)(2)(i) and (g)(2)(i). These source-specific limits were appropriately based on dispersion modeling in the Billings/Laurel area to determine what was needed to meet national ambient air quality standards (NAAQS) for SO 2 in the Billings/Laurel area. In contrast , the nationally applic able standards and requirements we are promulgating in this rule mu st represent the BSER achievable for an entire industry sector scattered across th e entire country. This requires th at we consider costs and other non-air quality factors that affect all petroleum refineries nationw ide in making that decision and not just as applied to a pa rticular group of sources in a particular location. Additionally, those four s ources subject to the Billings/Laurel FIP demonstrate compliance with the 150 lb SO 2 /3-hours emission limit by measuring the total sulfur
concentration and volumetric flow rate of the gas stream at the inlet to the flare. See 40 CFR 52.1392(d)(2)(ii), (e)(2)(ii), (f)(2)(ii) , (g)(2)(ii) and (h). Since the FIP must include emissions
limits that insure attainment and maintenance of the NAAQS in the Billings/Laurel area, it was appropriate, in setting the standards for the Billin gs/Laurel FIP, to conservatively assume that 100 percent of the sulfur in the gases discharged to th e flare is converted to SO 2 , and based on this conversion, set the numeric limit as a value that is not to be exceeded. However, that same assumption is not appropriate when setting nati onal standards for flares. Instead, we must consider the many factors a ffecting the formation of SO 2 at the flare tip and how these factors
affect how much of the sulfur in the gases sent into the flare actually converts to SO 2 . Therefore, although setting such source-specifi c limits was appropriate to satisfy what the modeling showed100 was necessary to meet the SO 2 NAAQS in the Billings/Laurel ar ea, a different analysis and standard is appropriate for a national rulemaking. Therefore, for the reasons discussed above, th e EPA is finalizing th is collective set of CAA section 111(h)-compliant standards for fl ares, based on our interpretation of CAA section 111(h) as it applies to flares.
Comment : Commenter 0299 requested that the EP A provide provisions for fuel gas compressor preventative maintenance to reduce compressor outages as compared to running the compressor until it fails. Commenter 0311 stated th at FGR system outages may occur for safety reasons ( e.g. , if oxygen gets in the flare gas) and requested clarification that proposed 40 CFR 60.103a(a)(6) specifically acknowledge this possibility by inclusion of “flare gas recovery system outages ( e.g. , for maintenance or for safety reasons).” Response : We expect that refineries will properly maintain the compressors, and RCA will need to be conducted for FGR outages and sy stems put in place to eliminate the recurrence
of such events. Maintenance of the FGR does not constitute a process SSM event that excludes the fuel gas from the H 2 S concentration limits. However, inclus ion of procedures in the FMP to minimize the volume of gas flared during FGR sy stem maintenance is reasonable and we have added this requirement to 40 CFR 60.103a(a )(7) as requested by the commenter.101 

## 5.0 PROCESS HEATERS

5.1 Emissions Limits 5.1.1 Equivalence of Emissions Limit Units

Comment : Commenters 0296, 0305 and 0311 stated thatthe limits for the concentration and heating value emissions limits should be the same numerically; i.e. , the process heat rate limit numerically equivalent to the 40 ppmv concentration limit is 0.04 lb/MMBtu and the process heat rate limit numeri cally equivalent to the 60 ppm v concentration limit is 0.06
lb/MMBtu. Response : In August 2008, Industry Petitioners pr ovided the EPA with suggestions for revising the process heater standards (Doc ket Item No. EPA-HQ-OA R-2007-0011-0257). One of their recommendations was to include emissions limits based on heating value (lb/MMBtu) to account for hydrogen content variations in the fuel gas. They suggest ed that, on an annual basis, most natural draft process heaters could meet 0.035 lb/MMBtu and all other process heaters could meet 0.055 lb/MMBtu. We evaluated these sugge sted emissions limits and determined that they were reasonably equivalent to the concentration-based limits we were proposing. We also requested comment on their use and their equiva lency, as described in the preamble to the proposed amendments (see 73 FR 78527). Industry co mmenters now assert that the emissions limit numerically equivalent to the 40 ppmv concentration limit is 0.040 lb/MMBtu and the emissions limit numerically equivalent to the 60 ppmv concentration limit is 0.060 lb/MMBtu. We note that, as discussed in the preamb le to the proposed amendments, the exact conversion from ppmv to lb/MMBtu depends on th e hydrogen content of the fuel gas. However, our calculations generally s upport the more direct numeri cal conversion suggested by commenters over the typical range of hydrogen concentrations expected in the fuel gas (see
Revised NOX Impact Estimates for Process Heaters , in Docket ID No. EPA-HQ-OAR-2007- 0011). Therefore, we are finalizing heating valu e-based emissions limits of 0.040 lb/MMBtu and 0.060 lb/MMBtu for natural draft pr ocess heaters and forced draft process heaters, respectively,
based on direct numerical conversions from the concentration-based emissions limits.102 We are also clarifying that th e owner or operator must demons trate that the process heater is in compliance with either the applicable concentration-based or heating value-based NO X limit. The heating value-based NO X emission rate is ca lculated using the O 2 -based F factor,
which is the ratio of combusti on gas volume to heat input. Ongoing compliance with this NO X emissions limit is determined using a NO X CEMS 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. Specifically, if the F factor is determined at least daily, the owner or operator may elect to calculate both a 30-day rolling average NO X concentration (ppmv, dr y basis, corrected to 0-percent excess air) and a 30-day rolling average NO X emission factor (in lb/MMBtu) and demonstrate that the process heater is in complian ce with either one of these limits. For most fuel gas systems, the alternative emissions limits are expected to be identica l; however, there may be instances where a process heater may be complyi ng with one of the emissions limits and not the other. For example, a process heater combusti ng fuel gas with very high hydrogen content may have an average NO X concentration above the 60 ppmv limit, but below the 0.060 lb/MMBtu limit, largely due to the concen tration limit being determined on a dry basis (and understanding that the combustion of hydrogen produces only wa ter and not carbon dioxide). Provided that the appropriate monitoring is conducte d, an affected source would onl y be out of compliance if it
exceeds both the concentration-based limit and th e heating value-based limit at the same time. However, to have the option to determine compliance with the alternative heating value-based emissions limit, the refinery ow ner or operator must, at least daily, determine the F factor (dry basis) for the fuel gas accord ing to the monitoring provision s in 40 CFR 60.107a(d). If the F
factor is not determined at least daily, the heating value-ba sed alternative cannot be used. Generally, fuel gas heating value is important to the overall operation of refinery boilers and process heaters; as such, refiners maintain their fuel gas within an operating range that they need to fire these sources, often by mixi ng with natural gas, etc., so we anticipate that most, if not all, refiners will already have this info rmation available on a daily basis.


### 5.1.2 Limits for New, Modified and Reco nstructed Forced Draft Process Heaters

Comment : Commenters 0296, 0311 and 0314 suggested that newly constructed forced draft process heaters should have the same 60 ppmv emissions limit as modified and103 reconstructed forced draft process heaters. Co mmenter 0296 stated that the emissions limit for newly constructed forced draft process heaters was based on only two datapoints and that it does not fully consider the operating range of newly constructed units. The commenter included a John Zink white paper and asserted that this wh ite paper shows that newly constructed forced draft process heaters (particu larly those that use air preh eat) cannot meet the 40 ppmv NO X emissions limit. Commenter 0314 ag reed, noting that they designe d a new forced draft process heater with air preheat to meet 50 ppmv NO X , and the “heater vendor and burner supplier have determined that they cannot get appreciably lowe r emissions than the current design achieves.”
The commenter noted that since burner modificati ons alone will not be able to achieve 40 ppmv, this heater would need SCR to meet the 40 ppmv NO X limit, and they provided costs and emission reductions to support the EPA’s finding that SCR is not cost effective. Commenter 0314 also suggested that the EPA could re turn to the proposed limit of 80 ppmv NO X . Similarly, Commenter 0297 supported higher emissi ons limits for process heaters with air preheat. The commenter noted that meeting a 40 ppmv limit for new forced draft process heaters with combustion air preheat “and allowing for a comfortable margin to ensure compliance is extremely difficult, if not impossible, without th e use of add-on controls .” The commenter also suggested that the mass emissions of NO X from units with air prehea t would not be higher than units without air preheat due to the reduced flue gas flow ra te and recommended the 60 ppmv
NO X limit be extended to new forced draft proce ss heaters equipped with combustion air preheat. Response : The commenters provided only limited and theoretical data to support their argument that new forced draft process heat ers cannot meet the 40 ppmv (or 0.040 lb/MMBtu)
NO X emissions limit. Specifically, the John Zink white paper cited by Commenter 0296 (submitted as an attachment to Docket Item No. EPA-HQ-OAR-2007-0011-0296) stated only that the 40 ppmv emissions limit could not be “gua ranteed” for a new forced draft process heater, based on the design conditions, whic h included air preheat. Actual NO X performance data for that commenter’s new forced draft process heaters are not available, as those particular process heaters are not yet operational. As such, the actu al performance of these forced draft process heaters is still in question. However, we acknowle dge that we only have data for one new forced draft process heater without air preheat that is currently operating thatcould meet a 40 ppmv
NO X emissions limit on a 365-day average. We conducted additional data evaluations to determine appropriate limits and averaging tim es for all process heaters at normal operating104 conditions while considering this and other public comments we received. As part of the data analysis effort, we obtained a y ear’s worth of hourly CEMS data for the new forced draft process heater without air preheat capable of meeting 40 ppmv on a 365-day average. As discussed later in this chapter, our analysis of the additional data that we obtained following the proposal supported revising all NO X emissions limits to be on a 30-day average basis. The data indicate that the 30-day averages for the new forced draf t process heater without air preheat capable of meeting 40 ppmv on a 365-day average exceeded 40 ppmv 15 percent of the time, but none of the 30-day averages exceeded 60 ppmv NO X . Consequently, we are raising the NO X emissions limit (while c oncurrently reducing the averaging time) for all new forced draft process heaters to be equivalent to the emissions limit
for modified and reconstructed forced draft process heaters ( i.e. , 60 ppmv or 0.060 lb/MMBtu with a 30-day averaging peri od). Furthermore, based on th e information provided by the commenters, as well as the available performance data for existing forced draft process heaters with air preheat that have been retrofitted with ultra-low NO X burners, we also conclude that the 60 ppmv (or 0.060 lb/MMBtu) on a 30-day rolli ng average basis adequately accommodates forced draft process heaters thatuse air preheat. Based on our re view of CEMS data for new and
retrofitted forced draf t process heaters, we conclude that 60 ppmv (or 0.060 lb/MMBtu) on a 30- day rolling average basis is BSER for new, r econstructed or modified forced draft process heaters. (For additional details, see Revised NOX Impact Estimates for Process Heaters , in Docket ID No. EPA-HQ-OAR-2007-0011.)



### 5.1.3 Turndown

Comment : Several commenters addressed the n eed for the rule to address turndown, which is a period of time when process heater s are firing below capacity . Commenter 0296 stated that turndown conditions can extend over a full year , so special provisions are needed for these turndown conditions. Commenters 0296 and 0305 suggest ed that a mass emission cap be used as the sole compliance requirement (lb/MMBtu limit multiplied by the heater’s rated capacity). Alternatively, Commenter 0296 suggested that a mass emission cap be provided for “turndown operations,” which the commenter s uggested be defined as operati ng at 50 percent of the rated capacity or less. Commenter 0311 requested that the proposed emissions limits only apply to furnaces that are firing at or above 50 percent of design rates. Days when firing rates are below105 50 percent of capacity would not be included in the 365-day average and the units would meet a mass emission rate (pounds per hour [lb/hr]) based on the emi ssions limit at design capacity, according to the commenter. Also, according to Commenter 0311, process heaters must often operate at higher oxygen (O 2 ) levels during turndown, so the proposed maximum O 2 operating limit should not apply when small furnaces (those not required to install continuous emission monitoring systems [CEMS]) are firing at less th an 50 percent of design rates. Commenter 0315 added that limited new data suggest that meeting a NO X concentration limit becomes problematic at 70 percent of capacity , so the mass limit should apply when a process heater is firing below 70 percent of capacity and the emissions limit sh ould be calculated as the allowed emission factor for that heater multiplied by the 70-percent firing rate. Response : In our proposed amendments, we provid ed a longer averaging time (365-day average) so that short periods of turn-dow n would not significantly affect the overall performance of the unit. However, according to the commenters, the longer averaging time does not adequately address turndown conditions. Ther efore, we re-evaluated the available data, including our existing data a nd additional data provided by the industry, to determine the appropriate emissions limits during differenttypes of operation, including turndown. The additional data provided by Indus try and our evaluation of those data are included in the docket for the final amendments (Docket ID No. EPA–OAR–HQ–2007–0011). Based on our analysis of the data (described in greater detail in the next paragraph), we conclude d that a 30-day averaging period is appropriate for the NO X emission limits under most operating scenarios. Upon examination of all available CEMS data, we determined that, for periods of normal operation ( i.e. , firing at 50 percent or more of design capacity), the proposed NO X emissions limits of 40 and 60 ppmv were not achievable fo r all process heaters us ing a 24-hour averaging period (the averaging period included in the final June 2008 rule). From the available data, shortterm fluctuations in the NO X concentrations of process heaters using ultra-low NO X burners caused them to exceed a 24-hour average limit somewhat frequently, but a 30-day average provided adequate time to average out the short- term fluctuations. We note that a few of the process heaters operated atrelatively high excess O 2 concentrations at normal conditions ( i.e. , at exhaust O 2 concentrations of 6 percent or more). These units had periods of excess emissions above the 30-day average emission limits, but we rejected the performance of these process heaters as BSER because of the high exhaust O 2 concentrations for th ese units during normal106 ( i.e. , non-turndown) firing rates. Th at is, these process heaters we re not being operated optimally for reducing NO X emissions. Furthermore, when these pro cess heaters were operated at the lower range of exhaust concentrations for the unit (a lthough generally higher than what would be considered optimal excess O 2 concentrations for reducing NO X emissions), the process heater could meet the applicable 40 or 60 ppmv emi ssions limit on a 30-day averaging period. Based on our review of CEMS data for process heaters with ultra-low NO X burners that operated at excess
O 2 concentrations less than 6 percent ( i.e. , operated in a manner consistent with proper low NO X burner operation), all such process heaters could comply with the final NO X emissions limits on a 30-day average basis. Conseque ntly, we revised the basic emissions limits to be on a 30-day

average. As described previously in this section, we conclude that the applicable 40 or 60 ppmv emissions limit on a 30-day averag ing period is achievable for pro cess heaters during periods of normal operation. Our next step was to evaluate the achievability of th e emissions limits during turndown conditions and alternative approaches for establishing emissions limitations where necessary. The following paragraphs describe our analysis of the data , including our evaluation of alternative methods for accommodating turndo wn conditions and our rationale for providing the site-specific alternative for extended turndown conditions. There were very limited CEMS data av ailable for process heaters operating under turndown conditions ( i.e. , firing below 50 percent of design capacity). However, two general
trends were observed in the CEMS data th at were available: (1) typical exhaust O 2 concentrations increase at lower firing rates; and (2) exhaust NO X concentrations (corrected to 0-percent excess O 2 ) increase with increasing O 2 concentration (regardless of firing rates). These data, along with the need to operate the process heater at higher O 2 concentrations during low firing rates to maintain flame stab ility, suggest that an alternative NO X emissions limit could, in some instances, be needed to address extende d turndown conditions (turndown events lasting a majority of the 30-day averaging time). As suc h, we considered alternative compliance options
to address turndown conditions. One alternative compliance op tion considered to addre ss turndown was a mass-based
NO X emissions limit that would be equivalent to the mass of NO X emitted from a unit meeting the 0.040 (or 0.060) lb/MMBtu limit while firing at 50 percent of capacity, as suggested by commenters. However, for most units for which CEMS data are available, the alternative mass-107 based emissions limit did not improve the ability of the process heater to meet the emissionslimit. We note that most of the process heaters were able to meet the applicable concentrationbased emissions limit (40/60 ppmv) or the heating value-based (0.040/0.060 lb/MMBtu) emissions limit during turndown. Therefore, the issue appears to be limited to a few of the process heaters that must operate at relatively high excess O 2 concentrations during turndown conditions. For these units, the al ternative mass-based emissions limit that we were considering rarely, if ever, provided a means for these units to comply with the performance standard. We understand that technology providers recommend operating process heaters that are turned down at higher excess O 2 concentrations to improve flame stability and ensure safe operation of the process heater; however, base d on the information provided by the technology providers, there is still an optimal excess O 2 concentration at which flame stability is achieved while minimizing NO X formation. That is, even when a proc ess heater is operating at less than 50-percent design capacity, excess O 2 concentrations should still be controlled to minimize NO X formation within the safe operating constraint s to maintain flame stability. We do not have specific data on process heaters th at are near, but below, the concentration emissions limits when firing above 50-percent capacit y, but cannot meet the concentr ation limit when firing below 50-percent capacity, so we have no data that show that process heaters op erating at less than 50-percent design capacity and controlling excess O 2 concentrations cannot meet the emissions limits. However, we acknowledge that the correlations with firing rates and O 2 and/or NO X concentrations and the need for higher O 2 concentrations to maintain flame stability generally support the commenter’s argument that a few marg inally compliant process heaters will have difficulty meeting the basic emissions limit wh en the unit is turned down. As such, we acknowledge that there may be pe riods of turndown in which a process heater is operating as recommended, but may be unable to meet the co ncentration or heating value-based emissions limits in the final rule, especially when the unit is operated at turndown for extended periods ( e.g. , for 20 days or more compared to the 30-day averaging time). As the need for an alternative limit appears to be limited to a few process heaters and the optimal O 2 concentration is expected to vary, based on fuel gas composition, we determin ed that a site-specific emissions limit was the best approach to account for these extended turndo wn conditions. As such, the final rule provides owners and operators that have a process heater operating in tu rndown for an extended period of108 time the option of developing a site-specific emi ssions limit that would apply to those operating conditions and requesting approval from th e Administrator to use that limit. For process heaters between 40 and 100 million British thermal units per hour (MMBtu/hr) capacity that do not install a NO X CEMS, turndown is also expected to be an issue with respect to achieving the O 2 operating limit. As described above, higher O 2 concentrations are generally needed to maintain flame stability at low firing rates. To address potential turndown compliance issues with the O 2 operating limit, we have provided an allowance for process heater owners or operators to develop an O 2 operating curve to provide different O 2 operating limits based on the firing rate of the process heater. If a single O 2 operating limit is established, it must be determined when the process heater is being fired at 70 percent or more of capacity ( i.e. , far from turndown conditions). For proce ss heaters that routinely operate at less than 50 percent of design capacity and require additional O 2 to maintain flame stability, a separate O 2 operating limit should be establishe d for turndown by conducting a second performance test while the unit is operating at less than 50 percent of capacity. Additional performance tests can be conducted to develop O 2 operating limits for additional operating

ranges.


### 5.1.4 Site-Specific Emissions Limit Clarifications

Comment : Commenters 0302, 0305, 0308 and 0311 supported the provision in 40 CFR 60.102a(i) for a site-specific NO X emissions limit for process heaters that cannot be
retrofit with ultra-low NO X burners. Commenters 0308 and 0311 suggested expanding the applicability of the paragraph to include process heaters for whic h it may be physically possible
to install ultra-low NO X burners, but other “structural or op erability reasons” would prevent the process heaters from operating properly. Commente r 0308 also noted that is land refineries that have difficulty obtaining natural ga s may have fuel gas with higher levels of olefins and propane, which contribute to higher NO X emissions. The commenter sugge sted allowing process heaters
that cannot meet the NO X limits for “fuel gas quality reas ons” to apply for a site-specific emissions limit. Commenter 0311 stated that the pr ovisions should also appl y to new forced draft process heaters, especially thos e using air preheat, that might have trouble meeting a 40 ppmv
limit.109 Commenter 0311 also stated that the General Provisions provides 180 days to achieve full process rates, test the unit and submit the re sults, and this timeframe, rather than the 90-day time frame proposed, is needed to file the petiti on. Finally, Commenter 0311 stated that the rule should specify that the petition’s limit applies to the process heat er until the petition is acted upon since the petition is being submitted because th e facility cannot meet the emissions limit. Response : We appreciate the commenters’ support of the option to petition for a sitespecific emissions limit. We have clarified th e site-specific emissions limit provisions under 40 CFR 60.102a(i) to address most of the commenter s’ concerns as described in this response. Regarding process heaters that ca nnot properly operate ultra-low NO X burners, the preamble to the proposed rule notes that owners and operators may seek EPA approval for a sitespecific limit for “modified or rec onstructed natural draf t and forced draft process heaters that
have limited firebox size or other limitations and th erefore cannot apply the [BSER] of ultra-low
NO X burners.” Our intention was to accommoda te process heaters that cannot install and properly operate combustion modi fication-based technology due to structural limitations of the process heater ( e.g. , size of the heater box, flame impi ngement on tubes containing process fluids, spacing of the individual burners ). In other words, if ultra-low NO X burners can physically fit in a process heater but the process heater cannot be operated safely or the ultra-low
NO X burners themselves cannot operate as recomme nded by the manufacturer, then we consider there to be physical limitations preventing th e use of combustion modi fication-based technology. We agree that the proposed language in 40 CF R 60.102a(i) could be interpreted more narrowly than intended, so we revised th e language in 40 CFR 60.102a(i)(1)(i) to specify that “a modified or reconstructed process heater that lacks sufficient space to accomm odate installation and proper operation of combustion m odification-based technology ( e.g. , ultra-low NO X burners)” may submit a petition for a site-specific limit. This provision, while considering “proper operation,” was specifi cally included to address process heaters with physical ( i.e. , “structural”) constraints in retrofitting a process
heater with ultra-low NO X burners. This provision is not intended to provide unlimited operational flexibility for the burners. Further, we find that the requested “operability” provision undermines part of the BSER analysis. As seen by several of the comments received, the process heater specifications often include maximum radiant section temperatures, maximum preheat temperatures, maximum excess oxygen content a nd flexibility in burner design to allow both110 natural draft or forced draft ope ration. We recognize that, for exis ting process heaters, some of these parameters are fixed, but the question is : should the design and operation of the process heater be cognizant and reflective of the NO X emissions limits? In developing our BSER analysis, we included limiting the amount of excess oxygen employed and included costs for excess oxygen measurement and control. We do not expect that process h eaters that are subject to subpart Ja will operate exactly like process heater s that are not subject to subpart Ja, just with different burner designs. Fo r example, in reviewing NO X emissions data, we found that several process heaters were operating with excess oxygen c oncentrations of 6 to 8 percent while firing at or near capacity. Discu ssions with technology vendors, ho wever, suggest that “proper operation” of a low-NO X burner firing at or ne ar burner capacity would be to operate at excess oxygen concentrations of 2 to 4 percent. We recognize that there are several factors that
contribute to NO X formation, and it is incumbent on the ow ner or operator of an affected process heater to control, to the ex tent possible, these various parameters so as to minimize NO X emissions and to comply with the NO X emissions limits. Thus, while we recognize that certain
low-NO X burner retrofits may be inf easible due to structural limita tions, we do not want to open the door for refinery owners and operators to disregard the emissions limits when operating modified process heaters or when designing ne w process heaters and th en contend that the emissions limits in 40 CFR 60.102a(g)(2) are not achievable for “operability” reasons. Therefore, we reject the request to expand the scope of the site-specific emissions limit eligibility to include “operability” issu es per se unconstrained by the “proper operation” of low-NO X burners. Similarly, we reject the request to expand th e scope of the site-specific emissions limit eligibility to include fuel gas qua lity constraints. Based on our anal ysis of the available data, the
final NO X emissions limits are achievable over a wide range of refinery fuel gas compositions. Furthermore, we have added alternative NO X emissions limits determined on a heating value basis, which provides flexibility for times when the composition of refinery fuel gas varies ( e.g. , high hydrogen content). Regarding new forced draft process heaters, the preamble to the final amendments explains that we have finalized amendments that do not include new forced draft process heaters in the list of process heaters eligible to submit a petition for a site-specific emissions limit. As noted in the preamble to the final amendments, we have revised the NO X emission limit for new111 forced draft process heaters to be 60 ppmv (on a 30-day rolling average basis), rather than 40 ppmv (on a 365-day average) as provided in the proposed amendments. Based on available
emission data and ultra-low NO X burner performance guarantees, we conclude that all new forced draft process heaters can m eet an emissions limit of 60 ppmv NO X on a 30-day rolling average basis; therefore, site-specific emissions limits are not warranted for new forced draft process heaters. Regarding the specifics of submitting the petiti on, we agree with the commenter that it is appropriate to allow an owner or operator up to 180 days after startup to submit a petition for a site-specific limit. As the commenter noted, 180 days is consistent with the General Provisions, and it is also consistent with similar pe rformance level determinations for boilers (40 CFR 60.44b(f)). We also agree with the comm enter that clarificati on is needed regarding compliance during the time between submittal of the petition and approval by the Administrator.
We have clarified in the final amendments that the owner or operator should comply with the site-specific limit identified in the submitte d petition until the petition is approved by the
Administrator.



### 5.1.5 Co-Fired Process Heaters

Comment : Commenter 0308 requested clarification regarding the parenthetical qualifier “(applicable only when the process heat er is being co-fir ed)” in proposed 40 CFR 60.102a(g)(2)(iv)(A). The commenter st ated that it is unclear if proposed 40 CFR 60.102a(g)(2)(i)-(iii) apply to these process heaters when they are not co-firing or if only proposed 40 CFR 60.102a(g)(2)(iv)( B) must be applied. Based on the limitations of co-fired burner design, the emission limitations in proposed 40 CFR 60.102a (g)(2)(i)-(iii) are unachievable for co-fired process heaters, and clar ifying language is needed to ensure that these limits are not enforced for co-fired process he aters when only gaseous fuels are used. If the parenthetical was intended to exclude only those times when 100-percen t fuel oil is being burned, then the parenthetical shou ld be clarified as follows: “(a pplicable only when the process heater is being fired in whole orin part with fuel gas).” Co mmenter 0311 likewise suggested that the EPA clarify that process heat ers with co-firing capabilities (including those with separate burners dedicated to gas and liquid fuels) would have to meet either 150 ppmv or 0.08 lb/MMBtu when firing only gaseous fuels.112 Commenters 0308 and 0311 requested that the introductory text in proposed 40 CFR 60.102a(g)(2)(iv) be clarified to clearly state that a co-firedprocess heater must “comply with either” proposed 40 CFR 60.10 2a(g)(2)(iv)(A) or (B) as some might interpret the current language to mean that co-fired process heaters must comply with both paragraphs (A) and (B). Response : We agree that the langua ge concerning co-fired pr ocess heaters is ambiguous, and we have revised this langua ge to clarify the requirements. The final rule provides two subcategories of co-fired process heaters: natu ral draft and forced dr aft. Each subcategory includes two options for emissions limits, one on a concentration basis and the other on a mass
basis. The mass-based emissions limit considers the daily average amounts of gas and fuel oil fired by the heater, but the language no longer includes a qu alifier addressing the type of fuel that must be fired for the limits to apply. In other wo rds, the applicability of the emissions limits is based on the design of the process heaters and not on the type of fuel be ing fired at any given time. As stated previously (see Section 3.2), we do not consider process heaters that have completely separate gas and oil bu rners to meet the definition of co-fired process heaters. These units must demonstrate compliance with the NO X emissions limits when they are fired only with gaseous fuels. Additionally, the final amendments clarify that the owner or operator of an affected co-fired process heater may elect to co mply with either the heating value-based or the concentration-based emissions limit, but the owne r or operator must comply with the selected limit at all times. That is, the owner or ope rator cannot switch back and forth between compliance methods depending on the fuel burned.
We also note that the final rule does not addr ess process heaters desi gned to fire only fuel oil. Because we did not propose requirements specifi c to oil-fired process heaters, the final rule does not include amendments addressing oil-fired process heaters. However, we will evaluate adding requirements for oil-fired pro cess heaters in a future rulemaking.
Comment : Commenter 0308 stated that the emissions limits in proposed 40 CFR 60.102a(g)(2)(iv)(A) and (B) are not achiev able “...for the conditions that exist at HOVENSA...” and submitted a white paper to s upport higher emissions limits, which the commenter recommended be adopted, especia lly in light of a da ily averaging period. Alternatively, the commenter suggested the EPA defer the promulgation of NO X limits for cofired process heaters due to the l ack of adequate data to “adequa tely demonstrate” an achievable113 emissions limit under section 111 of the CAA. Commenter 0311 stated that the 0.27 lb/MMBtu
limit is not achievable when firing residual fuel oil.
Commenters 0308 and 0311 recommended that the emissions limit alternative in proposed 40 CFR 60.102a(g)(2)(iv)( B) be determined on a 365-day average as these process heaters will have the same issues with respec t to turndown and variab ility as other process
heaters. Commenter 0311 also stated that the notation “E NOx,hour ” in proposed Equation 3 was confusing and that the “hour” subscript s hould be dropped or changed to “daily.” Response : The final June 2008 rule included only one emissions limit for all co-fired process heaters, and Industry Petitioners assert ed that differences in the configuration and operation of different types of process heaters warranted different emissions limits. The proposed amendments introduced two specific emissions lim its for co-fired process heaters, one based on vendor guarantees for the burners and one based on an average NO X concentration for a combination of fuel gas and fuel oil. We note th at, for purposes of this rule, a co-fired process heater is defined as a process heater that em ploys burners that are de signed to be supplied by both gaseous and liquid fuels. In other words, co -fired process heaters ar e designed to routinely fire both oil and gas in the same burner. These do not include burners th at are designed to burn gas, but have supplemental oil firing capability that is not routinely used ( i.e. , emergency oil back-up). To respond to the comments requesting higher emissions limits for co-fired process heaters, we reviewed the white paper provided by one commenter (submitted as an attachment to Docket Item No. EPA-HQ-OAR-2007-0011-0308), as well as additional burner emissions test data provided by another commenter 16 (conducted under well-controlled conditions using best
available ultra-low NO X burner technologies at the manuf acturer’s testing facility). This information indicates that, for co-fired natural draft process heaters, a daily average emissions
limit calculated based on a lim it of 0.06 lb/MMBtu for the gas portion of the firing and 0.35 lb/MMBtu for the oil portion of the firing is achievable. Sim ilarly, the information indicates that, for co-fired forced draft process heaters, a daily average emissions limit calculated 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 is achievable. As noted above, these values are ba sed on burner performance tests,

16 The commenter providing this data asserted that it is confidential business information (CBI). We will follow our CBI regulations in 40 CFR part 2 in ha ndling this data. The data has been placed in the docket, but is not publicly available.114 which are considered a better s ource of information than the ve ndor guarantees that were relied upon to develop the proposed emissions lim it. Therefore, we are revising the NO X emissions limits for co-fired process heater s to those described above. We note that we have revised the
concentration-based NO X emissions limits to be on a 30-day average basis (same as the limits for gas-fired process heaters). We have also revise d the nomenclature of the daily average emissions limit in Equations 3 and 4 (proposed Equation 3) to be clear that we intend the limit to be determined on a daily basis rather than on an hourly basis. We also note that the burner performa nce tests were conduc ted in a controlled
environment at the burner manuf acturer’s full-scale facilities. Wh ile it is incumbent on the owner or operator of an affected proce ss heater to control certain oper ating parameters, such as excess
O 2 concentrations, to the extent possible, we re cognize that the performa nce limits in the final amendments are based on limited data, none of whic h are direct test data for a co-fired process heater operated at a petroleum refi nery. We conclude that the low-NO X burner technologies exist, are demonstrated and are co st effective for co-fired process heaters and they are, therefore, BSER for co-fired process heaters. However, as the performance limits are based on limited operational data, we also conclude that it is reasonable to provide an alternative, site-specific
limit in the event that factors outside the infl uence of the burner design and operation (such as nitrogen content in the fuel oil) suggests the emission limits in the final rule are inappropriate for a specific application. Conseque ntly, co-fired process heater s that cannot meet the limits specified above can request approval for a site-s pecific emissions limit, as allowed above, for process heaters that operate for extended periods under turndown.



### 5.2 Monitoring of Process Heaters
Comment : Commenters 0305 and 0311 noted that CEMS compliance requirements in 40 CFR part 75 are similar to those in 40 CFR part60, but not identical. The commenters requested an exemption from the 40 CFR part 60 monitori ng and QA requirements for any process heater or boiler subject to and complying with 40 CFR pa rt 75 monitoring required by Acid Rain rules,
a NO X State Implementation Plan (SIP) call, or other rules. Alternatively, the commenters requested that the EPA specifically provide 40 CFR part 75 monitoring a nd QA provisions to be compliant with 40 CFR part 60, subpart Ja.115 Response : We reviewed the QA/QC requirements in 40 CFR part 75. It appears that the 40 CFR part 75 NO X emissions limits (provided predominan tly for coal-fired units) are much higher than those provided in these final amendm ents (which are predominantly for gas-fired process heaters). The accuracy requirement for the RATA on NO X is ±0.015 or 0.020 lb/MMBtu, depending on the RATA frequency. We find that these accuracies are not appropriate given the
NO X emissions limits that are in the final rule . Consequently, we do not consider the 40 CFR part 75 QA/QC requirements sufficient for comp liance with the final rule and we are not amending the rule to allow 40 CFR part75 monitoring and QA provisions.
Comment : Commenter 0311 asserted that daily determ ination of fuel oil heating value to comply with the co-fired process heater NO X emissions limit is excessive and unnecessary if the
fuel oil is fed from a tank because the heati ng value does not vary that much. The commenter requested that the EPA allow the 40 CFR pa rt 75 sampling protocols (Sections 2.2.3 and 2.2.4.1 through 2.2.4.3 of Appendix D) instead of da ily sampling. The commenter stated that 40 CFR 60.4370 (40 CFR part 60, subpart KKKK) allows these protocols for sulfur sampling of liquid fuels to turbines. Response : We reviewed the referenced secti ons in 40 CFR part 75. While we do not understand the reference to Section 2.2.3, which s eems to indicate daily sampling, we recognize that heating value of fuel oil fed from a comm on storage tank is not expected to vary unless additional shipments are received. As many of the alternatives in the cited sections are sulfurcentric, we have provided similar alternatives in 40 CFR 60.107a(d)(7)(viii ) to reduce the burden associated with daily sampling when daily sa mpling will not improve the accuracy of the

measurements. Comment : Commenter 0307 stated that the EPA should require CEMS for all process heaters to demonstrate compliance with the NO X emissions limit. The proposed amendments allow the option of biennial source testi ng for certain process heaters with low-NO X or ultra-low
NO X burners; however, commenters a ssert that biennial source te sting is not sufficient for ensuring that these process heaters are meeting their NO X emissions limits. The commenter stated that section 504(c) of the CAA requires that Title V permits include monitoring requirements that “assure compliance with the permit terms and conditions,” and in Sierra Club
v. USEPA , 17 the D.C. Circuit held that the EPA and state permitting agencies must include

17 536 F.3d 673 (D.C. Cir. 2008).116 additional monitoring requirements in Title V permits if the existing requirements are insufficient to ensure compliance with an emissi ons limit. The commenter stated that biennial source testing for process heaters is not suffi cient to demonstrate compliance; instead, the
commenter asserted that CEMS are needed for demonstrating that all process heaters are in continuous compliance with the NO X emissions limit. The commenter also noted that if the EPA relies on CEMS data provided by industry to weaken the NO X emissions limits, then the EPA should at least require CEMS to ensure indus try is complying with that weaker limit. Commenter 0315 countered that subpart Ja does require CEMS for process heaters firing
more than 100 MMBtu/hr. The commenter also noted that Commenter 0307 did not provide data supporting their assertion that bienni al source testing is insufficien t for small process heaters, and the EPA has discretion in determining what m onitoring is adequate. Commenter 0315 noted that the EPA originally proposed CEMS on all pr ocess heaters, but based on public comments received through the subpart Ja rulemaking pr ocess, the EPA revised the evaluation and determined that CEMS were not justified for small process heaters (see Docket Item No. EPAHQ-OAR-2007-0011-0222 and the third attachment to Docket Item No. EPA-HQ-OAR-2007- 0011-0222). The commenter noted that the EPA’s de termination was reasonable and consistent with the agency’s longstanding approach fo r assuring continuous compliance, and the
commenter cited several sections of 40 CFR part 64 for support. Commenter 0311 supported the more flexible span range for NO X and the ability for process heaters between 40 and 100 MMBtu/hr to use either a CEMS or biennial test. Response : We consider the monitoring requirements in the final rule sufficient for all process heaters to demonstrate continuous complia nce with their applicab le emissions limits. The final rule requires that owners or operators in stall CEMS for demonstrating compliance with the
NO X emissions limits for all process heaters (40 CFR 60.107a(c) and (d)). As an alternative to this general requirement, the rule also provides that small proce ss heaters—those with rated heat capacities of less than 100 MMBtu/hr—may instead conduct bie nnial testing for demonstrating compliance with their NO X emissions limits. Commenter 0307 did not make this distinction in their comments. Thus, we want to reiterate that only smaller process he aters (those with rated heat capacities of less than 100 MMBtu/hr) may choose the opti on of biennial tests. This provision was included after consider ing available data on these small process heaters as well as the cost of applying a CEMS for these smalle r process heaters. For the available data117 summarized in the process heater memorandum, only one of 29 process heaters with data
obtained via CEMS has less than 100 MMBtu/h r capacity. For the data from small process heaters summarized in the process heater memo randum, 9 of 10 data points are a result of onetime source tests. Regarding the monitoring costs for small process heaters, we reviewed the estimated costs supporting the proc ess heater impacts memorandum (see the third attachment to Docket Item No. EPA-HQ-OAR-2007-0011-0222). Th e cost of a CEMS is fixed, regardless of the process heater size, so it is a larger portion of the cost for smaller process heaters, and the effect is to make the control option less cost effective for that process heater. For modified forced draft process heaters, for example, the CEMS contributes an additional 50 percent to the
annualized cost of the burner retrofits. The cost effectiveness of ultra-low NO X burner retrofits for a 200 MMBtu/hr process heater with and without CEMS is approximately $1,000 per ton of
NO X reduced and $1,500 per ton of NO X reduced, respectively. In cont rast, the cost effectiveness for a modified 70 MMBtu/hr forced draft process heater (the mid-point of the range of small process heaters) at a medium-sized refinery with and without a CEMS is about $3,600 and $2,300 per ton of NO X , reduced, respectively. Additionally, this option for small process heaters is not without its own continuous monitoring requirements. This option is provi ded specifically for units that use low-NO X or ultra-low NO X burner technologies because the performan ce of these control systems is generally quite stable. As noted previousl y, one important variable that a ffects the performance of these
burners is the level of exce ss oxygen supplied. To verify continuous performance that is indicative of the conditions presen t during the biennial source test s, the owner or operator must establish a maximum excess oxygen operating lim it or operating curve during the performance test and monitor the oxygen conten t in the exhaust on a continuous basis. What was inadvertently left out of the requirements for this option is the inclusion of this CPMS operating limit in the list of conditions that define reportable excess emi ssions. We are adding that requirement in these final amendments at 40 CFR 60.107a(h)(5); the eff ect of this amendment is that the owner or operator of a small process heater that elects to use biennial te sting for compliance must report any daily average oxygen concentration thatexceeds the maximum excess oxygen operating limit or operating curve as an exceedance of the NO X emissions limit, just as an owner or operator electing to comply us ing a CEMS must report any 30 -day period during which the average concentration of NO X exceeds the applicable emissions limit. Thus, considering all of118 the above, the monitoring requirements for process heaters—both large and small—are appropriate and sufficient for an owner or opera tor to demonstrate continuous compliance with the applicable NO X emissions limits.



### 5.3 Other Clarifications
Comment : Commenter 0311 requested that the term “other means” in 40 CFR 60.102a(i)(2) be replaced with “other combustion modification based technology” to clarify that evaluation or use of post-combustion technologies, su ch as SCR, are not required. Response : We agree that the language in 40 CFR 60.102a(i)(2), as worded, could be interpreted to mean that the petitioner would have to eval uate SCR technology and provide evidence as to why the emissions limit could notbe met using an add-on control technology.
This was not our intent. We meant for the evaluation to include potential combustion modifications. We have clarified the language in 40 CFR 60.102a(i)(2)(ii) to require that the owner or operator “demonstrate that ultra-low NO X burners, flue gas reci rculation, control of
excess air or other combustion modification-base d technology (including combinations of these combustion modification-based technologies) cannot be used to meet the applicable emissions
limit.”119 

## 6.0 COMPLIANCE REQUIREMENTS AND GENERAL MONITORING, RECORDK EEPING AND REPORTING

6.1 Rolling Averages
Comment : Commenter 0309 requested clarification regarding how to calculate rolling averages during periods when a CMS (including CEMS) exceeds the maximum prescribed span range in the rule. The commenter suggested that the EPA’s policy was that the maximum prescribed span range provided in the rule be used. For example, the commenter noted, for periods when the fuel gas monitor exceeds 300 ppmv H 2 S, 300 ppmv should be used in calculating the average for that time peri od, regardless of the monitor’s reading. Response : We do not agree that it is the EPA’s po licy, at least within 40 CFR part 60, to use the maximum prescribed span range when the monitor’s reading exceeds the maximum prescribed span when calculating rolling averages . It is our policy that sources with CMS data outside the certified span should report the CMS “out of contro l” and declare their compliance status as other than continuous. Additionally, for the purposes of calculating rolling averages, the direct monitor reading should be used for all pe riods that the CMS is operational, except for periods when the CMS data are invalidate d according to 40 CFR 60.13((h)(2)(iv). The CMS must be operational for all periods except for sy stem breakdowns, repairs, calibration checks and zero and span adjustments as specified in 40 CFR 60.13(e).
Comment : Commenter 0311 requested clarificati on on how the “365 successive calendar day rolling average” in 40 CFR 60.102a(g)(1)(ii) and the “rolling 365 successive operating day average” in 40 CFR 60.102a(g)(2) is to be calculat ed when: a) the unit is not opera ting; b) when the monitor is unavailable (or “out of control” according to Appendix F); a nd c) turndown occurs (if a separate emissions limit does not appl y to these periods as recommended by the commenter). According to the commenter, a fixed 365 calendar day period is easier to calculate than having to determine which days are to be included and having a different and changing number of calendar days in th e calculation of the average. Response : The final rule includes a requirement in 40 CFR 60.102a(g)(1 )(ii) to limit the long-term H 2 S concentration of fuel gas “determine d daily on a 365 successive calendar day120 average basis.” The final rule also includes NO X limits for process heaters determined on a “30- day rolling average basis” in 40 CFR 60.102a(g)(2). It is our intention that each 365-day average would be based on 365 calendar days. Similarly, it is our intention that each 30-day average would be based on 30 calendar days, regardless of whether the process heat er is operating at full capacity or in turndown. Only the hours that th e fuel gas combustion device is operating should be used when calculating the daily average for a given calendar day. If the fuel gas combustion device did not operate at all du ring a given calendar day, that day would have a null value and
would not be counted in the 30- day or 365-day average. As such, the 30-day rolling average may only contain 20 days of values if the process heater was not ope rating for 10 days during this 30- day period. Similarly, CMS “out of control” periods would be c onsidered null values for the purposes of calculating the 30-day or 365-day av erage. See also the previous comment and response regarding CMS “out of control” periods.



### 6.2 Excess Emissions
Comment : Commenter 0309 requested clarification of “all 12-hour periods” for excess emissions reporting because the note in 40 CFR 60.106a(b) conflic ts with guidance provided by EPA Region 3 on April 14, 2000. If the April 200 0 guidance is the preferred methodology, then
the EPA should delete the note and 3-hour st andards should be expressed as 180-minute

averages. Response : First, we note that the guidance pr ovided by EPA Region 3 is based on the language as it was in subpart J prior to amendm ents, where no additional guidance in the rule was provided on how to calculate the 12-hour aver ages. As such, Region 3’s interpretation is justified based on the language used in subpart J. However, requiring 12-hour averages to be calculated every minute greatly increases the co mputational and data storage requirements for the refinery with little to no environmental benefit. It is extremely unlikely that a 12-hour average excursion will be “seen” when evaluating “by minute” 12-hour aver ages and not “seen” when calculating hourly averages. While the hourly averages should be calculated using the continuous data ( i.e. , by minute), there is no need to store these “by minute” data for 12 hours, increasing the storage needs by an order of ma gnitude. We note that the sections describing excess emissions ( e.g. , 40 CFR 60.106a(b), 40 CFR 60.107a(h)) already specify that the 3-hour or 12-hour periods are to be dete rmined by first calculating hourly averages and then taking the121 arithmetic average of the appropriate number of contiguous hourly averages, and we do not find it necessary to amend the rule to provide further guidance.



### 6.3 Monitoring Methods
Comment : Commenter 0311 stated that the refere nce to Gas Processors Association (GPA) Standard 2172-96 in 40 CFR 60.17(m)(2 ) and 40 CFR 60.107a(d)(7)(v) should be updated to GPA 2172-09 because the standard has been updated. Response : We agree, and both 40 CFR 60.17(m)(2 ) and 40 CFR 60.107a(d)(7)(viii) have been updated to reference the latest version of the standard.



### 6.4 Reporting Requirements
Comment : Commenter 0311 suggested that the reporting requirement in 40 CFR 60.108a(c)(6) for RCA be revised to quarterly rather than per event. Response : First, 40 CFR 60.108a(c)(6) includes reco rdkeeping requirements and should not be confused with reporting requirements. Section 60.108a(c)(6) requires refinery owners and operators to keep records of a ll the RCA info, but it does not specifically require submission of reports. We also note that 40 CFR 60.103a(d) an d (e) use the term “record” or “record and explain.” While the latter sugge sts reporting, neither of these sp ecifically requires submission of the record. The actual reporting requirements are summarized in 40 CFR 60.108a(d), which requires refinery owners and operators to submit excess emission reports on the schedule required by 40 CFR 60.7(c) and describes the information to be included in th e report. Section 60.7(c) requires excess emission reports to be submitted semi-annually: “E ach owner or operator required to install a continuous monitoring device shall submit excess emissions and monitoring systems performance report (excess emissions are defined in appli cable subparts)...to the Administrator semiannually....All reports shall be postmarked by the 30th day following the end of each six-month period.” Therefore, while th e report must detail each event that occurred during the reporting period, these reports only need to be submitted on a semi-annual basis.



### 6.5 Impacts on Small Refineries
Comment : Commenter 0302 stated that much of the monitoring, recordkeeping and reporting requirements are independent of the size of the refinery, and small refineries, especially122 those not subject to a consent decree, will have a greater burden in terms of “cost per gallon” than larger refineries. Response : We expect smaller refineries will have fewer flares and fewer process heaters
above 40 MMBtu/hr and/or 100 MM Btu/hr thresholds that requi re monitoring. The alternative monitoring for process heat ers less than 100 MMBtu was specifically included at 40 CFR 60.107a(c)(6) and 40 CFR 60.107a(d)( 8) based on the costs of the NO X CEMS, and should provide significant relief for small refine ries. We were unable to identify reasonable
alternatives to direct monito ring for flares, given the expect ed variability in flow and composition of flare gas. As such, we require the same level of monitoring for flares regardless of the size of the flare or the refinery.