From: Brenda Shine/RTP/USEPA/US@EPA Sent: 02/28/2012 0 6 :4 4 PM To: "Higgins, Cortney" < Cortney_Higgins@omb.eop.gov > Cc: Penny Lassiter/RTP/USEPA/US@EPA, William Nickerson/DC/USEPA/US@EPA Subject: RE: Interagency Comments under EO 13563 on Petroleum Ja draft final rule

Cortney,
Here is the Response to Comments document.

Brenda Shine Environmental Engineer US Environmental Protection Agency Research Triangle Park, NC 27711 (919) 541

- 3608, Mail Drop E143

- 01

<< Subpart Ja Draft Response to Comments

- 1

- 26

- 12_clean.doc >>

From: "Higgins, Cortney" < Cortney_Higgins@omb.eop.gov > Sent: 02/28/2012 0 5 :4 7 PM To: Brenda Shine/RTP/USEPA/US@EPA Cc: Penny Lassiter/RTP/USEPA/US@EPA, William Nickerson/DC/USEPA/US@EPA Subject: RE: Interagency Comments under EO 13563 on Petroleum Ja draft final rule

Additionally, we also request the response to comments document ( Standards of Performance for Petroleum Refineries: Background Inform ation for Final Amendments

- Summary of Public Comments and Responses , dated December 2011) referenced in the preamble.
Regards, CortneyDRAFT

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

Summary of Public Comments and ResponsesDRAFT

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ii This page intentionally left blank.DRAFT

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

Summary of Public Comments and Responses

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 Emission Standards Division Research Triangle Park, North Carolina 27711

December 2011DRAFT

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iv Disclaimer

This report has been reviewed by the Sector Policies and Programs Division of the Office of Air Quality Planning and Standards, EPA, and approved for publication. Mention of trade names or commercial products is not intended to constitute endorsem ent or recommendation for use.DRAFT

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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

................................ ................................ ................................ ....... 18 2.4 Notification Schedule

................................ ................................ ................................ ... 33 2.5 Overlap with and Effect on Other Subparts

................................ ................................ . 34 2.6 Equivalence with State and Local Ru les

................................ ................................ ...... 35 3.0 Definitions

................................ ................................ ................................ ............................. 40 3.1 Air Preheat

................................ ................................ ................................ ................... 40 3.2 Co

- Fired Proces s Heater

................................ ................................ .............................. 40 3.3 Corrective Action Analysis

................................ ................................ .......................... 41 3.4 Delayed Coking Unit

................................ ................................ ................................ ... 42 3.5 Flare

................................ ................................ ................................ ............................. 43 3.6 Fuel Gas

................................ ................................ ................................ ....................... 45 3.7 Fuel Gas Combustion Device

................................ ................................ ...................... 48 3.8 Natural Draft and Forced Draft Process Heaters

................................ ......................... 48 3.9 Process Upset Gas

................................ ................................ ................................ ........ 50 3.10 Refinery Process Unit

................................ ................................ ................................ .. 52 3.11 Sulfur Recovery Plant

................................ ................................ ................................ .. 53 4.0 Fuel Gas Combustion Devices and Flares

................................ ................................ ............ 57 4.1 Emissions Limits

................................ ................................ ................................ .......... 57 4.1.1 Long

- Term H 2 S Concentration Limit for Fuel Gas Combusted in Flares

....... 57 4.1.2 Alternative Complianc e Options

................................ ................................ ...... 58 4.2 Elimination of Routine Flaring

................................ ................................ .................... 61 4.3 Flare Flow Rate Limit

................................ ................................ ................................ .. 65 4.4 Other Standards for Flares

................................ ................................ ........................... 65 4.4.1 General Comments on Other Flare Standards

................................ ................. 65 4.4.2 Flare Management Plan Requirements

................................ ............................ 67 4.4.3 Root Cause Analysis and Corrective Action Analysis

................................ .... 69 4.5 Monitoring Fuel Gas Combustion Devices

................................ ................................ .. 76 4.6 Sulfur Monitoring for Flares

................................ ................................ ........................ 77 4.7 Flow Monitoring for Flares

................................ ................................ .......................... 83 4.8 Compliance Schedule

................................ ................................ ................................ ... 86 4.9 Startup, Shutdown and Malfunction

................................ ................................ ............ 88 5.0 Process Heaters

................................ ................................ ................................ ..................... 98 5.1 Emissions Limits

................................ ................................ ................................ .......... 98 5.1.1 Equivalence of Emissions Limit Units

................................ ............................ 98 5.1.2 Limits for New, Modified and Reconstructed Forced Draft Process Heaters

................................ ................................ ................................ ............. 98DRAFT

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vi 5.1.3 Turndown

................................ ................................ ................................ ....... 100 5.1.4 Site

- Specific Emissions Limit Clarifications

................................ ................. 102 5.1.5 Co

- Fired Process Heaters

................................ ................................ ............... 108 5.2 Monitoring of Process Heaters

................................ ................................ ................... 110 5.3 Other Clarifications

................................ ................................ ................................ .... 115 6.0 Compliance Requirements and General Monitoring, Recordkeeping and Reporting

........ 116 6.1 Rolli ng Averages

................................ ................................ ................................ ....... 116 6.2 Excess Emissions

................................ ................................ ................................ ....... 117 6.3 Monitoring Methods

................................ ................................ ................................ .. 118 6.4 Reporting Requirements

................................ ................................ ............................ 118 6.5 Impacts on Small Refineries

................................ ................................ ...................... 118DRAFT

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1 

## 1 .0 I NTRODUCTION

On June 24, 2008 ( 73 FR 35838 ), the U.S. Environmental Protection Agenc y (EPA)
issued : (1) final amendments to the existing refineries new source 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 stay of the following provisions of 40 CFR part 60, subpart Ja: (1)
the flare modification provision ; (2) the definition 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 flares; and (6) the nitrogen oxides (NO X ) emissions limit for pro cess heaters. On December 22, 2008, the EPA proposed to extend the original 90

- day stay until the

a gency 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, 2 00 8 (7 3 FR 78522 ) , the EPA proposed amendments to the NSPS in 40 CFR part 60, subpart s J and Ja to address the reconsidered issues as well as technical
corrections

. The proposal provided a 45

- day comment period
, ending February 5, 200 9

. The
EPA received 20 comments on the proposed amendments from refiners, industry trade associations and consultants, s tate environmental departments, environmental groups and other interested parties during the comment period. Following the close of the public comment period,

two additional comment letter s w ere received. All 2 2 of t hese comments have been placed in the docket for this rulemaking (Docket No. EPA

- HQ

- OAR

- 200 7

- 0 0 1 1). Table 1 lists the names and affiliation of each comment and the assigned docket number

.DRAFT

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2 Table 1. L ist of Commenters on the Proposed Amendments to 40 CFR Part 6 0 , Subpart Ja

Docket Item No. EPA

- HQ

- OAR

200 7

- 0 0 1 1

- Commenter and Affiliation
0 2 9 5 B. Lane, Environmental Consultant
0 2 9 6 R.A. Cade, Marathon Petroleum Company LLC
0 2 9 7 M. Resh, Linde North Am erica, Inc.
02 9 8 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 G roup, 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 Proj ect (EIP) , also on behalf of Natural Resources Defense Council ( NRDC) and Sierra Club
0308 C

. S. Colman, HESS C orporation , on behalf of HOVENSA LLC
0309 T.K. Metrose, Tesoro Corporation
0310 K.A. Saffell, Valero Energy Corporation

0311 R. Chittim, Ameri can 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, BAAQMDDRAFT

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3 Several commenters, in addition to providing specific comments, also expressed support for comments provided by other commenters (generally, individual companies indicating support for comments submitted by the ir trade organization). Specifically, Commenters 0295, 0301, 0302, 0304, 0305, 0306, 0308 and 0310 supported comments submitted by Commenter 0311 (API , NPRA and WSPA ). By convention, the commenter numbers presented in the comment 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 commen ts 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

.DRAFT

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4 

## 2 .0 APPLICABILITY

2 .1 Applicability of Subpart Ja

2.1.1 Gasification

Comment : Commente r 0300 stated that the EPA should exempt entrained flow gasification processes from subpart Ja. The commenter cited a recent applicability determination provided by the South Dakota Department of Environmental Resources that indicated syngas produced from coke gasification was not fuel gas subject to subpart Ja and questioned how the gasification process would be considered a refinery process unit and the associated flare a fuel gas combustion device under the proposed amendments

. The commenter stated that the best system of emission reduction ( B SER ) 1 determination did not address 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 fu el gas. The commenter noted that both 40 CFR part 60, subpart Da and subpart Ja would apply to their gasification facility, causing redundant requirements, but the commenter’s only specific object ion was to the requirement to conduct a root cause analysis (RCA) for planned startup and shutdown 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

c ombustion under normal operations

. Commenters 0310 and 0311 objected to the proposed amendments to the definition of “fuel gas” and “refinery process unit” to include coke gasification. The commenters cited a Delaware court case that an adjacent coke gasif ication 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 contend ed that coke gasification was not considered in the original NSPS ( 40 CFR part 60, subpart J) because the technology was n ot developed until

1 The level of control prescribed by CAA section 111 historically has been referred to as “ b est d emonstrated t echnology” or BDT. In order to better reflect that CAA section 111 was amended in 1990 to clarify that “best systems” may or may no t 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.DRAFT

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5 the mid

- 1980 s , and the subpart Ja rulemaking docket contains no BSER analysis specific to coke gasification. As such, the commenters asserted that the revision is more than a “clari fication
, ” the rulemaking record fail ed to satisfy applicable procedural standards for establishing BSER and
the EPA f a il ed 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 i s in the form of carbonyl sulfide (COS) and provided a cost for systems to meet a TRS 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 successive calendar day rolling average basis (hereafter referred to as the long

- term 60 ppmv H 2 S concen tration limit). The commenter stated
that the control system i s not BSER because the cost effectiveness of the system is roughly $20,000/ton of sulfur dioxide ( SO 2 ) reduced

. The commenter also contend ed that flexicoking
units are “materially different” tha n coke gasifiers by focusing on the upstream coking processes associated with a flexicoking unit rather the production and treatment of low energy gas from the flexicoking gasifier. The commenter note d that FLEXSORB amine treatment units achieve <10 ppmv H 2 S on fl e xicoking gas but suggest ed that this performance is not applicable or representative of the performance achievable from 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 security objectives. Response : The key issues here are: ( 1) whether the clarifications to the definition of “fuel gas” and “refinery process units” alter ed the historic applicability of the refinery fuel gas
standards for coke gasifiers ; and ( 2) whether low

- Btu gas produced from coke gasification units
should be subject to the fuel gas standard s. 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 “ fuel gas ” at 40 CFR 60.101a is “any gas which is

gener ated at a petroleum refinery and which is combusted
, ” and the amendments do not alter that language. The definition does not require 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 refinery” at 40 CFR 60.101a is “any facility engaged in producingDRAFT

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6 gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleu m or through redistillation, cracking, or reforming of unfinished petroleum derivatives. ” The primary subject in this definition is “ a ny facilit y .” It is not “the group of refinery process units” or similarly limiting phrases

. The definition of petroleum r efinery include s the entire facility. If a coke gasifier is located at a facility “engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or throu gh 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 gasification process itself is considered a refinery process unit ( see next paragraph for discussion on this issue). Consequently, prior to the newly proposed clarification to the definition of “fuel gas” in subpart Ja, it appears that a flare or other

un it that combust s gas for a coke gasifie r would be a “fuel gas combustion device” and an affected facility under subpart J or Ja, provided that the ga s ifier is located at a petroleum refinery

. B ased on the backg round provided by Commenter 0 300 ( “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” ) , th e coke gasifier is located at a petroleum refinery and th e gas generate d by the gasifier meets the
definition of “fuel gas” regardless of the proposed clarification s to subpart Ja

. Consequently, we find that the coke gasification unit described by C ommenter 0300 is located at a petroleum refinery, the syngas pro duced by the unit is “fuel gas” and the flare combusting the fuel gas is an affected source subject to subpart Ja

. ( See letter to Preston Phillips, Vice President, Hyperion Refining LLC, from Cynthia J. Reynolds, Director, Technical Enforcement Program, U. S. EPA, Region 8, dated November 20, 2008 (Applicability Determination Control Number: 0800090)
for further 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 Co mmenters 0310 and 0311, the reason
the Court held that the coke gasification plant was not part of the refinery was because of the physical location of the coke gasification plant, i.e. , it was located next door to the refinery rather
than “in” the refiner y (“[I]n determining 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 fa cilities inDRAFT

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7 question.”). The Court did not address the factual situation in which a coke gasifier and turbines are physically located “in” the petroleum refinery

. See 40 CFR 60.100a(a); Star Enterprise , 235
F.3d at 151

- 152. With respect to the proposed cla rification 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 conducted.” As stated previously , the petroleum refinery include s the entire facility. Thus, to be considered a refinery process unit, only two
criteria are needed: ( 1) the unit must be located at a petroleum refinery ; and ( 2) the unit must be used to conduct “a specific processing operation.” The definition does not di rectly limit the scope of “processing operations.” That is, the definition of refinery process unit does not limit process operations to distillation, re

- distillation, cracking or reforming, and it does not limit it to only those processes used to produce gasoline, kerosene, 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 located at a petroleum refinery

. Consequently, we considered the

pro posed inclusion of coke gasification (as well as product loading, sulfur recovery and wastewater treatment) as an example of a refinery process unit to be a clarification of the existing
definition rather than an expansion of the definition

. (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 subject to the fuel gas standards. The commenters suggest that a separate analysis of the BSER is needed for coke gasification units and that the requirements of

s ubpart Ja are not cost effective for coke ga s ifiers

. We find that both the long

- term 60 ppmv H 2 S concentration limit and the 162 ppmv H 2 S concentration limit determine d hourly on a 3

- hour rolling average basis (hereafter referred to as the short

- term 162 ppmv H 2 S concentration limit)

are achievable based on the information provided by C ommenter 0300 , as well as the performance of other integrated gasification combined c ycle ( 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 sulfur can be efficiently removed prior to final
combustion. Commenter 0300 only expressed concern 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 oxygenDRAFT

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8 rather t han air, the fact that the FLEXSORB amine treatment units achieves <10 ppmv H 2 S on 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 long

term 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 gasification , 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 ga s. While we evaluated limiting the concentration of other reduced sulfur compounds in fuel 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 c ontent of the fuel gas. Although we encourage the use of these COS removal technologies, 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 limit s

. 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 concentrati on limit
is achievable and cost effective and therefore BSER

. In addition, this information supports our decision to finalize the proposed clarification that fuel gas includes “gases from flexicoking unit gasifiers and other gasifiers .” Regarding flares as sociated with coke gasification units, we note that a s described in
more detail in Section 4. 4 .3 , we agree that a RCA is unnecessary for planned startup s and
shutdown s that are already subject to and following minimization requirements of the flare

managem ent plan (FMP) under 40 CFR 60.103a(a)( 5 )

. Eliminating the RCA requirement for planned startups and shutdowns of units following the ir 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 should regulate facilities 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 definitions for “petroleum refinery” and “ refineryDRAFT

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9 process unit,” but it is important for the EPA to set strict emission s limits and monitoring requirements to regulate emissions from these facilities. The commenter noted that extraction of oil from tar sands and oil shale are energy intensive pro cesses, resulting in nearly three times more greenhouse gas emissions than extraction of conventional crude oi l

. 2 The commenter also
noted that oil shale extraction releases emissions of SO 2 and other sulfur compounds, particulate matter ( PM ) , carbon monox ide ( 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 req uested that the definition specifically exclude oil production as well, either by referring to Standard Industrial Classification (SIC) 2911 or adding
, “nor is the extraction or production of
crude oil” to the end of the definition. Response : The definitio n of “ petroleum refiner y” does not include, and could not be reasonably con s trued to include
, conventional oil production facilities. W hile w e also do not
believe oil shale and tar sand processing facilities fall within the regulatory definitions for “petr oleum refinery,” the presence of a distillation or separation unit at these oil shale and tar sands processing facilities led to ambiguities, which is why the clarification was included in the
definition. I t may be reasonable to apply certain subpart Ja st andards , 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 refinery. As in the previous discussion regarding coke gasification, we do consider oil shal e 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 emissions standards. However, m ore information is needed on the operations and emissions from these oil production facilities. We are continuing to look at these processes to determine if regulation of these emission sources is ne eded. We do note that upgrading units that employ coking units to process tar sands into a synthetic crude oil do not meet the exclusion from the definition of a petroleum refinery because these facilities do more than simply remove diluent from the heavy oil that was added to effect extraction or to improve flow characteristics for pipeline transport.

2 Wakefield
, Ben , and Matt Price, Environ m ental In tegrity Project

. Tar Sands: Feeding U.S. Refinery Expansions with Dirty Fuel

. June 2008

. 3 Bordetsky
, Ann , et a l ., Natural Res. Def. Council et a l

. Driving it Home: Choosing the Right Path for Fueling North America’s Transportation Future

. June 2007

. A vail able at http://www.nrdc.org/energy/drivingithome/drivingithome.pdf

.DRAFT

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10 

### 2 .1.3 Flares

Comment : Commenters 0305 and 0311 objected to the reference to the expanded subpart
Ja definition of “flare” in s ubpart J and stated that it expands the applicability of subpart J retroactively. According to Commenter 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 historically under subpart J. Response : We find that the lack of a definition of “flare” in subpart J has lead to confusion and disagreement with what is included in the definition of a flare. As stated previously, we do not consider the reference in subpart J to the definition of flare in subpart Ja as changing the definition of flare under subpart J, regardl ess of there being no formal definition included in that subpart. The industry petitioners to the final rule and this commenter suggest that the definition of “flare” in subpart Ja is different from the general interpretation of a flare under subpart J, bu t we find no support for this position, and commenters have provided none. After again reviewing the available information, we maintain that the cross

- reference in subpart J to the definition of “flare” in subpart Ja only changes the applicability date for flares. If disagreements exist regarding what parts of a flare are covered as fuel gas combustion devices under subpart J, these disagreements should be addressed through other available Clean Air Act ( CAA ) regulatory mechanisms, such as through Applicabi lity Determinations under 40 CFR
60.5.
Comment : Commenter 0311 stated that temporary flares (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 cl eanings or similar activities in remote areas of the refinery. Commenter 0315 clarified that temporary flares might be needed to handle emergency flows
while the main flare is off

- line for purposes of installing equipment needed for that main flare to

comp ly with subpart Ja. According to the commenter, the EPA should encourage maintenance of existing flares, but these activities would be discourage d if the temporary flares were subject to
the rule. Also, the commenter state d that the EPA did not consider th e costs of subjecting temporary flares to s ubpart Ja. Response : With respect to flare maintenance, if the flare being maintained is already subject to subpart Ja, it appears that the temporary flare should be able to comply with subpart
Ja. If the temporar y flare is considered a “new” flare , then routine maintenance of a flare notDRAFT

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11 currently subject to subpart Ja would effectively trigger the rule. We can see that this could create an unnecessary barrier to properly maintaining the flare

. Given the importanc e of flares in the safe operation of the facility and in the destruction of flammable gases in the case of an upset or malfunction, we agree that a temporary flare installed for the purposes of conducting maintenance on an existing flare must meet the appl icable limits of the flare that it is temporarily replacing and does not, in itself, trigger applicability to subpart Ja. For tank cleaning operations , we believe that the gases generated can be considered process upset gases (produced as a res ult of start up or shutdown). Thus, the rule specifically allows the use of a flare to combust these gases without subjecting them to H 2 S concentration requirements for fuel gas

. As such , for tank cleaning operations
, these flares would only be subject to RCA and FMP r equirements

. As discussed in Section 4.4.3 , we have modified the requirements in 40 CFR 60.103a( d ) ( 3 ) t o 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 minimization to clarify that the provisions apply to

“ planned startup and shutdown of the refinery process units and ancillary equipment that are
connected to the affected flare. ” W e interpret “ancillary 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 o r operator prepares FMP for tank cleaning operations
and follows those plans
, then the tempora ry flare would be compliant with the requirements of subpart Ja. Consequently, the question becomes whether preparing a FMP is necessary and appropriate ( i.e. , BSER ) for storage vessel cleaning operations. The additional cost is minimal, as
one flare manag ement protocol can cover multiple storage vessels. While adequate purging of the storage vessels is necessary, protocols to minimize unnecessary purges to the flare are expected to reduce both SO 2 and NO X emission s and minimize auxiliary natural gas use (n eeded to maintain Btu content of the high nitrogen content purge gas). As such, we find that it is reasonable to require temporar y flares used for planned start up and shutdown of process units to comply with subpart Ja by preparing and follo wing a FMP

. Con sequently, we are not providing a general exclusion for temporary flares. While there 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.DRAFT

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12 Comment : Commenter 0296 stated that the EPA ignored hydrogen flares in the ir analysis
and stated that no volatile organic compound ( VOC ) emissions occur as a result of flarin g 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 hydroc racking units) , and if the hydrogen i s nearly pure, recovery and use of this stream has environmental benefits. If the hydrogen stream is not pure, then flaring reduc tions can also lead to emission reductions of SO 2 and VOC. As such, the final requirements for flares do not specifically exclude hydrogen flares.



### 2.1.4 Other Units

Comment : Commenter 0311 stated that fluid catalytic cracking unit (FCCU) start up heaters should be excluded from the process heater definition. These in

- line heaters are used for
10 0 to 125 hours to heat air that then heats the catalyst and catalyst vessel during FCCU startup. The commenter believes these are not process heaters as they do not “transfer heat indirectly to process stream materials” and request ed that the EPA clarify t he point by specifically excluding such heaters from the process heater definition

. Response : Based on the limited description of the startup F CCU heater provided by the commenter, it does appear that this type of unit does not meet the definition of proce ss heater and would not be subject to the NO X emission s limits. Additional information obtained on an FCCU heater at the ConocoPhillips Trainer Refinery 4 indicates that for at least one of these types of units, there is no process feed during the FCCU star tup 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 emission s limits or the H 2 S concentration limits

. We are not making any changes to the final rule to address 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 the 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

4 Wallwork, James F. ConocoPhillips Trainer Refinery Additional Comments on Proposed Plan Approval 23

- 0003P . Letter to Sachin Shankar, P.E., Pennsylvania Department of Environmental Protec tion. October 15, 2009.DRAFT

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13 specific unit meets the definition of “ process heater ” 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 considered fuel gas if it is combusted in an internal combustion engine or thermal oxidizer. The commenter recommended that subpart s J and Ja not apply to these temporary controls. 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 engi ne or thermal 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 start up or shutdown). Thus, the rule specifically allows the use of a flare to combust these g ases, but the use of an internal combustion engine or thermal oxidizer would appear to be prohibited 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
the se control systems is difficult to justify. We agree that it is preferable that these tank cleaning emissions be combusted rather than released directly to the atmosphere. We also find that internal combustion engines would provide a comparable level of co ntrol as a flare with the added advantage of producing useful work, which can further reduce emissions elsewhere in the refinery by reducing energy consumption demand

. A thermal oxidizer, while providing a comparable level of control, has the disadvantage 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. Finally, we agree that
, for most tanks, based on distance to a fuel gas line and th e frequency of degassing and cleaning (typically once every 5 to 10 years) , it
would not be cost effective to have to capture and treat the relatively small quantities of gas that are produced infrequently due to tank degassing and cleaning. As such , we ha ve added a provision to 40 CFR 60.10 2 a ( g )(1)(iii) to specifically exempt “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 sug gested that December 22,
2008 (the proposal date of the amendments 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 industryDRAFT

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14 was provided adequate notice of the new requirements

. Commenters 0310 and 0311 further
asserted that the EPA has the discretion and authority to extend the applicability dat e to December 22, 2008. Commenter 0306 and 0311 stated that the June 24, 2008
, trigger date for flares is inappropriat e because the term “modification” 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 inconsistent with and interfere with consent decree obligations.
Comm enter 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 December 22, 2008
, proposal
date should be the applicability date for process heater provisions. The commenters state d that the original proposal date is inappropriate because the final standards were more stringent than
those originally proposed on May 14, 2007

. Commenter 0296 noted that the June 24, 2008 , final
rule notice included NO X limits of 40 ppmv but suggested th at December 22 , 2008, is the proper applicability date
, as the NO X provisions in the final rule were stayed. Commenter s 0311 and
0314 suggest ed 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 Commenter s 0296 and 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 expect ed the standard to be 80 ppmv NO X . C ommenter 0296 cited an erroneous statement in the Regulatory Impact Analysis suggesting th at 80 ppmv would be allowed for process heaters that commenced construction 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 pp mv emissions limit. Similarly, Commenter 0314 noted that the only way for their process heater currently under construction to meet the 40 ppmv emissions limit is to install selective catalytic reduction (SCR), so they are making provisions to install SCR even though the EPA already determined that SCR is not
BSER

. According to both commenters, e ither changing the effective date of the requirement or changing the emission s limit for newly constructed forced draft process heaters would eliminate
this “retroa ctive noncompliance” issue

.DRAFT

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15 Commenter s 0310 and 0311 stated that, if the EPA imposes standards on syngas produced by coke gasification, then the applicability date of those requirements should be no earlier than the December 22, 2008
, proposal date. Commen ter 0311 also indicated that the trigger date for other newly defined 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 heater is a “new source” and subject to subpart Ja? (2) When must that “new” flare or process heater be in compliance with the applicable requirements in subpart
Ja? Section 111(a)(2) of the CAA defines a “new source” as “any s tationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.” An impor tant aspect of this definition is the “notice” it provides that NSPS will be prospectively applicable after construction, reconstruction or
modification of an affected source. For NSPS subpart Ja, a “new” process heater is one that commences construction, reconstruction or modification after May 14, 2007, which is the date of the “proposed regulations.” For the reasons explained in the final rule preamble at 73 FR 35856

- 35857 , a “new” flare is one that commences construction, recon struction or modification after June 24, 2008, which is the date of the “publication of regulations.” Therefore, in compliance
with CAA section 111(a)(2), refineries are on “notice” that after these respective dates, “new” process heaters and “new” flares will be subject to subpar t 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 their basic po sition boils down to a lack of “notice,” which they assert requires the EPA to move the “trigger date” for subpart Ja applicability to December 22, 2008, the proposal date for the proposed amendments. With respect to flares, we find no validity in the argu ments that the June 24, 2008, applicability data is inappropriate. The limited changes in the flare modification provision proposed on December 22, 2008, only identified certain connections that are not considered
modifications of a flare. As such, we see no scenario where the revised flare modification provision would trigger retroactive application of the rule.DRAFT

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16 For process heaters, while we recognize that the emission s limits and form of the
standard ha ve changed based on the information gathered during t he rulemaking process, the regulated community was notified that NO X standards were being considered for process heaters on May 14, 2007

. The b est system of emission reduction should be implemented at this time. We recognize that refinery owners and operat ors desire maximum operating flexibility, but the proposed rule clearly indicated that controlling excess oxygen amounts is part of BSER , and process heater design and operation at high excess oxygen content was not considered BSER

. While we acknowledge th at the initially promulgated 40 ppmv 24

- hour NO X emission s limit and

even the final amendments to these standards may limit operator flexibility to a greater extent than the originally proposed emission s limits, we find that the emission s limits in the fin al amendments are achievable and appropriate for newly constructed process heaters.
As discussed in greater detail in Section 2.1.1, the proposed clarifications of fuel gas and refinery process units in no way impacted the applicability of subpart Ja stand ards to the units in question. As such, we see no reason to specify 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 commenced , then all the fuel gas combusted by that
device must meet th e sulfur standards, regardless of its origin, so an applicability date for coke gasification is irrelevant. Similarly, we see no basis or need to specify applicability dates for wastewater treatment systems or loading operations. Gas es generated from these units w ere always considered to be fuel gas ( unless they meet the newly established exempt ion from the definition of fuel gas for combustion of vapors in a flare or thermal oxidizer to control
emissions )

. If these gases were not already considered fuel ga s, than this exemption would have
been unnecessary and the industry would not have provided so many comments to expand the exemptions for different types of fuel gases. Furthermore, as w e did not specify any specific regulations for wastewater treatment un its or loading racks under subpart Ja , we do not
understand the commenters ’ request to change the applicability date.
Comment : Commenter 0305 recommended that 40 CFR 60.100a(c) clarify that: “For the purpose of this subpart, all projects committed to and s ubject to compliance with a Consent Decree filed with the Department of Justice prior to May 14, 2007 are deemed to haveDRAFT

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17 commenced prior to May 14, 2007.” Th e commenter stated that thi s clarification is needed
because s ubpart Ja could significantly impact (or create uncertainty in) some projects which have been long planned and committed to in order to comply with a c onsent d ecree

. Response : We decline to make this change, which equates to a request that the EPA find that the filing date of a c onsent d ecree is equivalent or should be deemed equivalent to the date
construction “commences” for all refinery projects covered under consent decrees. Instead, sources should continue to use the following definitions from 40 CFR 60.2 in making this
determination :

Co mmenced means, with respect to the definition of new source in section 111(a)(2) of the Act, that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligatio n to undertake and complete, within a reasonable time, a continuous program of construction or modification.

Construction means fabrication, erection, or installation of an affected facility.

Modification 5 means any physical change in, or change in the met hod of operation of, an existing facility which increases the amount 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 pollutant (to which a standard applies) into th e atmosphere not previously emitted.
The definitions provide a reasonable set of criteria for determining when construction or
modification commenced and should be applied on a project

- specific basis. Sources that have any questions regarding how the final amendments to subpart Ja may impact their compliance with their consent decree should contact the EPA personnel within EPA’s Office of Enforcement and Compliance Assurance (OECA) with whom they negotiated the consent decree.
Comment : Commenter 0315 reques ted clarification regarding the timing of potential
modifications. The proposed rule text, read literally, could be interpreted 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 i f that connection is a modification. However, in most cases, most of the work on the project has occurred before the actual connection is made, partly because accomplishing the connection and allowing flare header hydrocarbon to flow into new equipment pos es a major

5 Sources should also reference CAA section 111(a)(4) and 40 CFR 60.14 when determining whether a “modification” has occurred.DRAFT

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18 safety risk. The commenter also noted that this literal interpretation 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 undertaken a cont inuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or modification.” The commenter requested that t he final rule clearly specify that, for projects where a flare connection is part of an entire project, the potential flare modification is considered to have begun upon the commencement or contracting of the project ( i.e. , a continuous program of

construc tion or modification that happens to include a new connection to a flare). Response : It is not our intention to apply a definition of “commenced” 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 continue using the definitions of “commenced,”
“construction” and “modification” 6 from the General Provisions for determining when a particular project “commences.” Using those definitions, it already appears tha t the date a source would use for evaluating whether a new connection to a flare is a “ modification ” of that flare

w ould be t he date that the entire project “commences
, ” not necessarily the date the piping is physically connected to the flare header. Howev er , we recognize that the “new connection” language in the flare modification provision could be misconstrued in this context; t herefore , we have added a sentence to 40 CFR 60.100a(b) that states: “For the purposes of this subpart, a
modification to a flar e commences when a project that includes any of the activities in paragraphs (c)(1) or (2) of this section is commenced.”



### 2

. 3 Flare Modification
Comment : Commenter 0308 objected to the special modification provision for flares in subpart Ja. The commenter stated that the provisions in 40 CFR 60.14 can and should apply to
flares. Specifically, the EPA should consider the “...hourly emission rate, at maximum physical capacity, before and after an operational change” (57 FR 32316). Because the maximum physical

c apacity of the flare, even when considering the header system as part of the flare, is not changed by additional tie

- ins, new tie

- ins should not constitute a modification, according to
Commenters 0308 and 0311. Furthermore, the commenters asserted that the NSPS program was

6 See footnote 4.DRAFT

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19 never intended to apply across an entire industry based on minor changes of an affected facility. Commenter 0310 stated that the flare modification provision is unlawful because routine connections generally do not result in an emissions increase and may be seen as having the primary purpose of reducing emissions, which has 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 m odification 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 t ie

- ins, so that the net emissions could actually be reduced, and requested clarification if it

was the EPA’s intent for such projects to constitute a flare modification. Commenter 0310 stated that the flare modification provision in 40 CFR 60.100a(c)(2)
sh ould specify that the increase in flow capacity is an increase in the total volume of gas under standard conditions that could reach the flare and that it is specific to flow increases of VOC or sulfur compounds. Commenter 0309 suggested that most of the e xemptions could be reduced down by focusing the rule on SO 2 emissions and exempting any connection of fuel gas that has a
H 2 S concentration of less than 162 ppmv. Commenter 0305 stated that “flow” is not a regulated pollutant, so an increase in flow should not be considered a modification. Commenter 0314 agreed that examining what is a flare modification is warranted and agreed that projects that increase production through new process vents to flares or projects that increase process vent
flow rates to fla res should be subject to subpart 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 proces s unit to the flare , such as delayed coking unit offgas

. Response : The a gency made a conscious decision to promulgate a separate provision for
a flare modification in 40 CFR part 60, subpart Ja (see 40 CFR 60.14(f)) because flares are operated differently from other refinery process units, making it difficult to apply the modification provision in the General Provisions (40 CFR 60.14) to them

. The physical capacity of a flare is based on the amount of gas potentially discharged to a flare as a result of eme rgency relief

. Refiners frequently make connections to existing flares that result in emissions increases at the flares, but may never approach the physical capacity of the flare system

. Contrary to commenters’ assertions, the flare modification provision in 40 CFR 60.100a(c) does meet theDRAFT

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20 statutory definition of “modification” in CAA section 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 su ch source or which results 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 resulted in emissions increases from the flare (see
73 FR 78529 )

. Thus, these types of new connections of refinery process units (including ancillary equipment) and fuel gas system s to the flare qualify as a “m odification” of the flare and trigger subpart Ja applicability for the flare

. Those connections we identified that do not increase emissions from the flare were specifically excluded from triggering 40 CFR part 60, 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 not be considered a modification of the flare: (1) connections made to install monitoring systems to the flares; (2) connections made to install a flare gas recovery (FGR) system; (3) connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an inter nal diameter no greater than the existing equipment being replaced or upgraded ; and (4) r eplacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved

. 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 details), we disagree w ith the commenters that the flare modification provision should 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

. As such, using the flare as a VOC emissions control device may yield a net emissions decrease of VOC at
the r efinery, but it will result in an increase in VOC emissions at the flare, which is the affected

source

. 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 asDRAFT

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21 other air pollutants, all of which are relevant when determining whether a flare has been
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 , genera lly
, 7 3 FR 35838, 35842, 35854

- 35856 (June 24, 2008); 73 FR 78522, 78533 (December 22, 2008 ) , as well as Table 3 of the preamble to
the final amendments

. U sing the flare to control VOC emissions at other refinery process units will increase CO, PM and NO X emissions from the flare and are
, therefore
, considered modifications 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 directl y indicative of increased 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 i mpossible, 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 specifically exempt the following situations fr om the flare modification provision: (1) connections made to upgrade or enhance (not just to install) a FGR system (Commenters 0301 and 0311); (2) new flare header interconnect lines, since the connection is between flares and not from a process unit or fuel gas system to a flare (Commenters 0308, 0310 and 0311); (3) connections made for flare gas sulfur 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 (PRV) connections from existing equipment because the rule may create a disincentive to improving safety (Commenter 0298, 0305 and 0311) and the upset gases released by these valves are exempt from the emissions standard (Co mmenter 0301); (6) connections of monitoring system purge gases and analyzer exhausts (Commenters 0298 and 0301) or closed vent sampling systems (Commenter 0314); (7) purge and clearing vapors, block and bleeder vents and other uncombusted vapors where t he flare is the control device (Commenter 0301 and 0306);DRAFT

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22 (8) connections made to comply with other federal, s tate or local rules where the flare is the control device (Commenters 0301 and 0314); (9) connections of “unregulated gases” such as hydrogen, n itrogen, ammonia, other non

hydrocarbon gases or natural gas” (Commenters 0301, 0305, 0309 and 0311) or any connection that is not “fuel 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 replaced piping connections that do not result in a net increase in emissions (Commenter 0311 specifically indicated increases in VOC or SO 2 emissions) from the flare
, regardless 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 source or mass emissions, it just allows the pressure to relieve more quickly; (12) vapors from tanks used to store sweet or treated products (Commenter 0309); (13) temporary connections for purging existing equipment (Commenters 0311 and 0314; these are essentially “existing” connections); and (14) connections of safety instrumentation systems (SIS) described under Occupational Safety and Health Administration (OSHA) process safety standards at 29 CFR 1910.119, the EPA’s risk management program at 49 CFR 68 and/or American National Standards I nstitute (ANSI)/International Society of Automation (ISA)

- 84.00.01

- 2004 (Commenter 0314; the purpose of these systems is for safety and can often minimize process upsets when they do happen).

Commenter 0315 stated that for existing flares with sufficient F GR capacity
, the EPA should make clear that sites are allowed to make new connections, tie

- ins 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 flow without trigger ing a flare modification. Commenter 0301 noted that a safety project to add a new pressure relief valve 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 f lare rather than venting them to the atmo sphere or compromising safety. Response : We carefully reviewed the commenters’ suggested changes to the flare modification provision to determine whether there are additional connections that should not be
considere d modifications to the flare

. We agree that the first four connections in the commenters’
list should not be considered modifications of a flare

. Projects to upgrade or enhance components
of a FGR system ( e.g. , addition of compressors or recycle lines) wil l improve the operation of
the FGR system, and connections to these additional components will not result in increasedDRAFT

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23 emissions

. Connections made for removal of sulfur from flare gas (Item 2 above) will generally result in a slight decrease in volumetric flow 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 consider to be the affected facility

. The definition of “flare” specifically 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 could potentially be an affected facility subject to 40 CFR part 60, subpart Ja

. However, because the f lare 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 amo unt of gas being flared ( i.e. , interconnecting two flares does not result in an emissions increase relative to the two single flares prior to interconnection)

. 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 occurs, this gas will now flow to both of the interconnected flares rather than a single flare

. The maximum emission rate for the original single flare actually decreases, while the combined emiss ions from both flares is the same quantity as prior to the interconnection

. Considering this, we agree that the interconnection of two flares does not necessarily result in a modification of the flare and we have specifically
excluded flare interconnection s from the modification provisions. However, we also clarify in this response that when a flare that is subject to 40 CFR part 60, subpart Ja is interconnected with a flare that is not subject to subpart Ja, then the resulting interconnected flare is subje ct to subpart Ja

. That is, the only case in which an interconnection between two (or more) flares results in a combined, interconnected flare that is not subject to subpart Ja is when none of the original individual flares were subject to subpart Ja

. Addit ionally, we note that if a new connection is made to the interconnected flare, then the flare (including each individual flare tip within the interconnected flare header system) is modified and becomes an affected facility subject to subpart Ja.DRAFT

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24 While we a gree that connections that do not increase 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 gases are discharged via the new connection

. Each of the commenters’ suggestions is discussed in the following paragraphs. We previously proposed an exemption for emergency pressure relief valve connections from existing equipment (Item 5 above) if they replace or upgrade existing equ ipment 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 finalizing that a mendment
, as proposed

. However, new connections, even if they are made to “existing equipment,” 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 system p urge 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 block and bleeder vents (Item 7 above), also trigger a modification of the f lare 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 comply with other federal, s tate or local rules where the flare is an emissions control device (Item 8 a bove)

. In fact, nearly all flares could be considered “control 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 d oes decrease emissions from the process unit being controlled, the increase of gas flow to the flare will increase the emissions from the flare

. Therefore, a connection from a process unit to a flare for use as an emissions control device results in a
modi fication of that flare. Comments suggesting that connections of “unregulated gases” such as hydrogen, nitrogen, ammonia, other non

- hydrocarbon gases or natural gas or connections that are not “fuel gas,” should not be considered a modification of the 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 increase emissions of at least one pollutant (either PM, CO or NO X ) from
the flare (all of which the standard is 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, weDRAFT

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25 do not agree that the types of gas streams suggested 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 FG R system’s capacity” under normal conditions), and the amount of gases sent to the flare 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 pipi ng 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 valve connections that do
not result in a net increase in emissions from the flare re gardless of piping 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 will concentrate on the “regardless of piping or pressure relief valve size” comment in this paragraph

. First, the size of the pressure relief valve or piping does correlate to the discharge rate to the flare, with larger pressure relief valves or
l arger diameter piping allowing higher discharge rates to the flare at a given pressure

. In fact, larger pressure relief valves and larger diameter 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 diameter piping will be larger than the flow rate experienced u sing the smaller pressure relief valve or smaller diameter piping and will result in higher emissions from the flare

. Therefore, we reject the notion that larger diameter pipes and larger pressure relief valves do not increase the emissions rate from the f lare during a release

event

. We are finalizing the proposed exemptions for moved or replaced piping or pressure relief valves with the size and design restrictions for the new piping or pressure relief valves as proposed o n December 22, 2008.
Commenters su ggested that connections of vapors from tanks used to store sweet or treated products (Item 12 above) should not be modifications 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 the emissions of at least one pollutant from theDRAFT

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26 flare, so we are not exempting these types of connections to the flare from the 40 CFR part 60, subpart Ja flare modification provision

. However, we hav e amended the sulfur monitoring requirements for flares to exempt vapors from tanks used to store sweet or treated products from the flare sulfur monitoring requirements

. This monitoring exemption is justified because it is not needed for the purposes of a RCA or other compliance purpose

. For these sweet vapors, the flow

rate RCA threshold will be exceeded well before the SO 2 RCA threshold. We carefully considered temporary connections for purging existing equipment (Item 13 above), but we failed to see how these temporary connections are essentially “existing connections.” According to t he commenters, “ maintenance gases have been routed in some form or other to the flare for years, and the temporary tie

- in to accomplish that is not a change and is
not an in crease in emissions when viewed from 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 relocated and the pi ping used is the same diameter as the pre

- existing connection, then this scenario is adequately covered by the proposed exclusion for relocated connections

. However, if a new connection is made specifically to purge an existing piece of equipment, this pur ge gas unequivocally represents additional gas flow sent to the flare that did not exist and could not exist prior 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 lea st one pollutant from the flare

. 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 considered in the FMP and t hat flaring from these “temporary” connections should be minimized to the extent practicable. The impact of connections of SIS described under OSHA process safety standards at 29 CFR 1910.119, the EPA’s risk management program 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 expect that, if these connections are made for flare monitoring purposes, these connections are already exclude d 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 flare, these connections would be considered a
modification
, as previously discussed

. The commenter may also be referring to new connectionsDRAFT

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27 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 analysi s, we are finalizing three of the connections
, as proposed, adding three of the connections requested by commenters and revising one of the proposed connections as requested by commenters in 40 CFR 60.100a(c)(1)

. Thus, the following seven types of connecti ons 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 system or connections made to upgrade or enhance components of a FGR system ( e.g. , addition of compre ssors 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 existing equipment being replaced or upgraded. (4) Connections that interconnect two or more flares. (5) Connections made for flare gas sulfur removal. (6) Connections made to install back

- up (redundant) equipment associated with the flare (such as a back

- up compre ssor) 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 new pipe diameter is less than or equal to the diameter of the pipe /connection being replaced/moved.
Comment : Commenter 0309 stated that the flare modification provision in
40 CFR 60.100a(c)(2) should explicitly exclude the following physical changes made to the
flare: (1) change in flare pilot and igniter systems (includ ing larger pilot lines or those that use more gas); (2) installation of sweep or purge gas reduction device ( e.g. , an internal ring or molecular seal); (3) increase in steam capacity (to limit smoke); (4) alteration of flare seal drum
level or control sche me; and (5) connections to increase sweep or purge gas rates provided the

sweep or purge gas has an H 2 S concentration of less than 162 ppmv on a 3

- hour rolling average
basis

. Response : Under 40 CFR 60.100a(c)(2) , a flare is modified 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 t he “flow capacity of the flare”
is intended to refer to the capacity of flare ga s ( i.e. , gas from the “ flare gas header system
, ”DRAFT

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28 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
definitio n of “modification” in CAA section 111(a)(4)
, which i s “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 results 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 flare because these alteration s do not typically
increase the flare gas flow capacity of the flare. H owever, 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), wh ich results in an emissions increase, then these alterations would be deemed a

“ modification ” of the flare under 40 CFR 60.100a(c)(2)

. Similarly, installation 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 alterations are “ modifications ” of the flare

. While the exemptions specified by the commenter may not be flare modification s under
40 CFR 60.100a(c)(2), a few of these examples may be considered flare modification s under
40 CFR 60.100a(c)(1)

. Specifically, Item 5, connecti ons to increase sweep or purge gas rates , would be considered a modification of the flare if these gases originate from a process unit or fuel gas system. However, i f these connections are from a separate, independent natural gas line, for example, these c onnections would not be considered a flare modification under
40 CFR 60.100a(c)(1)

. As noted in this response, we disagree that a blanket exemp tion of the modifications requested by the commenter i s appropriate. This response, while clarifying the
intent o f the rule’s language, also indicates the need to evaluate potential modifications on a

case

- by

- case basis. If there is any question about whether an alteration of the flare should be
considered a modification of the flare based on the subpart Ja flare mod ification 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 (o r net emission decreases) resulting
from new connect ions to a flare made to control and combust fugitive emissions such as leaksDRAFT

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29 from compressor seals, valves or pumps
, are not flare modifications

. Commenter 0302 suggested allowing site

- specific exempt ions for connections that do not increase emissions or that result in

a de minimis emissions increase. Conversely, Commenter 0313 objected to setting a de minimis emissions increase below which a modification would not trigger subpart Ja applicability. The

com menter noted that the specific exclusions proposed by the EPA are acceptable because they arguably cause no emission increases. However, emissions from a flare are difficult to determine, particularly at low flow rates, and allowing a de minimis approach w ould 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 modification provision. 73 FR 78522,
78529. Industry Peti tioners had suggested some type of de minimis emissions increase should be allowed without triggering 40 CFR part 60, subpart Ja applicability

. Id . The EPA acknowledged that these exceptions are “permissible but not required” under the modification provisi on 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 emissio ns that would be considered de
minimis .” Id

. Industry Petitioners continue to recommend that any emissions increases resulting from “routine connections” to the flare system “will be de minimis ” and should not trigger 40 CFR part 60, subpart Ja applicabili ty at the flare , but they have not provided the comments or data requested in the proposal preamble that the EPA could consider to evaluate the impacts of such an approach

. Docket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 0311 (second attachment) , pg 20. Industry Peti tioners again suggest that the EPA exercise its authority and “authorize exceptions from otherwise clear statutory 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 a gency flexibility in interpreting a statute to prevent “pointless expenditures 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 significant deference due an a gency’s use of a de
minimis exception. Id . at 400; Shays v. Federal Election Com’n , 414 F.3d 76, 113 (D.C. Cir.DRAFT

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30 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 reg arding its use of the de minimis exception: “EPA must take into account in any action

... that this exemption authority is narrow in reach and tightly bounded by the need to show that the situation is genuinely de minimis.” Id . at 361. The Court also noted th at exemptions from “the clear commands of a regulatory statute, though sometimes permitted, are
not favored.” Id . at 358. The EPA must exercise this authority 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 assertions, Industry Petitioners have still provided no data to support a finding that the emissions increases resulting from the alleged “routine connection s” to a flare system are truly “trivial or [of] no value.” Docket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 0311 (second attachment) , pg 20. Without the requested information showing that “the situation
is genuinely de minimis
, ” Alabama Power , 636 F.2d at 361 and
, the refore
, warrants this kind of exception, we believe such an exemption would be inappropriate. Additionally, Industry Petitioners’ example that “venting a new small storage tank to a flare system

... easily would cost a typical refinery tens of millions of dol lars” since “the entire flare system” (emphasis in original) 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 (second attachment) , pg 21. As the District of
Columbia Circuit specifically states in Shays , authority for promulgating a de minimis exception
“does not extend to a situation where the regulatory function does provide benefits, in the sense of furthering regulatory objectives, but the agency concludes the acknowledged benefits are 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 cos t

- benefit analysis prohibited by the Shays Court. Such cost analyses are improper in these types of decisions. Industry Petitioners generally focus their discussion on VOC emissions 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, emphasisDRAFT

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31 added) ). Furthermore, they disregard add itional emissions of NO X and CO resulting from the combustion of these gases at the flare. Industry Petitioners also provide no data quantifying these
emissions increases and
, therefore
, cannot demonstrate that the y are “trivial or [of] no value ” or , in ot her words, that the emissions increases are
, in fact
, de minimis . As releases to the flare are often event driven, one can envision situations where the release from even a small storage tank

c ould be significant. On the other hand, the EPA sees a substant ial 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 these 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 original comments (0311) and addressed the comparison between the flare modification provision in subpart Ja and modification of a municipal solid waste (MSW) landfill in the direct final amendments to Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills (63 FR 32743, Jun e 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 amou nt of waste placed in the landfill, and “total ‘production’ for the entire life of the facility is controlled through the amount of design capacity specified in the permit.” The commenter noted that according to the preamble, 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; there fore, they are not included in the modification provision. Finally, the commenter noted that the preamble to the proposal stated that “if an MSW landfill increased its waste acceptance rate, such a change would be analogous to an increase in production rat e at a manufacturing facility” which is excluded under 40 CFR 60.14. Therefore, the commenter asserted, the MSW modification provision is consistent with 40 CFR 60.14, while the subpart Ja flare modification provision is a departure from 40 CFR 60.14.
The commenter made several points in comparing the MSW landfill modification provision to their recommendations for the flare modification provision in subpart Ja. First, the commenter stated that the provision that a modification occurs only if the design cap acity of theDRAFT

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32 landfill is changed is consistent with the suggestion that a new connection to a flare is only a modification if other changes are made to the flare system that would increase the capacity of the
flare. Second, using the landfill in its intend ed 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; therefore, 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 modifica tion provision, they should be available for the subpart 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 changes 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 provision in subpart Ja. Response : In developi ng the modification provisions for MSW landfills, we evaluated the special circumstances associated with landfills and developed a modification provision specific
to landfills. In exactly the same manner, we evaluated the special circumstances associated w ith flares and developed a modification provision specific to flares

. In both cases, we considered the

same underlying principles of what constitute s a “ modification ” based on the provisions in CAA section 111(a)(4), 40 CFR 60.2 and 40 CFR 60.14

. We arrive d at different modification provisions for MSW landfills and flares because of the many factual and operational differences
for these two very different sources

. We therefore do not consider it appropriate to make the changes to the flare modification prov ision that are suggested by the commenter.
Comment : Commenter 0308 requested clarification with respect to how the flare modification provision applies to flare interconnects, which are used to direct flow from one
flare to another flare if one flare is te mporarily out of service. T he 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 systems are generally operated independently. Response : We disagree tha t only the first or primary flare in an interconnected flare system sh ould be subject to subpart Ja when a new connection to a process unit or fuel gas system is made

. New connections to the interconnected flare system would suggest thatDRAFT

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33 additional gas cou ld 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 applicability 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 the flare gas pressure at the primary flare exceeds a certain p ressure), the final amendments provide a simplified water seal monitoring approach
under 40 CFR 60. 107a(g) to ensure gas is not sent to th e secondary flare

. It is anticipated that any event that causes a release so large as to trigger gas flow to subsequen t flares in the series would trigger a RCA on the primary flare. The root 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. The refore, the fi nal amendments do not require duplicative RCA for the secondary flare if a RCA is triggered for the primary flare. However, if flare gas is sent to the secondary flare (as detected by the water seal monitoring) prior to triggering a RCA on the primary flar e, then the indication of flow to the secondary flare automatically triggers a RCA for
the primary flare

. If the interconnect ion do es not have a water seal or other device that prevents flow to the interconnected flare during normal operation
, then a new c onnection to a n interconnected flare header system would require flow and sulfur monitoring for each flare
within the in t erconnected 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 the stay. Similarly, Commenter 0311 requested that the 40 CFR 60.108a and 40 CFR 60.7 notifications for construction or startup be due 60 days after th e 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 requirements existed under subpart J and there is no

reaso n to delay these no tifications.DRAFT

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34 

### 2

. 5 Overlap with and Effect on Other Subparts
Comment : Commenter 0311 noted that 40 CFR part 63, subpart UUU (Refinery
MACT 2) often references specific subpart J requirements, resulting 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 60.100 a (e) of subpart Ja : “Owners or operators may also choose to comply with the applicable provisions of Subpart Ja of this part to satisfy the requirements of
Par t 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 allow compliance with subpart Ja to fulfill
the requirements of Refinery MACT 2, it is inappr opriate to effectively put the suggested Refinery MACT 2 alternative in subpart Ja. It is much more appropriate to include this alternative directly in subpart UUU. Refinery MACT 2 is currently under review, and we intend to include subpart Ja as a complia nce option for 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 allow affected sources subject to s ubpart J to elect to comply
with the corresponding provisions of s ubpart 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 individual affected facility basis , not the entire refinery

. For example, if a facility has two FCCU subject to subpart J requirements, the owner or operator may elect to comply with subpart J requirements for one FCCU and subpart Ja

re quiremen ts for the second FCCU.
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 subpart 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 mo nitors used to demonstrate compliance generally output the H 2 S concentration in ppmv

. W e expect that th e inclusion of the short

- term 162 ppmv H 2 S concentration limit in subpart Ja should help to resolve debates about the properDRAFT

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35 conversion

. However, w e deci ded not to specifically 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 permit s may rang e from 160 to 164 ppmv

. W e did not want to require re

permittin g of these facilities , re programming of monitoring equipment and/or potential
retroactive non

- compliance issues that could occur with this “new” emission s limit if we had specified the H 2 S concentration limit as 162 ppmv in subpart J.
Comment : Commenter 03 11 stated that 40 CFR part 63, subpart LLLLL indicates at
40 CFR 63.8681(e) that subpart J does not apply for asphalt blowing stills subject to subpart
LLLLL. The commenter requested similar clarification 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
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 c ontrols 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 ex emption within the definition of fuel gas similar to the exemptions included for combustion controls on vapors collected and combusted from wastewater treatment and marine vessel loading 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 emissions from asphalt processing units ( i.e. , asphalt blowing stills).



### 2. 6 Equivalence with State and Local Rules
Comment : Several commenters address ed 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 (SCAQMD) Rule 1118]” and “whether the EPA could deem a facility in compliance with subp art Ja as proposed to be amended today if that facility was found to be in compliance with SCAQMD Rule 1118, or other equivalent State or local rules” (73 FR 78532, December 22, 2008). Commenter 0307 disagreed with the EPA’s position, alleging that the “EP A’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 existingDRAFT

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36 state and local requirements render the federal requirements irrelevant only confirms that EPA’s proposed flaring requirements do not reflect the best technological system of continuous
emission reduction.” 42 U.S.C. §7411(h)(1) (emphasis added). The commenter also stated that the CAA already provides a mechanism for implementation of alter native work practice standards in narrowly defined circumstances (42 U.S.C. §7411(h)(3)); an owner or operator may
demonstrate to the Administrator that an alternative means of emission s limitation is equivalent to the federal standard and request permissi on to comply with the alternative method in lieu of
the federal standard. Therefore, the commenter asserted, 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 emissions reductions achieved through compliance with SCAQMD Rule 1118 are equivalent to subpart Ja. Further, the commenter asserted that the EPA
neither identified other s tate rules that could be considered equivalent
, nor explain ed how the EPA would determine that a specific s tate or local rule is equivalent to subpart Ja. Therefore, the commenter stated, it is impossible to fully assess the merit of the EPA’s idea and provide meaningful comments.
Commenter 0315 responded to Comme nter 0307’s comments. Commenter 0315 noted that it appears that Commenter 0307 argues that if s tate regulations are more stringent than the proposed requirements for subpart Ja, then the subpart Ja proposed requirements cannot be
“best” demonstrated techno logy. The c ommenter stated that the existence of more stringent control measures is not per se fatal to an EPA BSER determination because “most stringent” is not the criteria that must be applied under the law to determine BSER

. In response to Commenter
03 07’s statement that the EPA must grant permission to use alternative methodologies on a case

by

- case basis, Commenter 0315 stated that the EPA has full authority to establish alternative regulatory standards that are determined to be as stringent as or mor e stringent than BSER

. The
commenter noted that CAA section 111(h)(3) generally 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 lo gical that
, if an alternative 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 111 ] , where the alternative would have to be
determ ined through notice and comment rulemaking

– which, in essence, requires EPA to amend the regulation to accomplish the site

- specific alternative).” Finally, Commenter 0315 noted thatDRAFT

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37 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 for flares and designed s ubpart Ja so that affected flares would be subject to similar requirements. Commenters 0304, 0306 and 0311 recommended that refineries complying with California flare rules, specifically SCAQMD Rule 1118 (Commenters 0304 and 0311) and Bay Area Air Quality Management District (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 or more stringent than the corresponding requirements” of subparts J and Ja. Although Commenter 0311 did note that the FMP in SCAQMD Rule 1118 is only required for facilities that fail to achieve sulfur oxides (SO X ) emission reduction targets, the commenter asserted the subpart Ja FMP provided no greater emiss ion 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 standards (Section 60.103a) satisfy the requi rements of this section, including South Coast AQMD Rule 1118 and Bay Area AQMD rules 12

- 11 and 12

- 12.” The c ommenter also requested a similar paragraph be added to 40 CFR 60.107a(e) to allow the monitoring methods used in SCAQMD Rule 1118 and BAAQMD Regul ation 12

- 12 and 12

- 11 to be acceptable under subpart Ja

. Commenter 0315 provided a table comparing each of the six proposed FMP requirements
in 40 CFR 60.103a(a) to the SCAQMD and BAAQMD regulations. The commenter’s table identified sections of BAAQMD Regu lation 12

- 12 and 12

- 11 that are equivalent to the six subpart Ja FMP requirements, but the commenter also noted that SCAQMD Rule 1118 is only equivalent to five of the proposed requirements; it does not require an owner or operator to identify procedures t o reduce flaring in cases of fuel gas imbalance (although Commenter 0311 noted that SCAQMD Rule 1118 requires minimization of all flaring, including fuel gas imbalance). Based on this information, the commenter stated that facilities already complying
with SCAQMD Rule 1118 or BAAQMD Regulation 12

- 12 and 12

- 11 are already meeting requirements equivalent to or more stringent than BSER , so these facilities should not have to meet different requirements under subpart Ja

.DRAFT

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38 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 calculates 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 sulfur monitoring for SSM flares

. Response : First, we note that there seems to be some misunderstanding 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 “w aive” the obligation to comply with subpart Ja if the source is complying with SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12. In other words, the EPA 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 Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 are determined t o be equivalent to subpart Ja, then these requirements would be provided as an alternative within subpart Ja for the source to demonstrate that it is meeting the requirements of subpart Ja. To assess the comments, we reviewed SCAQMD Rule 1118, BAAQMD Regul ation 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 have included documentation of this review in
Docket ID No. EPA

- HQ

- OAR

- 2007

- 0011 that shows the sections of e ach of those rules that we consider are equivalent to the subpart Ja requirements. 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 reductions result ing from the subpart Ja 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 equivalent to the flare requirements and monitoring, recordkeeping and repor ting provisions for determining 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 Regulation 12, Rule 12 are equivalent to the flare requirements and monitoring, recordkeeping and reporting provisions for determiningDRAFT

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39 compliance with the flare requirements in subpart Ja. Therefore, we have added specific compliance options for flares that are located in the SCAQMD and are in compliance with SCAQMD R ule 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 t he 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, R ule 11 and BAAQMD Regulation 12, Rule 12 to comply with the FMP requirements of 40 CFR 60.103a(a) and (b) and the RCA and corrective 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, Rule 11 and BAAQMD Regulat ion 12, Rule 12 to comply with the monitoring 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 SCAQMD 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
und er 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 least equivalent to the reduction in emissions ” achieved under the flare standar ds 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 submit a request for “an alternative means of emission
limitation ” that will achieve a reduction in e missions at least equivalent to the reduction in
emissions achieved under the final standards in subpart Ja

.DRAFT

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40 

## 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

- fir ed process heater” should be revised to remove reference 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 recommended: “ Co

- fired process heater means a process heater designed to be supplied by both gaseous and liquid fuels.” Response : It appears that there is some confusion regarding what is meant by “burners ”
with in this definition. We intended that a “burner” refers to each location in t he process heater designed to produce a flame to impart heat to the system. A single burner that is designed to be supplied with both gaseous and liquid fuels is expected to have separate burner tips within the burner, but both burner tips are part of the single burner location. If a process heater has some burners that can only be fired with gaseous fuels and other burners that can only be fired by liquid fuels, these process heaters are not considered co

- fired process heaters. The gas burners in such a pr ocess heater can employ ultra

- low NO X burners capable of meeting the emissions limit
in the same manner as conventional gas

- fired process heaters , and these process heaters should
demonstrate compliance with the rule when firing only with the gas burners. B urners that are designed with multiple tips ( so that the single burner can be supplied by both gaseous and liquid fuels) have different design considerations, because staged fuel is generally needed for reducing
NO X in gas

- fired burners, where staged air is used to reduce NO X in oil

- fired burners

. T he se burners ( i.e. , those with both types of burner tips in the same burner ) cannot be designed to stage
both air and fuel. As such, the se burners can be either designed for staged air to limit NO X whileDRAFT

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41 firing oil but will have conventional gas

- fired burners, or the burners can be designed for staged
fuel to limit NO X when firing gaseous fuels but will have conventional burner s for fuel oil

. If a process heater ha s 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 inappropriate to revise the definition of co

- fired process heater as requested by the commenter. Furthermore , we find that gas

- fired process heaters that have emergency oil back

- up burners in the event of a natural gas curtailment should employ gas burners that are optimized for firing gas using staged fuel ultra

- low NO X burners because they do

not r outinely fire oil. Therefore, we revised the definition of co

- fired process heaters to clarify
th at 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 clarify in the definition that process heaters that have gas burners with emergency oil back

- up burners are not considered co

- fired process heaters

. We clarify in this response that a process heater that contains gas burners with emergency oil
back

- up burners must compl y with the NO X limits for conventional gas

- 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 t he facility to document “all” potential corrective actions (and subjects the facility to liability if it does n o t include all possible actions ) rather than focusing on the most promising. Response : We disagree that the proposed definition of “corrective ac tion analysis” requires the facility to describe “all” potential corrective actions or otherwise put s undue burden on the refinery owner or operator

. The actual definition requires “a description of all reasonable interim and long

- term measures.” The inclu sion of the word “reasonable” modifies and limits the
term “all.” The phrase “all reasonable” clarifies the requirements to perform a comprehensive analysis while limiting the need to document unreasonable measures. Deleting the word “all” is unlikely to a lter the a gency’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.DRAFT

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42 

### 3.4 Delaye d 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 with a single f ractionator. The
commenters stated that the definition should not include the fractionator itself because VOC emissions from the fractionator are covered by NSPS for equipment leaks. Response : The proposed amendments to the definition of “delayed coking un it” 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 delayed coking unit is generally 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 riser, which is part of the affected facility in subpart Ja. As the feed to the delayed coking unit is to the fractionator, we find that the fractionator is an integral part of the delayed coking unit, so we specifically include it as part of the affected facility. While our proposed amendments covered only the major components of the delayed coking unit, upon our review of the definition based on the comments received, we note that there are several other components of the delayed cok ing unit that are integral to the operation of the delayed coking unit. Additionally, even though the standards are specific to the coke drum, many of these integral components are interconnected and necessary for the delayed coking unit to meet the applic able standards. Based on our review of the operation of a delayed coking unit, we also include coke cutting and blowdown recovery equipment in the final definition because this equipment is also integral to the overall cyclical operation of the process
uni t. 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 cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit includes but is not limited to all of the coke drums associated with a single fractionator; the fractionator, including bottoms receiver and overhead condenser ; the coke drum cutting water a nd quench system, including the jet pump and coker quench water tank; process piping and associated equipment such as pumps, valves and connectors; and the coke drum blowdown recovery compressor system.DRAFT

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43 

### 3.5 Flare
Comment : Commenter 0308 and 0311 recommende d deleting “knock

- out pots, piping and header system” from the definition of “flare” because piping 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 E PA retains this expanded definition, then the EPA should clarify that the other fuel gas combustion devices are limited to just the “equipment used to combust fuel gas” and do not include the fuel gas lines. Commenter 0311 stated that if “knock

out pots, p iping and header systems” are included, the flare’s knock

- out pot, piping and header system must be clarified since numerous process units have knock

- out pots and nearly all will be connected either directly or indirectly (via the fuel gas system) to a fla re. As such
, the entire fuel gas system could be considered part of the flare header system. The commenter also requested that the definition include a primary use clause so as to clarify the affected facility in cases of interconnected flare systems. Comm enter 0311 recommended: “Flare means an open

- flame fuel gas combustion device used for burning off unwanted gas or flammable gas and liquids. The flare includes the foundation, flare tip, structural support, burner, igniter, flare controls including
air in jection or steam injection systems, flame 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 flares are assigned on a primary u se basis.”
Commenter 0315 also stated that the flare should not include the piping within process units and fuel gas systems. The commenter recommended that the EPA clearly differentiate the boundary between the refinery process unit, the fuel gas system a nd the flare. The commenter noted that main lines from individual refinery process units and fuel gas systems to flares are generally equipped with battery limit isolation valves, and these 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 the knockout pots, piping and headers outside of a process unit’s or fuel gas system’s battery limits ; and (2) any new piping or
connecti ons that are made inside the process unit'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 system that either results in a new connection from the process unit or fuel gas system to the flare or increases the capacity of an existing flare system to handle more flow ( e.g. increasing the size of a flare header or a knock out pot) wouldDRAFT

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44 be a modification to the flare

. The comm enter provided a diagram of an example refinery to illustrate their points. Response : We agree that a clarification is needed to 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 response to the next comment for further details

. We have also listed flares as a completely separate affected facility, so we do not believe a clarification to the definition of fuel gas combustion device is needed to specific ally 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 modi fied when a connection meeting those defined for a flare modification is made to such a system. Please see Section 2.3 of this document for more details.
Comment : Commenter 0313 requested that the definition 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 commenter noted that refiners in the BA AQMD are submitting permit applications asserting that all flare 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 system in the definition of “flare.” The commenter
stated that the EP A should explicitly include the FGR system in the definition to eliminate any confusion and clarify the a gency’s intent. Response : We have added a definition to clarify what is included in the flare gas header system. We specify that all piping used to tra nsport gas to a flare either directly from a process
unit or directly from a pressure relief val ve from the fuel gas system is part of the flare gas header system , regardless of whether or not the flare gas header system includes a FGR system ( i.e. , regard less of whether or not a FGR system draws gas from the flare gas header system).
Consistent with this definition, we note that if a FGR system is present, it is considered to be part
of the flare gas header system

.DRAFT

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45 

### 3.6 Fuel Gas
Comment : Commenters 0304, 0 305 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 clarifie d to list all types of premium coke (specifically recarburizer 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 pare nthetical 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 forward , there is no need to revise the definition of fuel gas in subpart J at this point in time.
Comment : Commenter 0309 suggested that the exclusion in the definition of “fuel gas” be extended to vapors combusted to comply with the storage vessel requirements in 40 CFR 60
, subpart s K, Ka, Kb (NSPS for storage vessels) and 40 CFR part 63 , subpart CC (Refinery MACT 1) because these are low pressure vapor streams and most have low sulfur content. The
commenter stated that at least certain storage vessel s (reformate, alkylate, 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 remotely located, many of these storage vessels are located nea r refinery process units or each other so that combined coll ection and, if necessary, treatment of the gases can be accomplished cost effectively. The current provisions in s ubpart Ja (and subpart J) contain an exemption from the continuous H 2 S monitoring requirements for gas es that are inherently low sulfur or can be determined to be low sulfur. As such, the current provisions for low sulfur fuel gas adequately address the commenter’s issue without needing to exempt certain types of storage vessels from the definition of fuel gas.
Comment : Commenter 0311 recommende d that the exclusion from the definition of “fuel gas” be extended to vapors “from marine vessel loading operations or waste management units that are collected and combusted” without any reference to a federal requirement. At a minimum,
Commenter 0311 sta ted that marine benzene loading under 40 CFR p art 61, subpart BB ; the wastewater provision s of 40 CFR p art 63 , s ubpart G ; remediation efforts regulated underDRAFT

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46 Resource Conservation and Recovery Act ( RCRA ) corrective action; and RCRA 7003 orders
should be ad ded 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 o xidizers 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 sources (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 heater 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 expected to be only a small portion of the fuel gas combusted in these units, and the refinery has an option to over

- treat th e 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 mixture of fuels used in the device. In reviewing the rules suggested by the commenter, as well as those we originally listed, we noted that acceptable “control devices” or “combustion units” in these rules include process
heaters and boilers. We did not intend to exclude vapors that are collected 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 specifically considered the combustion of these gases via a thermal
oxidiz er or flare currently located at the marine vessel loading or wastewater treatment location. These remote combustion devices were really the subject 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 controlled. It is clear from our rationale and the description of the exemption included in the preamble of the 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

. ) Process heaters or boilers would
not be “installed” to comply with these provisions, and it was not our intent to exclude vapors sent to these types of combustion units. However, the re gulatory text is more ambiguous andDRAFT

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47 appears to exclude any vapors collected and combusted, regardless of where they are co mbusted. As such, we are amending this exclusion to better represent our original intent. Additionally, with the added clarity in the regulatory text, it seems appropriate to extend this exclusion to control devices used at these locations regardless of wh y the emission controls were installed. That is, while we originally considered air pollution control devices that were mandated by the EPA, we see no reason to discriminate against air pollution control devices that were installed voluntarily to reduce th e 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 would be economically viable to treat. Therefore
, we are also c larifying that the exemption does not extend to the sour water system. Therefore, the amended definition of “fuel gas” in both 40 CFR part 60, subparts J and Ja states that fuel gas “does not include vapors that are collected and combusted in a thermal oxi dizer or flare installed
to control emissions from wastewater treatment units other than those processing sour water
, marine tank vessel loading operations or asphalt processing units ( i.e. , asphalt blowing stills).” With respect to remediation efforts con ducted 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 o r operator could apply for 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 existing process units. Fina lly, the range of activities included in RCRA remediation efforts is broad, and we have little information regarding the number and types of RCRA remediation 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 reference 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 acknowledge that the proposed definition did
include an inadvertent error. We have removed the section that contained the error from the final
definition.DRAFT

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48 

### 3

. 7 Fuel Gas Combustion Device
Comment : Commenter 0308 recom mended that the EPA delete flares from the definition of “fuel gas combustion devices” and create a separate affected facility covering only flares so that flares can be regulated in a targeted , coherent and consistent fashion. Response : We a gree. Due to t he 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 flares were defined as separate affected facilities

. Therefore, the final rule defines a flare as a n affected facility rather than including flares as a type of fuel gas combustion device

. Comment : Commenter 0305 suggested clarifying the definition of “fuel gas combustion device” to clarify that the fuel g as combustion device is located at the petroleum refinery. Response : We do not agree that the requested clarification is necessary

. A fuel gas
combustion device is defined as “any equipment, such as process heaters and boilers, used to combust fuel gas.” S ection 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 b e located at a petroleum refinery to be an affected 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 definition does not specif y that fuel gas mus t 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 process heaters and it
is unclear whether balanced draft or induced draft process heaters are considered natural draft or forced draft process heaters

. The commenter suggested that the EPA should clarify the definition
of “ forced draft process heater ” to include these configuratio ns. 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, andDRAFT

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49 those process heaters experience NO X control issues similar to forced draft process heaters

. As

s uch, Commenter 0311 recommended that “process heaters with downward firing burners that are equipped with an induced draft fan” be included in the definition of “forced draft process
heater.” Commenter 0311 also requested that the definition be clarified b ased 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 maintenance on the fan or preheat system while still operating the process heater and requested clarifica tion on whether 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 process heaters: (1) natural 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 air (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 a ir (typically used for air preheat). The definition of forced draft process heater clearly 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 clearly excludes induced draft process heaters because these process heaters do not have a fan in the inlet air line

. T he definition of natural draft process heaters
includes induced draft process heaters because induced draft process heaters do not have a fan on the inlet air ( i.e. , they are not “forced draft” process heaters )

. Nonetheless, the definitions are somewhat confusing given the inclusion of “under positive pressure” for forced dr aft systems and “under ambient pressure” for natural draft systems. We have clarified these definitions to more clearly indicate that, for the purposes of subpart Ja, balanced draft systems are considered forced draft process heaters and induced draft syst ems are considere d natural draft process
heaters.
The commenters provided no direct data on “downwardly 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 th at they can meet the same limits as natural draft units, but given the lack of data for this argument, we have included downwardly firing induced draft burners in the list of process heaters that that may apply for a site

- specific NO X emissions limit. If a process heater equipped with downwardly firing burners is modified or reconstructed, the owner orDRAFT

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50 operator of the process heater should strive to m eet the 40 ppmv emissions limit but may apply
for a site

- specific emissions limit if the process heater cann ot meet that limit.
We intended the emission s limits and the definitions of the process heaters to be based on the operation of the heater (except for co

- fired process heaters, the definition of which is design based). According to comments received, inclu ding design performance levels from low

- NO X burner vendors for process heaters that are designed to operate in both natural draft mode and forced draft mode, the burners can achieve the 40 ppmv (or 0. 040 pounds per million British thermal unit [lb/MMBtu]) NO X emission s limit while operating under natural draft conditions even though it cannot meet this limit while operating in the forced draft mode, specifically because of the higher inlet air temperatures when using air preheat. Based on the available
info rmation, we conclude that the natural draft emissions limit is appropriate and BSER when the process heater is operating in natural draft mode even if the unit is “designed” to operate as a forced draft process heater. Therefore, we made no changes to the definitions of “forced draft process heater” and “natural draft process heater” as a result of this comment.



### 3

. 9 Process Upset Gas
Comment : Commenter 0303, 0305, 0306, 0308 and 0311 supported the amended definition of “process upset gas” to include startup and shutdown and stated that the FMP is effective in reducing SSM emissions. Commenter 0315 provided specific examples of planned startups and shutdowns in which flaring is necessary for the proper operation of the unit and the process train. Commenter 03 02 requested that the definition of “process upset gas” include “gas generated during periods when the fuel gas desulfurization system is down for maintenance in
accordance with the manufacturer’s recommendations and good operating practices” as it is
uncl ear if these maintenance periods can be considered “malfunctions.” If this provision in not provided, the EPA should revise its cost analysis to include back

- up desulfurization systems, which would be needed if these periods cannot be excluded.
On the othe r hand, Commenter 0313 requested that the EPA not finalize the addition of planned startups and shutdowns to the definition of “process upset gas.” The commenter stated that planned startups and shutdowns are a major cause of flare emissions, and unlike em ergency situations, refineries have the ability and resources to mitigate flare emissions during a planned

event. If the EPA adds startup and shutdown to the definition, then a large amount of theDRAFT

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51 emission reductions associated with subpart Ja will not be realized. In a subsequent letter (Comment 0316), the c ommenter clarified this comment, noting that while many refineries in the
BA AQMD have found alternatives to flaring during planned startups and shutdowns by modifying the design of new flares, it may no t be possible for all new flares to be designed to avoid flaring during all startups and shutdowns. The commenter 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 t o promulgate the fuel gas combustion device sulfur standards for new
flares as originally proposed ( i.e. , if startup and shutdown gases are included in the definition of process upset gas) , then the FMP approach would be an alternative way to address flari ng emissions from startups and shutdowns that would provide significant benefits. Response : The only impact of including startup and shutdown gases within the definition of process upset gas is to exclude these gases from the H 2 S concentration requirement

. As an example, the planned shutdown of a reactor vessel 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 gas may contain concentrations of
H 2 S that exceed 162 ppmv, depending on the reactor vessel contents. Flaring this gas to destroy
H 2 S is the best environmental practice , and it is not feasible to recover this gas
, nor is it cost
effective to treat thi s gas separately to reduce its H 2 S concentration to below 162 ppmv

. Th erefore
, 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 rolling average basis is BSER for planned startup or shutdown for all refinery process units at a petroleum refinery

. However, we have placed requirements on the flares to address releases during startups and shutdowns

. The
FMP effectively addresses flare flow from planned startup and shutdowns a s it requires minimization of the amount of gas discharged to a flare under 40 CFR 60. 103a(a)( 5 )

. The rule
also require s RCA to be performed if more than 500 pounds (lb) of SO 2 are discharged from a
flare in a 24

- hour period under 40 CFR 60. 103a( c ) , and th is requirement applies to process upset gas ( including planned startup and shutdowns that do not follow the procedures in the FMP ). 7

T hese requirements effectively limit discharges of planned startup and shutdown gases to the
flare , and these provisions in s ubpart Ja are expected to yield significant emission reductions

7 While we expect that most process upset gas will be combusted in flares, it is import ant 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

.DRAFT

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52 compared to the requirements in s ubpart J

. Consequently, we conclude that the inclusion of startup and shutdown gases in the definition of “process upset gas” is necessary and aligned with

o ur BSER assessment for flares, and 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 fo llowed. With respect to maintenance of fuel gas desulfurization units, we find that the fuel gas desulfurization unit is a control device used to meet the fuel gas standards. Continuing to operate fuel gas combustion devices unabated when the control syste m 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 considered 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 long

- term 60 ppmv H 2 S concentration limit , and would have to install ad ditional amine treatment systems. We conclude that the cost analysis conducted for fuel gas combustion devices adequately reflects the incremental costs of subpart Ja. Therefore, the final amendments to subpart Ja do not include the requested maintenance e xemption.
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 Provis ions of 40 CFR part 60, and it appears more frequently than “start

- up” throughout subpart Ja. For consistency,
we have revised the occurrences of “start

- up” to read “startup.”



### 3

. 1 0 Refinery Process Unit
Comment : Commenter s 0305 and 0311 objected to the cha nge to the definition of “refinery process unit” to include coke gasification, loading and wastewater treatment, stating the change makes the term more expansive

. The commenters stated that the EPA did not evaluate the impacts or explain the consequences o f the revised definition. Commenter 0311 also stated that product loading is generally considered part of the refinery process unit to which it is associatedDRAFT

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53 and wastewater treatment is a utility. Commenter 0305 suggested that the definition specify SIC
29 11 (as in Refinery MACT 1). Response : The original definition of “refinery process unit” in 40 CFR part 60, subpart J
and t he definition of “refinery process unit” promulgated in 40 CFR part 60, subpart Ja in June
2008 read as follows: “Refinery process un it means any segment 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 refinery; and (2) the
unit must be used to conduct “a specific processing 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

- distillation, crackin g or reforming, and it is not limit ed to only those processes used to produce gasoline, kerosene, fuel oils, etc. In the proposed amendment to this definition, we listed “operations” that we construed as conducting a “specific processing operation” when th ese 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.
We reviewed t he impact of the proposed revision of this definition on 40 CFR part 60, subpart Ja as well as its historic use in 40 CFR part 60, subpart J

. The term “refinery process unit” is used primarily in the definitions of certain affected facilities, “process gas ” and “process upset gas” in subparts J and Ja. The term is also used in the flare 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 proposal and promulgation of subpart J. In response to a comment that the definition of “process gas” “should have included the non

- hydrocarbon

gases p roduced by various process units in a refinery,” the EPA responded: “The definition has been revised to include all gases produced by process 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 (BID Vol. 3), EPA 450/2

- 74

- 003 (Feb. 1974),
Docket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 0082). The definition had actually been revised to
include “ any gas generated by a petroleum refinery process unit .” Th e response in BID Vol. 3 suggests that the EPA considered “refinery process units” and “process units in a refinery” toDRAFT

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54 have the same meaning, and there is no mention of limiting what is considered to be a “refinery process unit” or a “process units in a r efinery.”

“ P rocess 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 g ases sent to a flare that would qualify as “process upset gas.” For example, i f a coke gasifier is not a refinery process unit, then gases generated during the startup, shutdown or malfunction of a coke gasifier located at the refinery would not be “proces s upset gas” and would 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 “process upset gas” exclusion has considered a broad definiti on 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 unit,” it was clearly our
intent that a broa d 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 consider
flare minimization methods for th is broadly defined range of equipment referred to collectively as “refinery process units.” Based on our review of the impacts of changes to the definition of “refinery process
unit
, ” and considering all o f the comments received, we maintain that the existing definition of “refinery process unit” is broad and should be broadly interpreted. For consistency between 40 CFR part 60, subparts J and Ja, we have elected 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 connected to the flare, we revised the language in the flaring provisions to refer to “refi nery process units, including ancillary equipment.” This revision is made to clarify our original intent that coke gasification units, storage tanks, product loading operations and wastewater treatment systems, as well as pressure relief valves, pumps, sam pling vents, continuous analyzer vents 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 de finition of “ancillary equipment.” Specifically :DRAFT

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55 Ancillary equipment means equipment used in conjunction with or that serve a refinery process unit. Ancillary equipment includes , but is not limited to, storage tanks, product loading operations, wastewater treatment systems, steam

- or electricity

- producing units (including 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 trigge r a flare modification and generate gas streams that should be considered in the FMP . We recognize
that on

- site sulfur recovery plants are considered refinery process units, and we proposed amendments to the definitions of “refinery process unit” and “sulf ur recovery plant” to clarify that we consider a sulfur recovery plant to be “ a segment of the petroleum refinery in which a specific processing operation is conducted

. ” However, the strict definition of “refinery process unit” would only apply to sulfur r ecovery plants physically located 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 contradictory to define a sulfur recovery plant located

o utside the refinery as a “refinery process unit,” so we are also not finalizing the proposed amendment to include the term “all refinery process units” in the definition of “sulfur recovery plant.” However, while connections to a refinery flare from an off

- site sulfur recovery plant are not expected to be common, off

- site sulfur recovery plants 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 e quipment
, ” such that connecting an off

- site sulfur recovery plant that is subject to subpart Ja to a flare at a refinery would cause that flare to be a modified flare subject to subpart Ja. Further, in reviewing the definition of “sulfur recovery plant,” w e 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 provisions in 40 CFR 60.100(a) and 40 CFR 60.100a(a). Specifically, we inadvertently om itted 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 gases “produced at the petroleum refinery.” Thus, we are amending the
definitio n of “sulfur recovery plant” to correct inadvertent errors and 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 facilities in 40 CFR part 60, subpart Ja.DRAFT

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56 

### 3.11 Sulfur Recovery Plant
C omment : Commenter 0305 requested a clarification in the definition of “sulfur recovery plant” to exclude loading facilities (in addition to secondary storage vessels). Response : We a gree and have revised the final de finition

. We also corrected an inadvertent omission of the word “produced” in the definition. The “sulfur recovery plant” need not be located at a petroleum refinery, but, for the purposes of subpart Ja, is limited to units that recover sulfur from sour ga ses “ produced at a petroleum refinery.”DRAFT

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57 

## 4 .0 FUEL GAS COMBUSTION DEVICES AND FLARES

4.1 Emission s 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 asserted that the EPA did not properly demonstrate that the long

- term 60 ppmv H 2 S fuel gas concentration limit i s BSER for flares as fuel gas combustion devices because the EPA underestimated the cost of treating the flare gas and overstated emissions reductions

. According to Comm enter 0296, flare gas treatment would require a compressor system for each flare header and would be more likely to require additional amine treatment systems and/or sulfur recovery units than the EPA estimated. The commenters also suggested that the EPA o verestimated 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 requiring fuel gas to meet a long

- term 60 ppmv
H 2 S concentration limit would result in significant re

- piping and capital investment for minimal
emission reductions , which the EPA’s impact analysis did not consider

. Commenter 0 311 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 that are incu rred by individual 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 those 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 amine systems of actual projects showing cost effectiveness of $44,000 to $63,000 per ton of SO 2 reduced; (2) FGR systems with cost effe ctiveness of $25,000 to $65,000 per ton of SO 2 reduced ( details of theDRAFT

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58 commenter’s estimate are confidential ); and (3) FGR system expansions, which included an additional compressor, surge storage capacity, and amine scrubber capacity, showing cost
effecti veness of recovery system expansions 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 fuel gas combustion devices in general because it could preclude some refineries from 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 emission s 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 emission s limits for non

- exempt gas streams upstream of the flare header. Alternatively, Commenter 0296 recommended that t he long

- term 60 ppmv
H 2 S fuel gas concentration limit be applicable only to the refinery f uel 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 effective 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 refinery, adding one new fuel gas combustion device to the fuel gas system would essentially require the owner or operator 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 gas system. Upon review of the BSER analysis conducted at proposal for fuel gas combustion devices, we now realize that the analysis is not applicable to flares (See Docket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 0289). Moreover, since we are regulating flares separately from other fuel gas combustion devices in this final rule, we should separately consider 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 optimize 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 determined that
, for refineries to demonstrate thatDRAFT

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59 their fuel gas complies with a long

- term H 2 S concentration of 60 ppmv, refine ries would have to
install a FGR system (which was not needed for other fuel gas combustion devices) and then upgrade the fuel gas desulfurization system. Alternatively, refineries would have to treat the recovered fuel gas to limit the long

- term concentra tion of H 2 S to 60 ppmv with new amine
treatment units on each flare. While some of the costs provided by the commenters did not include the value of the recovered gas and appeared, at times, to include equipment not necessarily required by the regulation, we generally agree with the commenters, 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 p rovided by the commenters and the costs and emissions reductions 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 require refineries to limit the concentration of H 2 S in the fuel gas to levels lower than the short

- term 162 ppmv H 2 S concentration, our baseline when evaluating the impacts of a nationa l standard (in this case, 40 CFR part 60, subpart Ja) is the national set of requirements to which an affected flare would be subject 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 Impacts 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) Emission reduction (tons SO 2 /yr) a Emission reduction (tons NO X /yr) a Emissio n reduction (tons VOC/yr) a Cost effectiveness ($/ton)

New 80,000 15,000 6 3 4 130 84,000

Modified / Reconstructed 860,000 160,000 53 3 1 0 1,200 100,000

a These emission reductions are based on flares already meeting the short

- term 162 ppmv H 2 S fuel gas co ncentration

limit in 40 CFR part 60, subpart J ( i.e. , these are the incremental emission reductions 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 origin ally proposed combined short

- term 162 ppmv H 2 S concentration and long

- term 60 ppmv H 2 S concentration in the fuel gas).DRAFT

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60 

### 4.1. 2 Alternative Compliance Options

Comment : Commenter 0301 requested that the EPA specifically allow alternative means of compliance i ncluded in consent decrees as acceptable compliance alternatives for subpart Ja. Specifically, certain flares have an alternative 500 pounds per day ( lb/day ) SO 2 emissions limit
in lieu of a requirement to limit the short

- term concentration of H 2 S in fuel gas combusted in a
flare to 162 ppmv , and the commenter requested assurance that this alternative is sufficient to demonstrate compliance with subpart Ja. Response : The requirements in consent decrees are negotiated settlements and are not
based on a n anal ysis of BSER , as several commenters have pointed out (although typically to argue why certain consent decree requirements 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 with 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 cost s 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 effective units, we generally base our decision on the
nationwide costs and emissions reductions achieved. As such, we do not feel compelled to loosen the national standard based on the poor cost effectiveness of a very limited number (l ess than
1 percent) of flares. We have conducted specific analyses that consider flares as separate and distinct affected
facili ties 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 limiting the short

- term concent ration of H 2 S to 162 ppmv H 2 S during normal operating conditions is cost effective for flares. We also find that the 500 lb/day SO 2 limit is not, in any way, equivalent to the long

- standing shor t

- term 162 ppmv
H 2 S concentration requirement for these units in subpart J. At 500,000 standard 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 500,0 00 scf in any 24

- hour period could exceed the short

- term 162 ppmv H 2 SDRAFT

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61 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
exis ting 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 amend ments 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 t echnologies such as FGR is technologically feasible,

cost effective and BSER under CAA section 111. However, the final rule (see 73 FR 35838, June 24, 2008) did not include those requirements, and the commenter asserted that the EPA did not adequately expl ain why the BSER determination for the final rule changed (see 73 FR 35838, June 24, 2008). The commenter stated that the EPA did not provide rationale for dismissing technology that the a gency determined was demonstrated and cost effective in favor of sta ndards such as the FMP to manage flare emissions. The 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’ events.” However, t he 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 EP A’s explanation for the change is “internally
inconsistent.” Commenter 0307 asserted that there is no question that FGR is demonstrated technology;
FGR is commonly used in existing refineries to capture and recycle process gases. Existing
refineries have b een able to significantly reduce or eliminate routine flaring 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 significantly reduce air pol lution as well as save owners and operators money through recovery 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. 199 9) (citing Portland Cemen t A ss ’ n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973))DRAFT

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62 and expensive to make. 9 In addition, demand for steam g eneration is reduced when steam

assisted 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 presen ted 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 emission reductions, the EPA did not explain why both eliminating routin e flaring and reducing flaring via a limit on flare 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 flaring because the CAA section 11 1 standards must reflect the best technology capable of capturing and 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 n ot feasible or cost effective when considering the revised emissions reductions. Commenter 0307 also noted that in the preamble to the final standards, the EPA stated
that FGR is not technically feasible if a refinery produces more fuel gas than it needs t o 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, s uch as the 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 a gency believed “other options exist, such as building an
electric co

- ge nerating unit.” Response : We note that our original proposal (see 72 FR 27178, May 14, 2007) did not eliminate all routine flaring, only routine flaring 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 requirements were to minimize releases to the flare during startup and shutdown and to eliminate routine flaring of gases from the fuel gas producing unit during normal operat ion. For units that produce significant quantities of fuel gas, refinery owners and operators routinely install 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 Attach m ent A to Comment 0307 (Docket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 0317)

.DRAFT

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63 refinery, so a gas recovery system (compressor) at the fuel gas producing unit was the expected method of compliance for an affected fuel gas producing unit at the time of the original proposal. The problems with the initial proposal were that there were ambiguities in the definition of a fuel gas producing unit and in what was meant by “no routine flaring.” As we evaluated the proposed rule based on the comments received, we determined that it would be more straightforward to make the flare the affected facility in the final rule (see 73 FR 35838, June 24, 2008). By regulating the flare, gi ven the specific flare modification 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 producing units. In other words, the initial proposal
af

fected only a portion of the gas sent to a flare, while the final rule affect s all of the gas sent to a
flare. As such, we find that the “flare as the affected facility” paradigm being finalized today is environmentally superior to the “no routine flaring from new fuel gas producing 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; therefore, a complete ban on “rou tine” flaring is not
BSER (see the “Flare Options Calculator” included as an attachment to Docket Item No. EPA

HQ

- OAR

- 2007

- 0011

- 0223 and the flare impact memoranda included as Docket Item No. EPA

HQ

- OAR

- 2007

- 0011

- 0223 and Docket Item No. EPA

- HQ

- OAR

- 2007

- 00 11

- 0289). We do agree
with the commenter that FGR systems are technically effective at reducing flare emissions. We
also maintain that it is cost effective to install FGR systems when the flow rate of flare gas
exceeds a certain threshold. However, the flo w 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 calculator was developed to evaluate a range of flow rates, flare gas Btu cont ent 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 per day (scfd) was determine d to be the
threshold at which FGR would be cost effective. In the proposed amendments (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 requireme nt to routine flaring discharges in an effort to address uncertainties on how to define “normal operations” and to account for highDRAFT

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64 daily flow rates that might cause exceedances of the 30

- day limit 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 the affected facility, it is necessary to provide provisions for flaring during periods 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 have to find somewhere else to send the fuel gas
besides the flare. The owner or operator may be able to store the fuel gas until it is needed, which
would require additional storage tanks , but this alternative has many drawbacks, such as s trict
limitations on excess storage capacity and safety hazards associated with s t oring the explosive

gases

. Alternatively, the owner or operator could 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 that could either be used

on

- site or sent off

- site ( e.g. , el ectricity supplied to the electric power grid )

. The additional costs associated with th e steam

- o r electric ity

- generating equipment greatly increases the amount of
flare gas that would need to be recover ed for a FGR /co

- generation system to be cost effectiv e , and this additional gas would be needed on a routine basis

. However , a refinery is not typically fuel gas rich consistently all year long

. Consequently , it is not cost effective to require FGR during periods when the refinery is fuel gas rich 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 gas

. Furthermore, the few facilities that are consistently fuel gas rich typica lly have made arrangements to sell their excess fuel gas, have already installed co

- generation units or have made other arrangements 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 did 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 o f a co

- generation unit or other type of potential control system, making the development of a single national standard highly problematic. The a gency collected additional data from the petroleum refinery industry throughDRAFT

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65 an information collection request d uring the course of 2011 (see Docket ID No. EPA

- HQ

- OAR

2010

- 0682 ), and we are in the process of analyzing the collected data

. If fuel gas rich situations are found to be more common than we anticipate, we will consider additional emission reduction opportu nities for these situations at that time. However, based on the information currently available, when we consider ed the flare as the affected source (rather than the fuel gas producing unit) and the technology needs to eliminate “routine flaring ” during pe riods when a refinery is fuel gas rich, we determined that a “no routine flaring” 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 ref inery is fuel gas rich is cost effective 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 FM P and other requirements will reduce flare flow
, and flexibility is needed in order to accommodate sweep gas requirements for different flares and
weather/seasonal conditions. Response : We appreciate these comments; however, as seen by the comments receive d on the flare flow RCA requirements, the re remain issues regarding sweep gas requirements, flare configurations and weather/seasonal conditions that still need to be addressed with respect to the
flow RCA. These issues are discussed in detai l 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 I nventory ( 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 the w aste gas was too high (Commenter s 0305 and 0311); (4) the EPA did not consider net costs when no offset is possible ( e.g. , when the refinery is long on fuel gas or flare gas is poor quality ) (Commenter s 0305 and 0311); (5) the EPA underestimated capital co sts for recovery systems (Commenter 0311); (6) the EPADRAFT

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66 underestimated capital costs for monitoring systems (Commenter 0311); ( 7) the EPA did not
consider that for certain types of flares
, no sulfur emission reductions are possible ( e.g. , liquefied petroleu m gas (LPG) tank, hydrogen or emergency

- only flares) , but owners and operators still incur the cost of installing sulfur monitor s on those flares (Commenter 030 5 ); and (8) limited data were used to assess emission reductions from RCA (Commenter s 0305 and 0 311). Response : We generally disagree with these criticisms 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 numbe r of factors, many of which are variable (such as the Btu content and flow rate of the flare gas). 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 fl ows above which FGR would be cost effective. The costs of the systems and monitors came from vendor

- reported costs. These costs agree well with or tend to be slightly higher than costs for FGR systems collected by the BA AQMD , m any of which came
from refine ry industry representatives to support their flare management requirements. We have acknowledged that cost credits were used predicated on the ability to productively use the recovered flare gas
, but we have provided specific exemptions from the flow RCA f or 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 reduced. We have also amended the flare flow RCA
threshold in 40 CFR 60.103a( c )(1) (ii) to be 500,000 scf abo ve a defined baseline in any 24

- hour period to account f or sweep and purge gas flow.
T he 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 t hat 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 finalizing 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) observations, it appears that the flare flow rates extrapolated from the NEI data may se riously underestimate 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 quantity 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. IfDRAFT

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67 anything, we find that the flare standards may achieve more emission reductions than previously projected. We uphold our analysis and the conclusion that the flare 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 subpart Ja than the existing definition in subpart J

was to i ndicate that existing process units are not subject to the flare standards

. The commenter suggested that the EPA should further clarify this point so that it is clear that existing affected facilities are exempt from the flare standards

. Response : The affe cted facility discussion is different primarily because the flare provisions were first published at a different date than the other rule requirements, not to denote
that the FMP does not cover existing sources connected to a newly modified flare. The FMP covers all refinery process units and ancillary emission sources (existing and new units) that are
connected to an affected flare.
Comment : Commenters 0308 and 0311 suggested that the requirement to minimize discharges to the flare in proposed 40 CFR 60.10 3a(a)(1) should specifically 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) consider “the cost of achieving such emission reduction, and any n on

- air quality health 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 co st under section 111 of the CAA

. Response : We agree that the language in proposed 40 CFR 60.103a(a)(1) appears to require an assessment of flare minimization irrespective of cost or other relevant considerations
, as contained in CAA section 111, which was not our intent. We are clarifying
, through this

response , that cost, safety and emissions reductions may be considered when evaluating what actions should be taken to minimize discharges to a flare, but we disagree that the flare
minimization assessment sh ould be limited to “routine discharges.” We have revised the FMP requirements in 40 CFR 60.103a(a) to more fully describe the types of information that must be evaluated and included in the plan.DRAFT

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68 As noted in s ection III.C of th e preamble to the final amend ments , we are finalizing our proposed withdrawal of the 250,000 scfd 30

- day rolling average flow limit for flares. This limitation does not adequately account for site

- specific factors regarding flare gas Btu content, ability to off set natural gas purchase and other considerations. We find that these factors need to
be addressed in a site

- specific basis and are more appropriately addressed through the FMP . In the absence of the specific flow 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 warranted. We have also revised the flare minimization requirements to require the 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 flare reduction options considered, the costs of each option, the quantity of flare gas that would be recover ed or prevented by the option, the Btu content of the flare gas and the ability or inability of the reduction option to offset natural gas purchases. The plan will also include the rationale for the selected reduction option, including
consideration of saf ety 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 comment for further detail on baselines), must also be submitted to the Administrator. In summary, although we did not incorporate the commenter’s suggested language for limiting the scope of the minimization requirements to actions that are “consistent with good engineering practices” and that “consider costs and other healt h and environmental impacts,” we acknowledge that these are valid considerations in the selection of the minimization alternatives available for a given affected flare. We find that the process of developing and submitting the
FMP will ensure that these fa ctors 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 proced ures to reduce flaring during periods of fuel imbalance in 40 CFR 60.103a(a)(6) does not require curtailed production of key fuel gas producing units, which would not be cost effective, even though it may be the only means of reducing flaring.DRAFT

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69 Response : We agree that the procedures to reduce flaring in cases of fuel gas imbalance are not intended to require refineries to curtail production of key fuel gas producing units such as the atmospheric distillation column, the FCCU, coking unit or similar processes

. We expect that refinery owners and operators will consider plans such as procedures for reducing overhead condenser temperatures (by increased cooling water recirculation or using refrigerated
condensers ) to minimize the amount of C3 or C4 hydrocarbons t hat are introduced to the fuel gas system, procedures for temporary fuel gas storage if appropriate storage vessels are available on

site or agreements to sell excess fuel gas to neighboring 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 records of the alternatives evaluated , including why certain options were not considered viable options for inclu sion in the FMP

.



### 4. 4 .3 Root Cause Analysis and Corrective Action Analysis

Comment : Commenter 0296 supported the RCA requirements 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 requested 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 replacing the word “implement” with the word “identify” in proposed 40 CFR 60.103a(a)(5), suggesting that this appears to be the EPA’s intent based on the implementation schedule described in proposed 40 CFR 60.103a(c). Commenter 0311 also requested that a provision be added for up to a 6

- month extension, with approval, to perform RCA evaluations for complicated 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

. W e do

agre e with commenters that some corrective actions may require more time t o 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

. Therefore, simply replaci ng 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 day s as follows : “ For corrective actions that cannot be fully implemented within 45 day s following the discharge for which the root cause andDRAFT

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7 0 corrective action analyses were required
, the owner 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 event basis. The commenter contend ed that flares complying with the short

- term 1 62 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 consolidated flare systems (larger individual flares). The commenter also
noted tha t the proposed language for flow RCA could be interpreted to require a RCA for every
minute when a 24

- hour accumulation exceeds a threshold and suggested that if the trigger is not changed to an event, then it should be evaluated on a calendar day basis, w hich is much easier to implement. Response : As the flare is the affected facility, triggering the RCA on a per flare basis i s an obvious and rational approach. With respect to the SO 2 RCA, we found that the consent decree requirements for a RCA did not con sider the allowable SO 2 emissions from the flare but rather the direct mass emissions (uncorrected for “allowable” emissions). Furthermore, the expected “allowable” mass emission correction based on 162 ppmv H 2 S will be negligible for events that trigger t he SO 2 RCA but not the flow RCA. We disagree 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 operati ng conditi ons

. The flare gas flow rate would have to be 20 million scf d at 162 ppmv H 2 S to exceed
500 lb SO 2 in any 24

- hour period , and in that case, the 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 consider ing “flaring events” and, to the exte nt possible, eliminat ing disincentives for large individual flares. However, w e see no reason why flare gas flow rates of th e magnitude described above would be considered normal operation or baseline flow rates compliant with the FMP requirements in the
f inal 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 last for more than 24 hours or events that exceed
both the flow and SO 2 RCA thresholds. Although not noted by the commenter, the per eventDRAFT

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71 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 flare

specific baseline flow adequ ately addresses the disincentives for large individual flares with respect to the flow limit. However, the final rule does continue to require evaluation of the SO 2 and flow RCA thresholds on a 24

- hour basis rather than a calendar day to more accurately

co nsider the emissions from a single discharge that lasts less than 24 hours but occurs over 2 calendar days. For all of the above reasons , we conclude that the final rule requirements (as amended) appropriately consider different refinery configurations wit h respect to the number and size of flares and, although the RCA is evaluated on a per flare basis, the final rule, as amended, effectively considers the emissions “event” from that flare.
Comment : Commenters 0304 and 0305 stated that the flare flow rate t hreshold 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 threshold should be either deleted ( Commenter 0304) or replaced with a site

- specific limit which appro priately reflects the size and complexity of the individual flare system ( Commenter s 0304 and 0305). Commenter 0304 cited an ultracracker
flare th at cycles from 5 million to 25 million scf d

. According to the commenter, this would result in meaningless dail y RCA , and the commenter asked 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 hy drocarbons) ; (2) purge and sweep gas ; (3) natural gas added to increase the Btu content of the flare gas ; and (4) gases regulated by other rules (where the flare is the control device). Commenter 0315 added that pilot gas should be excluded from the calcul ation of 500,000 scf gas
flow. Commenters 0308 and 0311 requested that the EPA clarify that the flow RCA be restricted to upsets and malfunctions as initially promulgated on June 24, 2008, because pilot gas, sweep

gas, purge gas and other routine flows wou ld trigger a RCA automatically or with a nomi nal
release event and because a RCA can only effectively reduce non

- routine flows. Commenters
0308 and 0311 also noted that the requirements in proposed 40 CFR 60.103a(a)(1) and (4) should not be duplicative ; pr oposed 40 CFR 60.103a (a)(1) should focus on routine flows and proposed 40 CFR 60.103a (a)(4) shoul d focus on non

- routine events. Commenter 0311 suggested the flow meters required in the rule could be used to identify step changes caused by an event from rou tine flow. Commenter 0315 recommended that theDRAFT

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72 EPA adopt the approach used in the refinery consent decrees to address RCA for recurring

events. For each “f laring d evice, ” sites may prepare and submit a single RCA for one or more root causes found by that a nalysis to routinely occur. The consent decrees include a provision that the owner or operator must inform 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, maintenance of a FGR system, flow from alkylation units which cannot be recycled due to contamination issues, fuel gas imbalan ce issues and high concentrations of hydrogen or nitrogen (either with 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 exceed 500,000 scfd, although we acknowledge that the
threshold at which FGR becomes cost effective is strongly (inversely) correlated 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 effective). Although we did not specifically exclude sweep or purge gas from the flow, we expected that the flo w 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 threshold of 500,000 scf in any 24

- hour period. In fact, in our original analysis of the appropriate flow rate RCA threshold (Docket Item No. EPA

- HQ

OAR

- 2007

- 0011

- 0246), we essentially assumed that the sweep and purge gas flow rates were zero, and we estimated costs and emissions reductions of the 500,000 scf in any 24

- hour period
thresho ld
, based on recovering that amount of gas or eliminating recurring 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 acknowle dge that the size of the flare, as well as the flare header system, will greatly

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

5 million scfd of flare gas flow. Additionally, a compositional 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 provided by the commenter, that the hydrogen stream recycle compressor was off

- line approximately ha lf the year. For such huge gas flows, considering the cost of purchasing or producing add itional hydrogen and the emissions associated with that process, it is reasonable to expect that the facility would have a back

- up compressor if the primary compressor is unreliable.DRAFT

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73 impact the required flow needed to maintain the readiness of the flare. Although we can derive suitable flare flow thresholds for average conditions, 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

- fits

- all threshold, the final rule requires facilities to develop their own base flare flow rates as part of their FMP . A flow

- based RCA is triggered if flows measured by the flow monitor exceed 500,000 scf greater than the base flare
flow rate in any 24

- hour period. Evaluating the flow rate threshold above a baseline better

r eflects our original analysis of the impacts of flow

- based RCA when the sweep or purge gas flow rates are not negligible. We also note that 40 CFR 60.103a(d) allows a single RCA to be conducted for any single continuous discharge that causes the flare to e xceed either 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 refinery process units and ancillary equipment connected to the flare, nor 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 for 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 a re 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, the FMP (as well as significan t revisions to the plan to include alternative baselines) must be submitted to the Administrator. 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 con sidered, all required
elements ar e included and all appropriate flare reduction measures are evaluated); (2) accuracy (the emission reductions and cost estimates for the different options are accurate); and (3) reasonableness (the selection of reduction op tions 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 were not evaluated or
selected when reason able, the baseline or alternative baseline flow rates are consideredDRAFT

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74 unreasonable), the Administrator will notify the owner or operator of the apparent deficiencies. The owner or operator must either revise the plan to address the deficiencies or provide

a dditional information to document the reasonableness of the plan.
Comment : Commenters 0298 , 0300 and 0304 requested that an exemption from the flare
flow RCA requirement be provided for planned startup and shutdown events that are consistent
with the facil ity’s FMP because it is redundant and unnecessary. Response : We agree. There will be some units whose startup and/or shutdown gas flow to
the flare will exceed the flow RCA threshold even though the gas flow to the flare has been
minimized to the extent po ssible. 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 th e fuel gas system, the amount of hydrogen that can be effectively redirected 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 pe rformance of the process heaters due to low heat input rates) and the amount of fuel gas that 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 b y the shutdown cannot be used to reduce natural gas purchases and some amount of hydrogen and/or fuel gas would then have to be flared). As long as planned startup and shutdowns are performed according to the FMP requirements, a RCA is not required
, and we have revised the regulatory language to exclude these circumstances.
Comment : Commenter 0311 requested clarification regarding the RCA and corrective action analysis requirements for sulfur recovery plants. The commenter asked the EPA to specify
if the 50 0 lb of SO 2 above the emission limit are to be calculated per calendar day or per 24 hour period. In addition, the commenter noted that sulfur 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 at 500 lb reduced sulfur or total sulfur (depending on the type of CMS used for monitoring the emissions) above the emission limit. Response : As state d previously, we elected to evaluate the SO 2 RCA threshold on a 24

- hour basis rather than a calendar day to more accurately consider the emissions from a single discharge that lasts less than 24 hours but occurs over 2 calendar days. However, w e agree thatDRAFT

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75 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 w as compared to the RCA threshold for fuel gas combustion devices

. The proposed RCA th reshold for both types of process units was 500 lb above the emission limit, but the proposed amendments directed the owner or operator to compare the SO 2 emissions to “the period of the exceedance” for fuel gas
combustion devices and “ the entire 24

- hour p eriod ” for sulfur recovery plants. Upon further consideration, we see no reason for these requirements 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 excess emissions” under 40 CFR 60.10 5 a( i) and
40 CFR 60.10 6 a( b ) ; to avoid confusion, we have decided to use the already

- defined term “period
of excess emissions.” Therefore, u nder 40 CFR 60.10 3 a( c ) (3) of t he final amendments
, the

owner or op erator is require d to conduct RCA as described in 40 CFR 60.10 3 a( 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 equal to the applicable emissions lim it in
40 CFR 60.102a(f)(1) or (2) during one or more consecutive period s of excess emissions or any 24 hour period, whichever is shorter .” Th is clarifying amendment is needed to ensure that the magnitude of the emission limit exceedance is properly compare d 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 words, if the owner or operator calculates four
consecutive 3

- or 12

- hour averages (as applica ble) that are above the applicable emission limit
, the owner or operator should compare the total emissions from those 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 rolli ng averages are typically about
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 emi ssions 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

-DRAFT

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76 hour average for e ach 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 with reductive control systems, we acknowledge
that the SO 2 RCA threshold is somewhat contrived for these systems; howe ver , we conclude that it is appropriate so that the magnitude of the event that triggers a RCA is essentially the sa me regardless of whether an oxidative or reductive control system is used. Specifically, t he
concentration measurement for the reduced sulfu r compounds is determined as ppm SO 2 by
volume. To convert the concentration into mass emissions , the molecular weight s of the pollutants are needed. Most reduced sulfur compound monitors do not determine the
concentration of individual reduced sulfur comp ounds ; 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 determine d from the monitored values

. One must either
calculate the mass of sulfur emitted in t he reduced sulfur compounds and/or calculate the equivalent mass of SO 2 emitted. The molecular weight for sulfur is half that of SO 2 . I f units with reductive control systems were allowed to calculate the excess emissions in terms of pounds of sulfur per da y rather than pounds of SO 2 (equivalents) per day , an event 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 appropriate considering that the emission limits for both systems are based on the same overall sulfur recovery efficiency. 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 b e determined considering the mass of
SO 2 equivalent emissions above the applicable emissions limit for all sulfur recovery plants
, including those with reductive control systems.



### 4. 5 Monitoring Fuel Gas Combustion Devices
Comment : Commenter 0305 recommende d that the EPA allow alternative monitoring plans for fuel gas combustion devices approved under subpart J to be deemed compliant with

s ubpart Ja. Response : The alternative monitoring plans in subpart Ja were developed based on the alternative monitoring p lan requirements in s ubpart J, but with the additional intent to ensure compliance with the long

- term 60 ppmv H 2 S concentration limit

. For flares, which are notDRAFT

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77 required to meet th e long

- term 60 ppmv H 2 S concentration limit, alternative monitoring plans

ap proved under subpart J are deemed compliant with s ubpart Ja

. However, for fuel gas combustion devices, which are required to meet the long

- term 60 ppmv H 2 S concentration limit,
the su bpart Ja criteria must be used to develop a new alternative monitoring pl an

.



### 4

. 6 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 engineering calcul ations are sufficient 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 allow engineering estimates of the TRS

- to

- H 2 S correction factor due to safety con cerns and inability 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 are 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 that generally see little or no gas flow, and sulfur emissions can be calculated based on sampling the flare gas (although the c ommenter 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), (iv) 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 sampling. Commenters 0305 and 0311 agreed that “emergency only” or “SSM only” fla res 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 the primary flare is overloaded during pe riods of
SSM. The commenter noted that
, in this situation, the continuous sulfur monitor on the primary flare would often provide data on the sulfur content of the flared gas (depending on the exact configuration). The commenter asserted that the burdens r elated to a continuous 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 exemptions be provided for flares in low sulfurDRAFT

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78 service (less than 5 ppmv or sulfur

- intolerant streams), similar to the exemptions provided in
40 CFR 60.107a(a)(3)

. Commenter 0296 stated that properly designed FGR systems should exempt a fl are from
the H 2 S concentration requirements in subpart Ja as 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 shou ld eliminate the TRS monitoring requirements for flares with FGR systems, 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 f or installation of a FGR system. Commenter 0305 requested clarification that when sweep gas is routed to an emergency

only flare, it is not required to be monitored if it meets one of the definitions of streams that do not require monitoring or is monitore d elsewhere (for example within the fuel gas system). Similarly, Commenter 0305 requested clarification that 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 f or compliance with subpart J or Ja, nor is it required to be included in the flare flow for the purposes of RCA

. Commenter 0314 noted that
, to meet the performance test requirements on flare sulfur monitors as proposed at 40 CFR 60.107a(e)(1)(ii) or (e)(2) (ii), the owner or operator of a flare
with FGR may have to intentionally 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 requirements 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 flare intentionally to perform required testing

. Response : We have a mended the final rule so that gases that are exempt from H 2 S monitoring due to low sulfur content are also exempt from sulfur monitoring requirements for
flares. For low

- sulfur gases, the flare RCA will always 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 content
, as described in 4 0 CFR 60.107a(a)(3), such as flares used for pressure relief of propane or butane product spheres (fuel gas streams meeting commercial grade product specifications for sulfur content of 30 ppmv or less) or flares used toDRAFT

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79 combust fuel gas streams produced i n process units that are intolerant to sulfur contamination ( e.g. , hydrogen plant, catalytic reforming unit, isomerization unit, hydrogen fluoride alkylation unit). We already clarified that flare pilot gas is not required to be monitored. Also , 40 CFR par t 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 allowed for flares as well). Thus, we agree that if a flare only burns natural gas, fuel gas monitored elsewhere 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 sulfur monitoring is necessary for “emergency only” flares. ( A n emergency flare is defined as a flare that combusts gas exclusively released as a result of malfunctions (and not startup, shutdown, routine operations or any other cause) on four
or f ewer occasions in a rolling 365

- day period. For purposes of the rule, a flare cannot be categorized as an emergency flare unless it maintains a water seal.) We acknowledge that there are difficulties and costs with installing monitors on flares that rarely operate. However, we are concerned about how the owner or operator will detect emissions above 500 lb SO 2 in any 24

- hour period during an upset or malfunction of a refinery process unit or ancillary equipment connected to the flare. Commenters appear to h ave 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 flaring events, then that would be a potential option.
Howeve r, during a process upset or malfunction, focus should be on alleviating the problem rather than taking a special sample. Also, given the duration of some of these events, it appears unlikely that representative samples can be manually collected. Taking t he 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 li quid level monitoring
, as previously described as an alternative to the sulfur and flow monitors. As described in more detail above, any fuel gas pressure exceeding the water seal liquid level triggers a RCA and there is a limit to the number of exceedance s 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 concentrations are less critical than for flares that must evaluate these parameters to determine i f a RCA is needed. Consequently, for these flares,DRAFT

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80 engineering calculations can be used to estimate the reported emissions during the flaring event,
but the RCA must be performed regardless of the magnitude of these engineering estimates. Using this altern ative monitoring option, emergency flares are not required to 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 alte rnative 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” procedures requested by the commenter are described as alternative relative accuracy procedures in s ection 16.0 of Performance 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 pr ocedures are appropriate for flares. We expect that
, for most affected flares, the variability in flow (including no flow conditions) and sulfur content of the gases discharged to the flare create significant barriers to the normally required relative accu racy assessments, particularly if those assessments need to be made over a range of sulfur concentrations potentially seen by the monitor. 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 operato r 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 Administrator of the ir intent to us e the alternative relative accuracy procedures.
Comment : Commenter 0312 requested that the EPA clarify whether the additionally proposed sulfur monitoring options for flares are for TRS or total sulfur. The commenter noted that measuring total sulfur is th e 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 gaseous fuels be included as acceptable options to perform the
relative ac curacy 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 sulfur monitor can be used for both the RCA and for compliance with the require ment 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. CommenterDRAFT

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81 0313 supported the addition of alternative monitoring methods for the sulfur content of flare gas
but noted that si nce the composition 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 eval uating 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 equivalent to a total sulfur monitoring method.
As disc ussed previously, we are relying on the suite of flare requirements we are promulgating to limit SO 2 emissions at the flare. These include optimizing management of the fuel gas by limiting the short

- term concentration of H 2 S to 162 ppmv during normal opera ting conditions. We expected most refineries would already have the H 2 S monitor and did not consider the use of a total sulfur monitor for use in complying with the short

- term 162 ppmv H 2 S concentration in the fuel gas. As the H 2 S concentration will always be less than the TRS concentration, it is acceptable to use 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 me et the 300 ppmv span requirement. However, we have not provided a correction factor to scale down the TRS concentration
to H 2 S. The owner or operator using this method must essentially be able to demonstrate they can achieve a 162 ppmv TRS concentration i n the fuel gas. The concentration ratio was provided for the purposes of the RCA because of the costs of adding a total sulfur monitoring system when a dual range H 2 S monitor was already in

- place
, as well as the expected accuracy needed for the system to a ssess 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 expected to be significant. On the other hand, the short

- term 162 ppmv H 2 S concentration in the fuel gas must be continuously maintained, and 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 sulfurDRAFT

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82 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 to tal sulfur content being attributable to fluctuations in
H 2 S concentrations. Consequently, we have determined that the inaccuracies of the ratio approach are not acceptable for continuously demonstrating that the short

- term concentration in the fuel gas do es not exceed 162 ppmv H 2 S. Therefore, owners or operators 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.
Com ment : Commenter 0311 supported the proposed amendment revis ing 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 requirement and that engineering
calculations can be used to assess exceedances of the SO 2 RCA threshold of 500 lb in any 24

- hour period

. Response : Th e 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 sulfur content in streams containing several percent
sulfu r. 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 dual range monitor will be n ecessary. 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 determining the sulfur concentration for the range of concentrations expected to be seen at the flare. We are particu larly interested in quantifying the concentrations of high sulfur

- containing streams as these would be the streams most likely to trigger a root

- cause analysis 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 the commenter that this may be too restrictive, and we have revised the span requirements to be determined based on the maximum sulfur content of gas that can be discharged to the flare ( e.g. , roughly 1.1 to 1.3 times theDRAFT

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83 max imum anticipated sulfur concentration)
, but no less 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 the applicable span specifications are met. In reviewing the span specifications, we noted that span requirements were inadvertently omitted from the TRS compound monitoring alternative. The purpose of
these monitors is identical to the H 2 S monitoring alterna tive, 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 Appendix F to part 60 defines “span value” as: “The upper limi t of a gas concentration measurement range that is specified for affected source categories in the applicable subpart of the regulation.” The concentrations 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.



### 4. 7 Flow Monitoring for Flares
Comment : Commenters 0305 and 0311 stated that “emergency only” or “SSM only” flares should be exempt from flow monitoring requirements, and Commenter 0311 also requeste d clarification that secondary and “malfunction only” flares are exempt from the flow meter requirement. Commenter 0311 stated that flare flow meters are costly and unnecessary because engineering calculations, which are currently used, are sufficient to e valuate 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 than 500,000 scfd should be excluded from the flow monitoring requirements, as there is no justi fication for flow monitors 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 not flow through the main flare header and thus would require a sepa rate flow monitor. Commenter 0303 stated that, for flares with FGR systems, the pressure drop across the flare seal drum can be used to calculate flow rate and this
method is a cost effective alternative to continuous flow monitors for these flares. Respon se : 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 certain specific cases, monitoring is not nec essaryDRAFT

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84 and should not be required. However, as a general rule, we believe flow monitors are needed
, not only to provide a verifiable measure of exceedances of the flow RCA threshold, but also
exceedances of the RCA threshold of 500 lb SO 2 in any 24

- hour pe riod. In a ddition, 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 greater than previously projected by the facilities. Consequently, we find great value in t he flow monitoring requirements for flares. These monitoring requirements will greatly 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 w e conduct future reviews of rules applicable to petroleum refineries. We did consider each of the commenters’ suggested exemptions in light of this fact; our specific
considerations follow. We did not specifically consider that some flares would not be cap able 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 monit oring 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 i s 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
base line 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 baseline flow determined for the flare would not expressly include the pilot gas flow rate. If the flare flow monitor is configured in such a way that it does measure pilot gas, then pilot gas would be considered part of the baseline conditions
for that flare. We agree with commenters tha t flares with FGR systems do have unique conditions and these warrant alternative monitoring options. Additionally, we recognize that the monitoring requirements may be burdensome for flares that are truly “emergency only” ( i.e. , flares that flare

gas rare ly, if at all, during a typical year) or for secondary flares in a cascaded flare system. These flares are expected to have a water seal that prevents flare use during normal operationsDRAFT

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85 and ensures that the pressure upstream of the water seal (expressed in inches of water) does not exceed the water seal height during normal operations (hereafter referred to as “properly maintain a water seal”). We find that, for these select types of flares, water seal monitoring as an alternative to the flow (and sulfur) m onitoring provisions is appropriate.
For flares with a FGR system and other emergency 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 water 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 exceeds the water seal liquid level, a RCA is trig gered unless the pressure exceedance is attributable to staging of compressors. This alternative reduces the costs associated with installing sulfur and flow monitoring systems for flares that rarely receive fuel gas. Engineering calculations can be used t o estimate the emissions during the event, but not for determining whether or not a RCA is required. To ensure that this option is only used for flares 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 occur in one year. Following the fifth reportable pressure exceedance in any consecutive 365 days, the owner or operator must comply with the sulfur and flow monitoring requireme nts 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 emergency flare three to four times per year, on average. Consistent with this information, we are providing 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.
C omment : Commenter 0305 expressed concern regarding the flow meter range for

emergency

- only flares and suggested that for existing monitors, the flow range currently being
used shou ld be deemed acceptable, even if it means additional engineering and process information must supplement the readings to estimate emissions. The commenter also suggested that the range for new meters should be determined as appropriate for the specific fla re. Commenter 0311 suggested that the flow meter range requirements should be clarified toDRAFT

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86 accommodate an average flow rate of 500,000 scf d
, and multiple flow meters should not be required to measur e very high or very low flows. Response : Flow meters for f lares are considered continuous parameter monitoring systems (CPMS) and no specific span is specified in the rule. The rule requires that the flow monitor be placed in a position to provide a representative measurement of the total gas flow rate and it spe cifies a minimum sensitivity and calibration requirements. W e 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 low or high flow rates. It is our understanding
that ultras onic flow monitoring systems are typically used for flares 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 meter 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 sulfur 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, the comment should have also provided direct and more substantive comments on the proposed Procedure 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. 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 commenters suggested that 3 to 5 years would be
needed to install a FGR system and/or additional amine treatment needed for compliance. Commenter 0310 further stated that the compliance sc hedule in subpart Ja for installing additional sulfur removal equipment should be consistent 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 fo r 5 years

.DRAFT

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87 Commenter 0311 stated that all flares should be given 3 years from the date of final promulgation and lifting of the stay to comply with the flare standards (regardless of whether new amine or FGR systems are being installed) to allow time for p lanning, re

- piping and other necessary activities, and the EPA should provide an optional additional 2 years for capital installation projects ( e.g. , for permitting, equipment installation). Commenter 0305 stated that any capital project (not just amine tr eatment) required to meet any of the subpart Ja flare
standards (not just the long

- term 60 ppmv H 2 S concentration ) should trigger a compliance deadline of up to 3 years after the effective date of the rule, with an allowance provided for refineries to requ est 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 recommended 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 needed since a number of the flare require ments will require shutdowns. The commenter also stated that since not all flares are currently subject to subpart J, additional time would be needed for all fuel gas combusted in those flares to meet
the short

- term H 2 S concentration requirement of 162 ppm v

. Commenter 0304 stated that the 18

- month compliance 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 equipme nt and crew). Commenter 0310 similarly asserted that 3 years would be needed to install monitors due to design and installation considerations together with the constraints on manufacturers by the sudden demand
for several hundred flow and sulfur monitors. Both commenters cited delays experienced in obtaining monitors to comply with SCAQMD Rule 1118

. Commenter 0295 requested clarification regarding the trigger date from which the additional time to comply with the flare provisions ( e.g. , 2 years when instal ling a FGR system) begins. The commenter asked whether the trigger date is when construction starts, at start up or when the stay is removed (or whichever is later)

. 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 Provisions for compliance timing.DRAFT

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88 Response : As we are no longer applying the long

- term 60 p pmv H 2 S fuel gas concentration limit to flares, the comments related to the amount of time needed 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 quic kly than modifications of traditional process

related emission sources. Therefore, we evaluated the comments regarding the amount of time needed to meet the various requirements for flares while keeping the 40 CFR part 60, subpart Ja flare modification pro vision in mind. We discuss each requirement and the time for demonstrating compliance with that requirement in the following paragraphs. We find it appropriate to require flares to meet the H 2 S concentration upon startup of the affected flare because, as i ndicated by earlier comments, it is likely that most refiners are already operating their fuel gas collection and treatment systems to achieve a short term H 2 S concentration of 162 ppmv. Thus, fuel gas discharged to the flare during normal operations will have already been treated to meet this limit in the existing refinery fuel gas collection and treatment system. We also note that consent decrees typically require immediate compliance with this requirement. Therefore, the final rule requires all refinerie s with new, modified and reconstructed flares to manage the fuel gas sent to these flares such that they meet the short

- term
H 2 S concentration of 162 ppmv upon startup of the affected flare. As we noted in the preamble to the proposed amendments, many of t he connections that would trigger applicability to 40 CFR part 60, subpart 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 refineries will need t ime for planning, designing, purchasing and installing (including any necessary re

- piping) sulfur and flow monitors that are newly required by subpart
Ja. Some refineries will elect to add FGR and/or sulfur treatment equipment to minimize their
emissions a s part of the evaluations conducted as required by the new FMP requirements, and time will be needed for planning, designing, purchasing and installing these components as well. Given that many flares will become modified affected sources relatively quickl y, 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 c omplying with SCAQMD Rule 1118. As such, we find that immediate compliance with some of the requirements for flares, such as the planning, designing, purchasing and installation of (including any necessary re

- piping)DRAFT

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89 sulfur and flow monitors, may be diffic ult for operators to meet, especially in situations where quick connections to the flare are made. A phased compliance schedule allows for the operators to comply with some requirements associated with flares, such as optimizing their fuel gas system to ac hieve a short

- term H 2 S concentration of 162 ppmv immediately, while allowing time to install monitoring equipment to comply with the other elements of the standards. A phased compliance schedule will also allow owners and operators to minimize process
inte rruption by coordinating the installation of monitoring equipment with process shutdowns or turnarounds. In addition to providing operating flexibility to the refinery, we are taking into consideration the fact that a process shutdown and subsequent startu p 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 operators to avoid startups and shutdowns that are not necessary to maintain the equipmen t 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 con sidering the need to coordinate this installation with process unit shutdown or turnarounds, we determined that completion of these activities within 3 years is consistent with the best system of emissions reductions for quickly modified flares. We note, h owever, that this phased compliance schedule for the flare requirements in 40 CFR part 60, subpart Ja is intended for those situations when a flare modification occurs quickly and the owner or operator does not have significant planning opportunities to in stall the required monitors or implement the selected flare minimization options without significant process interruptions. For a future large project on a schedule that includes time for planning, designing, purchasing and installing equipment and monitor s, 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 the modification of a flare, we expect that the owner or operator will then plan how to meet the standards in subpart Ja as part of the project itself, including the installation of the monitoring systems and the development of a FMP . Because of the ability to plan ahead, flares that are modified as part of a large project will no t 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 modified flare is app ropriate and consistent with the best systemDRAFT

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90 of emissions reduction for large projects resulting in a modification of a flare. Thus, we determined that the appropriate time period for compliance with the flare standards is either: (1) 3 years from the prom ulgation date of these amendments or (2) upon startup of the modified flare, whichever is later. 11 In this manner, flares that become subject to subpart Ja quickly
, based on a small safety

- related connection (or have already become subject to subpart Ja bas ed on a
modificati on prior to promulgation of th e amendments) will have up to 3 years fr om the promulgation date of th e amendments to comply fully with the flare standards, but flares that are modified as the result of a significant project, such as the in stallation of a new process unit that will be tied into an existing flare, will effectively be required to comply with the flare standards at the startup of the new process unit. Therefore, for the reasons described above, we are providing flares that beco me affected facilities subject to 40 CFR part 60, subpart Ja through modification with a phased compliance
schedule for the flare standards
, as described in this paragraph. The final rule requires all new,
modified and reconstructed flares to meet the shor t

- term 162 ppmv H 2 S concentration requirement upon startup of the affected flare. Additionally, we are requiring owners and operators of modified flares to complete and implement the FMP under 40 CFR 60.103a(a) by
3 years from the promulgation date or upon startup of the modified flare, whichever is later. We are requiring owners and operators of modified flares to begin conducting root cause and corrective action analyses under 40 CFR 60.103a(c) and (d) no later than 3 years from the promulgation date or t he date of the startup of the modified flare, whichever 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 m odified flares to install and begin operating the monitors necessary to demonstrate compliance with these provisions
, as required under 40 CFR 60.107a(e) through (g) within 3 years from the promulgation date or by the startup date of the modified flare, wh ichever is later, when the monitors are not already in place. C ompliance with the phased compliance schedule constitutes compliance with the flare standard s as of the effective date

.

11 For the purposes of this subpart, startup of the modified 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 a ncillary equipment can flow to the flare via that new connection).DRAFT

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91 

### 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 t he CAA requires continuous compliance with
standards issued under CAA section 111

. See CAA sections 111(a)(1), 302(k). Therefore, the

commenter asserted that it is n ot BSER to allow startup and shutdown events to be exempt from compliance, and these emissions may not be regulated 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 sta ted: “When sections 112 and 302(k) are read together, then, Congress has required that
there must be continuous section 112

- compliant standards.” The commenter noted that the C ourt found that the exemption from compliance with CAA section 112 standards dur ing SSM events

v iolates the CAA because the section 111 general duty to minimize emissions during SSM

events (see 40 CFR 60.11(d)) is not a CAA section 112

- complaint standard

. T he commenter
asserted that the CAA also requires that a section 111

- compliant s tandard 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 “limited instances” in which
CAA section 111(h) authorizes such standards. The commenter stated 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 e mit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or local law, or (B) ...the application 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 commenter stated 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 cann ot set a work practice standard for flares

. Thus , the commenter asserted

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 60.10 3 a(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 all times with the limits in 40 CFR 60.102a(g) (1)

. 13 The commenter assert ed
, without providing support, that it is not BSER to exempt flares from the H 2 S concentration limits during startup and shutdown events. The commenter also state d that the EPA, at a minimum, must demonstrate how the exemption from the H 2 S concentration limit s during SSM events does in fact represent BSER , but the commenter state d that the EPA has failed to make this demonstration

. 14 The commenter cite d the EPA’s rationale for proposing work practice standards for flaring in which we state: “ It is not feasible to prescribe or enforce a standard of performance for these sources because either the pollutionDRAFT

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92 that a CAA section 111

- compliant standard does not continuously apply to flares since both the exemption from the H 2 S concentration limits during SSM events and the flare work practic e standards are not lawful under the CAA

. Commenter 0315 disagreed and provided several reasons why they believe the EPA may lawfully exempt flares from the H 2 S concentration limits during SSM events. First
, the

commenter not ed that 40 CFR part 60, subpart Ja was promulgated as part of the mandatory periodic review of 40 CFR part 60, subpart J required by CAA section 111(b)(1)(B), which states that “the Administrator need not review any such [existing] standard if the Administrator
determines that such revi ew is not appropriate in light of readily available information on the efficacy of such [existing] standard.” The commenter noted that subpart J exempt s a flare from
the H 2 S concentration limits when combusting certain gases generated during SSM events (se e 40 CFR 60.104(a)(1), 60.101(e)) and stated that the record contains “ ample evidence ” to support maintaining that provision in subpart Ja

. The commenter asserted that including th e s e same provision s in subpart Ja is “ an appropriate exercise of the EPA’s a uthority 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 tha t Congress amended CAA section 112 out of 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 standards” without variance “based on
different ti me periods

. ” The commenter further explained that the Court pointed to CAA section 112(d)(1) regarding the EPA’s authority to “distinguish among classes, types, and sizes of sources” when promulgating CAA section 112 standards as further evidence for const raining the EPA’s ability to adopt different standards applicable during SSM events. In contrast, t he

commenter asserted that “ Congress has expressed no such concern about EPA’s efforts to implement section 111 ” of the CAA despite revisions to CAA section 111 in 1977 and 1990. Therefore, the commenter asserted, Congress has “effectively ratified EPA’s longstanding

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 application of a measurement methodology to these sources is not technically and economically practical. ” 72 FR 27178, 27194

- 27195 (May 14, 2007). In response, the commenter states: “[T]he plain language of the Act recognizes th at standards of performance leading to the ‘capture’ of emissions are not infeasible [citation omitted], and EPA has proposed to apply measurement methodologies to flares in spite of the transience of their emissions.”DRAFT

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93 approach to SSM under the NSPS program,” which includes the exemption for flares from the
H 2 S concentration requirements during SSM events.
Comme nter 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 assert ed that the word “continuous” as used in the NSPS program could be interpreted and applied differently
, as acknowledged by the Cou rt in National Lime Ass’n v.
EPA , 627 F.2d 416, 434 (D.C. Cir. 1980) (deferring to a gency regarding the effect of “the perplexing implications of Congress’ new requirement of systems of continuous emission
reduction” on the a gency’s longstanding “regulatio ns permitting flexibility to account for startups, shutdowns, and malfunctions”). The commenter urge d the EPA to exercise this discretion and “reassert the many practical, technical and economic factors” that justify promulgating separate standards for 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 BSER for this time period. According to the commenter, “startup and shutdown gases are intermittent streams that cannot be cost

- effectively treated for sulfur removal because of their infrequent occurrence, their scattered points of generation and their variability.” 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 appropr iate 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 previously, this suite of standards r equire s refineries to : (1) develop and im plement a FMP ; (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 correct ive 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 t oDRAFT

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94 162 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 standards that colle ctively 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 p ractice or operational standard or “combination thereof,” when “it is not feasible to prescribe or en force a standard of performance” which reflects BSER for the particular affected source. Section 111(h)(2) of the CAA defines the phrase “not feasible to prescribe or enforce a standard of performance” as follows:

[A]ny situation in which the Administrator determines that (A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or lo cal law, or (B) the application of measurement methodology to a particular class of sources is not practicable due to technological or economic limitations.
We have determined that flares meet the criteria set forth in CAA section 111(h)(2)(A)
because emis sions from a flare do not occur “ through a conveyance designed and constructed to emit or cap ture such pollutant.” Gases are conveye d 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 out side 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) i s not “ feasible ,” allow ing the EPA to instead promulgate standard s under CAA section 111(h)
, which will collectively limit emissions 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 exiting fuel gas combustion devices oth er 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 inDRAFT

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95 those devices is directly indicative of the SO 2 emitted from the exhau st stacks of those other devices. As explained in s ection III of the preamble to the final amendments , we are , for the first
time
, designating flares as their own affected facility. 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, flares are substantially different from other fuel gas combustion
devic es so that this approach is not workable for flares. For example, SO 2 emissions from a flare are dependent on many factors, including 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 variables. For example, combustion efficiency at the flare is dependent upon the flammability of the gases entering the flare, the turbulence at the
flare
, 15 the wind speed and wind di rection and the presence of other pollutants in the gases that
can react with the sulfur to form sulfur

- 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

c ould 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 amount of sulfur that is sent to a flare will
reduce the SO 2 emissions at the flare. Even with the uncertainty described above, we understand the importance of refineries managing the fuel gas sent 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 requiring 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 rely on various methods for optimizing the management of fuel

gas , including the use of amine treatment and FGR systems. Amine treatment removes the H 2 S
from the fla re gas that generates the pollutants before the gas is sent to the flare. Flare gas recovery systems remove the flare gas altogether and instead treat this gas in a fuel gas treatment system to be used elsewhere as fuel gas in the refinery. Requiring refin eries to meet this concentration limit at the flare ensures that the fuel gas has been adequately treated and managed

15 Turbulence is needed to insure good mixing at the flare, but is affected by whether the flare is assisted with air or steam or non

- assisted.DRAFT

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96 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 during high fuel gas flows. Thus, requiring that flares meet this H 2 S concentration limit during periods when high fuel gas
flows w ould likely overwhelm these FGR systems would not fully address the circumstances refineries face in managing these high flow periods. Designing FGR systems to capture the full range of gas flows to the flare would not only require the ability to predict t he full range of gas flows in the flare headers, but also would require 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, promu lgating flare requirements that include the H 2 S fuel gas concentration limit during normal operating conditions, coupled with requirements for
refineries to develop and im plement a FMP and conduct RCA and take corrective action when waste gas sent to the f lare exceeds a flow rate of 500,000 scf above the baseline or 500 lb of SO 2 in a 24

- hour period , recognizes these unique circumstances while still requiring the refinery to take all reasonable measures for reducing or eliminating the flow and sulfur conten t of gases being sent to the flares.
W e 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 source

specific circumstances differ markedly from t his 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 tha t 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). T hese source

- specific limits were appropriately based on dispersion modeling in the Billings/Laurel area to determine what was needed to meet national ambi ent air quality standards (NAAQS) for SO 2 in the Billings/Laurel area. In contrast, the nationally applicable standards and requirements we are promulgating in this rule must represent the best system of emission
reduction achievable for an entire industry sector scattered across the entire country. This requires that we consider costs and other non

- air quality factors that affect all petroleum refineries nationwide in making that decision and not just as applied to a particular group of sources in a partic ular location.DRAFT

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97 Additionally, those four sources 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). S ince 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 t he Billings/Laurel FIP , to conservatively assume that 100 percent of the sulfur in the gases discharged to the 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 assumpti on is not appropriate when setting national standards for flares. Instead, we must
consider the many factors affect ing 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 conve rts to SO 2 . Therefore,

a lthough setting such source

- specific limits was appropriate to satisfy what the modeling showed was necessary to meet the S O 2 NAAQS in the Billings/Laurel area, a different analysis and
standard is appropriate for a national rule mak ing. Therefore, for the reasons discussed above, the EPA is finalizing this collective set of
CAA section 111(h)

- compliant standards for flares
, based on our interpretation of CAA section 111(h) as it applies to flares. We also note that we will address ot her issues relating to flare
combustion efficiency in the near future, under a comprehensive strategy to address the range of regulated air pollutants

. Comment : Commenter 0299 requested that the EPA provide provisions for fuel gas compressor preventative m aintenance to reduce compressor outages as compared to running the compressor until it fails. Commenter 0311 stated that FGR system outages may occur for safety reasons ( e.g. , if oxygen gets in the flare gas) and requested clarification that proposed
40 CF R 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 systems 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, inclusion of procedures in the FMP to minimize the volume of gas flared during FGR system maintenance is reasonable and we have added this requirement to 40 CFR 60.103a(a) ( 7 ) as requested by the commenter.DRAFT

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98 

## 5 .0 PROCESS HEATERS

5 .1 E mission s Limits

5.1.1 Equivalence of Emission s L imit Units

Comment : Commenters 0296, 0305 and 0311 stated that the limits for the concentration and heating value emission s limits should be the same numerically ; i.e. , the process heat rate
limit numerically equivalent to the 40 ppmv concentration limit i s 0.04 lb/MMBtu and the process heat rate limit numerically equivalent to the 60 ppmv concentration limit is 0.06
lb/MMBtu. Response : In August 2008, Industry Petitioners to the final rule provided the EPA with suggestions for revising the process heater s tandards (Docket Item No. EPA

- HQ

- OAR

- 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 suggested
that
, on an annual basis, most n atural draft process heaters could meet 0.035 lb/MMBtu and all other process heaters could meet 0.055 lb/MMBtu

. We evaluated these suggested emissions limits and determined that they were reasonably equivalent to the concentration

- based limits we

were prop osing

. We also requested comment on their use and their equivalency
, as described in the preamble to the proposed amendments (see 73 FR 78527). Industry commenters now assert that the emissions limit numerically equivalent to the
40 ppmv concentration limi t 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 preamble to the proposed amendments, the exact conversion from ppmv to lb/MMBtu depends on the hydrog en content of the fuel gas

. However, our calculations g enerally support the more direct numerical conversion suggested by commenters over the typical range of hydrogen concentrations expected in the fuel gas ( see Revised NO X Impac t Estimates for Process He aters , in Docket ID No. EPA

- HQ

- OAR

- 2007

- 0011)

. Therefore, we are finalizing heating value

- based emissions limits of 0.040 lb/MMBtu and 0.060 lb/MMBtu for natural draft process heaters andDRAFT

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99 forced draft process heaters, respectively, based on direct numerica l conversions from the
concentration

- based emissions limits. We are also clarifying that the owner or operator must demonstrate that the process heater is in compliance with either the applicable concentration

- based or heating value

- based NO X limit

. Specif ically, 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, dry 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 compliance with either one of these limits

. For most fuel gas systems, the alternative emissions limits are expected to be identical; 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 combusting 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 c oncentration limit being determined on a dry basis (and understanding that the combustion of hydrogen produces only water and not carbon dioxide)

. Provided that the appropriate monitoring is conducted, an affected source would only be out of compliance if it
exceeds both the concentration

- based limit and the 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 owner or operator must, at least da ily, determine the F factor (dry basis) for the fuel gas according to the monitoring provisions in 40 CFR 60.107a(d)

. If the F factor is not determined at least daily, the heating value

- based alternative cannot be used.



### 5.1.2 Limits for New, Modified and R econstructed Forced Draft Process Heaters

Comment : Commenters 0296 , 0311 and 0314 suggested that newly constructed forced
draft process heaters should have the same 60 ppmv emission s limit as modified and
reconstructed forced draft process heaters. Comment er 0296 stated that the emission s limit for newly constructed forced draft process heaters was based on only two data points and that it do es not fully consider the operating range of newly constructed units. The commenter included a
John Zin k white paper and assert ed that this white paper shows that newly constructed forced draft process heaters (particularly those that use air preheat) cannot meet the 40 ppmv NO X emission s limit. Commenter 0314 agreed, noting that they designed a new forced draft process heater with air preheat to meet 50 ppmv NO X , and the “heater vendor and burner supplier haveDRAFT

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100 determined that they cannot get appreciably lower emissions than the current design achieves.”
The commenter noted that since burner modifications alone will not b e 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 return to the proposed limit of 80 ppmv NO X . Similarly, Commenter 0297 supported higher emission s 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 allowin g for a comfortable margin to ensure compliance is extremely difficult, if not impossible, without the use of add

- on controls.” The commenter also suggested that the mass emissions of NO X from units with air preheat would not be higher than
units without a ir preheat due to the reduced flue gas flow rate and recommended the 60 ppmv
NO X limit be extended to new forced draft process heaters equipped with combustion air preheat. Response : The commenters provided only limited and theoretical data to support thei r argument that new forced draft process heaters cannot meet the 40 ppmv (or 0.040 lb/MMBtu)
NO X emissions limit

. Specifically, the John Zink white paper cited by the C ommenter 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 “guaranteed” for a new forced draft process heater
, based on the design conditions, which 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 actual performance of these forced draft process heaters is still in question

. However, we acknowledge that we only have data for one new forced draft process heater w ithout air preheat that is currently operating that could meet a 40 ppmv
NO X emissions limit on a 365

- day average

. We conducted additional data evaluations to determine appropriate limits and averaging times for all process heaters at normal operating
cond itions while considering this and other public comments we received

. As part of the data analysis effort, we obtained a year’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 ave rage

. As discussed later in this section, 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 draft process heater without air preheat capable ofDRAFT

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101 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 concurrentl y 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 period)

. Furthermore, based on the 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 rolling average basis adequately accommodates forced draft process heaters that use air preheat

. Based on our review of CEMS data for new and retrofitted forced draft process heaters, we conclude that 60 ppmv (or 0.060 lb/MMBtu) on a 30

- day r olling average basis is BSER for new, reconstructed or modified forced draft process
heaters

. (For addi tional details, see Revised NO X Impact Estimates for Process Heaters in Docket
ID No. EPA

- HQ

- OAR

- 2007

- 0011.)



### 5.1.3 Turndown

Comment : Several commenters a ddressed the need for the rule to address turndown, which is a period of time when process heaters are firing below capacity

. Commenter 0296 stated that turndown conditions can extend over a full year, so special provisions are needed for these
turndown co nditions. Commenters 0296 and 0305 suggested 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 “t urndown operations,” which the commenter suggested be defined as operating at 50 percent of the rated capacity or less. Commenter 0311 requested that the proposed emission s limits only apply to furnaces that are firing at or above 50 percent of design rate s. Days when firing rates are below 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 emission s limit at design capacity, according to the commenter. Als o, 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 s ystems [ CEMS ] ) are firing at less than 50 percent of design rates. Commenter 0315DRAFT

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102 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 emission s limit should be calculated as the allowed emission factor for that heater multiplied by the 70

- percent firing rate. Response : In our proposed amendments, we provided a longer averaging time (365

- day average) so that short periods of turn

- down 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

. Therefore, we re

- evaluated the available data, including our existing data and additional data provided by the industry, to determine the appropriate emissions limits during different types of operation, including turndown

. The additional data provided by Industry 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 concluded 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 ppm v were not achievable for all process heaters using a 24

- hour averaging period (the averaging period included in the final June 2008 rule)

. From the available data, short

term fluctuations in the NO X concentrations of process heaters using ultra

- low NO X bu rners 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 at relatively 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 exhau st O 2 concentrations for these units during normal ( i.e. , non

- turndown) firing rates

. That is, these process heaters were not being operated optimally for reducing NO X emissions

. Furthermore, when these process heaters were operated at the lower range of e xhaust concentrations for the unit (although 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 emissions limit on a 30

- day averaging perio d

. Based on our review of CEMS data for process heaters with ultra

- low NO X burners that operated at excessDRAFT

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103 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 co mply with the final NO X emissions limits on
a 30

- day average basis

. Consequently, 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 3 0

- day averaging period is achievable for process heaters during periods of normal operation

. Our next step was to evaluate the achievability of the emissions limits during turndown conditions and alternative approaches for establishing emissions limitation s where

necessary

. The following paragraphs describe our analysis of the data, including our evaluation of alternative methods for accommodating turndown conditions and our rationale for providing
the site

- specific alternative for extended turndown conditi ons. There were very limited CEMS data available 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 that 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 a t higher O 2 concentrations during low firing rates to maintain flame stability, suggest that an alternative NO X emissions limit could, in some instances, be needed to address extended turndown conditions (turndown events lasting a majority of the 30

- day av eraging time)

. As such, we considered alternative compliance options
to address turndown conditions. One alternative compliance option considered to address turndown was a mass

- based
NO X emissions limit that would be equivalent to the mass of NO X emitted f rom 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

based emissions limit did not improve the ability of the process heater to meet the emissions
limit

. We note that most of the process heaters were able to meet the applicable concentration

based emissions limit (40/60 ppmv) or the heating value

- based (0.040/0.060 lb/MMBtu) emissions limit during turndown

. Th erefore, the issue appears to be limited to a few of the process heaters that must operate at relatively high excess O 2 concentrations during turndownDRAFT

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104 conditions

. For these units, the alternative 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 saf e operation of the process heater; however, based 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 process h eater 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 constraints to maintain flame stability

. We do not have specific data on process heaters tha t are near , but below
, the concentration emissions limits when firing above 50

- percent capacity, but cannot meet the concentration limit when firing below
50

- percent capacity, so we have no data that show that process heaters operating at less than
50

- perc ent 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 stab ility generally support the commenter’s argument that a few marginally compliant process heaters will have difficulty meeting the basic emissions limit when the unit is turned down

. As such, we acknowledge that there may be periods of turndown in which a p rocess heater is operating as
recommended
, but may be unable to meet the concentration 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 t he 30

- day averaging time)

. As the need for an alternative limit appears to be l imited to a few process heaters and the optimal O 2 concentration is expected to vary , based on fuel gas composition, we determined that a site

- specific emissions limit was the
b est approach to account for these extended turndown conditions

. As such, the final rule provides owners and operators that have a process heater operating in turndown for an extended period of time the option of developing a site

- specific emissions limit t hat would apply to those operating
conditions and requesting approval from the 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 al so 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 potentialDRAFT

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105 turndown compliance issues with the O 2 oper ating 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 mu st be determined when the process heater is being fired at 70 percent or more of capacity ( i.e. , far from turndown conditions)

. For process heaters that routinely operate at less than 50 percent of design capacity and require additional O 2 to maintain flam e stability, a separate O 2 operating limit should be established 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 lim its for additional operating

ranges.



### 5.1.4 Site

- Specific Emission s Limit Clarifications

Comment : Commenters 0302, 0305, 0308 and 0311 supported the provision in
40 CFR 60.102a(i) for a site

- specific NO X emission s limit for process heaters that cannot be

re trofit with ultra

- low NO X burners. Commenters 0308 and 0311 suggested expanding the applicability of the paragraph to include process heaters for which it may be physically possible
to install ultra

- low NO X burners , but other “ structural or operability rea sons ” would prevent the process heater s from operating properly. Commenter 0308 also noted that island refineries that have difficulty obtaining natural gas may have fuel gas with higher levels of olefins and propane, which contribute to higher NO X emissio ns. The commenter suggested allowing process heaters
that canno t meet the NO X limits for “ fuel gas quality reasons” to apply for a site

- specific
emission s limit. Commenter 0311 stated that the provisions should also apply to new forced draft process heater s , especially those using air preheat, that might have trouble meeting a 40 ppmv limit. Commenter 0311 also stated that the General Provisions provides 180 days to achieve full process rates, test the unit and submit the results, and this timeframe, rather than the 90

- day time frame proposed, is needed to file the petition. Finally, Commenter 0311 stated that the rule should specify that the petition’s limit applies to the process heater until the petition is acted upon since the petition is being submitted because the facility cannot meet the emissions limit.DRAFT

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106 Response : We appreciate the commenters ’ support of the option to petition for a site

specific emission s limit. We have clarified the site

- specific emission s limit provisions under
40 CFR 60.102a(i) to address most of the commenters’ concerns as described in this response.
R egarding process heaters that cannot properly operate ultra

- low NO X burners
, the preamble to the proposed rule notes that owners and operator s may seek EPA approval for a site

specifi c limit for “modified or reconstructed natural draft and forced draft process heaters that have limited firebox size or other limitations and therefore cannot apply the [BSER] of ultra

- low
NO X burners.” O ur intention was to accommodate process heaters that cannot install and properly operate combustion modification

- based technology due to structural limitations of the process heater ( e.g. , size of the heater box, flame impingement on tubes containing process fluids, spacing of the individual burners)

. In ot her words, if ultra

- low NO X burners c an 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 recommended by the manufacturer, then we consider there to be physical lim itations preventing the use of combustion modification

- based technology. We agree that the proposed language in 40 CFR 60.102a(i) could be interpreted more narrowly
than intended , so we revised the language in 40 CFR 60.102a(i)(1)(i) to specify that “a mod ified or reconstructed process heater that lacks sufficient space to accommodate installation and proper operation of combustion modification

- based technology ( e.g. , ultra

- low NO X burners) ” may submit a petition for a site

- specific limit.
T his provision , w hile considering “proper operation,” was specifically 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 operat ional flexibil ity for the burners. Further, w e 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 temper atures, maximum preheat temperatures, maximum excess oxygen content and flexibility in burner design to allow both natural draft or forced draft operation. We recognize that, for existing process heaters, some of these parameters are fixed, but the questio n is: should the design and operation of the process heater be cognizant and reflective of the NO X emission s limits? In developing our BSER analysis, we included limiting the amount o f excess oxygen employed and included costs for excess oxygen measurement and control. We do not expect that process heaters that are subjectDRAFT

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107 to subpart Ja will operate exactly like process heaters that are not subject to subpart Ja, just with different burner designs. For example, in reviewing NO X emissions data, we found that several process heaters were operating with excess oxygen concentrations of 6 to 8 percent while firing at or near capacity

. Discussions with technology vendors, however, suggest that “proper operation” of a low

- NO X burner firing at or near burner capacit y 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 owner or operator of an affected process heater to control, to the extent poss ible, these various parameters so as to minimize NO X emissions and to comply with the NO X emission s limits. Thus, w hile we recognize that certain
low

- NO X burner retrofits may be infeasible due to structural limitations , we do not want to open
the door for refinery owners and operators to disregard the emission s limits when operating
modified process heaters or when designing new process heaters and then contend that the
emission s limits in 40 CFR 60.102a (g)(2) are not achievable for “ operability ” reasons. T herefore, we reject the request to expand the scope of the site

- specific emission s limit eligibility
to include “ operability ” issues per se unconstrained by the “ proper operation ” of low

- NO X burners

. Similarly, we reject the request to expand the scope of the site

- specific emission s limit eligibility to include fuel gas quality constraints. Based on our analysis of the available data, the
final NO X emission s limits are achievable over a wide range of refinery fuel gas compositions

. Furthermore, w e have adde d 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 fin al 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 emission s limit

. As noted in the preamble to the final amendments , we have revised the NO X emission limit for new 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

- l ow NO X burner performance guarantees, we conclude that all new forced draft process heaters can meet an emission s limit of 60 ppmv NO X on a 30

- day rollingDRAFT

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108 average basis ; therefore, site

- specific emissions limits are not warranted for new forced draft

proce ss heaters

. Regarding the specifics of submitting the petition, we agree with the commenter that it is appropriate to allow an owner or operator up to 1 80 days after startup to submit a petition for a
site

- specific limit. As the commenter noted, 180 days i s consistent with the General Provisions, and it is also consistent with similar performance level determinations for boilers ( 40 CFR 60.44b(f) ). We also agree with the commenter that clarification i s needed regarding compliance during the time between sub mittal 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 submitted petition until the petition is approved by the
Administrat or.



### 5.1.5 Co

- Fired Process Heaters

Comment : Commenter 0308 requested clarification regarding the parenthetical qualifier “(applicable only when the process heater is being co

- fired)” in proposed
40 CFR 60.102a(g)(2)(iv)(A)

. The commenter stated 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 pr oposed 40 CFR 60.102a(g)(2)(i)

- (iii) are
unachievable for co

- fired process heaters, and clarifying language is needed to ensure that these
limits are not enforced for co

- fired process heaters when only gaseous fuels are used

. If the parenthetical was inten ded to exclude only those times when 100

- percent fuel oil is being burned, then the parenthetical should be clarified as follows: “(applicable only when the process heater is being fired in whole or in part with fuel gas).” Commenter 0311 likewise suggeste d that
the EPA clarify that process heaters 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.
Commenters 0308 and 0311 r equested that the introductory text in proposed
40 CFR 60.102a(g)(2)(iv) be clarified to clearly state that a co

- fired process heater must “comply
with either” proposed 40 CFR 60.102a(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).DRAFT

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109 Response : We agree that the language concerning co

- fired process heaters is ambiguous, and we have revised this language to clarify the requirements. The final rule provides two

s ubcategories of co

- fired process heaters : natural draft and forced draft. Each subcategory includes two options for emission s limits, one on a concentration basis and the other on a mass
basis. The mass

- based emission s limit considers the daily average amo unts of gas and fuel oil fired by the heater, but the language no longer includes a qualifier addressing the type of fuel that must be fired for the limits to apply. In other words, the applicability of the emission s limits is based on the design of the pr ocess heaters and not on the type of fuel being 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 burners to meet the definition of co

- fired process heaters. These units must demonstrate compliance with the NO X emissions limits when the y 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 comply with either the he ating value

- based or the
concentration

- based emission s limit, but the owner or operator must comply with the selected
limit at all times. That is, the owner or operator cannot switch back and forth between compliance methods depending on the fuel burned.
W e also note that the final rule does not address process heaters designed to fire only fuel
oil

. Because we did not propose requirements specific 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 process heaters in a future rulemaking.
Comment : Commenter 0308 stated that the emission s limits in proposed
40 CFR 60.102a(g)(2)(iv)(A) and (B) are not achievable “...for the conditions that exis t at HOVENSA...” and submitted a white paper to support higher emission s limits, which the commenter recommended be adopted
, especially in light of a daily averaging period. Alternatively, the commenter suggested the EPA defer the promulgation of NO X limits for co

fired process heaters due to the lack of adequate data to “adequately demonstrate” an achievable
emissions limit under s ection 111 of the CAA. Commenter 0311 stated that the 0.27 lb/MMBtu limit is not achievable when firing residual fuel oil.
Commen ters 0308 and 0311 recommended that the emission s 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 respect to turndown and variability as other processDRAFT

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110 heat ers

. Commenter 0311 also stated that the notation “E NOx,hour ” in proposed Equation 3 was confusing and that the “hour” subscript should 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 asserted that differences in the configuration and operation of different types of process heaters warranted different emissions limits

. The proposed amendments introduced two specific emissions limits 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 that
, for purposes of this rule, a co

- fired process heater is defined as a process heater tha t employs burners that are designed to be supplied by both gaseous and liquid fuels

. In other words, co

- fired process heaters are designed to routinely fire both oil and gas in the same burner

. These do not include burners that are designed to burn

gas , bu t 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 limit of 0.06 lb/MMBtu for the gas portion of the firing and 0.35 lb/MMBtu for the oil portion o f the firing is achievable

. Similarly, 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 p ortion of the firing is achievable

. As noted above, these values are based on burner performance tests, which are considered a better source of information than the vendor guarantees that were relied upon to develop the proposed emissions limit

. Therefore, we are revising the NO X emissions
limits for co

- fired process heaters 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)

. W e have also revised the nomenclature of the daily average emissions

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 i n handling this data. The data has been placed in the docket, but is not publicly available.DRAFT

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111 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 perform ance tests were conducted in a controlled
environment at the burner manufacturer’s full

- scale facilities

. While it is incumbent on the owner or operator of an affected process heater to control certain operating parameters, such as excess
O 2 concentrations , to the extent possible, we recognize that the performance limits in the final amendments are based on limited data, none of which are direct test data for a co

- fired process heater operated at a petroleum refinery

. We conclude that the low

- NO X burner tec hnologies exist, are demonstrated and are cost 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 reasonab le to provide an alternative, site

- specific limit in the event that factors outside the influence 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

. Consequently, co

- fired process heaters that cannot meet the limits specified above can request approval for a site

- specific 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 part 60, but not identical. The commenters requested an exemption from the 40 CFR p art 60 monitoring and QA requi rements for any process heater or boiler subject to and complying with 40 CFR p art 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 prov ide 40 CFR part 75 monitoring and QA provisions to be compliant with 40 CFR part 60, s ubpart Ja. Response : We reviewed the QA/QC requirements in 40 CFR part 75. It appears that the 40 CFR p art 75 NO X emissions limits ( provided predominantly for coal

- fired units) are much higher than those provided in these final amendments (which are predominantly for gas

- fired process heaters). The a ccuracy requirement for the RATA on NO X is ±0.015 or 0.020 lb/MMBtu, depending on the RATA frequency. We find that these accu racies are not appropriate given the
NO X emission s limits that are in the final rule. Consequently, we do not consider the 40 CFRDRAFT

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112 p art 75 QA/QC requirements sufficient for compliance with the final rule and we are not amending the rule to allow 40 CFR part 75 monitoring and QA provisions

. Comment : Commenter 0311 asserted that daily determination 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 th e heating value does not vary that much. The commenter requested that the EPA allow the 40 CFR part 75 sampling protocols ( Sections 2.2.3 and 2.2.4.1 through 2.2.4.3 of Appendix D ) instead of daily 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 sections in 40 CFR part 75. While we do not understand the reference to Section 2.2.3, which seems to indicate daily sampli ng, we recognize that heating value of fuel oil fed from a common storage tank is not expected to vary unless additional shipments are received. As many of the alternatives in the cited sections are sulfur

centric, we have provided similar alternatives in 40 CFR 60. 107a(d)(7)(viii) to reduce the burden associated with daily sampling when daily sampling will not improve the ac curacy of the

measurements. Comment : Commenter 0307 stated that the EPA should require CEMS for all process
heaters to demonstrate com pliance with the NO X emission s limit. The proposed amendments allow the option of biennial source testing for certain process heaters with low

- NO X or ultra

- low
NO X burners; however, commenters assert that biennial source testing is not sufficient for

ensur ing that these process heaters are meeting their NO X emission s 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 S ierra Club
v. USEPA , 17 the D.C. Circuit held that the EPA and state permitting agencies must include additional monitoring requirements in Title V permits if the existing requirements are insufficient to ensure compliance with an emission s limit. The commen ter stated that biennial source testing for process heaters is not sufficient to demonstrate compliance; instead, the

commenter assert ed that CEMS are needed for demonstrating that all process heaters are in continuous compliance with the NO X emission s lim it. The commenter also noted that if the EPA

17 536 F.3d 673 (D.C. Cir. 2008)

.DRAFT

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113 relies on CEMS data provided by industry to weaken the NO X emission s limits, then the EPA should at least require CEMS to ensure industry is complying with that weaker limit.
Commenter 0315 countered that subpar t 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 biennial source testing is insufficient for small process heaters, and
the EPA has d iscretion in determining what monitoring is adequate. Commenter 0315 noted that
the EPA originally proposed CEMS on all process heaters, but based on public comments received through the subpart Ja rulemaking process, the EPA revised the evaluation and
det ermined that CEMS were not justified for small process heaters (see Docket Item No. EPA

HQ

- 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 determination was reasonable and consis tent with the a gency’s longstanding approach for 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 betwe en 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 compliance with their applicable emissions limits. The
final rule requires that owners or operators install 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 process heaters

— those with rated heat capacities of less than 100 MMBtu/hr

— may instead conduct biennial 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 o nly smaller process heaters (those with rated heat capacities of less than 100 MMBtu/hr) may choose the option of biennial tests. This provision was included after considering available data on these small process heaters as well as the cost of applying a CEMS for these smaller process heaters. For the available data summarized in the process heater memo randum , only one of 29 process heaters with data
obtained via CEMS has less than 100 MMBtu/hr capacity. For the data from small process
heaters summarized i n the process heater memorandum , 9 of 10 data points are a result of one

time source tests

. Regarding the monitoring costs for small process heaters, we reviewed the estimated costs supporting the process heater impacts memorandum ( see the third attachment toDRAFT

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114 Docket Item No. EPA

- HQ

- OAR

- 2007

- 0011

- 0222). The 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. T he cost effectiveness of ultra

- low NO X burner retrofits
for a 200 MMBtu/hr process heate r 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 contrast, 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 , 6 00 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 prov ided specifically for units that use low

- NO X or ultra

- low NO X burner technologies because the performance of these control systems is generally quite stable. As noted previously, one important variable that affects the performance of these
burners is the l evel of excess oxygen supplied. To verify continuous performance that is indicative of the conditions present during the biennial source tests, the owner or operator must establish a maximum excess oxygen operating limit or operating curve during the perfo rmance test and monitor the oxygen content 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 emiss ion s

. We are adding that requirement in these
final amendments at 40 CFR 60.107a(h)(5) ; the effect of this amendment is that the owner or operator of a small process heater that elects to use biennial testing for compliance must report any daily average ox ygen concentration that exceeds the maximum excess oxygen operating limit or operating curve as an exceedance of the NO X emission s limit, just as an owner or operator electing to comply using a CEMS must report any 30

- day period during which the

average co ncentration of NO X exceeds the applicable emission s limit. Thus , considering all of the above, the monitoring requirements for process heaters

— both large and small

— are appropriate and sufficient for an owner or operator to demonstrate continuous compliance with the applicable NO X emissions limits.DRAFT

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115 

### 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, such as SCR, are not required. Response : We agree that the language in 40 CFR 60.102a(i)(2), a s worded, could be interpreted to mean that the petitioner would have to evaluate SCR technology and provide evidence as to why the emissions limit could not be 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 o r operator “ demonstrate that ultra

- low NO X burners, flue gas recirculation, control of
excess air or other combustion modification

- based technology (including combination s of these
combustion modification

- based technologies) cannot be used to meet the appl icable emission s limit

. ”DRAFT

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116 

## 6 .0 COMPLIANCE REQUIREME NTS AND GENERAL MONITORING , RECORDKEEPING 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 exc eeds 300 ppmv H 2 S, 300 ppmv should be used in calculating the average for that time period
, regar dless of the monitor ’ s reading. Response : We do not agree that it is the EPA’s policy , at least within 40 CFR p art 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 control ” and declare their compliance
status as other th an continuous. Additionally, for the purposes of calculating rolling averages, the direct monitor reading should be used for all periods that the CMS is operational, ex c e p t for periods when the CMS data are invalidated according to 40 CFR 60.13((h)(2)(iv). The CMS must be operation al for all periods except for system breakdowns, repairs, calibration checks and zero and span adjustments as specified in 40 CFR 60.13( e )

. Comment : Commenter 0311 requested clarification on how the “365 successive calendar day ro lling 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 calculated when: a) the unit is not operating; b) when the monitor is unavailable (or “out of control” according to Appendix F); and c) turndown occurs (if a separate emission s limit does not apply 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 inc luded and hav ing a different and changing number of calendar days in the 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 “ determined daily on a 365 successive calendar dayDRAFT

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117 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 3 65 calendar days

. Similarly, it is our intention that each 30

- day average
would be based on 30 calendar day s , regardless of whether the process heater is operating at full capacity or in turndown

. Only the hours that the fuel gas combustion device is operating should
be use d when calculating the daily average for a given calendar day. If the fuel gas combustion
device did not operate at all during 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 operating for 10 days during this 30

- day period. Similarly, CMS “ out of control ” periods would be considered null values for the

purposes o f calculating the 30

- day or 365

- day average. 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) conflicts with guidance provided by EPA Region 3 on April 14, 2000. If the April 2000 guidance is the preferred methodology, then
the EPA should delete the note and 3

- hour standards should be expressed as 180

- minute

averages. Response : First, we note t hat the guidance provided by EPA Region 3 is based on the language as it was in subpart J prior to amendments , where no additional guidance in the rule was provided on how to calculate the 12

- hour averages. As such, Region 3’s interpretation is justified b ased on the language used in s ubpart J

. However, r equiring 12

- hour averages to be
calculated every minute greatly increases the computational and data storage requirements for the refinery with little to no environmental benefit. It is extremely unlikely t hat a 12

- hour average excursion will be “seen” when evaluating “ by minute ” 12

- hour averages 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 sto re these “by minute” data for 12 hours, increasing the storage needs by an order of magnitude. W e note that the sections describing excess emissions ( e.g. , 40 CFR 60.106a(b), 40 CFR 60.107a(h)) already specif y that the 3

- hour
or 12

- hour periods are to be d etermined by first calculating hourly averages and then taking theDRAFT

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118 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 : Co mmenter 0311 stated that the reference 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)(v ii i ) 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 rath er than per event. Response : First
, 40 CFR 60.108a(c)(6) includes recordkeeping requirements and should not be confused with reporting requirements. Section 60.108a(c)(6) requires refinery owner s and operators to keep records of all the RCA info, but it do es n o t specifically require submi ssion of reports. We also note that 40 CFR 60.103a( d ) and (e) use the term “record” or “record and explain

. ” While the latter suggest s reporting, neither of these specifically require s submission of
the record. The actual r eporting requirements are summarized in 40 CFR 60.108a(d) , which requires refinery owner s 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 the report

. Section 60.7(c ) requires excess emission reports to be submitted semi

- annually: “Each owner or operator required to install a continuous monitoring device shall submit excess emissions and monitoring systems performance report (excess emissions are defined in applicable subparts )...to the
Administrator semiannually....All reports shall be postmarked by the 30th day following the end
of each six

- month period .” Therefore, while the 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, especiallyDRAFT

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119 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 MMBtu/hr thresholds that require monitoring. The alternative monitoring for process heaters 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 refinerie s. W e were unable to identif y reasonable
alternative s to direct monitoring for flares, given the expected 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 t he refinery.