Document ID: EPA-HQ-OAR-2007-0011-0271
Agency: epa
Document Type: Proposed Rule
Title: Standards of Performance for Petroleum Refineries; Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007; Proposed Rule
Posted Date: 2008-12-22T05:00Z

[Federal Register: December 22, 2008 (Volume 73, Number 246)]
[Proposed Rules]
[Page 78521-78544]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr22de08-32]

[[Page 78521]]

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Part IV

Environmental Protection Agency

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40 CFR Part 60

Standards of Performance for Petroleum Refineries; Standards of
Performance for Petroleum Refineries for Which Construction,
Reconstruction, or Modification Commenced After May 14, 2007; Proposed
Rule

[[Page 78522]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2007-0011; FRL-8753-5]
RIN 2060-AN72

Standards of Performance for Petroleum Refineries; Standards of
Performance for Petroleum Refineries for Which Construction,
Reconstruction, or Modification Commenced After May 14, 2007

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: On June 24, 2008, EPA promulgated amendments to the Standards
of Performance for Petroleum Refineries and new standards for process
units constructed, reconstructed, or modified after May 14, 2007. EPA
received three petitions for reconsideration of the final rule. On
September 26, 2008, EPA granted reconsideration and issued a stay for
the issues raised in the petitions regarding process heaters and
flares. In this action, EPA is addressing those specific issues by
proposing amendments to certain provisions for process heaters and
flares. EPA is also proposing various technical corrections in this
action that were raised in the petitions for reconsideration. EPA will
take action on other issues raised by Petitioners in future notices.

DATES: Comments must be received on or before February 5, 2009.
    Public Hearing. If anyone contacts EPA requesting to speak at a
public hearing by January 2, 2009 public hearing will be held on
January 6, 2009.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2007-0011, by one of the following methods:
     www.regulations.gov: Follow the on-line instructions for
submitting comments.
     E-mail: a-and-r-Docket@epa.gov, Attention Docket ID No.
EPA-HQ-OAR-2007-0011.
     Fax: (202) 566-9744, Attention Docket ID No. EPA-HQ-OAR-
2007-0011.
     Mail: Air and Radiation Docket and Information Center,
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, Attention Docket ID No. EPA-HQ-OAR-
2007-0011. Please include a total of two copies.
     Hand Delivery or Courier: EPA Docket Center (2822T), 1301
Constitution Avenue, NW., Room 3334, Washington, DC 20004, Attention
Docket ID No. EPA-HQ-OAR-2007-0011. Such deliveries are only accepted
during the Docket's normal hours of operation, and special arrangements
should be made for deliveries of boxed information. Please include a
total of two copies.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2007-0011. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be confidential
business information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through www.regulations.gov or e-mail.
The www.regulations.gov Web site is an ``anonymous access'' system,
which means EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an e-
mail comment directly to EPA without going through www.regulations.gov,
your e-mail address will be automatically captured and included as part
of the comment that is placed in the public docket and made available
on the Internet. If you submit an electronic comment, EPA recommends
that you include your name and other contact information in the body of
your comment and with any disk or CD-ROM you submit. If EPA cannot read
your comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses.
    Docket: All documents in the docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the EPA Docket Center,
Standards of Performance for Petroleum Refineries Docket, EPA West
Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the Docket
Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Robert B. Lucas, Office of Air
Quality Planning and Standards, Sector Policies and Programs Division,
Coatings and Chemicals Group (E143-01), Environmental Protection
Agency, Research Triangle Park, NC 27711, telephone number: (919) 541-
0884; fax number: (919) 541-0246; e-mail address: lucas.bob@epa.gov.

SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?

    Categories and entities potentially regulated by this proposed rule
include:

----------------------------------------------------------------------------------------------------------------
                  Category                     NAICS code \1\            Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Industry....................................             32411  Petroleum refiners.
Federal government..........................  ................  Not affected.
State/local/tribal government...............  ................  Not affected.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. To determine whether your facility would be regulated by this
action, you should examine the applicability criteria in 40 CFR 60.100
and 40 CFR 60.100a. If you have any questions regarding the
applicability of this proposed action to a particular entity, contact
the person listed in the preceding FOR FURTHER INFORMATION CONTACT
section.

[[Page 78523]]

B. What should I consider as I prepare my comments to EPA?

    Do not submit information containing CBI to EPA through
www.regulations.gov or e-mail. Send or deliver information identified
as CBI only to the following address: Roberto Morales, OAQPS Document
Control Officer (C404-02), Office of Air Quality Planning and
Standards, Environmental Protection Agency, Research Triangle Park, NC
27711, Attention Docket ID No. EPA-HQ-OAR-2007-0011. Clearly mark the
part or all of the information that you claim to be CBI. For CBI
information in a disk or CD-ROM that you mail to EPA, mark the outside
of the disk or CD-ROM as CBI and then identify electronically within
the disk or CD-ROM the specific information that is claimed as CBI. In
addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.

C. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of
this proposed action is available on the Worldwide Web (WWW) through
the Technology Transfer Network (TTN). Following signature, a copy of
this proposed action will be posted on the TTN's policy and guidance
page for newly proposed or promulgated rules at http://www.epa.gov/ttn/
oarpg. The TTN provides information and technology exchange in various
areas of air pollution control.

D. When would a public hearing occur?

    If anyone contacts EPA requesting to speak at a public hearing by
January 2, 2009, a public hearing will be held on January 6, 2009.
Persons interested in presenting oral testimony or inquiring as to
whether a public hearing is to be held should contact Mr. Bob Lucas,
listed in the FOR FURTHER INFORMATION CONTACT section, at least 2 days
in advance of the hearing. If a public hearing is held, it will be held
at 10 a.m. at the EPA's Environmental Research Center Auditorium,
Research Triangle Park, NC, or an alternate site nearby.

E. How is this document organized?

    The supplementary information presented in this preamble is
organized as follows:

I. General Information
    A. Does this action apply to me?
    B. What should I consider as I prepare my comments to EPA?
    C. Where can I get a copy of this document?
    D. When would a public hearing occur?
    E. How is this document organized?
II. Background Information
    A. Why are we proposing these amendments?
    B. What is the statutory authority for the proposed amendments?
    C. What are the current petroleum refinery NSPS that are
proposed to be amended?
III. Summary of the Proposed Amendments
    A. What are the proposed amendments to the existing standards
for petroleum refineries in 40 CFR part 60, subpart J?
    B. What are the proposed amendments to the new requirements for
affected process heaters in 40 CFR part 60, subpart Ja?
    C. What are the proposed amendments to the requirements for
affected flares in 40 CFR part 60, subpart Ja?
    D. What are the proposed amendments to the definitions in 40 CFR
part 60, subpart Ja?
IV. Rationale for the Proposed Amendments
    A. What is the rationale for the proposed amendments for
affected process heaters?
    B. What is the rationale for the proposed amendments for
affected flares?
    C. What miscellaneous corrections are being proposed?
V. Summary of Cost, Environmental, Energy, and Economic Impacts
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

II. Background Information

A. Why are we proposing these amendments?

    Standards of performance for petroleum refineries were promulgated
on June 24, 2008 that included: (1) Final amendments to the existing
petroleum refineries new source performance standards (NSPS) in 40 CFR
part 60, subpart J; and (2) a new petroleum refineries NSPS in 40 CFR
part 60, subpart Ja (73 FR 35838). On June 13, 2008, the American
Petroleum Institute (API), the National Petrochemical and Refiners
Association (NPRA), and the Western States Petroleum Association (WSPA)
(collectively referred to as ``Industry Petitioners'') requested an
administrative stay under Clean Air Act (CAA) section 307(d)(7)(B) of
certain provisions of 40 CFR part 60, subpart Ja (Docket Item EPA-HQ-
OAR-2007-0011-245). On July 25, 2008, the Industry Petitioners sought
reconsideration of the provisions of 40 CFR part 60, subpart Ja for
which they had previously requested a stay (Docket Item EPA-HQ-OAR-
2007-0011-267). Specifically, Industry Petitioners requested that EPA
reconsider the following provisions in subpart Ja: (1) The newly
promulgated definition of ``modification'' for flares (40 CFR
60.100a(c)); (2) the definition of ``flare'' (40 CFR 60.101a); (3) the
fuel gas combustion device sulfur limits as they relate to flares (40
CFR 60.102a(g)(1)); (4) the flow limit for flares (40 CFR
60.102a(g)(3)); (5) the total reduced sulfur and flow monitoring
requirements for flares (40 CFR 60.107a(d) and (e)); and (6) the
nitrogen oxide (NOX) limit for process heaters (40 CFR
60.102a(g)(2)). Subsequently, on August 21, 2008, Industry Petitioners
identified additional issues for reconsideration (Docket Item EPA-HQ-
OAR-2007-0011-246). Industry Petitioners identified a number of issues
with the standards for fluid catalytic cracking units (FCCU), fluid
coking units (FCU), fuel gas combustion devices, sulfur recovery
plants, and delayed coking units. The issues ranged from disagreeing
with the best demonstrated technology (BDT) analyses for FCCU/FCU and
delayed coking units to requests for clarification of requirements
regarding averaging times for various limits, to identifying
inconsistencies in compliance methods, to simple typographical errors.
A total of 82 items were identified in this submittal.
    On August 25, 2008, HOVENSA, LLC (``HOVENSA'') filed a petition for
reconsideration of the following provisions of 40 CFR part 60, subpart
Ja: (1) The NOX limit for process heaters (40 CFR
60.102a(g)(2)); (2) the flaring requirements, including the definitions
of ``flare'' and ``modification'' (40 CFR 60.100a(c), 60.101a,
60.102a(g) through (i), 60.103a(a) and (b)); and (3) the
depressurization work practice standard for delayed coking units (40
CFR 60.103a(c)) (Docket Item No. EPA-HQ-OAR-2007-0011-247). The
petition also requested that EPA stay the

[[Page 78524]]

effectiveness of these provisions during the reconsideration process.
    EPA received a third petition for reconsideration on August 25,
2008, from the Environmental Integrity Project, Sierra Club, and
Natural Resources Defense Council (``Environmental Petitioners'')
requesting that EPA reconsider several aspects of 40 CFR part 60,
subpart Ja (Docket Item No EPA-HQ-OAR-2007-0011-243). The petition
identified the following issues for reconsideration: (1) EPA's decision
not to promulgate standards for carbon dioxide (CO2) and
methane emissions from refineries; (2) the flaring requirements (40 CFR
60.100a(c), 60.101a, 60.102a(g) through (i), 60.103a(a) and (b)); (3)
the NOX limit for FCCU (40 CFR 60.102a(b)(2)); and (4) the
particulate matter (PM) limit for FCCU (40 CFR 60.102a(b)(1)). Unlike
the other Petitioners, Environmental Petitioners did not seek a stay of
these provisions during reconsideration.
    On September 26, 2008, EPA issued a Federal Register notice (73 FR
55751) granting reconsideration of the following issues: (1) The newly
promulgated definition of ``modification'' for flares; (2) the
definition of ``flare;'' (3) the fuel gas combustion device sulfur
limits as they apply to flares; (4) the flow limit for flares; (5) the
total reduced sulfur and flow monitoring requirements for flares; and
(6) the NOX limit for process heaters. EPA also granted
Industry Petitioners' and HOVENSA's request for a 90-day stay for those
same provisions under reconsideration. In this action, EPA is
addressing those issues for which it granted reconsideration and a stay
as outlined in the September 26 notice. We are also addressing certain
other minor issues raised by Industry Petitioners in this action, as
discussed later in this preamble; we will take action on all of the
remaining issues raised by the Petitioners for reconsideration in
future notices.

B. What is the statutory authority for the proposed amendments?

    New source performance standards implement CAA section 111(b) and
are issued for categories of sources which cause, or contribute
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare. The primary purpose of the NSPS is
to attain and maintain ambient air quality by ensuring that the best
demonstrated emission control technologies are installed as the
industrial infrastructure is modernized. Since 1970, the NSPS have been
successful in achieving long-term emissions reductions in numerous
industries by assuring cost-effective controls are installed on newly
constructed, reconstructed, or modified sources.
    Section 111 of the CAA requires that NSPS reflect the application
of the best system of emission reductions which (taking into
consideration the cost of achieving such emission reductions, any non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated. This
level of control is commonly referred to as best demonstrated
technology (BDT). CAA section 111 also authorizes EPA to distinguish
among classes, types, and sizes within categories of sources when
establishing standards.
    Section 111(b)(1)(B) of the CAA requires EPA to periodically, but
no later than every 8 years, review and revise the standards of
performance, as necessary, to reflect improvements in methods for
reducing emissions.

C. What are the current petroleum refinery NSPS that are proposed to be
amended?

    NSPS for petroleum refineries (40 CFR part 60, subpart J) apply to
the affected facilities at the refinery, such as fuel gas combustion
devices (which include process heaters and flares), that commence
construction, reconstruction, or modification after June 11, 1973. The
NSPS were originally promulgated on March 8, 1974, and have been
amended several times. In this action, we are granting reconsideration
and proposing technical corrections to subpart J for certain issues
that were identified by Industry Petitioners.
    Additional standards for petroleum refineries (40 CFR part 60,
subpart Ja) apply to flares that commence construction, reconstruction,
or modification after June 24, 2008, and other affected petroleum
refinery sources, including process heaters, that commence
construction, reconstruction, or modification after May 14, 2007. In
this action, we are proposing amendments to subpart Ja to address the
issues raised by Petitioners regarding flares and process heaters. We
are also granting reconsideration and proposing technical corrections
to subpart Ja for certain issues that were identified by Industry
Petitioners.

III. Summary of the Proposed Amendments

    The following sections summarize the proposed amendments in both 40
CFR part 60, subpart J and 40 CFR part 60, subpart Ja. Section IV
contains the rationale for these amendments, while the amendments
themselves follow the preamble.

A. What are the proposed amendments to the existing standards for
petroleum refineries in 40 CFR part 60, subpart J?

    We are proposing to add a new paragraph to 40 CFR 60.100 to allow
40 CFR part 60, subpart J affected sources the option of complying with
subpart J by following the requirements in 40 CFR part 60, subpart Ja.
We believe the subpart Ja requirements are at least as stringent as
those in subpart J, so providing this option will allow all process
units in a refinery to follow the same requirements and simplify
compliance. We request comments on this allowance. We are also
proposing to correct the value and units (in the metric system) for the
allowable incremental rate of PM emissions in 40 CFR 60.106(c)(1). We
amended the units for this constant in 40 CFR 60.102(b) on June 24,
2008, and we are now correcting 40 CFR 60.106(c)(1) accordingly.

B. What are the proposed amendments to the new requirements for
affected process heaters in 40 CFR part 60, subpart Ja?

    We are proposing to create three subcategories of process heaters
and to establish performance standards for NOX emissions
within these subcategories for new, modified, and reconstructed process
heaters. The subcategories that we are proposing to create are: (1)
Natural draft process heaters; (2) forced draft process heaters; and
(3) co-fired process heaters. We are also proposing to provide an
additional emission limit format for these subcategories, to extend the
averaging time over which compliance is determined, and to allow
additional options for demonstrating initial and ongoing compliance
with the limits. Other aspects of the final rule, such as recordkeeping
and reporting requirements, remain the same, and will apply as
promulgated to all of these subcategories.
    For the natural draft process heater subcategory, the proposed
NOX emission limit for newly constructed, modified, and
reconstructed natural draft process heaters is 40 parts per million by
volume (ppmv) on a 365-day rolling average basis (dry at 0 percent
excess air). For the second subcategory, forced draft process heaters,
the proposed NOX emission limit for newly constructed forced
draft process heaters is 40 ppmv on a 365-day rolling average basis
(dry at 0 percent excess air). For modified or reconstructed forced
draft process heaters, the proposed NOX

[[Page 78525]]

emission limit is 60 ppmv on a 365-day rolling average basis (dry at 0
percent excess air). These limits are based on the performance of
ultra-low NOX burner control technologies.
    We are also proposing an alternative compliance option that would
allow owners and operators to obtain EPA approval for a site-specific
NOX limit for certain process heaters in both of these
subcategories that are modified or reconstructed. In limited cases,
existing natural draft or forced draft process heaters have limited
firebox size or other constraints such that they cannot apply the BDT
of ultra-low NOX burners or otherwise meet the applicable
limit. This proposed compliance option would require a detailed
demonstration that the application of the ultra-low NOX
burner technology is not feasible and would require that the refinery
conduct source tests to develop a site-specific emission limit for the
process heater. This analysis would be subject to review and approval
by EPA and this review would not be delegable to a State or local
agency.
    We are not proposing to amend the methods for determining initial
compliance with the emission limits for any of the subcategories,
although we are proposing to provide owners and operators of process
heaters in any subcategory that are equipped with combustion
modification-based technology (low-NOX burners or ultra-low
NOX burners) with a rated heating capacity of less than 100
million British thermal units per hour (MMBtu/hr) the option of using
continuous emission monitoring systems (CEMS) (in the final rule, these
process heaters must use biennial source testing to demonstrate
compliance). We are also proposing to require that owners and operators
with process heaters in any subcategory that are complying using
biennial source testing establish a maximum excess oxygen concentration
operating limit, and comply with the O2 monitoring
requirements for ongoing compliance demonstration.
    We are also proposing to provide an alternative format for the
emission limits in terms of pounds per million British thermal units
(lb/MMBtu) that are equivalent to the concentration-based limits. For
newly constructed forced draft process heaters, and for newly
constructed, modified and reconstructed natural draft process heaters,
the proposed alternative emission limit is 0.035 lb/MMBtu on a 365-day
rolling average basis (dry at 0 percent excess air). For modified or
reconstructed forced draft process heaters, the proposed alternative
emission limit is 0.055 lb/MMBtu on a 365-day rolling average basis
(dry at 0 percent excess air). We propose that initial compliance with
the lb/MMBtu emission limit would be demonstrated by conducting a
performance evaluation of the CEMS in accordance with Performance
Specification 2 in appendix B to 40 CFR part 60, with Method 7 of 40
CFR part 60, appendix A-4 as the Reference Method, along with fuel flow
measurements and fuel gas compositional analysis. We propose that the
NOX emission rate would be calculated using the oxygen-based
F factor, dry basis according to Method 19 of 40 CFR part 60, appendix
A-7. We propose that ongoing compliance with this NOX
emission limit would be determined using a NOX CEMS, a
continuous fuel gas flow monitor, and at least daily sampling of fuel
gas heat content or composition, averaged over each 365-day period.
    The third subcategory we propose to create is for co-fired process
heaters. Certain refineries, such as island refineries, do not have
natural gas available and must supplement their fuel gas (co-fire) with
oil to meet their energy demands. We propose to create this subcategory
and set an emission limit for co-fired process heaters because
technology is presently not able to achieve as low a level of
NOX emissions as units that are fired by gas alone. The
NOX emission limit for these units is proposed to be the
weighted average based on a limit of 0.08 lb/MMBtu for the gas portion
of the firing and 0.27 lb/MMBtu for the oil portion of the firing.
    Because data indicates that some of these co-fired units may not be
able to achieve the NOX limitations even with ultra-low
NOX burner control technology, we are also proposing to
allow owners and operators an alternative compliance option to obtain
EPA approval for a site-specific NOX limit for these process
heaters. The site-specific limits for co-fired units would be based on
the same factors used to determine site-specific limits for other types
of process heaters. All of the requirements for monitoring,
recordkeeping, and reporting for co-fired heaters are the same as for
other process heaters.

C. What are the proposed amendments to the requirements for affected
flares in 40 CFR part 60, subpart Ja?

    We are proposing to amend several of the requirements for flares as
follows. First, we are proposing to remove the 250,000 standard cubic
feet per day (scfd) 30-day average flow rate limit in 40 CFR
60.102a(g)(3) and the requirement for a diagram of the flare
connections in the flare management plan required in 40 CFR
60.103a(a)(1).
    Second, we are proposing to require a list of refinery process
units and fuel gas systems connected to each affected flare in the
flare management plan and to assess and minimize flow to affected
flares from these process units and fuel gas systems. We are also
proposing to allow additional time for owner and operators of modified
flares to develop a flare management plan.
    Third, we are proposing to amend the modification provision in 40
CFR 60.100a(c) to exclude certain connections that do not result in
emission increases from being modifications. We are not proposing any
changes to the definition of ``flare'' in 40 CFR 60.101a.
    Fourth, we are proposing to provide additional time for modified
flares that need to install additional amine scrubbing and amine
stripping columns to meet the 60 ppmv, 365-day hydrogen sulfide
(H2S) concentration limit; however, we are not proposing any
changes to the short- or long-term H2S concentration limits
themselves as they apply to flares as contained in 40 CFR
60.102a(g)(1)(ii).
    Fifth, we are proposing changes to 40 CFR 60.103a(b) to specify
that a root cause analysis for flares would be required for all events
causing total sulfur dioxide (SO2) emissions from that flare
to exceed 227 kilograms (kg) (500 lb) in any 24-hour period. In the
final rule, root cause analysis was required when the SO2
emissions exceeded the applicable emission limits by 500 lb/day.
    Sixth, we are proposing to add language to the regulation to make
it clear that owners and operators must implement corrective actions on
the findings of the SO2 or flow rate root cause analyses and
to specify a deadline for performing the analyses. We are also
proposing to allow 2 years for a modified flare to begin complying with
these requirements if the owner or operator commits to installing a
flare gas recovery system.
    Seventh, we are proposing changes to the sulfur monitoring
requirements in 40 CFR 60.107a(d) (proposed to be redesignated as 40
CFR 60.107a(e)). The final rule required continuous total reduced
sulfur monitoring with CEMS. We are proposing two additional monitoring
options for measuring SO2 emissions to determine if a
release would trigger a root cause analysis. Both options would specify
procedures for determining total sulfur compound concentrations in the
fuel gas entering the flare. The two new proposed options include the
use of a CEMS to measure

[[Page 78526]]

the concentration of total reduced sulfur compounds of H2S.
If H2S CEMS are used, periodic manual sampling and analysis
would be performed to determine a ratio of the concentration of total
sulfur compounds to the concentration of H2S. This value
would be used with the H2S CEMS data to estimate the daily
concentrations of total sulfur compounds. We are also proposing that
existing flares that are modified and become affected sources have 18
months to install the sulfur monitoring device. Because we are
proposing to allow more time for these flares to install monitoring
devices, we are also proposing that root cause analysis and corrective
action analysis is not required until 18 months after a modified flare
becomes an affected source (i.e., until the monitoring device is in
place).
    Finally, we are proposing changes to the recordkeeping and
reporting requirements at 40 CFR 60.108a(c) and (d) when a root cause
analysis and corrective action analysis are required and to add
recordkeeping requirements for the proposed monitoring option that is
based on periodic manual sampling and analysis.

D. What are the proposed amendments to the definitions in 40 CFR part
60, subpart Ja?

    In reviewing the final standards, we determined that the definition
of ``refinery process unit'' is vague and not used consistently in
other definitions. For example, a ``flexicoking unit'' is defined as
``one or more refinery process units,'' but ``fluid catalytic cracking
unit'' is defined as ``a refinery process unit.'' We are proposing to
clarify that an affected source is one process unit by amending the
definitions of ``delayed coking unit,'' ``flexicoking unit,'' and
``fluid coking unit'' to be ``a refinery process unit'' rather than
``one or more refinery process units.'' We are also proposing to amend
the definition of ``delayed coking unit'' to clarify that each coking
unit includes all of the coke drums and associated fractionators, and
we are proposing to amend the definition of ``fluid coking unit'' to
clarify that each fluid coking unit includes the coking reactor and the
coking burner. We are proposing to add definitions of ``forced draft
process heater,'' ``natural draft process heater,'' and ``co-fired
process heater'' to define our new subcategories for the process heater
emission limits.
    We are proposing to add a new definition of ``flare gas recovery
system.'' The definition of ``flare gas recovery system'' is needed
because we are proposing requirements for systems with flare gas
recovery. We are also proposing to amend the definition of ``process
upset gas'' to mean ``any gas generated by a petroleum refinery process
unit as a result of start-up, shut-down, upset or malfunction.'' This
will make the definition the same as the definition of ``process upset
gas'' in 40 CFR part 60, subpart J.
    Finally, we are proposing to amend the rule to clarify the
definitions of ``petroleum refinery'' and ``refinery process unit.''
Facilities that only produce oil shale or tar sands-derived crude oil
for further processing using only solvent extraction and/or
distillation to recover diluent that is then sent to a petroleum
refinery are not themselves petroleum refineries. This is because they
are only producing feed to a petroleum refinery as a product and not
refined products. Facilities that produce oil shale or tar sands-
derived crude oil and then upgrade these materials and produce refined
products would be a petroleum refinery. In addition, because petroleum
coke is a refinery product and anode grade coke is not, process units
that calcine petroleum coke into anode grade coke are not petroleum
refinery process units. We are proposing to amend the definitions of
``fuel gas'' and ``refinery process unit'' to clarify that process
units that gasify petroleum coke at a petroleum refinery are refinery
process units because they are producing refinery fuel gases and
possibly other refined intermediates or final products.

IV. Rationale for the Proposed Amendments

A. What is the rationale for the proposed amendments for affected
process heaters?

1. Process Heater Emission Limits
    The final rule, in 40 CFR 60.102a(g)(2), established NOX
limits for all new, modified, or reconstructed process heaters with a
rated heat capacity of greater than 40 MMBtu/hr of 40 ppmv
NOX (dry basis, corrected to 0 percent excess air) on a 24-
hour rolling average basis (there were no subcategories). This limit
was more stringent than the NOX limit that was included in
the proposed rule. The NOX limit was based on emissions
tests for low-NOX and ultra-low NOX burners on
various types of process heaters. After promulgation of the final
NOX limit for process heaters, both Industry Petitioners and
HOVENSA raised several issues regarding this limit in their petitions
for reconsideration. We address these issues below and provide our
rationale for the proposed amendments to the NOX limits for
process heaters that are included in this action. For details on the
data analysis supporting the proposed amendments for process heaters,
see the memorandum ``Evaluation of Nitrogen Oxides Emissions Data for
Process Heaters'' in Docket ID No. EPA-HQ-OAR-2007-0011.
    Since promulgation of the final rule, Industry Petitioners have
provided additional CEMS data indicating that, for certain process
heaters, the NOX emission limit in 40 CFR 60.102a(g)(2) is
not achievable by the BDT, ultra-low NOX burners. Industry
Petitioners argued that, due to normal process fluctuations, including
process turn downs (operating at as low as half of the rated capacity)
and variations in the heat content of the fuel gas, the 40 ppmv
NOX emissions limit is not achievable on a 24-hour average
basis; thus, a longer averaging time or a higher limit is needed. In
addition, we reviewed the data that we used to establish the emissions
limits in the final rule and noted that the data were from short-term
source tests and, as such, were not generally indicative of the range
of operating conditions that might occur over the course of a year. We
concluded that all of these data demonstrate that the final
NOX limit is not always achievable on a 24-hour basis.
    We also find that this is a reasonable conclusion because during
process turn downs, especially those approaching 50 percent of
capacity, which can occur routinely, less fuel gas is combusted without
an equivalent reduction in the flow of combustion air. Turn downs,
therefore, result in less efficient combustion, which tends to increase
NOX concentrations in the heater exhaust. Even though the
concentration of NOX increases during turn downs, the mass
of NOX emitted does not because there is less exhaust gas
produced. Turn downs typically occur in hydrotreater or hydrogen units
that have varying operational rates. Some process heaters may be in
turn down for months (e.g., when a hydrotreater is using a new
catalyst). As Industry Petitioners point out, one way to allow for the
variations in emissions that are due to process fluctuations, turn
downs, and variations in fuel gas composition is to extend the
averaging time over which compliance is determined. Based on the above
information, we are proposing changes to the NOX limit to
address these issues.
    In the final rule, we considered all process heaters in one
category. Section 111(b)(2) of the CAA allows us to ``distinguish among
classes, types, and sizes within categories'' of affected sources when
establishing performance standards. Based on data received after

[[Page 78527]]

promulgation, we are now proposing to treat natural draft process
heaters and forced draft process heaters as two separate subcategories.
    Our review of the CEMS data received from Industry Petitioners
after promulgation of the final rule indicates that nearly all new,
modified, or reconstructed natural draft heaters using ultra-low
NOX burners can achieve NOX concentrations of
less than 40 ppmv on a 365-day rolling average basis (dry at 0 percent
excess air). We anticipate that the natural draft process heaters not
meeting a 40 ppmv emissions limit on a 365-day rolling average basis
have a higher hydrogen content and are currently meeting the proposed
0.035 lb/MMBtu limit (see Section IV.A.2 of this preamble). We found in
the additional performance data available for ultra-low NOX
burner retrofits provided by Industry Petitioners during
reconsideration that the exhaust gas NOX concentrations from
forced draft process heaters exceeded 40 ppmv on an annual average
basis. Industry Petitioners suggest that this is because retrofitting
the fireboxes of forced draft process heaters often results in excess
oxygen levels and higher flame temperatures that would result in higher
NOX emissions. Moreover, forced draft process heaters often
include heat exchangers that provide combustion air preheating, which
reduces fuel usage by up to 10 percent but increases the amount of
NOX generated. It would be possible to provide less
combustion air preheat, which would lower the inlet combustion air
temperatures and NOX concentrations, but that would come
with a reduction in the energy savings from the combustion air
preheater. To recognize the difference in these types of process
heaters and their performance, and to avoid creating disincentives for
energy savings, we propose to subcategorize according to these two
types of process heaters and establish separate limits for existing
forced draft process heaters that are modified or reconstructed. For
new, modified, or reconstructed natural draft process heaters, we are
proposing a 40 ppmv emissions limit on a 365-day rolling average basis
(dry at 0 percent excess air). For forced draft process heaters, we are
proposing limits of 40 ppmv for newly constructed process heaters and
60 ppmv for modified or reconstructed process heaters, both on a 365-
day rolling average basis (dry at 0 percent excess air). For modified
and reconstructed forced draft process heaters, we believe that the 60
ppmv limit constitutes BDT both because of the achievability of the
standard and because of the energy penalty noted above that may occur
were the units required to meet the 40 ppmv limit.
    The annual average format provides one means of dealing with
process and control system variability. We also considered shorter
averaging times, but these would require higher concentration limits
and special provisions to deal with turn down situations. California's
South Coast Air Quality Management District (SCAQMD) Rule 1109
effectively establishes a mass NOX emissions rate limit for
the process heater when operated at maximum capacity and allows the
owner or operator of the process heater to meet this mass emissions
rate when the unit is not operating at maximum capacity. We request
comment on the advantages and disadvantages of providing an extended
averaging time versus providing specific provisions to account for
higher NOX concentrations observed during process heater
turn downs where the process heater is running at about 50 percent or
less of capacity.
    We also received information from Industry Petitioners that a
particular type of forced draft process heater, one that is also
equipped with a combustion air preheater, may not consistently meet the
proposed emissions limit for newly constructed forced draft process
heaters of 40 ppmv (0.035 lb/MMBtu). We do not want to discourage this
type of system because of the potential fuel savings, but we do not
have data supporting Industry Petitioners' assertion. We are,
therefore, requesting comment and supporting data on the need to
establish a subcategory for this type of new forced draft process
heater, and to establish a higher NOX limit for this
particular type of new forced draft process heater.
2. Alternative lb/MMBtu Format
    Industry Petitioners suggested that we provide an alternative lb/
MMBtu emission limit format to address potential issues related to the
combustion of high-hydrogen fuel gases. In evaluating this request, we
looked at the differences in combusting high-hydrogen fuel gases versus
more typical low hydrogen, hydrocarbon-based fuel gases.
    Combustion of a wide range of fuel gases in a given process heater
produces approximately the same quantity of NOX. Fuel gases
contain varying amounts of hydrogen, and in certain cases, such as
hydrotreaters, hydrogen is a significant portion of the fuel gas.
Combustion of hydrocarbon fuel gases, such as methane, produce carbon
dioxide, which adds to the volume of the gas stream. Combustion of
hydrogen fuel gases produces water vapor, which also increases the gas
stream on an actual basis. Since our emission limit is on a dry basis,
however, this water vapor is discounted and the exhaust gases from
combustion of high-hydrogen fuel gases are more concentrated than they
are with low-hydrogen fuel gases. This means that if there is only a
concentration-based emission limit, high-hydrogen fuel gases would be
subject to more stringent emission limits than more typical hydrocarbon
fuel gases.
    For a range of hydrogen contents in the fuel gas, the 0.035 lb/
MMBtu NOX emissions limit in the final rule would convert to
a range of NOX concentrations on a dry basis of from 32 to
50 ppmv. This means our emission limit of 40 ppmv, which is the
midpoint of this range of hydrogen concentrations, equates to a 0.035
lb/MMBtu limit. This value was suggested by Industry Petitioners and is
also used in other rules and recent consent decrees between many
petroleum refiners and the United States government (representing EPA
and various individual States, depending on the petroleum refining
company). The consent decrees are in effect on over 90% of domestic
refining capacity. These negotiated requirements often set controls in
place that have provided the basis (including performance test data and
ongoing monitoring data) for our BDT performance levels for process
heaters. Similarly, the 0.055 lb/MMBtu NOX emission limit
reasonably equates to a 60 ppmv NOX concentration limit. We
request comments on the use of these lb/MMBtu limits and if these
values are reasonably equivalent to the corresponding concentration
limits.
3. Co-Fired Process Heaters
    In their petition, HOVENSA raised the issue of NOX
limits for co-fired units. Certain refineries, such as island
refineries, do not have natural gas available and must supplement their
fuel gas with oil to meet their energy demands. In addition, in times
of limited natural gas supplies, industry can undergo gas curtailments.
While refiners may have separate burners for oil in this situation,
they may also be set up to co-fire oil. Technology for these co-fired
systems are presently not able to achieve as low a level of
NOX emissions as systems that are fired by gas alone. We
received vendor-guaranteed performance levels for several ultra-low
NOX burner suppliers for co-fired units. These data indicate
a range of NOX emissions from 0.080 to

[[Page 78528]]

0.19 lb/MMBtu for gas firing and 0.27 to 0.63 lb/MMBtu for oil firing.
    After considering all these data, we are proposing the lowest
available NOX performance limit of the different ultra-low
NOX burner designs as the emissions limit for co-fired
process heaters. When fired with gas, we are proposing that these
burners achieve a NOX limit of 0.08 lb/MMBtu and when fired
with oil, a NOX limit of 0.27 lb/MMBtu. When the unit is co-
fired, we are proposing a weighted average emissions limit for these
units based on a limit of 0.08 lb/MMBtu for the gas portion of the
firing and 0.27 lb/MMBtu for the oil portion of the firing.
    In addition, we are also proposing an alternative performance
standard of 150 ppmv for these units when they are being co-fired. This
value represents the performance of these process heaters using a mid-
range mixture of gas and oil as fuel. We are proposing this
concentration-based alternative standard because it provides a simple
direct means of measuring compliance (no need to measure oil and gas
fuel flows or BTU contents of the fuels).
    We request comment on the unique issues related to process heaters
on island refineries and situations such as natural gas curtailments
that would lead non-island refineries to have burners that are designed
to co-fire both oil and fuel gas. We also request comments on
limitations that would keep these refiners from installing the best-
performing burners and, for process heater/burner combinations that are
available that limit NOX emissions, what NOX
limits would be achievable. Finally, we request comments on the
alternative concentration limit and on other methods that may be
available to determine compliance with the co-fired process heater
NOX limits.
4. Site-Specific Emission Limits
    We are also proposing an alternative compliance option for owners
and operators to obtain EPA approval for a site-specific NOX
limit for: (1) Modified or reconstructed natural draft and forced draft
process heaters that have limited firebox size or other limitations and
therefore cannot apply the BDT of ultra-low NOX burners and
(2) co-fired process heaters. This approach has been used in the past
to determine performance levels for boilers (see 40 CFR 60.44b(f)) and
would allow for limits that are tailored to the specific process
heater.
    Certain natural draft and forced draft process heaters, generally
ones that are more than 30 years old, have smaller fireboxes than more
recent heaters. For these heaters, it is physically impossible to
install ultra-low NOX burners because these burners minimize
NOX emissions through the use of long flame fronts. For
these or other process heaters that cannot install ultra-low
NOX burners, owners or operators can elect to submit to the
Administrator for approval a site-specific NOX emission
limit. This request must include: (1) The reasons why ultra-low
NOX burners or other means cannot be used to meet the
emission limits; (2) test data that reflects performance of
technologies that will otherwise minimize NOX emissions; and
(3) the means by which they will document continuous compliance.
    We request comments on possible ways of retrofitting ultra-low
NOX burners in space-limited situations, such as raising the
firebox height to accommodate flame length, which would enable modified
or reconstructed natural draft and forced draft process heaters to
install this control technology in space-limited situations.
    In addition, because of the high level of uncertainty and site-
specific nature of the specification of NOX limits for co-
fired process heaters, we are also proposing an alternative compliance
option for owners and operators of co-fired process heaters to obtain
EPA approval for a site-specific NOX limit. The request to
the Administrator must follow the same requirements as described above
for natural draft and forced draft process heaters.
    Finally, we request comments on all aspects of the use of site-
specific testing to establish EPA-approved limits for size-limited
natural draft and forced draft process heaters and for co-fired process
heaters.

B. What is the rationale for the proposed amendments for affected
flares?

1. Soliciting Comment on the Flare Requirements in the Final Rule
    All of the Petitioners noted that many of the flare provisions in
the final rule were not in the May 14, 2007, proposal (72 FR 27178) and
that there was no opportunity for notice and comment. Therefore, we now
solicit comments on all aspects of the final rule flare provisions on
which the public has not previously had an opportunity to comment and
that we do not propose to change in this action. In addition, the
following sections describe and give our rationale for proposed changes
to these final provisions.
    We also note that we have prepared revised cost and emissions
reduction impact estimates for the flare requirements that we are
proposing in this notice. Based on information provided by Industry and
Environmental Petitioners, we now believe that there will be more
existing flares that will become affected facilities in the first 5
years of this rule and that there are more sulfur emissions from events
that would cause root cause analysis than we anticipated. This leads
both the costs and the emission reductions anticipated in the final
rule to increase. The proposed amendments would remove some
requirements in the final rule while strengthening others. Overall, we
believe that the revised impacts represent the rule as it would be
amended by today's action. The revised impacts for proposed amendments
to the flare requirements are presented in Section V of this preamble;
for details on the revised impacts estimates for flares, see Docket ID
No. EPA-HQ-OAR-2007-0011.
    The following sections outline the major areas for which
Petitioners have sought reconsideration. They provide overview of the
Petitioners' concerns and propose our response.
2. Definition of ``Flare''
    Industry Petitioners and HOVENSA both requested that we change the
definition of flare so that it includes only the seal pot and flare
itself and not the flare header and associated equipment that provides
the flare gas from the process units or fuel gas system to the flare
burner assembly. Industry Petitioners suggested that we revise the
definition of the flare and thus the flare affected source in order to
limit applicability of the flare provisions. By limiting the definition
of flare to only the downstream components, they suggested that any
connection made upstream of the seal pots would not be considered a
modification. We disagree with this outcome because we are not trying
to limit the affected facility and what would be a modification.
Including the flare header system is crucial to our approach in that
the connections that trigger a modification are almost always made
prior to the seal pot. Accordingly, adopting a narrower definition may
result in many of the activities that increase emissions at the flare
being excluded from review. We are, therefore, retaining the definition
of flare as promulgated in the final rule and includes the upstream
components of the flare header as well as the actual flare itself. We
are requesting comments on all aspects of the flare definition,
including Industry Petitioners' suggested revisions to the definition.
    A related concern Industry Petitioners raised regarding the flare
definition we have included in 40 CFR part 60, subpart Ja is the impact
of cross-referencing it in 40 CFR part 60, subpart

[[Page 78529]]

J. Specifically, Industry Petitioners assert that we expanded the
applicability of subpart J and created retroactive noncompliance issues
for certain existing flares when we cross-referenced the flare
definition in 40 CFR 60.100(b). Industry Petitioners, however,
misinterpret the intent and impact of this cross-reference. The intent
of the provision was not to expand the definition of fuel gas
combustion device under subpart J; rather, it was included only to
clarify that flares were not subject to the new flare requirements in
subpart Ja until after the date of publication of the final rule.
    In the final rule we stated that a ``fuel gas combustion device
under paragraph (a) of this section,'' that is also a ``flare as
defined in Sec.  60.101a,'' is still subject to the requirements in 40
CFR part 60, subpart J, not 40 CFR part 60, subpart Ja, if it
``commences construction, reconstruction, or modification after June
11, 1973, and on or before June 24, 2008.'' In other words, the
provision only changes the applicability date for flares that have
always fallen within the definition of fuel gas combustion device in
subpart J, i.e., it does not impact applicability.
    We recognize that there may be disagreement regarding coverage of
flares. Specifically, we recognize that there may be disagreement under
40 CFR part 60, subpart J regarding what parts of a flare are covered
as fuel gas combustion devices. That disagreement is, however, not
being addressed by this rulemaking, nor was it addressed in the
rulemaking published on June 24, 2008. Rather, such disagreements
should be addressed through other available CAA regulatory mechanisms,
such as through Applicability Determinations under 40 CFR 60.5.
3. Flare Modification Provision
    Each petition we received requested that we reconsider the
modification provision in 40 CFR 60.100a(c) which states that ``a
modification to a flare occurs if: (1) Any new piping from a refinery
process unit or fuel gas system is physically connected to the flare
(e.g., for direct emergency relief or some form of continuous or
intermittent venting); or (2) a flare is physically altered to increase
flow capacity of the flare.''
    In developing this provision, we anticipated that all new
connections to the flare would result in an increase in emissions from
the flare, and thus qualify as a modification to the flare under the
statutory definition. While we have historically identified emission
increasing activities based on a numerical calculation, see 40 CFR
60.14(a) and (b), we believe that given the intermittent nature of
flare use, the variable composition of gas being flared, and other
factors, the listing approach we are proposing to adopt here will help
ease implementation issues while identifying ``any physical change in,
or change in the method of operation of [an affected facility] which
increases the amount of any air pollutant emitted.'' CAA section
111(a)(4). Thus, new connections of refinery process units to the flare
would trigger 40 CFR part 60, subpart Ja applicability for the flare.
    Industry Petitioners subsequently submitted data asserting that
many new connections made to the flare do not result in an increase in
emissions from the flare and, in fact, may decrease the emissions from
the flare. For example, they asserted that installing a flare gas
recovery system requires making several new connections to the flare,
but these connections do not increase the emissions from the flare, so
they should not qualify as a modification under CAA section 111(a)(4)
and should not trigger 40 CFR part 60, subpart Ja applicability for the
flare.
    We have evaluated a number of potential flare connection scenarios
and identified the types of connections that do not result in an
increase in emissions from the flare. Based on our evaluation, we are
proposing amendments to the modification provision in 40 CFR 60.100a(c)
that would clarify what constitutes a modification of the flare and
would exclude these types of connections because they will not result
in an emissions increase as required by the definition of modification.
See CAA section 111(a)(4) (``modification means 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.''). Specifically, we are proposing to exclude the following
types of connections: (1) Those associated with the installation of a
flare gas recovery system; (2) connections required to install a
monitoring device on the flare (e.g., flow meter, sulfur monitor, or
pressure transducer); and (3) connections used to replace or upgrade
old piping or pressure relief systems that are already connected to
that flare. We also request comment, including supporting
documentation, on whether there are other types of connections that do
not result in an increase in emissions from a flare.
    Industry Petitioners have also suggested that some de minimis
emissions increases should be allowed without triggering NSPS subpart
Ja applicability. Such exceptions are permissible but not required
under the modification provisions of CAA section 111--see Alabama Power
vs. Costle, 636 F.2d 323, 360-61 (D.C. Cir. 1980). We request comments
on a de minimis approach and on specific changes that may occur to
flares that will result in de minimis increases in emissions. We also
request comments on the type, number, and amount of emissions that
would be considered de minimis.
    Finally, Industry Petitioners requested that we consider the merits
of a two-tiered system for existing facilities to become affected
facilities through modifications. They suggest that the existing
definition of modification may be appropriate for triggering the flare
gas minimization requirements under 40 CFR 60.103a work practice
standards, but that we should consider a separate, more substantive,
trigger for requirements for fuel gas combustion devices under 40 CFR
60.103a(g)(1). We do not see the need for this type of system,
especially considering all the proposed changes included in this
notice. For example, we are proposing several changes to the flare
provisions that would reduce the number of changes that would make an
existing source an affected facility and reduce the scope of the
requirements, including, but not limited to, excluding some connections
from the definition of modification, including startup and shutdown
fuel gases as process upset gases which are exempt from the fuel gas
standards, providing additional time to comply when new fuel gas sulfur
removal equipment is needed, and removing the flow limits. Moreover, we
are concerned that their approach would not be consistent with the
broad statutory definition of modification and the requirement that new
sources, including modified sources, comply with the NSPS. We see no
basis in these statutory provisions to provide that different types of
modifications trigger fundamentally different NSPS requirements. We are
nonetheless requesting comments on this approach and the statutory
basis for this adoption.
4. Application of Fuel Gas Combustion Device Sulfur Limits to Flares
    a. ``Process upset gas'' definition. We are proposing to include
flaring events from startups and shutdowns in the definition of
``process upset gas.'' The final 40 CFR part 60, subpart Ja definition
excludes startups and shutdowns from the definition of process upset
gases. Process upset gases are exempt under 40 CFR 60.103a(h) from
meeting the sulfur standards (H2S or SO2) for
fuel gas combustion devices

[[Page 78530]]

in 40 CFR 60.103a(g)(1). Our basis for excluding these events in the
final rule was that, in conjunction with our flow limit, BDT was the
capture and treatment of these gases. Certain refiners were able to
nearly or completely eliminate flaring, including startup and shutdown
events that normally released gases to the flare. Since promulgation of
the final rule, we have learned from Industry Petitioners that many
refiners must release gases to their flares during startup and shutdown
events. During startup and shutdown of a process unit, refiners will
purge the process unit with nitrogen gas to ensure that hydrocarbons
are completely removed from the system. In most cases, the gas is
flared because it is a large quantity of gas over a short period of
time, and the high concentration of nitrogen will disrupt the
combustion and NOX control in the refinery process heaters
and boilers. These gases cannot typically meet the SO2 or
H2S standards for fuel gas combustion devices. The BDT
analysis is based on removing H2S from continuous or regular
intermittent streams and does not include controlling sulfur in
potentially large, infrequent fuel gas flows that we now understand are
necessary in some cases. We believe that SO2 emissions from
these events can be minimized or prevented by addressing them with a
flare management plan.
    b. Long-term H2S concentration limit. Industry Petitioners also
expressed concern that meeting the H2S limit of 60 ppmv on a
365-day rolling average basis (long-term sulfur limit) will be
difficult for affected flares because of the cost of treatment and the
method of complying with the long-term average. These Petitioners have
indicated that for typically intermittent flaring events, compliance
with an annual average limit is difficult because sulfur content may be
variable and less likely to be normalized over a limited number of data
points. We believe that we have adequately addressed the issue by
proposing to exclude process upset gases, which would include gases
from startups and shutdowns from this long-term sulfur limit, and we
are not proposing any changes to this long-term limit.
    Industry Petitioners suggest that the flare management plan and
root cause analysis would be an effective means of limiting
SO2 emissions from flares without the long-term limit. We
are not proposing changes to the long-term limit itself, but we are
requesting comment on whether the rule should require the long-term
sulfur limit for all flares or whether, to address the Industry
Petitioners' concern, it should limit applicability of the long-term
sulfur limit only to flares that operate a minimum number of hours per
year.
    We are proposing to provide additional time for modified flares to
meet the sulfur limits in cases where the treatment system does not
already have sufficient amine treatment capacity to remove the
H2S. Many of the 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, in much less time than it takes to
install sulfur removal equipment. For these reasons, we are proposing
that refineries that must install additional sulfur removal equipment
have 2 years after startup of the modified flare to install the sulfur
removal and recovery equipment to comply with the standards.
    We expect this additional time will only be necessary in limited
circumstances due to the consent decrees and refinery operating
practices and we expect most of the existing flares would already have
sufficient sulfur removal equipment to treat additional fuel gas
streams. However, for those that do not, it is necessary for these
systems to have additional time. Due to the planning, design,
purchasing, and installation required to expand fuel gas treatment
systems, we are proposing to provide 2 years after startup of a
modified flare to comply with the long-term sulfur limit for those
facilities that certify that they need to install additional sulfur
removal equipment, such as amine towers or sulfur recovery plants.
    We request comments on phasing out this time allowance for the
installation of fuel gas treatment systems. We note that a substantial
portion of the petroleum refineries in the United States are under
consent decrees with fuel gas sulfur requirements similar to the
requirements of subpart Ja as proposed to be amended. In this action,
we are proposing to clarify what constitutes modification of a flare,
and refiners are now aware that modification of the flare may happen
quickly and that they will be subject to the long-term sulfur limits.
Therefore, we expect that refiners would (or are required to under the
consent decrees) be able to install sufficient sulfur removal equipment
over the next several years to comply with the long-term sulfur limit
upon modification. We request comment on whether 5 years is sufficient
time for all flares potentially subject to subpart Ja to have sulfur
removal equipment in place and, therefore, not need this added time for
installation of equipment.
5. Flare Flow Rate Limit
    Both Environmental and Industry Petitioners questioned the 250,000
scfd flow rate limit for flares. Environmental Petitioners supported
the provisions in the May 14, 2007, proposed rule eliminating routine
flaring from affected fuel gas producing units (72 FR 27178), and they
were concerned that EPA issued standards would allow any routine amount
of flaring. Industry Petitioners, on the other hand, suggested that
specific flow limits are not warranted.
    In response to these petitions, we have reconsidered the final
rule. First, we considered reinstating the requirement for no routine
flaring as requested by Environmental Petitioners. This action would
have also required returning to the concept of applicability of the no
routine flaring requirement to fuel gas producing units. Under the 2007
proposed rule, only the gas stream from the modified fuel gas producing
unit was barred from routine flaring. Under the final rule, all of the
units connected to the flare were addressed. We concluded that this was
a preferable approach because it allowed us to consider how the flare
should be managed for all gases flared. We also concluded that no
routine flaring was not feasible in many cases where gases routed to
flares could not be effectively captured, stored, and returned to the
process or recovered as fuel.
    We then considered the flow limit of 250,000 scfd in the final
rule. In developing the final rule, we believed that sweep gas flow
needed to maintain the readiness of the flare would be only about 20
percent of the final flow limit. Based on the industry design data, it
appears likely that there are some flares that require significantly
higher sweep gas rates than we originally considered, and some sweep
gas rates may be as high as the 250,000 flow limit itself. For these
cases, the flow rate limit would be unachievable. Moreover, we
considered the effect that having a flow limit might create a perverse
incentive to increase the number of flares at a facility to spread the
flow out and avoid triggering the flow limit for individual flares.
Industry Petitioners suggested that there is a wide variety of
configurations and situations and a one-size-fits-all solution of a
flare flow limit is not appropriate. They believe that the flare
management plan will provide site-specific flexibility to minimize
flaring. We are proposing to strengthen both the flare management plan
and the root cause analysis provisions, and with those changes, we
believe that the 250,000 scfd flow limit is not necessary. Therefore,
we are

[[Page 78531]]

proposing to remove the 250,000 scfd flow rate limit in the final rule.
We request comments on the sufficiency of the proposed flare management
plan to address continuous flows to flares, suggestions for other
approaches to limit the volume of gas flared, and an alternative higher
flow rate limit that could be appropriate.
6. Total Reduced Sulfur and Flow Monitoring Requirements for Flares
    We are not proposing to remove the requirements to monitor the
flare flow and sulfur content from the final 40 CFR part 60, subpart Ja
standards. We continue to believe that monitoring is the key to
understanding and minimizing emissions from these diverse and highly
variable flare gas systems. We are proposing clarifications and
additional options for measuring the sulfur content of flare gases. We
are proposing to allow monitoring of H2S or total sulfur at
the flare as additional options for quantifying SO2
emissions. In the case of H2S monitoring for flares, we are
proposing that owners and operators must supplement the measured
readings with additional data to capture non-H2S sulfur
compounds that produce SO2 emissions. For flare flow
monitoring, we are requesting comments on exemptions from flow
monitoring for certain cases where monitoring may be unnecessary. We
are proposing to add requirements to keep records of the CEMS data, the
sampling and analysis data that provide the underlying concentration
information needed to calculate the daily SO2 emissions, and
the daily flare flow rate. Finally, we are proposing to allow the owner
or operator of an existing flare that becomes a modified source 18
months from the date the flare becomes a modified source to install
sulfur and flow monitoring devices. The final rule allowed 1 year, but
Industry Petitioners indicated that since more flares are expected to
become modified sources than we originally anticipated, additional time
should be allowed to ensure that vendors have sufficient time to
provide monitoring devices to all modified sources.
    Industry Petitioners suggested that we exempt certain flares from
the requirement to install continuous flow monitors. Examples they
cited include flares that have flare gas recovery systems or other
flares that do not routinely have any flow, such as emergency release-
only flares, flares on pressure storage vessels, and flares that
receive flow only during periods of startup or shutdown. We are not
aware of any alternative approaches for such flares that would be
effective at determining the need for a root cause analysis and are not
proposing such a requirement. Moreover, the costs for flow monitors are
reasonable and they provide a direct measure of emissions from the
flare. We request comments on the need to provide exemptions from flow
monitoring. Commenters should provide specific cases where they believe
that monitoring is not necessary and how compliance with the root cause
analysis and corrective action provisions would be maintained.
    Installation of flare gas recovery systems requires significant
planning, design, installation, and testing time, whereas some of the
connections that trigger applicability, as discussed previously, can
and must be accomplished very quickly. We believe it is important to
not create disincentives to the addition of flare gas recovery systems.
Therefore, for a modified flare that is being retrofitted with a flare
gas recovery system, we are proposing to provide 2 years from the date
that the flare becomes an affected facility to comply with the flare
management plan, the sulfur and flow monitoring requirements, and the
SO2 and flow root cause analysis and corrective action
analysis requirements.
7. Other Proposed Amendments and Requests for Comments
    a. Root cause analysis. We are proposing to clarify and revise the
requirements of 40 CFR 60.103a(b) for root cause analysis. For all
sulfur recovery plants and all fuel gas combustion devices except
flares, we are clarifying that a root cause analysis is required when
SO2 emissions exceed the applicable emissions limit by at
least 500 lb in any 24-hour period. The final rule included the same
requirement. We are proposing to amend the rule so that root cause
analysis is required for flares for any 24-hour period in which 500 lb
or more of total SO2 is emitted (not SO2 beyond
the applicable emissions limit and not limited to a single event). We
are proposing this amendment because flares receive numerous streams
that tend to be variable in both composition and flow and are
discharged intermittently so that the flow into a flare header at any
given time may not be easily associated with one single event or even
one single process unit operation. Therefore, we are basing the
requirement on a mass per unit time basis rather than on an event by
event basis. Further, since we are proposing to eliminate the flow rate
limit, there is no applicable mass limit beyond which an exceedance
would be calculated.
    We are also proposing to require a corrective action analysis and
corrective actions for both an SO2 and flow rate root cause
analysis (at 40 CFR 60.103a(b) and (a)(5), respectively). We believe
that an important part of conducting a root cause analysis is ensuring
that the root cause of the release is addressed and that a reasonable
attempt is made at preventing a similar occurrence from causing a
future release.
    We are proposing to clarify that an owner or operator should begin
the root cause analysis and corrective action analysis as soon as
possible after a discharge. No later than 45 days after the discharge,
the owner or operator must record detailed information about the
discharge, including the results of the root cause analysis and
corrective action analysis, and either implement corrective action,
develop an implementation schedule for corrective action that cannot be
completed in the 45 days following the discharge, or explain the basis
for the conclusion that corrective action should not be conducted.
    Finally, we are proposing to clarify that root cause analysis and
corrective action analysis are not required for a modified flare until
the compliance date for installation of the sulfur and flow monitoring
devices. As described earlier in this preamble, we propose to allow a
modified flare 18 months to install monitoring devices or 2 years if
the owner or operator commits to installing a flare gas recovery
system.
    We are not changing the final rule inclusion of startup or shutdown
events from the root cause analysis requirements for SO2. In
cases where exceedances are related to a startup or shutdown, the root
cause analysis would identify these events as causes, and the
corrective action analysis would address potential mitigation options.
    b. Flare management plan. We are proposing two amendments to the
flare management plan requirements other than the flow rate root cause
analysis and corrective action analysis. First, we are proposing to
extend the time provided to develop the flare management plan for
modified flares. The final rule provided 1 year, which was the same
amount of time provided for installation of sulfur and flow monitors.
Because the flare management plan includes a requirement to describe
methods for monitoring flow rate to the flare, we are proposing that
the owner or operator of a modified flare must develop and implement
the flare management plan on the same timeline as the installation of
the flow monitor. Specifically, the owner or operator of a

[[Page 78532]]

modified flare must develop and implement the flare management plan no
later than 18 months after the flare becomes an affected facility,
unless the owner or operator of the affected flare commits in writing
to install a flare gas recovery system, in which case the owner or
operator of a modified flare must develop and implement the flare
management plan no later than 2 years after the flare becomes an
affected flare.
    Second, Industry Petitioners noted that a diagram illustrating all
connections to the flare would be very complicated and difficult to
keep current. Therefore, we are proposing to require a list of refinery
process units and fuel gas systems connected to each affected flare in
the flare management plan and an assessment of whether discharges to
affected flares from these process units and fuel gas systems can be
minimized. This requirement is consistent with the intent in the final
rule to track which refinery process units and fuel gas systems are
connected to each flare and when a new connection is made, but it
should be less burdensome than the requirement in the final rule.
    c. Compliance with State or local rules as deemed compliance with
subpart Ja. We note that there are several State and local air
pollution control authorities that have requirements in place to
address flare gas flow and SO2 emissions from refinery
flares. For example, SCAQMD has standards for flares (Rule 1118) that
include many requirements that are similar to the flare standards as
amended by this action in 40 CFR part 60, subpart Ja. Industry
Petitioners requested that we recognize this potential for overlap with
these existing provisions and that we consider allowing flares subject
to both this rule and SCAQMD Rule 1118 to use compliance with Rule 1118
as compliance with the flaring provisions in subpart Ja. We request
comment on the equivalency of the subpart Ja requirements as proposed
to be amended today and the SCAQMD Rule 1118. We also request comment
on whether EPA could deem a facility in compliance with subpart Ja as
proposed to be amended today if that facility was found to be in
compliance with SCAQMD Rule 1118, or other equivalent State or local
rules.
    d. New source trigger date for flares. In the final rule, we
provided that the subpart Ja requirements for flares would apply only
to flares commencing construction, reconstruction, or modification
after June 24, 2008, the date of the final rule. We recognized that
this was a departure from the normal course, where an affected facility
must comply with the final standard if it commences construction,
reconstruction or modification after the proposal date, but justified
this departure because ``we are promulgating a newly defined affected
facility, adding a new provision specifically defining what constitutes
a modification of a flare, adding several new requirements, and adding
a definition of a flare. All of these changes significantly alter what
would be an affected facility and the obligations of the affected
facility for purposes of reducing flaring.'' 73 FR at 35856. We believe
this decision is justified under the definition of ``new source,'' CAA
section 111(a)(2), because the changes meant that numerous flares that
were modified according to the final rule were not covered by the
proposed rule and thus the proposal was not a standard ``which will be
applicable to such source[s].'' Reconsideration has not been sought on
this decision and we are not reopening that final action for comment.
    In connection with their reconsideration petition, Industry
Petitioners have requested that the ``new source'' trigger date for
flares be changed to the date of this reconsideration proposal,
December 22, 2008. We are concerned that such a change would be
improper under the definition of ``new source'' at CAA section
111(a)(2). That provision provides that ``[t]he term `new source' means
any stationary source, the construction * * * of which is commenced
after the publication of regulations (or, if earlier, proposed
regulation) prescribing a standard of performance under this section
which will be applicable to such source.'' As noted above, 40 CFR part
60, subpart Ja's applicability provisions for flares are currently June
24, 2008 (the date of ``publication of regulations * * * prescribing a
standard of performance''). While a reconsideration proceeding under
CAA section 307(d) constitutes a new rulemaking and acts to cure a
procedural flaw in the final rule, we do not interpret it as
invalidating or rendering a nullity to the prior rulemaking. This
position is supported by the structure of CAA section 307, which
provides that the rule remains in effect pending the reconsideration,
subject to the authority of the Administrator to stay the effective
date. See CAA section 307(d)(7)(B) (``Such reconsideration shall not
postpone the effectiveness of the rule.''). We also believe this
position to be consistent with Congressional intent, as reflected in
the definition of ``new source,'' which is tied to the date of
proposal, that sources be subject to the final rule if they are on
notice that the final rule may apply to them. Nonetheless, we solicit
comment on Industry Petitioners' request and, in particular, whether it
could be accommodated consistent with the text of CAA section
111(a)(2).

C. What miscellaneous corrections are being proposed?

    See Table 1 of this preamble for the miscellaneous technical
corrections not previously described in this preamble that we are
proposing throughout 40 CFR part 60, subpart Ja.

  Table 1--Proposed Technical Corrections to 40 CFR part 60, Subpart J
------------------------------------------------------------------------
           Section              Proposed technical correction and reason
------------------------------------------------------------------------
60.101a......................  In the definition of ``Sulfur recovery
                                plant,'' replace ``HS2'' with ``H2S'' to
                                correct a typographical error.
60.102a(f)(1)(ii)............  Replace ``10 ppm by volume of hydrogen
                                sulfide (HS2)'' with ``10 ppmv of H2S''
                                to correct a typographical error.
60.105a(b)...................  Replace ``paragraphs (b)(1) through (3)
                                of this section'' with ``paragraphs
                                (b)(1) and (2) of this section'' to
                                remove the reference to a nonexistent
                                paragraph.
60.105a(i)(5)................  Replace ``Except as provided in paragraph
                                (i)(7) of this section, all rolling 7-
                                day periods'' with ``All rolling 7-day
                                periods'' to remove the reference to a
                                nonexistent paragraph.
60.107a(2)(i)................  Replace ``320 ppmv H2S'' with ``300 ppmv
                                H2S'' to make the span value for an H2S
                                monitor consistent with the span value
                                in subpart J.
60.108a(b)...................  Replace ``the information described in
                                paragraph (e)(6) of this section'' with
                                ``the information described in paragraph
                                (c)(6) of this section'' to correct the
                                reference to a nonexistent paragraph.
------------------------------------------------------------------------

[[Page 78533]]

V. Summary of Cost, Environmental, Energy, and Economic Impacts

    The cost, environmental, and economic impacts presented in this
section for flares are revised estimates for the impacts of the final
requirements of 40 CFR part 60, subpart Ja as proposed to be amended by
this action. The impacts are presented for petroleum refinery flares
that commence construction, reconstruction, or modification over the
next 5 years. Industry Petitioners noted that we underestimated the
number of affected flares in our analysis of the final rule. Based on
the clarification of a flare modification, we agree, and we anticipate
that there will be 150 affected flares over the next 5 years, or about
one flare per refinery, and 80 percent of those will be modified or
reconstructed. Environmental Petitioners provided upset data from the
Texas Commission on Environmental Quality showing that flares can
release much higher quantities of SO2 emissions than we
estimated in our analysis of the final rule, and they stated that our
low estimates resulted in underestimated SO2 emissions
reductions for root cause analyses. Based on the data provided, our
updated analysis includes three model flare releases with different
amounts of SO2 emissions that are prevented by root cause
analysis. The values in Table 2 of this preamble include the costs for
those 150 flares to comply with the H2S emissions limits for
fuel gas combustion devices, the flare management plan, sulfur and flow
monitoring requirements, and root cause analyses.
    For details on the updated impacts estimates for flares, see Docket
ID No. EPA-HQ-OAR-2007-0011.

      Table 2--National Fifth Year Impacts of Proposed Emissions Limits and Work Practices for Flaring Devices Subject to 40 CFR Part 60, Subpart J
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Total
                                                             annual cost                              Emission     Emission     Emission
                                                  Capital      without    Natural gas     Total      reduction    reduction    reduction   Overall cost-
                 Requirements                       cost     natural gas     offset    annual cost   (tons SO2/   (tons NOX/   (tons VOC/  effectiveness
                                                  ($1,000)      offset      ($1,000)   ($1,000/yr)      yr)          yr)          yr)         ($/ton)
                                                               ($1,000)
--------------------------------------------------------------------------------------------------------------------------------------------------------
New Flares....................................       46,000       13,000     (12,000)          410        5,900            4          240            67
Modified and Reconstructed Flares.............      300,000       81,000     (49,000)       32,000       24,000           17          960         1,300
                                               ---------------------------------------------------------------------------------------------------------
    Total.....................................      350,000       94,000     (62,000)       32,000       30,000           21        1,200         1,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The cost, environmental, and economic impacts for the proposed
amendments to 40 CFR part 60, subpart Ja for process heaters are not
expected to be significantly different than those reported for the
final rule. We expect owners and operators to install the same
technology to meet these proposed amendments that we anticipated they
would install to meet the final subpart Ja requirements (i.e., ultra-
low NOX burners). Our proposal to create new subcategories
of process heaters and set different emissions limits for those
subcategories does not impact the control or compliance methods.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action'' because it may raise
novel legal or policy issues. Accordingly, EPA submitted this action to
the Office of Management and Budget (OMB) for review under Executive
Order 12866, and any changes made in response to OMB recommendations
have been documented in the docket for this action.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
The information requirements in these proposed amendments would add new
compliance options, provide more time to comply with the requirements
for fuel gas monitoring systems, and clarify the definition of a
``flare modification.'' These proposed changes will not result in any
increase in burden and are expected to reduce the costs associated with
testing, monitoring, recording, and reporting. However, the information
collection requirements contained in the existing regulation (40 CFR
part 60, subpart Ja) under the provisions of the Paperwork Reduction
Act, 44 U.S.C. 3501, et seq., have been sent to OMB for approval under
EPA ICR number 2263.02. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule
would not have a significant economic impact on a substantial number of
small entities. Small entities include small businesses, small not-for-
profit enterprises, and small governmental jurisdictions.
    For purposes of assessing the impact of today's proposed action on
small entities, small entity is defined as: (1) A small business whose
parent company has no more than 1,500 employees, that is primarily
engaged in refining crude petroleum into refined petroleum as defined
by NAICS code 32411 (as defined by Small Business Administration size
standards); (2) a small governmental jurisdiction that is a government
of a city, county, town, school district, or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. Our analyses
indicate that the proposed amendments will not increase the costs
associated with the final rule and may decrease costs. Therefore, no
adverse economic impacts are expected for any small or large entity. We
continue to be interested in the potential impacts of the proposed rule
on small entities and welcome comments on issues related to such
impacts.

D. Unfunded Mandates Reform Act

    This rule contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. It does not contain a Federal mandate that

[[Page 78534]]

may result in expenditures of $100 million or more for State, local,
and tribal governments, in the aggregate, or to the private sector in
any one year. The costs of the proposed amendments would not increase
costs associated with the final rule. Therefore, this rule is not
subject to the requirements of sections 202 and 205 of the UMRA.
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. The proposed
amendments contain no requirements that apply to such governments, and
impose no obligations upon them.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled Federalism (64 FR 43255, August 10,
1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
    This proposed rule does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. They do not modify existing
responsibilities or create new responsibilities among EPA regional
offices, States, or local enforcement agencies. Thus, Executive Order
13132 does not apply to this rule.
    In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials.

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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). The proposed
amendments impose no requirements on tribal governments. Thus,
Executive Order 13175 does not apply to this action.
    EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

    EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997)
as applying to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the
Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it is based
solely on technology performance.

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

    This proposed rule is not a ``significant energy action'' as
defined in Executive Order 13211 (66 FR 28355, May 22, 2001) because it
is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. The proposed amendments would not
increase the level of energy consumption required for the final rule
and may decrease energy requirements.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113, 15 U.S.C. 272 note) directs EPA
to use voluntary consensus standards (VCS) in its regulatory
activities, unless to do so would be inconsistent with applicable law
or otherwise impractical. VCS are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by VCS bodies. NTTAA directs
EPA to provide Congress, through OMB, explanations when the Agency
decides not to use available and applicable VCS.
    This proposed rulemaking involves technical standards. EPA proposes
to use the following VCS for determining the higher heating value of
fuel fed to process heaters: ASTM D240-02 (Reapproved 2007), ``Standard
Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb
Calorimeter''; ASTM D1826-94 (Reapproved 2003), ``Standard Test Method
for Calorific (Heating) Value of Gases in Natural Gas Range by
Continuous Recording Calorimeter''; ASTM D4809-06, ``Standard Test
Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb
Calorimeter (Precision Method)''; ASTM D4891-89 (reapproved 2006),
``Standard Test Method for Heating Value of Gases in Natural Gas Range
by Stoichiometric Combustion''; ASTM D1945-03, ``Standard Method for
Analysis of Natural Gas by Gas Chromatography''; and ASTM D1946-90
(reapproved 2006), ``Standard Method for Analysis of Reformed Gas by
Gas Chromatography.''
    The EPA also proposes to use the following VCS as acceptable
alternatives to Methods 2, 2A, 2B, 2C, or 2D for conducting relative
accuracy evaluations of fuel gas flow monitors: American Society of
Mechanical Engineers (ASME) MFC-3M-1989 (Reaffirmed 1995),
``Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and
Venturi''; ASME MFC-4M-1986 (Reaffirmed 2008), ``Measurement of Gas
Flow by Turbine Meters''; ASME MFC-5M-1986 (Reaffirmed 2006),
``Measurement of Liquid Flow in Closed Conduits Using Transit-Time
Ultrasonic Flowmeters''; ASME MFC-6M-1988 (Reaffirmed 2005),
``Measurement of Fluid Flow in Pipes Using Vortex Flowmeters''; ASME
MFC-7M-1987 (Reaffirmed 2006), ``Measurement of Gas Flow by Means of
Critical Flow Venturi Nozzles''; and ASME MFC-9M-1988 (Reaffirmed
2006), ``Measurement of Liquid Flow in Closed Conduits by Weighing
Method.''
    EPA proposes to use the following VCS as acceptable alternatives to
EPA Method 15A and 16A for conducting relative accuracy evaluations of
monitors for reduced sulfur compounds, total sulfur compounds, and
H2S: ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses.'' The EPA proposes to use the following VCS as acceptable
alternatives to EPA Method 16A for analysis of total sulfur samples:
ASTM D4468-85 (Reapproved 2006), ``Standard Test Method for Total
Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry''; and ASTM D5504-08, ``Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Chemiluminescence.''
    EPA proposes to use the following VCS as acceptable alternatives to
Method 18 for relative accuracy evaluations of gas composition
analyzers for gas-fired process heaters: ASTM D1945-03, Standard Method
for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90
(reapproved 2006), ``Standard Method for Analysis of Reformed Gas by
Gas Chromatography''; ASTM D6429-99 (reapproved 2004), ``Standard Test
Method for Determination of Gaseous Organic Compounds by Direct
Interface Gas Chromatography-Mass Spectrometry''; and ASTM D6420-99

[[Page 78535]]

(reapproved 2004), ``Standard Test Method for Determination of Gaseous
Organic Compounds by Direct Interface Gas Chromatography-Mass
Spectrometry (GC/MS).'' However, ASTM D6420-99 is a suitable
alternative to Method 18 only where:
    (1) The target compound(s) are those listed in Section 1.1 of ASTM
D6420-99, and
    (2) The target concentration is between 150 parts per billion by
volume and 100 ppmv.
    For target compound(s) not listed in Section 1.1 of ASTM D6420-99,
but potentially detected by mass spectrometry, the regulation specifies
that the additional system continuing calibration check after each run,
as detailed in Section 10.5.3 of the ASTM method, must be followed,
met, documented, and submitted with the data report even if there is no
moisture condenser used or the compound is not considered water
soluble. For target compound(s) not listed in Section 1.1 of ASTM
D6420-99, and not amenable to detection by mass spectrometry, ASTM
D6420-99 does not apply.
    These above-listed VCS are incorporated by reference (see Sec.
60.17).
    The EPA also proposes to use American Gas Association
``Transmission Measurement Commenter Report No. 7 (Second Revision,
April 1996),'' and American Petroleum Institute's ``Manual of Petroleum
Measurement Standards, Fifth Edition, August 2005, Chapter 22, Testing
Protocol, Section 2, Differential Pressure Flow Measurement Devices,''
for conducting relative accuracy evaluations of fuel gas flow monitors;
Gas Processor Association (GPA) Standard 2261-00, ``Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography,'' for
relative accuracy evaluations of gas composition analyzers for gas-
fired process heaters; and GPA 2172-96, ``Calculation of Gross Heating
Value, Relative Density and Compressibility Factor for Natural Gas
Mixtures from Compositional Analysis,'' for determining the higher
heating value of fuel fed to process heaters. These methods are also
incorporated by reference (see Sec.  60.17).
    While the Agency has identified five VCS as being potentially
applicable to this rule, we have decided not to use these VCS in this
rulemaking. The use of these VCS would have been impractical because
they do not meet the objectives of the standards cited in this rule.
See the docket for this rule for the reasons for these determinations.
    EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
regulation.
    Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may
apply to EPA for permission to use alternative test methods or
alternative monitoring requirements in place of any required testing
methods, performance specifications, or procedures in the final rule
and amendments.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. The proposed amendments are either clarifications or
compliance alternatives which will neither increase or decrease
environmental protection.

List of Subjects in 40 CFR Part 60

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

    Dated: December 12, 2008.
Stephen L. Johnson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as follows:

PART 60--[AMENDED]

    1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart A--[Amended]

    2. Section 60.17 is amended by:
    a. Revising paragraphs (a)(68) and (a)(84);
    b. Adding paragraphs (a)(93) through (a)(99);
    c. Adding paragraph (c)(2);
    d. Revising paragraph (h)(4) and adding paragraphs (h)(5) through
(h)(10);
    e. Adding paragraph (m)(2) and (m)(3); and
    f. Adding paragraph (o) to read as follows:

Sec.  60.17  Incorporations by reference.

* * * * *
    (a) * * *
    (68) ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec.  60.107a(e)(3)(v),
60.335(b)(10)(ii), 60.4415(a)(1)(ii).
* * * * *
    (84) ASTM D6420-99 (Reapproved 2004) Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, IBR approved for Sec.
60.107a(d)(4)(ii) of subpart Ja and table 2 of subpart JJJJ of this
part.
* * * * *
    (93) ASTM D240-02, (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR
approved for Sec.  60.107a(d)(7)(i) of subpart Ja of this part.
    (94) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, IBR approved for Sec.  60.107a(d)(7)(ii) of
subpart Ja of this part.
    (95) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec.  60.107a(d)(7)(iii) of subpart Ja of this part.
    (96) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, IBR approved for Sec.  60.107a(d)(7)(iv) of subpart Ja of
this part.
    (97) ASTM D5504-08, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec.  60.107a(e)(3)(v) of
subpart Ja of this part.
    (98) ASTM D1945-03, Standard Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for

[[Page 78536]]

Sec.  60.107a(d)(4)(i) of subpart Ja of this part.
    (99) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis
of Reformed Gas by Gas Chromatography, IBR approved for Sec.
60.107a(d)(4)(iii) of subpart Ja of this part.
* * * * *
    (c) * * *
    (2) Manual of Petroleum Measurement Standards, Fifth Edition,
Chapter 22--Testing Protocol, Section 2, Differential Pressure Flow
Measurement Devices, August 2005, IBR approved for Sec.
60.107a(d)(5)(viii) of subpart Ja of this part.
* * * * *
    (h) * * *
    (4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [part
10, Instruments and Apparatus], IBR approved for Sec.  60.106(e)(2) of
subpart J, Sec. Sec.  60.104a(d)(3), (d)(5), (d)(6), (h)(3), (h)(4),
(h)(5), (i)(3), (i)(4), (i)(5), (j)(3), and (j)(4), 60.105a(d)(4),
(f)(2), (f)(4), (g)(2), and (g)(4), 60.106a(a)(1)(iii), (a)(2)(iii),
(a)(2)(v), (a)(2)(viii), (a)(3)(ii), and (a)(3)(v), and
60.107a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii), (c)(2), (c)(4), (d)(2),
(e)(1)(ii), (e)(2)(ii), and (e)(3)(ii) of subpart Ja, tables 1 and 3 of
subpart EEEE, tables 2 and 4 of subpart FFFF, table 2 of subpart JJJJ,
and Sec. Sec.  60.4415(a)(2) and 60.4415(a)(3) of subpart KKKK of this
part.
    (5) ASME MFC-3M-1989 (Reaffirmed 1995), Measurement of Fluid Flow
in Pipes Using Orifice, Nozzle, and Venturi, IBR approved for Sec.
60.107a(d)(5)(i) of subpart Ja of this part.
    (6) ASME MFC-4M-1986 (Reaffirmed 2008), Measurement of Gas Flow by
Turbine Meters, IBR approved for Sec.  60.107a(d)(5)(ii) of subpart Ja
of this part.
    (7) ASME-MFC-5M-1986 (Reaffirmed 2006), Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR
approved for Sec.  60.107a(d)(5)(iii) of subpart Ja of this part.
    (8) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow
in Pipes Using Vortex Flowmeters, IBR approved for Sec.
60.107a(d)(5)(iv) of subpart Ja of this part.
    (9) ASME MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.
60.107a(d)(5)(v) of subpart Ja of this part.
    (10) ASME MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid Flow
in Closed Conduits by Weighing Method, IBR approved for Sec.
60.107a(d)(5)(vi) of subpart Ja of this part.
* * * * *
    (m) * * *
    (2) Gas Processors Association Standard 2172-96, Calculation of
Gross Heating Value, Relative Density and Compressibility Factor for
Natural Gas Mixtures from Compositional Analysis, IBR approved for
Sec.  60.107a(d)(7)(v) of subpart Ja of this part.
    (3) Gas Processors Association Standard 2261-00, Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR
approved for Sec.  60.107a(d)(4)(iv) of subpart Ja of this part.
* * * * *
    (o) The following American Gas Association material is available
for purchase from the following address: ILI Infodisk, 610 Winters
Avenue, Paramus, New Jersey 07652:
    (1) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters, Second Revision,
April 1996, IBR approved for Sec.  60.107a(d)(5)(vii) of subpart Ja of
this part.
    (2) [Reserved]

Subpart J--[Amended]

    3. Section 60.100 is amended by:
    a. Redesignating paragraph (e) as (f); and
    b. Adding a new paragraph (e) to read as follows:

Sec.  60.100  Applicability, designation of affected facility, and
reconstruction.

* * * * *
    (e) Owners or operators may choose to comply with the applicable
provisions of subpart Ja of this part to satisfy the requirements of
this subpart for an affected facility.
* * * * *
    4. Section 60.106 is amended by revising paragraph (c)(1) to read
as follows:

Sec.  60.106  Test methods and procedures.

* * * * *
    (c) * * *
    (1) The allowable emission rate (Es) of PM shall be
computed for each run using the following equation:

Es = F + A (H/Rc)

Where:

Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke
burn-off in catalyst regenerator.
F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in
catalyst regenerator.
A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 lb/
million Btu).
H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million
Btu/hr).
Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr).
* * * * *

Subpart Ja--[Amended]

    5. Section 60.100a is amended by revising paragraph (c)
introductory text and paragraph (c)(1) to read as follows:

Sec.  60.100a  Applicability, designation of affected facility, and
reconstruction.

* * * * *
    (c) For all affected facilities other than flares, the provisions
in Sec.  60.14 regarding modification apply. As provided in Sec.
60.14(f), the special provisions set forth under this subpart shall
supersede the provisions in Sec.  60.14 with respect to flares. For the
purposes of this subpart, a modification to a flare occurs as provided
in paragraphs (c)(1) or (2) of this section.
    (1) Any new piping from a refinery process unit or fuel gas system
is physically connected to the flare (e.g., for direct emergency relief
or some form of continuous or intermittent venting). However, the
connections described in paragraphs (c)(1)(i) through (iv) of this
section are not considered modifications of a flare.
    (i) Connections made to install monitoring systems to the flare.
    (ii) Connections made to install a flare gas recovery system.
    (iii) 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.
    (iv) 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.
* * * * *
    6. Section 60.101a is amended by:
    a. Adding, in alphabetical order, definitions of ``Air preheat,''
``Co-fired process heater,'' ``Corrective action,'' ``Corrective action
analysis,'' ``Flare gas recovery system,'' ``Forced draft process
heater,'' ``Natural draft process heater,'' and ``Root cause
analysis''; and
    b. Revising the definitions of ``Delayed coking unit,''
``Flexicoking unit,'' ``Fluid coking unit,'' ``Fuel gas,'' ``Petroleum
refinery,'' ``Process upset gas,'' ``Refinery process unit'' and
``Sulfur recovery plant'' to read as follows:

Sec.  60.101a  Definitions.

    Air preheat means a device used to heat the air supplied to a
process heater generally by use of a heat exchanger to recover the
latent heat of exhaust gas from the process heater.

[[Page 78537]]

    Co-fired process heater means a process heater that employs burners
that are designed to be supplied by both gaseous and liquid fuels.
    Corrective action means the design, operation, and maintenance
changes consistent with good engineering practice to reduce or
eliminate the likelihood of recurrence of an event identified by a root
cause analysis as having caused a discharge of gases to an affected
flare in excess of the flow rate threshold in Sec.  60.103a(a)(4) or
the discharge of gases from an affected fuel gas combustion device or
sulfur recovery plant in excess of the applicable SO2
threshold in Sec.  60.103a(b).
    Corrective action analysis means a description of all reasonable
interim and long-term measures, if any, that are available, and an
explanation of why the selected corrective action is the best
alternative, including any consideration of cost-effectiveness.
    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 consists of the coke drums and
associated fractionator.
* * * * *
    Flare gas recovery system means a system of one or more
compressors, piping, and associated water seal, rupture disk, or
similar device used to divert gas from the flare and direct the gas to
the fuel gas system or to a fuel gas combustion device other than a
flare.
    Flexicoking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced and then gasified to produce a
synthetic fuel gas.
* * * * *
    Fluid coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system. The
fluid coking unit includes the coking reactor, the coking burner, and
equipment for controlling air pollutant emissions and for heat recovery
on the fluid coking burner exhaust vent.
    Forced draft process heater means a process heater in which the
combustion air is supplied under positive pressure produced by a fan at
any location in the inlet air line prior to the point where the
combustion air enters the process heater or air preheat.
* * * * *
    Fuel gas means any gas which is generated at a petroleum refinery
and which is combusted. Fuel gas includes natural gas when natural gas
is combusted in any proportion with a gas generated at a refinery. Fuel
gas does not include gases generated by catalytic cracking unit
catalyst regenerators, coke calciners (used to make anode grade coke)
and fluid coking burners, but does include gases from flexicoking unit
gasifiers and other gasifiers. Fuel gas does not include vapors that
are collected and combusted to comply with the wastewater provisions in
Sec.  40 CFR 61.343 though 61.348, 40 CFR 63.647 or the marine tank
vessel loading provisions in 40 CFR 63.652 or 40 CFR 63.651.
    Natural draft process heater means any process heater in which the
combustion air is supplied under ambient pressure without the use of an
inlet air (forced draft) fan. For the purposes of this subpart, a
natural draft process heater is any process heater that is not a forced
draft process heater.
* * * * *
    Petroleum refinery means any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, asphalt (bitumen) or other products through distillation of
petroleum or through redistillation, cracking, or reforming of
unfinished petroleum derivatives. A facility that produces only oil
shale or tar sands-derived crude oil for further processing at a
petroleum refinery using only solvent extraction and/or distillation to
recover diluent is not a petroleum refinery.
* * * * *
    Process upset gas means any gas generated by a petroleum refinery
process unit as a result of start-up, shutdown, upset or malfunction.
* * * * *
    Refinery process unit means any segment of the petroleum refinery
in which a specific processing operation is conducted, including but
not limited to distillation, cracking, coking, reforming, alkylation,
isomerization, coke gasification, product loading, sulfur recovery, and
wastewater treatment.
    Root cause analysis means an assessment to determine the primary
cause and any other significant contributing cause(s), as determined
through a process of investigation, of discharge of gases to an
affected flare in excess of the flow rate threshold in Sec.
60.103a(a)(4) or in excess of the applicable SO2 threshold
in Sec.  60.103a(b)(1), or the discharge of gases from an affected fuel
gas combustion device or sulfur recovery plant in excess of the
applicable SO2 thresholds in Sec.  60.103a(b)(2) and (3).
* * * * *
    Sulfur recovery plant means all refinery process units which
recover sulfur from H2S and/or SO2 from a common
source of sour gas at a petroleum refinery. The sulfur recovery plant
also includes sulfur pits used to store the recovered sulfur product,
but it does not include secondary sulfur storage vessels downstream of
the sulfur pits. For example, a Claus sulfur recovery plant includes:
Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits,
and, if present, oxidation or reduction control systems, or
incinerator, thermal oxidizer, or similar combustion device. Multiple
sulfur recovery plants are a single affected facility only when the
units share the same source of sour gas. Sulfur recovery plants that
receive source gas from completely segregated sour gas treatment
systems are separate affected facilities.
    7. Section 60.102a is amended by:
    a. Revising paragraph (a);
    b. Revising paragraph (f)(1)(ii);
    c. Revising paragraph (g) introductory text;
    d. Revising paragraph (g)(1)(ii);
    e. Revising paragraph (g)(2);
    f. Removing paragraph (g)(3); and
    g. Revising paragraph (i) to read as follows:

Sec.  60.102a  Emissions limitations.

    (a) Each owner or operator that is subject to the requirements of
this subpart shall comply with the emissions limitations in paragraphs
(b) through (i) of this section on and after the date on which the
initial performance test, required by Sec.  60.8, is completed, but not
later than 60 days after achieving the maximum production rate at which
the affected facility will be operated, or 180 days after initial
startup, whichever comes first.
* * * * *
    (f) * * *
    (1) * * *
    (ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere in excess of
300 ppmv of reduced sulfur compounds and 10 ppmv of hydrogen sulfide
(H2S), each calculated as ppmv SO2 (dry basis) at
0 percent excess air; or
* * * * *
    (g) Each owner or operator of an affected fuel gas combustion
device shall comply with the emission limits in paragraphs (g)(1) and
(2) of this section.

[[Page 78538]]

    (1) * * *
    (ii) The owner or operator shall not burn in any fuel gas
combustion device any fuel gas that contains H2S in excess
of 162 ppmv determined hourly on a 3-hour rolling average basis and
H2S in excess of 60 ppmv determined daily on a 365
successive calendar day rolling average basis. An owner or operator of
a modified flare that needs to install additional amine scrubbing and
amine stripping columns to comply with the long-term H2S
limit shall comply with the 60 ppmv 365-day H2S
concentration limit no later than 2 years after that flare becomes an
affected facility subject to this subpart.
    (2) For each process heater with a rated capacity of greater than
40 million British thermal units per hour (MMBtu/hr) on a higher
heating value basis, the owner or operator shall not discharge to the
atmosphere any emissions of NOX in excess of the applicable
limits in paragraphs (g)(2)(i) through (g)(2)(iv).
    (i) For each newly constructed, modified, or reconstructed natural
draft process heater:
    (A) 40 ppmv (dry basis, corrected to 0 percent excess air)
determined daily on a 365 successive operating day rolling average
basis; or
    (B) 0.035 pounds per million British thermal units (lb/MMBtu)
determined daily on a 365 successive operating day rolling average
basis.
    (ii) For each new forced draft process heater:
    (A) 40 ppmv (dry basis, corrected to 0 percent excess air)
determined daily on a 365 successive operating day rolling average
basis; or
    (B) 0.035 lb/MMBtu determined daily on a 365 successive operating
day rolling average basis.
    (iii) For each modified or reconstructed forced draft process
heater:
    (A) 60 ppmv (dry basis, corrected to 0 percent excess air)
determined daily on a 365 successive operating day rolling average
basis; or
    (B) 0.055 lb/MMBtu determined daily on a 365 successive operating
day rolling average basis.
    (iv) For each co-fired process heater:
    (A) 150 ppmv (dry basis, corrected to 0 percent excess air)
determined daily on a 365 successive operating day rolling average
basis (applicable only when the process heater is being co-fired); or
    (B) The daily average emission limit calculated using Equation 3 of
this section:
[GRAPHIC] [TIFF OMITTED] TP22DE08.000

Where:

ENOx, hour = Daily average emission rate of
NOX, lb/MMBtu (higher heating value basis);
Qgas = Daily average volumetric flow rate of fuel gas,
scf/hr;
Qoil = Daily average volumetric flow rate of fuel oil,
scf/hr;
HHVgas = Daily average higher heating value of gas fired
to the process heater, MMBtu/scf; and
HHVoil = Daily average higher heating value of fuel oil
fired to the process heater, MMBtu/scf.
* * * * *
    (i) For a modified or reconstructed process heater that lacks
sufficient space to accommodate combustion modification-based
technology, or for a co-fired process heater, the owner or operator may
petition the Administrator within 90 days after initial startup of the
process heater for approval of a NOX emissions limit which
shall apply specifically to that affected facility. The petition shall
include sufficient and appropriate data, as determined by the
Administrator, to allow the Administrator to confirm that the process
heater is unable to comply with the applicable NOX emission
limit in paragraph (g)(2) of this section. If the petition is approved
by the Administrator, a facility-specific NOX emissions
limit will be established at the NOX emission level
achievable when the affected facility is operating in a manner that the
Administrator determines to be consistent with minimizing
NOX emissions. At a minimum, the petition shall contain the
information described in paragraphs (i)(1) through (4) of this section.
    (1) The design and dimensions of the process heater, evaluation of
available combustion modification-based technology, description of fuel
gas and, if applicable, fuel oil characteristics and combustion
conditions, and any other data determined by the Administrator as
appropriate.
    (2) An explanation of how the data in paragraph (i)(1) demonstrate
that ultra-low NOX burners or other means cannot be used to
meet the applicable emission limit in paragraph (g)(2) of this section.
    (3) Results of a performance test conducted under representative
conditions using the applicable methods specified in Sec.  60.104a(i)
to demonstrate the performance of the technology the owner or operator
will use to minimize NOX emissions.
    (4) The means by which the owner or operator will document
continuous compliance with the site-specific emissions limit.
    8. Section 60.103a is amended by:
    a. Revising paragraph (a) introductory text and paragraphs (a)(1),
(a)(4), (a)(5), and (a)(6);
    b. Revising paragraph (b);
    c. Redesignating paragraph (c) as paragraph (d); and
    d. Adding a new paragraph (c) to read as follows:

Sec.  60.103a  Work practice standards.

    (a) Each owner or operator that operates a flare that is subject to
this subpart shall develop and implement a written flare management
plan. The owner or operator of a newly constructed or reconstructed
flare must develop and implement the flare management plan by no later
than the date that flare becomes an affected flare subject to this
subpart. The owner or operator of a modified flare must develop and
implement the flare management plan by no later than 18 months after
the flare becomes an affected flare subject to this subpart unless the
owner or operator of the affected flare commits in writing to install a
flare gas recovery system, in which case the owner or operator of a
modified flare must develop and implement the flare management plan by
no later than 2 years after the flare becomes an affected flare subject
to this subpart. The plan must include:
    (1) A listing of all refinery process units and fuel gas systems
connected to the flare for each affected flare and an assessment of
whether discharges to affected flares from these process units and fuel
gas systems can be minimized;
* * * * *
    (4) Procedures to conduct a root cause analysis as soon as possible
but no later than 45 days after any discharge to the flare in excess of
14,160 standard cubic meters (m\3\) (500,000 standard cubic feet (scf))
in any 24-hour period. The first root cause analysis and corrective
action analysis for a modified flare must be conducted no later than
the first discharge triggering a root cause

[[Page 78539]]

analysis that occurs after the flare has been an affected flare subject
to this subpart for 18 months, unless the owner or operator of the
affected flare commits in writing to install a flare gas recovery
system, in which case the flow rate root cause analysis for a modified
flare must be conducted no later than the first discharge triggering a
flow rate root cause analysis that occurs after the flare has been an
affected flare subject to this subpart for 2 years;
    (5) Procedures to conduct a corrective action analysis and
implement corrective actions as soon as possible but no later than 45
days after a discharge exceeding the flow rate threshold in paragraph
(a)(4) of this section to minimize the recurrence of similarly caused
events based on the finding of the root cause analysis required under
paragraph (a)(4) of this section; and
    (6) Procedures to reduce flaring in cases of fuel gas imbalance
(i.e., excess fuel gas for the refinery's energy needs).
    (b) Each owner or operator that operates a fuel gas combustion
device or sulfur recovery plant subject to this subpart shall conduct a
root cause analysis and a corrective action analysis under each of the
conditions specified in paragraphs (b)(1) through (3) of this section
and implement corrective actions to minimize the recurrence of a
similarly caused event. If a single continuous discharge causes
emissions to exceed a level specified in paragraphs (b)(1) through (3)
of this section for 2 or more consecutive 24-hour periods, a single
root cause analysis may be conducted. For any root cause analysis and
corrective action analysis performed, and for any corrective action
taken, the owner or operator shall, as soon as possible but no later
than 45 days after the discharge, record the identification of the
affected facility, the date and duration of the discharge, a
description of the root cause of the discharge as identified by the
root cause analysis, results of the corrective action analysis, and the
corrective action taken as a result of the root cause analysis, as
specified in Sec.  60.108a(c)(6).
    (1) For a flare, conduct a root cause analysis and a corrective
action analysis and take corrective action each time the SO2
emissions exceed 227 kilograms (kg) (500 pounds (lb)) in any 24-hour
period. The first root cause analysis and corrective action analysis
for a modified flare must be conducted no later than the first
discharge of SO2 triggering a root cause analysis that
occurs after the flare has been an affected flare subject to this
subpart for 18 months, unless the owner or operator of the affected
flare commits in writing to install a flare gas recovery system, in
which case the root cause analysis for a modified flare must be
conducted no later than the first discharge of SO2
triggering a root cause analysis that occurs after the flare has been
an affected flare subject to this subpart for 2 years.
    (2) For any fuel gas combustion device other than a flare, conduct
a root cause analysis and a corrective action analysis and take
corrective action for each exceedance of an applicable short-term
emissions limit in Sec.  60.102a(g)(1) if the SO2 discharge
to the atmosphere is 227 kg (500 lb) greater than the amount that would
have been emitted if the emissions limits had been met during the
period of the exceedance.
    (3) For a sulfur recovery plant, conduct a root cause analysis and
a corrective action analysis and take corrective action when the daily
SO2 emissions are more than 227 kg (500 lb) greater than the
amount that would have been emitted if the SO2 or reduced
sulfur concentration was equal to the applicable emission limit in
Sec.  60.102a(f)(1) or (2) for the entire 24-hour period.
    (c) When an owner or operator implements corrective action(s) as
specified by paragraphs (a)(5) and (b) of this section, the owner or
operator shall, no later than 45 days following the discharge, record a
description of the action(s) and, if not already completed, a schedule
for its (their) implementation, including proposed commencement and
completion dates. If an owner or operator concludes that corrective
action should not be conducted, the owner or operator shall record and
explain the basis for that conclusion no later than 45 days following
the discharge.
* * * * *
    9. Section 60.104a is amended by:
    a. Revising paragraphs (d)(4)(ii), (d)(4)(iii), (d)(4)(v), and
(d)(8);
    b. Adding paragraph (e)(3); and
    c. Revising paragraph (h)(5)(iv) to read as follows:

Sec.  60.104a  Performance tests.

* * * * *
    (d) * * *
    (4) * * *
    (ii) The emissions rate of PM (EPM) is computed for each
run using Equation 4 of this section:
[GRAPHIC] [TIFF OMITTED] TP22DE08.001

Where:

E = Emission rate of PM, g/kg, lb per 1,000 lb (lb/1,000 lb) of coke
burn-off;
cs = Concentration of total PM, grams per dry standard
cubic meter (g/dscm), gr/dscf;
Qsd = Volumetric flow rate of effluent gas, dry standard
cubic meters per hour, dry standard cubic feet per hour;
Rc = Coke burn-off rate, kilograms per hour (kg/hr), lb
per hour (lb/hr) coke; and
K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).

    (iii) The coke burn-off rate (Rc) is computed for each
run using Equation 5 of this section:
[GRAPHIC] [TIFF OMITTED] TP22DE08.002

Where:Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emissions control or
energy recovery system that burns auxiliary fuel, dry standard cubic
meters per minute (dscm/min), dry standard cubic feet per minute
(dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or
fluid coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air
to FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator
or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration in FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis);
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis);
%Ooxy = O2 concentration in O2 enriched air
stream inlet to the FCCU regenerator or fluid coking burner, percent
by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
* * * * *
    (v) For subsequent calculations of coke burn-off rates or exhaust
gas flow rates, the volumetric flow rate of Qr is calculated
using average exhaust gas

[[Page 78540]]

concentrations as measured by the monitors required in Sec.
60.105a(b)(2), if applicable, using Equation 6 of this section:
[GRAPHIC] [TIFF OMITTED] TP22DE08.003

Where:

Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emission control or
energy recovery system that burns auxiliary fuel, dscm/min (dscf/
min);
Qa = Volumetric flow rate of air to FCCU regenerator or
fluid coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air
to FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator
or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis). When no auxiliary fuel is
burned and a continuous CO monitor is not required in accordance
with Sec.  60.105a(g)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis); and
%Ooxy = O2 concentration in O2
enriched air stream inlet to the FCCU regenerator or fluid coking
burner, percent by volume (dry basis).
* * * * *
    (8) The owner or operator shall adjust PM, NOX,
SO2, and CO pollutant concentrations to 0 percent excess air
or 0 percent O2 using Equation 7 of this section:
[GRAPHIC] [TIFF OMITTED] TP22DE08.004

Where:

Cadj = pollutant concentration adjusted to 0 percent
excess air or O2, parts per million (ppm) or g/dscm;
Cmeas = pollutant concentration measured on a dry basis,
ppm or g/dscm;
20.9c = 20.9 percent O2-0.0 percent
O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry
basis, percent.

    (e) * * *
    (3) Compute the site-specific limit using Equation 8 of this
section:
[GRAPHIC] [TIFF OMITTED] TP22DE08.005

Where:

Opacity limit = Maximum permissible hourly average opacity, percent,
or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the
source test runs, percent; and
PMEmRst = PM emission rate measured during the source
test, lb/1,000 lb coke burn.
* * * * *
    (h) * * *
    (5) * * *
    (iv) The owner or operator shall use Equation 7 of this section to
adjust pollutant concentrations to 0 percent O2 or 0 percent
excess air.
* * * * *
    10. Section 60.105a is amended by:
    a. Revising paragraph (b) introductory text and paragraphs
(b)(2)(i) and (b)(2)(ii); and
    b. Revising paragraph (i)(5) to read as follows:

Sec.  60.105a  Monitoring of emissions and operations for fluid
catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *
    (b) Control device operating parameters. Each owner or operator of
a FCCU or FCU subject to the PM per coke burn-off emissions limit in
Sec.  60.102a(b)(1) shall comply with the requirements in paragraphs
(b)(1) and (2) of this section.
* * * * *
    (2) * * *
    (i) The owner or operator shall install, operate, and maintain each
monitor according to Performance Specifications 3 and 4 of Appendix B
to part 60.
    (ii) The owner or operator shall conduct performance evaluations of
each CO2, O2, and CO monitor according to the
requirements in Sec.  60.13(c) and Performance Specifications 3 and 4
of Appendix B to part 60. The owner or operator shall use Method 3 of
Appendix A-3 to part 60 and Method 10, 10A, or 10B of Appendix A-4 to
part 60 for conducting the relative accuracy evaluations.
* * * * *
    (i) * * *
    (5) All rolling 7-day periods during which the average
concentration of SO2 as measured by the SO2 CEMS
under Sec.  60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods
during which the average concentration of SO2 as measured by
the SO2 CEMS exceeds 25 ppmv.
* * * * *
    11. Section 60.107a is amended by:
    a. Revising the section heading;
    b. Revising paragraph (a)(2)(i);
    c. Revising paragraph (c) introductory text and paragraphs (c)(1)
and (c)(6);
    d. Redesignating paragraphs (d), (e), and (f) as paragraphs (e),
(f), and (g), respectively;
    e. Adding a new paragraph (d);
    f. Revising newly redesignated paragraph (e);
    g. Revising newly redesignated paragraph (f) introductory text; and
    h. Revising newly redesignated paragraphs (g)(3) and (g)(4) to read
as follows:

Sec.  60.107a  Monitoring of emissions and operations for process
heaters and other fuel gas combustion devices.

    (a) * * *
    (2) * * *
    (i) The owner or operator shall install, operate, and maintain each
H2S monitor according to Performance Specification 7 of
Appendix B to part 60. The span value for this instrument is 300 ppmv
H2S.
* * * * *
    (c) Process heaters complying with the NOX
concentration-based limit. The owner or operator of a process heater
subject to the NOX emission limit in Sec.  60.102a(g)(2) and
electing to comply with the applicable emission limit in Sec.
60.102a(g)(2)(i)(A), (g)(2)(ii)(A), (g)(2)(iii)(A), or (g)(2)(iv)(A)
shall install, operate, calibrate, and maintain an instrument for
continuously monitoring and recording the concentration (dry basis, 0
percent excess air) of NOX emissions into the atmosphere
according to the requirements in paragraphs (c)(1) through (5) of this

[[Page 78541]]

section, except as provided in paragraph (c)(6) of this section. The
monitor must include an O2 monitor for correcting the data
for excess air.
    (1) The owner or operator shall install, operate, and maintain each
NOX monitor according to Performance Specification 2 of
Appendix B to part 60. The span value of this NOX monitor
must be between 2 and 3 times the applicable emission limit, inclusive.
* * * * *
    (6) The owner or operator of a process heater that has a rated
heating capacity of less than 100 MMBtu and is equipped with combustion
modification-based technology to reduce NOX emissions (i.e.,
low-NOX burners, ultra-low-NOX burners) may elect
to comply with the monitoring requirements in paragraphs (c)(1) through
(5) of this section or, alternatively, the owner or operator of such a
process heater shall conduct biennial performance tests, establish a
maximum excess oxygen concentration operating limit, and comply with
the O2 monitoring requirements in paragraphs (c)(3) through
(5) of this section to demonstrate compliance.
    (d) Process heaters complying with the NOX heating
value-based limit. The owner or operator of a process heater subject to
the NOX emissions limit in Sec.  60.102a(g)(2) and electing
to comply with the applicable emissions limit in Sec.
60.102a(g)(2)(i)(B), (g)(2)(ii)(B), or (g)(2)(iii)(B) shall install,
operate, calibrate, and maintain an instrument for continuously
monitoring and recording the concentration (dry basis, 0 percent excess
air) of NOX emissions into the atmosphere and shall
determine the F factor of the fuel gas stream no less frequently than
once per day according to the monitoring requirements in paragraphs
(d)(1) through (4) of this section. The owner or operator of a co-fired
process heater subject to the NOX emission limit in Sec.
60.102a(g)(2) and electing to comply with the heating value-based limit
in Sec.  60.102a(g)(2)(iv)(B) shall also install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording
the concentration (dry basis, 0 percent excess air) of NOX
emissions into the atmosphere according to the monitoring requirements
in paragraph (d)(1) of this section, an instrument for continuously
monitoring and recording the flow rate of the fuel oil and fuel gas fed
to the process heater according to the monitoring requirements in
paragraph (d)(5) and (6) of this section, and shall determine the
heating value of the fuel oil and fuel gas streams no less frequently
than once per day according to the monitoring requirements in paragraph
(d)(7) of this section.
    (1) The owner or operator shall install, operate, and maintain each
NOX monitor according to the requirements in paragraphs
(c)(1) through (5) of this section. The monitor must include an
O2 monitor for correcting the data for excess air.
    (2) Except as provided in paragraph (d)(3) of this section, the
owner or operator shall sample and analyze each fuel stream fed to the
process heater using the methods and equations in section 12.3.2 of
Method 19 of Appendix A-7 to part 60 to determine the F factor on a dry
basis. If a single fuel gas system provides fuel gas to several process
heaters, the F factor may be determined at a single location in the
fuel gas system provided it is representative of the fuel gas fed to
the affected process heater(s).
    (3) As an alternative to the requirements in paragraph (d)(2) of
this section, the owner or operator of a gas-fired process heater shall
install, operate, and maintain a gas composition analyzer and determine
the average F factor of the fuel gas using the factors in Table 1 of
this subpart and Equation 9 of this section. If a single fuel gas
system provides fuel gas to several process heaters, the F factor may
be determined at a single location in the fuel gas system provided it
is representative of the fuel gas fed to the affected process
heater(s).
[GRAPHIC] [TIFF OMITTED] TP22DE08.006

Where:

Fd = F factor on dry basis at 0% excess air.
Xi = mole or volume fraction of each component in the
fuel gas.
MEVi = molar exhaust volume, dry standard cubic feet per
mole (dscf/mol).
MHCi = molar heat content, Btu per mole (Btu/mol).
1,000,000 = unit conversion, Btu per MMBtu.

    (4) The owner or operator shall conduct performance evaluations of
each compositional monitor according to the requirements in Performance
Specification 9 of Appendix B to part 60. Method 18 of Appendix A-6 to
part 60 shall be used for conducting the relative accuracy evaluations.
The following methods are acceptable alternatives to EPA Method 18 of
Appendix A-2 to part 60:
    (i) ASTM D1945-03, Standard Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference-see Sec.  60.17);
    (ii) ASTM D6420-99 (Reapproved 2004) Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry (incorporated by reference-see Sec.
60.17);
    (iii) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis
of Reformed Gas by Gas Chromatography (incorporated by reference-see
Sec.  60.17); and
    (iv) Gas Processors Association Standard 2261-00, Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography
(incorporated by reference-see Sec.  60.17).
    (5) The owner or operator shall conduct performance evaluations of
each fuel gas flow monitor according to the requirements in Sec.
60.13(c) and Performance Specification 6 of Appendix B to part 60.
Method 2, 2A, 2B, 2C, or 2D of Appendix A-2 to part 60 shall be used
for conducting the relative accuracy evaluations. The following methods
are acceptable alternatives to EPA Method 2, 2A, 2B, 2C, or 2D of
Appendix A-2 to part 60:
    (i) ASME MFC-3M-1989 (Reaffirmed 1995), Measurement of Fluid Flow
in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference-
see Sec.  60.17);
    (ii) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by
Turbine Meters (incorporated by reference-see Sec.  60.17);
    (iii) ASME-MFC-5M-1985, (Reaffirmed 1994), Measurement of Liquid
Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
(incorporated by reference-see Sec.  60.17);
    (iv) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference-see Sec.  60.17);
    (v) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference-see
Sec.  60.17);
    (vi) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow
in Closed Conduits by Weighing Method (incorporated by reference-see
Sec.  60.17);
    (vii) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters Second Revision,
April 1996 (incorporated by reference-see Sec.  60.17); and
    (viii) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, First Edition, Chapter 22-Testing Protocol,
Section 2-Differential Pressure Flow Measurement Devices, August 2005
(incorporated by reference-see Sec.  60.17).
    (6) The owner or operator shall conduct install, operate, and
maintain each fuel oil flow monitor according to the manufacturer's
recommendations.

[[Page 78542]]

    (7) The owner or operator shall determine the higher heating value
of each fuel fed to the process heater using any of the applicable
methods included in paragraphs (d)(7)(i) through (v) of this section.
If a common fuel supply system provides fuel gas or fuel oil to several
process heaters, the higher heating value of the fuel in each fuel
supply system may be determined at a single location in the fuel supply
system provided it is representative of the fuel fed to the affected
process heater(s).
    (i) ASTM D240-02, (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
(incorporated by reference-see Sec.  60.17).
    (ii) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter (incorporated by reference-see Sec.  60.17).
    (iii) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)
(incorporated by reference-see Sec.  60.17).
    (iv) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion (incorporated by reference-see Sec.  60.17).
    (v) Gas Processors Association Standard 2172-96, Calculation of
Gross Heating Value, Relative Density and Compressibility Factor for
Natural Gas Mixtures from Compositional Analysis (incorporated by
reference--see Sec.  60.17).
    (8) The owner or operator of a process heater that has a rated
heating capacity of less than 100 MMBtu and is equipped with combustion
modification based technology to reduce NOX emissions (i.e.,
low-NOX burners or ultra-low NOX burners) may
elect to comply with the monitoring requirements in paragraphs (d)(1)
through (7) of this section or, alternatively, the owner or operator of
such a process heater shall conduct biennial performance tests,
establish a maximum excess oxygen concentration operating limit, and
comply with the O2 monitoring requirements in paragraphs
(c)(3) through (5) of this section to demonstrate compliance.
    (e) Sulfur monitoring for affected flares. The owner or operator of
an affected flare subject to Sec.  60.103a(b) shall determine reduced
sulfur compound concentrations in accordance with paragraph (e)(1) of
this section or total sulfur compound concentrations in accordance with
either paragraph (e)(2) or (3) of this section.
    (1) The owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring and recording the
concentration of reduced sulfur compounds in flare gas. The owner or
operator of a modified flare must install this instrument no later than
18 months after the flare becomes an affected flare subject to this
subpart unless the owner or operator of the affected flare commits in
writing to install a flare gas recovery system, in which case the owner
or operator of a modified flare must install this instrument no later
than 2 years after the flare becomes an affected flare subject to this
subpart.
    (i) The owner or operator shall install, operate, and maintain each
reduced sulfur compounds CEMS according to Performance Specification 5
of Appendix B to part 60.
    (ii) The owner or operator shall conduct performance evaluations of
each reduced sulfur compounds monitor according to the requirements in
Sec.  60.13(c) and Performance Specification 5 of Appendix B to part
60. The owner or operator shall use Method 15 or 15A of Appendix A-5 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 15A of Appendix A-5 to part 60.
    (iii) The owner or operator shall comply with the applicable
quality assurance procedures in Appendix F to part 60 for each reduced
sulfur monitor.
    (2) The owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring and recording the
concentration of total sulfur compounds in flare gas. The owner or
operator of a modified flare must install this instrument no later than
18 months after the flare becomes an affected flare subject to this
subpart unless the owner or operator of the affected flare commits in
writing to install a flare gas recovery system, in which case the owner
or operator of a modified flare must install this instrument no later
than 2 years after the flare becomes an affected flare subject to this
subpart.
    (i) The owner or operator shall install, operate, and maintain each
total sulfur compounds CEMS according to Performance Specification 5 of
Appendix B to part 60.
    (ii) The owner or operator shall conduct performance evaluations of
each total sulfur compounds monitor according to the requirements in
Sec.  60.13(c) and Performance Specification 5 of Appendix B to part
60. The owner or operator shall use Method 16 or 16A of Appendix A-6 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 16A of Appendix A-6 to part 60.
    (iii) The owner or operator shall comply with the applicable
quality assurance procedures in Appendix F to part 60 for each reduced
sulfur monitor.
    (3) The owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring and recording the
concentration of H2S in flare gas according to the
requirements in paragraphs (e)(3)(i) through (iii) of this section and
shall collect and analyze samples of flare gas and calculate total
sulfur concentrations as specified in paragraphs (e)(3)(iv) through
(ix) of this section. The owner or operator of a modified flare must
install this H2S monitor no later than 18 months after the
flare becomes an affected flare subject to this subpart unless the
owner or operator of the affected flare commits in writing to install a
flare gas recovery system, in which case the owner or operator of a
modified flare must install this instrument no later than 2 years after
the flare becomes an affected flare subject to this subpart.
    (i) The owner or operator shall install, operate, and maintain each
H2S monitor according to Performance Specification 7 of
Appendix B to part 60. The span value must be between 1 and 5 percent
(by volume) inclusive. A single dual range H2S monitor may
be used to comply with the requirements of this paragraph and paragraph
(a)(2) of this section provided the applicable span specifications are
met.
    (ii) The owner or operator shall conduct performance evaluations of
each H2S monitor according to the requirements in Sec.
60.13(c) and Performance Specification 7 of Appendix B to part 60. The
owner or operator shall use Method 11, 15, or 15A of Appendix A-5 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 15A of Appendix A-5 to part 60.
    (iii) The owner or operator shall comply with the applicable
quality assurance procedures in Appendix F to part 60 for each
H2S monitor.
    (iv) In the first 10 operating days after the flare may be required
to perform a root cause analysis under Sec.  60.103a(b)(1), the owner
or operator

[[Page 78543]]

shall collect representative daily samples of the flare gas. The
samples may be grab samples or integrated samples. The owner or
operator shall take subsequent representative daily samples at least
once per week or as required in paragraph (e)(3)(vii) of this section.
    (v) The owner or operator shall analyze each daily sample for total
sulfur using Method 16A of Appendix A-6 to part 60, ASTM Method D4468-
85 (Reapproved 2006), ``Standard Test Method for Total Sulfur in
Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry''
(incorporated by reference--see Sec.  60.17), or ASTM Method D5504-01
(Reapproved 2006), ``Standard Test Method for Determination of Sulfur
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence'' (incorporated by reference--see Sec.  60.17).
    (vi) The owner or operator shall develop a 10-day average total
sulfur-to-H2S ratio and 95 percent confidence interval as
follows:
    (A) Calculate the ratio of the total sulfur concentration to the
H2S concentration for each day during which samples are
collected.
    (B) Determine the 10-day average total sulfur-to-H2S
ratio as the arithmetic average of the daily ratios calculated in
paragraph (e)(3)(vi)(A) of this section.
    (C) Determine the 95 percent confidence interval for the
distribution of daily ratios based on the 10 individual daily ratios.
    (vii) For each day during the period when data are being collected
to develop a 10-day average, the owner or operator shall estimate the
total sulfur concentration using the measured total sulfur
concentration measured for that day.
    (viii) For all days other than those during which data are being
collected to develop a 10-day average, the owner or operator shall
multiply the most recent 10-day average total sulfur-to-H2S
ratio by the daily average H2S concentrations obtained using
the monitor as required by paragraph (e)(3)(i) through (iii) of this
section to estimate total sulfur concentrations.
    (ix) If the total sulfur-to-H2S ratio for a subsequent
weekly sample is outside the 95 percent confidence interval for the
most recent distribution of daily ratios, the owner or operator shall
develop a new 10-day average ratio and 95 percent confidence interval
based on data for the outlying weekly sample plus data collected over
the following 9 operating days.
    (f) Flow monitoring for flares. The owner or operator of an
affected flare subject to Sec.  60.103a(a)(4) shall install, operate,
calibrate, and maintain CPMS to measure and record the flare gas flow
rate. The owner or operator of a modified flare shall install this
instrument by no later than 18 months after the flare becomes an
affected flare subject to this subpart unless the owner or operator of
the affected flare commits in writing to install a flare gas recovery
system, in which case flow monitoring is not required until after the
flare has been an affected flare subject to this subpart for 2 years.
* * * * *
    (g) * * *
    (3) All rolling 365-day periods during which the average
concentration of NOX as measured by the NOX
continuous monitoring system required under paragraph (c) or (d) of
this section exceeds:
    (i) 40 ppmv or 0.035 lb/MMBtu for a newly constructed process
heater or a modified or reconstructed natural draft process heater;
    (ii) 60 ppmv or 0.055 lb/MMBtu for a modified or reconstructed
forced draft process heater;
    (iii) 150 ppmv or the daily average emission limit calculated using
Equation 3 in Sec.  60.102a(g)(2)(iv)(B) for a co-fired process heater;
and
    (iv) The site-specific limit determined by the Administrator under
Sec.  60.102a(i).
    (4) All daily periods during which the concentration of
NOX as measured by the NOX continuous monitoring
system required under paragraph (d) of this section exceeds the
applicable emissions limit in Sec.  60.102a(g)(2)(iv).
    12. Section 60.108a is amended by:
    a. Revising paragraph (b);
    b. Revising paragraph (c)(6) introductory text and paragraphs
(c)(6)(ii) through (vi);
    c. Adding paragraphs (c)(6)(vii), (viii) and (ix);
    d. Adding paragraph (c)(7); and
    e. Revising paragraph (d)(5) to read as follows:

Sec.  60.108a  Recordkeeping and reporting requirements.

* * * * *
    (b) Each owner or operator subject to an emissions limitation in
Sec.  60.102a or work practice standard in Sec.  60.103a shall notify
the Administrator of the specific monitoring provisions of Sec. Sec.
60.105a, 60.106a, and 60.107a with which the owner or operator seeks to
comply. The notification must include, if applicable, a written
statement that the owner or operator of an affected flare is installing
a flare gas recovery system or additional amine adsorption and
stripping columns. Notification shall be submitted with the
notification of initial startup required by Sec.  60.7(a)(3).
    (c) * * *
    (6) The owner or operator shall record and maintain records of
discharges greater than 500 lb SO2 in any 24-hour period
from any affected flare, discharges greater than 500 lb SO2
in excess of the allowable limits from a fuel gas combustion device
other than a flare or sulfur recovery plant, and discharges to an
affected flare in excess of 500,000 scf in any 24-hour period. The
following information shall be recorded no later than 45 days following
the end of a discharge exceeding the thresholds:
* * * * *
    (ii) The date and time the discharge was first identified and the
duration of the discharge.
    (iii) The measured or calculated cumulative quantity of gas
discharged over the discharge duration. If the discharge duration
exceeds 24 hours, record the discharge quantity for each 24-hour
period. For a flare, record the measured or calculated cumulative
quantity of gas discharged to the flare over the discharge duration. If
the discharge duration exceeds 24 hours, record the quantity of gas
discharged to the flare for each 24-hour period. Engineering
calculations are allowed for fuel gas combustion devices other than
flares.
    (iv) For each discharge greater than 500 lb SO2 in any
24-hour period from a flare, the measured reduced sulfur concentration,
measured total sulfur concentration, or both the measured H2S
concentration and the estimated total sulfur concentration in the fuel
gas at a representative location in the flare inlet.
    (v) For each discharge greater than 500 lb SO2 in excess
of the applicable short-term emissions limit in Sec.  60.102a(g)(1)
from a fuel gas combustion device other than a flare, either the
measured concentration of H2S in the fuel gas or the measured
concentration of SO2 in the stream discharged to the
atmosphere. Process knowledge can be used to make these estimates for
fuel gas combustion devices other than flares.
    (vi) For each discharge greater than 500 lb SO2 in
excess of the allowable limits from a sulfur recovery plant, either the
measured concentration of reduced sulfur or SO2 discharged
to the atmosphere.
    (vii) For each discharge greater than 500 lb SO2 in any
24-hour period from any affected flare or discharge greater than 500 lb
SO2 in excess of the allowable limits from a fuel gas

[[Page 78544]]

combustion device other than a flare or sulfur recovery plant, the
cumulative quantity of H2S and SO2 released into
the atmosphere. For releases controlled by flares, assume 99 percent
conversion of reduced sulfur or total sulfur to SO2. For
other fuel gas combustion devices, assume 99 percent conversion of
H2S to SO2.
    (viii) The steps that the owner or operator took to limit the
emissions during the discharge.
    (ix) Results of any root cause analysis and corrective action
analysis conducted as required in Sec.  60.103a(a)(4) and (5) and Sec.
60.103a(b), including a statement noting whether the discharge resulted
from the same root cause identified in a previous analysis, and either
a description of the corrective action and a schedule for
implementation or an explanation of why corrective action is not
necessary as required in Sec.  60.103a(c).
    (7) If the owner or operator complies with Sec.  60.107a(d)(3) for
a flare, records of the H2S and total sulfur analyses of
each grab or integrated sample, the calculated daily total sulfur-to-
H2S ratios, the calculated 10-day average total sulfur-to-
H2S ratios, and the 95 percent confidence intervals for each
10-day average total sulfur-to-H2S ratio.
    (d) * * *
    (5) The information described in paragraph (c)(6) of this section
for all discharges for which a root cause analysis, corrective action
analysis, and implementation of corrective action were required by
Sec.  60.103a(a)(4) and (5), Sec.  60.103a(b), and Sec.  60.103a(c).
* * * * *
    13. Section 60.109a is amended by revising paragraph (b)
introductory text and adding paragraph (b)(4) to read as follows:

Sec.  60.109a  Delegation of authority.

* * * * *
    (b) In delegating implementation and enforcement authority of this
subpart to a State, local, or tribal agency, the approval authorities
contained in paragraphs (b)(1) through (4) of this section are retained
by the Administrator of the U.S. EPA and are not transferred to the
State, local, or tribal agency.
* * * * *
    (4) Approval of a petition to establish a site-specific
NOX emissions limit for a modified or reconstructed process
heater under Sec.  60.102a(i).
    14. Table 1 to subpart Ja is added to read as follows:

Tables to Subpart Ja of Part 60

 Table 1 to Subpart Ja of Part 60--Molar Exhaust Volumes and Molar Heat
                    Content of Fuel Gas Constituents
------------------------------------------------------------------------
                                                 MEVa dscf/   MHCb Btu/
                  Constituent                       mol          mol
------------------------------------------------------------------------
 Methane (CH4)................................         7.28          842
 Ethane (C2H6)................................        12.94        1,475
 Hydrogen (H2)................................         1.61          269
 Ethene (C2H4)................................        11.34        1,335
 Propane (C3H8)...............................        18.61        2,100
 Propene (C3H6)...............................        17.01        1,947
 Butane (C4H10)...............................        24.28        2,717
 Butene (C4H8)................................        22.67        2,558
 Inerts.......................................         0.85            0
------------------------------------------------------------------------
a MEV = molar exhaust volume, dry standard cubic feet per mole (dscf/
  mol).
b MHC = molar heat content, Btu per mole (Btu/mol).

[FR Doc. E8-29959 Filed 12-19-08; 8:45 am]

BILLING CODE 6560-50-P