[Federal Register: May 14, 2007 (Volume 72, Number 92)]
[Proposed Rules]
[Page 27177-27219]
[DOCID:fr14my07-13]

-----------------------------------------------------------------------

Part II

Environmental Protection Agency

-----------------------------------------------------------------------

40 CFR Part 60

 Standards of Performance for Petroleum Refineries; Proposed Rule

-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2007-0011; FRL-8309-1]
RIN 2060-AN72

Standards of Performance for Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rules.

-----------------------------------------------------------------------

SUMMARY: EPA is proposing amendments to the current Standards of
Performance for Petroleum Refineries. This action also proposes
separate standards of performance for new, modified, or reconstructed
process units at petroleum refineries. Unless otherwise noted, the term
new includes modified or reconstructed units. The proposed standards
for new process units include emissions limitations and work practice
standards for fluid catalytic cracking units, fluid coking units,
delayed coking units, process heaters and other fuel gas combustion
devices, fuel gas producing units, and sulfur recovery plants. These
proposed standards reflect demonstrated improvements in emissions
control technologies and work practices that have occurred since
promulgation of the current standards.

DATES: Comments. Written comments must be received on or before July
13, 2007.
    Public Hearing. If anyone contacts EPA by June 4, 2007 requesting
to speak at a public hearing, a public hearing will be held on June 13,
2007.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2007-0011, by one of the following methods:
     http://www.regulations.gov: Follow the on-line

instructions for submitting comments.
     E-mail<EMAIL_ADDRESS>     Fax:<PHONE_NUMBER>.
     Mail: U.S. Postal Service, send comments to: EPA Docket
Center (6102T), New Source Performance Standards for Petroleum
Refineries Docket, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
Please include a total of two copies. In addition, please mail a copy
of your comments on the information collection provisions to the Office
of Information and Regulatory Affairs, Office of Management and Budget
(OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC
20503.
     Hand Delivery: In person or by courier, deliver comments
to: EPA Docket Center (6102T), New Source Performance Standards for
Petroleum Refineries Docket, EPA West, Room 3334, 1301 Constitution
Avenue, NW., Washington, DC 20004. 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
http://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 http://www.regulations.gov or e-mail. The http://www.regulations.gov website

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 http://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 http://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 http://www.regulations.gov or in hard copy at the EPA Docket Center,

Standards of Performance for Petroleum Refineries Docket, EPA West,
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<PHONE_NUMBER>, and the telephone number for the Docket
Center is<PHONE_NUMBER>.

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:<PHONE_NUMBER>; e-mail address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?

    Categories and entities potentially regulated by this proposed rule
include:

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

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

    Do not submit information containing CBI to EPA through http://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
June 4, 2007, a public hearing will be held on June 13, 2007. 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.

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. What is the statutory authority for the proposed standards
and proposed amendments?
    B. What are the current petroleum refinery NSPS?
III. Summary of the Proposed Standards and Proposed Amendments
    A. What are the proposed amendments to the standards for
petroleum refineries (40 CFR part 60, subpart J)?
    B. What are the proposed requirements for new fluid catalytic
cracking units and new fluid coking units (40 CFR part 60, subpart
Ja)?
    C. What are the proposed requirements for new sulfur recovery
plants (SRP) (40 CFR part 60, subpart Ja)?
    D. What are the proposed requirements for new process heaters
and other fuel gas combustion devices (40 CFR part 60, subpart Ja)?
    E. What are the proposed work practice and equipment standards
(40 CFR part 60, subpart Ja)?
IV. Rationale for the Proposed Amendments (40 CFR part 60, subpart
J)
    A. How is EPA proposing to change requirements for refinery fuel
gas?
    B. How is EPA proposing to amend definitions?
    C. How is EPA proposing to revise the coke burn-off equation?
    D. What miscellaneous corrections are being proposed?
V. Rationale for the Proposed Standards (40 CFR part 60, subpart Ja)
    A. What is the performance of control technologies for fluid
catalytic cracking units?
    B. What is the performance of control technologies for fuel gas
combustion?
    C. What is the performance of control technologies for process
heaters?
    D. What is the performance of control technologies for sulfur
recovery systems?
    E. How did EPA determine the proposed standards for new
petroleum refining process units?
VI. Modification and Reconstruction Provisions
VII. Request for Comments
VIII. Summary of Cost, Environmental, Energy, and Economic Impacts
    A. What are the impacts for petroleum refineries?
    B. What are the secondary impacts?
    C. What are the economic impacts?
    D. What are the benefits?
IX. 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 Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

II. Background Information

A. What is the statutory authority for the proposed standards and
proposed amendments?

    New source performance standards (NSPS) implement Clean Air Act
(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 new, 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).
    Section 111(b)(1)(B) of the CAA requires EPA to periodically review
and revise the standards of performance, as necessary, to reflect
improvements in methods for reducing emissions.

B. What are the current petroleum refinery NSPS?

    NSPS for petroleum refiners (40 CFR part 60, subpart J) apply to
fluid catalytic cracking unit catalyst regenerators and fuel gas
combustion devices that commence construction or modification after
June 11, 1973. Fluid catalytic cracking unit catalyst regenerators are
subject to standards for particulate matter (PM), opacity, and carbon
monoxide (CO). Fluid catalytic cracking unit catalyst regenerators that
commence construction after January 17, 1984 are also subject to
standards for sulfur dioxide (SO2) (or a feed sulfur content
limit). Fuel gas combustion devices are subject to concentration limits
for hydrogen sulfide (H2S) as a surrogate for SO2
emissions.

    The current NSPS also apply to all Claus sulfur recovery plants
(SRP) of more than 20 long tons per day (LTD) that commence
construction or modification after October 4, 1976. Claus SRP are
subject to standards for either SO2 or both reduced sulfur
compounds and H2S.
    The NSPS were originally promulgated on March 8, 1974 and have been
amended several times. Significant changes to emission limits since the
original promulgation date include the addition of the sulfur oxide
standards for SRP and fluid catalytic cracking units (see 43 FR 10869,
March 15, 1978 and 54 FR 34027, August 17 1989).

III. Summary of the Proposed Standards and Proposed Amendments

    We are proposing several amendments to provisions in the existing
NSPS in 40 CFR part 60, subpart J. Many of these amendments are
technical clarifications and corrections that are also included in the
proposed standards in 40 CFR part 60, subpart Ja. For example, we are
proposing language to change the definition of fuel gas to indicate
that vapors collected and combusted to comply with certain wastewater
and marine vessel loading provisions are not considered fuel gas and
are exempt from 40 CFR 60.104(a)(1). These gas streams are not required
to be monitored. In a related amendment, we are proposing to clarify
that monitoring is not required for fuel gases that are identified as
inherently low sulfur or can demonstrate a low sulfur content. We are
also revising the coke burn-off equation to account for oxygen
(O2)-enriched air streams. Other amendments include
clarification of definitions and correction of grammatical and
typographical errors.
    The proposed standards in 40 CFR part 60, subpart Ja include
emission limits for fluid catalytic cracking units, fluid coking units,
SRP, and fuel gas combustion devices. They also include work practice
standards for minimizing the quantity of fuel gas streams flared from
all refinery process units and for minimizing the SO2
emissions from process units that are subject to standards of
performance for SO2 emissions. Proposed equipment standards
would reduce emissions of volatile organic compounds (VOC) from delayed
coker units. Only those affected facilities that begin construction,
modification, or reconstruction after May 14, 2007 would be affected by
the proposed standards in 40 CFR part 60, subpart Ja. Units for which
construction, modification, or reconstruction began on or before May
14, 2007 would continue to comply with the applicable standards under
the current NSPS in 40 CFR part 60, subpart J, as amended.

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

    We are proposing to amend the definition of ``fuel gas'' to exempt
vapors that are collected and combusted in an air pollution control
device installed to comply with a specified wastewater or marine vessel
loading emissions standard. The thermal combustion control devices
themselves would still be considered affected fuel gas combustion
devices, and all auxiliary fuel fired to these devices would be subject
to the fuel gas limit; however, continuous monitoring would not be
required for the collected vapors that are being incinerated because
these gases would not be considered fuel gases under the proposed
definition of ``fuel gas'' in subpart J.
    We are also proposing to exempt certain fuel gas streams from all
continuous monitoring requirements. Monitoring is currently not
required for events that are exempt from the requirements in 40 CFR
60.104(a)(1) (flaring of process upset gases or flaring of gases from
relief valve leakage or emergency malfunctions). Additionally,
monitoring would not be required for inherently low sulfur fuel gas
streams. These streams include pilot gas flames, gas streams that meet
commercial-grade product specifications with a sulfur content 30 parts
per million by volume (ppmv) or less, fuel gases produced by process
units that are intolerant to sulfur contamination, and fuel gas streams
that an owner or operator can demonstrate are inherently low-sulfur.
Owners and operators would be required to document the exemption for
which each fuel gas stream applies and ensure that the stream remains
qualified for that exemption.
    We are proposing to amend the definitions of ``Claus sulfur
recovery plant,'' ``oxidation control system,'' and ``reduction control
system'' to clarify that a SRP may consist of multiple units, that
sulfur pits are part of the Claus SRP, and that the oxidized or reduced
sulfur is recycled to the beginning of a sulfur recovery train within
the SRP. We are also proposing to add a fourth term to the coke burn-
off rate equation to account for the use of O2-enriched air.
    Finally, the proposed amendments include a few technical
corrections to fix references and other miscellaneous errors in subpart
J. The specific changes are detailed in section IV.D of this preamble.

B. What are the proposed requirements for new fluid catalytic cracking
units and new fluid coking units (40 CFR part 60, subpart Ja)?

    The proposed standards for new fluid catalytic cracking units
include emission limits for PM, SO2, nitrogen oxides
(NOX), and CO. One difference from the existing standards in
subpart J is that new fluid coking units would be subject to the same
standards as fluid catalytic cracking units. Other differences from the
existing standards are that the proposed PM and SO2 emission
limits are more stringent and the NOX emission limit is a
new requirement. Unlike the existing standards, the proposed standards
include no opacity limit because the opacity limit was intended to
ensure compliance with the PM limit and because we are now proposing
that sources use direct PM monitoring or parameter monitoring to ensure
compliance with the PM limit.
    The proposed PM emission limit for new fluid catalytic cracking
units and new fluid coking units is 0.5 kilogram (kg) per Megagram (kg/
Mg) (0.5 pound (lb)/1,000 lb) of coke burn-off in the regenerator.
Initial compliance with this emission limit would be determined using
Method 5 in Appendix A to 40 CFR part 60. Procedures for computing the
PM emission rate using the total PM concentration, effluent gas flow
rate, and coke burn-off rate would be the same as in 40 CFR part 60,
subpart J, as amended. To demonstrate ongoing compliance, an owner or
operator must either monitor PM emission control device operating
parameters or use a PM continuous emission monitoring system (CEMS). If
operating parameters will be used to demonstrate ongoing compliance,
the owner or operator must monitor the same parameters during the
initial performance test, and develop operating parameter limits for
the applicable parameters. The operating limits must be based on the
lowest hourly average values for the applicable parameters measured
over the three test runs. The owner or operator must also conduct
additional performance tests at least once every 24 months to verify
compliance with the PM emission limit and confirm or reestablish
operating limits. If ongoing compliance will be demonstrated using a PM
CEMS, the CEMS must meet the conditions in Performance Specification
11. Thus, separate performance tests are not required because the
equivalent of an initial performance test will be part of the initial
correlation test for the PM CEMS, and periodic response correlation
audits (every 5 years) will

include the equivalent of performance tests. We are co-proposing
requiring reconstructed and modified fluid catalytic cracking units to
meet the current standards in 40 CFR part 60, subpart J, and we are
requesting comments on the effects of the proposed PM standard on
modified or reconstructed facilities and if it is appropriate to adopt
a different standard for these sources.
    The proposed SO2 emission limits for new fluid catalytic
cracking units and new fluid coking units are to maintain
SO2 emissions to the atmosphere less than or equal to 50
ppmv on a 7-day rolling average basis, and less than or equal to 25
ppmv on a 365-day rolling average basis (both limits corrected to 0
percent moisture and 0 percent excess air). Initial compliance with the
proposed 50 ppmv SO2 emission limit would be demonstrated by
conducting a performance evaluation of the SO2 CEMS in
accordance with Performance Specification 2 in appendix B of 40 CFR
part 60, with Method 6, 6A, or 6C of 40 CFR part 60, appendix A as the
reference method. Ongoing compliance with both proposed SO2
emission limits would be determined using the CEMS to measure
SO2 emissions as discharged to the atmosphere, averaged over
the 7-day and 365-day averaging periods. Rolling average concentrations
would be calculated once per day using the applicable number of daily
average values. We are co-proposing requiring reconstructed and
modified fluid catalytic cracking units to meet the current standards
in 40 CFR part 60, subpart J, and we are requesting comments on the
effects of the proposed SO2 standard on modified or
reconstructed facilities.
    The proposed NOX emission limits for new fluid catalytic
cracking units and new fluid coking units are 80 ppmv on a 7-day
rolling average basis (dry at 0 percent excess air). Initial compliance
with the 80 ppmv 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, subpart A as the Reference Method. Ongoing compliance with
this emission limit would be determined using the CEMS to measure
NOX emissions as discharged to the atmosphere, averaged over
7-day periods. We are also co-proposing no new standards for
NOX emissions from fluid coking units and for modified or
reconstructed fluid catalytic cracking units.
    The proposed CO emission limit for new fluid catalytic cracking
units and new fluid coking units is 500 ppmv (1-hour average, dry at 0
percent excess air). Initial compliance with this emission limit would
be demonstrated by conducting a performance evaluation for the CEMS in
accordance with Performance Specification 4 in appendix B to 40 CFR
part 60, with Method 10 or 10A in 40 CFR part 60, appendix A as the
Reference Method. For Method 10, the integrated sampling technique is
to be used. Ongoing compliance with this emission limit would be
determined on an hourly basis using the CEMS to measure CO emissions as
discharged to the atmosphere. An exemption from monitoring may be
requested if the owner or operator can demonstrate that average CO
emissions are less than 50 ppmv (dry basis). This limit and the
compliance procedures are the same as in the existing NSPS for fluid
catalytic cracking units.

C. What are the proposed requirements for new sulfur recovery plants
(SRP) (40 CFR part 60, subpart Ja)?

    The proposed standards include SO2 emission limits for
all SRP. The proposed emission limit for new SRP greater than 20 LTD is
250 ppmv or less of combined SO2 and reduced sulfur
compounds as discharged to the atmosphere (reported as SO2
on a dry basis at 0 percent excess air). For a SRP with a capacity of
20 LTD or less, the proposed standard is mass emissions of combined
SO2 and reduced sulfur compounds equal to 1 weight percent
or less of sulfur recovered. In addition, the proposed standards
include an H2S concentration limit of 10 ppmv or less (dry
basis at 0 percent excess air) for all new SRP. Both SO2 and
H2S concentration limits would be determined hourly on a 12-
hour rolling average basis. As in the amendments to subpart J, the
proposed definition of a SRP would include the sulfur pit.
    Initial compliance with the emission limit for combined
SO2 and reduced sulfur compounds is demonstrated by
conducting a performance evaluation for the SO2 CEMS in
accordance with Performance Specification 2 in appendix B to 40 CFR
part 60, with Method 6, 6A, or 6C in 40 CFR part 60, appendix A as the
Reference Method to determine the SO2 concentration, and
Method 15 in 40 CFR part 60, appendix A as the Reference Method to
determine the SO2-equivalent concentration of the reduced
sulfur compounds. The results of the test using Method 15 are also used
to demonstrate initial compliance with the H2S concentration
limit. Initial compliance with the mass sulfur emission limit is
demonstrated by conducting a performance test as described above to
determine the combined SO2 and SO2-equivalent
concentration, and then converting that concentration to a mass
fraction using the volumetric flow rate of effluent gas and the mass
rate of sulfur recovery during the performance test.
    Ongoing compliance with the combined SO2 and reduced
sulfur compounds emission limit would be determined using a CEMS that
uses an air or O2 dilution and oxidation system to convert
the reduced sulfur to SO2 and then measures the total
resultant SO2 concentration. An O2 monitor would
also be required for converting the measured combined SO2
concentration to the concentration at 0 percent O2. Ongoing
compliance with the mass sulfur emission limit would be determined
using the same types of CEMS. A flow monitor that continuously monitors
the volumetric flow rate of gases released to the atmosphere would be
required so that the mass emitted can be calculated. The hourly sulfur
production rates would also have to be tracked so that mass fraction
emitted can be calculated and compared with the proposed 1 percent
emission limit.
    Ongoing compliance with the H2S concentration limit
would be determined using either an H2S CEMS or, if the SRP
is equipped with an oxidation control system or followed by
incineration, by continuous monitoring of the operating temperature and
O2 concentration. Minimum operating limits for the operating
temperature and O2 concentration would be established during
the performance test.

D. What are the proposed requirements for new process heaters and other
fuel gas combustion devices (40 CFR part 60, subpart Ja)?

    The proposed standards for new process heaters include both
SO2 and NOX emission limits. Because of this, the
fuel gas combustion units as defined in the existing subpart J
standards were divided into two separate affected sources: ``process
heaters'' and ``other fuel gas combustion devices.'' The primary sulfur
oxides emission limit for new process heaters and other fuel gas
combustion devices is 20 ppmv or less SO2 (dry at 0 percent
excess air) on a 3-hour rolling average basis and 8 ppmv or less on a
365-day rolling average basis. For process heaters that use only fuel
gas and other fuel gas combustion devices, we are proposing an
alternative concentration limit of 160 ppmv or less H2S or
total reduced sulfur (TRS) in the fuel gas on a 3-hour rolling average
basis (as in the existing NSPS) and 60 ppmv or less H2S or
TRS in the fuel gas on a

365-day rolling averaging basis. The TRS concentration limit is
required for new fuel gas combustion devices that combust fuel gas
generated from coking units (as either the only fuel or as a mixture of
fuel gases from other units). On the other hand, new fuel gas
combustion devices that do not combust fuel gas generated from coking
units are required to monitor H2S concentrations. Compliance
would be demonstrated either by measuring H2S (or TRS) in
the fuel gas or by measuring SO2 in the exhaust gas.
    Initial compliance with the 20 ppmv SO2 limit or the 160
ppmv H2S or TRS concentration limits would be demonstrated
by conducting a performance evaluation for the CEMS. The performance
evaluation for an SO2 CEMS would be conducted in accordance
with Performance Specification 2 in appendix B to 40 CFR part 60, with
Method 6, 6A, or 6C as the Reference Method. The performance evaluation
for an H2S CEMS would be conducted in accordance with
Performance Specification 7 in 40 CFR part 60, with Method 11, 15, 15A,
or 16 as the Reference Method. The performance evaluation for a TRS
CEMS would be conducted in accordance with Performance Specification 7
in 40 CFR part 60, with Method 16 as the Reference Method. Ongoing
compliance with the proposed sulfur oxides emission limits would be
determined using the applicable CEMS to measure either H2S
or TRS in the fuel gas being used for combustion or SO2 in
the exhaust gas to the atmosphere, averaged over the 3-hour and 365-day
averaging periods.
    Similar to proposed clarifications for 40 CFR part 60, subpart J,
we are proposing a definition of ``fuel gas'' that includes exemptions
for vapors collected and combusted in an air pollution control device
installed to comply with specified wastewater or marine vessel loading
provisions. Also similar to subpart J, we are proposing to exempt from
continuous monitoring fuel gas streams exempt under 40 CFR 60.102a(i)
and fuel gas streams that are inherently low in sulfur. We are also
proposing to streamline the process for an owner or operator to
demonstrate that a fuel gas stream not explicitly exempted from
continuous monitoring is inherently low sulfur.
    The proposed NOX emission limits for new process heaters
is 80 ppmv on a 7-day rolling average basis (dry at 0 percent excess
air). Initial compliance with the 80 ppmv 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, subpart A as the Reference
Method. Ongoing compliance with this emission limit would be determined
using the CEMS to measure NOX emissions as discharged to the
atmosphere, averaged over 7-day periods.

E. What are the proposed work practice and equipment standards (40 CFR
part 60, subpart Ja)?

    Three work practice standards are proposed to reduce both VOC and
SO2 emissions from flares, start-up/shutdown/malfunction
events, and delayed coker units. First, the proposed rule requires all
new fuel gas producing units at a refinery to be designed and operated
in such a way that the fuel gas produced by the new process units does
not routinely discharge to a flare. Second, a requirement for a start-
up, shutdown and malfunction plan that includes procedures to minimize
discharges either directly to the atmosphere or to the flare gas system
during the planned startup or shutdown of these units, procedures to
minimize emissions during malfunctions of the amine treatment system or
sulfur recovery plant, and procedures for conducting a root-cause
analysis of an emissions limit exceedance or process start-up,
shutdown, upset, or malfunction that causes a discharge into the
atmosphere, either directly or indirectly, from any refinery process
unit subject to the provisions of this subpart in excess of 500 lb per
day (lb/d) of SO2. Third, the proposed rule would require
delayed coking units to depressure to 5 lbs per square inch gauge
(psig) during reactor vessel depressuring and vent the exhaust gases to
the fuel gas system. For new, reconstructed, or modified units, we are
co-proposing to require only the last of these work practice standards,
the requirement to depressure coking units to the flare.

IV. Rationale for the Proposed Amendments (40 CFR part 60, subpart J)

    Because we are proposing a new subpart to 40 CFR part 60 for
affected sources at petroleum refineries beginning construction,
reconstruction, or modification after May 14, 2007, our proposed
amendments to subpart J of 40 CFR part 60 would impact only those
affected sources that are already subject to 40 CFR part 60, subpart J.
The proposed amendments to this subpart include clarifications of the
current requirements and technical corrections to the regulatory
language. These changes to subpart J of 40 CFR part 60 are discussed
below.

A. How is EPA proposing to change requirements for refinery fuel gas?

    As we conducted our review of 40 CFR part 60, subpart J, we found
that the definition of ``fuel gas'' has been broadly interpreted by
States and EPA Regions over the last 30 years. Because of the
increasing complexity of petroleum refineries, this interpretation may
be more inclusive than originally intended in the 1970s. We agree that
the interpretation ensures that all streams that could be considered
fuel gas and have the potential for high-sulfur emissions are included
in the regulatory requirements, but we recognize that this broad
definition has resulted in application of the fuel gas concentration
limits to fuel gas streams and combustion devices that were not
originally considered in the standards development process.
Furthermore, had these extended applications been considered in the
standards development process, some of the applications would have been
found to be either technically or economically infeasible. The existing
requirements in subpart J of 40 CFR part 60 do recognize and limit the
applicability of the fuel gas concentration limits to certain gas
streams. For example, 40 CFR 60.101(d) excludes gases generated by
catalytic cracking unit catalyst regenerators and fluid coking burners
from the definition of ``fuel gas.'' These gases were excluded because
the sulfur in the gases generated by the catalytic cracking unit
catalyst regenerators and fluid coking burners is in the form of sulfur
oxides rather than H2S. As such, these gases are not
amenable to amine treatment, which was the primary treatment technique
on which the fuel gas concentration limits were based. In addition, 40
CFR 60.104(a)(1) exempts process upset gases or fuel gas released to
the flare as a result of relief valve leakage or emergency malfunctions
from the fuel gas H2S concentration limits. In this case, it
was determined that requiring treatment of these gases was either
technically or economically infeasible. Therefore, it is entirely in
keeping with the regulatory intent of the NSPS and the specific
requirements in 40 CFR part 60, subpart J to exclude or exempt sources
based on technical and economic considerations.
    Since the development of the refinery fuel gas concentration limits
in the early 1970s, EPA has developed numerous other standards in which
incineration was promoted as a best air pollution management practice
for certain organic vapors which had traditionally been

released directly to the atmosphere. These gas streams were never
considered in the development of the 40 CFR part 60, subpart J
standards because they were not directed to a fuel gas combustion
device at the time. As such, the technical and economical feasibility
of meeting the fuel gas concentration limits was not specifically
evaluated for these gas streams at that time. During our review, we
evaluated the application of the fuel gas concentration limits to a
variety of process gas streams that did not exist in the early 1970s.
We concluded that most of these gas streams are amenable to amine
treatment and that it is both technically and economically feasible to
treat those gas streams to meet the fuel gas concentration limits.
However, we identified a few specific streams that are not readily
amenable to amine treatment (or direct diversion to the SRP) and/or are
not cost-effective to amine treatment due to the typically low (but
potentially variable) H2S content and the typical location
of these gas streams in relationship to the primary processing units at
the refinery.
    As a result of this evaluation, we are proposing to change the
requirements of the fuel gas concentration limits in keeping with a
broad definition of fuel gas, but recognizing the technical and
economic issues related to certain fuel gas streams or combustion
devices. Specifically, we are proposing to exempt from the definition
of ``fuel gas'' vapors that are collected and combusted in an air
pollution control device installed to comply with the Standards of
Performance for VOC Emissions From Petroleum Refinery Wastewater
Systems (40 CFR part 60, subpart QQQ), National Emission Standards for
Benzene Waste Operations (40 CFR part 61, subpart FF), the National
Emission Standards for Marine Tank Vessel Loading Operations (40 CFR
part 63, subpart Y), or the National Emission Standards for Hazardous
Air Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC),
specifically either 40 CFR 63.647 or 40 CFR 63.651. The wastewater and
marine vessel loading sources subject to these specific regulations are
often located at the edge of the refinery property, if not off-site,
and compliance with the regulations is generally demonstrated by
capturing and combusting the organic vapors. The collected gases
generally have low sulfur content, but variability in the products
being loaded and in wastewater treatment process operations may result
in the collected gases exceeding the current fuel gas concentration
limits for short periods of time. Due to the typical low sulfur content
of these gases, they are not generally suitable for amine treatment;
due to the presence of O2 in these collected gases, they
cannot be routed to the fuel gas system. Furthermore, these sources are
typically far from amine treatment or the SRP, and it is not
economically reasonable to propose control beyond the existing
regulations for these sources (e.g., requiring these streams to be
routed to sulfur treatment rather than being combusted). Therefore, we
are proposing to amend the definition of ``fuel gas'' in 40 CFR
60.101(d) to exclude from the fuel gas concentration limits the vapors
collected and combusted in air pollution control devices to comply with
the specified regulations in 40 CFR part 60, subpart QQQ, 40 CFR part
61, subpart FF, or 40 CFR part 63, subparts Y or CC. The thermal
combustion control devices would still be considered affected fuel gas
combustion devices and all auxiliary fuel fired to these devices would
be subject to the fuel gas concentration limit; however, continuous
monitoring would not be required for the collected vapors that are
being incinerated because these gases would not be considered fuel
gases under the proposed definition of ``fuel gas'' in subpart J.
    We are also proposing to clarify that monitoring is not required
for fuel gas streams that are exempt from the requirements in 40 CFR
60.104(a)(1). These streams include process upset gases or fuel gases
that are released to the flare as a result of relief valve leakage or
other emergency malfunctions. To clarify this point, the proposed
introductory text for 40 CFR 60.105(a)(4)(iv) specifies that continuous
monitoring is not required for streams that are exempt from 40 CFR
60.104(a)(1). We are also proposing to add the phrase ``for fuel gas
combustion devices subject to 40 CFR 60.104(a)(1)'' after ``Instead of
the SO2 monitor in paragraph (a)(3) of this section'' in 40
CFR 60.105(a)(4). This proposed amendment is more consistent with the
language in 40 CFR 60.105(a)(3). Given our intent not to require fuel
gas monitoring of process upset gases, combustion devices such as
emergency flares would likely not require monitoring unless sources
other than process upset gases are burned, such as routine vents or
sweep gas. We are aware of issues related to the identification and
exemption of these units from fuel gas monitoring. We are requesting
comment on the need to provide specific language exempting these units,
and on appropriate methods for identifying emergency flares and
verifying on an ongoing basis that no flaring of nonexempt gases is
occurring.
    In addition to the exemptions described in the previous paragraphs,
we are proposing to exempt certain fuel gas streams from all monitoring
requirements. These streams would still be subject to the fuel gas
concentration limits, but since we do not expect that these streams
would exceed this limit (except in the case of a process upset or
malfunction, in which case the fuel gases would be exempt from meeting
the limit), continuous monitoring of these streams is unnecessary. We
have divided these streams into four overall categories, as specified
in proposed 40 CFR 60.105(a)(4)(iv)(A) through (D). The first category
includes pilot gas flames, which are fairly insignificant sources.
Although previous determinations effectively excluded these gases from
the requirements of the rule, we believe it is good air pollution
control practice to fire pilot lights with natural gas or treated fuel
gas. However, even when considering the pilot flame as part of the fuel
gas combustion device, the potential for sulfur oxide emissions from
these sources is insignificant and it is not cost-effective to require
continuous monitoring of these gas streams. Therefore, we are changing
in the monitoring requirements that monitoring of pilot flame fuel gas
is not required.
    The second category includes gas streams that meet commercial-grade
product specifications with a sulfur content of 30 ppmv or less.
Placing a limit on the sulfur content of the products that we are
proposing to exempt from monitoring ensures that only low-sulfur
products are excluded. The 30 ppmv limit for commercial-grade gas
products was selected because it provides a sufficient margin of safety
to ensure continuous compliance with the proposed annual average
H2S concentration limit of 60 ppmv regardless of normal
fluctuations in the composition of commercial grade products.
    We are requesting comment on the appropriateness of an additional
exemption for gas streams that were generated from certain commercial-
grade liquid products (e.g., displaced vapors from a storage tank or
loading rack for gasoline or diesel fuel). The most straightforward
approach would be to exempt gas streams associated with commercial
liquid products that contain sulfur below some specified weight percent
level. For example, we expect that most of the sulfur-containing
compounds in gasoline meeting the Tier 2 sulfur standards or in diesel
fuel

meeting the low-sulfur diesel fuel standards have high molecular
weights and low vapor pressures such that gas streams in equilibrium
with them would have sulfur contents below the proposed 30 ppmv level.
To confirm this assumption, we are asking for data on the typical
concentrations and vapor pressures of the most prevalent mercaptans,
thiophenes, and other sulfur-containing compounds in these or other
commercial liquid products.
    We would use these data to calculate the corresponding vapor phase
concentrations of gas streams in equilibrium with the liquid products
using Raoult's Law. Given the extremely low concentrations of the
sulfur-containing compounds in the liquid products, we are also seeking
comment on whether Raoult's Law gives a realistic estimate of their
vapor phase partial pressures. We are also interested in any test data
to support this approach, and we are interested in any other approaches
to develop an exemption for gas streams associated with commercial-
grade liquid products.
    The third category includes fuel gases produced by process units
that are intolerant of sulfur contamination. There are a few process
units within a refinery whose operation is dependent on keeping the
sulfur content low. If there is too much sulfur in the gas streams
entering these units, the process units could malfunction.
Specifically, the methane reforming unit in the hydrogen plant, the
catalytic reforming unit, and the isomerization unit are intolerant of
sulfur in the process streams; therefore, these streams are treated to
remove sulfur prior to processing in these units. Fuel gases
subsequently formed in these process units are low in sulfur because
the process feedstocks are necessarily low in sulfur. As such, we find
that requiring continuous monitoring of the H2S content in
these gas streams or requiring each individual refinery to develop and
implement an alternative monitoring plan (AMP) is unnecessary and
creates needless obstacles to using the produced fuel gas directly in
the heaters associated with these process units. We are asking for
comment on whether fuel gas is generated from any other process units
that are intolerant of sulfur. Comments recommending the exemption of
fuel gas streams from other units should identify the problems sulfur
cause in the unit, procedures used to reduce sulfur in the gas stream
before it is processed in the unit, and the expected sulfur content of
the outlet fuel gas stream.
    For all of the above low-sulfur streams that an owner or operator
determines are exempt from all monitoring requirements, the owner or
operator must document which of the exemptions applies to each stream.
If the refinery operations associated with an exempt stream change, the
owner or operator must document the change and determine whether the
stream continues to be exempt. If the refinery operations or the
composition of an exempt stream change in such a way that the stream is
no longer exempt from monitoring, the owner or operator must begin
continuous monitoring within 15 days after the change occurs.
    In addition, we are proposing a standardized, streamlined procedure
to exempt from continuous monitoring streams that an owner or operator
can demonstrate are inherently low-sulfur (i.e., consistently 5 ppmv or
less H2S) following the procedures specified in proposed 40
CFR 60.105(b). The information that an owner or operator must provide
to EPA is similar to the information and items needed to apply for an
AMP, as described in the EPA document ``Alternative Monitoring Plan for
NSPS Subpart J Refinery Fuel Gas.'' In general, once an AMP is approved
for an affected source, the owner or operator must continue to monitor
the stream, although a methodology other than a continuous monitor may
be used. For this specific exemption, however, once an application to
demonstrate that a stream is inherently low-sulfur is approved by EPA,
that stream is exempt from monitoring until there is a change in the
refinery operation that affects the stream or the stream composition
changes. If the sulfur content of the stream changes but is still
within the range of concentrations included in the original
application, the owner or operator will conduct H2S testing
on a grab sample as proof and record the results of the test. If the
sulfur content of the stream changes such that the sulfur concentration
is outside the range provided in the original application, the owner or
operator must submit a new application that must be approved in order
for the stream to continue to be exempt from continuous monitoring. If
a new application is not submitted, the owner or operator must begin
continuous monitoring within 15 days.

B. How is EPA proposing to amend definitions?

    We are proposing to amend the definition of ``Claus sulfur recovery
plant'' in 40 CFR 60.101(i). These changes would clarify that the SRP
may consist of multiple units, and the types of units that are part of
a SRP would be listed within the definition. Note that sulfur pits
would be included as one of the units, which is consistent with the
Agency's current interpretation of the existing definition.
    In conjunction with this amendment, we are also proposing to amend
the definitions of ``oxidation control system'' and ``reduction control
system'' in 40 CFR 60.101(j) and 40 CFR 60.101(k), respectively. The
amended definitions would specify that the oxidized or reduced sulfur
is recycled to the beginning of a sulfur recovery train within the SRP
and are consistent with the proposed definitions in 40 CFR 60.101a of
subpart Ja. This clarification would ensure that thermal oxidizers that
convert the sulfur to SO2 but do not recycle and recover the
oxidized sulfur are not considered oxidation control systems.

C. How is EPA proposing to revise the coke burn-off equation?

    The current equation for calculating coke burn-off rate in 40 CFR
60.106(b)(3) assumes that each fluid catalytic cracking unit is using
air with 21 percent O2. However, there are some fluid
catalytic cracking units that use O2-enriched air, and for
these units, the current equation is not completely accurate. Equation
1 in 40 CFR 63.1564(b)(4)(i) of the National Emission Standards for
Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking
Units, Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR
part 63, subpart UUU) includes an additional term to account for the
use of an O2-enriched air stream. For accuracy in the
calculation of the coke burn-off rate, we are proposing to revise the
coke burn-off rate equation in 40 CFR 60.106(b)(3) to be consistent
with the equation in 40 CFR 63.1564(b)(4)(i). This revision also
includes changing the constant values and the units of the resulting
coke burn-off rate from Megagrams per hour (Mg/hr) and tons per hour
(tons/hr) to kilograms per hour (kg/hr) and pounds per hour (lb/hr).

D. 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 J.

  Table 1.--Proposed Technical Corrections to 40 CFR Part 60, Subpart J
------------------------------------------------------------------------
                                      Proposed technical correction and
              Section                              reason
------------------------------------------------------------------------
60.100............................  Replace instances of ``construction
                                     or modification'' with
                                     ``construction, reconstruction, or
                                     modification.''
60.100(b).........................  Replace ``except Claus plants of 20
                                     long tons per day (LTD) or less''
                                     with ``except Claus plants with a
                                     design capacity of 20 long tons per
                                     day (LTD) or less'' to clarify that
                                     the size cutoff is based upon
                                     design capacity and sulfur content
                                     in the inlet stream rather than the
                                     amount of sulfur produced.
60.100(b).........................  Insert ending date for applicability
                                     of 40 CFR part 60, subpart J;
                                     sources beginning construction,
                                     reconstruction, or modification
                                     after this date will be subject to
                                     40 CFR part 60, subpart Ja.
60.101............................  Rearrange definitions alphabetically
                                     for ease in locating a specific
                                     definition.
60.102(b).........................  Replace ``g/MJ'' with ``grams per
                                     Gigajoule (g/GJ)'' to correct
                                     units.
60.104(b)(1)......................  Replace ``50 ppm by volume (vppm)''
                                     with ``50 ppm by volume (ppmv)''
                                     for consistency in unit definition.
60.104(b)(2)......................  Add ``to reduce SO2 emissions'' to
                                     the end of the phrase ``Without the
                                     use of an add-on control device''
                                     at the beginning of the paragraph
                                     to clarify the type of control
                                     device to which this paragraph
                                     refers.
60.105(a)(3)......................  Add ``either'' before ``an
                                     instrument for continuously
                                     monitoring'' and replace ``except
                                     where an H2S monitor is installed
                                     under paragraph (a)(4)'' with ``or
                                     monitoring as provided in paragraph
                                     (a)(4)'' to more accurately refer
                                     to the requirements of Sec.
                                     60.105(a)(4) and clarify that there
                                     is a choice of monitoring
                                     requirements.
60.105(a)(3)(iv)..................  Replace ``accurately represents the
                                     SO2 emissions'' with ``accurately
                                     represents the SO2 emissions'' to
                                     correct a typographical error.
60.105(a)(4)......................  Replace ``In place'' with
                                     ``Instead'' at the beginning of
                                     this paragraph to clarify that
                                     there is a choice of monitoring
                                     requirements.
60.105(a)(8)......................  Replace ``seeks to comply with Sec.
                                      60.104(b)(1)'' with ``seeks to
                                     comply specifically with the 90
                                     percent reduction option under Sec.
                                       60.104(b)(1)'' to clearly
                                     identify the emission limit option
                                     to which the monitoring requirement
                                     in this paragraph refers.
60.105(a)(8)(i)...................  Change ``shall be set 125 percent''
                                     to ``shall be set at 125 percent''
                                     to correct a grammatical error.
60.106(e)(2)......................  Replace the incorrect reference to
                                     40 CFR 60.105(a)(1) with a correct
                                     reference to 40 CFR 60.104(a)(1).
60.107(c)(1)(i)...................  Replace both occurrences of ``50
                                     vppm'' with ``50 ppmv'' for
                                     consistency in unit definition.
60.107(f).........................  Redesignate current 40 CFR 60.107(e)
                                     as 40 CFR 60.107(f) to allow space
                                     for a new paragraph (e).
60.107(g).........................  Redesignate current 40 CFR 60.107(f)
                                     as 40 CFR 60.107(g) to allow space
                                     for a new paragraph (e).
60.108(e).........................  Replace the incorrect reference to
                                     40 CFR 60.107(e) with a correct
                                     reference to 40 CFR 60.107(f).
60.109(b)(2)......................  Add a reference to 40 CFR
                                     60.106(e)(3) to specify that
                                     determining whether a fuel gas
                                     stream is low-sulfur may not be
                                     delegated to States.
60.109(b)(3)......................  Redesignate current 40 CFR
                                     60.109(b)(2) as 40 CFR 60.109(b)(3)
                                     to allow space for a new paragraph
                                     (b)(2).
------------------------------------------------------------------------

V. Rationale for the Proposed Standards (40 CFR part 60, subpart Ja)

A. What is the performance of control technologies for fluid catalytic
cracking units?

1. PM Control Technologies
    Filterable PM emissions from fluid catalytic cracking units are
predominately fine catalyst particles generated from the mechanical
grinding of catalyst particles as the catalyst is continuously
recirculated between the fluid catalytic cracking unit and the catalyst
regenerator. Control of PM emissions from fluid catalytic cracking
units relies on the use of post-combustion controls to remove solid
particles from the flue gases. Electrostatic precipitators (ESP) and
wet scrubbers are the predominant technologies used to control PM from
fluid catalytic cracking units. Either of these PM control technologies
can be designed to achieve overall PM collection efficiencies in excess
of 95 percent.
    Electrostatic Precipitator (ESP). An ESP operates by imparting an
electrical charge to incoming particles, and then attracting the
particles to oppositely charged metal plates for collection.
Periodically, the particles collected on the plates are dislodged in
sheets or agglomerates (by rapping the plates) and fall into a
collection hopper. The normal PM control efficiency range for an ESP is
between 90 and 99+ percent. One of the major advantages of an ESP is
that it operates with essentially little pressure drop in the gas
stream. They are also capable of handling high temperature conditions.
    Wet Scrubbers. Wet scrubbers use a water spray to coat and
agglomerate particles entrained in the flue gas. To improve wetting of
fine particulates, either enhanced spray nozzles or venturi
acceleration is used. The wetted particles are then removed from the
flue gas through centrifugal separation. Wet scrubbers have similar
collection efficiencies as dry ESP (90 to 98 percent), but they are
also effective in removing SO2 emissions. Wet scrubbers may
also be more effective in controlling condensable PM as they often use
water quench and thereby operate at lower temperatures than ESP used to
control fluid catalytic cracking units. Wet scrubbers are generally
more costly to operate than ESP due to higher pressure drops across the
control device and because of water treatment and disposal costs.
However, they become economically viable if significant SO2
emissions reductions are also needed.
    Fabric Filters. A fabric filter collects PM in the flue gases by
passing the gases through a porous fabric material. The buildup of
solid particles on the fabric surface forms a thin, porous layer of
solids, which further acts as a filtration medium. Gases pass through
this cake/fabric filter, and all but the finest-sized particles are
trapped on the cake surface. Collection efficiencies of fabric filters
can be as high as 99.99 percent. Fabric filters tend to be more
efficient for fine particles (those less than 2.5 microns in diameter)
than ESP or wet scrubbers.
    The primary concern with fabric filters are maintenance
requirements of the baghouses given the long run times of typical fluid
catalytic cracking units. Small process upsets (e.g., pressure changes)
in the fluid catalytic cracking unit and regenerator system can send
high concentrations of particles to the control system. These particles
would likely blind the filter bags, causing a shut-down of the unit to
replace the filter bags. Wet scrubbers and ESP can more easily
accommodate and control high concentrations of particles.
2. SO2 Control Technologies
    During combustion, sulfur compounds present in the deposited coke
are predominately oxidized to gaseous SO2. One approach to
controlling SO2 emissions from catalytic cracking units is
to limit the maximum sulfur content in the feedstock to the

catalytic cracking unit. This can be accomplished by processing crude
oil that naturally contains low amounts of sulfur or a feedstock that
has been pre-treated to remove sulfur (i.e., hydrotreatment or
hydrodesulfurization). A second approach is to use a post-combustion
control technology that removes SO2 from the flue gases.
These technologies rely on either absorption or adsorption processes
that react SO2 with lime, limestone, or another alkaline
material to form an aqueous or solid sulfur by-product. A third
approach is the use of catalyst additives, which capture sulfur oxides
in the regenerator and return them to the fluid catalytic cracking
reactor where they are transformed to H2S that is ultimately
exhausted to the SRP.
    Feedstock Selection or Pre-Treatment. The SO2 emissions
from the fluid catalytic cracking unit are directly related to the
amount of sulfur deposited on the catalyst particles in the riser and
reactor section of the unit. The amount of sulfur deposited on the
catalyst is a function of both the amount of sulfur in the feedstocks
and the relative composition of the sulfur-containing compounds in the
feedstocks (mercaptans, thiosulfates). As the concentration of sulfur
in the feedstocks is reduced, the SO2 emissions from the
regenerator portion of the unit are also reduced. Therefore, if a
refinery processes ``sweet'' crude (oil naturally low in sulfur) or if
a refinery removes sulfur from the feedstocks of the fluid catalytic
cracking unit, the SO2 emissions from the catalyst
regenerator will be lower than from refineries that process feedstocks
that have higher sulfur content. At a petroleum refinery, the primary
means of removing sulfur compounds in the liquid feedstocks is
catalytic hydrotreatment. Hydrotreatment typically reduces the sulfur
content in process streams to between 20 and 1,000 parts per million by
weight.
    Alkali Wet Scrubbing. The SO2 in a flue gas can be
removed by reacting the sulfur compounds with a solution of water and
an alkaline chemical to form insoluble salts that are removed in the
scrubber effluent. Wet scrubbing processes used to control
SO2 are generally termed flue-gas desulfurization (FGD)
processes. The normal SO2 control efficiency range for
SO2 scrubbers is 80 percent to 90 percent for low efficiency
scrubbers and 90 percent to 99 percent for high efficiency scrubbers.
In recent fluid catalytic cracking unit applications, control
guarantees of 25 ppmv SO2 are commonly provided by FGD
suppliers.
    Spray Dryer Adsorption. An alternative to using wet scrubbers is to
use spray dryer adsorber (SDA) technology. A SDA operates by the same
principle as alkali wet scrubbing, except that instead of a bulk liquid
(as in wet scrubbing) the flue gas containing SO2 is
contacted with fine spray droplets of hydrated lime slurry in a spray
dryer vessel. This vessel is located downstream of the air heater
outlet where the gas temperatures are in the range of 120 [deg]C to 180
[deg]C (250 [deg]F to 350 [deg]F). The SO2 is absorbed in
the slurry and reacts with the hydrated lime reagent to form solid
calcium sulfite and calcium sulfate. The water is evaporated by the hot
flue gases and forms dry, solid particles containing the reacted
sulfur. Most of the SO2 removal occurs in the spray dryer
vessel itself, although some additional SO2 capture has also
been observed in downstream particulate collection devices. The
SO2 removal efficiencies of new lime spray dryer systems are
generally greater than 90 percent. Only one refinery has ever used an
SDA to control SO2 from its fluid catalytic cracking unit;
this system has since been removed in favor of feedstock
hydrotreatment.
    Catalyst Additives. One common method used by refineries to reduce
SO2 emissions from the fluid catalytic cracking unit is the
use of catalyst additives (typically various types of metal oxides).
The metal oxide reacts with some of the SO3 in the catalyst
regenerator to form a metal sulfate. The metal sulfate is then returned
to the cracking unit where the sulfur is converted to a metal sulfide
and then to H2S and the original metal oxide. The
H2S is subsequently recovered in the SRP, and the metal
oxide returns to the catalyst regenerator to repeat the process. The
control efficiency of catalyst additives is difficult to assess, but is
generally around 50 percent (ranging from 20 to 70 percent, depending
on the application).
3. NOX Control Technologies
    NOX are formed in a catalyst regenerator (and downstream
CO boiler, if present) by the oxidation of molecular nitrogen
(N2) in the combustion air and any nitrogen compounds
contained in the fuel (i.e., thermal NOX and fuel
NOX). The formation of NOX from nitrogen in the
combustion air is dependent on two conditions occurring simultaneously
in the unit's combustion zone: high temperature and an excess of
combustion air. Under these conditions, significant quantities of
NOX are formed, regardless of the fuel type burned. There
are several NOX emission control strategies that can be
considered combustion controls (e.g., low NOX burners or
flue gas recirculation) that reduce the amounts of NOX
formed during combustion. These control technologies are primarily
applicable to incomplete combustion fluid catalytic cracking units
controlled by CO boilers. As there is limited or no direct flame in the
catalyst regenerator during normal operations, these control strategies
may be limited for complete combustion fluid catalytic cracking units.
Most post-combustion control technologies involve converting the
NOX in the flue gas to N2 and water using either
a process that requires a catalyst (called selective catalytic
reduction (SCR)) or a process that does not use a catalyst (called
selective noncatalytic reduction (SNCR)). A recently developed post-
combustion technology (LoTOxTM) uses ozone to oxidize
NOX to nitric pentoxide, which is water soluble and easily
removed in a water scrubber.
    NOX Combustion Controls. Flue gas recirculation (FGR) uses flue gas
as an inert material to reduce flame temperatures. In a typical FGR
system, flue gas is collected from the heater or stack and returned to
the burner via a duct and blower. The addition of flue gas with the
combustion air reduces the O2 content of the inlet air
stream to the burner. The lower O2 level in the combustion
zone reduces flame temperatures which in turn reduces NOX
emissions. The normal NOX control efficiency range for FGR
is 30 percent to 50 percent. When coupled with low-NOX
burners (LNB), the control efficiency increases to 50-72 percent.
    LNB technology utilizes advanced burner design to reduce
NOX formation through the restriction of O2,
flame temperature, and/or residence time. The two general types of LNB
are staged fuel and staged air burners. Staged fuel LNB are
particularly well suited for boilers and process heaters burning
process and natural gas which generate higher thermal NOX.
The estimated NOX control efficiency for LNB when applied to
petroleum refining fuel burning equipment is generally around 40
percent.
    One NOX combustion control technique that is applicable
to complete combustion fluid catalytic cracking units is the use of
catalyst additives and/or combustion promoters. The control efficiency
of these additives varies from 10 to 50 percent.
    Selective Catalytic Reduction (SCR) Technology. The SCR process
uses a catalyst with ammonia (NH3) to reduce the nitrogen
oxide (NO) and nitrogen dioxide (NO2) in the flue gas to
N2 and water. Ammonia is diluted with air or

steam, and this mixture is injected into the flue gas upstream of a
metal catalyst bed that typically is composed of vanadium, titanium,
platinum, or zeolite. The SCR catalyst bed reactor is usually located
between the economizer outlet and air heater inlet where temperatures
range from 230 [deg]C to 400 [deg]C (450 [deg]F to 750 [deg]F). The SCR
technology is capable of NOX reduction efficiencies of 90
percent or higher.
    Selective Noncatalytic Reduction (SNCR) Technology. An SNCR process
is based on the same basic chemistry of reducing the NO and
NO2 in the flue gas to N2 and water, but it does
not require the use of a catalyst to promote these reactions. Instead,
the reducing agent is injected into the flue gas stream at a point
where the flue gas temperature is within a specific temperature range
of 870[deg]C to 1,090[deg]C (1,600[deg]F to 2,000[deg]F). The
NOX reduction levels for SNCR are in the range of
approximately 30 to 50 percent.
    LoTOxTM Technology. The LoTOx\TM\ process (i.e., low-temperature
oxidation) is a patented technology that uses ozone to oxidize
NOX to nitric pentoxide and other higher order
NOX, all of which are water soluble and easily removed from
exhaust gas in a wet scrubber. The system operates optimally at
temperatures below 300[deg]F. Thus, ozone is injected after scrubber
inlet quench nozzles and before the first level of scrubbing nozzles.
Outlet NOX emission levels have been reduced to less than 20
ppmv, and often as low as 10 ppmv, when inlet NOX
concentrations ranged from 50 to 200 ppmv.

B. What is the performance of control technologies for fuel gas
combustion?

    Refinery fuel gas is generally used in process heaters and boilers
to meet the energy demands of the refinery. Excess refinery fuel gas is
typically combusted using flares. Flares also serve an important safety
function to destroy organics and convert H2S to
SO2 during process upsets and malfunctions.
    Over the past several years, many refineries have reduced flaring
episodes by adding flare gas recovery systems and/or by changing their
start-up and shutdown procedures to limit flaring. Installing a flare
gas recovery system and implementing new start-up and shutdown
procedures are expected to reduce VOC, sulfur oxides, and
NOX emissions from flares. Improved amine scrubbing systems
are expected to reduce sulfur oxide emissions from all fuel gas
combustion systems. In addition, excess capacity in the SRP will help
to minimize sour gas flaring that might be caused by a malfunction in
the SRP. Each of these ``control'' techniques are described in the
following paragraphs.
    Flare Gas Recovery Systems. Flare gas recovery systems recover fuel
gas from the flare gas header prior to the flare's liquid seal. A flare
gas recovery system consists of a compressor, separator, and process
controls (to maintain slight positive pressure on the flare header).
Flare gas recovery systems are typically designed to recover fuel gas
from miscellaneous processes that might regularly be relieved to the
flare header system and can effectively recover 100 percent of these
fuel gases. However, flare gas recovery systems cannot recover large
quantities of fuel gas that might be suddenly released to the flare
header system as a result of a process upset or malfunction. These
gases would still be flared as necessary to maintain the integrity of
the process units and the safety of the plant personnel.
    Modified Start-up and Shutdown Procedures. Although flaring is
necessary to ensure safety during process upsets and malfunctions,
start-up and shutdown procedures can be designed so as to minimize
flaring. For example, depressurization of process vessels can be
performed more slowly so as to not overwhelm the fuel gas needs of the
refinery and/or the capacity of the flare gas recovery system.
Depending on the number of units being shut down at a given time,
nearly 100 percent of flaring can be eliminated during start-up and
shutdown. There are cases, such as emergency shutdowns for safety
reasons or approaching hurricanes, where the timing of the shutdown and
the magnitude of the number of processes needing to be shut down would
warrant the use of flaring. However, modified procedures should be able
to eliminate flaring associated with process start-ups and shutdowns
due to routine maintenance of select processes.
    Amine Scrubbers. Amine scrubber systems remove H2S and
other impurities from sour gas. Lean amine solution absorbs the
H2S from the sour gas in an absorption tower. The acid gas
is removed from the rich amine solution in a stripper, or still column.
The resulting lean amine is recirculated to the absorption tower, and
the stripped H2S is generally sent to the SRP. Vendors
generally provide redundant pumps to ensure continuous operation of the
system. Some refineries choose to store a day's worth of lean amine
solution in case the stripper fails; this allows the continuous
operation of the absorption tower. This option also requires adequate
empty storage space for the rich amine solution produced by the
absorption tower while the stripper is out of service.
    Redundant Sulfur Recovery Capacity. When a sulfur recovery unit
(SRU) malfunctions, the sour gas is typically flared to convert the
highly toxic H2S to less toxic SO2. As many SRU
recover more than 20 long tons of elemental sulfur per day, even short
sulfur recovery process upsets can result in several tons of
SO2 emissions. Furthermore, refineries often operate
multiple Claus sulfur recovery processes in parallel. Having an extra
Claus sulfur recovery train can dramatically reduce the likelihood of
sour gas flaring. Depending on the severity of the process upset,
having a redundant SRU can reduce these large SO2 releases
by as much as 100 percent.

C. What is the performance of control technologies for process heaters?

    The mechanisms by which NOX are formed in process
heaters are the same as for their formation in catalyst regenerators.
The possible control options are also the same. See section V.A.3 of
this preamble for a discussion of these formation mechanisms and
control technologies.

D. What is the performance of control technologies for sulfur recovery
systems?

    Sulfur recovery (the conversion of H2S to elemental
sulfur) is typically accomplished using the modified-Claus process. In
the Claus unit, one-third of the H2S is burned with air in a
reaction furnace to yield SO2. The SO2 then
reacts reversibly with H2S in the presence of a catalyst to
produce elemental sulfur, water, and heat. This is a multi-stage
catalytic reaction in which elemental sulfur is removed between each
stage, thereby driving the reversible reaction towards completion. The
gas from the final condenser of the Claus unit (referred to as the
``tail gas'') consists primarily of inert gases with less than 2
percent sulfur compounds. Additionally, the sulfur recovery pits used
to store the recovered elemental sulfur also have a potential for
fugitive H2S emissions. Typically a Claus unit recovers
approximately 94 to 97 percent of the inlet sulfur load as elemental
sulfur.
    There are some methods that extend the Claus reaction to improve
the overall sulfur collection efficiency of the SRP. For example, the
Superclaus[supreg] SRU is similar to the Claus unit. It contains a
thermal stage, followed by three to four catalytic reaction stages. The
first two or three catalytic reactors use the Claus catalyst, while the
last reactor uses a selective oxidation catalyst. The

catalyst in the last reactor oxidizes the H2S to sulfur at a
very high efficiency, recovering 99 percent of the incoming sulfur.
    There are a few refineries that operate non-Claus type SRU. All of
the refineries that use non-Claus SRU technologies have very low sulfur
production rates (2 LTD or less). There are several different trade
names for these ``other'' types of SRU, such as the LoCat[supreg],
Sulferox[supreg], and NaSH processes. These processes can achieve
sulfur recovery efficiencies of 99 percent or more, although they
typically yield a sulfur product that has limited market value because
the sulfur content is much lower than in the sulfur product from a
Claus unit (50 to 70 percent sulfur compared to 99.9 percent sulfur
from the Claus process).
    The primary means of reducing sulfur oxide emissions from the SRU
is to employ a tail gas treatment unit that recovers the sulfur
compounds and recycles them back to the inlet of the Claus treatment
train. There are three basic types of tail gas treatment units: (1)
Direct amine adsorption of the Claus tail gas; (2) catalytic reduction
of the tail gas to convert as much of the tail gas sulfur compounds to
H2S (coupled with amine adsorption or Stretford solution
eduction); and (3) oxidative tail gas treatment systems to convert the
Claus tail gas sulfur compounds to SO2 (coupled with an
SO2 recovery system).
    Direct Amine Adsorption. Direct amine adsorption of the Claus tail
gas is the least efficient of the tail gas treatment methods because
only about two-thirds of the sulfur in the direct Claus tail gas is
amenable to scrubbing (i.e., in the form of H2S). Direct
amine adsorption is therefore expected to increase the overall sulfur
recovery efficiency of the sulfur plant to approximately 99 percent.
However, direct amine adsorption alone is generally not expected to
reduce sulfur oxide concentrations to below 250 ppmv (i.e., enough to
meet the existing NSPS emission limits for Claus units greater than 20
LTD).
    Reductive Tail Gas Catalytic Systems. The most common reductive
tail gas catalytic systems in use at refineries include: (1) The
Shell[supreg] Claus Offgas Treatment (SCOT) unit; (2) the Beavon/amine
system; and (3) the Beavon/Stretford system. Each of these systems
consist of a catalytic reactor to convert the sulfur compounds
remaining in the Claus tail gas to H2S and an H2S
recovery system (an amine scrubber or a Stretford solution) to strip
the H2S from the tail gas. The recovered H2S is
then recycled to the front of the Claus unit. The overhead of the amine
scrubber or Stretford unit (caustic scrubber) may be vented to the
atmosphere or incinerated to convert any remaining H2S or
other reduced sulfur compounds to SO2. The total sulfur
recovery efficiency of a Claus/catalytic tail gas treatment train is
expected to be 99.7 to 99.9 percent.
    Oxidative Tail Gas Treatment Systems. The Wellman-Lord is the only
oxidative tail gas treatment system used in the United States. The
Wellman-Lord process uses thermal oxidation followed by scrubbing with
a sodium sulfite and sodium bisulfite solution to remove
SO2. The rich bisulfite solution is sent to an evaporator-
recrystallizer where the bisulfite decomposes to SO2 and
water and sodium sulfite is precipitated. The recovered SO2
is then recycled back to the Claus plant for sulfur recovery. The total
sulfur recovery efficiency of a Claus/oxidative tail gas treatment
train is expected to be 99.7 to 99.9 percent.

E. How did EPA determine the proposed standards for new petroleum
refining process units?

    Four sources of information were considered in reviewing the
appropriateness of the current NSPS requirements for new sources: (1)
Source test data from recently installed control systems; (2)
applicable State and local regulations; (3) control vendor emission
control guarantees; and (4) consent decrees. (A significant number of
refineries, representing about 77 percent of the national refining
capacity, are subject to consent decrees that limit the emissions from
subpart J process units.) Once we identified potential emission limits
for various process units, we evaluated each limit in conjunction with
control technology, costs, and emission reductions to determine BDT for
each process unit.
    The cost methodology incorporates the calculation of annualized
costs and emission reductions associated with each of the options
presented. Cost-effectiveness is the annualized cost of control divided
by the annual emission reductions achieved. Incremental cost-
effectiveness refers to the difference in annualized cost from one
option to the next divided by the difference in emission reductions
from one option to the next. For NSPS regulations, the standard metric
for expressing costs and emission reductions is the impact on all
affected facilities accumulated over the first 5 years of the
regulation. Details of the calculations can be found in the public
docket. Our BDT determinations took all relevant factors into account,
including cost considerations which were generally consistent with
other Agency decisions.
1. Fluid Catalytic Cracking Units
    Particulate Matter (PM) and Sulfur Dioxide (SO2). In order to
determine the appropriate emission limits for PM and SO2, we
evaluated PM and SO2 limits in conjunction with one another.
One of the reasons for this is that wet scrubbers control both PM and
SO2 emissions, and refineries will decide whether to choose
a wet scrubber as opposed to an ESP with catalyst additives based on
both the PM and the SO2 emission limit to be met.
    Currently, 40 CFR part 60, subpart J limits PM emissions from the
fluid catalytic cracking unit to 1.0 kg/Mg of coke burn-off. The limit
applies to filterable PM as measured by Method 5B or 5F in 40 CFR part
60, Appendix A. It excludes condensable PM such as sulfuric acid (under
Method 5B), sulfates that condense at temperatures greater than 320
[deg]F (under Method 5F), and all other condensables (using either
Method). The measurement of condensable PM is important to EPA's goal
of reducing ambient air concentrations of fine PM. Since promulgation
of Method 202 in 1991, EPA has been working to overcome problems
associated with the accuracy of Method 202 and will promulgate
improvements to the method in the future. The existing NSPS also
requires opacity, as measured using a continuous opacity monitoring
system, to be no more than 30 percent.
    The current standards in 40 CFR part 60, subpart J for
SO2 include three alternative formats: (1) If using an add-
on control device, reduce SO2 emissions by at least 90
percent or to less than 50 ppmv, (2) if not using an add-on control
device, limit sulfur oxides emissions (calculated as SO2) to
no more than 9.8 kg/Mg of coke burn-off, or (3) process in the fluid
catalytic cracking unit fresh feed that has a total sulfur content no
greater than 0.30 percent by weight. The 90 percent reduction, 9.8 kg/
Mg, and 0.3 percent feed sulfur formats were determined to be
equivalent for a unit operating with a feed that contains 3.5 percent
sulfur by weight before implementing a control measure.
    In reviewing the PM and SO2 emission limits, we
evaluated five combined options and a baseline. The baseline is
considered to be the current requirements, as described in the two
previous paragraphs. The first option is to maintain the existing
subpart J standard for PM and provide only the 50 ppmv concentration
limit for SO2. The additional options are a range of
emission limits coupled with a change in the compliance test method to
Method 5 to measure a portion of the

condensable PM. The second option is to combine Method 5 with the
existing 1.0 kg/Mg coke burn-off performance level, and a third option
is to lower the PM emission limit to 0.5 kg/Mg. Both the second and
third options include an SO2 limit of 50 ppmv. A fourth
option includes the PM limit of 0.5 kg/Mg presented in the third option
and a lower SO2 limit of 25 ppmv. The fifth option is to
lower the PM emission limit to 0.15 kg/Mg with an SO2 limit
of 25 ppmv. Costs and emission reductions for each option were
estimated as the increment between complying with subpart J and subpart
Ja.
    Option 1 includes the same emissions and requirements for PM as the
current 40 CFR part 60, subpart J. For SO2, this option
excludes the alternative compliance options of meeting a higher
emission limit without an SO2 control device or meeting a
limit on the sulfur content of the fresh feed. These two alternatives
are less stringent than the outlet concentration limit, and available
information indicates the concentration limits are achievable. An
advantage of the proposed concentration limit is that ongoing
compliance can be directly measured using a CEMS. The impacts of this
option are limited to the impacts of removing those alternative
compliance options for SO2 and are presented in Table 2 to
this preamble. To comply with Option 1 (i.e., meet the 50 ppmv limit
for SO2) we expect that the fraction of new sources choosing
wet scrubbers instead of ESP would be greater than under the existing
subpart J. Filterable PM emissions are assumed to be the same for both
types of control devices because the PM performance levels are the same
under both option 1 and the baseline subpart J requirements. However,
because condensable PM emissions are lower from wet scrubbers than from
ESP, this shift in the ratio of wet scrubbers to ESP would also result
in an estimated reduction in total PM emissions of 17 tons per year, as
shown in Table 2 to this preamble.
    Option 2 includes the same emission limit as current subpart J for
PM but requires compliance using Method 5 rather than Method 5B or
Method 5F. As noted above, Methods 5B and 5F exclude all PM that
condenses at temperatures below 320[deg]F, and Method 5F also excludes
sulfates that condense at temperatures greater than 320[deg]F. The PM
measured by Method 5 includes filterable PM that condenses above
250[deg]F in the front half of the Method 5 sampling train. Thus, the
estimated PM emission reductions achieved by this option equal the
amount of sulfates and other condensable PM between 250[deg]F and
320[deg]F that would be measured by Method 5 but not Method 5B or 5F.
The baseline emissions were estimated assuming Method 5B is used for
wet scrubbers and Method 5F is used for ESP. For SO2, Option
2 includes the same emission limit as described in Option 1, and the
estimated SO2 emission reductions are also the same. The
impacts of this option are presented in Table 2 to this preamble.
    Option 3 lowers the PM limit to 0.5 kg/Mg coke burn, again using
Method 5, and includes the same emission limit as described in Option 1
for SO2. The existing NSPS limit was based on control with
ESP. Those ESP were rated at efficiencies of only 85 to 90 percent.
More recently installed ESP have greater specific plate area, which
should result in better control efficiencies. In addition, many
refineries have installed wet scrubbers to control both PM and
SO2. At petroleum refineries, wet scrubbers typically
perform as well as, if not better than, ESP. Available test data
indicate that at least one ESP and one wet scrubber are reducing total
filterable PM to 0.5 kg/Mg of coke burn or less, as measured by Method
5-equivalent test methods. Based on this information, both ESP and wet
scrubbers can achieve PM emission levels below the level of the
existing PM standard, and a lower standard for new units is technically
feasible. The impacts of this option are presented in Table 2 to this
preamble.
    Option 4 includes the same PM limit as Option 3, and the discussion
presented for Option 3 applies to Option 4 as well. It also includes a
long-term limit for SO2 of 25 ppmv, averaged over 365 days,
in addition to the current subpart J limit of 50 ppmv, averaged over 7
days. These limits have been shown to be readily achievable by flue gas
desulfurization systems. Many fluid catalytic cracking units are now
subject to consent decrees that require control to these levels.
Petroleum refiners typically use wet scrubbers to control
SO2 emissions, and test data indicate that outlet
concentrations below 25 ppmv are common. At least one wet scrubber
manufacturer also provides performance guarantees to meet a 25 ppmv
emission limit. The incremental SO2 reductions for this
option relative to Option 3 are achieved by using catalyst additives in
the fluid catalytic cracking units that are assumed to be controlled
with ESP; fluid catalytic cracking units controlled with wet scrubbers
have the same SO2 emissions as under Option 3 because wet
scrubbers under all options are assumed to achieve SO2
emissions below 25 ppmv. The impacts of this option are presented in
Table 2 to this preamble.
    The final option, Option 5, includes a lower PM limit, 0.15 kg/Mg
of coke burn, measured using Method 5, and the same SO2
limits as Option 4. This PM limit is equivalent to the limit of 0.005
gr/dscf required by California's South Coast Air Quality Management
District (SCAQMD). To meet this PM limit, we expect that a refinery
would need an ESP rather than a wet scrubber because we are unaware of
any wet scrubber that is meeting this PM limit (and as in Option 4,
catalyst additives in the fluid catalytic cracking unit would be needed
to meet the SO2 limit). In addition, the refinery would
likely need ammonia injection to improve the performance of the ESP.
Based on test data from at least three fluid catalytic cracking units,
ammonia injection improves the control of filterable PM in ESP, but it
also produces a considerable amount of condensable PM. Therefore, the
estimated total PM reduction for this option is much lower (worse) than
the reduction that would be achieved under Option 4. The shift to ESP
for all new fluid catalytic cracking units under this option also
slightly degrades the estimated SO2 emissions reduction
relative to Option 4 because available data indicate that wet scrubbers
achieve lower SO2 emissions than ESP and catalyst additives.
In addition to reduced performance relative to Option 4, the capital
and annual costs of this option are considerably higher than for Option
4. The reduced performance of this option relative to Option 4 means
that incremental cost-effectiveness is not meaningful for this option.
The impacts of this option are presented in Table 2 to this preamble.

 Table 2.--National Fifth Year Impacts of Options for PM and SO2 Limits Considered for Fluid Catalytic Cracking
                                   Units Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                    Total       Emission     Emission    Cost-effectiveness ($/
                                      Capital    annual cost   reduction    reduction             ton)
              Option                    cost       ($1,000/    (tons PM/    (tons SO2/ -------------------------
                                      ($1,000)       yr)        yr) \a\        yr)        Overall    Incremental
----------------------------------------------------------------------------------------------------------------
1.................................          500        3,100           17        6,800          460
2.................................          670        3,600          350        6,800          500        1,400
3.................................       40,000        9,200        1,200        7,200        1,100        4,400
4.................................       40,000        9,500        1,200        8,300        1,000          220
5.................................      140,000       30,000          460        7,900        3,600         N/A
----------------------------------------------------------------------------------------------------------------
\a\ Both filterable and condensable PM.

    Based on our review of performance data and potential impacts, we
have determined that control of PM emissions (as measured by Method 5)
to 0.5 kg/Mg of coke burn or less and control of SO2
emissions to 25 ppmv or less averaged over 365 days and 50 ppmv or less
averaged over 7 days is BDT for new, reconstructed, or modified fluid
catalytic cracking units. The more stringent filterable PM control
level in Option 5 is technically achievable, but we rejected this
option because it results in higher total PM and SO2
emissions than Option 4. Option 4 was selected as BDT because it
achieves the best performance of the remaining options, and both
overall and incremental costs are reasonable.
    Table 3 to this preamble shows the impacts of Option 4 for modified
and reconstructed sources. Although the impacts of Option 4 are
reasonable, we are aware that there is some concern about the ability
to retrofit reconstructed and modified sources to meet these emission
limits. Specifically, there may be issues with physical space
availability, process unit or control device configurations, or other
factors that are not adequately included in our impacts analyses.
Therefore, we are co-proposing requiring reconstructed and modified
units to meet the current standards in 40 CFR part 60, subpart J. We
are requesting comment on specific examples, supported by data, of
situations that would support this proposed option.

  Table 3.--National Fifth Year Impacts of Proposed Option for PM and SO2 Limits for Reconstructed and Modified
                                                     Sources
----------------------------------------------------------------------------------------------------------------
                                                Total annual       Emission         Emission          Cost-
            Capital cost ($1,000)              cost  ($1,000/     reduction        reduction      effectiveness
                                                    yr)          (tons PM/yr)    (tons SO2/yr)       ($/ton)
----------------------------------------------------------------------------------------------------------------
31,000......................................           6,200              700            3,700            1,400
----------------------------------------------------------------------------------------------------------------

    Finally, available test data indicate that the two control devices
(an ESP and a wet scrubber) that reduce filterable PM to less than 0.5
kg/Mg coke burn (as well as at least one other ESP) also can meet a
total PM limit, including condensables, of 1.0 kg/Mg of coke burn
(i.e., demonstrate compliance using Method 5 for filterable PM and
Method 202 for condensable PM). Condensable sulfates and other
condensable compounds measured by Method 5 and Method 202 vary widely,
but the average is about 0.5 kg/Mg of coke burn-off. In an attempt to
create some incentive to begin measuring condensables using improved
Method 202, we are considering establishing an alternative PM limit of
1 kg/Mg coke burn, including condensables. Therefore, we are asking for
comments with rationale to either support or reject an alternative PM
limit that would be based on both filterable PM and condensable PM.
    Carbon Monoxide. The current standards in 40 CFR part 60, subpart J
limit CO emissions to 500 ppmv or less. This limit was established for
fluid catalytic cracking units that operate in either ``partial
combustion'' catalyst regeneration mode or ``complete combustion''
catalyst regeneration mode. In partial combustion mode, relatively
large amounts of CO are generated in the regenerator. The resulting CO
is then combusted in a CO or waste heat boiler. This operation results
in nearly complete combustion of the CO, with outlet concentrations on
the order of 25 to 50 ppmv being common. In complete combustion mode
the CO emissions from the regenerator are much lower, and a downstream
CO or waste heat boiler is impractical. However, complete combustion
catalyst regeneration was a recent advance at the time the current NSPS
was promulgated; test data were limited at that time, and a CO level of
500 ppmv was estimated to be a practical limit for the technology.
    After consideration of available information, we are proposing to
retain the current CO standard for new fluid catalytic cracking units.
Although test data show CO emissions from complete combustion
regenerators can be less than 500 ppmv, the lower levels generally are
achieved by operating with higher levels of excess air. Unfortunately,
this operation is likely to result in higher NOX emissions.
If a trade-off is necessary, limiting NOX emissions is a
higher priority than limiting CO emissions because NOX is a
precursor to fine PM and ground-level ozone, both of which have more
significant health impacts than CO. Available data also indicate that
formaldehyde emissions tend to increase with the higher oxidation/
combustion conditions needed to reduce CO emissions. Therefore, we
determined that control to 500 ppmv or less is still BDT for CO
emissions, and the proposed standards are based on this emission limit.
Accordingly, the proposed limit for 40 CFR part 60, subpart J poses no
additional costs over those incurred to comply with the existing NSPS.
    NOX. NOX emissions are not subject to control under the
existing NSPS in 40 CFR part 60, subpart J. However, several petroleum
refiners limit NOX emissions based on State regulations and
consent decrees. The emission limits to which refineries are subject
vary from facility to facility. We evaluated three options

as part of the BDT determination: Outlet NOX emission levels
of 80 ppmv, 40 ppmv, and 20 ppmv, each averaged over 7 days or less.
Each of these limits is technically feasible, but the technology needed
to meet them depends on the current NOX concentrations in
the vented gas streams, which are either uncontrolled or controlled to
levels required by existing State and local requirements.
    The estimated fifth year emission reductions and costs for each of
the options are summarized in Table 4. To estimate impacts for Option
1, we assumed that a few units have current NOX emissions
below 80 ppmv, and many other units can meet this level with combustion
controls (e.g., limiting excess O2 or using non-platinum
catalyst combustion promoters in a complete combustion catalyst
regenerator, or using flue gas recirculation or low-NOX
burners in a CO boiler after a partial combustion catalyst
regenerator). Other units with higher uncontrolled NOX
emissions levels will need to install more costly control technology
such as LoTOxTM or SCR in order to meet the 80 ppmv option.
All units will also incur costs for a continuous NOX
monitor. The costs for Options 2 and 3 are higher than for Option 1
because the ratio of add-on controls to combustion controls would
increase in order to meet the lower limits of 40 and 20 ppmv.
    Based on the impacts shown in Table 4, we determined that BDT is
option 1, a NOX emission limit of 80 ppmv. The costs of
option 1 are commensurate with the emission reductions while the more
stringent options would impose compliance costs that are not warranted
for the emissions reductions that would be achieved as shown by the
incremental cost effectiveness impacts shown in table 4. In general, we
expect that most sources will be able to meet the NOX limit
through combustion controls. In cases where add-on controls would be
necessary, however, there may be retrofit concerns for modified and
reconstructed sources. Therefore, we are co-proposing no new standards
for NOX emissions on modified or reconstructed sources and
are requesting comments on the necessity, feasibility and costs of
retrofits to meet the 80 ppmv limit for modified and reconstructed
sources.

  Table 4.--National Fifth Year Impacts of Options for NOX Limits Considered for Fluid Catalytic Cracking Units
                                      Subject to 40 CFR part 60, subpart Ja
----------------------------------------------------------------------------------------------------------------
                                   Total capital   Total annual      Emission       Cost effectiveness ($/ton)
             Option                   cost, $       cost, $/yr      reduction,   -------------------------------
                                    (millions)      (millions)      tons NOX/yr       Overall       Incremental
----------------------------------------------------------------------------------------------------------------
1...............................              28             7.3           3,500           2,100  ..............
2...............................              80              20           5,200           4,200           7,600
3...............................             120              30           5,800           5,500          16,000
----------------------------------------------------------------------------------------------------------------

    Available test data for units controlled with SCR indicate that
emissions less than 20 ppmv are continuously achievable when averaged
over long periods of time such as 365 days. Although we determined that
the average costs to meet such a limit are unreasonable, we are
requesting comment on whether there may be a subset of units for which
costs would be reasonable to meet lower limits such as 20 or 40 ppmv,
averaged over 365 days.
    Opacity. The current standards require fluid catalytic cracking
units to meet an opacity limit of 30 percent. This limit was included
as a means of identifying failure of the PM control device. This
objective is achieved much more effectively by monitoring control
device operating parameters or by using a PM CEMS. These monitoring
options are included in the proposed standards for PM. Therefore, the
proposed standards do not include an opacity emissions limit.
2. Fluid Coking Units
    The current NSPS includes no requirements for fluid coking units.
There are few fluid coking units at refineries in the U.S., but data in
the National Emission Inventory database shows the few existing units
are significant sources of PM, SO2, and NOX
emissions. Therefore, we evaluated several options as part of a BDT
determination for fluid coking units. All of the options we considered
are comparable to options that we considered for fluid catalytic
cracking units because of similarities in the function, operation, and
emissions of the two types of units.
    Particulate Matter and Sulfur Dioxide. To determine BDT for PM and
SO2 emissions we evaluated two options. Because control
technology can reduce both pollutants simultaneously, the options also
consider both pollutants. Option 1 is a PM limit of 1.0 kg/Mg coke burn
and a short-term SO2 limit of 50 ppmv, averaged over 7 days;
and Option 2 is a PM limit of 0.5 kg/Mg coke burn, a short-term
SO2 limit of 50 ppmv, averaged over 7 days, and a long-term
SO2 limit of 25 ppmv, averaged over 365 days. (Because
catalyst additives are not a feasible option for reducing
SO2 from a fluid coking unit, we did not consider the fifth
option evaluated for fluid catalytic cracking units.)
    The Energy Information Administration (EIA) Refinery Capacity
Report 2006 lists six fluid coking units; at least two of these coking
units are flexi-coking units that use the coking exhaust as a synthetic
fuel gas. Therefore, there are at most four fluid coking units in the
United States that could potentially become subject to the standard.
Although coking capacity is expected to increase, most new units are
expected to be delayed coking units. For this analysis, we assumed that
one existing fluid coking unit becomes a modified or reconstructed
source in the next 5 years. A wet scrubber is the most likely
technology that would be used to meet either Option 1 or Option 2. To
estimate the impacts, we estimated costs for a basic wet scrubber to
meet Option 1 and an enhanced wet scrubber to meet Option 2. The
resulting emission reductions and costs for both of the options are
shown in Table 5 to this preamble. The costs for both options are
reasonable. Therefore, we determined that BDT is Option 2 which
requires technology that reduces PM emissions to 0.5 kg/Mg of coke burn
and reduces SO2 emissions to 50 ppmv, averaged over 7 days,
and 25 ppmv, averaged over 365 days. We are proposing standards
consistent with these levels.

Table 5.--National Fifth Year Impacts of Options for PM and SO2 Limits Considered for Fluid Coking Units Subject
                                          to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                                Emission     Emission    Cost-effectiveness ($/
                                      Capital       Total      reduction    reduction             ton)
              Option                    cost     annual cost   (tons PM/    (tons SO2/ -------------------------
                                      ($1,000)   ($1,000/yr)      yr)          yr)        Overall    Incremental
----------------------------------------------------------------------------------------------------------------
1.................................       14,000        4,700        1,700       21,000          210  ...........
2.................................       14,000        4,800        2,000       21,000          210          120
----------------------------------------------------------------------------------------------------------------

    Nitrogen Oxides (NOX). To determine BDT for NOX
emissions, we evaluated three options: Outlet NOX emission
levels of 80 ppmv, 40 ppmv, and 20 ppmv, each averaged over 7 days or
less. The specific technology that will be needed to meet these levels
will depend on the NOX concentration in the exhaust gas
stream from uncontrolled fluid coking units. As noted in the discussion
above for PM and SO2 options, we estimated that only one
fluid coking unit will be modified or reconstructed in the next 5
years, and there will be no new units constructed. Because each unit is
likely to have a different uncontrolled NOX concentration in
its exhaust stream, we developed impacts for a composite model unit
based on a weighted distribution of all the various types of controls
(low-efficiency combustion controls, higher efficiency combustion
controls, and add-on controls such as LoToxTM or SCR). As in
the analysis for fluid catalytic cracking units, the ratio of add-on
controls to combustions controls increases from Option 1 through Option
3. The results of this analysis are shown in Table 6 to this preamble.

Table 6.--National Fifth Year Impacts Options for NOX Limits Considered for Fluid Coking Units Subject to 40 CFR
                                               Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total                     Emission    Cost-effectiveness  ($/
                                                  capital    Total annual   reduction,            ton)
                    Option                        cost, $     cost, $/yr   (tons  NOX/ -------------------------
                                                (millions)    (millions)       yr)        Overall    Incremental
----------------------------------------------------------------------------------------------------------------
1............................................           4.5          0.97          760        1,300
2............................................           9.5          2.1           980        2,200        5,300
3............................................          13            2.9         1,000        2,800       12,000
----------------------------------------------------------------------------------------------------------------

    The costs for option 1 are commensurate with the emission
reductions, but the incremental impacts for options 2 and 3 are not
reasonable, as shown in Table 6. Based on these potential impacts and
available performance data, we have determined that BDT is technology
needed to meet an outlet NOX concentration of 80 ppmv or
less, and we are proposing this emission limit as the performance
standard for NOX emissions from fluid coking units. However,
there are uncertainties in this analysis. For example, if the few
existing units are not readily amenable to retrofitting NOX
controls, the cost and emission reduction impacts might no longer be
favorable, and we would conclude that no control is BDT. Therefore, we
are co-proposing no new standard for NOX emissions from
fluid coking units.
3. Sulfur Recovery Plants
    Emission limits in the existing NSPS (40 CFR part 60, subpart J)
apply to Claus SRP with a capacity greater than 20 LTD. The emission
limits are consistent with an overall sulfur recovery efficiency of
99.9 percent (i.e., 250 ppmv SO2 for the Claus unit followed
by oxidative tail gas treatment, and 10 ppmv H2S and 300
ppmv total reduced sulfur compounds for a Claus unit followed by
reductive tail gas treatment). Although small SRP and non-Claus SRP are
not subject to the existing NSPS, they are often subject to control.
For example, Texas requires sulfur removal efficiencies of 99.8 percent
for SRP with capacities greater than 10 LTD and 96 percent to 98.5
percent for SRP with capacities less than or equal to 10 LTD. In
addition, a few consent decrees require 95 percent sulfur recovery for
Claus SRP with capacities less than 20 LTD.
    To determine BDT we evaluated 4 options. The options are based on
various sulfur recovery efficiencies for SRP with capacities less than
20 LTD, and all of the options include the same 99.9 percent efficiency
as in the current standards for SRP with capacities greater than 20
LTD. Option 1 is based on 99 percent recovery for SRP with capacities
between 10 LTD and 20 LTD, and 95 percent recovery for SRP with
capacities less than 10 LTD. Option 2 is based on 99 percent recovery
for all SRP with capacities less than 20 LTD. Option 3 is based on 99.9
percent recovery for SRP with capacities between 10 LTD and 20 LTD, and
99 percent recovery for SRP with capacities less than 10 LTD. Option 4
is based on 99.9 percent recovery for all SRP, regardless of size or
design. All of the options include 99.9 percent recovery for SRP larger
than 20 LTD (both Claus and non-Claus units) because we are not aware
of a more effective SO2 control technology. The 95 percent
option is equivalent to the efficiency of a two-stage Claus unit
without controls. The 99 percent and 99.9 percent recovery levels are
achievable for SRP of all sizes by various types of tail gas
treatments, as discussed in section V.D of this preamble.
    The estimated fifth year emission reductions and costs for each of
the options are summarized in Table 7. These values reflect the impacts
only for SRP smaller than 20 LTD because we expect that all non-Claus
units will be smaller than 20 LTD and because the impacts for larger
Claus units would be the same as to comply with the existing standards
in subpart J. The costs for Options 1, 2, and 3 are reasonable. We then
evaluated the incremental costs and emission reductions between the
options. We found that Option 2 is the most stringent option for which
incremental costs are reasonable compared to the incremental emission
reduction between the options.
    Based on the available performance data and cost considerations, we
have concluded that tail gas treatments that achieve 99.9 percent
control are still

BDT for SRP with capacities greater than 20 LTD, and tail gas
treatments that achieve 99 percent recovery are BDT for SRP with
capacities less than 20 LTD. Therefore, we are proposing standards for
SO2 and H2S emissions from SRP with capacities
larger than 20 LTD that are equivalent to the existing standards, and
we are proposing standards for SRP with capacities smaller than 20 LTD
that would limit emissions of sulfur to less than 1 percent by weight
of the sulfur recovered.

Table 7.--National Fifth Year Impacts of Options for SO2 Limits Considered for Sulfur Recovery Plants Subject to
                                           40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total                     Emission    Cost-effectiveness  ($/
                                                  capital    Total annual   reduction,            ton)
                    Option                        cost, $     cost, $/yr   (tons  SO2/ -------------------------
                                                (millions)    (millions)       yr)        Overall    Incremental
----------------------------------------------------------------------------------------------------------------
1............................................          0.27          0.14          180          780
2............................................          1.1           0.68          550        1,200        1,500
3............................................          1.9           1.0           590        1,700        8,200
4............................................          4.5           2.3           670        3,400       15,000
----------------------------------------------------------------------------------------------------------------

4. Process Heaters and Other Fuel Gas Combustion Devices Sulfur Dioxide
    The current NSPS in 40 CFR part 60, subpart J limits SO2
emissions from fuel gas combustion devices by specifying that the
H2S content of fuel gas must be less than or equal to 230
mg/dscm, averaged over 3 hours (equivalent to 160 ppmv averaged over 3
hours). Alternatively, any fuel gas may be combusted, provided the
outlet SO2 emissions are controlled to no more than 20 ppmv
(dry basis, 0 percent excess air). When the current NSPS was
promulgated, we concluded that amine scrubbing as well as new processes
that use other scrubbing media represented BDT for continuous reduction
of H2S from fuel gas. The 160 ppmv concentration limit was
consistent with good operation of such scrubbing processes. In
addition, burning such fuel gas will result in an SO2
concentration in the exhaust gas of about 20 ppmv.
    After consideration of current operating practices, we concluded
that amine scrubbing units are still the predominant technology for
reduction of H2S in fuel gas (and SO2 emissions
from subsequent fuel gas combustion). Considering the variability of
the fuel gas streams from various refinery processing units, 160 ppmv
also is still a realistic short term H2S concentration
limit. However, one California Air Quality Management District rule
sets a 40 ppmv H2S limit in fuel gas (averaged over 4
hours), and several refiners have reported that the typical fuel gas
H2S concentrations (after scrubbing) are in the same range.
Additionally, amine scrubbing technology can be designed and is, in
fact, being used to achieve much lower (1 to 5 ppmv) H2S
concentrations in product gas applications. Based on this information,
we concluded that additional SO2 control could be achieved
by requiring SO2 emission limits with both long-term and
short-term averaging periods.
    We considered three options for increasing SO2 control
of fuel gas combustion units: Outlet SO2 emission levels of
10 ppmv, 8 ppmv, and 5 ppmv SO2, each averaged over 365
days. Each of the options also includes the same 20 ppmv 3-hour
SO2 concentration limit as in the current NSPS. To achieve
each of these options, we expect that petroleum refiners will increase
their amine recirculation rates to reduce the H2S
concentration in the fuel gas. We estimate that meeting the options
will increase steam consumption for a typical scrubbing unit by about
5, 7, and 10 percent, respectively. No new equipment or other capital
expenditures would be necessary. The estimated fifth-year impacts of
each of these options are presented in Table 8 to this preamble.
Overall costs for all the options are reasonable compared to the
emission reduction achieved. We further evaluated the incremental costs
and reductions between the 3 options and found that they were
reasonable for Options 1 and 2, while the incremental cost for Option 3
is not.

  Table 8.--National Fifth Year Impacts of Options for SO2 Limits Considered for Process Heaters and Other Fuel
                          Gas Combustion Devices Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                                             Emission    Cost-effectiveness  ($/
                                               Capital cost  Total annual   reduction             ton)
                    Option                        ($1,000)       cost      (tons  SO2/ -------------------------
                                                              ($1,000/yr)      yr)        Overall    Incremental
----------------------------------------------------------------------------------------------------------------
1............................................           0        2,000           1,000        1,900
2............................................           0        2,900           1,300        2,200        3,500
3............................................           0        4,100           1,600        2,600        4,700
----------------------------------------------------------------------------------------------------------------

    Based on these impacts and consideration of current operating
practices, we concluded that BDT is use of technology that reduces the
SO2 emissions from fuel gas combustion units to 8 ppmv or
less averaged over 365 days and 20 ppmv or less averaged over 3 hours.
Therefore, we are proposing SO2 standards consistent with
this determination. We are also requesting comment on the proposed
long-term concentration limit and the length of the averaging period.
    Although the proposed emission limits are based primarily on the
fuel gas desulfurization technologies (e.g., amine scrubbing), new
process heaters, regardless of fuel type, also would be subject to
these emission limits. New process heaters can elect to meet these
emission limits by using treated fuel gas, low sulfur distillate fuel
oils, or flue gas desulfurization or other SO2 add-on
controls. Considering the low sulfur fuel standards and available
control technologies, we believe the 20 ppmv 3-hour average
SO2 emission limit and an

8 ppmv 365-day average emission limit represent the performance of BDT
regardless of whether the new process heaters use gaseous or liquid
fuels.
    The current NSPS allows refineries to demonstrate compliance with
fuel gas concentration limits for H2S as a surrogate for
SO2 emission limits. This approach is reasonable when
H2S is the only sulfur-containing compound in the fuel gas
because the H2S concentration in the fuel gas that is
equivalent to the SO2 concentration in the exhaust from the
fuel gas combustion unit can be easily estimated. However, based on
available data, we understand that a significant portion of the sulfur
in fuel gas from coking units is in the form of methyl mercaptan and
other reduced sulfur compounds. These compounds will also be converted
to SO2 in the fuel gas combustion unit, which means the
SO2 emissions will be higher than the amount predicted when
H2S is the only sulfur-containing compound in the fuel gas.
Therefore, for process heaters and other fuel gas combustion devices
that burn only fuel gas, we are proposing two alternatives to the
SO2 emission limit. The first option would require
measurement of H2S if none of the fuel gas is from a coking
unit. The H2S concentration limits that would be equivalent
to the SO2 emission limits are 160 ppmv, averaged over 3
hours, and 60 ppmv averaged over 365-days. The second option would
require measurement of TRS instead of H2S when any of the
fuel gas burned in the process heater or other fuel gas combustion unit
is from a coking unit. The TRS concentration limits would be the same
as the H2S concentration limits. We are requesting comment
on the proposed requirement to measure the TRS concentration. We are
interested in any technological limitations of this option and whether
there are other fuel gas streams that contain reduced sulfur compounds
that should not be subject to the same requirement.
    In addition to the proposed SO2 emission limits and
H2S and TRS concentration limits, we are also proposing to
include the same exemptions from fuel gas continuous monitoring
requirements that we are proposing for subpart J. See section IV.A of
this preamble for a discussion of our rationale for these proposed
exemptions.
    NOX. NOX emissions from process heaters are not subject
to control under the existing NSPS in 40 CFR part 60, subpart J.
However, several petroleum refiners are subject to NOX
control requirements for process heaters in their consent decrees and
State regulations. The emission limits to which refineries are subject
vary from facility to facility. We evaluated four options as part of
the BDT determination. Each option consists of a potential
NOX emission limit and applicability based on process heater
size. Option 1 would limit NOX emissions to 80 ppmv or less
for all process heaters with a capacity greater than 20 million British
thermal units per hour (MMBtu/hr). Option 2 would limit NOX
emissions to 40 ppmv or less for all process heaters with a capacity
greater than 20 MMBtu/hr. Option 3 would limit NOX emissions
to 30 ppmv or less for all process heaters with a capacity greater than
40 MMBtu/hr. Option 4 would limit NOX emissions to 40 ppmv
or less for process heaters with a capacity greater than 20 MMBtu/hr or
less than or equal to 100 MMBtu/hr, and to 20 ppmv or less for process
heaters with a capacity greater than 100 MMBtu/hr. In each option, the
NOX concentration is based on a 24-hour rolling average.
    The estimated fifth year emission reductions and costs for each
option are summarized in Table 9. We believe that nearly all process
heaters at refineries that will become subject to subpart Ja can meet
Option 1 using combustion controls (low NOX burners or ultra
low NOX burners). Stepping from Option 1 through Option 4
increases the fraction of process heaters that would need to use more
efficient control technologies, such as LoTOxTM or SCR, to
meet the NOX concentration limit. The options include a
minimum 20 MMBtu/hr size threshold because none of the control
technologies are cost effective for units with smaller capacities.

  Table 9.--National Fifth Year Impacts Options for NOX Limits Considered for Process Heaters Subject to 40 CFR
                                               Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                    Total        Total       Emission    Cost effectiveness ($/
                                                   capital       annual     reduction,            ton)
                     Option                        cost, $     cost, $/yr  (tons  NOX/ -------------------------
                                                  (millions)   (millions)      yr)        Overall    Incremental
----------------------------------------------------------------------------------------------------------------
1..............................................          140           28       17,000        1,600  ...........
2..............................................          200           38       20,000        1,900        3,100
3..............................................          280           52       21,000        2,600       85,000
4..............................................          470           88       22,000        4,000       27,000
----------------------------------------------------------------------------------------------------------------

    Based on the impacts in Table 9, the overall costs of option 1 and
option 2 are reasonable compared to the emission reductions. The
incremental cost, however, between options 1 and 2 is not commensurate
with the additional emission reduction achieved. Therefore, BDT for
process heaters greater than 20 MMBtu/hr was determined to be
technology that achieves an outlet NOX concentration of 80
ppmv or less, and we are proposing standards for NOX
emissions from process heaters consistent with this determination.
5. Work Practice Standards for Fuel Gas Production Units
    We reviewed applicable state and local regulations and consent
decree requirements and met with individual refinery representatives
regarding their pollution prevention practices. The pollution
prevention practices identified included flare minimization plans, fuel
gas recovery requirements, start-up and shutdown requirements, and
sulfur shedding plans (including redundant sulfur recovery capacity).
Based on our review, all of these approaches could be expected to
reduce emissions of VOC and SO2 to the atmosphere. As
described in the following subsections, we reviewed these pollution
prevention practices and are proposing three different work practice
standards. Work practice standards are being proposed because it is not
feasible to prescribe or enforce a standard of performance for these
emission sources. As provided in section 111(h) of the Clean Air Act,
we may promulgate design, equipment, work practice, or operational
standards when it is not feasible to prescribe or enforce a standard of