[6560-50-P]

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2007-0011; FRL-        ]

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 process units at petroleum
refineries.  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 must be received on or before [INSERT DATE 30 DAYS FROM
DATE OF PUBLICATION], unless a public hearing is requested by [INSERT
DATE 10 DAYS FROM DATE OF PUBLICATION].  If a hearing is requested on
this proposed rule, written comments must be received by [INSERT DATE 45
DAYS FROM DATE OF PUBLICATION].  Under the Paperwork Reduction Act,
comments on the information collection provisions must be received by
the Office of Management and Budget (OMB) on or before [INSERT DATE 30
DAYS FROM DATE OF PUBLICATION].

ADDRESSES:  Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2007-0011, by one of the following methods:

www.regulations.gov:  Follow the on-line instructions for submitting
comments.

E-mail<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 www.regulations.gov, including any personal
information provided, unless the comment includes information claimed to
be Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute.  Do not submit information that you
consider to be CBI or otherwise protected through www.regulations.gov or
e-mail.  The www.regulations.gov 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
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   HYPERLINK
"http://www.regulations.gov"  www.regulations.gov  index.  Although
listed in the index, some information is not publicly available, e.g.,
CBI or other information whose disclosure is restricted by statute.
Certain other material, such as copyrighted material, will be publicly
available only in hard copy.  Publicly available docket materials are
available either electronically in www.regulations.gov or in hard copy
at the EPA Docket Center, Standards of Performance for Petroleum
Refineries Docket, EPA West, 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:<PHONE_NUMBER>; 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:

Category	NAICS   code1	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
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
[INSERT DATE 10 DAYS FROM DATE OF PUBLICATION], a public hearing will be
held on [INSERT DATE 15 DAYS FROM DATE OF PUBLICATION].  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 standards for fuel gas

    production (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?

VI.  Request for Comments

VII.  Modification and Reconstruction Provisions

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.    SEQ CHAPTER \h \r 1 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 [INSERT DATE OF PUBLICATION] 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 [INSERT DATE OF
PUBLICATION] 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 PM 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.

	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 60.103a(a)
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)?

Five 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 an emissions
minimization plan is proposed for all planned start-up and shutdown
events to minimize direct discharges to the atmosphere and discharges to
the flare system during planned start-ups and shutdowns.  Third, a
requirement for a sulfur shedding plan is proposed to minimize SO2
releases that may be caused by process upsets or malfunctions affecting
the amine scrubbing system, SRP, or other systems used to comply with
the fuel gas and SRP emission limits.  Fourth, the proposed rule
includes a requirement to perform a root-cause analysis for any SO2
releases in excess of 500 lbs per day over the allowable emission
limits; this proposed requirement also requires that a root-cause
analysis be performed for any SO2 releases in excess of 500 lbs per day
due to a process start-up, shutdown, upset, or malfunction of an
affected unit.  Fifth, 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.
We are co-proposing only the fifth of these work practice standards for
new, reconstructed, or modified units.

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 [INSERT DATE OF PUBLICATION], 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 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 sulfur recovery plant) and/or are not
cost-effective to amine treat 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 (NESHAP)
From Petroleum Refineries (40 CFR part 63, subpart CC), specifically
either 40 CFR 63.647 or 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 sulfur recovery plant, 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 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 to identify these emergency flares and to
verify 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
sulfur recovery plant may consist of multiple units, and the types of
units that are part of a sulfur recovery plant 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 sulfur
recovery plant 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 sulfur dioxide 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 NESHAP 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.

Section	Proposed technical correction and 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 subpart J; sources
beginning construction, reconstruction, or modification after this date
will be subject to 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 §60.105(a)(4)
and clarify that there is a choice of monitoring requirements.

§60.105(a)(3)(iv)	Replace “accurately represents the S2 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 §60.104(b)(1)” with
“seeks to comply specifically with the 90 percent reduction option
under §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 §60.105(a)(1) with a
correct reference to §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 §60.107(e) as §60.107(f) to allow
space for a new paragraph (e).

§60.107(g)	Redesignate current §60.107(f) as §60.107(g) to allow
space for a new paragraph (e).

§60.108(e)	Replace the incorrect reference to §60.107(e) with a
correct reference to §60.107(f).

§60.109(b)(2)	Add a reference to §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 §60.109(b)(2) as §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 (ESPs) 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.  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 ESPs (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 ESPs used to control fluid catalytic
cracking units.  Wet scrubbers are generally more costly to operate than
ESPs 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 ESPs 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 ESPs 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 sulfur recovery plant.

	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 ppm 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 spray dryer adsorber
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 120OC to 180OC
(250OF to 350OF).  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 sulfur
recovery plant, 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

	Nitrogen oxides are formed in a catalyst regenerator (and downstream CO
boiler, if present) by the oxidation of molecular nitrogen 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 molecular nitrogen (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 flue gas
recirculation 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 (LNBs), the control efficiency increases to
50-72 percent.

Low-NOx burner 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 LNBs are staged fuel and
staged air burners.  Staged fuel LNBs 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
LNBs 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.

	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 molecular nitrogen 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 230ºC to 400ºC (450ºF to 750ºF).  The SCR technology is
capable of NOx reduction efficiencies of 90 percent or higher.

	SNCR Technology.  An SNCR process is based on the same basic chemistry
of reducing the NO and NO2 in the flue gas to molecular nitrogen 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 870ºC to 1,090ºC (1,600ºF to 2,000ºF).  The NOx
reduction levels for SNCR are in the range of approximately 30 to 50
percent.

	LoTOxTM Technology.  The LoTOxTM process (i.e., low –temperature
oxidation) is a patented technology that uses ozone to oxidize NOx to
nitric pentoxide and other higher order nitrogen oxides, all of which
are water soluble and easily removed from exhaust gas in a wet scrubber.
 The system operates optimally at temperatures below 300°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 sulfur recovery plant will help to
minimize sour gas flaring that might be caused by a malfunction in the
sulfur recovery plant.  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 shutdown 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 shutdown 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 sulfur recovery plant.  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 SRUs 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 sulfur recovery plant.  For
example, the Superclaus® sulfur recovery unit 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 SRUs.  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®, Sulferox®,
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®
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 and Sulfur Dioxide.  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°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 ESPs 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
ESPs, this shift in the ratio of wet scrubbers to ESPs 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°F, and Method 5F also excludes sulfates that
condense at temperatures greater than 320°F.  The PM measured by Method
5 includes filterable PM that condense above 250°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°F and 320°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
ESPs.  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 ESPs.  Those
ESPs were rated at efficiencies of only 85 to 90 percent.  More recently
installed ESPs 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, ESPs.  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 ESPs 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 ESPs; 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 ESPs, 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 ESPs 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 ESPs 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

Option	Capital Cost ($1,000)	Total Annual Cost ($1,000/yr)	Emission
Reduction (tons PM/yr)a	Emission Reduction (tons SO2/yr)
Cost-Effectiveness ($/ton)

	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 this option on these
sources 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

Capital Cost ($1,000)	Total Annual Cost ($1,000/yr)	Emission Reduction
(tons PM/yr)	Emission Reduction (tons SO2/yr)	Cost-Effectiveness ($/ton)

31,000	6,200	700	3,700	1,400

Finally, available test data indicate that the two control devices 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 Ja poses no additional costs over those incurred to
comply with the existing NSPS.

Nitrogen Oxides.  Nitrogen oxide 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 that will be needed to meet
them will depend on the current NOx concentrations in the vented gas
streams, which are either uncontrolled or the levels required by
existing 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.

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

Option	Total capital cost, $ (millions)	Total Annual

Cost, $/yr (millions)	Emission reduction, tons NOx/yr	Cost effectiveness

($/ton)

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.  We are also asking for comments on whether
assumptions in our cost analysis are overly conservative.

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 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 day.  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

Option	Capital Cost ($1,000)	Total Annual Cost ($1,000/yr)	Emission
Reduction (tons PM/yr)	Emission Reduction (tons SO2/yr)
Cost-Effectiveness ($/ton)

	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

	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

Option	Total capital cost, $ (millions)	Total Annual

Cost, $/yr (millions)	Emission reduction, tons NOx/yr	Cost-effectiveness

($/ton)

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 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 SRPs 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 SRPs and non Claus SRPs 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 SRPs with capacities
greater than 10 LTD and 96 percent to 98.5 percent for SRPs with
capacities less than or equal to 10 LTD.  In addition, a few consent
decrees require 95 percent sulfur recovery for Claus SRPs with
capacities less than 20 LTD.

	To determine BDT we evaluated 4 options.  The options are based on
various sulfur recovery efficiencies for SRPs with capacities less than
20 LTD, and all of the options include the same 99.9 percent efficiency
as in the current standards for SRPs with capacities greater than 20
LTD.  Option 1 is based on 99 percent recovery for SRPs with capacities
between 10 LTD and 20 LTD, and 95 percent recovery for SRPs with
capacities less than 10 LTD.  Option 2 is based on 99 percent recovery
for all SRPs with capacities less than 20 LTD.  Option 3 is based on
99.9 percent recovery for SRPs with capacities between 10 LTD and 20
LTD, and 99 percent recovery for SRPs with capacities less than 10 LTD.
Option 4 is based on 99.9 percent recovery for all SRPs, regardless of
size or design.  All of the options include 99.9 percent recovery for
SRPs 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 SRPs 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 SRPs 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 SRPs with capacities greater than 20 LTD, and tail gas
treatments that achieve 99 percent recovery are BDT for SRPs with
capacities less than 20 LTD.  Therefore, we are proposing standards for
SO2 and H2S emissions from SRPs with capacities larger than 20 LTD that
are equivalent to the existing standards, and we are proposing standards
for SRPs 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

Option	Total capital cost, $ (millions)	Total Annual

Cost, $/yr (millions)	Emission reduction, tons SO2/yr	Cost effectiveness

($/ton)

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 period.

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

Option	Capital Cost ($1,000)	Total Annual Cost ($1,000/yr)	Emission
Reduction (tons SO2/yr)	Cost-Effectiveness ($/ton)

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.

Nitrogen Oxides.  Nitrogen oxide 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

Option	Total capital cost, $ (millions)	Total Annual

Cost, $/yr (millions)	Emission reduction, tons NOx/yr	Cost effectiveness

($/ton)

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 five 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 performance.  It is
not feasible to prescribe or enforce a standard of performance for these
sources because either the pollution prevention measures eliminates the
emission source, so that there are no emissions to capture and convey,
or the emissions are so transient, and in some cases, occur so randomly,
that the application of a measurement methodology to these sources is
not technically and economically practical.

Elimination of Routine Flaring.  Flares are first and foremost a safety
device used to reduce emissions from emergency pressure relief of gases
from refinery process units.  We in no way want to limit the use of
flares for emergency releases.  However, many refineries also routinely
use flares as an emission control device under normal operating
conditions.  Fuel gases produced within the refinery can be roughly
divided into two categories based on the fuel gas stream pressure.  Fuel
gases produced in processes operated at higher pressures are easily
routed to the fuel gas system; however, fuel gases that are produced
from units operated near atmospheric pressures are not as easily routed
to the fuel gas system.  These “low pressure” fuel gases are often
routed to flares because the flare gas system operates at a much lower
pressure than the fuel gas system.  Flare gas recovery systems are
designed to compress the low pressure fuel gases, creating a high
pressure fuel gas stream that can readily be added to the fuel gas
system.

In 1998, the South Coast Air Quality Management District developed a
rule requiring refineries to measure the flow rate and hydrocarbon
content of the gases sent to a flare.  This South Coast rule, although
it did not set prescriptive emission limits, led to reduced flaring as
refinery operators, armed with the monitoring results, identified
cost-effective flare gas minimization or recovery projects.  In 2005,
South Coast amended this rule and established a no routine flaring goal
based on the cost and anticipated emission reductions of flare gas
recovery systems.  The Bay Area Air Quality Management District also
adopted a rule requiring flare monitoring in 2003 and adopted a rule to
minimize flaring in 2006.

We considered adopting the South Coast and Bay Area rules for this NSPS
for new flare systems.  However, many refinery flares operate for 50
years, so very few flares or flare systems are expected to become
subject to NSPS requirements, even after several decades.  Instead, we
are proposing to add “fuel gas producing process units” as a new
affected source under subpart Ja and focus the requirement on
eliminating routine flaring of fuel gas at the process units producing
the fuel gas.  A refinery owner or operator installing a new process
unit that produces low pressure fuel gas can then decide whether it is
more economical to divert the fuel gas to a nearby low-pressure heater
or boiler, pressurize the fuel gas so that it can be diverted to the
fuel gas system, or install a system-wide flare gas recovery system.
The proposed work practice standard is designed to allow flexibility in
compliance approaches without imposing undue restrictions on the use of
flares during malfunctions or other conditions wherein flaring is the
best environmental management practice considering the safety of the
plant personnel and surrounding people.  Additionally, several new fuel
gas producing units are expected to be installed every year, so by
regulating the fuel gas producing units we not only provide flexibility,
but we also increase the rate at which the no routine flaring
requirement is implemented within the industry.

The impacts for this work practice are highly dependent on the amount of
fuel gas generated by different fuel gas combustion units.  Recovered
fuel gas reduces the amount of natural gas a refinery must purchase to
operate their process heaters.  For example, fuel gases generated by
fluid catalytic cracking units and coking units are routinely recovered
into the fuel gas system due to the quantity of fuel gas generated in
the process.  For these systems, the savings associated with the
recovered fuel gas provides a return on the capital investment
associated with the compressor and ancillary equipment needed to
recovery the fuel gas.  For other fuel gas producing units, such as
reforming units, it is possible to route the fuel gas directly to the
unit’s process heater without additional gas compression.  For a few
refineries, a system-wide flare gas recovery system may be required.

We estimated planning and design costs for assessing methods to recover
or otherwise avoid the release of fuel gas from new fuel gas producing
units.  As described previously, for many fuel gas producing units, the
cost savings associated with the recovered fuel recovers the costs of
the recovery equipment within the life-span on the equipment so that the
annualized cost of controls is zero or slightly negative (indicating a
cost savings).  As a worst-case scenario, we used the impacts developed
by the Bay Area for a system-wide flare gas recovery system.  The total
annualized cost of the system was estimated to be approximately
$2-million; no credit was provided for the heating value of the flare
gas recovered.  VOC emission reductions were estimated to be
approximately 1,000 tons per year and SO2 emissions were estimated to be
3,500 tons per year.  The cost-effectiveness on the flare gas recovery
system was estimated to be approximately $2,000/ton of VOC removed and
approximately $570/ton of SO2 removed.  Therefore, even when fuel
credits are not considered, flare gas recovery is cost-effective as an
emissions control device.  When properly sized, these flare gas recovery
systems can eliminate all routine flaring.  Therefore, eliminating
routine flaring by use of fuel gas recovery, in-process fuel use, or
system wide flare gas recovery is determined to be BDT.

We request comment on alternative means of eliminating routine flaring.
As noted previously, a simple requirement to monitor gas flow and
composition of gases sent to the flares resulted in reduced use of
flares.  An exemption of this monitoring requirement for flare systems
that install flare gas recovery could provide refineries an incentive to
install flare gas recovery systems.  We request comment on this
alternative and on the need to monitor flares that have flare gas
recovery systems to ensure that the flare gas recovery system is
properly sized and that no routine flaring is occurring.

Additionally, we understand that there are a limited number of
refineries that produce more fuel gas than they can use in the refinery
process heaters or steam boilers.  These “fuel gas rich” refineries
contend that flaring is BDT for these refineries.  Although we believe
that other options exist, such as building an electric co-generating
unit, the cost-effectiveness of such an endeavor is very site-specific,
and we cannot conclude at this time that co-generation or other projects
that beneficial use the fuel gas are BDT.  Therefore, we are
co-proposing no requirement for fuel gas producing units.  We request
comment on the actual number and location of “fuel gas rich”
refineries.  We also request comment and data regarding the technical
and economical feasibility of alternatives for “fuel gas rich”
refineries to avoid routine flaring.

Emission Prevention During Planned Start-ups and Shutdowns.  Flaring and
direct venting of certain gas streams have been routinely used during
planned start-up and shutdown of process units to quickly bring a
process unit online or offline.  These flaring and venting episodes have
traditionally been exempt from any emission limitations.  Nonetheless,
some refineries have chosen to evaluate their start-up and shutdown
emissions and alter their procedures so as to reduce or eliminate direct
venting or flaring during planned start-up and shutdown events.

Typically, alternative start-up and shutdown procedures that reduce
atmospheric emissions or flaring require more time to complete than
conventional procedures.  Therefore, there is a cost associated with the
alternative procedures in terms of potential product/productivity loss.
For refineries that have system-wide flare gas recovery systems, it may
be a simple matter of scheduling the start-up or shutdown during a time
when limited other flare gas is being generated so as to not overwhelm
the flare gas recovery system.  The cost-effectiveness of the
alternative procedures would depend on the amount of gas flared or
vented using the traditional procedures, the amount of these emissions
that can be avoided using alternative procedures, the amount of product
lost due to the increased start-up/shutdown time period, and the value
of that product.  As such, it is difficult to conclude that significant
or complete emission reductions during planned start-up or shutdown
events will be cost-effective under all conditions; therefore, we chose
not to set a specific venting or flaring limit (or prohibition).
Nonetheless, we believe it is the duty of every refinery owner and
operator to review their start-up and shutdown procedures, evaluate
alternative procedures that can reduce atmospheric releases, and
implement those procedures that can effectively reduce atmospheric
emissions or flaring.

We estimate that the engineering review revision of a unit’s start-up
and shutdown plan would require approximately 20 engineering hours per
process unit, at total cost of $1,300 to $1,500 per process unit
(one-time costs).  Assuming the unit requires maintenance shut-down only
once every 5 years and the revised procedures only reduce VOC and SO2
emissions by 1 ton each per event, the cost-effectiveness of the
engineering review is $1,300 to $1,500 per ton of VOC and the same for
SO2.

Based on this simplistic analysis, implementing a start-up and shutdown
plan focused on reducing emissions during planned start-up and shutdown
events is BDT.  Therefore, we are proposing that all new affected
process units develop a start-up and shutdown plan focused on reducing
atmospheric venting and flaring.  The proposed rule is intended to
provide flexibility for each refinery owner and operator to develop
procedures that are efficient and effective for their process
configuration.  We are focusing the rule on new process units affected
by some other requirement of 40 CFR part 60, subpart Ja, as fuel gas
producing units and other process units subject to subpart Ja are
expected to have the greatest potential for VOC and SO2 emissions during
start-up and shutdown.  However, we request comment on the need to
implement this requirement to all new process units at the refinery, not
just fuel gas producing process units such as fluid catalytic cracking
units, fluid coking units, fuel gas combustion devices, and sulfur
recovery plants.

On the other hand, we have limited data by which to assess the potential
emissions avoided by developing revised start-up and shutdown
procedures.  Furthermore, we do not believe it is technically feasible
that all planned start-up and shutdown events occur with no use of
flares.  As such, it is impossible to conclusively determine that the
flare minimization plan will achieve any set level of emissions
reduction or that those reductions, if any, will be cost-effective.
Therefore, we are co-proposing no flare minimization plan for planned
start-up and shutdown events.  We request comments and supporting data
that indicate the emission reductions that could be reasonably expected
from a flare minimization plan for planned start-up and shutdown events,
the number of planned events that occur per year (or over a 5 year
period), and any other information that can be used to justify either
the inclusion or exclusion of this provision in the final rule.

Sulfur Shedding Plan.  We evaluated several different requirements to
ensure continuous compliance with the SO2 emission limits associated
with fuel gas combustion devices and sulfur recovery plants even during
times of process upsets or malfunctions associated with the amine system
or sulfur recovery plant.  “Process upset gas” is “gas generated
by a petroleum refinery process unit as a result of upset or
malfunction.”  Process upset gas is exempt from the SO2 emission
limits, but process upset gas is not exempt from meeting the H2S
concentration limit (or alternative combustion unit SO2 limit) in the
event of a malfunction of the amine treatment system.  That is, the
amine treatment system is not “generating” the gas stream, it is
merely treating it.  As such, refinery owners and operators are required
to comply with the fuel gas concentration limits in spite of a
malfunction in the amine treatment system.  Similarly, it is our intent