Standards of Performance for Petroleum Refineries, 27178-27219 [E7-8547]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 72, Number 92 (Monday, May 14, 2007)]
[Proposed Rules]
[Pages 27178-27219]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E7-8547]



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Part II





Environmental Protection Agency





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40 CFR Part 60



 Standards of Performance for Petroleum Refineries; Proposed Rule

Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed 
Rules

[[Page 27178]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

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


Standards of Performance for Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rules.

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

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

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2007-0011, by one of the following methods:
     https://www.regulations.gov: Follow the on-line 
instructions for submitting comments.
     E-mail: a-and-r-docket@epa.gov.
     Fax: (202) 566-1741.
     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 
https://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 https://
www.regulations.gov or e-mail. The https://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 https://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 https://
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 https://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 (202) 566-1744, and the telephone number for the Docket 
Center is (202) 566-1742.

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

SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?

    Categories and entities potentially regulated by this proposed rule 
include:

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                                 NAICS
           Category             code \1\  Examples of regulated entities
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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.

[[Page 27179]]

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

    Do not submit information containing CBI to EPA through https://
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 https://www.epa.gov/ttn/
oarpg. The TTN provides information and technology exchange in various 
areas of air pollution control.

D. When would a public hearing occur?

    If anyone contacts EPA requesting to speak at a public hearing by 
June 4, 2007, a public hearing will be held on June 13, 2007. Persons 
interested in presenting oral testimony or inquiring as to whether a 
public hearing is to be held should contact Mr. Bob Lucas, listed in 
the FOR FURTHER INFORMATION CONTACT section, at least 2 days in advance 
of the hearing.

E. How is this document organized?

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

I. General Information
    A. Does this action apply to me?
    B. What should I consider as I prepare my comments to EPA?
    C. Where can I get a copy of this document?
    D. When would a public hearing occur?
    E. How is this document organized?
II. Background Information
    A. What is the statutory authority for the proposed standards 
and proposed amendments?
    B. What are the current petroleum refinery NSPS?
III. Summary of the Proposed Standards and Proposed Amendments
    A. What are the proposed amendments to the standards for 
petroleum refineries (40 CFR part 60, subpart J)?
    B. What are the proposed requirements for new fluid catalytic 
cracking units and new fluid coking units (40 CFR part 60, subpart 
Ja)?
    C. What are the proposed requirements for new sulfur recovery 
plants (SRP) (40 CFR part 60, subpart Ja)?
    D. What are the proposed requirements for new process heaters 
and other fuel gas combustion devices (40 CFR part 60, subpart Ja)?
    E. What are the proposed work practice and equipment standards 
(40 CFR part 60, subpart Ja)?
IV. Rationale for the Proposed Amendments (40 CFR part 60, subpart 
J)
    A. How is EPA proposing to change requirements for refinery fuel 
gas?
    B. How is EPA proposing to amend definitions?
    C. How is EPA proposing to revise the coke burn-off equation?
    D. What miscellaneous corrections are being proposed?
V. Rationale for the Proposed Standards (40 CFR part 60, subpart Ja)
    A. What is the performance of control technologies for fluid 
catalytic cracking units?
    B. What is the performance of control technologies for fuel gas 
combustion?
    C. What is the performance of control technologies for process 
heaters?
    D. What is the performance of control technologies for sulfur 
recovery systems?
    E. How did EPA determine the proposed standards for new 
petroleum refining process units?
VI. Modification and Reconstruction Provisions
VII. Request for Comments
VIII. Summary of Cost, Environmental, Energy, and Economic Impacts
    A. What are the impacts for petroleum refineries?
    B. What are the secondary impacts?
    C. What are the economic impacts?
    D. What are the benefits?
IX. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

II. Background Information

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

    New source performance standards (NSPS) implement Clean Air Act 
(CAA) section 111(b) and are issued for categories of sources which 
cause, or contribute significantly to, air pollution which may 
reasonably be anticipated to endanger public health or welfare. The 
primary purpose of the NSPS is to attain and maintain ambient air 
quality by ensuring that the best demonstrated emission control 
technologies are installed as the industrial infrastructure is 
modernized. Since 1970, the NSPS have been successful in achieving 
long-term emissions reductions in numerous industries by assuring cost-
effective controls are installed on new, reconstructed, or modified 
sources.
    Section 111 of the CAA requires that NSPS reflect the application 
of the best system of emission reductions which (taking into 
consideration the cost of achieving such emission reductions, any non-
air quality health and environmental impact and energy requirements) 
the Administrator determines has been adequately demonstrated. This 
level of control is commonly referred to as best demonstrated 
technology (BDT).
    Section 111(b)(1)(B) of the CAA requires EPA to periodically review 
and revise the standards of performance, as necessary, to reflect 
improvements in methods for reducing emissions.

B. What are the current petroleum refinery NSPS?

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

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

III. Summary of the Proposed Standards and Proposed Amendments

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

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

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

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

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

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

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

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

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

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

[[Page 27182]]

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

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

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

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

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

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

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

[[Page 27183]]

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

[[Page 27184]]

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

B. How is EPA proposing to amend definitions?

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

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

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

D. What miscellaneous corrections are being proposed?

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

[[Page 27185]]



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

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

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

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

[[Page 27186]]

catalytic cracking unit. This can be accomplished by processing crude 
oil that naturally contains low amounts of sulfur or a feedstock that 
has been pre-treated to remove sulfur (i.e., hydrotreatment or 
hydrodesulfurization). A second approach is to use a post-combustion 
control technology that removes SO2 from the flue gases. 
These technologies rely on either absorption or adsorption processes 
that react SO2 with lime, limestone, or another alkaline 
material to form an aqueous or solid sulfur by-product. A third 
approach is the use of catalyst additives, which capture sulfur oxides 
in the regenerator and return them to the fluid catalytic cracking 
reactor where they are transformed to H2S that is ultimately 
exhausted to the SRP.
    Feedstock Selection or Pre-Treatment. The SO2 emissions 
from the fluid catalytic cracking unit are directly related to the 
amount of sulfur deposited on the catalyst particles in the riser and 
reactor section of the unit. The amount of sulfur deposited on the 
catalyst is a function of both the amount of sulfur in the feedstocks 
and the relative composition of the sulfur-containing compounds in the 
feedstocks (mercaptans, thiosulfates). As the concentration of sulfur 
in the feedstocks is reduced, the SO2 emissions from the 
regenerator portion of the unit are also reduced. Therefore, if a 
refinery processes ``sweet'' crude (oil naturally low in sulfur) or if 
a refinery removes sulfur from the feedstocks of the fluid catalytic 
cracking unit, the SO2 emissions from the catalyst 
regenerator wi