[Federal Register Volume 72, Number 92 (Monday, May 14, 2007)]
[Proposed Rules]
[Pages 27178-27219]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-8547]
[[Page 27177]]
-----------------------------------------------------------------------
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
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]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2007-0011; FRL-8309-1]
RIN 2060-AN72
Standards of Performance for Petroleum Refineries
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rules.
-----------------------------------------------------------------------
SUMMARY: EPA is proposing amendments to the current Standards of
Performance for Petroleum Refineries. This action also proposes
separate standards of performance for new, modified, or reconstructed
process units at petroleum refineries. Unless otherwise noted, the term
new includes modified or reconstructed units. The proposed standards
for new process units include emissions limitations and work practice
standards for fluid catalytic cracking units, fluid coking units,
delayed coking units, process heaters and other fuel gas combustion
devices, fuel gas producing units, and sulfur recovery plants. These
proposed standards reflect demonstrated improvements in emissions
control technologies and work practices that have occurred since
promulgation of the current standards.
DATES: Comments. Written comments must be received on or before July
13, 2007.
Public Hearing. If anyone contacts EPA by June 4, 2007 requesting
to speak at a public hearing, a public hearing will be held on June 13,
2007.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2007-0011, by one of the following methods:
http://www.regulations.gov: Follow the on-line
instructions for submitting comments.
E-mail: [email protected].
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
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov website
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through http://www.regulations.gov, your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the EPA Docket Center,
Standards of Performance for Petroleum Refineries Docket, EPA West,
Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (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: [email protected].
SUPPLEMENTARY INFORMATION:
I. General Information
A. Does this action apply to me?
Categories and entities potentially regulated by this proposed rule
include:
------------------------------------------------------------------------
NAICS
Category code \1\ Examples of regulated entities
------------------------------------------------------------------------
Industry..................... 32411 Petroleum refiners.
Federal government........... ......... Not affected.
State/local/tribal government ......... Not affected.
------------------------------------------------------------------------
\1\ North American Industrial Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. To determine whether your facility would be regulated by this
action, you should examine the applicability criteria in 40 CFR 60.100
and 40 CFR 60.100a. If you have any questions regarding the
applicability of this proposed action to a particular entity, contact
the person listed in the preceding FOR FURTHER INFORMATION CONTACT
section.
[[Page 27179]]
B. What should I consider as I prepare my comments to EPA?
Do not submit information containing CBI to EPA through http://www.regulations.gov or e-mail. Send or deliver information identified
as CBI only to the following address: Roberto Morales, OAQPS Document
Control Officer (C404-02), Office of Air Quality Planning and
Standards, Environmental Protection Agency, Research Triangle Park, NC
27711, Attention Docket ID No. EPA-HQ-OAR-2007-0011. Clearly mark the
part or all of the information that you claim to be CBI. For CBI
information in a disk or CD-ROM that you mail to EPA, mark the outside
of the disk or CD-ROM as CBI and then identify electronically within
the disk or CD-ROM the specific information that is claimed as CBI. In
addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.
C. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this proposed action is available on the Worldwide Web (WWW) through
the Technology Transfer Network (TTN). Following signature, a copy of
this proposed action will be posted on the TTN's policy and guidance
page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides information and technology exchange in various
areas of air pollution control.
D. When would a public hearing occur?
If anyone contacts EPA requesting to speak at a public hearing by
June 4, 2007, a public hearing will be held on June 13, 2007. Persons
interested in presenting oral testimony or inquiring as to whether a
public hearing is to be held should contact Mr. Bob Lucas, listed in
the FOR FURTHER INFORMATION CONTACT section, at least 2 days in advance
of the hearing.
E. How is this document organized?
The supplementary information presented in this preamble is
organized as follows:
I. General Information
A. Does this action apply to me?
B. What should I consider as I prepare my comments to EPA?
C. Where can I get a copy of this document?
D. When would a public hearing occur?
E. How is this document organized?
II. Background Information
A. What is the statutory authority for the proposed standards
and proposed amendments?
B. What are the current petroleum refinery NSPS?
III. Summary of the Proposed Standards and Proposed Amendments
A. What are the proposed amendments to the standards for
petroleum refineries (40 CFR part 60, subpart J)?
B. What are the proposed requirements for new fluid catalytic
cracking units and new fluid coking units (40 CFR part 60, subpart
Ja)?
C. What are the proposed requirements for new sulfur recovery
plants (SRP) (40 CFR part 60, subpart Ja)?
D. What are the proposed requirements for new process heaters
and other fuel gas combustion devices (40 CFR part 60, subpart Ja)?
E. What are the proposed work practice and equipment standards
(40 CFR part 60, subpart Ja)?
IV. Rationale for the Proposed Amendments (40 CFR part 60, subpart
J)
A. How is EPA proposing to change requirements for refinery fuel
gas?
B. How is EPA proposing to amend definitions?
C. How is EPA proposing to revise the coke burn-off equation?
D. What miscellaneous corrections are being proposed?
V. Rationale for the Proposed Standards (40 CFR part 60, subpart Ja)
A. What is the performance of control technologies for fluid
catalytic cracking units?
B. What is the performance of control technologies for fuel gas
combustion?
C. What is the performance of control technologies for process
heaters?
D. What is the performance of control technologies for sulfur
recovery systems?
E. How did EPA determine the proposed standards for new
petroleum refining process units?
VI. Modification and Reconstruction Provisions
VII. Request for Comments
VIII. Summary of Cost, Environmental, Energy, and Economic Impacts
A. What are the impacts for petroleum refineries?
B. What are the secondary impacts?
C. What are the economic impacts?
D. What are the benefits?
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
II. Background Information
A. What is the statutory authority for the proposed standards and
proposed amendments?
New source performance standards (NSPS) implement Clean Air Act
(CAA) section 111(b) and are issued for categories of sources which
cause, or contribute significantly to, air pollution which may
reasonably be anticipated to endanger public health or welfare. The
primary purpose of the NSPS is to attain and maintain ambient air
quality by ensuring that the best demonstrated emission control
technologies are installed as the industrial infrastructure is
modernized. Since 1970, the NSPS have been successful in achieving
long-term emissions reductions in numerous industries by assuring cost-
effective controls are installed on new, reconstructed, or modified
sources.
Section 111 of the CAA requires that NSPS reflect the application
of the best system of emission reductions which (taking into
consideration the cost of achieving such emission reductions, any non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated. This
level of control is commonly referred to as best demonstrated
technology (BDT).
Section 111(b)(1)(B) of the CAA requires EPA to periodically review
and revise the standards of performance, as necessary, to reflect
improvements in methods for reducing emissions.
B. What are the current petroleum refinery NSPS?
NSPS for petroleum refiners (40 CFR part 60, subpart J) apply to
fluid catalytic cracking unit catalyst regenerators and fuel gas
combustion devices that commence construction or modification after
June 11, 1973. Fluid catalytic cracking unit catalyst regenerators are
subject to standards for particulate matter (PM), opacity, and carbon
monoxide (CO). Fluid catalytic cracking unit catalyst regenerators that
commence construction after January 17, 1984 are also subject to
standards for sulfur dioxide (SO2) (or a feed sulfur content
limit). Fuel gas combustion devices are subject to concentration limits
for hydrogen sulfide (H2S) as a surrogate for SO2
emissions.
[[Page 27180]]
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
[[Page 27181]]
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 will be lower than from refineries that process feedstocks
that have higher sulfur content. At a petroleum refinery, the primary
means of removing sulfur compounds in the liquid feedstocks is
catalytic hydrotreatment. Hydrotreatment typically reduces the sulfur
content in process streams to between 20 and 1,000 parts per million by
weight.
Alkali Wet Scrubbing. The SO2 in a flue gas can be
removed by reacting the sulfur compounds with a solution of water and
an alkaline chemical to form insoluble salts that are removed in the
scrubber effluent. Wet scrubbing processes used to control
SO2 are generally termed flue-gas desulfurization (FGD)
processes. The normal SO2 control efficiency range for
SO2 scrubbers is 80 percent to 90 percent for low efficiency
scrubbers and 90 percent to 99 percent for high efficiency scrubbers.
In recent fluid catalytic cracking unit applications, control
guarantees of 25 ppmv SO2 are commonly provided by FGD
suppliers.
Spray Dryer Adsorption. An alternative to using wet scrubbers is to
use spray dryer adsorber (SDA) technology. A SDA operates by the same
principle as alkali wet scrubbing, except that instead of a bulk liquid
(as in wet scrubbing) the flue gas containing SO2 is
contacted with fine spray droplets of hydrated lime slurry in a spray
dryer vessel. This vessel is located downstream of the air heater
outlet where the gas temperatures are in the range of 120 [deg]C to 180
[deg]C (250 [deg]F to 350 [deg]F). The SO2 is absorbed in
the slurry and reacts with the hydrated lime reagent to form solid
calcium sulfite and calcium sulfate. The water is evaporated by the hot
flue gases and forms dry, solid particles containing the reacted
sulfur. Most of the SO2 removal occurs in the spray dryer
vessel itself, although some additional SO2 capture has also
been observed in downstream particulate collection devices. The
SO2 removal efficiencies of new lime spray dryer systems are
generally greater than 90 percent. Only one refinery has ever used an
SDA to control SO2 from its fluid catalytic cracking unit;
this system has since been removed in favor of feedstock
hydrotreatment.
Catalyst Additives. One common method used by refineries to reduce
SO2 emissions from the fluid catalytic cracking unit is the
use of catalyst additives (typically various types of metal oxides).
The metal oxide reacts with some of the SO3 in the catalyst
regenerator to form a metal sulfate. The metal sulfate is then returned
to the cracking unit where the sulfur is converted to a metal sulfide
and then to H2S and the original metal oxide. The
H2S is subsequently recovered in the SRP, and the metal
oxide returns to the catalyst regenerator to repeat the process. The
control efficiency of catalyst additives is difficult to assess, but is
generally around 50 percent (ranging from 20 to 70 percent, depending
on the application).
3. NOX Control Technologies
NOX are formed in a catalyst regenerator (and downstream
CO boiler, if present) by the oxidation of molecular nitrogen
(N2) in the combustion air and any nitrogen compounds
contained in the fuel (i.e., thermal NOX and fuel
NOX). The formation of NOX from nitrogen in the
combustion air is dependent on two conditions occurring simultaneously
in the unit's combustion zone: high temperature and an excess of
combustion air. Under these conditions, significant quantities of
NOX are formed, regardless of the fuel type burned. There
are several NOX emission control strategies that can be
considered combustion controls (e.g., low NOX burners or
flue gas recirculation) that reduce the amounts of NOX
formed during combustion. These control technologies are primarily
applicable to incomplete combustion fluid catalytic cracking units
controlled by CO boilers. As there is limited or no direct flame in the
catalyst regenerator during normal operations, these control strategies
may be limited for complete combustion fluid catalytic cracking units.
Most post-combustion control technologies involve converting the
NOX in the flue gas to N2 and water using either
a process that requires a catalyst (called selective catalytic
reduction (SCR)) or a process that does not use a catalyst (called
selective noncatalytic reduction (SNCR)). A recently developed post-
combustion technology (LoTOxTM) uses ozone to oxidize
NOX to nitric pentoxide, which is water soluble and easily
removed in a water scrubber.
NOX Combustion Controls. Flue gas recirculation (FGR) uses flue gas
as an inert material to reduce flame temperatures. In a typical FGR
system, flue gas is collected from the heater or stack and returned to
the burner via a duct and blower. The addition of flue gas with the
combustion air reduces the O2 content of the inlet air
stream to the burner. The lower O2 level in the combustion
zone reduces flame temperatures which in turn reduces NOX
emissions. The normal NOX control efficiency range for FGR
is 30 percent to 50 percent. When coupled with low-NOX
burners (LNB), the control efficiency increases to 50-72 percent.
LNB technology utilizes advanced burner design to reduce
NOX formation through the restriction of O2,
flame temperature, and/or residence time. The two general types of LNB
are staged fuel and staged air burners. Staged fuel LNB are
particularly well suited for boilers and process heaters burning
process and natural gas which generate higher thermal NOX.
The estimated NOX control efficiency for LNB when applied to
petroleum refining fuel burning equipment is generally around 40
percent.
One NOX combustion control technique that is applicable
to complete combustion fluid catalytic cracking units is the use of
catalyst additives and/or combustion promoters. The control efficiency
of these additives varies from 10 to 50 percent.
Selective Catalytic Reduction (SCR) Technology. The SCR process
uses a catalyst with ammonia (NH3) to reduce the nitrogen
oxide (NO) and nitrogen dioxide (NO2) in the flue gas to
N2 and water. Ammonia is diluted with air or
[[Page 27187]]
steam, and this mixture is injected into the flue gas upstream of a
metal catalyst bed that typically is composed of vanadium, titanium,
platinum, or zeolite. The SCR catalyst bed reactor is usually located
between the economizer outlet and air heater inlet where temperatures
range from 230 [deg]C to 400 [deg]C (450 [deg]F to 750 [deg]F). The SCR
technology is capable of NOX reduction efficiencies of 90
percent or higher.
Selective Noncatalytic Reduction (SNCR) Technology. An SNCR process
is based on the same basic chemistry of reducing the NO and
NO2 in the flue gas to N2 and water, but it does
not require the use of a catalyst to promote these reactions. Instead,
the reducing agent is injected into the flue gas stream at a point
where the flue gas temperature is within a specific temperature range
of 870[deg]C to 1,090[deg]C (1,600[deg]F to 2,000[deg]F). The
NOX reduction levels for SNCR are in the range of
approximately 30 to 50 percent.
LoTOxTM Technology. The LoTOx\TM\ process (i.e., low-temperature
oxidation) is a patented technology that uses ozone to oxidize
NOX to nitric pentoxide and other higher order
NOX, all of which are water soluble and easily removed from
exhaust gas in a wet scrubber. The system operates optimally at
temperatures below 300[deg]F. Thus, ozone is injected after scrubber
inlet quench nozzles and before the first level of scrubbing nozzles.
Outlet NOX emission levels have been reduced to less than 20
ppmv, and often as low as 10 ppmv, when inlet NOX
concentrations ranged from 50 to 200 ppmv.
B. What is the performance of control technologies for fuel gas
combustion?
Refinery fuel gas is generally used in process heaters and boilers
to meet the energy demands of the refinery. Excess refinery fuel gas is
typically combusted using flares. Flares also serve an important safety
function to destroy organics and convert H2S to
SO2 during process upsets and malfunctions.
Over the past several years, many refineries have reduced flaring
episodes by adding flare gas recovery systems and/or by changing their
start-up and shutdown procedures to limit flaring. Installing a flare
gas recovery system and implementing new start-up and shutdown
procedures are expected to reduce VOC, sulfur oxides, and
NOX emissions from flares. Improved amine scrubbing systems
are expected to reduce sulfur oxide emissions from all fuel gas
combustion systems. In addition, excess capacity in the SRP will help
to minimize sour gas flaring that might be caused by a malfunction in
the SRP. Each of these ``control'' techniques are described in the
following paragraphs.
Flare Gas Recovery Systems. Flare gas recovery systems recover fuel
gas from the flare gas header prior to the flare's liquid seal. A flare
gas recovery system consists of a compressor, separator, and process
controls (to maintain slight positive pressure on the flare header).
Flare gas recovery systems are typically designed to recover fuel gas
from miscellaneous processes that might regularly be relieved to the
flare header system and can effectively recover 100 percent of these
fuel gases. However, flare gas recovery systems cannot recover large
quantities of fuel gas that might be suddenly released to the flare
header system as a result of a process upset or malfunction. These
gases would still be flared as necessary to maintain the integrity of
the process units and the safety of the plant personnel.
Modified Start-up and Shutdown Procedures. Although flaring is
necessary to ensure safety during process upsets and malfunctions,
start-up and shutdown procedures can be designed so as to minimize
flaring. For example, depressurization of process vessels can be
performed more slowly so as to not overwhelm the fuel gas needs of the
refinery and/or the capacity of the flare gas recovery system.
Depending on the number of units being shut down at a given time,
nearly 100 percent of flaring can be eliminated during start-up and
shutdown. There are cases, such as emergency shutdowns for safety
reasons or approaching hurricanes, where the timing of the shutdown and
the magnitude of the number of processes needing to be shut down would
warrant the use of flaring. However, modified procedures should be able
to eliminate flaring associated with process start-ups and shutdowns
due to routine maintenance of select processes.
Amine Scrubbers. Amine scrubber systems remove H2S and
other impurities from sour gas. Lean amine solution absorbs the
H2S from the sour gas in an absorption tower. The acid gas
is removed from the rich amine solution in a stripper, or still column.
The resulting lean amine is recirculated to the absorption tower, and
the stripped H2S is generally sent to the SRP. Vendors
generally provide redundant pumps to ensure continuous operation of the
system. Some refineries choose to store a day's worth of lean amine
solution in case the stripper fails; this allows the continuous
operation of the absorption tower. This option also requires adequate
empty storage space for the rich amine solution produced by the
absorption tower while the stripper is out of service.
Redundant Sulfur Recovery Capacity. When a sulfur recovery unit
(SRU) malfunctions, the sour gas is typically flared to convert the
highly toxic H2S to less toxic SO2. As many SRU
recover more than 20 long tons of elemental sulfur per day, even short
sulfur recovery process upsets can result in several tons of
SO2 emissions. Furthermore, refineries often operate
multiple Claus sulfur recovery processes in parallel. Having an extra
Claus sulfur recovery train can dramatically reduce the likelihood of
sour gas flaring. Depending on the severity of the process upset,
having a redundant SRU can reduce these large SO2 releases
by as much as 100 percent.
C. What is the performance of control technologies for process heaters?
The mechanisms by which NOX are formed in process
heaters are the same as for their formation in catalyst regenerators.
The possible control options are also the same. See section V.A.3 of
this preamble for a discussion of these formation mechanisms and
control technologies.
D. What is the performance of control technologies for sulfur recovery
systems?
Sulfur recovery (the conversion of H2S to elemental
sulfur) is typically accomplished using the modified-Claus process. In
the Claus unit, one-third of the H2S is burned with air in a
reaction furnace to yield SO2. The SO2 then
reacts reversibly with H2S in the presence of a catalyst to
produce elemental sulfur, water, and heat. This is a multi-stage
catalytic reaction in which elemental sulfur is removed between each
stage, thereby driving the reversible reaction towards completion. The
gas from the final condenser of the Claus unit (referred to as the
``tail gas'') consists primarily of inert gases with less than 2
percent sulfur compounds. Additionally, the sulfur recovery pits used
to store the recovered elemental sulfur also have a potential for
fugitive H2S emissions. Typically a Claus unit recovers
approximately 94 to 97 percent of the inlet sulfur load as elemental
sulfur.
There are some methods that extend the Claus reaction to improve
the overall sulfur collection efficiency of the SRP. For example, the
Superclaus[supreg] SRU is similar to the Claus unit. It contains a
thermal stage, followed by three to four catalytic reaction stages. The
first two or three catalytic reactors use the Claus catalyst, while the
last reactor uses a selective oxidation catalyst. The
[[Page 27188]]
catalyst in the last reactor oxidizes the H2S to sulfur at a
very high efficiency, recovering 99 percent of the incoming sulfur.
There are a few refineries that operate non-Claus type SRU. All of
the refineries that use non-Claus SRU technologies have very low sulfur
production rates (2 LTD or less). There are several different trade
names for these ``other'' types of SRU, such as the LoCat[supreg],
Sulferox[supreg], and NaSH processes. These processes can achieve
sulfur recovery efficiencies of 99 percent or more, although they
typically yield a sulfur product that has limited market value because
the sulfur content is much lower than in the sulfur product from a
Claus unit (50 to 70 percent sulfur compared to 99.9 percent sulfur
from the Claus process).
The primary means of reducing sulfur oxide emissions from the SRU
is to employ a tail gas treatment unit that recovers the sulfur
compounds and recycles them back to the inlet of the Claus treatment
train. There are three basic types of tail gas treatment units: (1)
Direct amine adsorption of the Claus tail gas; (2) catalytic reduction
of the tail gas to convert as much of the tail gas sulfur compounds to
H2S (coupled with amine adsorption or Stretford solution
eduction); and (3) oxidative tail gas treatment systems to convert the
Claus tail gas sulfur compounds to SO2 (coupled with an
SO2 recovery system).
Direct Amine Adsorption. Direct amine adsorption of the Claus tail
gas is the least efficient of the tail gas treatment methods because
only about two-thirds of the sulfur in the direct Claus tail gas is
amenable to scrubbing (i.e., in the form of H2S). Direct
amine adsorption is therefore expected to increase the overall sulfur
recovery efficiency of the sulfur plant to approximately 99 percent.
However, direct amine adsorption alone is generally not expected to
reduce sulfur oxide concentrations to below 250 ppmv (i.e., enough to
meet the existing NSPS emission limits for Claus units greater than 20
LTD).
Reductive Tail Gas Catalytic Systems. The most common reductive
tail gas catalytic systems in use at refineries include: (1) The
Shell[supreg] Claus Offgas Treatment (SCOT) unit; (2) the Beavon/amine
system; and (3) the Beavon/Stretford system. Each of these systems
consist of a catalytic reactor to convert the sulfur compounds
remaining in the Claus tail gas to H2S and an H2S
recovery system (an amine scrubber or a Stretford solution) to strip
the H2S from the tail gas. The recovered H2S is
then recycled to the front of the Claus unit. The overhead of the amine
scrubber or Stretford unit (caustic scrubber) may be vented to the
atmosphere or incinerated to convert any remaining H2S or
other reduced sulfur compounds to SO2. The total sulfur
recovery efficiency of a Claus/catalytic tail gas treatment train is
expected to be 99.7 to 99.9 percent.
Oxidative Tail Gas Treatment Systems. The Wellman-Lord is the only
oxidative tail gas treatment system used in the United States. The
Wellman-Lord process uses thermal oxidation followed by scrubbing with
a sodium sulfite and sodium bisulfite solution to remove
SO2. The rich bisulfite solution is sent to an evaporator-
recrystallizer where the bisulfite decomposes to SO2 and
water and sodium sulfite is precipitated. The recovered SO2
is then recycled back to the Claus plant for sulfur recovery. The total
sulfur recovery efficiency of a Claus/oxidative tail gas treatment
train is expected to be 99.7 to 99.9 percent.
E. How did EPA determine the proposed standards for new petroleum
refining process units?
Four sources of information were considered in reviewing the
appropriateness of the current NSPS requirements for new sources: (1)
Source test data from recently installed control systems; (2)
applicable State and local regulations; (3) control vendor emission
control guarantees; and (4) consent decrees. (A significant number of
refineries, representing about 77 percent of the national refining
capacity, are subject to consent decrees that limit the emissions from
subpart J process units.) Once we identified potential emission limits
for various process units, we evaluated each limit in conjunction with
control technology, costs, and emission reductions to determine BDT for
each process unit.
The cost methodology incorporates the calculation of annualized
costs and emission reductions associated with each of the options
presented. Cost-effectiveness is the annualized cost of control divided
by the annual emission reductions achieved. Incremental cost-
effectiveness refers to the difference in annualized cost from one
option to the next divided by the difference in emission reductions
from one option to the next. For NSPS regulations, the standard metric
for expressing costs and emission reductions is the impact on all
affected facilities accumulated over the first 5 years of the
regulation. Details of the calculations can be found in the public
docket. Our BDT determinations took all relevant factors into account,
including cost considerations which were generally consistent with
other Agency decisions.
1. Fluid Catalytic Cracking Units
Particulate Matter (PM) and Sulfur Dioxide (SO2). In order to
determine the appropriate emission limits for PM and SO2, we
evaluated PM and SO2 limits in conjunction with one another.
One of the reasons for this is that wet scrubbers control both PM and
SO2 emissions, and refineries will decide whether to choose
a wet scrubber as opposed to an ESP with catalyst additives based on
both the PM and the SO2 emission limit to be met.
Currently, 40 CFR part 60, subpart J limits PM emissions from the
fluid catalytic cracking unit to 1.0 kg/Mg of coke burn-off. The limit
applies to filterable PM as measured by Method 5B or 5F in 40 CFR part
60, Appendix A. It excludes condensable PM such as sulfuric acid (under
Method 5B), sulfates that condense at temperatures greater than 320
[deg]F (under Method 5F), and all other condensables (using either
Method). The measurement of condensable PM is important to EPA's goal
of reducing ambient air concentrations of fine PM. Since promulgation
of Method 202 in 1991, EPA has been working to overcome problems
associated with the accuracy of Method 202 and will promulgate
improvements to the method in the future. The existing NSPS also
requires opacity, as measured using a continuous opacity monitoring
system, to be no more than 30 percent.
The current standards in 40 CFR part 60, subpart J for
SO2 include three alternative formats: (1) If using an add-
on control device, reduce SO2 emissions by at least 90
percent or to less than 50 ppmv, (2) if not using an add-on control
device, limit sulfur oxides emissions (calculated as SO2) to
no more than 9.8 kg/Mg of coke burn-off, or (3) process in the fluid
catalytic cracking unit fresh feed that has a total sulfur content no
greater than 0.30 percent by weight. The 90 percent reduction, 9.8 kg/
Mg, and 0.3 percent feed sulfur formats were determined to be
equivalent for a unit operating with a feed that contains 3.5 percent
sulfur by weight before implementing a control measure.
In reviewing the PM and SO2 emission limits, we
evaluated five combined options and a baseline. The baseline is
considered to be the current requirements, as described in the two
previous paragraphs. The first option is to maintain the existing
subpart J standard for PM and provide only the 50 ppmv concentration
limit for SO2. The additional options are a range of
emission limits coupled with a change in the compliance test method to
Method 5 to measure a portion of the
[[Page 27189]]
condensable PM. The second option is to combine Method 5 with the
existing 1.0 kg/Mg coke burn-off performance level, and a third option
is to lower the PM emission limit to 0.5 kg/Mg. Both the second and
third options include an SO2 limit of 50 ppmv. A fourth
option includes the PM limit of 0.5 kg/Mg presented in the third option
and a lower SO2 limit of 25 ppmv. The fifth option is to
lower the PM emission limit to 0.15 kg/Mg with an SO2 limit
of 25 ppmv. Costs and emission reductions for each option were
estimated as the increment between complying with subpart J and subpart
Ja.
Option 1 includes the same emissions and requirements for PM as the
current 40 CFR part 60, subpart J. For SO2, this option
excludes the alternative compliance options of meeting a higher
emission limit without an SO2 control device or meeting a
limit on the sulfur content of the fresh feed. These two alternatives
are less stringent than the outlet concentration limit, and available
information indicates the concentration limits are achievable. An
advantage of the proposed concentration limit is that ongoing
compliance can be directly measured using a CEMS. The impacts of this
option are limited to the impacts of removing those alternative
compliance options for SO2 and are presented in Table 2 to
this preamble. To comply with Option 1 (i.e., meet the 50 ppmv limit
for SO2) we expect that the fraction of new sources choosing
wet scrubbers instead of ESP would be greater than under the existing
subpart J. Filterable PM emissions are assumed to be the same for both
types of control devices because the PM performance levels are the same
under both option 1 and the baseline subpart J requirements. However,
because condensable PM emissions are lower from wet scrubbers than from
ESP, this shift in the ratio of wet scrubbers to ESP would also result
in an estimated reduction in total PM emissions of 17 tons per year, as
shown in Table 2 to this preamble.
Option 2 includes the same emission limit as current subpart J for
PM but requires compliance using Method 5 rather than Method 5B or
Method 5F. As noted above, Methods 5B and 5F exclude all PM that
condenses at temperatures below 320[deg]F, and Method 5F also excludes
sulfates that condense at temperatures greater than 320[deg]F. The PM
measured by Method 5 includes filterable PM that condenses above
250[deg]F in the front half of the Method 5 sampling train. Thus, the
estimated PM emission reductions achieved by this option equal the
amount of sulfates and other condensable PM between 250[deg]F and
320[deg]F that would be measured by Method 5 but not Method 5B or 5F.
The baseline emissions were estimated assuming Method 5B is used for
wet scrubbers and Method 5F is used for ESP. For SO2, Option
2 includes the same emission limit as described in Option 1, and the
estimated SO2 emission reductions are also the same. The
impacts of this option are presented in Table 2 to this preamble.
Option 3 lowers the PM limit to 0.5 kg/Mg coke burn, again using
Method 5, and includes the same emission limit as described in Option 1
for SO2. The existing NSPS limit was based on control with
ESP. Those ESP were rated at efficiencies of only 85 to 90 percent.
More recently installed ESP have greater specific plate area, which
should result in better control efficiencies. In addition, many
refineries have installed wet scrubbers to control both PM and
SO2. At petroleum refineries, wet scrubbers typically
perform as well as, if not better than, ESP. Available test data
indicate that at least one ESP and one wet scrubber are reducing total
filterable PM to 0.5 kg/Mg of coke burn or less, as measured by Method
5-equivalent test methods. Based on this information, both ESP and wet
scrubbers can achieve PM emission levels below the level of the
existing PM standard, and a lower standard for new units is technically
feasible. The impacts of this option are presented in Table 2 to this
preamble.
Option 4 includes the same PM limit as Option 3, and the discussion
presented for Option 3 applies to Option 4 as well. It also includes a
long-term limit for SO2 of 25 ppmv, averaged over 365 days,
in addition to the current subpart J limit of 50 ppmv, averaged over 7
days. These limits have been shown to be readily achievable by flue gas
desulfurization systems. Many fluid catalytic cracking units are now
subject to consent decrees that require control to these levels.
Petroleum refiners typically use wet scrubbers to control
SO2 emissions, and test data indicate that outlet
concentrations below 25 ppmv are common. At least one wet scrubber
manufacturer also provides performance guarantees to meet a 25 ppmv
emission limit. The incremental SO2 reductions for this
option relative to Option 3 are achieved by using catalyst additives in
the fluid catalytic cracking units that are assumed to be controlled
with ESP; fluid catalytic cracking units controlled with wet scrubbers
have the same SO2 emissions as under Option 3 because wet
scrubbers under all options are assumed to achieve SO2
emissions below 25 ppmv. The impacts of this option are presented in
Table 2 to this preamble.
The final option, Option 5, includes a lower PM limit, 0.15 kg/Mg
of coke burn, measured using Method 5, and the same SO2
limits as Option 4. This PM limit is equivalent to the limit of 0.005
gr/dscf required by California's South Coast Air Quality Management
District (SCAQMD). To meet this PM limit, we expect that a refinery
would need an ESP rather than a wet scrubber because we are unaware of
any wet scrubber that is meeting this PM limit (and as in Option 4,
catalyst additives in the fluid catalytic cracking unit would be needed
to meet the SO2 limit). In addition, the refinery would
likely need ammonia injection to improve the performance of the ESP.
Based on test data from at least three fluid catalytic cracking units,
ammonia injection improves the control of filterable PM in ESP, but it
also produces a considerable amount of condensable PM. Therefore, the
estimated total PM reduction for this option is much lower (worse) than
the reduction that would be achieved under Option 4. The shift to ESP
for all new fluid catalytic cracking units under this option also
slightly degrades the estimated SO2 emissions reduction
relative to Option 4 because available data indicate that wet scrubbers
achieve lower SO2 emissions than ESP and catalyst additives.
In addition to reduced performance relative to Option 4, the capital
and annual costs of this option are considerably higher than for Option
4. The reduced performance of this option relative to Option 4 means
that incremental cost-effectiveness is not meaningful for this option.
The impacts of this option are presented in Table 2 to this preamble.
[[Page 27190]]
Table 2.--National Fifth Year Impacts of Options for PM and SO2 Limits Considered for Fluid Catalytic Cracking
Units Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
Total Emission Emission Cost-effectiveness ($/
Capital annual cost reduction reduction ton)
Option cost ($1,000/ (tons PM/ (tons SO2/ -------------------------
($1,000) yr) yr) \a\ yr) Overall Incremental
----------------------------------------------------------------------------------------------------------------
1................................. 500 3,100 17 6,800 460
2................................. 670 3,600 350 6,800 500 1,400
3................................. 40,000 9,200 1,200 7,200 1,100 4,400
4................................. 40,000 9,500 1,200 8,300 1,000 220
5................................. 140,000 30,000 460 7,900 3,600 N/A
----------------------------------------------------------------------------------------------------------------
\a\ Both filterable and condensable PM.
Based on our review of performance data and potential impacts, we
have determined that control of PM emissions (as measured by Method 5)
to 0.5 kg/Mg of coke burn or less and control of SO2
emissions to 25 ppmv or less averaged over 365 days and 50 ppmv or less
averaged over 7 days is BDT for new, reconstructed, or modified fluid
catalytic cracking units. The more stringent filterable PM control
level in Option 5 is technically achievable, but we rejected this
option because it results in higher total PM and SO2
emissions than Option 4. Option 4 was selected as BDT because it
achieves the best performance of the remaining options, and both
overall and incremental costs are reasonable.
Table 3 to this preamble shows the impacts of Option 4 for modified
and reconstructed sources. Although the impacts of Option 4 are
reasonable, we are aware that there is some concern about the ability
to retrofit reconstructed and modified sources to meet these emission
limits. Specifically, there may be issues with physical space
availability, process unit or control device configurations, or other
factors that are not adequately included in our impacts analyses.
Therefore, we are co-proposing requiring reconstructed and modified
units to meet the current standards in 40 CFR part 60, subpart J. We
are requesting comment on specific examples, supported by data, of
situations that would support this proposed option.
Table 3.--National Fifth Year Impacts of Proposed Option for PM and SO2 Limits for Reconstructed and Modified
Sources
----------------------------------------------------------------------------------------------------------------
Total annual Emission Emission Cost-
Capital cost ($1,000) cost ($1,000/ reduction reduction effectiveness
yr) (tons PM/yr) (tons SO2/yr) ($/ton)
----------------------------------------------------------------------------------------------------------------
31,000...................................... 6,200 700 3,700 1,400
----------------------------------------------------------------------------------------------------------------
Finally, available test data indicate that the two control devices
(an ESP and a wet scrubber) that reduce filterable PM to less than 0.5
kg/Mg coke burn (as well as at least one other ESP) also can meet a
total PM limit, including condensables, of 1.0 kg/Mg of coke burn
(i.e., demonstrate compliance using Method 5 for filterable PM and
Method 202 for condensable PM). Condensable sulfates and other
condensable compounds measured by Method 5 and Method 202 vary widely,
but the average is about 0.5 kg/Mg of coke burn-off. In an attempt to
create some incentive to begin measuring condensables using improved
Method 202, we are considering establishing an alternative PM limit of
1 kg/Mg coke burn, including condensables. Therefore, we are asking for
comments with rationale to either support or reject an alternative PM
limit that would be based on both filterable PM and condensable PM.
Carbon Monoxide. The current standards in 40 CFR part 60, subpart J
limit CO emissions to 500 ppmv or less. This limit was established for
fluid catalytic cracking units that operate in either ``partial
combustion'' catalyst regeneration mode or ``complete combustion''
catalyst regeneration mode. In partial combustion mode, relatively
large amounts of CO are generated in the regenerator. The resulting CO
is then combusted in a CO or waste heat boiler. This operation results
in nearly complete combustion of the CO, with outlet concentrations on
the order of 25 to 50 ppmv being common. In complete combustion mode
the CO emissions from the regenerator are much lower, and a downstream
CO or waste heat boiler is impractical. However, complete combustion
catalyst regeneration was a recent advance at the time the current NSPS
was promulgated; test data were limited at that time, and a CO level of
500 ppmv was estimated to be a practical limit for the technology.
After consideration of available information, we are proposing to
retain the current CO standard for new fluid catalytic cracking units.
Although test data show CO emissions from complete combustion
regenerators can be less than 500 ppmv, the lower levels generally are
achieved by operating with higher levels of excess air. Unfortunately,
this operation is likely to result in higher NOX emissions.
If a trade-off is necessary, limiting NOX emissions is a
higher priority than limiting CO emissions because NOX is a
precursor to fine PM and ground-level ozone, both of which have more
significant health impacts than CO. Available data also indicate that
formaldehyde emissions tend to increase with the higher oxidation/
combustion conditions needed to reduce CO emissions. Therefore, we
determined that control to 500 ppmv or less is still BDT for CO
emissions, and the proposed standards are based on this emission limit.
Accordingly, the proposed limit for 40 CFR part 60, subpart J poses no
additional costs over those incurred to comply with the existing NSPS.
NOX. NOX emissions are not subject to control under the
existing NSPS in 40 CFR part 60, subpart J. However, several petroleum
refiners limit NOX emissions based on State regulations and
consent decrees. The emission limits to which refineries are subject
vary from facility to facility. We evaluated three options
[[Page 27191]]
as part of the BDT determination: Outlet NOX emission levels
of 80 ppmv, 40 ppmv, and 20 ppmv, each averaged over 7 days or less.
Each of these limits is technically feasible, but the technology needed
to meet them depends on the current NOX concentrations in
the vented gas streams, which are either uncontrolled or controlled to
levels required by existing State and local requirements.
The estimated fifth year emission reductions and costs for each of
the options are summarized in Table 4. To estimate impacts for Option
1, we assumed that a few units have current NOX emissions
below 80 ppmv, and many other units can meet this level with combustion
controls (e.g., limiting excess O2 or using non-platinum
catalyst combustion promoters in a complete combustion catalyst
regenerator, or using flue gas recirculation or low-NOX
burners in a CO boiler after a partial combustion catalyst
regenerator). Other units with higher uncontrolled NOX
emissions levels will need to install more costly control technology
such as LoTOxTM or SCR in order to meet the 80 ppmv option.
All units will also incur costs for a continuous NOX
monitor. The costs for Options 2 and 3 are higher than for Option 1
because the ratio of add-on controls to combustion controls would
increase in order to meet the lower limits of 40 and 20 ppmv.
Based on the impacts shown in Table 4, we determined that BDT is
option 1, a NOX emission limit of 80 ppmv. The costs of
option 1 are commensurate with the emission reductions while the more
stringent options would impose compliance costs that are not warranted
for the emissions reductions that would be achieved as shown by the
incremental cost effectiveness impacts shown in table 4. In general, we
expect that most sources will be able to meet the NOX limit
through combustion controls. In cases where add-on controls would be
necessary, however, there may be retrofit concerns for modified and
reconstructed sources. Therefore, we are co-proposing no new standards
for NOX emissions on modified or reconstructed sources and
are requesting comments on the necessity, feasibility and costs of
retrofits to meet the 80 ppmv limit for modified and reconstructed
sources.
Table 4.--National Fifth Year Impacts of Options for NOX Limits Considered for Fluid Catalytic Cracking Units
Subject to 40 CFR part 60, subpart Ja
----------------------------------------------------------------------------------------------------------------
Total capital Total annual Emission Cost effectiveness ($/ton)
Option cost, $ cost, $/yr reduction, -------------------------------
(millions) (millions) tons NOX/yr Overall Incremental
----------------------------------------------------------------------------------------------------------------
1............................... 28 7.3 3,500 2,100 ..............
2............................... 80 20 5,200 4,200 7,600
3............................... 120 30 5,800 5,500 16,000
----------------------------------------------------------------------------------------------------------------
Available test data for units controlled with SCR indicate that
emissions less than 20 ppmv are continuously achievable when averaged
over long periods of time such as 365 days. Although we determined that
the average costs to meet such a limit are unreasonable, we are
requesting comment on whether there may be a subset of units for which
costs would be reasonable to meet lower limits such as 20 or 40 ppmv,
averaged over 365 days.
Opacity. The current standards require fluid catalytic cracking
units to meet an opacity limit of 30 percent. This limit was included
as a means of identifying failure of the PM control device. This
objective is achieved much more effectively by monitoring control
device operating parameters or by using a PM CEMS. These monitoring
options are included in the proposed standards for PM. Therefore, the
proposed standards do not include an opacity emissions limit.
2. Fluid Coking Units
The current NSPS includes no requirements for fluid coking units.
There are few fluid coking units at refineries in the U.S., but data in
the National Emission Inventory database shows the few existing units
are significant sources of PM, SO2, and NOX
emissions. Therefore, we evaluated several options as part of a BDT
determination for fluid coking units. All of the options we considered
are comparable to options that we considered for fluid catalytic
cracking units because of similarities in the function, operation, and
emissions of the two types of units.
Particulate Matter and Sulfur Dioxide. To determine BDT for PM and
SO2 emissions we evaluated two options. Because control
technology can reduce both pollutants simultaneously, the options also
consider both pollutants. Option 1 is a PM limit of 1.0 kg/Mg coke burn
and a short-term SO2 limit of 50 ppmv, averaged over 7 days;
and Option 2 is a PM limit of 0.5 kg/Mg coke burn, a short-term
SO2 limit of 50 ppmv, averaged over 7 days, and a long-term
SO2 limit of 25 ppmv, averaged over 365 days. (Because
catalyst additives are not a feasible option for reducing
SO2 from a fluid coking unit, we did not consider the fifth
option evaluated for fluid catalytic cracking units.)
The Energy Information Administration (EIA) Refinery Capacity
Report 2006 lists six fluid coking units; at least two of these coking
units are flexi-coking units that use the coking exhaust as a synthetic
fuel gas. Therefore, there are at most four fluid coking units in the
United States that could potentially become subject to the standard.
Although coking capacity is expected to increase, most new units are
expected to be delayed coking units. For this analysis, we assumed that
one existing fluid coking unit becomes a modified or reconstructed
source in the next 5 years. A wet scrubber is the most likely
technology that would be used to meet either Option 1 or Option 2. To
estimate the impacts, we estimated costs for a basic wet scrubber to
meet Option 1 and an enhanced wet scrubber to meet Option 2. The
resulting emission reductions and costs for both of the options are
shown in Table 5 to this preamble. The costs for both options are
reasonable. Therefore, we determined that BDT is Option 2 which
requires technology that reduces PM emissions to 0.5 kg/Mg of coke burn
and reduces SO2 emissions to 50 ppmv, averaged over 7 days,
and 25 ppmv, averaged over 365 days. We are proposing standards
consistent with these levels.
[[Page 27192]]
Table 5.--National Fifth Year Impacts of Options for PM and SO2 Limits Considered for Fluid Coking Units Subject
to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
Emission Emission Cost-effectiveness ($/
Capital Total reduction reduction ton)
Option cost annual cost (tons PM/ (tons SO2/ -------------------------
($1,000) ($1,000/yr) yr) yr) Overall Incremental
----------------------------------------------------------------------------------------------------------------
1................................. 14,000 4,700 1,700 21,000 210 ...........
2................................. 14,000 4,800 2,000 21,000 210 120
----------------------------------------------------------------------------------------------------------------
Nitrogen Oxides (NOX). To determine BDT for NOX
emissions, we evaluated three options: Outlet NOX emission
levels of 80 ppmv, 40 ppmv, and 20 ppmv, each averaged over 7 days or
less. The specific technology that will be needed to meet these levels
will depend on the NOX concentration in the exhaust gas
stream from uncontrolled fluid coking units. As noted in the discussion
above for PM and SO2 options, we estimated that only one
fluid coking unit will be modified or reconstructed in the next 5
years, and there will be no new units constructed. Because each unit is
likely to have a different uncontrolled NOX concentration in
its exhaust stream, we developed impacts for a composite model unit
based on a weighted distribution of all the various types of controls
(low-efficiency combustion controls, higher efficiency combustion
controls, and add-on controls such as LoToxTM or SCR). As in
the analysis for fluid catalytic cracking units, the ratio of add-on
controls to combustions controls increases from Option 1 through Option
3. The results of this analysis are shown in Table 6 to this preamble.
Table 6.--National Fifth Year Impacts Options for NOX Limits Considered for Fluid Coking Units Subject to 40 CFR
Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
Total Emission Cost-effectiveness ($/
capital Total annual reduction, ton)
Option cost, $ cost, $/yr (tons NOX/ -------------------------
(millions) (millions) yr) Overall Incremental
----------------------------------------------------------------------------------------------------------------
1............................................ 4.5 0.97 760 1,300
2............................................ 9.5 2.1 980 2,200 5,300
3............................................ 13 2.9 1,000 2,800 12,000
----------------------------------------------------------------------------------------------------------------
The costs for option 1 are commensurate with the emission
reductions, but the incremental impacts for options 2 and 3 are not
reasonable, as shown in Table 6. Based on these potential impacts and
available performance data, we have determined that BDT is technology
needed to meet an outlet NOX concentration of 80 ppmv or
less, and we are proposing this emission limit as the performance
standard for NOX emissions from fluid coking units. However,
there are uncertainties in this analysis. For example, if the few
existing units are not readily amenable to retrofitting NOX
controls, the cost and emission reduction impacts might no longer be
favorable, and we would conclude that no control is BDT. Therefore, we
are co-proposing no new standard for NOX emissions from
fluid coking units.
3. Sulfur Recovery Plants
Emission limits in the existing NSPS (40 CFR part 60, subpart J)
apply to Claus SRP with a capacity greater than 20 LTD. The emission
limits are consistent with an overall sulfur recovery efficiency of
99.9 percent (i.e., 250 ppmv SO2 for the Claus unit followed
by oxidative tail gas treatment, and 10 ppmv H2S and 300
ppmv total reduced sulfur compounds for a Claus unit followed by
reductive tail gas treatment). Although small SRP and non-Claus SRP are
not subject to the existing NSPS, they are often subject to control.
For example, Texas requires sulfur removal efficiencies of 99.8 percent
for SRP with capacities greater than 10 LTD and 96 percent to 98.5
percent for SRP with capacities less than or equal to 10 LTD. In
addition, a few consent decrees require 95 percent sulfur recovery for
Claus SRP with capacities less than 20 LTD.
To determine BDT we evaluated 4 options. The options are based on
various sulfur recovery efficiencies for SRP with capacities less than
20 LTD, and all of the options include the same 99.9 percent efficiency
as in the current standards for SRP with capacities greater than 20
LTD. Option 1 is based on 99 percent recovery for SRP with capacities
between 10 LTD and 20 LTD, and 95 percent recovery for SRP with
capacities less than 10 LTD. Option 2 is based on 99 percent recovery
for all SRP with capacities less than 20 LTD. Option 3 is based on 99.9
percent recovery for SRP with capacities between 10 LTD and 20 LTD, and
99 percent recovery for SRP with capacities less than 10 LTD. Option 4
is based on 99.9 percent recovery for all SRP, regardless of size or
design. All of the options include 99.9 percent recovery for SRP larger
than 20 LTD (both Claus and non-Claus units) because we are not aware
of a more effective SO2 control technology. The 95 percent
option is equivalent to the efficiency of a two-stage Claus unit
without controls. The 99 percent and 99.9 percent recovery levels are
achievable for SRP of all sizes by various types of tail gas
treatments, as discussed in section V.D of this preamble.
The estimated fifth year emission reductions and costs for each of
the options are summarized in Table 7. These values reflect the impacts
only for SRP smaller than 20 LTD because we expect that all non-Claus
units will be smaller than 20 LTD and because the impacts for larger
Claus units would be the same as to comply with the existing standards
in subpart J. The costs for Options 1, 2, and 3 are reasonable. We then
evaluated the incremental costs and emission reductions between the
options. We found that Option 2 is the most stringent option for which
incremental costs are reasonable compared to the incremental emission
reduction between the options.
Based on the available performance data and cost considerations, we
have concluded that tail gas treatments that achieve 99.9 percent
control are still
[[Page 27193]]
BDT for SRP with capacities greater than 20 LTD, and tail gas
treatments that achieve 99 percent recovery are BDT for SRP with
capacities less than 20 LTD. Therefore, we are proposing standards for
SO2 and H2S emissions from SRP with capacities
larger than 20 LTD that are equivalent to the existing standards, and
we are proposing standards for SRP with capacities smaller than 20 LTD
that would limit emissions of sulfur to less than 1 percent by weight
of the sulfur recovered.
Table 7.--National Fifth Year Impacts of Options for SO2 Limits Considered for Sulfur Recovery Plants Subject to
40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
Total Emission Cost-effectiveness ($/
capital Total annual reduction, ton)
Option cost, $ cost, $/yr (tons SO2/ -------------------------
(millions) (millions) yr) Overall Incremental
----------------------------------------------------------------------------------------------------------------
1............................................ 0.27 0.14 180 780
2............................................ 1.1 0.68 550 1,200 1,500
3............................................ 1.9 1.0 590 1,700 8,200
4............................................ 4.5 2.3 670 3,400 15,000
----------------------------------------------------------------------------------------------------------------
4. Process Heaters and Other Fuel Gas Combustion Devices Sulfur Dioxide
The current NSPS in 40 CFR part 60, subpart J limits SO2
emissions from fuel gas combustion devices by specifying that the
H2S content of fuel gas must be less than or equal to 230
mg/dscm, averaged over 3 hours (equivalent to 160 ppmv averaged over 3
hours). Alternatively, any fuel gas may be combusted, provided the
outlet SO2 emissions are controlled to no more than 20 ppmv
(dry basis, 0 percent excess air). When the current NSPS was
promulgated, we concluded that amine scrubbing as well as new processes
that use other scrubbing media represented BDT for continuous reduction
of H2S from fuel gas. The 160 ppmv concentration limit was
consistent with good operation of such scrubbing processes. In
addition, burning such fuel gas will result in an SO2
concentration in the exhaust gas of about 20 ppmv.
After consideration of current operating practices, we concluded
that amine scrubbing units are still the predominant technology for
reduction of H2S in fuel gas (and SO2 emissions
from subsequent fuel gas combustion). Considering the variability of
the fuel gas streams from various refinery processing units, 160 ppmv
also is still a realistic short term H2S concentration
limit. However, one California Air Quality Management District rule
sets a 40 ppmv H2S limit in fuel gas (averaged over 4
hours), and several refiners have reported that the typical fuel gas
H2S concentrations (after scrubbing) are in the same range.
Additionally, amine scrubbing technology can be designed and is, in
fact, being used to achieve much lower (1 to 5 ppmv) H2S
concentrations in product gas applications. Based on this information,
we concluded that additional SO2 control could be achieved
by requiring SO2 emission limits with both long-term and
short-term averaging periods.
We considered three options for increasing SO2 control
of fuel gas combustion units: Outlet SO2 emission levels of
10 ppmv, 8 ppmv, and 5 ppmv SO2, each averaged over 365
days. Each of the options also includes the same 20 ppmv 3-hour
SO2 concentration limit as in the current NSPS. To achieve
each of these options, we expect that petroleum refiners will increase
their amine recirculation rates to reduce the H2S
concentration in the fuel gas. We estimate that meeting the options
will increase steam consumption for a typical scrubbing unit by about
5, 7, and 10 percent, respectively. No new equipment or other capital
expenditures would be necessary. The estimated fifth-year impacts of
each of these options are presented in Table 8 to this preamble.
Overall costs for all the options are reasonable compared to the
emission reduction achieved. We further evaluated the incremental costs
and reductions between the 3 options and found that they were
reasonable for Options 1 and 2, while the incremental cost for Option 3
is not.
Table 8.--National Fifth Year Impacts of Options for SO2 Limits Considered for Process Heaters and Other Fuel
Gas Combustion Devices Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
Emission Cost-effectiveness ($/
Capital cost Total annual reduction ton)
Option ($1,000) cost (tons SO2/ -------------------------
($1,000/yr) yr) Overall Incremental
----------------------------------------------------------------------------------------------------------------
1............................................ 0 2,000 1,000 1,900
2............................................ 0 2,900 1,300 2,200 3,500
3............................................ 0 4,100 1,600 2,600 4,700
----------------------------------------------------------------------------------------------------------------
Based on these impacts and consideration of current operating
practices, we concluded that BDT is use of technology that reduces the
SO2 emissions from fuel gas combustion units to 8 ppmv or
less averaged over 365 days and 20 ppmv or less averaged over 3 hours.
Therefore, we are proposing SO2 standards consistent with
this determination. We are also requesting comment on the proposed
long-term concentration limit and the length of the averaging period.
Although the proposed emission limits are based primarily on the
fuel gas desulfurization technologies (e.g., amine scrubbing), new
process heaters, regardless of fuel type, also would be subject to
these emission limits. New process heaters can elect to meet these
emission limits by using treated fuel gas, low sulfur distillate fuel
oils, or flue gas desulfurization or other SO2 add-on
controls. Considering the low sulfur fuel standards and available
control technologies, we believe the 20 ppmv 3-hour average
SO2 emission limit and an
[[Page 27194]]
8 ppmv 365-day average emission limit represent the performance of BDT
regardless of whether the new process heaters use gaseous or liquid
fuels.
The current NSPS allows refineries to demonstrate compliance with
fuel gas concentration limits for H2S as a surrogate for
SO2 emission limits. This approach is reasonable when
H2S is the only sulfur-containing compound in the fuel gas
because the H2S concentration in the fuel gas that is
equivalent to the SO2 concentration in the exhaust from the
fuel gas combustion unit can be easily estimated. However, based on
available data, we understand that a significant portion of the sulfur
in fuel gas from coking units is in the form of methyl mercaptan and
other reduced sulfur compounds. These compounds will also be converted
to SO2 in the fuel gas combustion unit, which means the
SO2 emissions will be higher than the amount predicted when
H2S is the only sulfur-containing compound in the fuel gas.
Therefore, for process heaters and other fuel gas combustion devices
that burn only fuel gas, we are proposing two alternatives to the
SO2 emission limit. The first option would require
measurement of H2S if none of the fuel gas is from a coking
unit. The H2S concentration limits that would be equivalent
to the SO2 emission limits are 160 ppmv, averaged over 3
hours, and 60 ppmv averaged over 365-days. The second option would
require measurement of TRS instead of H2S when any of the
fuel gas burned in the process heater or other fuel gas combustion unit
is from a coking unit. The TRS concentration limits would be the same
as the H2S concentration limits. We are requesting comment
on the proposed requirement to measure the TRS concentration. We are
interested in any technological limitations of this option and whether
there are other fuel gas streams that contain reduced sulfur compounds
that should not be subject to the same requirement.
In addition to the proposed SO2 emission limits and
H2S and TRS concentration limits, we are also proposing to
include the same exemptions from fuel gas continuous monitoring
requirements that we are proposing for subpart J. See section IV.A of
this preamble for a discussion of our rationale for these proposed
exemptions.
NOX. NOX emissions from process heaters are not subject
to control under the existing NSPS in 40 CFR part 60, subpart J.
However, several petroleum refiners are subject to NOX
control requirements for process heaters in their consent decrees and
State regulations. The emission limits to which refineries are subject
vary from facility to facility. We evaluated four options as part of
the BDT determination. Each option consists of a potential
NOX emission limit and applicability based on process heater
size. Option 1 would limit NOX emissions to 80 ppmv or less
for all process heaters with a capacity greater than 20 million British
thermal units per hour (MMBtu/hr). Option 2 would limit NOX
emissions to 40 ppmv or less for all process heaters with a capacity
greater than 20 MMBtu/hr. Option 3 would limit NOX emissions
to 30 ppmv or less for all process heaters with a capacity greater than
40 MMBtu/hr. Option 4 would limit NOX emissions to 40 ppmv
or less for process heaters with a capacity greater than 20 MMBtu/hr or
less than or equal to 100 MMBtu/hr, and to 20 ppmv or less for process
heaters with a capacity greater than 100 MMBtu/hr. In each option, the
NOX concentration is based on a 24-hour rolling average.
The estimated fifth year emission reductions and costs for each
option are summarized in Table 9. We believe that nearly all process
heaters at refineries that will become subject to subpart Ja can meet
Option 1 using combustion controls (low NOX burners or ultra
low NOX burners). Stepping from Option 1 through Option 4
increases the fraction of process heaters that would need to use more
efficient control technologies, such as LoTOxTM or SCR, to
meet the NOX concentration limit. The options include a
minimum 20 MMBtu/hr size threshold because none of the control
technologies are cost effective for units with smaller capacities.
Table 9.--National Fifth Year Impacts Options for NOX Limits Considered for Process Heaters Subject to 40 CFR
Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
Total Total Emission Cost effectiveness ($/
capital annual reduction, ton)
Option cost, $ cost, $/yr (tons NOX/ -------------------------
(millions) (millions) yr) Overall Incremental
----------------------------------------------------------------------------------------------------------------
1.............................................. 140 28 17,000 1,600 ...........
2.............................................. 200 38 20,000 1,900 3,100
3.............................................. 280 52 21,000 2,600 85,000
4.............................................. 470 88 22,000 4,000 27,000
----------------------------------------------------------------------------------------------------------------
Based on the impacts in Table 9, the overall costs of option 1 and
option 2 are reasonable compared to the emission reductions. The
incremental cost, however, between options 1 and 2 is not commensurate
with the additional emission reduction achieved. Therefore, BDT for
process heaters greater than 20 MMBtu/hr was determined to be
technology that achieves an outlet NOX concentration of 80
ppmv or less, and we are proposing standards for NOX
emissions from process heaters consistent with this determination.
5. Work Practice Standards for Fuel Gas Production Units
We reviewed applicable state and local regulations and consent
decree requirements and met with individual refinery representatives
regarding their pollution prevention practices. The pollution
prevention practices identified included flare minimization plans, fuel
gas recovery requirements, start-up and shutdown requirements, and
sulfur shedding plans (including redundant sulfur recovery capacity).
Based on our review, all of these approaches could be expected to
reduce emissions of VOC and SO2 to the atmosphere. As
described in the following subsections, we reviewed these pollution
prevention practices and are proposing three different work practice
standards. Work practice standards are being proposed because it is not
feasible to prescribe or enforce a standard of performance for these
emission sources. As provided in section 111(h) of the Clean Air Act,
we may promulgate design, equipment, work practice, or operational
standards when it is not feasible to prescribe or enforce a standard of
performance. It is not feasible to prescribe or enforce a standard of
performance for these
[[Page 27195]]
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 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 has options for eliminating routine
flaring, including, but not limited to, diverting the fuel gas to a
nearby low-pressure heater or boiler, pressurizing the fuel gas so that
it can be diverted to the fuel gas system, or installing a 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 recover 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 flare gas recovery system may be used.
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,
assuming total costs are assigned to each pollutant. 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 from 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.
We cannot conclude at this time that co-generation or other projects
that use 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 Start-up, Shutdown, and Malfunctions.
The current NSPS includes no requirements for a start-up, shutdown, and
malfunction plan. We identified three emission prevention methods that
can be addressed within the context of a start-up, shutdown, and
malfunction plan. These are: Flare minimization during planned start-
ups and shutdowns; flare minimization during malfunctions of the sour
gas amine
[[Page 27196]]
treatment units and sulfur recovery plants; and performing root-cause
analyses of malfunctions that release in excess of 500 lb per day of
SO2. Our rationale for including each of these three
emission prevention methods are described in the following paragraphs.
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).
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, we are proposing that
implementing a start-up and shutdown plan focused on reducing emissions
during planned start-up and shutdown events would be BDT.
We evaluated several different requirements to promote 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.
However, when there is a malfunction of the amine treatment system or
the sulfur recovery plant, there has been some uncertainty as to
whether combustion or flaring of the sour gas is considered to be
exempt from the SO2 emission limit. This is because the
amine treatment system or sulfur recovery plant is not ``generating''
the gas stream, it is merely treating it. As such, the amine treatment
system and sulfur recovery plant are essentially control devices, and
refinery owners and operators are required to minimize emissions during
these control system malfunctions, up to and including the shutdown of
the emissions generating units.
A variety of prescriptive requirements were reviewed, such as
requiring 24-hour storage capacity of lean amine solution and empty
tank storage capacity to receive 24 hours worth of rich amine solution,
requiring inventory of critical spare parts, and requiring redundant
amine scrubbing and sulfur recovery capacity. While these are all
viable options that a plant can employ to minimize malfunction
emissions associated with the amine treatment system or sulfur recovery
plant, the most cost-effective means to minimize these emissions are
highly site-specific, being dependent on the number and location of the
amine units or sulfur recovery trains within the sulfur recovery plant.
We evaluated two alternatives, which are not mutually exclusive,
for minimizing flaring of H2S-rich fuel gas in the event of
a malfunction in the amine stripper or sulfur recovery plant. Option 1
is to store 24 hours worth of lean amine solution in case of a
malfunction in the amine stripper. We estimate that this alternative
would require a capital cost of approximately $10 million (for 2
storage tanks and excess amine) for a 50 long LTD SRU system, resulting
in an annualized cost of $1 million/year. If the 24 hours of excess
amine was used one time per year for an entire day, 50 LTD of sulfur
would have resulted in 110 tons of SO2 emissions avoided. If
there are three occurrences per year where the excess amine solution is
used, 330 tons of emissions would be reduced. This scenario results in
a cost-effectiveness ranging from $3,000 to 9,000 per ton of
SO2 reduced.
Option 2 is to have a redundant Claus unit. The capital cost of a
50 LTD Claus unit is also approximately $10 million, resulting in an
annualized cost of $1 million/year. Again, if there are one to three
days of emissions avoided, this option results in a cost-effectiveness
ranging from $3,000 to $9,000 per ton of SO2 reduced. For
sulfur recovery plants consisting of multiple Claus units, the
likelihood of needing the additional Claus train more than three times
per year increases significantly, making the redundant Claus unit a
cost-effective option.
It is difficult to predict the quantity of emissions avoided as
they are dependent on random malfunction events of variable durations.
While the cost-effectiveness values of these options are not
necessarily compelling given the uncertainty in the emissions avoided,
the options evaluated are expected to be extreme measures. It is
likely, for example, that maintaining appropriate spare parts for the
system would provide a cost-effective means of reducing emissions.
This, along with short-term reductions in high-sulfur fuel gas
production could be used to eliminate the need to flare or otherwise
combust these high sulfur-containing fuel gases.
Based on this analysis, we are proposing that a start-up, shutdown,
and malfunction plan that specifically addresses the minimization of
fuel gas combustion of high sulfur-containing fuel gases during
malfunctions of an amine treatment system or sulfur recovery plant is
BDT. The start-up, shutdown, and malfunction plan will address specific
process upset and malfunction events associated with the amine
treatment system and sulfur recovery plant and the standard operating
procedures to follow to minimize emissions during these events.
Compliance is demonstrated by following the procedures in the plan. As
previously mentioned, we are proposing a work practice standard rather
than an equipment standard to provide flexibility to the refinery owner
or operator regarding the best way to minimize malfunction emissions
given the refinery's specific configuration and sulfur loads.
Finally, we evaluated a requirement for performing root-cause
analyses as a means to minimize the frequency of process malfunctions
and thereby
[[Page 27197]]
reduce malfunction emissions. Even though process upset gas is exempt
from the SO2 emission limits associated with fuel gas
combustion units, we believe it is good air pollution practice to
investigate the causes of significant atmospheric releases caused by
process upsets or malfunctions to determine if similar upsets or
malfunctions can be reasonably prevented from recurring. Similarly, we
believe it is good pollution control practice to investigate
significant emission exceedances to determine the cause of the
exceedance and to implement procedures to prevent its recurrence. The
cost-effectiveness of these investigations is dependent on the
frequency and magnitude of the emission episodes; for very small
emission episodes, the manpower required to perform the investigations
do not justify the potential emission reductions that might be realized
from the root-cause analysis. We estimate that a root-cause analysis
would cost approximately $2,500 to perform. For emissions of less than
500 pounds per day, the cost-effectiveness of the root-cause analysis,
even assuming it would completely eliminate a future recurrence, would
be approximately $10,000 per ton of SO2 reduced. Similarly,
for emissions of 1,000 pounds per day, the cost-effectiveness would be
on the order of $5,000 per ton of SO2 reduced. As the
probability of successfully identifying a means to avoid future
emissions from each root-cause analysis performed is certainly less
than 100 percent, we determined that it was not cost effective to
perform root-cause analyses for SO2 emissions exceedances of
500 pounds per day or less and request comment on alternative
thresholds in the range of 500 to 1,000 lbs per day.
For SO2 releases of greater than 500 pounds per day, the
emissions reductions potential of the root-cause analyses increases and
the cost-effectiveness improves, so we are proposing that performing
root-cause analyses for SO2 releases of greater than 500
pounds per day would be BDT. Any emission limit exceedance or any
process start-up, shutdown, upset or malfunction that causes a
discharge into the atmosphere in excess of 500 pounds per day of
SO2 would require a root cause analysis to be performed. We
also considered a similar requirement for hydrocarbon flaring events
with the purpose of reducing VOC emissions. However, we expect refinery
owners and operators to investigate large hydrocarbon releases as these
releases represent lost revenues. Furthermore, as flares are efficient
in destroying VOC, the potential to significantly reduce VOC emissions
by performing root-cause analysis is much less than the potential for
reducing SO2 emissions. We request comment on the need to
include root cause analyses for hydrocarbon releases. If root-cause
analyses are recommended, please provide in your comments the
recommended release quantities that would trigger the root-cause
analysis and justification for the recommendation. If root cause
analyses are not recommended, please provide in your comments the
rationale for not requiring root-cause analysis for any VOC
(hydrocarbon) releases.
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. The scope of these
requirements is limited to affected facilities under this rule. We
request comment on the need to implement this requirement to all new
process units at the refinery, not just fuel gas producing units such
as fluid catalytic cracking units, fluid coking units, fuel gas
combustion devices, and sulfur recovery plants.
On the other hand, based on site-specific conditions and given the
nature of the types of emissions events that are being addressed by the
start-up, shutdown, and malfunction plan, it is impossible to
conclusively determine that one or all of the emission reduction
methods addressed in the start-up, shutdown, and malfunction 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
requirement for a start-up, shutdown, and malfunction plan. 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. We also request comments and supporting data that
indicate the number and duration of malfunctions in the amine stripper
and sulfur recovery plants, the costs associated with alternative
sulfur shedding practices, and other information that can be used to
justify either the inclusion or exclusion of this provision in the
final rule.
Finally, we request comment, along with supporting data, that
indicate the frequency of emission events exceeding 500 pounds per day,
the percentage of times the root-cause analysis results in positive
steps that may avoid future recurrence of the event, and other
information that can be used to justify either the inclusion or
exclusion of this provision in the final rule.
Delayed Coking Unit Depressurization. The primary emission releases
from delayed coking units occur as the coking vessels are depressurized
and petroleum coke is removed from the unit. When the delayed coking
cycle is completed, the coke-filled vessel is steam stripped. Most of
the gases from this process continue to be sent to the coking unit
distillation column. At some point in time, the steam gas discharge is
diverted to the blow-down system. The delayed coking unit typically has
a fuel gas recovery system (compressor) due to the quantity of fuel gas
produced by the unit. Therefore, it is cost-effective to require the
blow-down system gases to be recovered in the unit's fuel gas recovery
system, in keeping with the proposed work practice standard that fuel
gas from fuel gas producing units will not be routinely flared.
As the process unit continues to depressurize, there is a point
where the gases can no longer be discharged to the blow-down system or
fuel gas recovery line, at which point the remaining steam and gases
are vented to the atmosphere. To achieve maximum reduction of
uncontrolled releases, the unit should be depressurized to as low a
pressure as possible before venting to the atmosphere. Below a pressure
of 5 pounds per square inch gauge (psig) in the delayed coking unit
drum, it is not technically feasible to divert the emissions for
recovery. Above a vessel pressure of 5 psig, it is technically feasible
to divert the emissions for recovery. Furthermore, as the unit already
has a gas compressor, the costs associated with recovering these gases
is minimal.
We estimate that this practice can reduce VOC emissions by 120 tons
per year and SO2 emissions by at 200 tons per year. The
total annualized costs are expected to be minimal for new units, but
installing the appropriate piping for a modified or reconstructed unit
may result in annualized costs of up to $100,000 per year. Even under
this extreme condition, the cost effectiveness of the requirement is
about $800 per ton of VOC reduced and $500 per ton of SO2
reduced. Therefore, we conclude that a work practice standard that
requires a delayed coking unit to depressure to 5 psig during reactor
vessel depressuring and vent the exhaust gases to the fuel gas system
for recovery is BDT. Note this determination is independent of the
[[Page 27198]]
work practice to eliminate routine flaring from fuel gas producing
units and requires flare gas recovery of depressurization gases even
under the option of no work practice requirement to minimize flaring.
In addition to the depressurization emissions, we also identified
at least one refinery that has designed an enclosed system for their
coke-cutting operations. Coke cutting operations were identified as a
significant VOC emission source at refineries during an Alberta
Research Council study, with an estimated VOC emissions rate of 1,300
tons per year. We do not have any data regarding the effectiveness of
the coke-cutting enclosure system, whether the enclosure seals are air
tight or if they allow some percentage of the emissions escape. The
enclosure may simply suppress the emissions until the coke is removed
from the unit, at which time the emissions are released. Additionally,
we do not have any data on the costs of these systems and whether or
not existing units can be retrofitted if the delayed coking unit is
modified or reconstructed. Therefore, we cannot conclude that an
enclosed coke cutting system is BDT, but we request comment and
additional information on coke-cutting system controls, their cost,
their effectiveness, and their limitations.
VI. Modification and Reconstruction Provisions
Existing affected sources that are modified or reconstructed would
be subject to the proposed standards in 40 CFR part 60, subpart Ja. A
modification is any physical or operational change to an existing
facility which results in an increase in the emission rate to the
atmosphere of any pollutant to which a standard applies (see 40 CFR
60.14). Changes to an existing facility that do not result in an
increase in the emission rate, as well as certain changes that have
been exempted under the General Provisions (see 40 CFR 60.14(e)) are
not considered modifications.
Rebuilt petroleum refinery process units would become subject to
the proposed standards in 40 CFR part 60, subpart Ja under the
reconstruction provisions, regardless of changes in emission rate.
Reconstruction means the replacement of components of an existing
facility such that (1) the fixed capital cost of the new components
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility; and (2) it is
technologically and economically feasible to meet the applicable
standards (40 CFR 60.15).
With the exception of the standards for fluid catalytic cracking
units, we are proposing that modified or reconstructed sources be
subject to the same proposed standards in 40 CFR part 60, subpart Ja,
as new sources. The decision to maintain consistent standards for both
new and modified or reconstructed sources was based on an evaluation of
the cost-effectiveness and incremental cost-effectiveness of the
proposed standards on both types of sources and on the feasibility of
retrofitting existing units. We have included in the docket a table
(Impacts Summary) which summarizes our estimates costs for different
control options for both new and reconstructed or modified process
units. We request comment on these cost estimates and on specific
issues related to the feasibility of retrofitting existing units, as
well as our assessment that cost-effectiveness numbers are similar
enough such that it is appropriate to have identical standards for both
new and modified or reconstructed sources.
VII. Request for Comments
Table 10 summarizes the topics on which we have specifically
requested comment throughout this preamble. We note, however, that
comments on all aspects of this proposal are welcome.
Table 10.--Summary of Topics on Which Comment Is Requested
------------------------------------------------------------------------
Section in this preamble where
Topic topic is discussed
------------------------------------------------------------------------
Effects of proposed PM, SO2 and NOX III.B. and V.E.1.
standard on modified or reconstructed
fluid catalytic cracking units. Also
co-proposed 40 CFR part 60, Subpart J
standards for SO2 and PM and no NOX
limits for modified and reconstructed
sources.
Exemption for emergency flares......... IV.A.
Exemption from monitoring for fuel gas IV.A.
streams related to commercial liquid
products.
Exemption from monitoring for fuel gas IV.A.
streams generated by process units
that are intolerant of sulfur.
Alternative PM limit for fluid V.E.1.
catalytic cracking units based on
condensable PM as well as filterable
PM.
Alternative lower (20 ppmv, 40 ppmv) V.E.1.
NOX limit, averaged over 365 days, for
fluid catalytic cracking units.
Co-propose no new NOX standard for V.E.2.
fluid coking units.
Appropriate long-term average H2S V.E.4.
concentration limit for fuel gas
combustion units, and requirement to
monitor TRS instead of H2S for fuel
gas from coker units.
Various aspects of work practice V.D.5.
standards to minimize routine flaring
and enhance SO2 control versus no
standards: alternative means of
eliminating flaring, number of ``fuel
gas rich'' refineries, need for a
startup, shutdown, and malfunction
plan (SSMP), including rationale for
or against requiring a root cause
analysis for hydrocarbon releases and
sulfur shedding practices, and
information about emission control
systems for coke cutting operations.
Also co-propose no requirements for
routine flaring and no SSMP.
------------------------------------------------------------------------
VIII. Summary of Cost, Environmental, Energy, and Economic Impacts
In setting standards, the CAA requires us to consider alternative
emission control approaches, taking into account the estimated costs as
well as impacts on energy, solid waste, and other effects. We request
comment on whether we have identified the appropriate alternatives and
whether the proposed standards adequately take into consideration the
incremental effects in terms of emission reductions, energy, and other
effects of these alternatives. We will consider the available
information in developing the final rule.
A. What are the impacts for petroleum refining process units?
We are presenting estimates of the impacts for the proposed
requirements of subpart Ja that change the performance standards: the
emission limits for fluid catalytic cracking units, sulfur recovery
plants, fluid coking units, fuel gas combustion devices, and process
heaters, as well as the work practice standards. The proposed
amendments to 40 CFR part 60, subpart J are clarifications to the
existing rule, and they have no emission reduction impacts. The cost,
environmental, and economic impacts presented in this section are
expressed as incremental
[[Page 27199]]
differences between the impacts of petroleum refining process units
complying with the proposed subpart Ja and the current NSPS
requirements of subpart J (i.e., baseline). The impacts are presented
for petroleum refining process units that commence construction,
reconstruction, or modification over the next 5 years. The analyses and
the documents referenced below can be found in Docket ID No. EPA-HQ-
OAR-2007-0011.
In order to determine the incremental costs and emission reductions
of this proposed rule, we first estimated baseline impacts. For new
sources, baseline costs and emission reductions were estimated for
complying with subpart J; incremental impacts for subpart Ja were
estimated as the costs to comply with subpart J subtracted from the
costs to comply with proposed subpart Ja. Sources that are modified or
reconstructed over the next 5 years would comply with subpart J in the
absence of proposed subpart Ja. We assumed that prior to reconstruction
or modification, these sources would either be subject to a consent
decree (equivalent to about 77 percent of the industry by capacity),
complying with subpart J or equivalent limits, or complying with 40 CFR
part 63, subpart UUU (MACT II). Baseline costs and emission reductions
were estimated as the effort needed to comply with subpart J from one
of those three starting points. The costs and emission reductions to
comply with proposed subpart Ja were estimated from those starting
points as well. The estimated costs presented for work practice
standards include only the labor cost to prepare the required plan or
analysis; we did not attempt to quantify costs and emission reductions
for the variety of ways a facility may choose to implement those plans.
We assumed that each facility would evaluate their options and choose
the most cost-effective option for the facility's unique position. For
further detail on the methodology of these calculations, see Docket ID
No. EPA-HQ-OAR-2007-0011.
When considering and selecting emission limits for the proposed
rule, we evaluated the cost-effectiveness of each option for new
sources separately from reconstructed and modified sources. However,
since our selections for each process unit and pollutant were
consistent for all units, we are presenting our costs and emission
reductions for the overall rule. We estimate that the proposed
amendments will reduce combined emissions of PM, SO2, and
NOX about 55,800 tons/yr from the baseline. The estimated
increase in annual cost, including annualized capital costs, is about
$54,100,000. The overall cost-effectiveness is about $970 per ton of
pollutants removed. The estimated nationwide 5-year incremental
emissions reductions and cost impacts for the proposed amendments are
summarized in Table 11 of this preamble.
Table 11.--National Incremental Emission Reductions and Cost Impacts for Petroleum Refinery Units Subject to
Proposed Standards Under 40 CFR Part 60, Subpart Ja (Fifth Year After Proposal)
----------------------------------------------------------------------------------------------------------------
Annual
Total capital Total annual emission Cost-
Process unit Pollutant cost ($1,000) cost ($1,000/ reductions effectiveness
yr) (tons/yr) ($/ton)
----------------------------------------------------------------------------------------------------------------
FCCU.......................... PM and SO2...... 40,000 9,500 9,500 1,000
FCCU.......................... NOX............. 28,000 7,300 3,500 2,100
Fluid Coker................... PM and SO2...... 14,000 4,800 23,000 210
Fluid Coker................... NOX............. 4,500 970 760 1,300
SRP........................... SO2............. 1,100 680 550 1,200
Process Heaters and Fuel Gas SO2............. 0 2,880 1,300 2,200
Combustion.
Process Heaters............... NOX............. 140,000 28,000 17,000 1,600
Work Practices................ ................ .............. 250 .............. ..............
---------------------------------------------------------------
Total..................... ................ 230,000 54,000 56,000 970
----------------------------------------------------------------------------------------------------------------
B. What are the secondary impacts?
Indirect or secondary air quality impacts of this proposed rule
would result from the increased electricity usage associated with the
operation of control devices. Assuming that plants would purchase
electricity from a power plant, we estimate that the standards as
proposed would increase secondary emissions of criteria pollutants,
including PM, SO2, NOX, and CO from power plants.
For new, modified or reconstructed sources, this proposed rule would
increase secondary PM emissions by 24 Mg/yr (27 tpy); secondary
SO2 emissions by about 970 Mg/yr (1,100 tpy); secondary
NOX emissions by about 480 Mg/yr (530 tpy); and secondary CO
emissions by about 16 Mg/yr (17 tpy) for the 5 years following
proposal.
As explained earlier, we expect that affected facilities will
control emissions from fluid catalytic cracking units by installing and
operating ESP or wet gas scrubbers. We also expect that the emissions
from the affected fluid coker will be controlled with a wet scrubber.
For these process units, we estimated solid waste impacts for both
types of control devices and water impacts for wet gas scrubbers. In
addition, the controls needed by small sulfur recovery plants will
generate condensate. We project that this proposed rule will generate
4.5 billion gallons of water per year for the 5 years following
proposal. We also estimate that this proposed rule will generate 8,600
Mg/yr (7,800 tpy) of solid waste over those 5 years.
Energy impacts consist of the electricity and steam needed to
operate control devices and other equipment that would be required
under the proposed rule. Our estimate of the increased energy demand
includes the electricity needed to produce the required amounts of
steam as well as direct electricity demand. We project that this
proposed rule would increase overall energy demand by about 170
gigawatt-hours per year (590 billion British thermal units per year).
C. What are the economic impacts?
This proposal affects certain new and reconstructed/modified
sources found at petroleum refineries as defined earlier in this
preamble. We performed an economic impact analysis that estimates
changes in prices and output for gasoline nationally using the annual
compliance costs estimated for this proposal. The methodology for this
[[Page 27200]]
analysis incorporates changes in producer and consumer behavior by
considering passthrough of increased production costs from producers to
consumers. All estimates are for the fifth year after proposal since
this is the year for which the compliance cost impacts are estimated.
The analysis estimates a price increase in gasoline of less than
0.02 percent nationally will take place along with a corresponding
reduction in gasoline output of less than 0.004 percent (or less than 6
million gallons a year). The overall total annual social costs, which
reflect changes in consumer and producer behavior in response to the
compliance costs, are $53.0 million (2005 dollars) or almost identical
to the compliance costs.
For more information, please refer to the economic impact analysis
report that is in the public docket for this proposed rule.
D. What are the benefits?
We estimate the monetized benefits of this proposed rule to be $957
million (2005$) in the fifth year after proposal. We base the portion
of the benefits estimate derived from the PM2.5 and
SO2 emission reductions on the approach and methodology laid
out in EPA's 2004 benefits analysis supporting the regulation of
emissions from the Industrial Boilers MACT (included in the Regulatory
Impact Analysis (RIA) for the Industrial Boilers and Process Heaters
NESHAP, February 2004). We chose the benefit analysis contained in this
RIA as the basis for estimating the benefits from emission reductions
of these two pollutants since most of the elements in that rule are
similar to those covered here. These elements, which are the stack
height, a number of the controls applied, and the pollutants affected--
PM2.5 and SO2, but not NOX--are
similar to those covered by the Industrial Boiler MACT standard.
We base the portion of the benefits estimate derived from the
NOX emission reductions on the approach and methodology laid
out in EPA's 2005 benefits analysis supporting the regulation of
emissions from the Clean Air Interstate Rule (CAIR) (included in the
Regulatory Impact Analysis for the Clean Air Interstate Rule, March
2005). We chose the CAIR analysis as the basis for estimating the
benefits from emission reductions of this pollutant since most of the
elements in CAIR are similar to those covered here. These elements,
which are the stack height, a number of the controls applied, and the
pollutant affected--in this case, NOX only--are similar to
those covered by CAIR. These three factors lead us to believe that we
might reasonably estimate benefits for this proposed rule using a
benefits transfer approach and values from the Industrial Boilers MACT
analysis for estimating the SO2 and PM2.5
benefits of this rule, and the CAIR analysis for the NOX
benefits of the rule. Specifically, these estimates are based on
application of the benefits scaling approach derived from the benefits
analyses completed for these rulemakings. As mentioned above, the
methodologies are laid out in the Industrial Boilers MACT and CAIR RIA.
A summary of the benefits estimates is in Table 12 below.\1\
---------------------------------------------------------------------------
\1\ We use the SO2 benefits/ton estimate derived from
the Industrial Boilers MACT benefit analysis based on the factors
listed above. We also note that the SO2 benefits/ton
estimate derived from the CAIR benefits analysis is $18,000 in 2010
and $22,000 in 2015, both of which are quite close to the estimate
we use in this analysis. We use the NOX benefits/ton
estimate from the CAIR Boilers MACT benefits analysis (no
NOX reductions take place as a result of the Industrial
Boilers MACT).
Table 12.--Summary of Benefits Estimates For Proposed NSPS
----------------------------------------------------------------------------------------------------------------
Total
Monetized Emission monetized
Pollutant benefits per reductions benefits*
ton emission (tons) (millions of
reduction 2005 dollars)
----------------------------------------------------------------------------------------------------------------
PM2.5........................................................... $88,000 3,221 $283.4
SO2............................................................. 20,000 31,358 627.2
NOX............................................................. 2,200 21,266 46.8
-----------------------------------------------
Grand Total:................................................ .............. .............. $957.4
----------------------------------------------------------------------------------------------------------------
* All estimates are for the analysis year (fifth year after proposal). Emission reductions reflect the
combination of proposed options for both new and reconstructed/modified sources.
The specific estimates of benefits per ton of pollutant reductions
included in this analysis are largely driven by the concentration
response function for premature mortality, which is based on the
American Cancer Society cohort (ACS) (Pope, C.A. III, et al., ``Lung
Cancer, Cardiopulmonary Mortality, and Long-Term Exposure to Fine
Particulate Air Pollution,'' JAMA, 2002). Since the publication of
CAIR, the EPA's Office of Air and Radiation has adopted a different
format for its benefits analysis in which characterization of the
uncertainty in the concentration response function is integrated into
the main benefits analysis. The PM NAAQS analysis provides an
indication of the sensitivity of our results to the use of alternative
concentration response functions, including those derived from the
recently completed expert elicitation study. Specifically, compared to
the final PM NAAQS estimate of the mean mortality from the ACS cohort,
the expert-based premature mortality incidence ranged from 50 percent
of the mean ACS estimate to more than five times the size of the ACS
mean estimate. The Agency is currently updating the estimates used here
to calculate the benefits of the proposed NSPS and intends to consider
using these updated benefits estimates as part of an approach similar
to that used in the PM NAAQS RIA in the benefits analyses for the final
NSPS.
With the annualized costs of this rulemaking estimated at $54
million (2005$) in the fifth year after proposal and with estimated
benefits of $957 million (2005$) for that same year, EPA believes that
the benefits are likely to exceed the costs by a significant margin
even when taking into account the uncertainties in the cost and benefit
estimates. For more information, please refer to the RIA for this
proposed rule that is available in the docket.
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the
[[Page 27201]]
economy of $100 million or more. Accordingly, EPA submitted this action
to the Office of Management and Budget (OMB) for review under Executive
Order 12866 and any changes made in response to OMB recommendations
have been documented in the docket for this action.
In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
Regulatory Impact Analysis (RIA) for the Proposed Petroleum Refinery
NSPS, EPA-452/R-07-006. A copy of the analysis is available in the
docket for this action and the analysis is briefly summarized here. The
monetized benefits of this action are estimated at $957 million (2005
dollars), and the annualized costs of this action are estimated at $54
million (2005 dollars). We also estimated the economic impacts, small
business impacts, and energy impacts associated with this action. These
analyses are included in the RIA and are summarized elsewhere in this
preamble.
B. Paperwork Reduction Act
The proposed amendments to the existing standards of performance
for petroleum refineries would add a monitoring exemption for fuel gas
streams combusted in a fuel gas combustion device that are inherently
low in sulfur content. The exemption would apply to fuel gas streams
that meet specified criteria or that the owner or operator demonstrates
are low sulfur according to the rule requirements. The owner or
operator would submit a written application for the exemption
containing information needed to document the low sulfur content. The
application is not a mandatory requirement and the incremental
reduction in monitoring burden that would occur as a result of the
exemption would not be significant compared to the baseline burden
estimates for the existing rule. Therefore, we have not revised the
information collection request (ICR) for the existing rule. The OMB has
previously approved the information collection requirements in the
existing rule (40 CFR part 60, subpart J) under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501, et seq. and has assigned OMB
control number 2060-0022, EPA ICR number 1054.07.
A copy of the OMB-approved ICR for the Standards of Performance for
Petroleum Refineries may be obtained from Susan Auby, Collection
Strategies Division, Environmental Protection Agency (2822T), 1200
Pennsylvania Ave., NW., Washington, DC 20460, by e-mail at
[email protected], or by calling (292) 566-1672.
The information collection requirements in the proposed standards
of performance for petroleum refineries (40 CFR part 60, subpart Ja)
have been submitted for approval to OMB under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. The ICR document prepared by EPA has been
assigned EPA ICR number 2263.01.
The proposed standards of performance for petroleum refineries
include work practice requirements for delayed coking reactor vessel
depressuring and written plans to minimize emissions during startups,
shutdowns, and malfunctions. Plants also would be required to analyze
the cause of any exceedance that releases more than 500 pounds per day
of SO2 above an allowable limit. EPA is co-proposing work
practice standards that would include the requirement for delayed
coking reactor vessel depressuring but exclude the requirements for
written plans and root-cause analyses for SO2 emissions
discharges exceeding allowable limits by at least 500 pounds per day.
The proposed standards also include testing, monitoring, recordkeeping,
and reporting provisions. Monitoring requirements may include control
device operating parameters, bag leak detection systems, or CEMS,
depending on the type of process, pollutant, and control device.
Exemptions are also proposed for small emitters. These requirements are
based on recordkeeping and reporting requirements in the NSPS General
Provisions in 40 CFR part 60, subpart A, and on specific requirements
in subpart J or subpart Ja which are mandatory for all operators
subject to new source performance standards. These recordkeeping and
reporting requirements are specifically authorized by section 114 of
the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant to
the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to EPA policies set
forth in 40 CFR part 2, subpart B.
The annual burden for this information collection averaged over the
first 3 years of this ICR is estimated to total 6,084 labor-hours per
year at a cost of $526,241 per year. The annualized capital costs are
estimated at $2,736,000 per year and operation and maintenance costs
are estimated at $1,627,200 per year. We note that the capital costs as
well as the operation and maintenance costs are for the continuous
monitors; these costs are also included in the cost impacts presented
in section VIII.A of this preamble. Therefore, the burden costs
associated with the continuous monitors presented in the ICR are not
additional costs incurred by affected sources subject to proposed
subpart Ja.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this rule, which
includes this ICR, under Docket ID number EPA-HQ-OAR-2007-0011. Submit
any comments related to the ICR for this proposed rule to EPA and OMB.
See Addresses section at the beginning of this document for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after May 14, 2007, a comment to OMB is best
assured of having its full effect if OMB receives it by June 13, 2007.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any
[[Page 27202]]
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impact of today's proposed action on
small entities, small entity is defined as: (1) A small business whose
parent company has no more than 1,500 employees and no more than
125,000 barrels per day total operable atmospheric crude oil
distillation capacity, depending on the size definition for the
affected NAICS code (as defined by Small Business Administration (SBA)
size standards); (2) a small governmental jurisdiction that is a
government of a city, county, town, school district, or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
After considering the economic impact of today's proposed action on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. Of the 58
entities that we expect could be affected by today's proposed action,
24 of these (or 41 percent) are classified as small according to the
SBA small business size standard listed previously. Of these 24
affected entities, one small entity is expected to incur an annualized
compliance cost of more than 1.0 percent to comply with today's
proposed action. In addition, the impact on gasoline prices nationwide
is expected to be less than 0.02 percent of the baseline gasoline
price, and this represents less than a 1 cent increase in the price per
gallon of gasoline. Also, the output of gasoline in the U.S. is
expected to fall by less than 0.004 percent, or less than 6 million
gallons per year in the U.S. For more information, please refer to the
economic impact analysis that is in the public docket for this
rulemaking.
Although this proposed action would not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of this proposed action on small entities by
incorporating specific standards for small sulfur recovery plants and
streamlining procedures for exempting inherently low-sulfur fuel gases
from continuous monitoring. We continue to be interested in the
potential impacts of this proposed action on small entities and welcome
comments on issues related to such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures by State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
EPA has determined that this proposed action does not contain a
Federal mandate that may result in expenditures of $100 million or more
for State, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. As discussed earlier in this preamble,
the estimated expenditures for the private sector in the fifth year
after proposal are $54 million. Thus, this proposed action is not
subject to the requirements of section 202 and 205 of the UMRA. In
addition, EPA has determined that this proposed action contains no
regulatory requirements that might significantly or uniquely affect
small governments. This proposed action contains no requirements that
apply to such governments, imposes no obligations upon them, and would
not result in expenditures by them of $100 million or more in any 1
year or any disproportionate impacts on them. Therefore, this proposed
action is not subject to the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132 (64 FR 43255, August 10, 1999) requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications.'' ``Policies that have
federalism implications'' is defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
This proposed action does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. None of the affected facilities
are owned or operated by State governments. Thus, Executive Order 13132
does not apply to this proposed action.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed action
from State and local officials.
F. Executive Order 13175: Consultation and Coordination with Indian
Tribal Governments
Executive Order 13175, entitled (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This proposed action does not
have tribal implications, as specified in Executive Order 13175. It
will not have substantial direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in Executive Order 13175.
The proposed rules impose requirements on owners and operators of
specified
[[Page 27203]]
industrial facilities and not tribal governments. Thus, Executive Order
13175 does not apply to this proposed action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
EPA interprets Executive Order 13045 as applying to those
regulatory actions that concern health or safety risks, such that the
analysis required under section 5-501 of the Order has the potential to
influence the regulation. This proposed action is not subject to
Executive Order 13045 because it is based on technology performance and
not on health or safety risks.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR
28355, May 22, 2001) because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy. We
prepared an analysis of the impacts on energy markets as part of our
economic impact analysis for today's proposed action. Our analysis
shows that there is a reduction in gasoline output of less than 6
million gallons per year, or less than 400 barrels of gasoline
production per day, in the fifth year after proposal of this proposed
action. In addition, our analysis shows that there is an increase in
gasoline prices of less than 0.02 percent in the fifth year after
proposal of this proposed action. Given this degree of increase in
domestic gasoline prices, no significant increase in our dependence on
foreign energy supplies should take place. Finally, today's proposed
action will have no adverse effect on crude oil supply, coal
production, electricity production, and energy distribution. Based on
the findings from the analysis of impacts on energy markets, we
conclude that today's proposed action is not a ``significant energy
action'' as defined in Executive Order 13211. For more information on
this analysis, please refer to the economic impact analysis for this
rulemaking. This analysis is found in the public docket.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Public Law No. 104-113, Section 12(d), 15 U.S.C.
272 note) directs EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. The VCS are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
VCS bodies. The NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency does not use available and applicable VCS.
Today's proposed rule (subpart Ja) involves technical standards.
The EPA cites the following standards: EPA Methods 1, 2, 3, 3A, 3B, 5,
6, 6A, 6B, 6C, 7, 7A, 7C, 7D, 7E, 10, 10A, 11, 15, 15A, and 16 of 40
CFR part 60, appendix A; Performance Specifications 2, 3, 4, 5, 7, and
11 in 40 CFR part 60, appendix B; and Appendix F to 40 CFR Part 60.
This rule also cites ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' for its manual methods of measuring the content of the
exhaust gas. This part of ASME PTC 19.10-1981 is an acceptable
alternative to EPA Methods 3B, 6, 6A, 6B, 7, 7C, and 15A.
Consistent with the NTTAA, EPA conducted searches to identify VCS
in addition to these methods. No applicable VCS were identified for EPA
Methods 7D and 11; EPA Performance Specifications 3, 4, 5, and 7; and
Appendix F to 40 CFR part 60. The search and review results are in the
docket for this rule.
The search for emissions measurement procedures identified 22 other
VCS. The EPA determined that these 22 standards identified for
measuring emissions of the targeted pollutants or surrogates subject to
emission standards in this rule were impractical alternatives to EPA
test methods for the purposes of this rule. Therefore, EPA does not
intend to adopt these standards for this purpose. The reasons for the
determinations for the 22 standards are discussed in the memorandum
submitted to the docket to this rule.
Both the proposed amendments for subpart J and the proposed rule
(subpart Ja) cite the Gas Processor's Association Method 2377-86,
``Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using
Length of Stain Tubes'' (incorporated by reference-see 40 CFR 60.17) as
an acceptable method for determining the H2S content of low sulfur
streams. The amendments to subpart J do not include any other technical
standards.
Consistent with the NTTAA, EPA conducted searches to identify VCS
in addition to Gas Processor's Association Method 2377-86. No
applicable voluntary consensus standards were identified for Gas
Processor's Association Method 2377-86. The search and review results
are in the docket for this rule.
Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may
apply to EPA for permission to use alternative test methods or
alternative monitoring requirements in place of any required testing
methods, performance specifications, or procedures in the proposed rule
and amendments.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States. EPA has determined that the proposed
amendments would not have disproportionately high and adverse human
health or environmental effects on minority or low-income populations
because they do not affect the level of protection provided to human
health or the environment. The proposed amendments are clarifications
which do not relax the control measures on sources regulated by the
rule and therefore will not cause emissions increases from these
sources. EPA has determined that the proposed standards would not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because they would
increase the level of
[[Page 27204]]
environmental protection for all affected populations without having
any disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. These proposed standards would reduce emissions of criteria
pollutants from all new, reconstructed, or modified sources at
petroleum refineries, decreasing the amount of such emissions to which
all affected populations are exposed.
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: April 30, 2007.
Stephen L. Johnson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as follows:
PART 60--[AMENDED]
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
2. Section 60.17 is amended by:
a. Revising paragraph (h)(4),
b. Revising the last sentence of paragraph (m) introductory text,
and
c. Revising paragraph (m)(1) to read as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(h) * * *
(4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], IBR approved for Tables 1 and 3 of
subpart EEEE, Tables 2 and 4 of subpart FFFF, Sec. 60.106(e)(2) of
subpart J, Sec. Sec. 60.104a(d)(3), (d)(6), (g)(3), (g)(4), (g)(6),
(i)(3), (i)(4), (j)(3), (j)(4), (j)(4)(iii), and 60.105a(d)(4), (e)(4),
(f)(2), and (f)(4), and 60.106a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii),
(a)(2)(iv), (a)(3)(ii), (a)(3)(iv), and (a)(4)(iii), and
60.107a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii), (c)(2), and (c)(4) of
subpart Ja, and Sec. Sec. 60.4415(a)(2) and 60.4415(a)(3) of subpart
KKKK of this part.
* * * * *
(m) * * * You may inspect a copy at EPA's Air and Radiation Docket
and Information Center, Room 3334, 1301 Constitution Ave., NW.,
Washington, DC 20460.
(1) Gas Processors Association Method 2377-86, Test for Hydrogen
Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,
IBR approved for Sec. Sec. 60.105(b)(1)(iv), 60.107a(b)(1)(iv),
60.334(h)(1), 60.4360, and 60.4415(a)(1)(ii).
* * * * *
Subpart J--[Amended]
3. Section 60.100 is amended by revising the first sentence in
paragraph (a) and revising paragraphs (b) through (d) to read as
follows:
Sec. 60.100 Applicability, designation of affected facility, and
reconstruction.
(a) The provisions of this subpart are applicable to the following
affected facilities in petroleum refineries: fluid catalytic cracking
unit catalyst regenerators, fuel gas combustion devices, and all Claus
sulfur recovery plants except Claus plants with a design capacity of 20
long tons per day (LTD) or less. * * *
(b) Any fluid catalytic cracking unit catalyst regenerator or fuel
gas combustion device under paragraph (a) of this section which
commences construction, reconstruction, or modification after June 11,
1973, and on or before May 14, 2007, or any Claus sulfur recovery plant
under paragraph (a) of this section which commences construction,
reconstruction, or modification after October 4, 1976, and on or before
May 14, 2007, is subject to the requirements of this subpart except as
provided under paragraphs (c) and (d) of this section.
(c) Any fluid catalytic cracking unit catalyst regenerator under
paragraph (b) of this section which commences construction,
reconstruction, or modification on or before January 17, 1984, is
exempted from Sec. 60.104(b).
(d) Any fluid catalytic cracking unit in which a contact material
reacts with petroleum derivatives to improve feedstock quality and in
which the contact material is regenerated by burning off coke and/or
other deposits and that commences construction, reconstruction, or
modification on or before January 17, 1984, is exempt from this subpart
* * * * *
4. Section 60.101 is amended by revising paragraphs (d), (i), (j),
and (k) to read as follows:
Sec. 60.101 Definitions.
* * * * *
(d) Fuel gas means any gas which is generated at a petroleum
refinery and which is combusted. Fuel gas also includes natural gas
when the natural gas is combined and combusted in any proportion with a
gas generated at a refinery. Fuel gas does not include gases generated
by catalytic cracking unit catalyst regenerators and fluid coking
burners. Fuel gas does not include vapors that are collected and
combusted to comply with the wastewater provisions in Sec. 60.692, 40
CFR 61.343 through 61.348, or 40 CFR 63.647, or the marine tank vessel
loading provisions in 40 CFR 63.562 or 40 CFR 63.651.
* * * * *
(i) Claus sulfur recovery plant means a series of process units
which recover sulfur from hydrogen sulfide (H2S) by a vapor-
phase catalytic reaction of sulfur dioxide and H2S. The
Claus sulfur recovery plant includes the reactor furnace and waste heat
boiler, catalytic reactors, sulfur pits, and, if present, oxidation or
reduction control systems. One Claus sulfur recovery plant may consist
of multiple trains.
(j) Oxidation control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to sulfur dioxide and recycling the sulfur dioxide to the
reactor furnace or the first-stage catalytic reactor of the Claus
sulfur recovery plant.
(k) Reduction control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to H2S and recycling the H2S to the
reactor furnace or the first-stage catalytic reactor of the Claus
sulfur recovery plant.
* * * * *
5. Section 60.102 is amended by revising paragraph (b) to read as
follows:
Sec. 60.102 Standard for particulate matter.
* * * * *
(b) Where the gases discharged by the fluid catalytic cracking unit
catalyst regenerator pass through an incinerator or waste heat boiler
in which auxiliary or supplemental liquid or solid fossil fuel is
burned, particulate matter in excess of that permitted by paragraph
(a)(1) of this section may be emitted to the atmosphere, except that
the incremental rate of particulate matter emissions shall not exceed
43 grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units
(Btu)) of heat input attributable to such liquid or solid fossil fuel.
6. Section 60.104 is amended by revising paragraphs (b)(1) and
(b)(2) to read as follows:
Sec. 60.104 Standards for sulfur oxides.
* * * * *
(b) * * *
(1) With an add-on control device, reduce SO2 emissions
to the atmosphere by 90 percent or maintain SO2
[[Page 27205]]
emissions to the atmosphere less than or equal to 50 ppm by volume
(ppmv), whichever is less stringent; or
(2) Without the use of an add-on control device to reduce
SO2 emissions, maintain sulfur oxides emissions calculated
as SO2 to the atmosphere less than or equal to 9.8 kg/Mg (20
lb/ton) coke burn-off; or
* * * * *
7. Section 60.105 is amended by:
a. Revising the first sentence of paragraph (a)(3) introductory
text;
b. Revising paragraph (a)(3)(iv);
c. Revising paragraph (a)(4) introductory text;
d. Adding paragraph (a)(4)(iv);
e. Revising paragraph (a)(8) introductory text;
f. Revising paragraph (a)(8)(i); and
g. Adding paragraph (b) to read as follows:
Sec. 60.105 Monitoring of emissions and operations.
(a) * * *
(3) For fuel gas combustion devices subject to Sec. 60.104(a)(1),
either an instrument for continuously monitoring and recording the
concentration by volume (dry basis, 0 percent excess air) of
SO2 emissions into the atmosphere or monitoring as provided
in paragraph (a)(4) of this section). * * *
* * * * *
(iv) Fuel gas combustion devices having a common source of fuel gas
may be monitored at only one location (i.e., after one of the
combustion devices), if monitoring at this location accurately
represents the SO2 emissions into the atmosphere from each
of the combustion devices.
(4) Instead of the SO2 monitor in paragraph (a)(3) of
this section for fuel gas combustion devices subject to Sec.
60.104(a)(1), an instrument for continuously monitoring and recording
the concentration (dry basis) of H2S in fuel gases before
being burned in any fuel gas combustion device.
* * * * *
(iv) The owner or operator of a fuel gas combustion device is not
required to comply with paragraph (a)(3) or (4) of this section for
streams that are exempt under Sec. 60.104(a)(1) and fuel gas streams
combusted in a fuel gas combustion device that are inherently low in
sulfur content. Fuel gas streams meeting one of the requirements in
paragraphs (a)(4)(iv)(A) through (D) of this section will be considered
inherently low in sulfur content. If the composition of a fuel gas
stream changes such that it is no longer exempt under Sec.
60.104(a)(1) or it no longer meets one of the requirements in
paragraphs (a)(4)(iv)(A) through (D) of this section, the owner or
operator must begin continuous monitoring under paragraph (a)(3) or (4)
of this section within 15 days of the change.
(A) Pilot gas for heaters and flares.
(B) Gas streams that meet commercial-grade product specifications
and have a sulfur content of 30 ppmv or less.
(C) Fuel gas streams produced in process units that are intolerant
to sulfur contamination, such as fuel gas streams produced in the
hydrogen plant, the catalytic reforming unit, and the isomerization
unit.
(D) Other streams that an owner or operator demonstrates are low-
sulfur according to the procedures in paragraph (b) of this section.
* * * * *
(8) An instrument for continuously monitoring and recording
concentrations of SO2 in the gases at both the inlet and
outlet of the SO2 control device from any fluid catalytic
cracking unit catalyst regenerator for which the owner or operator
seeks to comply specifically with the 90 percent reduction option under
Sec. 60.104(b)(1).
(i) The span value of the inlet monitor shall be set at 125 percent
of the maximum estimated hourly potential SO2 emission
concentration entering the control device, and the span value of the
outlet monitor shall be set at 50 percent of the maximum estimated
hourly potential SO2 emission concentration entering the
control device.
* * * * *
(b) An owner or operator may demonstrate that a gas stream
combusted in a fuel gas combustion device subject to Sec. 60.104(a)(1)
that is not specifically exempted in Sec. 60.105(a)(4)(iv) is
inherently low in sulfur. A gas stream that is determined to be low-
sulfur is exempt from the monitoring requirements in paragraphs (a)(3)
and (4) of this section until there are changes in operating conditions
or stream composition.
(1) The owner or operator shall submit to the Administrator a
written application for an exemption from monitoring. The application
must contain the following information:
(i) A description of the gas stream/system to be considered,
including submission of a portion of the appropriate piping diagrams
indicating the boundaries of the gas stream/system, and the affected
fuel gas combustion device(s) to be considered;
(ii) A statement that there are no crossover or entry points for
sour gas (high H2S content) to be introduced into the gas
stream/system (this should be shown in the piping diagrams);
(iii) An explanation of the conditions that ensure low amounts of
sulfur in the gas stream (i.e., control equipment or product
specifications) at all times;
(iv) The supporting test results from sampling the requested gas
stream/system demonstrating that the sulfur content is less than 5
ppmv. Minimum sampling data must consist of 2 weeks of daily monitoring
(14 grab samples) for frequently operated gas streams/systems; for
infrequently operated gas streams/systems, seven grab samples must be
collected unless other additional information would support reduced
sampling. The owner or operator shall use detector tubes (``length-of-
stain tube'' type measurement) following the Gas Processor
Association's Test for Hydrogen Sulfide and Carbon Dioxide in Natural
Gas Using Length of Stain Tubes, 1986 revision with ranges 0-10/0-100
ppm (N = 10/1) to test the applicant stream (incorporated by
reference--see Sec. 60.17).
(v) A description of how the 2 weeks (or seven samples for
infrequently operated gas streams/systems) of monitoring results
compares to the typical range of H2S concentration (fuel
quality) expected for the gas stream/system going to the affected fuel
gas combustion device (e.g., the 2 weeks of daily detector tube results
for a frequently operated loading rack included the entire range of
products loaded out, and, therefore, should be representative of
typical operating conditions affecting H2S content in the
gas stream going to the loading rack flare).
(2) Once EPA receives a complete application, the Administrator
will determine whether an exemption is granted. The owner or operator
shall continue to comply with the monitoring requirements in paragraph
(a)(3) or paragraph (a)(4) of this section until an exemption is
granted.
(3) Once an exemption from continuous monitoring is granted, no
further action is required unless refinery operating conditions change
in such a way that affects the exempt gas stream/system (e.g., the
stream composition changes). If such a change occurs, the owner or
operator will follow the procedures in paragraph (b)(2)(i), (b)(2)(ii),
or (b)(2)(iii) of this section.
(i) If the operation change results in a sulfur content that is
still within the range of concentrations included in the original
application, the owner or operator shall conduct an H2S test
on a grab sample and record the results as proof that the concentration
is still within the range.
[[Page 27206]]
(ii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application, the owner or operator may submit a new application
following the procedures of paragraph (b)(1) of this section within 60
days (or within 30 days after the seventh grab sample is tested for
infrequently operated process units).
(iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit a new
application, the owner or operator must begin continuous monitoring as
specified in paragraphs (a)(3) or (a)(4) of this section within 60 days
of the operation change.
* * * * *
8. Section 60.106 is amended by revising paragraph (b)(3)
introductory text and revising the first sentence of paragraph (e)(2)
to read as follows:
Sec. 60.106 Test methods and procedures.
* * * * *
(b) * * *
(3) The coke burn-off rate (Rc) shall be computed for
each run using the following equation:
Rc = K1Qr (%CO2 + %CO) +
K2Qa-K3Qr(%CO/2 +
%CO2 + %O2) + K3Qoxy
(%Ooxy)
Where:
Rc = Coke burn-off rate, kilograms per hour (kg/hr) (lb/
hr).
Qr = Volumetric flow rate of exhaust gas from fluid
catalytic cracking unit regenerator before entering the emission
control system, dscm/min (dscf/min).
Qa = Volumetric flow rate of air to fluid catalytic
cracking unit regenerator, as determined from the fluid catalytic
cracking unit control room instrumentation, dscm/min (dscf/min).
Qoxy = Volumetric flow rate of O2 enriched air
to fluid Catalytic cracking unit regenerator, as determined from the
fluid catalytic cracking unit control room instrumentation, dscm/min
(dscf/min).
%CO2 = Carbon dioxide concentration in fluid catalytic
cracking unit regenerator exhaust, percent by volume (dry basis).
%CO = CO concentration in FCCU regenerator exhaust, percent by
volume (dry basis).
%O2 = O2 concentration in fluid catalytic
cracking unit regenerator exhaust, percent by volume (dry basis).
%Ooxy = O2 concentration in O2
enriched air stream inlet to the fluid catalytic cracking unit
regenerator, percent by volume (dry basis).
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)].
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm-%) [0.1303 (lb-min)/(hr-dscf-%)].
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
* * * * *
(e) * * *
(2) Where emissions are monitored by Sec. 60.105(a)(3), compliance
with Sec. 60.104(a)(1) shall be determined using Method 6 or 6C and
Method 3 or 3A. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 6. * * *
* * * * *
9. Section 60.107 is amended by:
a. Revising the first sentence of paragraph (c)(1)(i);
b. Redesignating paragraphs (e) and (f) as (f) and (g); and
c. Adding paragraph (e) to read as follows:
Sec. 60.107 Reporting and recordkeeping requirements.
* * * * *
(c) * * *
(1) * * *
(i) The average percent reduction and average concentration of
sulfur dioxide on a dry, O2-free basis in the gases
discharged to the atmosphere from any fluid cracking unit catalyst
regenerator for which the owner or operator seeks to comply with Sec.
60.104(b)(1) is below 90 percent and above 50 ppmv, as measured by the
continuous monitoring system prescribed under Sec. 60.105(a)(8), or
above 50 ppmv, as measured by the outlet continuous monitoring system
prescribed under Sec. 60.105(a)(9). * * *
* * * * *
(e) For each stream combusted in a fuel gas combustion device
subject to Sec. 60.104(a)(1), if an owner or operator determines that
one of the exemptions listed in Sec. 60.105(a)(4)(iv) applies to that
stream, the owner or operator shall maintain records of the specific
exemption chosen for each stream. If the owner or operator applies for
the exemption described in Sec. 60.105(a)(4)(iv)(D), the owner or
operator must keep a copy of the application as well as the letter from
the Administrator granting approval of the application.
* * * * *
10. Section 60.108 is amended by revising the last sentence of
paragraph (e) to read as follows:
Sec. 60.108 Performance test and compliance provisions.
* * * * *
(e) * * * The owner or operator shall furnish the Administrator
with a written notification of the change in the semiannual report
required by Sec. 60.107(f).
11. Section 60.109 is amended by redesignating paragraph (b)(2) as
(b)(3) and adding paragraph (b)(2) to read as follows:
Sec. 60.109 Delegation of authority.
* * * * *
(b) * * *
(1) * * *
(2) Section 60.105(b), and
* * * * *
12. Part 60 is amended by adding subpart Ja to read as follows:
Subpart Ja--Standards of Performance for Petroleum Refineries for Which
Construction, Reconstruction, or Modification Commenced After May 14,
2007
Sec.
60.100a Applicability, designation of affected facility, and
reconstruction.
60.101a Definitions.
60.102a Emissions limitations.
60.103a Work practice standards.
60.104a Performance tests.
60.105a Monitoring of emissions and operations for fluid catalytic
cracking units (FCCU) and fluid coking units.
60.106a Monitoring of emissions and operations for sulfur recovery
plants.
60.107a Monitoring of emissions and operations for process heaters
and other fuel gas combustion devices.
60.108a Recordkeeping and reporting requirements.
60.109a Delegation of authority.
Subpart Ja--Standards of Performance for Petroleum Refineries for
Which Construction, Reconstruction, or Modification Commenced After
May 14, 2007
Sec. 60.100a Applicability, designation of affected facility, and
reconstruction.
(a) The provisions of this subpart apply to the following affected
facilities in petroleum refineries: Fluid catalytic cracking units
(FCCU), fluid coking units, delayed coking units, process heaters,
other fuel gas combustion devices, fuel gas producing units, and sulfur
recovery plants. The sulfur recovery plant need not be physically
located within the boundaries of a petroleum refinery to be an affected
facility, provided it processes gases produced within a petroleum
refinery.
(b) The provisions of this subpart apply only to affected
facilities under paragraph (a) of this section which commence
construction, modification, or reconstruction after May 14, 2007.
(c) For purposes of this subpart, under Sec. 60.15, the ``fixed
capital cost of the new components'' includes the fixed capital cost of
all depreciable components which are or will be replaced pursuant to
all continuous
[[Page 27207]]
programs of component replacement which are commenced within any 2-year
period following May 14, 2007. For purposes of this paragraph,
``commenced'' means that an owner or operator has undertaken a
continuous program of component replacement or that an owner or
operator has entered into a contractual obligation to undertake and
complete, within a reasonable time, a continuous program of component
replacement.
Sec. 60.101a Definitions.
Terms used in this subpart are defined in the Clean Air Act, in
Sec. 60.2, and in this section.
Coke burn-off means the coke removed from the surface of the FCCU
catalyst by combustion in the catalyst regenerator. The rate of coke
burn-off is calculated by the formula specified in Sec. 60.104a.
Contact material means any substance formulated to remove metals,
sulfur, nitrogen, or any other contaminant from petroleum derivatives.
Delayed coking unit means one or more coking units in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system
reactors.
Flexicoking unit means one or more coking units in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced then gasified to produce a synthetic fuel
gas.
Fluid catalytic cracking unit means one or more units in which
petroleum derivatives are continuously charged and hydrocarbon
molecules in the presence of a catalyst suspended in a fluidized bed
are fractured into smaller molecules, or react with a contact material
suspended in a fluidized bed to improve feedstock quality for
additional processing and the catalyst or contact material is
continuously regenerated by burning off coke and other deposits. The
unit includes the riser, reactor, regenerator, air blowers, spent
catalyst or contact material stripper, catalyst or contact material
recovery equipment, and regenerator equipment for controlling air
pollutant emissions and for heat recovery.
Fluid coking unit means one or more coking units in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system and
in which the fluid coking burner exhaust gas is continuously released
to the atmosphere. The fluid coking unit includes equipment for
controlling air pollutant emissions and for heat recovery on the fluid
coking burner exhaust vent. Flexicoking units that use gasifiers to
generate a synthetic fuel gas for use in other processes and that do
not exhaust to the atmosphere are not considered fluid coking units
under this subpart.
Fresh feed means any petroleum derivative feedstock stream charged
directly into the riser or reactor of a FCCU except for petroleum
derivatives recycled within the FCCU, fractionator, or gas recovery
unit.
Fuel gas means any gas which is generated at a petroleum refinery
and which is combusted. Fuel gas includes natural gas when the natural
gas is combined and combusted in any proportion with a gas generated at
a refinery. Fuel gas does not include gases generated by catalytic
cracking unit catalyst regenerators and fluid coking burners, but does
include gases from flexicoking unit gasifiers. Fuel gas does not
include vapors that are collected and combusted to comply with the
wastewater provisions in Sec. 60.692, 40 CFR 61.343 through 61.348, 40
CFR 63.647, or the marine tank vessel loading provisions in 40 CFR
63.562 or 40 CFR 63.651.
Fuel gas producing unit means any refinery process unit that
produces fuel gas as a routine part of normal operations. A fuel gas
producing unit includes, but is not limited to, the atmospheric
distillation unit, the FCCU, the catalytic hydrocracking unit, all
types of coking units, and the catalytic reforming unit.
Other fuel gas combustion device means any equipment, such as
boilers and flares, used to combust fuel gas, except process heaters
and facilities in which gases are combusted to produce sulfur or
sulfuric acid.
Oxidation control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to sulfur dioxide (SO2) and recycling the
SO2 to the reactor furnace or the first-stage catalytic
reactor of the Claus sulfur recovery plant.
Petroleum means the crude oil removed from the earth and the oils
derived from tar sands, shale, and coal.
Petroleum refinery means any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, asphalt (bitumen) or other products through distillation of
petroleum or through redistillation, cracking, or reforming of
unfinished petroleum derivatives.
Process gas means any gas generated by a petroleum refinery process
unit, except fuel gas and process upset gas as defined in this section.
Process heater means an enclosed combustion device used to transfer
heat indirectly to process stream materials (liquids, gases, or solids)
or to a heat transfer material for use in a process unit instead of
steam.
Process upset gas means any gas generated by a petroleum refinery
process unit as a result of upset or malfunction.
Reduced sulfur compounds means hydrogen sulfide (H2S),
carbonyl sulfide, and carbon disulfide.
Reduction control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to H2S and recycling the H2S to the
reactor furnace or the first-stage catalytic reactor of the Claus
sulfur recovery plant.
Refinery process unit means any segment of the petroleum refinery
in which a specific processing operation is conducted.
Sulfur recovery plant means all process units which recover sulfur
from H2S and/or SO2 at a petroleum refinery. The
sulfur recovery plant also includes vessels, tanks, or pits used to
store the recovered sulfur product. For example, a Claus sulfur
recovery plant includes: reactor furnace and waste heat boiler,
catalytic reactors, sulfur pits, and, if present, oxidation or
reduction control systems, or incinerator, thermal oxidizer, or similar
combustion device.
Sec. 60.102a Emissions limitations.
(a) Each owner or operator that is subject to the requirements of
this subpart shall comply with the emissions limitations in paragraphs
(b) through (h) of this section on and after the date on which the
initial performance test, required by Sec. 60.8, is completed, but not
later than 60 days after achieving the maximum production rate at which
the affected facility will be operated, or 180 days after initial
startup, whichever comes first.
Option 1 for Paragraph (b):
(b) An owner or operator subject to the provisions of this subpart
shall not discharge or cause the discharge into the atmosphere from any
FCCU or fluid coking unit:
(1) Particulate matter (PM) in excess of 0.5 gram per kilogram (g/
kg) coke burn-off (0.5 pound (lb) PM/1,000 lbs coke burn-off) or 0.020
grains per dry standard cubic feet (gr/dscf) corrected to 0 percent
excess air; and
(2) NOX in excess of 80 parts per million by volume
(ppmv), dry basis corrected to 0 percent excess air, on a 7-day rolling
average basis; and
[[Page 27208]]
(3) SO2 in excess of 50 ppmv dry basis corrected to 0
percent excess air, on a 7-day rolling average basis and 25 ppmv, dry
basis corrected to 0 percent excess air, on a 365-day rolling average
basis; and
(4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected
to 0 percent excess air, on an hourly average basis.
Option 2 for Paragraph (b)
(b) Except as provided in paragraph (b)(2) of this section, an
owner or operator subject to the provisions of this subpart shall not
discharge or cause the discharge into the atmosphere from any FCCU or
fluid coking unit:
(1) Particulate Matter (PM) in excess of 0.5 gram per kilogram (g/
kg) coke burn-off (0.5 lb PM/1,000 lbs coke burn-off) or 0.020 grains
per dry standard cubic feet (gr/dscf) corrected to 0 percent excess
air; and
(2) NOX in excess of 80 parts per million by volume
(ppmv), dry basis corrected to 0 percent excess air, on a 7-day rolling
average basis. This emissions limit does not apply to a fluid coking
unit subject to this subpart;
(3) SO2 in excess of 50 ppmv dry basis corrected to 0
percent excess air, on a 7-day rolling average basis and 25 ppmv, dry
basis corrected to 0 percent excess air, on a 365-day rolling average
basis; and
(4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected
to 0 percent excess air, on an hourly average basis.
(c) The owner or operator of a FCCU or fluid coking unit that uses
continuous parameter monitoring systems (CPMS) according to Sec.
60.105a(b)(1) shall comply with the applicable control device parameter
operating limit in paragraph (c)(1) or (c)(2) of this section.
(1) If the FCCU or fluid coking unit is controlled using an
electrostatic precipitator:
(i) The hourly average total power and secondary current to the
control device must not fall below the level established during the
most recent performance test; and
(ii) The exhaust coke burn-off rate must not exceed the level
established during the most recent performance test.
(2) If the FCCU or fluid coking unit is controlled using a wet
scrubber:
(i) The hourly average pressure drop must not fall below the level
established during the most recent performance test; and
(ii) The hourly average liquid-to-gas ratio must not fall below the
level established during the most recent performance test.
(d) The owner or operator of a FCCU or fluid coking unit that is
exempted from the requirement for a CO continuous emissions monitoring
system (CEMS) under Sec. 60.105a(g)(3) shall comply with the parameter
operating limits in paragraph (d)(1) or (d)(2) of this section.
(1) For a FCCU or fluid coking unit with no post-combustion control
device:
(i) The hourly average temperature of the exhaust gases exiting the
FCCU or fluid coking unit must not fall below the level established
during the most recent performance test.
(ii) The hourly average oxygen (O2) concentration of the
exhaust gases exiting the FCCU or fluid coking unit must not fall below
the level established during the most recent performance test.
(2) For a FCCU or fluid coking unit with a post-combustion control
device:
(i) The hourly average temperature of the exhaust gas vent stream
exiting the control device must not fall below the level established
during the most recent performance test.
(ii) The hourly average O2 concentration of the exhaust
gas vent stream exiting the control device must not fall below the
level established during the most recent performance test.
(e) Each owner or operator that is subject to the provisions of
this subpart shall comply with the following emissions limits for each
sulfur recovery plant:
(1) For a sulfur recovery plant with a capacity greater than 20
long tons per day (LTD), the owner or operator shall not discharge or
cause the discharge of any gases into the atmosphere containing a
combined SO2 and reduced sulfur compounds concentration in
excess of 250 ppmv as SO2 (dry basis) at 0 percent excess
air determined hourly on a 12-hour rolling average basis. If the sulfur
recovery plant consists of multiple process trains or release points
the owner or operator shall comply with the 250 ppmv limit for each
process train or release point or comply with a flow rate weighted
average of 250 ppmv for all release points from the sulfur recovery
plant.
(2) For a sulfur recovery plant with a capacity of 20 LTD or less,
the owner or operator shall not discharge or cause the discharge of any
gases into the atmosphere containing combined SO2 and
reduced sulfur compounds mass emissions in excess of 1 percent by
weight of sulfur recovered, measured as the mass ratio of sulfur
emitted (from all release points combined) to sulfur recovered
determined hourly on a 12-hour rolling average basis.
(3) For all sulfur recovery plants, regardless of size, the owner
or operator shall not discharge or cause the discharge of any gases
into the atmosphere containing H2S in excess of 10 ppmv (dry
basis) at 0 percent excess air determined hourly on a 12-hour rolling
average basis.
(f) The owner or operator of a sulfur recovery plant subject to the
H2S emissions limit in paragraph (e)(3) of this section and
that uses CPMS pursuant to Sec. 60.106a(a)(4) shall comply with the
following operating limits:
(1) The hourly average temperature of the exhaust gases exiting the
sulfur recovery plant must not fall below the level established during
the most recent performance test.
(2) The hourly average O2 concentration of the exhaust
gases exiting the sulfur recovery plant must not fall below the level
established during the most recent performance test.
(g) Each owner or operator subject to the provisions of this
subpart shall comply with the emission limitations in paragraphs (g)(1)
through (3) for each process heater and other fuel gas combustion
device, except as provided in paragraph (h) and (i) of this section.
(1) SO2 in excess of 20 ppmv (dry basis, corrected to 0
percent excess air) on a 3-hour rolling average basis; and
(2) SO2 in excess of 8 ppmv (dry basis, corrected to 0
percent excess air), determined daily on a 365 successive day rolling
average basis; and
(3) For process heaters with a rated capacity of greater than 20
million British thermal units per hour, NOX in excess of 80
ppmv (dry basis, corrected to 0 percent excess air) on a 24-hour
rolling average basis.
(h) For process heaters that combust only fuel gas and for other
fuel gas combustion devices, the following emission limitations may be
used instead of the SO2 emission limits in paragraph (g)(1)
and (2) of this section:
(1) For process heaters and other fuel gas combustion devices that
do not combust fuel gas generated from a coking unit:
(i) H2S in excess of 160 ppmv determined hourly on a 3-
hour rolling average basis; and
(ii) H2S in excess of 60 ppmv determined daily on a 365
successive calendar day rolling average basis.
(2) For process heaters and other fuel gas combustion devices that
combust fuel gas generated from a coking unit or fuel gas that is mixed
with fuel gas generated from a coking unit:
(i) Total reduced sulfur (TRS) in excess of 160 ppmv determined
hourly on a 3-hour rolling average basis; and
(ii) TRS in excess of 60 ppmv determined daily on a 365 successive
calendar day rolling average basis.
[[Page 27209]]
(i) The combustion in a flare of process upset gases or fuel gas
that is released to the flare as a result of relief valve leakage or
other emergency malfunctions is exempt from paragraphs (g) and (h) of
this section.
Option 1 for Sec. 60.103a:
Sec. 60.103a Work practice standards.
(a) Each owner or operator subject to the provisions of this
subpart shall not routinely release fuel gas to a flare from any fuel
gas producing unit. The combustion in a flare of process upset gases or
fuel that that is released to the flare as a result of relief valve
leakage or other emergency malfunctions is exempt from this paragraph.
(b) The owner or operator shall develop a written startup,
shutdown, and malfunction plan that describes, in detail, procedures
for operating and maintaining each affected facility during periods of
startup, shutdown, and malfunction; and a program of corrective action
for malfunctioning process, air pollution control, and monitoring
equipment used to comply with the requirements of this subpart. The
owner or operator may use the affected source's standard operating
procedures (SOP) manual, or an Occupational Safety and Health
Administration (OSHA) or other plan, provided the alternative plans
meet all the requirements of this section and are made available for
inspection or submitted when requested by the Administrator.
(1) The written plan must cover fluid catalytic cracking units,
fluid coking units, sulfur recovery plants (including tail gas
treatment system), amine treatment system, and fuel process heaters and
other gas combustion devices. The written plan must include 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 any 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.
(2) When actions taken by the owner or operator during a startup or
shutdown (and the startup or shutdown causes the source to exceed any
applicable emission limitation in the relevant emission standards), or
malfunction (including actions taken to correct a malfunction) are
consistent with the procedures specified in the startup, shutdown, and
malfunction plan, the owner or operator must keep records for that
event which demonstrate that the procedures specified in the plan were
followed. These records may take the form of a ``checklist,'' or other
effective form of recordkeeping that confirms conformance with the
startup, shutdown, and malfunction plan and describes the actions taken
for that event. The owner or operator must identify the exceedance in
the semiannual excess emissions report and certify that the actions
taken during the startup, shutdown, or malfunction were consistent with
the procedures in the startup, shutdown, and malfunction plan.
(3) If an action taken by the owner or operator during a startup,
shutdown, or malfunction (including an action taken to correct a
malfunction) is not consistent with the procedures specified in the
startup, shutdown, and malfunction plan, and the source exceeds any
applicable emission limitation, then the owner or operator must record
the actions taken for that event and identify the exceedance in the
semiannual excess emissions report.
(4) The owner or operator must maintain at the affected facility a
current startup, shutdown, and malfunction plan and must make the plan
available to the Administrator upon request.
(5) The Administrator may require the owner or operator to make
changes to the startup, shutdown, and malfunction plan if the
Administrator finds:
(i) The plan does not address a startup, shutdown, or malfunction
event that has occurred;
(ii) The plan fails to provide for the minimization of emissions
during operation of the source (including associated air pollution
control and monitoring equipment) during a startup, shutdown, or
malfunction event;
(iii) The plan does not provide adequate procedures for correcting
malfunctioning process and/or air pollution control and monitoring
equipment as quickly as practicable; or
(6) The owner or operator may periodically revise the startup,
shutdown, and malfunction plan as necessary to satisfy the requirements
of this subpart or to reflect changes in equipment or procedures at the
affected facility. However, each such revision to a startup, shutdown,
and malfunction plan must be reported in the semiannual report.
(c) Each owner or operator of a delayed coking unit shall
depressure to 5 lb per square inch gauge (psig) during reactor vessel
depressuring and vent the exhaust gases to the fuel gas system for
recovery.
Option 2 for Sec. 60.103a:
Sec. 60.103a Work practice standards.
Each owner or operator of a delayed coking unit shall depressure to
5 lb per square inch gauge (psig) during reactor vessel depressuring
and vent the exhaust gases to the fuel gas system for recovery.
Sec. 60.104a Performance tests.
(a) The owner or operator shall conduct a performance test for a
FCCU, fluid coking unit, sulfur recovery plant, process heater and
other fuel gas combustion device to demonstrate initial compliance with
each applicable emissions limit in Sec. 60.102a according to the
requirements of Sec. 60.8. The notification requirements of Sec.
60.8(d) apply to the initial performance test and to subsequent
performance tests required by paragraph (b) of this section (or as
required by the Administrator), but does not apply to performance tests
conducted for the purpose of obtaining supplemental data because of
continuous monitoring system breakdowns, repairs, calibration checks,
and zero and span adjustments as provided in Sec. 60.105a(l).
(b) The owner or operator of a FCCU or fluid coking unit that
elects to monitor control device operating parameters according to the
requirements in Sec. 60.105a(b) shall conduct a PM performance test at
least once every 24 months and furnish the Administrator a written
report of the results of each test.
(c) In conducting the performance tests required by this subpart
(or as requested by the Administrator), the owner or operator shall use
the test methods in 40 CFR part 60, appendix A or other methods as
specified in this section, except as provided in Sec. 60.8(b).
(d) The owner or operator shall determine compliance with the PM,
NOX, SO2, and CO emissions limits in Sec.
60.102a(b) for FCCU and fluid coking units using the following methods
and procedures:
(1) Method 1 for sample and velocity traverses.
(2) Method 2 for velocity and volumetric flow rate.
(3) Method 3, 3A, or 3B for gas analysis. The method ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.
[[Page 27210]]
(4) Method 5 for determining PM emissions and associated moisture
content from affected facilities.
(i) The PM performance test consists of 3 valid test runs; the
duration of each test run must be no less than 60 minutes.
(ii) The emissions rate of PM (EPM) is computed for each
run using Equation 1 of this section:
[GRAPHIC] [TIFF OMITTED] TP14MY07.000
Where:
E = Emission rate of PM (EPM), g/kg, lbs per 1,000 lbs (lb/1,000
lbs) of coke burn-off;
Cs = Concentration of total PM, grams per dry standard
cubic meter (g/dscm), gr/dscf;
Qsd = Volumetric flow rate of effluent gas, dry standard
cubic meters per hour, dry standard cubic feet per hour;
Rc = Coke burn-off rate, kilograms per hour (kg/hr), lbs
per hour (lbs/hr) coke; and
K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).
(iii) The coke burn-off rate (Rc) is computed for each
run using Equation 2 of this section:
[GRAPHIC] [TIFF OMITTED] TP14MY07.001
Where:
Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emissions control or
energy recovery system that burns auxiliary fuel, dry standard cubic
meters per minute (dscm/min), dry standard cubic feet per minute
(dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or
fluid coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air
to FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator
or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration in FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis);
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis);
%Ooxy = O2 concentration in O2
enriched air stream inlet to the FCCU regenerator or fluid coking
burner, percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm-%) [0.1303 (lb-min)/(hr-dscf-%)]; and
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
(iv) During the performance test, the volumetric flow rate of
exhaust gas from catalyst regenerator (Qr) before any
emission control or energy recovery system that burns auxiliary fuel is
measured using Method 2.
(v) For subsequent calculations of coke burn-off rates or exhaust
gas flow rates, the volumetric flow rate of Qr is calculated
using average exhaust gas concentrations as measured by the monitors in
Sec. 60.105a(b)(2), if applicable, using Equation 3 of this section:
[GRAPHIC] [TIFF OMITTED] TP14MY07.002
Where:
Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emission control or
energy recovery system that burns auxiliary fuel, dscm/min (dscf/
min);
Qa = Volumetric flow rate of air to FCCU regenerator or
fluid coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air
to FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator
or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis). When no auxiliary fuel is
burned and a continuous CO monitor is not required in accordance
with Sec. 60.105a(g)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis); and
%Ooxy = O2 concentration in O2
enriched air stream inlet to the FCCU regenerator or fluid coking
burner, percent by volume (dry basis).
(5) Method 7, 7A, 7C, 7D, or 7E for moisture content and for the
concentration of NOX calculated as nitrogen dioxide
(NO2); the duration of each test run must be no less than 4
hours.
(6) Method 6, 6A, or 6C for moisture content and for the
concentration of SO2; the duration of each test run must be
no less than 4 hours. The method ASME PTC 19.10-1981, ``Flue and
Exhaust Gas Analyses,'' (incorporated by reference--see Sec. 60.17) is
an acceptable alternative to EPA Method 6 or 6A.
(7) Method 10, 10a, or 10B for moisture content and for the
concentration of CO. The sampling time for each run must be 60 minutes.
(8) The owner or operator shall adjust PM, NOX,
SO2, and CO pollutant concentrations to 0 percent excess air
or 0 percent O2 using Equation 4 of this section:
[GRAPHIC] [TIFF OMITTED] TP14MY07.003
Where:
Cadj = pollutant concentration adjusted to 0 percent
excess air or O2, parts per million (ppm) or g/dscm;
Cmeas = pollutant concentration measured on a dry basis,
ppm or g/dscm;
20.9c = 20.9 percent O2-0.0 percent
O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry
basis, percent.
[[Page 27211]]
(e) The owner or operator of a FCCU or fluid coking unit that is
controlled by an electrostatic precipitator or wet scrubber and that is
subject to control device operating parameter limits Sec. 60.102a(c)
shall establish the limits based on the performance test results
according to the following procedures:
(1) Reduce the parameter monitoring data to hourly averages for
each test run;
(2) Determine the operating limit for each required parameter as
the lowest hourly average voltage and secondary current and the highest
coke burn-off rate (if you use an electrostatic precipitator) or the
lowest average pressure drop and liquid-to-gas ratio (if you use a wet
scrubber) measured during a test run that achieves the applicable PM
emission limit.
(f) The owner or operator of a FCCU or fluid coking unit that is
exempt from the requirement to install and operate a CO CEMS pursuant
to Sec. 60.105a(g)(3) and that is subject to control device operating
parameter limits in Sec. 60.102a(d) shall establish the limits based
on the performance test results using the following procedures:
(1) Reduce the temperature and O2 concentrations from
the parameter monitoring systems to hourly averages for each test run.
(2) Determine the operating limit for temperature and O2
concentrations as the lowest hourly average temperature and
O2 concentration measured during a test run achieving the
emission limitation.
(g) The owner or operator shall determine compliance with the
SO2 and H2S emissions limits for sulfur recovery
plants in Sec. 60.102a(e) using the following methods and procedures:
(1) Method 1 for sample and velocity traverses.
(2) Method 2 for velocity and volumetric flow rate.
(3) Method 3, 3A, or 3B for gas analysis. The method ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.
(4) Method 6, 6A, or 6C to determine the SO2
concentration. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 6 or 6A.
(5) Method 15 or 15A to determine the reduced sulfur compounds and
H2S concentrations.
(i) Each run consists of 16 samples taken over a minimum of 3
hours.
(ii) The owner or operator shall calculate the average
H2S concentration after correcting for moisture and
O2 as the arithmetic average of the H2S
concentration for each sample during the run (ppmv, dry basis,
corrected to 0 percent excess air).
(iii) The owner or operator shall calculate the SO2
equivalent for each run after correcting for moisture and O2
as the arithmetic average of the SO2 equivalent of reduced
sulfur compounds for each sample during the run (ppmv, dry basis,
corrected to 0 percent excess air).
(iv) The owner or operator shall use Equation 4 of this section to
adjust pollutant concentrations to 0 percent O2 or 0 percent
excess air.
(6) The owner or operator shall calculate the combined
SO2 and reduced sulfur compound concentrations for a sulfur
recovery plant with a capacity greater than 20 LTD that is subject to
the emissions limit in Sec. 60.102a(e)(1) using Equation 5 of this
section:
[GRAPHIC] [TIFF OMITTED] TP14MY07.004
Where:
Ccombined = Cmbined SO2 and reduced sulfur
compounds concentration, ppmv, dry basis, at 0 percent excess air;
CSO2,M6 = SO2 concentration in the exhaust
stream measured using Method 6, 6A, or 6C as required in paragraph
(c)(4) of this section, ppmv, dry basis at 0 percent excess air; The
method ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 6 or 6A.
CSO2--eq,M15 = SO2 equivalent concentration of
reduced sulfur compounds in the exhaust stream measured using Method
15 or 15A as required in paragraph (c)(5) of this section, ppmv, dry
basis at 0 percent excess air. The method ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see
Sec. 60.17) is an acceptable alternative to EPA Method 15A.
(7) The owner or operator shall calculate the mass sulfur emission
percentage for a sulfur recovery plant with a capacity of 10 LTD or
less that is subject to the emissions limit in Sec. 60.102a(e)(2)
using the following procedures:
(i) Calculate the combined SO2 and reduced sulfur
compound concentration using Equation 5 of this section.
(ii) Calculate the mass sulfur emissions percentage using Equation
6 of this section:
[GRAPHIC] [TIFF OMITTED] TP14MY07.005
Where:
FS,emit = Mass fraction of sulfur emitted, weight
percent;
K4 = Conversion factor, 0.5 [lbs S/lb SO2] x
60 [min/hr] x 1.66E-7 [lbs/dscf per ppmv]/2,240 [lbs/long ton] =
2.22E-9 (lbs S[middot]min[middot]long ton[middot]lbs/dscf)/(lbs
SO2[middot]hr[middot]lb[middot]ppmv);
Ccombined = Combined SO2 and reduced sulfur
compounds concentration, ppmv, dry basis at 0 percent excess air;
Qsd = Volumetric flow rate of effluent gas dscf/min; and
Msulfur = Mass rate of sulfur recovery, long tons/hr.
(h) The owner or operator of a sulfur recovery plant that is
subject to the operating limits in Sec. 60.102a(f) shall establish the
limits based on the results of the performance test according to the
following procedures:
(1) Reduce the temperature and O2 concentrations from
the CPMS to hourly averages for each test run;
(2) Determine the operating limit for temperature and O2
concentrations as the lowest hourly average temperature and
O2 concentration measured during a test run achieving the
H2S emissions limit.
(i) The owner or operator shall determine compliance with the
SO2 and NOX emissions limits in Sec. 60.102a(g)
for a process heater or other fuel gas combustion device according to
the following test methods and procedures:
[[Page 27212]]
(1) Method 1 for sample and velocity traverses;
(2) Method 2 for velocity and volumetric flow rate;
(3) Method 3, 3A, or 3B for gas analysis. The method ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.;
(4) Method 6, 6A, or 6C to determine the SO2
concentration. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 6 or 6A.
(i) The performance test consists of 3 valid test runs; the
duration of each test run must be no less than 1 hour.
(ii) If a single fuel gas combustion device having a common source
of fuel gas is monitored as allowed under Sec. 60.107a(a)(2)(v), only
one performance test is required. That is, performance tests are not
required when a new affected fuel gas combustion device is added to a
common source of fuel gas that previously demonstrated compliance.
(5) Method 7, 7A, 7C, 7D, or 7E for moisture content and for the
concentration of NOX calculated as NO2; the
duration of each test run must be no less than 4 hours.
(j) The owner or operator shall determine compliance with the
H2S or TRS emissions limit in Sec. 60.102a(h) for a process
heater or other fuel gas combustion device according to the following
test methods and procedures:
(1) Method 1 for sample and velocity traverses;
(2) Method 2 for velocity and volumetric flow rate;
(3) Method 3, 3A, or 3B for gas analysis. The method ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.;
(4) Method 11, 15, 15A, or 16 for determining the H2S
concentration for affected plants using an H2S monitor as
specified in Sec. 60.107a(a)(1) or Method 16 for determining the TRS
concentration. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 15A.
(i) For Method 11, the sampling time and sample volume must be at
least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal
sampling times must be taken at about 1-hour intervals. The arithmetic
average of these two samples constitute a run. For most fuel gases,
sampling times exceeding 20 minutes may result in depletion of the
collection solution, although fuel gases containing low concentrations
of H2S may necessitate sampling for longer periods of time.
(ii) For Method 15 or 16, at least three injects over a 1-hour
period constitutes a run.
(iii) For Method 15A, a 1-hour sample constitutes a run. The method
ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated
by reference--see Sec. 60.17) is an acceptable alternative to EPA
Method 15A.
(iv) If monitoring is conducted at a single point in a common
source of fuel gas as allowed under Sec. 60.107a(a)(1)(iv), only one
performance test is required. That is, performance tests are not
required when a new affected fuel gas combustion device is added to a
common source of fuel gas that previously demonstrated compliance.
Sec. 60.105a Monitoring of emissions and operations for fluid
catalytic cracking units (FCCU) and fluid coking units.
(a) FCCU and fluid coking units subject to PM emissions limit. Each
owner or operator subject to the provisions of this subpart shall
monitor each FCCU and fluid coking unit subject to the PM emissions
limit in Sec. 60.102a(b)(1) according to the requirements in paragraph
(b), (c), or (d) of this section.
(b) Control device operating parameters. Each owner or operator of
a FCCU or fluid coking unit subject to the PM emissions limit in Sec.
60.102a(b)(1) shall comply with the requirements in paragraphs (b)(1)
through (3) of this section.
(1) The owner or operator shall install, operate, and maintain
continuous parameter monitor systems (CPMS) to measure and record
operating parameters for each control device according to the
requirements in paragraph (b)(1)(i) through (iii) of this section.
(i) For units controlled using an electrostatic precipitator, the
owner or operator shall use CPMS to measure and record the hourly
average total power input and secondary voltage to the control device.
(ii) For units controlled using a wet scrubber, the owner or
operator shall use CPMS to measure and record the hourly average
pressure drop, liquid feed rate, and exhaust gas flow rate.
(iii) The owner or operator shall install, operate, and maintain
each CPMS according to the manufacturer's specifications and
requirements.
(2) The owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring the concentrations
of CO2, O2 (dry basis), and if needed, CO in the
exhaust gases prior to any control or energy recovery system that burns
auxiliary fuels.
(i) The owner or operator shall install, operate, and maintain each
monitor according to Performance Specification 3 (40 CFR part 60,
appendix B).
(ii) The owner or operator shall conduct performance evaluations of
each CO2, O2, and CO monitor according to the
requirements in Sec. 60.13(c) and Performance Specification 3. The
owner or operator shall use Method 3 for conducting the relative
accuracy evaluations.
(iii) The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F, including
quarterly accuracy determinations for CO2 and CO monitors,
annual accuracy determinations for O2 monitors, and daily
calibration drift tests.
(3) The owner or operator shall determine and record the average
coke burn-off rate and hours of operation for each FCCU or fluid coking
unit using the procedures in Sec. 60.104a(d)(4)(vii).
(c) Bag leak detection systems. Each owner or operator of a FCCU or
fluid coking unit shall install, operate, and maintain a bag leak
detection system for each baghouse that is used to comply with the PM
emissions limit in Sec. 60.102a(b)(1) according to paragraph (c)(1) of
this section; prepare and operate by a site-specific monitoring plan
according to paragraph (c)(2) of this section; take corrective action
according to paragraph (c)(3) of this section; and record information
according to paragraph (c)(4) of this section.
(1) Each bag leak detection system must meet the specifications and
requirements in paragraphs (c)(1)(i) through (viii) of this section.
(i) The bag leak detection system must be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 0.00044 grains per actual cubic foot or less.
(ii) The bag leak detection system sensor must provide output of
relative PM loadings. The owner or operator shall continuously record
the output from the bag leak detection system using electronic or other
means (e.g., using a strip chart recorder or a data logger).
(iii) The bag leak detection system must be equipped with an alarm
system that will sound when the system detects an increase in relative
particulate loading over the alarm set point established according to
paragraph (c)(1)(iv) of this section, and the alarm must be located
such that it can be
[[Page 27213]]
heard by the appropriate plant personnel.
(iv) In the initial adjustment of the bag leak detection system,
the owner or operator must establish, at a minimum, the baseline output
by adjusting the sensitivity (range) and the averaging period of the
device, the alarm set points, and the alarm delay time.
(v) Following initial adjustment, the owner or operator shall not
adjust the averaging period, alarm set point, or alarm delay time
without approval from the Administrator or delegated authority except
as provided in paragraph (c)(1)(vi) of this section.
(vi) Once per quarter, the owner or operator may adjust the
sensitivity of the bag leak detection system to account for seasonal
effects, including temperature and humidity, according to the
procedures identified in the site-specific monitoring plan required by
paragraph (c)(2) of this section.
(vii) The owner or operator shall install the bag leak detection
sensor downstream of the baghouse and upstream of any wet scrubber.
(viii) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
(2) The owner or operator shall develop and submit to the
Administrator for approval a site-specific monitoring plan for each
baghouse and bag leak detection system. The owner or operator shall
operate and maintain each baghouse and bag leak detection system
according to the site-specific monitoring plan at all times. Each
monitoring plan must describe the items in paragraphs (c)(2)(i) through
(vii) of this section.
(i) Installation of the bag leak detection system;
(ii) Initial and periodic adjustment of the bag leak detection
system, including how the alarm set-point will be established;
(iii) Operation of the bag leak detection system, including quality
assurance procedures;
(iv) How the bag leak detection system will be maintained,
including a routine maintenance schedule and spare parts inventory
list;
(v) How the bag leak detection system output will be recorded and
stored;
(vi) Corrective action procedures as specified in paragraph (c)(3)
of this section. In approving the site-specific monitoring plan, the
Administrator or delegated authority may allow owners and operators
more than 3 hours to alleviate a specific condition that causes an
alarm if the owner or operator identifies in the monitoring plan this
specific condition as one that could lead to an alarm, adequately
explains why it is not feasible to alleviate this condition within 3
hours of the time the alarm occurs, and demonstrates that the requested
time will ensure alleviation of this condition as expeditiously as
practicable; and
(vii) How the baghouse system will be operated and maintained,
including monitoring of pressure drop across baghouse cells and
frequency of visual inspections of the baghouse interior and baghouse
components such as fans and dust removal and bag cleaning mechanisms.
(3) For each bag leak detection system, the owner or operator shall
initiate procedures to determine the cause of every alarm within 1 hour
of the alarm. Except as provided in paragraph (c)(2)(vi) of this
section, the owner or operator shall alleviate the cause of the alarm
within 3 hours of the alarm by taking whatever corrective action(s) are
necessary. Corrective actions may include, but are not limited to the
following:
(i) Inspecting the baghouse for air leaks, torn or broken bags or
filter media, or any other condition that may cause an increase in
particulate emissions;
(ii) Sealing off defective bags or filter media;
(iii) Replacing defective bags or filter media or otherwise
repairing the control device;
(iv) Sealing off a defective baghouse compartment;
(v) Cleaning the bag leak detection system probe or otherwise
repairing the bag leak detection system; or
(vi) Shutting down the process producing the particulate emissions.
(4) The owner or operator shall maintain records of the information
specified in paragraphs (c)(4)(i) through (iii) of this section for
each bag leak detection system.
(i) Records of the bag leak detection system output;
(ii) Records of bag leak detection system adjustments, including
the date and time of the adjustment, the initial bag leak detection
system settings, and the final bag leak detection system settings; and
(iii) The date and time of all bag leak detection system alarms,
the time that procedures to determine the cause of the alarm were
initiated, the cause of the alarm, an explanation of the actions taken,
the date and time the cause of the alarm was alleviated, and whether
the alarm was alleviated within 3 hours of the alarm.
(d) Continuous emissions monitoring systems (CEMS). The owner or
operator of a FCCU or fluid coking unit subject to the PM emissions
limit (gr/dscf) in Sec. 60.102a(b)(1) shall install, operate,
calibrate, and maintain an instrument for continuously monitoring and
recording the concentration (0 percent excess air) of PM in the exhaust
gases prior to release to the atmosphere. The monitor must include an
O2 monitor for correcting the data for excess air.
(1) The owner or operator shall install, operate, and maintain each
PM monitor according to Performance Specification 11 of 40 CFR part 60,
appendix B. The span value of this PM monitor is 0.08 gr/dscf PM.
(2) The owner or operator shall conduct performance evaluations of
each PM monitor according to the requirements in Sec. 60.13(c) and
Performance Specification 11. The owner or operator shall use Method 5
for conducting the relative accuracy evaluations.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of 40
CFR part 60, appendix B. The span value of this O2 monitor
is 25 percent.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3. Method 3, 3A, or 3B shall be
used for conducting the relative accuracy evaluations. The method ASME
PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.
(5) The owner or operator shall comply with the quality assurance
requirements of procedure 2 in 40 CFR part 60, appendix F for each PM
CEMS and procedure 1 in 40 CFR part 60, appendix F for each
O2 monitor, including quarterly accuracy determinations for
each PM monitor, annual accuracy determinations for each O2
monitor, and daily calibration drift tests.
(e) FCCU and fluid coking units subject to NOX limit. Each owner or
operator of a FCCU or fluid coking unit subject to the NOX
emissions limit in Sec. 60.102a(b)(2) shall install, operate,
calibrate, and maintain an instrument for continuously monitoring and
recording the concentration by volume (dry basis, 0 percent excess air)
of NOX emissions into the atmosphere. The monitor must
include an O2 monitor for correcting the data for excess
air.
(1) The owner or operator shall install, operate, and maintain each
NOX monitor according to Performance Specification 2 (40 CFR
part 60,
[[Page 27214]]
appendix B). The span value of this NOX monitor is 200 ppmv
NOX.
(2) The owner or operator shall conduct performance evaluations of
each NOX monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2. The owner or operator shall
use Methods 7, 7A, 7C, 7D, or 7E (40 CFR part 60, appendix A) for
conducting the relative accuracy evaluations.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of 40
CFR part 60, appendix B. The span value of this O2 monitor
is 25 percent.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3. Method 3, 3A, or 3B shall be
used for conducting the relative accuracy evaluations. The method ASME
PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.
(5) The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F for each
SO2 and O2 monitor, including quarterly accuracy
determinations for SO2 monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(f) FCCU and fluid coking units subject to SO2 limit.
The owner or operator a FCCU and fluid coking unit subject to the
SO2 emissions limit in Sec. 60.102a(b)(3) shall install,
operate, calibrate, and maintain an instrument for continuously
monitoring and recording the concentration by volume (dry basis,
corrected to 0 percent excess air) of SO2 emissions into the
atmosphere. The monitor shall include an O2 monitor for
correcting the data for excess air.
(1) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 (40 CFR
part 60, appendix B). The span value of this SO2 monitor is
200 ppmv SO2.
(2) The owner or operator shall conduct performance evaluations of
each SO2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2. The owner or operator shall
use Methods 6, 6A, or 6C (40 CFR part 60, appendix A) for conducting
the relative accuracy evaluations. The method ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see
Sec. 60.17) is an acceptable alternative to EPA Method 6 or 6A.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of 40
CFR part 60, appendix B. The span value of this O2 monitor
is 10 percent.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3. Method 3, 3A, or 3B shall be
used for conducting the relative accuracy evaluations. The method ASME
PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B.
(5) The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F for each
SO2 and O2 monitor, including quarterly accuracy
determinations for SO2 monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(g) FCCU and fluid coking units subject to CO emissions limit.
Except as specified in paragraph (g)(3) of this section, the owner or
operator shall install, operate, calibrate, and maintain an instrument
for continuously monitoring and recording the concentration by volume
(dry basis) of CO emissions into the atmosphere from each FCCU and
fluid coking unit subject to the CO emissions limit in Sec.
60.102a(b)(4).
(1) The owner or operator shall install, operate, and maintain each
CO monitor according to Performance Specification 4 (40 CFR part 60,
appendix B). The span value for this instrument is 1,000 ppm CO.
(2) The owner or operator shall conduct performance evaluations of
each CO monitor according to the requirements in Sec. 60.13(c) and
Performance Specification 4 (40 CFR part 60, appendix A). The owner or
operator shall use Methods 10, 10A, or 10B for conducting the relative
accuracy evaluations using the procedures specified in Sec.
60.106a(b).
(3) A CO CEMS need not be installed if the owner or operator
demonstrates that the average CO emissions are less than 50 ppm (dry
basis) and also submits a written request for exemption to the
Administrator and receives such an exemption.
(i) The demonstration shall consist of continuously monitoring CO
emissions for 30 days using an instrument that meets the requirements
of Performance Specification 4 (40 CFR part 60, appendix B). The span
value shall be 100 ppm CO instead of 1,000 ppm, and the relative
accuracy limit shall be 10 percent of the average CO emissions or 5 ppm
CO, whichever is greater. For instruments that are identical to Method
10 and employ the sample conditioning system of Method 10A, the
alternative relative accuracy test procedure in section 10.1 of
Performance Specification 2 may be used in place of the relative
accuracy test.
(ii) The written request for exemption must include descriptions of
the CPMS for exhaust gas temperature and O2 monitor required
in paragraph (g)(4) of this section and operating limits for those
parameters to ensure combustion conditions remain similar to those that
exist during the demonstration period.
(4) The owner or operator of a FCCU or fluid coking unit that is
exempted from the requirement to install and operate a CO CEMS in
paragraph (g)(3) of this section shall install, operate, calibrate, and
maintain CPMS to measure and record the operating parameters in
paragraph (g)(4)(i) or (ii) of this section. The owner or operator
shall install, operate, and maintain each CPMS according to the
manufacturer's specifications.
(i) For a FCCU or fluid coking unit with no post-combustion control
device, the temperature and O2 concentration of the exhaust
gas stream exiting the unit.
(ii) For a FCCU or fluid coking unit with a post-combustion control
device, the temperature and O2 concentration of the exhaust
gas stream exiting the control device.
(h) Excess emissions. For the purpose of reports required by Sec.
60.7(c), periods of excess emissions for a FCCU or fluid coking unit
subject to the emissions limitations in Sec. 60.102a(b) are defined as
specified in paragraphs (h)(1) through (4) of this section. Note:
Determine all averages as the arithmetic average of the applicable 1-
hour averages, e.g., determine the rolling 3-hour average as the
arithmetic average of three contiguous 1-hour averages.
(1) All 24-hour periods during which the average PM control device
operating characteristics, as measured by the continuous monitoring
systems under Sec. 60.105a(b)(1), fall below the levels established
during the performance test. Alternatively, if a PM CEMS is used
according to Sec. 60.105a(d), all 7-day periods during which the
average PM emission rate, as measured by the continuous PM monitoring
system under Sec. 60.105a(a)(2) exceeds 0.020 gr/dscf.
(2) All rolling 7-day periods during which the average
concentration of NOX
[[Page 27215]]
as measured by the NOX CEMS under Sec. 60.105a(e) exceeds
80 ppmv.
(3) All rolling 7-day periods during which the average
concentration of SO2 as measured by the SO2 CEMS
under Sec. 60.105a(f) exceeds 50 ppmv, and all rolling 365-day periods
during which the average concentration of SO2 as measured by
the SO2 CEMS exceeds 25 ppmv.
(4) All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under Sec. 60.105a(g)
exceeds 500 ppmv or, if applicable, all 1-hour periods during which the
average temperature and O2 concentration as measured by the
continuous monitoring systems under Sec. 60.105a(g)(4) fall below the
operating limits established during the performance test.
Sec. 60.106a Monitoring of emissions and operations for sulfur
recovery plants.
(a) Sulfur recovery plants. The owner or operator of a sulfur
recovery plant shall comply with the applicable requirements in
paragraphs (a)(1) through (5) of this section.
(1) The owner or operator of a sulfur recovery plant with a
capacity greater than 20 LTD that is subject to an SO2
emissions limit in Sec. 60.102a(e)(1) shall install, operate,
calibrate, and maintain an instrument using an air or O2
dilution and oxidation system to convert any reduced sulfur to
SO2 for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of the total resultant
SO2. The monitor must include an O2 monitor for
correcting the data for excess O2.
(i) The owner or operator shall install, operate, and maintain each
SO2 CEMS according to Performance Specification 2 (40 CFR
part 60, appendix B). The span value for this monitor is 500 ppm
SO2.
(ii) The owner or operator shall conduct performance evaluations of
each SO2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2 (40 CFR part 60, appendix B).
The owner or operator shall use Methods 6 or 6C and 15 or 15A (40 CFR
part 60, appendix A) for conducting the relative accuracy evaluations.
The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference-see Sec. 60.17) is an acceptable
alternative to EPA Method 6 or 15A.
(iii) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 (40
CFR part 60, appendix B). The span value for the O2 monitor
is 25 percent O2.
(iv) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3. The owner or operator shall
use Methods 3, 3A, or 3B for conducting the relative accuracy
evaluations. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference-see Sec. 60.17) is an
acceptable alternative to EPA Method 3B.
(v) The owner or operator shall comply with the applicable quality
assurance procedures of 40 CFR part 60, appendix F for each monitor,
including quarterly accuracy determinations for each SO2
monitor, annual accuracy determinations for each O2 monitor,
and daily calibration drift determinations.
(2) The owner or operator of a sulfur recovery plant with a
capacity of less than 20 LTD that is subject to an SO2
emissions limit in Sec. 60.102a(e)(2) shall install, operate,
calibrate, and maintain an instrument using an air or O2
dilution and oxidation system to convert any reduced sulfur to
SO2 for continuously monitoring and recording the
concentration of the total resultant SO2 and an instrument
for continuously monitoring the volumetric flow rate of gases released
to the atmosphere. The SO2 monitor must include an
O2 monitor for correcting the data for excess O2.
(i) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 (40 CFR
part 60, appendix B). The span value for the SO2 monitor
shall be set at 125 percent of the maximum estimated hourly potential
SO2 emission concentration that translates to the applicable
emission limit at full sulfur production capacity.
(ii) The owner or operator shall conduct performance evaluations
for the SO2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 2 (40 CFR part 60, appendix B).
Methods 6, 6A, 6C, 15, or 15A (40 CFR part 60, appendix A) shall be
used for conducting the relative accuracy evaluations. The method ASME
PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference-see Sec. 60.17) is an acceptable alternative to EPA Method
6, 6A, or 15A.
(iii) The owner or operator shall install, operate, and maintain
each O2 monitor and flow monitor according to Performance
Specification 3 (40 CFR part 60, appendix B). The span value for the
O2 monitor is 25 percent O2. The span value for
the volumetric flow monitor shall be set at 125 percent of the maximum
estimated volumetric flow rate when the unit is operating at full
process capacity.
(iv) The owner or operator shall conduct performance evaluations
for the O2 monitor and flow monitor according to the
requirements of Sec. 60.13(c) and Performance Specification 3. The
owner or operator shall use Methods 3, 3A, or 3B for conducting the
relative accuracy evaluations. The method ASME PTC 19.10-1981, ``Flue
and Exhaust Gas Analyses,'' (incorporated by reference-see Sec. 60.17)
is an acceptable alternative to EPA Method 3B.
(v) The owner or operator shall comply with the applicable quality
assurance requirements in 40 CFR part 60, appendix F for each monitor,
including quarterly accuracy determinations for SO2 and flow
monitors, annual accuracy determinations for O2 monitors,
and daily calibration drift tests.
(3) Except as provided under paragraph (a)(4) of this section, the
owner or operator of a sulfur recovery plant that is subject to the
H2S emissions limit in Sec. 60.102a(e)(3) shall install,
operate, calibrate, and maintain an instrument for continuously
monitoring and recording the concentration of H2S (dry
basis, 0 percent excess air) emissions into the atmosphere. The
H2S monitor must include an O2 monitor for
correcting the data for excess O2.
(i) The owner or operator shall install, operate, and maintain each
H2S monitor according to Performance Specification 7 (40 CFR
part 60, appendix B). The span value for this instrument is 20 ppmv
H2S.
(ii) The owner or operator shall conduct performance evaluations
for each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 (40 CFR part 60, appendix B).
The owner or operator shall use Method 11, 15, 15A, or 16 (40 CFR part
60, appendix A) for conducting the relative accuracy evaluations. The
method ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 15A.
(iii) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
40 CFR part 60, appendix B. The span value of this O2
monitor is 25 percent.
(iv) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3. Method 3,
[[Page 27216]]
3A, or 3B shall be used for conducting the relative accuracy
evaluations. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B.
(v) The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F for each
monitor, including quarterly accuracy determinations and daily
calibration drift tests.
(4) In place of the H2S monitor required in paragraph
(a)(3) of this section, the owner or operator of a sulfur recovery
plant that is subject to the H2S emissions limit in Sec.
60.102a(e)(3) and that is equipped with an oxidation control system,
incinerator, thermal oxidizer, or similar combustion device can use a
CPMS for continuously monitoring and recording the temperature of the
exhaust gases and an O2 monitor for continuously monitoring
and recording the O2 concentration of the exhaust gases.
(i) The span values for the temperature monitor is 1,500 [deg]F.
(ii) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 (40
CFR part 60, appendix B). The span value for the O2 monitor
is 25 percent O2.
(iii) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3. The owner or operator shall
use Methods 3, 3A, or 3B for conducting the relative accuracy
evaluations. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B.
(iv) The owner or operator shall comply with the applicable quality
assurance procedures in 40 CFR part 60, appendix F for each
O2 monitor, including annual accuracy determinations.
(5) The owner or operator of a sulfur recovery plant subject to an
emissions limit in Sec. 60.102a(b) shall determine and record the
hourly sulfur production rate and hours of operation for each sulfur
recovery plant.
(b) Excess emissions. For the purpose of reports required by Sec.
60.7(c), periods of excess emissions for sulfur recovery plants subject
to the emissions limitations in Sec. 60.102a(b) are defined as
specified in paragraphs (b)(1) through (3) of this section.
Note: Determine all averages as the arithmetic average of the
applicable 1-hour averages, e.g., determine the rolling 3-hour
average as the arithmetic average of three contiguous 1-hour
averages.
(1) For sulfur recovery plants with a capacity greater than 20 LTD,
all 12-hour periods during which the average concentration of
SO2 and reduced sulfur compounds as measured by the
SO2 continuous monitoring system under paragraph (a)(1) of
this section exceeds 250 ppmv (dry basis, 0 percent excess air).
(2) For sulfur recovery plants with a capacity of 20 LTD or less,
all 12-hour periods during which the mass rate of SO2 and
reduced sulfur compounds as measured by the continuous monitoring
systems under paragraph (a)(2) of this section exceeds 1 percent of
sulfur recovered.
(3) All 1-hour periods during which the average concentration of
H2S as measured by the H2S continuous monitoring
system under paragraph (a)(3) of this section exceeds 10 ppm (dry
basis, 0 percent excess air) or, if applicable, all 1-hour periods
during which the average temperature and O2 concentration as
measured by the continuous monitoring systems under paragraph (a)(4) of
this section fall below the operating limits established during the
performance test.
Sec. 60.107a Monitoring of emissions and operations for process
heaters and other fuel gas combustion devices.
(a) Process heaters and other fuel gas combustion devices subject
to SO2, H2S, or TRS limit. The owner or operator of a process heater or
other fuel gas combustion device that is subject to the requirements in
Sec. 60.102(a)(g) shall comply with the requirements in paragraph
(a)(1) of this section for SO2 emissions. Alternatively, the
owner or operator of a process heater or other fuel gas combustion
device who elects to satisfy the requirements of Sec. 60.102(a)(h)
shall comply with the requirements in paragraph (a)(2) of this section
for H2S concentration limits or paragraph (a)(3) of this
section for TRS concentration limits. Certain exceptions to all of
these requirements are provided in paragraph (a)(4) of this section.
(1) The owner or operator of a process heater or other fuel gas
combustion device subject to the SO2 emissions limits in
Sec. 60.102a(g)(i) and (ii) shall install, operate, calibrate, and
maintain an instrument for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of SO2
emissions into the atmosphere. The monitor must include an
O2 monitor for correcting the data for excess air.
(i) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 (40 CFR
part 60, appendix B). The span values for the SO2 monitor is
50 ppm SO2.
(ii) The owner or operator shall conduct performance evaluations
for the SO2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 2 (40 CFR part 60, appendix B).
The owner or operator shall use Methods 6, 6A, or 6C (40 CFR part 60,
appendix A) for conducting the relative accuracy evaluations. The
method ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference-see Sec. 60.17) is an acceptable
alternative to EPA Method 6 or 6A. Method 6 samples shall be taken at a
flow rate of approximately 2 liters/min for at least 30 minutes. The
relative accuracy limit shall be 20 percent or 4 ppm, whichever is
greater, and the calibration drift limit shall be 5 percent of the
established span value.
(iii) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 (40
CFR part 60, appendix B). The span value for the O2 monitor
is 25 percent O2.
(iv) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3. The owner or operator shall
use Methods 3, 3A, or 3B for conducting the relative accuracy
evaluations. The method ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference-see Sec. 60.17) is an
acceptable alternative to EPA Method 3B.
(v) The owner or operator shall comply with the applicable quality
assurance procedures in 40 CFR part 60, appendix F, including quarterly
accuracy determinations for SO2 monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(vi) Process heaters or other fuel gas combustion devices having a
common source of fuel gas may be monitored at only one location (i.e.,
after one of the combustion devices), if monitoring at this location
accurately represents the SO2 emissions into the atmosphere
from each of the combustion devices.
(2) The owner or operator of a fuel gas combustion device subject
to the H2S concentration limits in Sec. 60.102a(h)(1) shall
install, operate, calibrate, and maintain an instrument for
continuously monitoring and recording the concentration by volume (dry
basis) of H2S in the fuel gases before being
[[Page 27217]]
burned in any fuel gas combustion device.
(i) The owner or operator shall install, operate, and maintain each
H2S monitor according to Performance Specification 7 (40 CFR
part 60, appendix B). The span value for this instrument is 425 ppmv
H2S.
(ii) The owner or operator shall conduct performance evaluations
for each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 (40 CFR part 60, appendix B).
The owner or operator shall use Method 11, 15, 15A, or 16 (40 CFR part
60, appendix A) for conducting the relative accuracy evaluations. The
method ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference-see Sec. 60.17) is an acceptable
alternative to EPA Method 15A.
(iii) The owner or operator shall comply with the applicable
quality assurance procedures in 40 CFR part 60, appendix F for each
H2S monitor.
(iv) Fuel gas combustion devices having a common source of fuel gas
may be monitored at only one location, if monitoring at this location
accurately represents the concentration of H2S in the fuel
gas being burned.
(3) The owner or operator of a fuel gas combustion device subject
to the TRS concentration limits in Sec. 60.102a(h)(2) shall install,
operate, calibrate, and maintain an instrument for continuously
monitoring and recording the concentration by volume (dry basis) of TRS
in the fuel gases before being burned in any fuel gas combustion
device.
(i) The owner or operator shall install, operate, and maintain each
TRS monitor according to Performance Specification 5 (40 CFR part 60,
appendix B). The span value for this instrument is 425 ppmv TRS.
(ii) The owner or operator shall conduct performance evaluations
for each TRS monitor according to the requirements of Sec. 60.13(c)
and Performance Specification 5 (40 CFR part 60, appendix B). The owner
or operator shall use Method 16 (40 CFR part 60, appendix A) for
conducting the relative accuracy evaluations.
(iii) The owner or operator shall comply with the applicable
quality assurance procedures in 40 CFR part 60, appendix F for each TRS
monitor.
(iv) Fuel gas combustion devices having a common source of fuel gas
may be monitored at only one location, if monitoring at this location
accurately represents the concentration of TRS in the fuel gas being
burned.
(4) The owner or operator of a process heater or other fuel gas
combustion device is not required to comply with paragraph (a)(1),
paragraph (a)(2), or paragraph (a)(3) of this section for streams that
are exempt under Sec. 60.102(a)(i) and fuel gas streams combusted in a
process heater or other fuel gas combustion device that are inherently
low in sulfur content. Fuel gas streams meeting one of the requirements
in paragraphs (a)(4)(i) through (iv) of this section will be considered
inherently low in sulfur content.
(i) Pilot gas for heaters and flares.
(ii) Gas streams that meet commercial-grade product specifications
and have a sulfur content of 30 ppmv or less.
(iii) Fuel gas streams produced in process units that are
intolerant to sulfur contamination, such as fuel gas streams produced
in the hydrogen plant, catalytic reforming unit, and isomerization
unit.
(iv) Other streams that an owner or operator demonstrates are low-
sulfur according to the procedures in paragraph (b) of this section.
(5) If the composition of an exempt stream changes such that it is
no longer exempt under Sec. 60.102(a)(i) or it no longer meets one of
the criteria in paragraph (a)(4)(i) through (iv) of this section, the
owner or operator must begin continuously monitoring the stream within
15 days of the change.
(b) Exemption from H2S monitoring requirements for low-
sulfur gas streams. The owner or operator of a fuel gas combustion
device may apply for an exemption from the H2S monitoring
requirements in paragraph (a)(2) of this section or the TRS monitoring
requirements in paragraph (a)(3) of this section for a gas stream that
is inherently low in sulfur content. A gas stream that is demonstrated
to be low-sulfur is exempt from the monitoring requirements of
paragraph (a)(2) or (a)(3) of this section until there are changes in
operating conditions or stream composition.
(1) The owner or operator shall submit to the Administrator a
written application for an exemption from the H2S or TRS
monitoring requirements. The owner or operator shall include the
following information in the application:
(i) A description of the gas stream/system to be considered,
including submission of a portion of the appropriate piping diagrams
indicating the boundaries of the gas stream/system, and the affected
fuel gas combustion device(s) to be considered;
(ii) A statement that there are no crossover or entry points for
sour gas (high H2S content) to be introduced into the gas
stream/system (this should be shown in the piping diagrams);
(iii) An explanation of the conditions that ensure low amounts of
sulfur in the gas stream (i.e., control equipment or product
specifications) at all times;
(iv) The supporting test results from sampling the requested gas
stream/system demonstrating that the sulfur content is less than 5 ppm
H2S or TRS. Sampling data must include, at minimum, 2 weeks
of daily monitoring (14 grab samples) for frequently operated gas
streams/systems; for infrequently operated gas streams/systems, seven
grab samples must be collected unless other additional information
would support reduced sampling. The owner or operator shall use
detector tubes (``length-of-stain tube'' type measurement) following
the ``Gas Processor Association's Test for Hydrogen Sulfide and Carbon
Dioxide in Natural Gas Using Length of Stain Tubes,'' 1986 Revision
(incorporated by reference--see Sec. 60.17) with ranges 0-10/0-100 ppm
(N =10/1) to test the applicant stream for H2S or Method 16
(40 CFR part 60, appendix A) for TRS.
(v) A description of how the 2 weeks (or seven samples for
infrequently operated gas streams/systems) of monitoring results
compares to the typical range of H2S concentration (fuel
quality) expected for the gas stream/system going to the affected fuel
gas combustion device (e.g., the 2 weeks of daily detector tube results
for a frequently operated loading rack included the entire range of
products loaded out, and, therefore, should be representative of
typical operating conditions affecting H2S or TRS content in
the gas stream going to the loading rack flare).
(2) Once EPA receives a complete application, the Administrator
will determine whether an exemption is granted. The owner or operator
shall continue to comply with the monitoring requirements in paragraph
(a)(2) or paragraph (a)(3) of this section until an exemption is
granted.
(3) Once an exemption from H2S or TRS monitoring is
granted, no further action is required unless refinery operating
conditions change in such a way that affects the exempt gas stream/
system (e.g., the stream composition changes). If such a change occurs,
the owner or operator shall follow the procedures in paragraph
(b)(3)(i), (b)(3) (ii), or (b)(3)(iii) of this section.
(i) If the operation change results in a sulfur content that is
still within the range of concentrations included in the original
application, the owner or operator shall conduct an H2S test
on a grab sample (or TRS test, if applicable)
[[Page 27218]]
and record the results as proof that the concentration is still within
the range.
(ii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application, the owner or operator may submit a new application
following the procedures of paragraph (b)(1) of this section within 60
days (or within 30 days after the seventh grab sample is tested for
infrequently operated process units).
(iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application, and the owner or operator chooses not to submit a new
application, the owner or operator must begin continuous H2S
or TRS monitoring as required in paragraph (a)(2) or paragraph (a)(3)
of this section within 15 days of the operation change.
(c) Process heaters subject to NOX limit. The owner or
operator of a process heater subject to the NOX emissions
limits in Sec. 60.102a(g)(iii) shall install, operate, calibrate, and
maintain an instrument for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of NOX
emissions into the atmosphere. The monitor must include an
O2 monitor for correcting the data for excess air.
(1) The owner or operator shall install, operate, and maintain each
NOX monitor according to Performance Specification 2 (40 CFR
part 60, appendix B). The span value of this NOX monitor is
200 ppmv NOX.
(2) The owner or operator shall conduct performance evaluations of
each NOX monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2. The owner or operator shall
use Methods 7, 7A, 7C, 7D, or 7E (40 CFR part 60, appendix A) for
conducting the relative accuracy evaluations. The method ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference-see Sec. 60.17) is an acceptable alternative to EPA Method 7
or 7C.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of 40
CFR part 60, appendix B. The span value of this O2 monitor
is 25 percent.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3. Method 3, 3A, or 3B shall be
used for conducting the relative accuracy evaluations. The method ASME
PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference-see Sec. 60.17) is an acceptable alternative to EPA Method
3B.
(5) The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F for each
SO2 and O2 monitor, including quarterly accuracy
determinations for SO2 monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(d) Excess emissions. For the purpose of reports required by Sec.
60.7(c), periods of excess emissions for process heaters and other fuel
gas combustion devices subject to the emissions limitations in Sec.
60.102a(g) or Sec. 60.102a(h) are defined as specified in paragraphs
(d)(1) and (3) of this section. Note: Determine all averages as the
arithmetic average of the applicable 1-hour averages, e.g., determine
the rolling 3-hour average as the arithmetic average of three
contiguous 1-hour averages.
(1) All rolling 3-hour periods during which the average
concentration of SO2 as measured by the SO2
continuous monitoring system under paragraph (a)(1) of this section
exceeds 20 ppmv, and all rolling 365-day periods during which the
average concentration as measured by the SO2 continuous
monitoring system under paragraph (a)(1) of this section exceeds 8
ppmv.
(2) All rolling 3-hour periods during which the average
concentration of H2S as measured by the H2S
continuous monitoring system under paragraph (a)(2) of this section or
the average concentration of TRS as measured by the TRS continuous
monitoring system under paragraph (a)(3) of this section exceeds 160
ppmv, and all rolling 365-day periods during which the average
concentration as measured by the H2S continuous monitoring
system under paragraph (a)(2) or the average concentration as measured
by the TRS continuous monitoring system under paragraph (a)(3) of this
section exceeds 60 ppmv.
(3) All rolling 24-hour periods during which the average
concentration of NOX as measured by the NOX
continuous monitoring system under paragraph (c) of this section
exceeds 80 ppmv (dry basis, 0 percent excess air).
Sec. 60.108a Recordkeeping and reporting requirements.
(a) Each owner or operator subject to the emissions limitations in
Sec. 60.102a shall comply with the notification, recordkeeping, and
reporting requirements in Sec. 60.7 and other requirements as
specified in this section.
(b) Each owner or operator subject to an emissions limitation in
Sec. 60.102a shall notify the Administrator of the specific monitoring
provisions of Sec. Sec. 60.105a, 60.106a, and 60.107a with which the
owner or operator seeks to comply. Notification shall be submitted with
the notification of initial startup required by Sec. 60.7(a)(3).
Option 1 for paragraph (c):
(c) The owner or operator shall maintain the following records:
(1) A copy of the startup and shutdown plan required in Sec.
60.103a(b).
(2) Records of information to document conformance with operation
and maintenance requirements in Sec. 60.105a(c).
(3) Records of bag leak detection system alarms and corrective
actions according to Sec. 63.105a(c).
(4) For each catalytic cracking unit or fluid coking unit subject
to the monitoring requirements in Sec. 60.105a(b)(3), records of the
average coke burn-off rate and hours of operation.
(5) For each sulfur recovery plant subject to monitoring
requirements in Sec. 60.106a(a)(5), records of the hourly sulfur
production rate and hours of operation for each sulfur recovery plant.
(6) For each fuel gas stream to which one of the exemptions listed
in Sec. 60.107a(a)(4) applies, records of the specific exemption
determined to apply for each stream. If the owner or operator applies
for the exemption described in Sec. 60.107a(a)(4)(iv), the owner or
operator must keep a copy of the application as well as the letter from
the Administrator granting approval of the application.
Option 2 for paragraph (c):
(c) The owner or operator shall maintain the following records:
(1) Records of information to document conformance with operation
and maintenance requirements in Sec. 60.105a(c).
(2) Records of bag leak detection system alarms and corrective
actions according to Sec. 63.105a(c).
(3) For each catalytic cracking unit or fluid coking unit subject
to the monitoring requirements in Sec. 60.105a(b)(3), records of the
average coke burn-off rate and hours of operation.
(4) For each sulfur recovery plant subject to monitoring
requirements in Sec. 0.106a(a)(5), records of the hourly sulfur
production rate and hours of operation for each sulfur recovery plant.
(5) For each fuel gas stream to which one of the exemptions listed
in Sec. 60.107a(a)(4) applies, records of the specific exemption
determined to apply for each stream. If the owner or operator applies
for the exemption described in Sec. 60.107a(a)(4)(iv), the owner or
[[Page 27219]]
operator must keep a copy of the application as well as the letter from
the Administrator granting approval of the application.
Option 1 for paragraph (d):
(d) The owner or operator shall record and maintain records of
discharges from any affected unit to the flare gas system. These
records shall include:
(1) A description of the discharge;
(2) The date and time the discharge was first identified and the
duration of the discharge;
(3) The measured or calculated cumulative quantity of gas
discharged over the discharge duration. If the discharge duration
exceeds 24 hours, record the discharge quantity for each 24 hour
period. Engineering calculations are allowed.
(4) The measured or estimated concentration of H2S and
SO2 of the stream discharged. Process knowledge can be used
to make these estimates;
(5) The cumulative quantity of H2S and SO2
released into the atmosphere. For releases controlled by flares or
other fuel gas combustion units, assume 99 percent conversion of
H2S to SO2 and no reduction of SO2.
(6) Results of any root-cause analysis conducted as required in
Sec. 60.103a(b).
Option 2 for paragraph (d):
(d) The owner or operator shall record and maintain records of
discharges from any affected unit to the flare gas system. These
records shall include:
(1) A description of the discharge;
(2) The date and time the discharge was first identified and the
duration of the discharge;
(3) The measured or calculated cumulative quantity of gas
discharged over the discharge duration. If the discharge duration
exceeds 24 hours, record the discharge quantity for each 24 hour
period. Engineering calculations are allowed.
(4) The measured or estimated concentration of H2S and
SO2 of the stream discharged. Process knowledge can be used
to make these estimates;
(5) The cumulative quantity of H2S and SO2
released into the atmosphere. For releases controlled by flares or
other fuel gas combustion units, assume 99 percent conversion of
H2S to SO2 and no reduction of SO2.
Option 1 for paragraph (e):
(e) Each owner or operator subject to this subpart shall submit an
excess emissions report for all periods of excess emissions according
to the requirements of Sec. 60.7(c) except that the report shall
contain the information specified in paragraphs (e)(1) through (7) of
this section.
(1) The date that the exceedance occurred;
(2) An explanation of the exceedance;
(3) Whether the exceedance was concurrent with a startup, shutdown,
or malfunction of a process unit or control system; and
(4) A description of the corrective action taken, if any.
(5) A root-cause summary report that provides the information
described in paragraphs (d)(1) through (4) of this section for all
discharges for which a root-cause analysis was required by Sec.
60.103a(b).
(6) For any periods for which monitoring data are not available,
any changes made in operation of the emission control system during the
period of data unavailability which could affect the ability of the
system to meet the applicable emission limit. Operations of the control
system and affected facility during periods of data unavailability are
to be compared with operation of the control system and affected
facility before and following the period of data unavailability; and
(7) A written statement, signed by a responsible official,
certifying the accuracy and completeness of the information contained
in the report.
Option 2 for paragraph (e):
(e) Each owner or operator subject to this subpart shall submit an
excess emissions report for all periods of excess emissions according
to the requirements of Sec. 60.7(c) except that the report shall
contain the information specified in paragraphs (e)(1) through (6) of
this section.
(1) The date that the exceedance occurred;
(2) An explanation of the exceedance;
(3) Whether the exceedance was concurrent with a startup, shutdown,
or malfunction of a process unit or control system;
(4) A description of the corrective action taken, if any.
(5) For any periods for which monitoring data are not available,
any changes were made in operation of the emission control system
during the period of data unavailability which could affect the ability
of the system to meet the applicable emission limit. Operations of the
control system and affected facility during periods of data
unavailability are to be compared with operation of the control system
and affected facility before and following the period of data
unavailability;
(6) A written statement, signed by a responsible official,
certifying the accuracy and completeness of the information contained
in the report.
(f) The owner or operator of an affected facility shall submit the
reports required under this subpart to the Administrator semiannually
for each 6-month period. All semiannual reports shall be postmarked by
the 30th day following the end of each 6-month period.
Sec. 60.109a Delegation of authority.
(a) This subpart can be implemented and enforced by the U.S. EPA or
a delegated authority such as a State, local, or tribal agency. You
should contact your U.S. EPA Regional Office to find out if this
subpart is delegated to a State, local, or tribal agency within your
State.
(b) In delegating implementation and enforcement authority of this
subpart to a State, local, or tribal agency, the approval authorities
contained in paragraphs (b)(1) through (4) of this section are retained
by the Administrator of the U.S. EPA and are not transferred to the
State, local, or tribal agency.
(1) Approval of an alternative non-opacity emissions standard.
(2) Approval of a major change to test methods under 40 CFR
60.8(b). A ``major change to test method'' is defined in Sec. 63.90.
(3) Approval of a major change to monitoring under 40 CFR 60.13(i).
A ``major change to monitoring'' is defined in Sec. 63.90.
(4) Approval of a major change to recordkeeping/reporting under 40
CFR 60.7(b) through (f). A ``major change to recordkeeping/reporting''
is defined in Sec. 63.90.
[FR Doc. E7-8547 Filed 5-11-07; 8:45 am]
BILLING CODE 6560-50-P