United States Office of Air Quality
Environmental Protection Planning and Standards
Agency Research Triangle Park NC 27711
Air
EPA-450/3-82-013b
ApriM989
Sulfur Oxides
Emissions from
Fluid Catalytic
Cracking Unit
Regenerators —
Background
Information for
Promulgated
Standards
Final
EIS
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EPA-450/3-82-0136
Sulfur Oxides Emissions from
Fluid Catalytic Cracking
Unit Regenerators —
Background Information
for Promulgated Standards
Emissions Standards Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
April 1989
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DISCLAIMER
This report has been reviewed by the Emission Standards Division,
Office of Air Quality Planning and Standards, Office of Air and
Radiation, Environmental Protection Agency, and approved for
publication. Mention of company or product names does not
constitute endorsement by EPA. Copies are available free of
charge to Federal employees, current contractors and grantees,
and non-profit orgaizations — as supplies permit — from the
Library Services Office, MD-35, Environmental Protection Agency,
Research Triangle Park NC 27711; or may be obtained, for a fee,
from the National Technical Information Services, 5285 Port Royal
Road, Springfield, Virginia 22161.
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ENVIRONMENTAL PROTECTION AGENCY
Background Information and Final
Environmental Impact Statement
for Sulfur Oxides Emissions From
Fluid Catalytic Cracking Unit
Regenerators
repared by:
j£ck R. Farmer
Director, Emission Standards Division
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
•/I'0 /;
/(Date)
The emission standards will limit emissions of sulfur oxides from
new, modified, and reconstructed fluid catalytic cracking unit
regenerators at petroleum refineries. The standards implement
Section 111 of the Clean Air Act and are based on the Administra-
tor's determination of June 11, 1973 (38 FR 15380) that petroleum
refineries contribute significantly to air pollution which may
reasonably be anticipated to endanger public health or welfare.
Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transpor-
tation, Agriculture, Commerce, Interior, and Energy; the National
Science Foundation; the Council on Environmental Quality; members
of the State and Territorial Air Pollution Program Administrators;
the Association of Local Air Pollution Control Officials; EPA
Regional Administrators; and other interested parties.
For additional information contact:
Mr. Robert L. Ajax
Standards Development Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
telephone: (919) 541-5578
Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
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TABLE OF CONTENTS
Section
Page
1.0 SUMMARY 1-1
1.1 Summary of Changes Since Proposal ... 1-1
1.1.1 Definition of Affected Facility ...... 1-1
1.1.2 Definition of Fresh Feed ......... 1-2
1.1.3 Methods for Compliance Determinations. . . . 1-2
1.1.4 Definition of Regulated Pollutant 1-3
1.1.5 Averaging Times for Compliance ....... 1-4
1.1.6 Clarification of Test Method Calculation
Procedures and Sampling Locations 1-4
1.1.7 Reduction in Reporting Requirements 1-5
1.1.8 Minor Changes . . . . . 1-6
1.2 Summary of Impacts of Promulgated Action 1-6
1.2.1 Environmental Impacts of Promulgated
Action 1-6
1.2.2 Energy and Economic Impacts of Promulgated
Action 1-6
1.2.3 Other Considerations 1-6
1.2.3.1 Irreversible and Irretrievable
Commitment of Resources ..... 1-6
1.2.3.2 Environmental and Energy Impacts
of Delayed Standards 1-7
1.3 Summary of Public Comments ..... 1-7
2.0 GENERAL COMMENTS 2-1
2.1 Need for the Standards 2-1
2.2 Regulated Pollutant 2-5
2.3 Designation of Affected Facility ... 2-8
2.4 Format of the Standards 2-11
2.5 Level 'of Standards 2-16
2.5.1 Level for Add-on Control Standard 2-16
2.5.2 Level of Standard for FCCU's without
• Add-on Controls . . 2-17
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TABLE OF CONTENTS (Continued)
Section
2.5.3 Feed Sulfur Cutoff . 2-19
2.6 Averaging Times ..... ... 2-19
3.0 CONTROL TECHNOLOGY COMMENTS , . 3-1
3.1 SOX Scrubbers 3-1
3.2 SOX Reduction Catalysts 3-6
3.3 Low-Sulfur Feedstocks ..... . . 3-7
4.0 ENVIRONMENTAL AND ENERGY IMPACTS COMMENTS . . 4-1
4.1 Model Plants Used for Impact Analyses ...... 4-1
4.2 Water Impacts 4-2
4.3 Solid Waste Impacts ...... 4-7
4.4 Energy Impacts . . 4-10
4.5 Air Impacts '•. .4-11
5.0 COSTS AND ECONOMIC IMPACTS COMMENTS . 5-1
5.1 Scrubber Costs 5-1
5.2 SOX Reduction Catalysts Costs . 5-10
5.3 Economic Impact Analysis . . 5-11
6.0 COMPLIANCE TESTING AND MONITORING COMMENTS 6-1
6.1 General ,.'.6-1
6.2 With Add-On Control Devices . 6-2
6.3 Without Add-On Control Devices ... 6-15
6.4 Feed Sulfur Cutoff . . 6-29
7.0 COMPLIANCE COMMENTS . . . :. . 7-1
7.1 Source. Operation During Malfunctions . 7-1
7.2 Compliance Using Partial Scrubbing ... 7-2
7.3 Changing Compliance Method 7-2
VI
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TABLE OF CONTENTS (Concluded)
Section
8.0 MODIFICATION/RECONSTRUCTION COMMENTS
Page
8-1
9.0 RECORDKEEPING AND REPORTING COMMENTS 9-1
10.0 MISCELLANEOUS COMMENTS 10-1
APPENDIX A - Control Equipment Costs and Fifth Year Impacts
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LIST OF TABLES
Table
Page
1-1 LIST OF COMMENTERS ON PROPOSED STANDARDS
OF PERFORMANCE FOR SULFUR OXIDES EMISSIONS
FROM FCCU REGENERATORS 1-8
A-l BASIS FOR DETERMINING SCRUBBER ANNUAL COSTS . . .: . A-l
A-2 CAPITAL COST FOR SODIUM-BASED HIGH ENERGY
VENTURI SCRUBBING SYSTEM AND
PURGE TREATMENT FOR MODEL UNITS A-2
A-3 ANNUAL COST OF SODIUM-BASED HIGH ENERGY
VENTURI SCRUBBING FOR 2,500 m3/sd MODEL UNITS . . . A-3
A-4 ANNUAL COST OF SODIUM-BASED HIGH ENERGY
VENTURI SCRUBBING FOR 8,000 m3/sd MODEL UNITS ... A-4
A-5 ANNUAL COST OF SODIUM-BASED JET EJECTOR
VENTURI SCRUBBING SYSTEM AND PURGE
TREATMENT FOR MODEL UNITS A-5
A-6 ANNUAL COST OF SODIUM-BASED JET EJECTOR
VENTURI SCRUBBING FOR 2,500 m3/sd
MODEL UNITS A-6
A-? ANNUAL COST OF SODIUM-BASED JET EJECTOR
VENTURI SCRUBBING FOR 8,000 m3/sd
MODEL UNITS A-7
A-8 DUAL ALKALI SCRUBBING SYSTEM COSTS BASED
ON 1.5 WEIGHT PERCENT SULFUR FEED . ' . A-8
A-9 ELECTROSTATIC PRECIPITATOR COSTS A-9
A-10 FIFTH YEAR CAPITAL COST IMPACTS A-ll
A-ll FIFTH YEAR ANNUAL COST IMPACTS A-12
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1.0 SUMMARY
On January 17, 1984, the U.S. Environmental Protection Agency
(EPA) proposed standards of performance for sulfur oxides (SOX) emis-
sions from fluid catalytic cracking unit (FCCU) regenerators at petroleum
refineries (49 FR 2058) under the authority of Section 111 of the Clean
Air Act. Public comments were requested on the proposed standards in
the Federal Register and 18 commenters responded. On November 8, 1985,
revisions to the proposed rule were proposed (50 FR 46464). The revi-
sions included a change in the regulated pollutant for the standard
for FCCU's with add-on controls, the determination of compliance on
a daily basis, the methods for making the daily compliance determina-
tions, and the averaging times over which the daily compliance deter-
minations would be made. Public comments were requested on the
proposed revisions and 12 commenters responded. Most of the commenters
represented refining companies. Other commenters included two State
air pollution control agencies, an industry trade association, an
engineering company, and a private individual. This summary of
comments and EPA's responses to these comments serve as the basis for
the revisions made to the standards between proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
The proposed standards were revised as a result of reviewing public
comments. The primary changes were made in the following areas:
o Definition of Affected Facility
o Definition of Fresh Feed
o Methods for Compliance Determinations
o Definition of Regulated Pollutant
o Averaging Times for Compliance
o Clarification of Test Method Calculation Procedures and Sampling
Locations
o Reductions in Reporting and Compliance Testing Requirements
1.1.1 Definition of Affected Facility
The proposed standards identified each regenerator as the affected
facility. This was done because SOX are generated in and emitted from
the FCCU regenerator. Some new FCCU's are designed to incorporate more
1-1
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than one regenerator. The EPA believes that identifying each FCCU
regenerator as the affected facility for multiple regenerator config-
urations Is unreasonable. If only one regenerator in a multiple
regenerator configuration were to become subject to the standards, it
would be impossible in some multiple regenerator ducting arrangements
to isolate and measure the SOX content of the exhaust gases from the
affected regenerator. Furthermore, because the refiner would want to
minimize the cost and downtime for revamping work on the unit, it is
unlikely that only one regenerator in a multiple regenerator config-
uration would be modified or reconstructed without the others. Therefore,
the affected facility is now defined to include all regenerators serving
an FCCU reactor.
1.1.2 Definition of Fresh Feed
The standards include a feed sulfur cutoff, which limits the
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amount of sulfur that is allowed in the fresh feed to an FCCU. The
possibility exists that a refiner could circumvent the feed sulfur
cutoff by identifying as "fresh feed" hydrocarbon streams recycled from
the fractionator or gas recovery unit because these units are not a
part of the affected facility. Therefore, the definition of fresh feed
was revised to ensure that a refiner would not circumvent the feed
sulfur cutoff by including as "fresh feed" low sulfur-containing
recycle from the fractionator and gas recovery urtits. The revised
definition specifically identifies petroleum derivatives from the FCCU,
the fractionator, and the gas recovery unit as "recycle", thus excluding
them from the "fresh feed."
1.1.3 Methods for Compliance Determinations
At proposal, a continuous emission monitoring system (CEMS) was
required to identify excess emissions, which were defined, for the standard
for FCCU's with add-on controls, as sulfur dioxide (SOg) in excess of
the control device outlet concentration measured during the most recent
performance test. The proposed standard specified the use of a continuous
SOg emission monitoring system only at the control device outlet. (The
standard for FCCU's without add-on controls also identified excess emissions,
which were defined as S02 in excess of 300 vppm at 0 percent oxygen on
a dry basis.) The EPA received comments that this approach would result
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in an unreasonable excess emissions limit when control device inlet
concentrations changed from the level measured during the performance
test. These comments, in part, led EPA to revise this approach to
eliminate the dependence of the excess emission definition on the
performance test.
Both the standards for FCCU's with add-on controls and for FCCU's
without add-on controls now require determination of compliance on a
daily basis, rather than using excess emissions to identify the need
for a compliance test. The standard for FCCU's with add-on controls
(90 percent reduction or 50 vppm, whichever is less stringent) now
identifies S02 as the controlled pollutant and requires the use of
continuous S0£ monitors located at the control device inlet and outlet
to determine the compliance status of the facility on a continual
(i.e., daily) basis. Only an outlet continuous SOg monitor is required
if the owner or operator seeks to comply specifically with only the
50 vppm emission limit. Because S02 monitors are now used for compli-
ance determinations, they are subject to 40 CFR Part 60 Appendix F,
"Quality Assurance Procedures, Procedure 1 - Quality Assurance Require-
ments for Gas Continuous Emission Monitoring Systems Used for Compliance
Determination." The standard for FCCU's without add-on controls now
requires daily Method 8 testing to demonstrate compliance with the
9.8 kg SOX/1,000 kg coke burn-off standard.
For the standards for FCCU's with add-on control devices, minimum
data requirements have been incorporated. They require 22 valid days
of data out of every 30 successive, rolling calendar days. A valid day
of data consists of at least 18 valid hours of data, where a valid hour
of data consists of at least 2 valid data points.
1.1.4 Definition of Regulated Pollutant
As proposed on January 17, 1984, SOX was the regulated pollutant
for all the standards for FCCU's. After further consideration, the
EPA concluded that the regulated pollutant for the standard for FCCU's
with add-on control devices should be S02- The reasons for this
change were: (1) as described above, the change to daily compliance
determinations resulted in requiring both inlet and outlet monitors;
(2) CEMS are not available for SOX, but are available for $02; (3)
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sulfur trioxide ($03) constitutes a small portion of total SOX emissions;
and (4) best demonstrated technology (i.e., scrubbers) would be essentially
the same for S02 and SOX.
For ;the standard for FCCU's without add-on control devices, the
Agency concluded that the regulated pollutant should remain SOX, because
503 could constitute a significant portion of the total SOX emissions
from FCCU's using SOX reduction catalysts. These conclusions were
included in the revisions proposed on November 8, 1985. No comments
were received on using S0£ as the regulated pollutant for FCCU's with
add-on controls, but comments were received regarding SOX as the
regulated pollutant for FCCU's without add-on controls. No additional
data or information was obtained that was sufficient for the Agency to
conclude that SOg should be the regulated pollutant for FCCU's without
add-on controls. Thus, the regulated pollutant for FCCU's with add-
on control devices is S02 and for FCCU's without add-on control
devices the regulated pollutant is SOX.
1.1.5 Averaging Times for Compliance
The averaging times for compliance has changed since proposal from
3 hours to 7 days. The EPA analyzed source test results for scrubbers
to determine the long term variability in scrubber performance and
considered the effect of process variability on SOX reduction catalyst
performance. The analysis indicated that selection of a 7-day rolling
average period for both the standards for FCCU's with add-on controls
and for FCCU's without add-on controls would better take into conside-
ration th<* normal variability. The proposed 7-day calendar averaging
time for the feed sulfur cutoff was changed to a rolling 7-day average
to be consistent with the averaging times for the other two standards,, and
so we would have daily compliance determinations.
1.1.6 Clarification of Test Method Calculation Procedures and Sampling
Locations ;
The Standard for FCCU's without add-on controls requires the use
of Method 8 to determine the total SOX emissions from affected facilities.
The proposed standards did not provide sufficient information regarding
calculation procedures for determining total SOX emissions:. The
standards were revised to include modifications to the calculation
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procedures specified in Method 8 to allow calculation of total SOX
emissions as SOg.
The proposed standards required that sampling to be conducted
upstream of the carbon monoxide (CO) boiler. One commenter stated that
it is unsafe to require personnel to conduct manual sampling due to the
high flue gas temperatures and pressures at this location. The stan-
dard for FCCU's without add-on controls has been revised to allow
sampling either upstream or downstream of the CO boiler. For FCCU's
with add-on controls, the recommended location for S02 monitoring has
been changed to downstream of the CO boiler.
1.1.7 Reduction in Reporting Requirements
This rulemaking provides the refiner with a standard -for add-on
control devices, an alternative standard for add-on control devices,
a standard without add-on control devices, and a feed sulfur content
cutoff. Initially, the refiner may elect to demonstrate compliance
with any one of these standards and, at a later time, the refiner may
elect to demonstrate compliance with one of the alternative standards.
The standards were developed in this way to allow the refiner greater
flexibility in compliance objectives but also to encourage the use of
hydrotreating and SOX reduction catalysts. The reporting and record-
keeping requirements for the proposed standards required that a refiner
give a 90-day prior notification of his intent to be subject to a
different standard and conduct a performance test with each change.
Since proposal, the EPA has changed the standards to require daily
compliance determinations. This change requires an owner or operator
to conduct performance tests every day regardless of the standard with
which the owner or operator seeks to comply. The 90-day prior
notification significantly reduces a refiner's flexibility without
significantly increasing EPA's ability to enforce the standard. There-
fore, the regulation has been changed so that prior notification is not
required when the owner or operator seeks to comply with one of the
other standards, regardless of whether the owner or operator has been
subject to the particular standard previously. All changes must be
identified in the next compliance report. Compliance reports are
required quarterly, unless no exceedances have occurred during a
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particular quarter, in which case semiannual reports may be submitted.
The proposal had not allowed semiannual reporting when there were
periods of no exceedances. If an owner or operator elects to comply
with an alternative SOX standard, a quarterly report with notification
of the change must be submitted to the Administrator in the quarter
following such a change even if no violations of a standard have occurred.
1.1.8 Minor Changes
Sevepal changes have been made to the SOX emission percent reduc-
tion equation and SOX emission rate equation such that direct results
from the test methods can be used in the equations.
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.2.1 Environmental Impacts of Promulgated Action
Environmental impacts of the proposed standards are described in
49 FR 2058. The revisions to the proposed standards will have a
minimal effect on the environmental impacts of the standards.
1.2.2 Energy and Economic Impacts of Promulgated Action
The energy and economic impacts of the standards are described in
Chapters 6, 8, and 9 of the proposal background information document
(BID). The energy impacts have not changed since proposal. The costs
for sodium scrubbers have been revised; the cost and economic impacts
f
of the final standards are greater than those calculated at proposal.
The nationwide cumulative capital costs in the fifth year of these
standards would be $117 million (reported in fourth quarter 1984 dollars),
if sodium scrubbers are used at all facilities with feed sulfur levels
above 0.30 percent by weight. The corresponding fifth year nationwide
annual cost would be $45 million (reported in fourth quarter 1984
dollars).; Fluid catalytic cracking units processing feeds with sulfur
contents of 0.30 weight percent would be ,at the feed sulfur cutoff and
therefore, would not need to install a scrubber. These nationwide cost
estimates differ, therefore, from those presented in Tables A-10 and
A-ll because costs for control of FCCU's with sulfur contents of 0.30
weight percent a're not included here.
1.2.3 Other Considerations
1.2.3.1 Irreversible and Irretrievable Commitment of Resources.
Implementation of these standards will result in the use of sodium-based
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scrubbers in many cases. This will necessitate the additional use of
natural resources, especially sodium carbonate and sodium hydroxide.
However, the commitment of these resources is expected to be small
compared to national use.
1.2.3.2 Environmental and Energy Impacts of Delayed Standards.
Delay in implementation of these standards would adversely impact air
quality at the rate shown in Table 7-6 of the proposal BID. The annual
"Sulfur Oxides Emissions Reduction" column in Table 7-6 represents the
lost emission reductions for each year the standards are delayed. No
adverse solid waste, water pollution, or energy impacts are expected
from delaying regulatory action.
1.3 SUMMARY OF PUBLIC COMMENTS
Letters were received from 18 correspondents commenting on the
proposed standards and the BID for the proposed standards, and from 12
correspondents commenting on the proposed revisions. There were no
requests for a public hearing so none was held. A list of commenters,
their affiliations, and the EPA docket numbers assigned to their
correspondence are given in Table 1-1 of this document.
This document presents comments pertaining to the preamble and
regulation resulting from the proposed standards. The comments from
interested parties and EPA's responses to those comments have been
categorized, and they are presented under the following topics:
o General Comments (Section 2)
o Control Technology Comments (Section 3)
o Environmental and Energy Impacts Comments (Section 4)
o Costs and Economic Impacts Comments (Section 5)
o Compliance Testing and Monitoring Comments (Section 6)
o Compliance Comments (Section 7)
o Modification/Reconstruction Comments (Section 8)
o Reco.rdkeeping and Reporting Comments (Section 9)
o Miscellaneous Comments (Section 10)
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TABLE 1-1. LIST OF COMMENTERS ON PROPOSED
STANDARDS OF PERFORMANCE FOR SULFUR OXIDES
EMISSIONS FROM FCCU REGENERATORS
Commenter and Affiliation
Docket Item No,
1. Mr. J.A. Stuart
South Coast, Air Quality Management District
9150 Flair Drive
El Monte, CA 91731
2. Mr. J.J. Moon
Phillips Petroleum Company
704 Phillips Building
Bartlesville, OK 74004
3. Mr. Phillip L. Youngblood
Conoco, Incorporated
P.O. Box 2197
Houston, TX 77252
4. Ms. Gael Fletcher
Koch Refining Company
P.O. Box 43596
St. Paul, MN 55164
5. Mr. R.V. Struebing
Getty Oil Company
P.O. Box 1650
Tulsa, OK 74102
6. Mr. William F. O'Keefe
American Petroleum Institute
1220 L Street, Northwest
Washington,: D.C. 20005
7. Mr. Peter W;. McCallum
The Standard Oil Company
Midland Building
Cleveland, OH 44115-1098
8. Mr. J.R. Bowler
CITGO Petroleum Corporation
Lake Charles Operations
Box 1562 ;
Lake Charles, LA 70602
9. Mr. R.H. Murray .
Mobil Oil Corporation
3225 Gallows Road
Fairfax, VA 22037
IV-D-1
IV-D-2
IV-D-3
IV-D-4
IV-D-5
IV-D-6
IV-D-7
IV-D-8
IV-D-9
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TABLE 1-1. LIST OF COMMENTERS ON PROPOSED
STANDARDS OF PERFORMANCE FOR SULFUR OXIDES
EMISSIONS FROM FCCU REGENERATORS
Commenter and Affiliation
Docket Item No.
10. Mr. J. Donald Annett
Texaco, U.S.A.
1050 17th Street, N.W.
Washington, D.C. 20036
11. Mr. A.6. Smith
Shell Oil Company
P.O. Box 4320
Houston, TX 77210
12. Mr. Michael J. Duffy
Ashland Petroleum Company
P.O. Box 391
Ashland, KY 41114
13. Mr. L.G. Arnel
Gulf Oil Products Company
P.O. Box 2001
Houston, TX 77252
14. Mr. J.M. Johnson
Exxon Company, U.S.A.
P.O. Box 2180
Houston, TX 77001
15. Mr. A.R. Johnson
Stone and Webster Engineering Corporation
P.O. Box 2325
Boston, MA 02107
16. Mr. Franklyn Isaacson
25 Summit Court
Westfield, NJ 07090
17. Mr. Bill Stewart
Texas Air Control Board
6330 Highway 290 East
Austin, TX 78723
18. Mr. J.G. Huddle
Amoco Oil Company
P.O. Box 6110A
Chicago, IL 60680
IV-D-10
IV-D-11
IV-D-12
IV-D-13
IV-D-14
IV-D-15
IV-D-16
IV-D-18
IV-D-20
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TABLE 1-1. LIST OF COMMENTERS ON PROPOSED
STANDARDS OF PERFORMANCE FOR SULFUR OXIDES
EMISSIONS FROM FCCU REGENERATORS
Commenter and Affiliation
Docket Item No.
19. Mr. Allan A. Griggs
Diamond Shatnrock
P.O. Box 20267
San Antonio:, TX 78220-0267
20. Mr. Franklyn Isaacson
25 Summit Court
Westfield, NJ 07090
21. Mr. J.G. Huddle
Amoco Oil Company
P.O. Box 6110A
Chicago, IL 60680
22. Mr. M.J. Hage
Mobil Oil Corporation
3225 Gallows Rd.
Fairfax, VA 22037
23. Mr. N.J. Wasilla
SOHIO
Midland Building
Cleveland, OH 44115-1098
24. Mr. J. Donald Annett
Texaco, USA
1050 17th Street, N.W.
Washington, D.C. 20036
25. Mr. J.R. Bowler
CITGO Petroleum Corporation
Lake Charles Operations
Box 1562
Lake Charles, LA 70602
26. Mr. James H. O'Brien
Lyondell Petrochemical Company
1200 Lawndale
Box 2451
Houston, TX 77252.-2451
27. Mr. J.M. Johnson
Exxon Company, U.S.A.
P.O. Box 2180
Houston, TX 77001
IV-K-1
IV-K-2
IV-K-3
IV-K-4
IV-K-5
IV-K-6
IV-K-7
IV-K-8
IV-K-9
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TABLE 1-1. LIST OF COMMENTERS ON PROPOSED
STANDARDS OF PERFORMANCE FOR SULFUR OXIDES
EMISSIONS FROM FCCU REGENERATORS
Commenter and Affiliation
Docket Item No.
28. Mr. B.F. Ballard
Phillips Petroleum Company
Bartlesville, OK 74004
29. Mr. J.A. Eslick
Shell Oil Company
One Shell Plaza
P.O. Box 4320
Houston, TX 77210
30. Mr. R.R. Kienle
Shell Oil Company
One Shell Plaza
P.O. Box 4320
Houston, TX 77210
IV-K-10
IV-K-11
IV-K-12
1-11
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2.0 GENERAL COMMENTS ;
2.1 NEED FOR THE STANDARDS
Comment:
Two commenters (IV-D-7 and IV-D-16) stated that the standards
represent an unnecessary burden to the petroleum industry and, there-
fore, the standards should be withdrawn. The reasons cited by the
commenters for withdrawal of the standards are: (1) other sources of
SOX could be controlled at a much lower cost per ton and (2) the SOX
emissions from FCCU's are insignificant when compared to the total SOX
emissions emitted in the United States.
Response:
Section 111 of the Clean Air Act directs the Administrator to
list categories of stationary sources. The Administrator "... shall
include a category of sources in such list if in his judgement it
causes, or contributes significantly to, air pollution which may
reasonably be anticipated to endanger public health or welfare."
Further, Section lll(a)(l) directs the Administrator to propose and
promulgate standards of performance, which reflect the "best ...
demonstrated" technology (BDT) for sources in this list.
Since passage of the Clean Air Act of 1970, considerable attention
has been given to the development of an approach for assigning prior-
ities to various source categories. The approach specifies areas of
interest by considering the broad strategy of EPA for implementing the
Clean Air Act. Often, these areas of interest are actually pollutants
emitted by stationary sources. Source categories that emit these
pollutants are evaluated and ranked by a process involving such factors
as: (1) the level of emission control (if any) already required by
State regulations; (2) estimated levels of control that might be
required from standards of performance for the source category;
(3) projections of growth and replacement of existing facilities for
the source category; and (4) the estimated incremental amount of air
pollution that could be prevented in a preselected future year by
standards of performance for the source category. Sources for which
new source performance standards (NSPS) were promulgated or under
development during 1977, or earlier, were selected using these criteria;
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one of the source categories placed on the initial priority list was
"Petroleum Refineries," of which FCCU's are a part.
Section lll(f), added by the Clean Air Act Amendments of 1977,
I
now requires EPA to list major source categories. Major source cate-
gories are defined as those categories for which an average size plant
has the potential to emit 100 tons or more per year of any one pollu-
tant. This helps demonstrate the significance of the SOX emissions
from FCCU's because EPA has estimated that total SOX emissions from
new, modified, and reconstructed FCCU's in the fifth year (a total of
17 units); under Regulatory Alternative I (baseline emissions; i.e.,
emissions from the units if controlled under current regulations) would
be 86,900 tons, an average emission rate of 5,100 tons/yr per FCCU. The
standards reflect BDT and would reduce these total emissions by about
76,100 tons/yr; this reduction represents a significant improvement.
In summary, the standards of performance for SOX emissions from
FCCU's serve the intent of Section 111 of the Clean Air Act- Neither the
abflity to control other SOX sources at a lower cost nor the percentage
of total SOX emissions emitted in the United States that are comprised by
FCCU SOX emissions negate the need for these standards.
Comment:
One icommenter (IV-D-16) asked the following questions pertaining
to the need for the standards with respect to prevention of signifi-
cant deterioration (PSD) requirements which also regulate FCCU SOX
emissions:
(1) If each model source could yield considerably more than
250 tons per year of uncontrolled SOX, the source is
covered by the PSD requirements for best available control
technology (BACT). Thus, if PSD will do the job, the proposed
rules should be withdrawn. If not, the proposal BID and
proposed rules should be reissued, with baseline emissions
stated as those necessary to satisfy PSD BACT.
(2) If the 3.5 weight percent sulfur feedstock model plant is
abandoned, the modeling results (proposal BID pages 7-4
through 7-7) show that unregulated FCCU's meet Class II and
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(3)
III PSD, and primary and secondary national ambient air
quality standard (NAAQS). Thus, there is no need for this
NSPS.
Since the SOX discharges are above the small source tons per
year limit, doesn't this trigger BACT, regardless of Class II
or III increment?
Response:
Congress clearly understood that many sources subject to NSPS's
would also be subject to PSD requirements, including BACT. Thus, the
applicability of PSD does not show that the NSPS is not needed, as is
discussed below. Petroleum refineries, of which FCCU's are a part, are
listed in 40 CFR 52.21 (b)(l)(i)(a) as a "major stationary source" (i.e.,
a stationary source of air pollutants which emits, or has a potential
to emit, 100 tons per year or more of any pollutant subject to regula-
tion under the Clean Air Act). Therefore, a new, modified, or recon-
structed FCCU would be subject to PSD requirements if the unit is
located in an S02 attainment area and if the emissions from the FCCU
will not affect the S02 levels in an area that is designated as attain-
ment for S02. Depending on the classification of the attainment or
unclassified area (Class I, II, or III), a maximum allowable increase
of the ambient air baseline-.concentration is specified for that area
[40 CFR 52.21(c)]. The maximum allowable increase will be less than
that specified if the specified increase will raise the ambient air
concentration above the NAAQS. If this situation occurs, the maximum
allowable increase will equal an increase that would cause the ambient
air concentration to equal the NAAQS. [Note: The EPA expects that no
FCCU would be located in a Class I area (pristine environment) and
there are no Class III areas.] The baseline concentration is established
on the earliest date after August 7, 1977, on which the first complete
application under 40 CFR 52.21 was submitted by a major stationary
source or major modification subject to the requirements of 40 CFR 52.21.
After that date, each net emissions increase by sources in the area
reduces, by the same amount, the maximum allowable emissions increase
for that area.
The current allowable emissions increase helps determine the
emission limitation under which the source may operate; that is, the
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source will be subject to BACT. The term BACT, as defined in 40 CFR
169(3), means "... an emission limitation based on the maximum degree
of reduction of each pollutant subject to regulation under this Act
emitted from, or which results from, any major emitting facility, which
the permitting authority, on a case-by-case basis, taking into
account energy, environmental, and economic impacts and other costs,
determines is achievable for such facility through application of
production processes and available methods, systems, and techniques,
including fuel cleaning or treatment or innovative fuel combustion
techniques for control of each such pollutant." However, the entire
allowable emissions increase may or may not be available for use by the
source. Several other constraints will influence the amount of emis-
sions the;source will be allowed to emit; these constraints are
unemployment conditions, attractiveness of the source (the area's
desire for that industry), other sources wanting to locate in the area,
etc. After all variables are taken into considderation, BACT is then
determined.
There are no specified levels of BACT; each BACT determination is
dependent on the constraints within the area (i.e., BACT is determined
on a case-by-case basis). If an area was interested in having an
industry locate in its region and there was a substantially large
allowable emissions increase available, the source could receive a
rather lenient BACT determination. Due to budget limitations, many
States are not able to conduct thorough BACT investigations without
relying upon the NSPS program. At this point, the NSPS program
provides an integral part of the BACT determinations process. The
development of NSPS follows the same course as the development of BACT
without the additional constraints that could be imposed on the BACT
determination process. As such, NSPS provides the baseline from which
BACT is developed. BACT could be more stringent than NSPS, however, as
stated in 40 CFR 169(3) "... in no event shall application of "best
available control technology" result in emissions of any pollutants
which will exceed the emissions allowed by any applicable standard
established pursuant to Sections 111 or 112 of this Act." In summary,
PSD/BACT requirements do not preclude the need for NSPS; rather, NSPS
defines the maximum emission level that BACT can allow.
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2.2 REGULATED POLLUTANT
In the proposed revisions (50 FR 46464), the Agency proposed to
change the regulated pollutant from SOX to S02 for the standard with
add-on controls, but keep SOX as the regulated pollutant for the
standard without add-on controls. Comments were received only on the
proposed decision to keep SOX as the regulated pollutant for the
standard without add-on controls. These comments and the Agency's
responses follow.
Comment:
Several commenters (IV-K-2, IV-K-6, and IV-K-8) suggested that EPA
use S02 rather than SOX as the regulated pollutant for the standard for
SOX reduction catalysts. One commenter (IV-K-2) stated that other
refinery sources are only regulated for S02 and that EPA usually regu-
lated only S02. This commenter questioned how an opacity standard
tested with an in-stack monitor could limit the emissions of $03.
According to the commenter, although $03 condenses to acid mist upon
contact with the atmosphere, the continuous monitors approved by EPA are
stack-mounted and monitor emissions before any atmospheric contact
occurs.
In another comment letter (IV-D-16), Commenter IV-K-2 stated
several points pertaining to the $63 component of the FCCU flue gas:
(1) The Federal Register notice claims that oxygen content may
substantially increase the $03 content of FCCU flue gas.
Although oxygen drives the reaction to sulfur trioxide, it
is only to the 0.5 power of oxygen content. Thus, the
effect is less than linear.
(2) $03 typically is greater than 10 percent of the total SOX
emissions. This statement is based on test data reported
in the proposal BID and on the commenter's experience in
the refining industry.
(3) SOX reduction catalysts work best when the regenerator
operates to maximize the fraction leaving as $03.
Another commenter (IV-K-6) stated that preliminary data previously
submitted to EPA from several SOX reduction catalyst trials at one of
their refineries indicate the SOX emissions have generally contained
only an insignificant amount of $03. (This commenter noted that the
same result was also found without the use of SOX reduction catalysts.)
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Commenter IV-K-8 stated that by using 862 as the regulated
pollutant (1) the same monitoring technique (proven S02 monitors) would
be used as is for add-on scrubber technology and (2) cost savings and
consistency and reliability of the sample results would be gained.
This commenter also stated that emerging SOX reduction catalyst data
indicate that $03 is unaffected by the catalysts; SOX reduction
catalysts control S02, while allowing the percent, but not the total
amount of $03 to increase; and, therefore, SOX reduction catalysts do
not create a large excess of $03.
Response:
The Agency has considered the arguments presented by the commenters
and reviewed the data available on the composition of SOX when using
SOX reduction catalysts. After this review, the Agency still believes
that the most appropriate regulated pollutant for SOX reduction
catalysts is SOX, not SOg.
The Agency recontacted SOX reduction catalyst vendors to review
the mechanism by which SOX reduction catalysts reduce total SOX emis-
sions (see Docket Nos. IV-E-19 and IV-E-20). Contrary to what
Commenter IV-K-8 states, the SOX reduction catalyst vendors indicate
that SOX reduction catalysts preferentially remove $03, forming a metal
sulfate compound that is much more stable than the metal sulfite com-
pound formed when the SOg reacts with the catalyst. As the SOX reduc-
tion catalyst picks up more and more 803, the equilibrium balance is
disturbed. To regain equilibrium, more S02 becomes $03. If the rate
of S02 to 863 is less than the rate of metal sulfate formation ($03
plus metal oxide), then the $03 percentage in the FCCU emissions will
decrease. On the other hand, if the S02 to $03 rate is faster than the
metal sulfate formation rate, then this $03 percentage will increase.
To ensure maximum SOX removal efficiency, the owner or operator would
likely operate a regenerator, to the extent possible, in such a manner
that the S02 to $03 rate is not limiting; that is, create conditions
within the regenerator that increase the $03 percentage.
The Agency again reviewed the data on S02/S03 in regenerator
emissions, including that submitted by Commenters IV-K-6 and IV-K-8.
The Agency requested in the revised proposal that any data that were
available on this be submitted. Very little data were submitted.
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The data base remains very limited and inconclusive. The Agency agrees
that the more recent data generally tend to have a lower percentage of
$03 than the earlier data. Some of the recent data still suggest, how-
ever, that there is a potential for large amounts of $03 to be emitted,
which would be undetected by a standard using $62 as the regulated
pollutant. Thus, regulating $63 only will not necessarily reflect
the potential control of SOX that can be obtained by SOX reduction
catalysts.
The Agency agrees with Commenter IV-K-2 that transmissometers would
not measure uncondensed $03 emissions in the stack. Opacity compliance
determinations, however, are made through visible emissions reading of
the plume opacity. Transmissometers are intended to show proper opera-
tion and maintenance of the particulate control device. Some informa-
tion is available that indicates plume opacity is higher than in-stack
opacity when higher sulfur fuels are burned. Thus, it is the plume
opacity that is affected by the condensation of $03 and, to the extent
this condensation affects the ability of a source to comply with the
(plume) opacity standard, it may also help limit the emissions of
$03. The Agency requested, but did not receive, data on this possi-
bility. If sufficient data had been presented, then the Agency would
have considered changing the regulated pollutant for FCCU's without
add-on controls from SOX to S02 so that SC>2 GEMS's could be used for
compliance determinations.
The Agency agrees that using S02 as the regulated pollutant would
allow the same monitoring technique to be used as for add-on controls
and that cost savings would likely be gained. However, the Agency is not
having an S02 standard for FCCU's without add-on controls, and using
S02 CEMS's will not necessarily yield more consistent and reliable
sample results than would keeping an SOX standard and using Method 8
sampling. There is no need or requirement that the same monitoring
technique be applied to alternative standards. Each possible monitoring
technique is evaluated on its own merit. The facts raised by Commenter
IV-K-2 that other refinery sources are regulated only for S02 and that
EPA usually regulated only S02 shed no light on whether an SOX standard
is appropriate for this source.
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2.3 DESIGNATION OF AFFECTED FACILITY
Comment: .
Several commenters (IV-D-1, IV-D-15, and IV-D-16) recommended a
broadening of the designation of the affected facility. Two commenters
(IV-D-1 and IV-D-15) stated that the FCCU reactor should be included
as part of the affected facility because of the dependency between
the reactor and regenerator. One commenter (IV-D-15) suggested that,
for an FCCU reactor using multiple regenerators, the affected facility
should include the reactor and all of the regenerators serving the
i '
reactor, because it may be possible that SOX control systems used on
multiple regenerator systems are more efficient. Another commenter
(IV-D-16) recommended that the affected facility should include the
FCCU reactor, fractionator, and gas recovery unit. The commenter
stated that hydrocarbon streams recycled from the fractionator or gas
recovery unit are defined as "fresh feed" to the affected facility.
Therefore, by increasing the amount of these low sulfur streams recycled
to the FCCU reactor, a refiner could circumvent the intent of the feed
sulfur cutoff, because it would be easier to maintain a feedstock
sulfur content below the 0.30 weight percent sulfur level by recycling
these.
Response:
The rationale for selection of the affected facility was presented
in the preamble to the proposed standards (49 FR 2060). As stated in
the preamble, SOX are generated in and emitted from the FCCU. regenerator.
The designation of the regenerator of each FCCU as the affected facility,
rather than the entire FCCU, would lead to bringing replacement equip-
ment under these standards sooner and thus, would adhere to the purpose
of Section 111 of the Clean Air Act.
The EPA agrees that identifying each FCCU regenerator as the
affected facility for multiple regenerator configurations is unreason-
able. If only one regenerator in a multiple regenerator configuration
were to become subject to the standards, it would be impossible in some
multiple regenerator ducting arrangements to isolate and measure the
SOX content of the exhaust gases from the affected regenerator.
Furthermore, because the refiner would want to minimize the cost and
downtime for revamping work on the unit, it is unlikely that only one
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regenerator in a multiple regenerator configuration would be modified
or reconstructed without the others. Therefore, the affected facility
is now defined to include all regenerators serving an FCCU reactor.
The proposed definition of "fresh feed" specifically excluded
those petroleum derivatives recycled within the FCCU. To ensure that a
refiner would not circumvent the feed sulfur cutoff by adding low-
sulfur content recycle from the fractionator and gas recovery unit,
EPA has revised the definition of "fresh feed" in the regulation. The
revised definition specifically identifies petroleum derivatives from
the FCCU, fractionator, and gas recovery unit as recycle, and thus
excludes them from the definition of "fresh feed."
Comment:
One commenter (IV-D-12) stated that the proposed standards should
not apply to Reduced Crude Conversion (RCC) processes or Asphalt Residual
Treatment (ART) units. The following justification was provided:
1. An FCCU processes clean gas oils while the commenter's RCC unit
processes asphalt-containing long residuum (reduced crude),
which has heavy metal constituents, high carbon residue, and
higher sulfur content. Consequently, RCC units may have a
very different catalyst design.
2. The refining objective for an RCC unit (residual upgrading) is
different from an FCCU processing distillate oils.
3. The ART process employs an adsorbent rather than a cracking
catalyst.
4. The ART process objective is minimal change in the feedstock
other than metals removal. It is a feedstock upgrading
process.
5. The ART and RCC units are operated under conditions critical to
residual upgrading. These units are designed and operated to
avoid undesirable secondary reactions. Control of heat release
is accomplished by multiple stage regeneration, limited carbon
burn, and catalyst heat exchange.
Response;
To upgrade residual feedstocks and to increase gasoline and middle
distillate product yields, new processes termed heavy oil cracking
(HOC), which includes RCC, and ART are being installed at refineries.
The HOC units are FCCU's that process residual and other heavy oil
feedstocks. As in a conventional FCCU, emissions occur as a result of
catalyst regeneration. Emissions of SOX may, in fact, be greater from
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HOC units than from other FCCU's because HOC feedstocks have a higher
coke make rate than gas oil feeds, and because a greater portion of the
sulfur in HOC feedstocks forms coke than that in gas oil feeds. The
EPA's analysis of SOX emissions, control costs, and cost effectiveness
for HOC units showed that the proposed standards for FCCU's are achiev-
able and affordable for HOC units. The results of this analysis were
presented in Appendix F of the proposal BID.
Emissions, emission control, and control costs for the ART process
were further evaluated by EPA (see Docket A-79-09, item IV-B-17). The
differences stated by the commenter between an ART unit and an FCCU do
exist. The ART process does not employ a catalyst, but rather uses an
inert microspheric contact material that collects contaminants. The
objective of the ART process is feedstock upgrading, not processing,
and some of the operating conditions may vary significantly.
Nevertheless, important similarities in regenerator configuration,
operation, and emissions exist that warrant the regulation of an ART
unit under the FCCU NSPS. For both an ART unit and a conventional
FCCU, regeneration is performed to burn off coke from the catalyst or
contact material, thereby restoring it for reuse in the unit. Opacity
and emissions of CO, SOX, and particulate from an ART unit regenerator
during normal operation are expected to be within the range of emissions
from all types of FCCU regenerators, including those on HOC's. The EPA
evaluated control feasibility and cost for an ART unit based on reported
emissions (see Docket A-79-09, item IV-D-30), and determined that
control of an ART unit by a scrubber was applicable and had a reasonable
cost. Based on a scrubber SOX efficiency of 90 percent,, the scrubber
cost effectiveness calculated for the ART unit is below the range of
cost effectiveness expected for FCCU's. In addition, costs to control
CO emissions, if necessary, and particulate emissions are estimated to
be reasonable.
The similarity in emissions from the regenerator and the avail-
ability of control equipment at a reasonable cost indicate that the ART
unit regenerator can meet the FCCU standards. The facts that the
objective of the ART process is different than that of the FCCU and
that the material being regenerated is not a catalyst are hot signif-
icant reasons to support the contention that an ART unit should not be
subject to the FCCU NSPS. Therefore, the proposed standards covered both
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ART and HOC units and the promulgated standards continue to require
that an ART unit, HOC, or any other similar type of fluidized bed
treatment unit regenerator achieve the FCCU particulate, opacity, CO,
and SOX standards.
2.4 FORMAT OF THE STANDARDS
Comment:
Several commenters (IV-D-3, IV-D-10, IV-D-11, IV-D-14, and IV-K-12)
stated that EPA should establish a single SOX standard for FCCU's. The
reasons cited by the commenters for setting a single standard are: (1)
a single standard would allow refiners the options and flexibility of
determining the most cost-effective method of meeting that limit; and
(2) a single standard would comply with Section lll(h) of the Clean Air
Act which implies that the Administrator should prescribe a performance
standard rather than a work practice or equipment standard, where
feasible to do so.
Response:
There are three techniques applicable to control FCCU SOX emissions:
(1) scrubbing of FCCU regenerator exhaust gases; (2) using SOX reduction
catalysts; and (3) using low sulfur FCCU feedstocks obtained by feedstock
hydrotreating or from naturally occurring low sulfur crude oils. The
Clean Air Act requires EPA to develop standards of performance for new,
modified, and reconstructed FCCU regenerators that reflect the best
method of continuous emission reduction, considering costs, environmental,
energy, and nonair quality health impacts.
To develop SOX emission standards for FCCU's, EPA evaluated all
available techniques for controlling FCCU SOX emissions. Upon thorough
consideration of the availability, SOX emission reduction capability,
and impacts associated with each of these techniques, EPA determined
that scrubbing systems effectively control SOX emissions from all types
of FCCU applications, and represent BDT for FCCU SOX and S0£ emissions.
However, for many FCCU applications, SOX emissions can be reduced
effectively by using SOX reduction catalysts or by using low sulfur
FCCU feedstocks obtained by either hydrotreating high sulfur feedstocks
or processing naturally occurring low sulfur crude oils. For the
sources that can effectively and continuously reduce SOX emissions
without the use of add-on controls, EPA concluded it is reasonable to
establish alternative standards.
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The standard for add-on controls requires that the control
device achieve a 90 percent reduction in S02 emissions. The percent
reduction format was selected because it best reflects the performance
of add-on controls for all expected feed sulfur levels. This is
consistent with Section lll(a)(l), which requires that the standard
reflect...application of BDT. A standard without add-on controls
also was established to allow refiners the flexibility to use SOX
reduction catalysts, low sulfur feedstocks, or a combination of both
techniques. Although these techniques may be less effective at reducing
SOX emissions than scrubbers for some FCCU applications, they have lower
costs and smaller nonair environmental impacts when compared to using a
scrubber. The EPA judged that it is reasonable to give up some emission
reduction by establishing a standard without add-on controls in return
for the other benefits afforded by using SOX reduction catalysts,
hydrotreating, or low sulfur feedstocks instead of scrubbers. If a
refiner believes that using SOX reduction catalysts, hydrotreating, or
low sulfur feedstocks for his particular FCCU application will not achieve
the standard without add-on controls, then the refiner can still
install and operate an add-on control device that achieves 90 percent
reduction of S02 emissions.
The standards are performance standards and are consistent with
Section 111 of the Clean Air Act. Neither the add-on control standard
nor the standard for FCCU's without add-on controls specifies the
type of controls that must be used or exactly how the controls are to
be operated to achieve the standard.
Comment:
Several commenters (IV-D-2, IV-D-3, IV-D-10, and IV-D-11) stated
that the percent reduction format proposed by EPA for the standard with
add-on controls should be changed to an emission limit format. An
emission limit standard would simplify compliance and would allow a
refiner to control SOX emissions to a specific level rather than a
percent reduction, which is a moving target.
Response:
Compliance'with the percent reduction format requires conducting a
performance source test at both the inlet and outlet of the control
device.. The EPA agrees that an emission limit format for the standard
for add-on controls would simplify compliance procedures by requiring
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source testing only at the control device outlet. However, this format
would not reflect the best level of control achievable by scrubbers.
As discussed above, 90 percent reduction represents BDT. An emission
limit format could result in greater emissions. A refiner may perceive
the percent reduction format to be a "moving target" because with a
percent reduction format there is no specific emission level that is to
be achieved at the control device outlet. Rather, the outlet emission
level will vary depending on the inlet concentration to the control
device. The proposed monitoring requirements that specified a control
device outlet S02 monitor only may have contributed to the commenters1
opinion that it is difficult to operate a control device to achieve a
constant percent reduction. With only a scrubber outlet S02 monitor,
the refiner had no means of monitoring the percent reduction achieved
by the control device. The EPA has changed the monitoring requirements
and continuous S02 monitors now are required at the inlet and outlet to
the control device (see Section 6.2). Consequently the refiner will
have the monitoring results available to determine the percent reduction
achieved by the control device. The percent reduction, calculated by
using the continuous monitoring results, thus becomes a fixed rather
than a moving target for refiners to achieve.
Comment:
Three commenters stated that the coke burn-off format proposed by
EPA for the standard for FCCU's without add-on controls is inappropri-
ate. One commenter (IV-D-9) stated that the coke burn-off format
allows no latitude for variation in coke sulfur content and will
discourage process improvements. The format penalizes refiners who
implement process improvements that increase yields of light products .
while reducing coke make because allowable emissions will be reduced,
perhaps to an unachievable level. The commenter suggested that EPA
consider a sliding scale format that allows for variation in coke
sulfur content. A second commenter (IV-D-1) stated that the coke
burn-off format was considered during the development of the South
Coast Air Quality Management District (SCAQMD) Rule 1105, but it was
concluded that this format was inappropriate because coke burn-off
rates are not normally recorded and can change significantly. Instead
of a coke burn-off format, the SCAQMD rule uses a format expressed in
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terms of kilograms of S02 per thousand barrels of feed. A third com-
menter (IV-D-8) stated that a percent reduction format should be
adopted rather than a nonflexible limit of sulfur on coke.
Response:
Based on a sensitivity analysis presented in Appendix F of the
proposal BID, EPA concluded that the coke burn-off format relates
well to normal fluctuations in SOX emissions from FCCU's processing a
variety of feeds. This is because SOX emissions are related directly
to the coke sulfur content. .Normally, FCCU's are operated to limit the
amount of coke that can be burned off in the regenerator. Process
improvements that reduce the coke make rate are made to allow the
refiner to process more feed through the unit until the unit is again
limited in the amount of coke it can burn off. An example of a process
improvement that results in reduced coke make is high temperature
regeneration (HTR). The initial result of HTR would be reduced SOX
emissions from FCCU's on a mass basis. However, SOX emissions in terms
of coke burn-off would remain the same because SOX emissions are
related to the sulfur on coke. Thus, the refiner could increase
throughput until the unit is again coke burn-off limited and still be
within the standard even though emissions would increase. This format
offers greater refining flexibility than a mass of SOX per unit of feed
basis. The commenters provided no new information to refute this
conclusion. i
A sliding scale format that allows for variation in coke sulfur
content would be difficult to enforce because the sulfur content of the
coke on catalyst is not readily obtainable. For this reason, EPA
considers a sliding scale format unreasonable.
The EPA considered a percent reduction format for the standard for
FCCU's without add-on controls. This format would require the SOX
reduction catalyst to reduce FCCU emissions by a set percentage. The
EPA did not select a percent reduction format because of compliance con-
siderations. With SOX reduction catalysts, there is no uncontrolled
or inlet SOX concentration to measure. Thus, it would be impossible to
determine through stack testing the percent reduction being achieved by
the catalysts. An alternative method would be to estimate the percent
reduction achieved by SOX reduction catalysts using EPA's correlation
for feed sulfur and SOX emissions. However, EPA's correlation represents
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an average for all FCCU's and feedstocks. While the correlation is
useful for analyzing the overall impact of the standards, inlet SOX
concentrations may be lower or higher than the level predicted by the
correlation for a specific FCCU and feedstock. Thus, the correlation
cannot be used on a case-by-case basis. The cost to develop a
separate correlation for each feedstock and FCCU affected by the stan-
dards is unreasonable. Therefore, EPA concluded that use of a correla-
tion for determining potential uncontrolled SOX emissions is not
practical. Because there is not a practical method for determining the
SOX inlet concentration when using SOX reduction catalysts, EPA did not
select a percent reduction format.
The EPA considers the. coke burn-off format reasonable because of
its direct relationship to the sulfur-on-coke relationship. The
coke burn-off format is identical to the format selected for the NSPS
particulate standard; the coke burn-off rate can be recorded reasonably
and would be readily available.
2.5 LEVEL OF STANDARDS
2.5.1 Level for Add-On Control Standard
Comment:
Two commenters (IV-D-2 and IV-D-4) questioned the level of the
standard for add-on controls. One commenter (IV-D-4) stated that the
standard for add-on controls is excessively stringent. Another
commenter (IV-D-2) stated that the standard for add-on controls
should be 300 vppm rather than 50 vppm because a 300 vppm standard is
approximately equivalent to a 90 percent SOX reduction for most FCCU
applications. In contrast, three commenters (IV-D-1, IV-D-11, and
IV-D-18) stated that the standard is reasonable. One commenter
(IV-D-11) stated that BDT for add-on controls at 90 percent by weight
reduction (or 50 vppm) is achievable. Another commenter (IV-D-18)
stated that the options provided for achieving compliance with the
proposed standards are realistic when analyzed in terms of existing
industry processing and emission control practices.
Response: •
The standard for add-on controls requires that FCCU S0£ emissions
are reduced by 90 percent or to 50 vppm, whichever is less stringent.
The standard is based on test data that demonstrate that scrubbers can
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achieve 90 percent reductions in FCCU SOX emissions. The 50 vppm
outlet concentration level was established because scrubber SOX removal
efficiency tends to decrease at low inlet SOX concentrations (see
Section 3.1 of this document). Therefore, the 50 vppm level is not
intended to compare with the 90 percent level for most cases.
The EPA disagrees that a 300 vppm standard is equivalent to
90 percent reductions for most FCCU applications. Most FCCU's are
processing feedstocks with sulfur contents ranging from 0.3 to 2 percent
by weight, with corresponding uncontrolled SOX emissions ranging from
300 to 2,000 vppm. Fluid catalytic cracking unit SOX emissions when
controlled by scrubbers would range from 50 to 200 vppm. Thus, a 300
vppm SOX emission standard would not compare to 90 percent reduction in
most cases. In summary, a 300 vppm standard does not represent the level
achievable by application of BDT and, therefore, was not selected as
the level for the standard for add-on controls.
2.5.2 Level of Standard for FCCU's Without Add-On Controls
Comment:
Seven commenters (IV-D-2, IV-D-3, IV-D-6, IV-D-7, IV-D-8, IV-D-9,
and IV-D-1Q) stated that the standard for FCCU's without add-on
controls Should be set at 13 kg SOX/1,000 kg coke burn-off because:
(1) increasing the level to 13 kg SOX/1,000 kg coke burn-off would
have a limited impact on ambient air quality; (2) 80 percent reductions
by SOX reduction catalysts are not supported by the limited commercial
tests cited by EPA; and (3) a 13 kg SOX/1,000 kg coke burn-off emis-
sion limit would allow more refiners to use the catalysts rather than
add-on controls since SOX reduction catalysts are the only cost-
effective and environmentally acceptable control alternative. Two
commenters (IV-D-6 and IV-D-10) added that an increase in the emission
limit should be made to account for the change in the controlled pollu-
tant from S02 to SOX. In contrast, two commenters (IV-D-1 and IV-D-18)
supported the levels proposed by EPA. One commenter (IV-D-1) reported
that Phase II of the SCAQMD Rule 1105 is more stringent than the stan-
dard. The commenter stated that SOX reduction catalysts are expected
to be used to meet Phase II of the rule. Another commenter (IV-D-18)
stated that the emission reduction required by the standard is essen-
tially equivalent to the level of control required by the Texas Air
Control Board (TACB) to control FCCU SOX emissions.
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Response:
The EPA disagrees with the comment that SOX reduction catalysts
are the only cost-effective and environmentally acceptable control
alternative. The EPA determined, considering costs, environmental,
energy, and nonair quality health impacts, that scrubbers effectively
control FCCU SOX emissions and are BDT. Furthermore, as an alternative
to using SOX reduction catalysts, refiners may use hydrotreating or low
sulfur feedstocks to achieve compliance with the 9.8 kg SOX/1,000 kg
coke burn-off level.
The level of the standard (9.8 kg SOX/1,000 kg coke burn-off)
was selected to allow refiners flexibility to use SOX reduction
catalysts with best currently available performance, and to encourage
the further development of the catalyst technology. For many feed-
stocks, especially those with lower sulfur content, the emission
reduction needed to achieve the level of the standard is less than
80 percent. For example, a feedstock with 0.5 weight percent sulfur
would need approximately 50 percent reduction in SOX emissions to
achieve the level of the standard. In response to the comments, EPA
contacted a number of companies known to be developing SOX reduction
catalysts to request updated information on the performance and avail-
ability of developmental SOX reduction catalysts. Based on a survey of
SOX reduction catalyst developers, current commercial SOX reduction
catalyst test data have been reported by the developers to reduce FCCU
SOX emissions by 65 to 75 percent. The test data reported by the
developers span a wide range of catalyst performance; some data points
show catalyst performance as high as 90 percent. As the technology
continues to develop, refiners will be able to use the catalyst
technology to achieve the standard for a greater range of feedstocks.
Based on the results of SOX reduction catalyst tests, EPA believes
the level of the standard for FCCU's without add-on controls is
reasonable. The determination of the level of this standard included
consideration of the benefits of SOX reduction catalysts and the
increase in SOX emissions compared to the BDT of scrubbing. Because the
primary purpose of the standards is to reduce future FCCU SOX emissions,
and scrubbers can achieve cost-effective emission reductions, EPA
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concluded that it is not reasonable to further increase allowable
emissions by raising the level of the standard.
The EPA proposed standards regulating total FCCU SOX emissions
because $03 can comprise a substantial portion of the FCCU SOX emis-
sions when SOX reduction catalysts are used, and the potential SOX
emissions from FCCU regenerators can be significant. Both S02 and
SOs are emitted from FCCU regenerators. Data from source tests indicate
that $03 usually comprises less than 10 percent of the total SOX emis-
sions. However, with high excess air and certain types of catalysts or
catalyst additives, $03 can comprise a substantial portion (up to 60
percent) of the total SOX emissions. The SOX reduction catalyst data
used by EPA to select the level of the standard are reported in terms
of total SOX emissions. Thus, EPA's choice for the level of the stan-
dard took into consideration that the controlled pollutant is SOX
instead of S0£.
2.5.3 Feed Sulfur Cutoff
Comment:
Two commenters (IV-D-4 and IV-D-11) stated that an arbitrary feed
sulfur cutoff of 0.30 weight percent sulfur is too restrictive. One
commenter (IV-D-11) wrote that a feed sulfur cutoff equivalent to 9.8 kg
SOX/1,000 kg coke burn-off should be established. This would be
accomplished by developing a correlation between feed sulfur content
and SOX production using test data.
Response;
The selection of the feed sulfur.cutoff level of 0.30 weight
percent was not arbitrary. As was discussed in the preamble to the
proposed standards, the feed sulfur cutoff level was selected based on
consideration of the costs for application of scrubbers to control SOX
emissions from FCCU's processing low sulfur feedstocks, and the feed-
stock sulfur levels refiners^ are expected to be processing if they
elect to use naturally occurring low sulfur feed or to hydrotreat high
sulfur feeds.
A correlation between FCCU feed sulfur content and SOX emissions
is presented on p. 3-18 of the proposal BID. The correlation is
based on test data for a large number of FCCU's and feedstock types.
Based on this correlation, an FCCU SOX emission level of 9.8 kg SOX/
1,000 kg coke burn-off corresponds to a feed sulfur level of
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approximately 0.3 weight percent. Thus, the feed sulfur cutoff level
established by EPA is approximately equivalent to the standard for
FCCU's without add-on controls. There is no need for each refiner to
determine, on a case-by-case basis, a correlation between feed
sulfur content and SOX production.
2.6 AVERAGING TIMES
Comment:
Commenters (IV-D-2, IV-D-3, IV-D-4, IV-D-6, IV-D-10, IV-D-11, and
IV-D-20) stated that the averaging time for the standards should be
increased. Several of these commenters (IV-D-3, IV-D-6, IV-D-10, and
IV-D-11) stated that a 7-day averaging period for compliance would be
appropriate for the standards for add-on controls and for FCCU's
without add-on controls for the following reasons: (1) a 7-day
averaging time would be consistent with the averaging time for the feed
sulfur cutoff; (2) no process variables can be adjusted in a 3-hour
period to regulate S02 emissions when using SOX reduction catalysts;
and (3) 7 days would account for variation in S02 inlet concentrations
to the control device whereas 3 hours would not. Another commenter
(IV-D-2) stated that the excess emissions averaging times should be
lengthened to 7 days for the same variability reasons. One of the
commenters (IV-D-11) stated that the averaging period for compliance
determinations should be set at 7 days with daily peaks not exceeding
13 kg SOX/1,000 kg coke burn-off. Two commenters (IV-D-4 and IV-D-20)
stated that the averaging period for the add-on control and 9.8 kg/
1,000 kg coke burn-off standards should be a rolling 30-day period.
Response:
Upon evaluation of the comments on variability, EPA agreed with the
commenters that the averaging time for compliance with the standards
for FCCU's with and without add-on controls should be lengthened.
The EPA assessed long-term variability by statistically analyzing the
continuous S0£ monitoring data from an EPA study of a sodium scrubber
applied to an FCCU (see Docket A-79-09, item IV-B-5). Several of the
commenters pointed to this study as an example of the potential vari-
ability in scrubber inlet conditions due to variability in FCCU opera-
tion and feedstocks. The hourly percent reductions achieved by the
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scrubber were used in a time series analysis to compare various
averaging times. For a given averaging time, the time series model
estimated the minimum scrubber performance level that would be expected
once in 10 years.
The results of this analysis showed that 3 hours is too short to
ensure that exceedances of the standard would not occur due to normal
variability. However, with a 7-day rolling average, the minimum
performance level estimated once in 10 years was greater than the level
of the standard. .This result indicates that 7 days would adequately
account for normal variability in scrubber performance.
Because the SOX reduction catalyst technology is still in the
developmental stages, there were no tests that were appropriate to use
for long-term analysis.- However, EPA agreed with the comment that
7 days would allow a reasonable amount of time to adjust process vari-
ables after such changes as to a different feedstock, whereas 3 hours
would be too short. Therefore, EPA concluded that a 7-day averaging
time would be reasonable for both the standards for add-on controls
and for FCCU's without add-on controls. The EPA did not choose a
longer time because 7 days is long enough to eliminate exceedances of
the standard due to normal variation. The revised proposed standards
included a revision of the compliance averaging time from 3 hours to
7 days. Six commenters (IV-K-1, IV-K-3, IV-K-5, IV-K-6, IV-K-9,-and
IV-K-10) all agreed with EPA:'s revision. No commenters disagreed.
Comment:
Two commenters (IV-D-4 and IV-D-20) stated that the averaging
period for the feed sulfur cutoff should be a 30-day rolling average
period. The use of the 30-day period would be appropriate because
a 30-day rolling average period is used for the fossil fuel-fired steam
generator NSPS.
Response:
Whenever practical, EPA determines NSPS regulatory requirements on
an individual source category basis. It is not appropriate to use a
30-day rolling average period for the FCCU feed sulfur cutoff standard
simply to copy the fossil fuel-fired steam generator NSPS. The
proposed 7-day averaging period was selected by EPA after careful
consideration of a range of averaging periods. A daily averaging time
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was judged by EPA to be too short to account for sampling variability.
Also, a daily averaging time would constrain a refiner's flexibility in
blending different types of feedstocks for processing in the FCCU. A
7-day averaging time would reduce sampling variability and increase
refiner flexibility in selecting the FCCU feedstock mix. However,
increasing the averaging time beyond a 7-day period would allow feed-
stocks with sulfur contents significantly greater than 0.30 weight
percent to be processed in the FCCU during a portion of the sampling
period. Consequently, a refiner would be able to process high sulfur
feedstocks without having to use any SOX controls. Therefore, EPA
selected the 7-day averaging period to allow reasonable flexibility
to the refiner for processing different sulfur content feedstocks.
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3.0 CONTROL TECHNOLOGY COMMENTS
3.1 SOX SCRUBBERS
Comment:
Two commenters (IV-D-5 and IV-D-9) challenged EPA's assessment of
the performance of scrubbers as applied to FCCU's. They stated that the
proposed standard for add-on controls is founded upon an insufficient
data base; that scrubber performance on FCCU's processing higher sulfur
feeds (2 percent or more sulfur) should be confirmed. One commenter
(IV-D-9) wrote that there can be subtle differences among scrubber
feeds and chemical constituents containing sulfur that affect scrubber
removal efficiencies. Thus, scrubber performance for boilers firing
high sulfur coal differs from scrubber performance for FCCU's processing
high sulfur feedstocks.
Response:
Scrubber SOX control is a function of the scrubbing liquor sorbent
and good contacting between the S0x-containing flue gas and the
scrubbing liquor. Based on engineering judgment, scrubbers applied to
higher S0x-containing gas streams would be expected to operate as
well as those scrubbers applied to lower S0x-containing gas streams.
However, because scrubbers have not been applied to FCCU's processing
high sulfur feeds, none was available for testing by EPA to confirm
scrubber performance. Therefore, EPA compared the composition of FCCU
exhaust gases to industrial boiler flue gases to determine if the
performance of sodium scrubbers for industrial boilers is applicable to
FCCU's processing high sulfur feedstocks. This comparison showed that
the coke formed on the FCCU catalyst is a carbonaceous material similar
to the coal used in solid fuel-fired industrial boilers. The catalyst
coke is burned off the catalyst during regeneration by adding air to
the regenerator. The regeneration process is thus similar to the
combustion processes that take place in boilers. Given the similar-
ities between catalyst coke and other solid fuels, the combustion
process that takes place in the FCCU regenerator is expected to yield
exhaust gases that are similar to those derived from coal-fired boilers.
A comparison between FCCU regenerator exhaust gases and industrial
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boiler flue gases was presented in Table 4-3 in the proposal BID. The
comparison showed that the ranges in concentration of most FCCU regen-
erator exhaust gas constituents [nitrogen (Ng), oxygen (02), COg, SOX,
nitrous oxides (NOX)] are similar to the boiler flue gas concentrations.
Scrubber systems installed o;n FCCU regenerators will thus experience
similar inlet concentrations as boiler scrubber systems. The primary
difference between FCCU regenerator exhaust gases and boiler flue gases
is the particulate emissions. Boiler particulate emissions are higher
and composed primarily of fly ash. Catalyst fines comprise the majority
of regenerator particulate emissions. In an industrial boiler application,
fly ash is typically collected upstream of a non-venturi type scrubber.
A similar type of scrubber applied to an FCCU would require particulate
control upstream from the scrubber. According to scrubber vendors
(refer to Docket A-79-09, item IV-J-6), the particulates that pass
through the particulate control device would not affect the design of
the scrubber regardless of the application. This is because catalyst
fines are no more erosive than fly ash and neither type of particulate
would interfere with the scrubbing reaction. Thus, the difference in
particulates from an industrial boiler and an FCCU are not expected to
affect scrubber performance. Hydrocarbon emissions from FCCU regenerators
may be higher than those from boilers. The presence of hydrocarbons in
the FCCU gas stream will not affect scrubber operation or performance.
Due to the low solubility of hydrocarbons in the aqueous scrubbing
liquor, the hydrocarbons will not be absorbed but pass through the
scrubber to the atmosphere. Other differences in gas compositions are
minor and are not expected to invalidate the applicability of scrubber
systems for FCCU regenerators.
The similarities in flue gas flow rates and characteristics
between industrial boilers and FCCU's (refer to Docket A-79-09, item
II-B-21) and consideration of their differences support the reasonable
conclusion that industrial boiler sodium scrubber performance is
applicable to FCCU's. Source test results for a sodium scrubber
applied to an industrial boiler burning a high sulfur fuel show that
sodium scrubbers can achieve at least 90 percent reduction in SOX emis-
sions at high inlet SOX concentrations (refer to Docket A-79-09, item
II-A-11)., Therefore, EPA has reached a reasonable conclusion that the
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FCCU standard is achievable and that scrubbers are applicable over the
expected range of FCCU regenerator exhaust gas sulfur concentrations.
The commenter did not provide any information to show that
scrubber performance for industrial boilers would be different than
scrubber performance for FCCU's. Therefore, in consideration of the
above mentioned similarities, EPA believes that it is reasonable to
expect that scrubber performance for industrial boilers is applicable
to FCCU's.
Comment:
One commenter (IV-D-16) asked if the licensor of the sodium
scrubber system currently applied to FCCU's will guarantee 90 percent
SOX removal as opposed to S0£ removal.
Response:
Since proposal, the regulated pollutant has been changed to S02-
As discussed below, 90 percent SOX reduction has been guaranteed,
and thus SOg removal would similarly be guaranteed.
Sodium scrubbers applied to FCCU's are venturi-type scrubbers
designed to achieve high levels of SOX emission reduction. Exxon
Research and Engineering (ERE) is the licensor of all sodium scrubbers
currently applied to FCCU's. The EPA test results for the ERE scrubber
system show that the scrubbers have achieved SOX control efficiencies
in excess of 95 percent (see Docket A-79-09, items II-I-42 and II-I-50).
The ERE has guaranteed SOX control efficiencies of 90 percent for the
scrubbers it has installed for other refining companies (see Docket
A-79-09, items II-D-41 and II-D-95). However, ERE states that at low
inlet concentrations (less than 500 vppm), SOX removal decreases. Due
to sampling and process fluctuation, a minimum outlet concentration of
50 vppm is reasonable (see Docket A-79-09, items II-B-10 and II-D-50)
and is included in the standard.
The EPA contacted other sodium scrubber vendors for information
regarding the applicability and performance of non-venturi type scrub-
bers (spray tower or tray tower scrubber designs) to FCCU's. These
vendors reported that non-venturi type scrubbers installed to control
FCCU SOX emissions at a location downstream from a particulate control
device should achieve at least 90 percent reductions in SOX emissions
(see Docket A-79-09, item IV-J-6). Based on these responses, EPA
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believes that, besides ERE, other sodium scrubber vendors will guarantee
90 percent SOX removal in FCCU applications.
Comment: '
One commenter (IV-K-2) stated that EPA does not have the authority
to issue an NSPS because no add-on control device for sulfur oxide
emissions has been adequately demonstrated. The commenter made this
claim by maintaining that if "a 3-hour averaging period is too short
to ensure that exceedances of the proposed standard would not occur due
to normal FCCU or control system variability," then tests of this dura-
tion would not prove the adequacy of add-on controls for sulfur oxide
emissions. In that event, the commenter noted, the Agency has no data
proving the adequacy of devices to lower FCCU SOX emissions, since "all
the data in the BID Appendix C are for short periods."
Response:
Since the standards were originally proposed, the Agency changed
the regulated pollutant from SOX to S02 for add-on controls. Even
if the regulated pollutant for the standard for add-on controls were
still SOX, the Agency disagrees that the lack of long-term SOX emis-
sion reduction data fails to support a conclusion that scrubbers have
been adequately demonstrated; for SOX emissions. [Appendix C does
contain long-term (12 day) test data for S02-] The Agency believes
that the ability of well-operated and maintained scrubbers in each
of the short-term tests to attain well over 90 percent SOX emission
reduction supports a scrubber's ability to attain at least 90 percent
SOX emission reduction over a 7-day period, because a 7-day averaging
period gives refinery operators more time to correct minor problems in
scrubber performance and adjust process variables, such as feedstock
changes, whereas a 3-hour period does not. Thus, the Agency disagrees
with the commenter's conclusion, and believes that add-on controls
are adequately demonstrated for SOX emissions.
Comment:
One commenter (IV-K-12) stated that EPA's reliance on flue gas
scrubbers: for effective $03 reduction is not warranted. The commenter
added that the company has test data, available to the Agency upon
request, that indicate that $03 percent removal from scrubbers on oil-
fired steam generators at a Western production field is very low, while
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S02 percent removal is much higher. According to the commenter,
scrubbers are known to be less effective for submicron particulates,
although they are efficient for S02 and particulate removal. ;
Response:
The Agency appreciates the concerns expressed by the commenter
that flue gas scrubbers are not effective for control of $03 emissions.
The EPA agrees that scrubber systems may not be as effective in
controlling 503 as in controlling S02- However, as shown in Appendix C
of the BID, data on $03 removal by scrubbers on FCCU regenerators
indicate that $03 removal efficiency can be substantial (80 to 99
percent). This appears to contradict, as pointed out, the commenter's
data from scrubbers on oil-fired steam generators showing "very low"
$03 removal. The Agency does not believe this apparent contradiction
needs to be resolved for this rulemaking, although it is likely due
to differences in scrubber design. Although possibly not as low as
indicated by the commenter for all regenerators, $03 constitutes a
small portion of total SOX from regenerators using add-on controls.
Thus, the potential adverse environmental impact, even if scrubber
efficiency for SOs removal is actually "very low," will be very small.
Thus, the Agency believes that the decision to use S02 as the regulated
pollutant for regenerators with add-on controls is still appropriate.
Comment:
One commenter (IV-D-7) stated that flue gas desulfurization (FGD)
systems (i.e., scrubbers) have poor operability. Scrubber shutdowns
would result in more frequent FCCU shutdowns, reducing refinery
profitability and the nation's refining capacity.
Response:
At proposal, sodium scrubbing systems had been effectively applied
to seven FCCU regenerators at five refineries to control SOX emissions.
These seven FCCU regenerators represent 11 percent of nationwide FCCU
processing capacity. Since proposal, to the Agency's knowledge, two
other scrubbers controlling FCCU's at two refineries have begun opera-
tion. There is ho information to show that the operation of these
sodium scrubbers has increased FCCU shutdowns, reduced refinery capacity,
or reduced refinery profitability. The commenter provided no data to
support his claims. The sodium scrubbers applied to FCCU's have operated
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continuously with no failures between FCCU turnarounds (see Docket
A-79-09, item II-B-10). Thus, EPA continues to believe scrubbers are
an effective control method for reducing FCCU SOX emissions.
3.2 SOX REDUCTION CATALYSTS
Comment:
Commenters (IV-D-2, IV-D-7, IV-D-8, IV-D-9, and IV-D-10) stated
that SOX reduction catalysts are not demonstrated and cannot achieve
80 percent reductions in SOX emissions. Three commenters (IV-D-2,
IV-D-9, and IV-D-10) argued that EPA's data on 80 percent reductions in
SOX emissions are based on "ideal" feedstocks which are not representa-
tive of many refinery operations. One commenter (IV-D-7) pointed out
that SOX reduction catalysts will reduce a refiner's flexibility in
selecting FCCU cracking catalysts thereby affecting FCCU efficiency in
processing a variety of feedstocks. Another commenter (IV-D-9) stated
that: (1) the thoroughness of contact between the SOX reduction
catalyst and regenerator gases determines the maximum achievable SOX
control; (2) innovations in regenerator technology that reduce regen-
erator catalyst inventory will reduce contact time and thereby nega-
tively affect SOX reduction catalyst capability; (3) FCCU regeneration
efficiency deteriorates over the course of a 2- to 3-year period., and
this deterioration, which may affect the performance of SOX reduction
catalysts, is not addressed by any existing commercial test data; and
(4) the impact of feedstock sulfur content and composition on SOX
reduction catalyst effectiveness has not been fully recognized, and
could impede applicability of the catalysts at moderate feedstock
sulfur levels.
Response::
The EPA considers SOX reduction catalysts to be an emerging
technology. The standards allow for their use and thereby encourage
their further development. Current catalysts show promising results.
According to SOX reduction catalyst developers, current SOX reduction
catalysts can achieve SOX emission reductions of 65 to 75 percent (see
Section 2.5.2). Concerns and uncertainties about catalyst performance
remain because the technology is not fully developed at this time.
Developers of SOX reduction catalysts report that optimum performance
of SOX reduction catalysts is achieved when: (1) the FCCU is operated
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in the complete CO combustion mode with an excess oxygen content of 1.5
to 2.0 percent by volume in the FCCU regenerator exhaust gas; (2) FCCU
regeneration temperatures are maintained as low as possible while
maintaining complete CO combustion; and (3) good contact is maintained
between the SOX reduction catalyst and combustion air within the regen-
erator (see Docket A-79-09, item IV-B-9). Thus, it is possible that
operating restrictions may prevent some refiners from achieving the
standard for FCCU's without add-on controls using SOX reduction cata-
lysts only. In these cases, the refiner can achieve the standards by
using hydrotreated or low sulfur feedstocks, either alone or in
combination with SOX reduction catalysts, or by scrubbing.
Comment:
One commenter (IV-D-1) stated that recently completed studies show
that SOX reduction catalysts are capable of achieving the necessary SOX
reductions such that FCCU's operating at refineries located in Southern
California can achieve Phase II of Rule 1105 of the SCAQMD regulations
(60 kg S02/l,000 barrels of feed).
Response:
Phase II of Rule 1105 is more stringent than the standard for FCCtfs
without add-on controls proposed by EPA. The commenter's indication
that SOX reduction catalysts used in FCCU's located in Southern California
are expected to achieve an emission limit more stringent than this standard
supports EPA's determination that, in many cases, the SOX reduction
catalysts can achieve the level of the 9.8 kg SOX/1,000 kg coke burn-off.
3.3 LOW-SULFUR FEEDSTOCKS
Comment:
One commenter (IV-D-16) stated that the proposal BID did not
consider using virgin feedstocks that naturally contain low sulfur as
a control technique for FCCU SOX emissions. The commenter recommended
that the standards be reevaluated with consideration given to whether
the proposed standards will have any impact because of the probable
diversion of low-sulfur feedstocks to affected facilities. The com-
menter suggested that EPA calculate an "avoidance cost" for refiners
using low sulfur FCCU feedstocks.
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Response:
The proposal BID did not evaluate the exclusive processing of
low sulfur virgin feedstocks as a control alternative for reducing FCCU
SOX emissions. At the time the proposed standards were being developed,
refiners in the United State$ were experiencing limited supplies and
high prices for low sulfur feedstocks and crude oils. As a consequence,
new process units were installed at many refineries in order to allow
the processing of high sulfur crude oils. Thus, EPA did not believe
that low sulfur feedstocks would be a cost-effective alternative to
achieve these standards. The proposed standards, however, provided a
feed sulfur cutoff. The EPA recognizes that low sulfur virgin feed-
stocks are one means a refiner may choose to achieve compliance with
either the standard for FCCUls without add-on controls or feed sulfur
cutoff. At present, the availability of low sulfur crude oils has
improved and crude oil prices have significantly declined from the peak
1980 prices, but not all refiners will choose to limit FCCU processing
to low sulfur virgin feedstocks. Many refiners are currently proces-
sing crude oils containing 1 to 2 percent sulfur. Furthermore, the
potential exists that refiners will be processing higher sulfur content
crude oils within the next 5 years. Therefore, EPA expects that most
refiners will use SOX reduction catalysts, hydrotreating, or scrubbers
to achieve these standards.
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2 percent and that the median value of the feedstock sulfur content was
0.6 percent.
Response:;
The EPA developed model plants based on current industry practices
and on projected refining trends over a 5-year period. At the time the
model plants were developed, many refining companies were developing
and putting in place "bottom-of-the-barrel" refining to allow the pro-
cessing of higher sulfur feedstocks than currently practiced by the
industry. Model plants were, selected to span the range of possible
feedstock sulfur contents including "bottom-of-the-barrel" refining.
The EPA recognizes that most refiners currently are processing feed-
stocks containing up to about 2 weight percent sulfur, but the potential
exists that FCCU's (especially HOC's) will be processing higher sulfur
feedstocks within 5 years. Thus, although the 3.5 weight percent
sulfur model plant may not reflect current industry practice, a reason-
able potential exists that spme FCCU's will be processing during the
next 5 years feedstocks containing greater than 2 weight percent sulfur.
Therefore, it is reasonable to include the 3.5 weight percent sulfur
model plant in the impact analyses.
Comment:
One commenter (IV-D-16) asked why environmental, energy, and
economic impacts for calcium-based scrubbers were omitted from the
proposal BID.
Response:
The analysis of various scrubbing systems presented in Chapter 4
of the proposal BID was not meant to be all inclusive. The environ-
mental , energy, and economic impacts for calcium-based scrubbers applied
to FCCU's were not analyzed in the-proposal BID because if a refiner
does not use a sodium scrubber to achieve the standards, EPA expects
that the refiner would choose either a dual alkali or a regenerable
scrubber,system. However, a refiner could choose to use a calcium-based
scrubber to achieve these standards.
4.2 WATER IMPACTS
Comment:;
Five:commenters (IV-D-4, IV-D-5, IV-D-7, IV-D-16, and IV-D-20)
stated that the waste disposal aspects of the proposed standards are
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more complex than shown by the analysis presented in the proposal BID.
One commenter (IV-D-16) stated that no inland refiner would be able to
obtain a permit for the discharge of waste liquids from sodium
scrubbers. This commenter noted that sodium scrubbers have been used
only where oceans or large rivers could be used for disposal. The
commenter requested that EPA show that inland refineries could receive
discharge permits under Federal regulations. Another commenter (IV-D-5|
stated that refineries not located near large bodies of water would
need to install expensive additional wastewater treatment systems to
meet permitted discharge levels. This commenter cited the costs for
replacement of a fly ash pond for a Wei Iman-Lord scrubber used at a
power plant, and stated that settling ponds can be expected to receive
scrutiny under the Resource Conservation and Recovery Act (RCRA).
Response:
The EPA agrees that the waste disposal aspects associated with
application of scrubbers are complex. However, it is EPA's judgement
that sodium scrubbers or other types of scrubber systems can be installed
and operated at reasonable costs for refineries at inland locations.
The petroleum refining effluent guidelines (40 CFR 419) technically
apply to all wastewater from air pollution control devices when these
wastes are treated with the main refinery wastewater or are discharged
from the main refinery wastewater treatment system. The costs for the
treatment of these wastes are accounted for under the Part 419 regula-
tions. If the scrubber wastes are processed, treated, or discharged
separately from the main refinery wastewater collection, treatment, or
disposal system, then case-by-case determinations would be made to
regulate them. However, the major polluting characteristic of the
treated sodium scrubber wastestream is its high dissolved solids content,
about 6 percent solids by weight, which consists primarily of sodium
sulfates. There are currently no Federal regulations applicable to the
dissolved solids content of the sodium scrubber wastestream. Instead,
limitations on dissolved solids, where appropriate, would be developed
on a case-by-case basis, outside of the Federal effluent guidelines.
Such limitations would be based on whether the receiving water body can
accommodate a discharge and still comply with a State's water quality
standards. The EPA's Quality Criteria for Water specifies a maximum
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dissolved solids content of 500 mg/1 in fresh water. Sodium scrubber
wastes are produced at the rate of 0.19 to 0.38 m3 per minute. Unless
the receiving water body has sufficient flow for dilution, its dissolved
solids content will exceed the water quality criterion downstream from
the sodium scrubber discharge point.
For many refineries, the sodium scrubber wastewater would constitute
a small portion of the total refinery wastewater flow. Therefore, the
dissolved solids content of the combined scrubber and treated refinery
wastestreams may be within acceptable levels. A permit may be issued
for the discharge of sodium scrubber wastes to a publicly-owned treatment
works (POTW) by way of a sewer if the POTW receives sufficient total
wastewater flow from the municipality it serves such that the scrubber
wastestream dissolved solidsiare diluted to acceptable levels.
At proposal, there were seven sodium scrubbers operating to control
SOX and particulate emissions from FCCU's. All seven sodium scrubbers
are located at coastal locations. Since proposal, to the Agency's
knowledge, two other scrubbers controlling SOX and particulate
emissions from FCCU's have begun operation. At least one of these
discharges to salt or brackish water. No requirements exist for the
discharge of sodium scrubber wastes to brackish or salt water. Disposal
to brackish or salt water or discharge to a sewer will not be available
to all refiners in inland locations. This was acknowledged by EPA in
the proposal preamble. Where permits are unavailable for direct
discharge to surface waters or sewers, other wastewater disposal
methods may apply. These other disposal methods include evaporative
ponding, deep-well injection * and recycle. Evaporative ponding is
limited to those western States where evaporation exceeds precipitation.
Deep-well injection is of limited applicability due to the hazards of
groundwater contamination in'many parts of the United States. If a
refiner elects to install a sodium scrubber but cannot obtain a dis-
charge permit, he will need to use one of these disposal methods. The
added cost of these disposal methods would be greater than the disposal
cost used for EPA's cost estimates. However, other scrubber systems,
such as dual alkali, are available to meet the standard for add-on
controls at reasonable cost.
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Sodium scrubbers have been used extensively at inland locations to
control SOX emissions from industrial boilers. From a total population
of 47 sodium scrubbers currently applied to industrial boilers, 5 dis-
charge to a sewer, 9 discharge to surface water, 23 use ponding, 7 use
deep-wel 1 injection, and 1 uses recycle to dispose of the wastestream.
Therefore, it is possible for a refiner at an inland refinery location
either to obtain a permit to discharge sodium scrubber wastes to surface
water or sewers, or to use another means to dispose of the liquid wastes.
As mentioned above, other SOX scrubber systems with minimal
wastewater impacts are applicable to FCCU's at a reasonable cost.
These include dual alkali and spray drying scrubbing, which have no
significant liquid wastes but instead produce solid wastes; or WeiIman-Lord
and citrate scrubbing, which have no significant liquid wastes and
produce a salable sulfur product. These scrubbing systems have demon-
strated removal efficiencies of 90 percent on industrial boilers (see
proposal BID, Chapter 4). Due to the similarities between industrial
boiler and FCCU flue gases (discussed in Section 3.2), these scrubbing
systems are applicable to FCCU's. The costs and cost effectiveness of
these scrubbers were evaluated by EPA in the proposal preamble (see
proposal BID, Chapter 8), and again for dual alkali scrubbers in response
to these comments (see Docket A-79-09, item IV-B-15) and are judged to
be reasonable. Table A-8 in the Appendix to this volume provides
dual alkali scrubbing costs developed since proposal. Alternatively,
the refiner may choose to demonstrate compliance with the standard for
FCCU's without add-on controls by using hydrotreating or SOX reduction
catalysts, or by complying with the feed sulfur cutoff using low sulfur
feedstocks.
The sodium scrubber wastewater contains catalyst fines removed
from the FCCU regenerator exhaust gas. These catalyst fines are removed
from the wastestream in a settling pond. Eventually, these catalyst
fines would be removed from the settling pond and disposed of in a
landfill. Currently, catalyst fines are collected in electrostatic
precipitators (E.SP's) to meet the FCCU particulate NSPS, and are disposed
of in landfills. Catalyst fines, when removed from the settling pond,
will be wet and will include dissolved sodium salts such as sodium
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sulfate, sulfite, and bisulfite. However, neither catalyst fines nor
sodium salts are reactive in water and do not create a leachate problem
like coal fly ash. Therefore, the SOX NSPS will not affect the method
selected for disposal of catalyst fines. Thus, it is doubtful that a
catalyst fines settling pond would fall under RCRA.
Comment:
One commenter (IV-D-20) agreed with EPA that single alkali scrubbers
may not be applicable in inland refinery locations or areas where water
availability or wastewater discharge is restricted. In support of this,
the commenter provided an example calculation showing the impact of
sodium scrubber blow-down on refinery wastewater quality, and stated
that such a high level of total dissolved solids in the blowdown would
seriously reduce the efficiency of the activated sludge plant, leading to
high dissolved solids in the receiving waters. The commenter stated
that the high dissolved solids impacts on receiving waters would
necessitate the installation of dual alkali scrubbers.
Response:
As discussed above, EPA agrees that the potential impact that high
dissolved solids from sodium scrubbers would have on receiving waters
may, in certain cases, necessitate use of another control technique,
such as a dual alkali scrubber. However, it is EPA's opinion that the
sodium scrubber will not negatively affect a refinery's wastewater
treatment plant.
The EPA's analysis of sodium scrubbers presented in the proposal
BID includes the cost of wastewater treatment facilities. These facil-
ities include a settling pond for removal of catalyst fines and an
aeration basin to reduce the chemical oxygen demand of the wastestream.
By using these wastewater treatment facilities, the scrubber waste-
stream does not need to pass through the refinery's main wastewater
treatment plant. If the treated effluent from the sodium scrubber
wastewater treatment facility is mixed with the treated effluent from
the refinery's main wastewatfer treatment plant, the refinery's main
wastewater treatment plant will not be affected.
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4.3 SOLID WASTE IMPACTS
Comment:
One commenter (IV-D-16) questioned two statements presented in
the preamble to the proposed standards that pertained to solid waste
impacts. The commenter asked why sodium scrubbers would have no added
cost impacts for solid waste disposal and why the preamble states that
sodium scrubber waste is 50 percent water by weight. Since the waste
is 50 percent water, the commenter reasoned that the waste disposal
costs should be twice as much. Another commenter (IV-D-7) wrote that
the proposed standards do not adequately address the solid waste impacts
of scrubber systems. According to the commenter, scrubber systems could
greatly increase the amount of solid waste generated by a refinery and
disposal costs would rise accordingly, if disposal locations are available,
Response:
The sodium scrubbing systems that are currently applied to FCCU's
control both particulate emissions as well as SOX emissions. With this
type of scrubber, an additional particulate control device would not be
required to achieve the current particulate standard. Control of FCCU
particulate emissions (primarily catalyst fines) by a sodium scrubber
does not incrementally increase the dry weight of solid waste over
control by a dry particulate control device, such as an ESP. Therefore,
the amount of particulates collected by the sodium scrubbers are not
"chargeable" to the SOX standards. However, solids collected in a
scrubber would be wet and, thus, weigh more and encompass a larger
volume. It will cost more to transport and dispose solids collected in
a scrubber to a landfill than dry solids. The increase due to the
amount of water added to the solids is "chargeable" to the SOX stan-
dards and is included as a "solid waste" cost in the analysis of sodium
scrubber costs. In addition, a "liquid waste" disposal cost was added
as a conservative estimate of the costs to dispose treated liquid
scrubber waste to the sewer (see Section 5.1 of this document).
In order to determine the additional solid waste disposal cost due to
the water contained in settled scrubber solids (sludge), it was necessary
to determine the percent solids content of the scrubber solids. However,
to date, none of the settling ponds used for sodium scrubbers applied
to FCCU's has been emptied. Thus, EPA has no information regarding the
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water content of settled participates (sludge) collected by a sodium
scrubber. Instead, EPA has information regarding the solids content of
wastes for other scrubbing systems, such as dual alkali scrubbers. For
these other systems, scrubber waste is typically 60 percent solids.
To be conservative, EPA assumed that the settled sodium scrubber waste
would be approximately 50 percent solids, by weight. The EPA believes
that sodium scrubbers would not significantly increase the amount of
solid waste generated by a refinery.
Other types of nonregenerable scrubber systems, such as dual
alkali, spray drying, or lime/limestone scrubbers, produce a greater
quantity of solid waste with little liquid discharge compared to
sodium scrubbers. A dual alkali scrubber controlling SOX emissions
from an FCCU processing a 1.5 weight percent sulfur feedstock will
produce approximately 7,700 Hg/yr of solid waste for a 2,500 m^/stream
day (sd) FCCU and 25,000 Mg/yr for an 8,000 m3/sd FCCU. The EPA
considers the solid waste impacts for these systems reasonable. Should
solid waste disposal not be possible, the refiner would need to
consider control techniques that do not produce solid waste. These
include using regenerable scrubber systems (e.g., Wei Iman-Lord or
citrate scrubbers which produce salable sulfur products), hydrotreating,
SOX reduction catalysts, or the purchase of low sulfur feedstocks.
Comment:
One commenter (IV-D-4) stated that the proposed standards
discourage the recovery of reusable material by imposing sodium
scrubbers which consume large quantities of raw materials and produce
other less desirable wastes. Each megagram of S02 scrubbed will con-
sume 1 Mg of sodium hydroxide. The waste is a potential surface and
groundwater contaminant.
Response:
The EPA disagrees that the proposed standards discourage the
recovery of sulfur. The standard for FCCU's without add-on controls
allows the use of hydrotreating or SOX reduction catalysts. With both
of these control technologies, sulfur removed from the FCCU feedstock
or from the regenerator is eventually reclaimed as a salable product in
the refinery sulfur plant.
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The amount of sodium hydroxide consumed by sodium scrubbers is
approximately 1.15 times the amount of SOX in the gas stream passing
through the scrubber. The EPA evaluated the impacts of secondary pollu-
tants resulting from the application of scrubbers and determined that
these impacts are reasonable. The water impacts of scrubber wastewater
discharge are discussed in Section 4.2 of this document, and the cost
impacts are discussed in Section 5.1 of this document.
Comment:
One commenter (IV-D-16) stated that according to the preamble,
SOX reduction catalysts are not expected to have a solid waste impact.
By dividing the nationwide fifth-year cost for SOX reduction catalysts
($20 million/yr) by the reported cost of the catalysts ($l,800/Mg), the
commenter determined that the use of SOX reduction catalysts would
increase FCCU solid waste by 11,000 Mg/yr.
Response:
The EPA does not believe that the use of SOX reduction catalysts
would result in a significant increase in FCCU solid waste for the
reasons discussed below. When used as an additive, SOX reduction
catalysts replace from less than 5 and up to 10 percent of the circulating
catalyst inventory (see Docket A-79-09, items II-D-57 and IV-D-24).
One of the catalyst developers stated that, due to the softness of
their SOX reduction catalyst (an additive), its makeup rate is greater
than that for the cracking catalyst. The developer reported that this
may result in an increase in solid waste of up to 40 percent. Based
on recent tests by another developer, solid waste increases of less
than 5 percent are anticipated for the newer SOX reduction catalyst
formulations because these are much harder than earlier formulations. .
The EPA believes that it would be in the catalyst developers interest
to produce a harder reduction catalyst because a harder formulation
would have a lower makeup rate and therefore, most likely cost less to
use than a softer one. Other recently developed catalyst formulations
incorporate the SOX reduction catalyst as a constituent of the cracking
catalyst and consequently, SOX control can be accomplished without
increasing the total quantity of cracking catalyst used in the FCCU
over a period of time. In this case, SOX reduction catalysts would not
increase particulate emissions or solid waste. In summary, whether
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the SOX reduction catalyst is in the form of an additive or a consti-
tuent of the cracking catalyst, it is unlikely that the use of newer
SOX reduction catalyst formulations would significantly increase FCCU
solid waste over current levels.
4.4 ENERGY IMPACTS
Comment:
One commenter (IV-D-5) stated that the scrubber electric require-
ments presented in the proposal BID are too low. Instead of the 0.2 to
2 percent increase in electric consumption estimated by EPA, the com-
menter stated that an increase in FCCU energy consumption of 100 percent
would be more realistic. The commenter operates a Wellman-Lord scrubbing
system to control SOX emissions from a utility boiler. The commenter
stated that energy usage for the scrubber is 10 MW compared to the
0.166 MW energy usage estimated by EPA for an 8,000 m-Vsd model plant.
The higher energy usage is due to the use of booster blowers necessary
to pressurize the flue gas in order to move the gases through the
Wellman-Lord scrubber, especially following a CO boiler.
Response:
The EPA reevaluated its;estimate of the electrical energy
requirements of Wellman-Lord scrubber systems. The gas stream leaves
the FCCU regenerator at a higher pressure than the flue gas exiting a
boiler. As a result, less energy is required to move the FCCU regenerator
exhaust gas through a Wellman-Lord system or other scrubber system than
the energy used for a boiler^application. Therefore, scrubber energy
requirements should be lower for an FCCU application than for an indus-
trial or utility boiler application. The Wellman-Lord system energy
requirements presented in the proposal BID are based on an FCCU
operating with high temperature regeneration instead of a CO boiler.
The EPA expects the majority;of new, modified, and reconstructed FCCU's
to operate with high temperature regeneration. Consequently, EPA
believes that the estimate of the electrical energy requirements of
Wellman-Lord scrubber system:presented in the proposal BID is reasonable.
The energy impacts reported in the proposal BID are based on the
energy requirements of sodium scrubbers rather than Wellman-Lord systems
because sodium scrubbers are the only scrubber systems that have been
applied to FCCU's and they are the systems EPA expects most refiners to
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install to achieve the standard for add-on controls. The commenter
provided no information regarding sodium scrubber energy requirements.
Therefore, EPA did not revise the energy impact of sodium scrubbers.
The EPA does acknowledge that an FCCU owner or operator choosing to use
a Wei Iman-Lord system may experience greater energy impacts than if one
chooses to use a sodium scrubber.
4.5 AIR IMPACTS
Comment:
Four commenters (IV-D-3, IV-D-6, IV-D-8, and IV-D-16) questioned
the appropriateness of using scrubbers if they increase ground-level
SOX concentrations. One commenter (IV-D-3) wrote that controlling FCCU
SOX emissions to a level below a 13 kg SOX/1,000 kg coke burn-off level
would only bring about a small decrease in a ground-level impact, an
impact that is already quite small. If control to a level below
13 kg SOX/1,000 kg coke burn-off is accomplished by scrubbing, the
cooling of the exhaust gas would lower the plume rise, thereby diminish-
ing the small air quality benefit, or in some cases, cause a net increase
in ground-level concentration. A 13 kg SOX/1,000 kg coke burn-off
level would reduce the air quality benefits of the proposed NSPS little,
if at all.
Another commenter (IV-D-16) suggested that EPA require reheating
the scrubber exit gases to reduce ground-level concentrations and to
include reheat in the sodium scrubber cost analysis. This commenter
stated that the flue gas temperature used in the modeling is below the
sulfuric acid dew point (200°C). The commenter suggested a stack
temperature of 260°C and a flue gas exit velocity of 15.3 m/s. The
commenter further suggested that stack heights and exit velocities
reported for the modeling of Regulatory Alternative I are distorted.
Response;
Scrubbing a gas stream lowers the temperature of the gas stream.
Unless the gas stream is reheated downstream of the scrubber, the plume
emitted from the scrubber stack will be cooler than the plume emitted
from a FCCU regenerator not using a scrubber. Lowering the temperature
of the plume reduces the effective height above the ground to which the
plume will rise.
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The results of dispersion modeling performed by EPA and presented in
the proposal BID were used to analyze the air quality impact of the
proposed standards. In all cases, ground level SOX concentrations are
within the national ambient air quality standards. For all the model
plant scenarios except the one processing a low sulfur feedstock, the
ground level SOX concentrations predicted for implementation of the
proposed standards are lower than the baseline (uncontrolled) concentrations,
In these cases, the decrease in SOX emissions afforded by implementation
of scrubbers offsets the lower plume rise. This analysis showed that
applying a scrubber to a model plant processing a low sulfur feedstock
(0.3 weight percent sulfur) ^o achieve 9.8 and 6.5 kg SOX/1,000 kg coke
burn-off levels (Regulatory Alternatives III and IV, respectively)
would increase the 1-hour maximum ground level SOX concentration downwind
of the FCCU to a level above the baseline (uncontrolled) case. The small
amount of emission reduction!achieved by the control alternatives did
not compensate for the lower plume rise resulting from the cooler
exhaust gas temperature. However, this model plant scenario would not
occur in actuality because any FCCU processing 0.3 weight percent
sulfur content feedstocks would comply with the low-sulfur cutoff
and, therefore, a scrubber would not be installed on the source.
Also the model assumes that a scrubber would reduce model plant SOX
emissions to the level of the regulatory alternative. The SOX emission
reductions required to achieve the model plant regulatory alternatives
considered are less than the190 percent required by the standard.
The EPA agrees that if a control technique other than a scrubber
was used to achieve the same, emission reduction as the scrubber would
achieve, the resulting maximum ground level concentrations may be less
than if a scrubber were used. However, the application of SOX reduc-
tion catalysts to meet the standard for FCCU's without add-on controls
would provide less emission reduction than the application of scrubbers.
The additional emission reduction provided by scrubbers would likely
compensate for the lower plume rise, so that the use of scrubbers would
result in lower-ground level concentrations than the use of SOX
reduction catalysts.
The stack temperatures,, heights, and exit velocities used in the
modeling analysis were selected as average values from data for actual
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FCCU scrubbers. Only one of the seven FCCU sodium scrubber installa-
tions existing before proposal is equipped with scrubber stack reheat.
Reheat is used only occasionally to reduce the visible steam plume
during certain weather conditions. The stack parameters EPA selected
for the model plants are based on actual sodium scrubber installations.
For this reason, EPA believes that the modeling input parameters selected
and the assumption of no reheat are appropriate.
Comment:
One commenter (IV-D-9) stated that the use of the correlation
between feed sulfur and coke sulfur overstates uncontrolled SOX emis-
sions, inflating the percent reduction attributed to catalysts.
Response:
The EPA agrees that the correlation, presented on p. 3-18 of the
proposal BID, overstates SOX emissions for some feedstocks. However,
at the same time, it understates SOX emissions from other feedstocks.
The correlation used by EPA was provided by industry and is based on
test data for a large number of FCCU's and feedstock types. For this
reason, EPA concludes that the correlation shown in the proposal BID is
representative of uncontrolled emissions. The EPA considers the corre-
lation a useful and reasonable means for estimating uncontrolled FCCU
SOX emissions and SOX reduction catalyst performance.
Comment:
One commenter (IV-D-16) stated that the preamble does not
adequately address the effect of SOX reduction catalysts on NOX emis-
sions. The commenter argued that the preamble states that SOX reduction
catalysts would not increase NOX emissions. However, the proposal BID
(Sections C.3.1.1 and C.3.1.2) and Docket A-79-09, item II-B-20 show
that SOX reduction catalysts raised NOX emissions.
Response:
Most refiners use one of two techniques to control CO emissions
from the FCCU regenerators: HTR or catalytically promoted CO combus-
tion. Data from some tests of NOX emissions from regenerators using
both CO combustion promoter catalysts and SOX reduction catalysts in
combination show an increase in NOX emissions. Separate data for
regenerators using CO combustion promoters without SOX reduction
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catalysts suggest that the use of these catalysts may increase NOX
emissions. Thus, at this time, it is unclear whether the NOX increases
observed for SOX reduction catalyst tests are due to the reduction
catalyst or the CO combustion promoter. Recent commercial tests of SOX
reduction catalysts in FCCU's utilizing HTR show no increase in NOX
emissions (see Docket A-79-09, item IV-B-9). No recent tests of SOX
reduction catalysts in FCCU's utilizing CO promoters were available.
Because most FCCU's subject to the standards are expected to use HTR
and because newer SOX reduction catalyst formulations have not increased
NOx emissions, EPA believes that the use of the SOX reduction catalyst
technology will not increase;NOx emissions.
Comment:
One commenter (IV-D-16) stated that the proposal BID fails to take
State regulations into account in estimating baseline emissions for
Regulatory Alternative I. To remedy this, the commenter recommended
that the selection of model plants include site selection for each
unit. Then, baseline emissions can be estimated based on the State in
which the model unit is located.
Response;
Emissions of SOX from FCCU's can vary significantly depending on
the feedstock processed, FCCU operation, and capacity utilization.
Many refiners have been able to achieve existing State SOX regulations
with little or no control. It is difficult to determine FCCU SOX emis-
sion rates taking individual State regulations into account because
the various formats of State!regulations do not lend themselves to
simplifying assumptions regarding FCCU SOX emissions.
Selection of sites for each model plant is not a reasonable
approach as there is no basis for site selection. Using an emission
factor provides a reasonable estimate of baseline nationwide FCCU SOX
emissions. This factor is based on emission test results for typical
FCCU operations that represent the level of SOX control achieved by
FCCU's to achieve State and local SOX regulations prior to 1979. State
and local SOX regulations have changed little since 1979; those regula-
tions that have changed do not affect EPA's estimate of nationwide
baseline FCCU SOX emissions.
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Comment:
One commenter (IV-D-16) asked why Table 1-1 in the proposal BID
shows a "-4" air impact in three cases.
Response:
A "-4", denoting significant short-term air impact, was entered
in Table 1-1 because FCCU's represent a significant source of SOX
emissions. This means that FCCU's emit much greater than 100 tons per
year of SOX. Because FCCU's are a significant source of SOX, and an
SOX control technology with reasonable cost and nonair environmental
impacts was identified for FCCU's, a short-term large adverse air
impact would result if: (1) standards more stringent than the current
level of SOX control were not developed, (2) development of standards
was delayed, and (3) no standards were developed.
Comment:
One commenter (IV-D-16) stated that an emission factor is used to
determine current nationwide FCCU SOX emissions. If the factor is
correct, EPA should use this factor to estimate model plant emissions.
Response:
The emission factor used by EPA to determine nationwide FCCU SOX
emissions is based on actual emission test data and does not predict
what potential SOX emissions will be from new, modified, and recon-
structed FCCU's. Model plants were developed based on feed sulfur
levels and throughputs; model plant emissions are based on the use of
the feed sulfur-SOx emissions correlation presented in the proposal
BID. Model plants generated in this way do not necessarily reflect
current FCCU operations or emissions but instead represent those newer
FCCU's that will be subject to these SOX standards over the next 5 years.
Thus, model plants provide a more reasonable estimate of emissions from
the FCCU's that will be subject to this standard than an emission factor
based on a composite of older FCCU's.
Comment:
One commenter (IV-K-2) questioned the source of EPA's claim that
uncontrolled emissions from a typical FCCU are between 2,000 and
6,000 Mg/yr and that controlled emissions from a typical FCCU are
between 400 and 1,200 Mg/yr.
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Response:
The uncontrolled emissions estimates referred to in the comment
represent Regulatory Alternative I (Baseline) for model FCCU units with
a throughput capacity of 2S500 and 8,000 m3/day, respectively, with a
fresh feed sulfur content of'1.5 percent. The Agency estimates that
this feed sulfur content would be typical of FCCU's subject to the
standard. Emissions were calculated on the basis of 1,400 vppm for
feed sulfur content of 1.5 weight percent. This vppm estimate is con-
sistent with actual data from pilot and commercial FCCU's, shown in
Figure 3-6 of the proposal BID. The controlled emission estimates of
400 Mg/yr and 1,200 Mg/yr represent control in the 2,500 m3/day and
8,000 m3/day regenerator, respectively, to 9.8 kg SOX/1000 kg coke
burn-off. This level can be| met by SOX reduction catalysts being
used at facilities with a fresh feed sulfur content of 1.5 percent. If
scrubbers are used, lower controlled emissions would occur at this
typical FCCU.
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5.0 COSTS AND ECONOMIC IMPACTS COMMENTS
5.1 SCRUBBER COSTS
Comment:
Five commenters (IV-D-5, IV-D-6, IV-D-9, IV-D-10, and IV-D-20)
stated the opinion that the scrubber costs presented in the proposal
BID are unrealistic and are significantly underestimated. The commenters
claimed that the scrubber cost estimates should be 2.2 to 7 times
higher. The reasons cited by the commenters for the low cost estimates
are:
(1) The EPA based the cost analysis on erroneous assumptions for
FCCU exhaust volumes, scrubber waste disposal costs, and
offsite costs.
(2) The EPA did not consider site space availability and soil
conditions, FCCU turnaround schedule, equipment availability,
startup costs, or climate when preparing the capital costs
estimates. These factors can cause considerable variation in
cost of FCCU's at different refineries.
(3) The EPA did not cost dual alkali F6D systems at any of the
model units, although use of dual alkali systems might be
required in areas where water availability or wastewater
discharge is restricted.
(4) The EPA should include separate costs to account for the diff-
iculty of retrofit installations.
(5) The EPA did not consider a cost for business interruption
that would result from a scrubber malfunction shutting down
the FCCU.
(6) It is not appropriate for EPA to subtract a credit for ESP
costs from the scrubber costs in the case of an existing
FCCU with an ESP if scrubbers are required as a result of
modification or reconstruction.
Response:
To respond to these comments, EPA decided first to solicit more
detailed cost data for single alkali scrubbers from vendors and then
to perform a general revaluation of the cost data presented in the
proposal BID. Concurrently, EPA solicited supplemental cost data from
commenters and then addressed the individual comments pertaining to
specific cost items.
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A. General Cost Review. First, EPA solicited data from scrubber
vendors other than Exxon; Exx'ori provided the costs on which the proposal
BID cost estimates were based. The EPA received detailed cost data
from two other scrubber vendors, Environmental Elements Corporation
(EEC) and Andersen 2000 (IV-D-32, IV-D-36). Exxon is the only company
whose scrubber has actually been installed on an FCCU. Environmental
Elements Corporation has, however, served as a subcontractor to Exxon
in installation of several Exxon scrubbers, and, therefore, is familiar
with FCCU operation, refinery codes, and equipment specifications.
Andersen 2000 has considerable experience with the design and applica-
tion of scrubbers to industrial boilers, but not to FCCU's.
The analysis of these data (see Docket A-79-09, item IV-B-14)
showed that the costs provided by Exxon, the vendor of single alkali
scrubbers applied to FCCU's, .were the highest of all the vendor cost
estimates and are conservative due to more stringent design specifica-
tions than other vendors use !and the use of redundant equipment that
serve to provide the scrubber with the reliability that petroleum
companies believe is necessary in the refining industry. In particular,
the Exxon system design specifications call for vessel design coded by
the American Society of Mechanical Engineers (ASME) and design of
pumps, piping, and electrical equipment coded by the American Petroleum
Institute (API); one of the bther two vendors that provided cost data
did not specify such coded design. Exxon scrubber vessels are larger
than those designed by the other two companies, and use special refrac-
tory linings to protect the steel shell from the abrasive effects of
catalyst fines in the refinery flue gas. Further, the Exxon design
requires sparing of all rotating equipment and critical analyzers, and
specifies multiple Venturis, rather than a single variable throat
venturi as specified by the other vendors. Fluid catalytic cracking
units may be in continuous operation for about 3 years nonstop, or
significantly longer in some cases, and Exxon designs their scrubbers
to maintain safe and reliable operation for time periods equal to that
of the FCCU's the scrubbers control.
B. Review of Specific Cost Comments. Second, EPA considered the
specific cost comments provided by companies.
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One commenter (IV-D-5) stated that EPA's costs were low, in part,
because of erroneous assumptions of FCCU exhaust gas volumes. Additional
information was requested and received from the commenter, and EPA
reviewed the information (see Docket A-79-09, item IV-B-4). The EPA
concluded that the exhaust gas volumes used for the cost analysis for
FCCU's using HTR appear to be appropriate. Model plant FCCU exhaust
gas volumes were developed based on stoichiometric relationships between
the coke composition, the amount of air necessary to burn the coke, and
typical levels of excess air. The calculated exhaust gas volumes were
compared to actual exhaust volumes reported for FCCU regenerators and
were found to be reasonable. Furthermore, the values used for the
model plant regenerator exhaust gas volumes were sent to industry
representatives for review prior to beginning the impact analyses, and
no comments were received by EPA indicating that the exhaust gas
volumes were not representative of actual conditions.
During these cost evaluations, EPA revised the exhaust gas volume
for FCCU's operating with jet ejector Venturis (JEV's) to include the
flue gas contribution from the CO boiler. As a result, EPA also revised
the capital and annual costs for JEV scrubbers installed on FCCU's (see
Docket A-79-09, item IV-B-16). Fluid catalytic cracking units using CO
boilers must install the JEV-type scrubber. The JEV costs presented
in the proposal BID did not account for the additional flue gas volume
that would enter a JEV scrubber because of the combustion air required
in the CO boiler. The EPA determined that flue gas volume to a JEV
scrubber would be about 10 percent higher than the volume of gas from
an FCCU to a high-energy venturi scrubber (see Docket A-79-09, item
IV-B-16). This increased volume resulted in about a 3 percent increase
in the cost of the JEV scrubber over that previously calculated.
Tables A-5 through A-7 in the Appendix to this volume contain the
revised JEV costs.
Several commenters (IV-D-5, IV-D-6, IV-D-9, IV-D-10) stated that
EPA used erroneous assumptions for scrubber waste disposal costs. The
EPA, therefore, -reviewed the waste disposal costs used in the proposal
BID. The cost values used in the proposal BID represent the cost for
the transport and disposal of collected catalyst fines in a landfill.
This solid waste disposal cost is based only on the additional mass of
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solid wastes to be disposed due to the use of a wet scrubber as the
collection device instead of an ESP (see Section 4.3 of this document).
In the proposal BID, no costs were credited to the disposal of the
treated liquid wastes because EPA assumed that the treated liquid
wastes were disposed to surface water. Upon review, EPA decided that
it is appropriate to provide a more conservative estimate of liquid
waste disposal costs by assuming that all affected facilities would
discharge to sewers. Some refiners, especially in coastal locations,
will likely be able to discharge the treated scrubber liquid wastes to
surface waters without incurring a sewer discharge cost.
Two commenters (IV-D-5 and IV-D-9) questioned EPA's assumptions
of offsite costs. Two other commenters (IV-D-6 and IV-D-10) stated
that EPA did not consider site space or equipment variability, soil
conditions, FCCU turnaround schedule, start up costs, or construction
climate. The EPA has considered including specific costs for offsites,
soil conditions, turnaround schedule, equipment availability, climate,
and startup in the costs estimates. Offsites include electricity,
water, fire protection, steam, compressed air, and other utilities.
The scrubber costs used by EPA to evaluate cost impacts include the
cost of connecting utilities:to the scrubber provided the utilities are
located within the battery limits of the FCCU. The battery limits
refer to that portion of the,refinery associated with a particular
process unit and its supporting equipment. Where utilities are not
available or insufficient capacity is available within the FCCU battery
limits, the refiner will incur a cost greater than that assumed in the
cost estimates. However, a 20-percent contingency is provided in
each capital cost estimate. • The EPA considers that the site-specific
costs related to soil conditions, turnaround schedules, site space and
equipment availability, climate, startup, and the expense of offsites
are included in this contingency and have, therefore, been considered
by EPA.
In support of their comments on costs of construction climate,
space and equipment availability, and pond and treatment system
requirements, one commenter (IV-D-IO) provided capital costs for the
retrofit installation of a sodium scrubber to control both particulate
and SOX emissions from an FCCU at an existing refinery. The single
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alkali scrubber is sized for a flue gas volumetric flow rate similar to
the 8,000 ni3/sd model plant used by EPA in developing costs. A compar-
ison of the commenter's cost estimate with EPA's revised cost estimate
shows that the total direct cost for both estimates is about the same.
The commenter applied a 60-percent factor to account for indirect costs
compared to the 40-percent factor used by EPA. The commenter also
applied to this base cost estimate an additional 27-percent cost
adjustment, which included labor productivity, design allowance, and
construction climate. The EPA evaluated the commenter's cost factors
and believes that these factors are adequately accounted for by EPA's
20 percent contingency cost factor (see the discussion of cost factors
in this response). When adjusted to equivalent dollars, the commenter's
cost estimate is approximately 50 percent higher than EPA's revised
cost estimate for a comparably-sized single alkali scrubber installed
on an existing FCCU.
The commenter's scrubber costs were developed from a preliminary
factor-type cost estimate provided by a vendor. This type of cost
estimate is developed in the early stages of a construction project
when the project specifications are not very well defined. A factor-
type estimate will typically contain several generous cost allowances
to account for uncertainties in equipment specifications and construc-
tion. As a project becomes more defined, the final cost estimate
normally is lower, and closer to the actual cost of the project. The
EPA's costs are based on a vendor's experience with scrubber applica-
tions to FCCU's, and EPA believes that these costs are more representa-
tive of the actual cost of this scrubber design than the cost estimate
provided by the commenter. Thus, the difference between the commenter's
cost estimate and EPA's revised costs is largely due to the preliminary
nature of the commenter's cost estimate.
One commenter (IV-D-20) indicated that EPA's cost estimates should
more appropriately be based on the use of dual alkali FGD systems,
because single alkali systems may not be applicable in areas where
water availability or wastewater discharge is restricted. The commenter
provided cost data to show that dual alkali systems are more expensive
than single alkali systems. A dual alkali scrubber consists of two
parts, the "front half" and the "back half." The front half of a dual
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alkali scrubber resembles a single alkali scrubber without a wastewater
treatment unit and performs the same function—removing SOX from a gas
stream by contacting it with'a caustic or soda ash scrubbing liquor.
In the back half of a dual alkali scrubber, however, the purge is
treated to regenerate the scrubbing liquor for reuse; a single alkali
scrubber simply treats and discharges the purged liquor.
The EPA agrees that, where direct discharge of scrubber wastewater
is not permitted, dual alkali scrubbers would be a viable alternative
to single alkali scrubbers because dual alkali scrubbers produce a
calcium sulfate sludge that would be more readily disposed than waste-
water, but disagrees that dual alkali scrubbing systems would be more
expensive than single alkali.
The commenter compared capital costs for dual alkali scrubbers to
EPA's proposed single alkali scrubber costs. The commenter1s cost
estimates were based on proprietary actual scrubber cost information
provided by the commenter"s Contractors. For each of the model plants
presented in the proposal BID, a computer cost model was used by the
commenter to estimate dual alkali scrubber costs assuming 90 percent
SOX reduction. The commenter1s dual alkali scrubber costs are a func-
tion of volumetric gas flow rates and sulfur loading. The commenters
cost estimates for dual alkali scrubbing were significantly higher than
EPA's proposal estimates for all dual alkali model units.
Because these differences existed, EPA performed a further evalua-
tion of dual alkali costs based on data from vendors of dual alkali
systems (see Docket A-79-09, item IV-B-15). Specifically, Exxon's
single alkali scrubber costs were used to develop costs for the front
half of both sizes of a dual; alkali scrubber. Environmental Elements
Corporation provided back-half costs for both sizes of dual alkali
scrubber. Also, Exxon provided EPA with a cost estimate provided to
them by an independent vendor of dual alkali scrubbers for the back
half of a dual alkali scrubber applied to the 8000 m3/sd FCCU only.
The commenter's and EPA's costs are based on a scrubber design that
would control both FCCU particulate and SOX emissions.
The EPA's revised capital cost estimates for dual alkali scrubbers
are greater,than those in the proposal BID, but less than Exxon's
capital cost estimates for Exxon's single alkali scrubber. This is
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because the back half of the dual alkali scrubber, where the purged
scrubbing liquor is treated to regenerate it for reuse, was found to be
less costly than the wastewater treatment system needed to treat the
purged scrubbing liquor before discharge from a single alkali system.
Construction costs for the in-ground ponds specified by Exxon for waste-
water treatment are greater than the cost of the dual alkali sludge
dewatering and disposal facilities.
A comparison of EPA's revised dual alkali costs with those provided
by the commenter shows that the commenter's total dual alkali costs
remained significantly higher than EPA's revised dual alkali total cost
estimate. However, because the commenter's cost information is based
on proprietary actual cost data developed by contractors of dual alkali
scrubbers and provided to the commenter, detailed cost information was
not provided to EPA by the commenter, and a comparison of EPA's indivi-
dual capital costs to those provided by the commenter was not possible.
The EPA's analysis of data supplied by vendors of dual alkali sys-
tems indicates that total single alkali scrubber costs are more costly
than total dual alkali scrubber costs rather than less costly as the
commenter believes. Therefore, EPA's current cost estimates for model
plants, which reflect the use of only single alkali scrubbing, represent
a conservative estimate of nationwide costs; dual alkali cost estimates
applied to the model plants would only decrease the national costs.
Therefore, it was decided not to revise costs of S02 control of model
plants to reflect the use of dual alkali at some facilities.
This commenter (IV-D-20) also provided cost data for single alkali
systems. The EPA performed an analysis of this single alkali cost data
for comparison to single alkali cost estimates in the proposal BID (see
Docket A-79-09, item IV-B-24). The commenter's costs for single alkali
scrubber systems are similar to EPA's revised costs for the low sulfur
model plants, but are significantly higher than EPA's revised costs for
the 1.5 and 3.5 weight percent sulfur model plants. The commenter's
single alkali cost estimates assume that single alkali capital costs
are 93 percent of dual alkali costs. The EPA believes this approach is
inappropriate because, whereas capital costs for dual alkali systems
are a function of both waste gas flow rate and feed sulfur content,
capital costs for single alkali systems are a function only of waste
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gas flow rate. Dual alkali control requires equipment to;regenerate
the reagent solution, the cost of which depends, in part, on the sulfur
content of the flue gas. Because single alkali systems do not have
such equipment, single alkali control costs are a function only of
waste gas flow rate. Therefore, single alkali cost estimates derived
by applying a constant percentage of dual alkali costs for different
sulfur content models would Result in erroneous estimates. The EPA
believes, therefore, that the accuracy of the commenter's single alkali
costs, which increase with feed sulfur content, is doubtful.
Two commenters (IV-D-9 and IV-D-20) stated that EPA needed to
reevaluate the cost of retrofitting existing FCCU's with scrubbers.
The EPA reevaluated these costs. Costs associated with retrofit will
vary widely from one refinery to another based on the refinery configu-
ration and the availability of land. In some cases, space limitations
around an existing FCCU may result in relocating utilities and piping
runs, longer ducting runs, and other factors that may make scrubber
installations more difficult than at a new refinery. Therefore, EPA
agrees that retrofit should be included in the cost estimates for some
model plants. A retrofit cost factor of 20 percent of the scrubber
capital cost (less contingency) was estimated by one commenter. This
cost was added to three of the seven modified/reconstructed FCCU's
anticipated to be subject to^this standard over the next 5 years.
One commenter (IV-D-20):stated that EPA did not consider a cost
for business interruption that would result from a scrubber malfunction
shutting down the FCCU. Although sodium scrubbers have demonstrated
reliability factors in excess of 95 percent (discussed in Section 3.2),
scrubber malfunctions can occur. The General Provisions to 40 CFR 60
states that emissions in excess of an emission limit during a period of
malfunction of a control device are not considered a violation provided
the control device has been properly operated and maintained. During a
period of a sudden or unavoidable scrubber failure, the refiner would
still be able to operate the!FCCU. Therefore, no business interruption
cost would be incurred. For-this reason, EPA did not include a business
interruption impact when revising the proposal BID costs.
One commenter (IV-D-20)'stated that EPA subtracted an ESP cost
credit inappropriately in the cases of an existing FCCU with an ESP in
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place If scrubbers are required as a result of modification or
reconstruction. The EPA agrees that an ESP cost credit is not appro-
priate in these cases. The proposal BID costs were revised to eliminate
the ESP cost credit for the three modified or reconstructed FCCU's in
which retrofit costs were included.
C. Summary of Cost Changes. As a result of both the general
revaluation of costs and of the review of specific cost comments,
EPA revised the capital and annual cost estimates for FCCU scrubbers.
The following changes were made: (1) costs of individual components
were adjusted based on the data received; (2) JEV scrubber costs were
revised to account for increased flue gas volume entering the scrubber
as a result of CO boiler combustion air; (3) waste disposal costs were
increased to include liquid waste discharges; (4) a cost for retrofit
installation was added for of the modified or reconstructed FCCU's;
and (5) the ESP cost credit was deleted for the three scrubbers that
were installed on modified or reconstructed FCCU's and for which retrofit
costs were included. Costs were then further adjusted to 1984 dollars.
After both the general and the specific cost analyses, EPA concluded
that the proposal BID costs are not understated by a factor of 2.2 to 7.
Results of the new cost estimates are presented in Appendix A of this
document. Changes in cost as described above caused nationwide capital
costs to increase by 30 percent (from $72 to $93.6 million); adjusted to
1984 dollars, capital costs increased a total of 63 percent from proposal
(from $72 to $117 million). Changes in cost caused nationwide annual
costs to increase by 5 percent (from $35 to $36.6 million per year);
adjusted to 1984 dollars, annual costs increased a total of 29 percent
from proposal (from $35 to $45 million per year).
Thus, these estimates show that the standards would result in a
total nationwide capital cost for SOX control for the first 5 years
after the effective date of the standards of $117 million, assuming
sodium-based scrubbers are used at all facilities processing feedstocks
with sulfur content above 0.3 weight percent. The fifth year nationwide
annual cost is $45 million. Units processing feedstocks with sulfur
contents of 0.3 weight percent would be below the feed sulfur cutoff and
therefore, would not need to install a scrubber. Where sodium scrubbers
are not applicable, dual alkali scrubbers could be used at a similar
cost to sodium scrubbers.
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5.2 SOX REDUCTION CATALYSTS COSTS
Comment: ,
Three commenters (IV-D-£, IV-D-9, and IV-D-20) wrote that the SOX
reduction catalyst technology requires a capital outlay. Two commenters
(IV-D-6 and IV-D-9) stated that because the catalysts can only be used
in units with HTR, older units subject to the modification or reconstruc-
tion provisions that do not or cannot operate in this mode will be
required to convert or modify their units. This conversion could cost
from $10-20 million per FCCU. The third commenter (IV-D-20) stated that
although it may be true that the use of SOX reduction catalysts would
require little outlay for capital equipment, two exceptions would be:
(1) a small refinery that does not have a sulfur recovery unit, and
(2) a refinery with inadequate sulfur recovery unit capacity to handle
the increased sulfur load due to the SOX reduction catalyst technology.
In either case, a capital expenditure would be necessary. Two of the
commenters (IV-D-6 and IV-D-9) also stated that annual costs for SOX
reduction catalysts will likely be at least 2 times higher than EPA's
estimate.
Response:
Many refiners have modified their older FCCU's to HTR. High
temperature regeneration offers advantages over conventional regenera-
tion (e.g., reduced SOX emissions, improved yields, and increased
throughput). It is unlikely that an older FCCU would become subject to
these standards through the modification/reconstruction provisions
without modifying the unit to HTR. A refiner is more likely to use SOX
reduction catalysts in an FCCU modified for HTR than modify an FCCU
solely to use SOX reduction 'catalysts. If an FCCU subject to these
standards cannot utilize SOX reduction catalysts, the refiner is more
likely to select another control technique than incur a $10-20 million
capital expenditure.
Use of SOX reduction catalysts will increase the amount of HgS in
refinery fuel gas, which is removed from the fuel gas in a sulfur
recovery unit. The increase in the amount of H£S to a sulfur recovery
unit is only about 5 to 10 percent. Sulfur recovery units generally
are overdesigned by much more than this to account for swings or{surges
in H£S production from refinery process units. It is doubtful that the
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use of SOX reduction catalysts alone would overload a sulfur recovery
unit. The EPA does agree, however, that in certain cases sulfur recovery
unit capacity or a new unit would need to be added. These factors do
not affect the reasonableness of the standards, however, since the
standards are based on scrubbers as best demonstrated technology.
The EPA contacted companies developing or licensing SOX reduction
catalysts to obtain current costs for commercially available SOX reduc-
tion catalysts. Catalyst developers reported costs for the technology
ranging from $0.60 to $1.60/m3 of fresh feed processed. The fifth year
cost for SOX reduction catalysts was then calculated by multiplying the
cost factors provided by the catalyst developers by the total fifth year
annual throughput for all affected facilities processing feedstocks
containing greater than 0.30 weight percent sulfur. The new fifth year
cost for SOX reduction catalysts ranges from $20 million to $50 million.
Costs for SOX reduction catalyst are presented as a range because the
technology is under development. The upper end of the range represents
a newer catalyst formulation; the developer of this catalyst expects
the cost to decrease as the catalyst formulation is produced in greater
quantities.
5.3 ECONOMIC IMPACT ANALYSIS
Comment;
Several commenters (IV-D-3, IV-D-6, IV-D-9, IV-D-10, IV-D-15, and
IV-D-20) stated that the proposed standards would have an adverse affect
on the refining industry and the nation's economy. Four commenters
(IV-D-6, IV-D-9, IV-D-15, and IV-D-20) wrote that the compliance costs
are sufficiently high to require the preparation of a Regulatory Impact
Analysis under Executive Order 12291. One commenter (IV-D-15) wrote
that current prices will reduce the attractiveness of FCCU modifica-
tions to the point where the additional cost of a scrubber or other SOX
control device would not be feasible. Three commenters (IV-D-3, IV-D-9,
and IV-D-10) wrote that the costs of the proposed standards would, in
some cases, postpone new investments and would cause a significant
economic impact on the profitability of FCCU operation and construction
of new FCCU's.
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Response:
The cost analysis presented in the proposal BID was reviewed under
Executive Order 12291 by the Office of Management and Budget (OMB).
Since that time, in response to comments, EPA has revised these costs
upward. This latest cost revision is presented in Appendix A. With
these revisions, the fifth year nationwide annualized costs are still
below the $100 million level that triggers a regulatory impact analysis
under Executive Order 12291.' The price increases published in the proposal
BID were all less than 0.4 percent. Using the revised control costs and
second quarter 1984 product prices, that figure increases to approximately
0.8 percent for the worst case considered (3.5 weight percent sulfur
feedstock). The EPA still considers this to be acceptable.
The capital required for the control devices will increase the
investment for a new FCCU by 9 percent for the 8,000 m3/sd unit and by
15 percent for the 2,500 m3/sd unit. The EPA does not consider these
percentages sufficiently high to deter a decision to install an FCCU
that is otherwise economically justified.
Comment:
One commenter (IV-D-16): suggested an exemption for refineries
classified as small businesses because EPA had stated in the proposal
BID that due to the discontinuance of the entitlements program, very
little construction is anticipated at small refineries. Therefore,
the percentage of small refiming businesses affected will be well below
the level of concern. The commenter seemed to interpret this statement
to mean insignificant emissions and suggested that small refineries
should be exempt for that reason.
Response:
The EPA does not consider the potential emissions from small
refineries to be insignificant. Scaling down emissions from EPA's
model FCCU sizes to a unit of the size discussed below (950 m3/sd)
indicates that, even with a low sulfur feedstock, emissions would be
greater than 100 Mg S0x/yr. • Therefore, EPA would not exempt small
refineries because of insignificant emissions.
A recent investigation has revealed that 14 of the 116 refineries
that currently operate FCCUrs are classified as small refiners, i.e.,
less than 1500 employees and less than 8000 m3/sd crude oil refinery
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throughput. The EPA guidelines require that a Regulatory Flexibility
Analysis should be performed if more than 20 percent of the small
business sector will experience a significant adverse economic impact.
The EPA continues to believe that, due to the discontinuance of the
entitlements program, very little construction is anticipated at small
refineries. However, EPA examined the impact that the regulations
would have on a small business.
To examine that impact, EPA selected from the 1984 Oil and Gas
Journal Annual Refining Survey, the FCCU representing the low 20th
percentile throughput of the population of currently operating small
refineries, which was an 950 m3/sd FCCU in a 1,350 m3/sd refinery.
To approximate the impact on revenue and production costs, EPA used the
control costs in Appendix A and the revenues on page 9-34 of the proposal
BID scaled down to the refinery size with revenues reduced to reflect a
19 percent drop in product prices. The compliance cost as a percent of
sales revenue amounted to less than one and one-half percent. The
same was true of compliance costs as a percent of production costs. To
install an FCCU of this size under these standards would cost an addi-
tional 15 percent to provide scrubber controls. Furthermore, EPA does
not expect any small refineries to close as a result of this action.
Therefore, EPA does not feel that the differential impact between large
and small refiners is significant enough to justify an exemption based
on unit size.
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6.0 COMPLIANCE TESTING AND MONITORING COMMENTS
6.1 GENERAL
Comment:
One commenter (IV-D-11) pointed out that the preamble to the
proposed standards states that SOX testing is conducted upstream of the
CO incinerator while velocity and volumetric flow rates are determined
downstream of the CO incinerator. The regulation indicates that samp-
ling for SOX concentration "shall be the same as for determining volu-
metric flow rate." The commenter believed the regulation statement is
correct.
Response:
The EPA agrees with the commenter; SOX testing should be performed
at the same location as the volumetric flow rate measurement, as is
specified in the regulation.
Comment:
One commenter (IV-D-20) pointed out that the proposed regulation
states that sampling should be conducted upstream of the CO boiler.
The commenter stated that it is unsafe to require personnel to conduct
manual sampling due to the high flue gas temperatures at this location
(650-769°C). Additionally, sampling at extreme temperatures is imprac-
tical due to frequent sampling train operating problems and rapid
sample probe failures.
Response:
The EPA recognizes the commenter1s concern regarding safety.
Sampling either upstream or downstream from the CO boiler is acceptable
for the standard without add-on controls. However, if the owner or
operator chooses to test downstream of the CO boiler, alternative
calculation procedures for determining the coke burn-off rate and the
SOX contribution due to the auxiliary fuel burned in the boiler must be
submitted to and approved by the Administrator prior to sampling. In
addition, the recommended location for the inlet CEMS has been changed
to downstream of the CO boiler for the standard with add-on controls.
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Comment:' |
Seven commenters (IV-D-2, IV-D-3, IV-D-6, IV-D-7, IV-D-9, IV-D-16,
and IV-D-20) requested the inclusion of alternative methods in the
standards to be used to determine excess emissions. A number of com-
menters (IV-D-2, IV-D-3, IV-D-6, IV-D-7, IV-D-9, and IV-D-20) suggested
conducting periodic performance tests to determine excess emissions.
One commenter (IV-D-2) also suggested periodic (weekly) monitoring or
the establishment of a relationship between feed sulfur or sulfur on
the spent catalyst and emitted SOX emissions. Another commenter
(IV-D-3) also suggested the determination of a relationship between
feed sulfur and coke sulfur. One commenter (IV-D-16) suggested estab-
lishment ,of a trigger-level value (T) that would be derived from the
compliance test value (C) multiplied by the ratio of actual feed sulfur
during the 3-hour report period (A) to the feed sulfur during the
compliance test (S): T = CA/S.
Response;
The standards now require compliance to be determined on a daily
basis. The methods proposed: by the commenters for excess emissions are
not reasonable methods to use for determining compliance on a daily basis
because they do not generate data sufficiently accurate for compliance
(vs. excess emissions) determinations.
6.2 WITH ADD-ON CONTROL DEVICES
Comment:
One commenter (IV-K-1) stated that an operator of an add-on control
device should be given the flexibility to choose between the original
proposal, which would have required using an outlet monitor only, and
the operation of a CEMS in which both an inlet and outlet monitor are
used. The commenter supported this by suggesting that the advantages
of continuous inlet monitoring would not justify the additional cost
over the most recent compliance test if the feed to the FCCU is not
highly variable. The commenter stated that, where the feed sulfur
content is expected to be highly variable, the operator may benefit
from using both an inlet and outlet monitor to demonstrate compliance
with the standard.
Another commenter (IV-Kr2) stated that, during the compliance
test for the standard for add-on controls, a measurement at both the
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inlet and the outlet is needed. However, after the compliance test,
the proposed standards only need an "alerting service," which could be
provided by an outlet monitor alone.
Response:
The standard for FCCU's using add-on controls is 90 percent
reduction or 50 vppm, whichever is less stringent. The intent of
monitoring for the standard for add-on controls is to determine
compliance on a daily basis, as described in the revised proposal. To
meet this intent, the Agency needs data that show the actual compliance
status of the source, not data that simply alert the Agency to poten-
tial problems, and to make an accurate determination of compliance with
the 90 percent reduction standard, the Agency must have both scrubber
inlet and outlet data. Even where feed sulfur is not "highly" variable,
the outlet concentration may vary due to FCCU operation or the source
of the feed, while scrubber performance may stay constant. Therefore,
measuring only the outlet emissions may lead to an incorrect compliance
determination for the percent reduction standard. The Agency recognizes,
however, that an inlet monitor is unnecessary for making continuous
compliance determinations in relation to the 50 vppm standard for add-
on controls. Thus, the Agency has modified the regulation so that
owners or operators may choose to declare their intent to meet the
standard for add-on controls by limiting their outlet S02 emissions
to 50 vppm and install a CEMS at only the outlet of the control device
to determine compliance. The Agency wishes to point outthat, for such
owners or operators, compliance determinations will be made only on the
basis of the outlet S02 emissions without regard for the percent reduc-
tion being achieved by the control device. Such owners or operators may
change their choice so they would be subject to the whole standard on
"90 percent reduction or 50 vppm, whichever is less stringent," provided
a CEMS is installed and maintained at the inlet of the control device
as well as the outlet.
Comment:
Several commenters (IV-D-3, IV-D-6, IV-D-9, IV-D-11, and IV-D-16)
recommended that the outlet CEM requirements should be eliminated for
the standard for add-on controls because CEMS are an unsuitable means
to indicate compliance (determine excess emissions). Three commenters
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(IV-D-3, IV-D-6, and IV-D-9) stated that a post-scrubber CEMS Is
unsuitable to indicate scrubber performance due to large variations
in scrubber inlet SOX concentrations. Therefore, the scrubber outlet
S02 concentration established during the performance test cannot be
expected to indicate compliance with the SOX emission standard over
extended periods of operation. Three commenters (IV-D-6, IV-D-11, and
IV-D-16) cited that the outlet S02 concentration measured during the
performance test of the scrubber and used to define excess emissions is
relatively meaningless since it would be very difficult to determine a
"representative" feed. Two commenters (IV-D-6 and IV-D-9) also stated
that the outlet S02 concentration level measured during the scrubber
performance test could very likely correspond to a scrubber efficiency
better than the standard as there exists a strong possibility that the
scrubber would be operating at a reduction efficiency greater than 90
percent during the performance test. One commenter (IV-D-6) noted that
using an SOg concentration level to indicate scrubber performance is
unsuitable because the method does not take into account the variation
of the relationship between $03 and SC>2 over time and over the range of
feedstocks to be used. Finally, one commenter (IV-D-11) stated that
the outlet-monitor approach cannot compensate for changes in flue gas
volume. The commenter recommended that an S02 monitor upstream of the
scrubber is necessary to indicate scrubber performance.
Response;
At proposal, affected facilities complying with the standard for
add-on controls were required to maintain a continuous S02 monitor at
the scrubber outlet, and excess emissions were determined based on a
trigger outlet concentration level established during the initial
performance test. In the revised proposal, EPA proposed that the
standard for add-on controls has been changed to require daily compli-
ance determinations of the percent reduction being achieved by the
add-on control device. Therefore, the regulation has been revised to
require the installation of a scrubber inlet and outlet S02 monitor for
owners or operators who elect to comply with the standard for add-on
controls. (An owner or operator who seeks to comply solely with the 50
vppm standard, as discussed in the previous comment, is required to
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install only an outlet CEM.) Thus, the situation described by the
commenters is eliminated.
Comment:
One commenter (IV-D-16) stated that since an excess emission report
only triggers awareness, the method of determining excess emissions
specified under 40 CFR 60.105(e)(3)(iii) need not be precise, and thus,
adjusting to an oxygen-free basis is unnecessary.
Response:
The standards now require determination of compliance, on a daily
basis, rather than determination of excess emissions. Compliance
determinations have a greater need for precision than excess emission
determinations because the former are used to determine whether or not
a source Js^ in compliance while the latter are used to trigger aware-
ness that a source may not be in compliance. Therefore, the oxygen-free
basis has been retained.
Comment:
One commenter (IV-K-9) felt that because an add-on control device
achieves greater reductions in SOg emissions than technologies meeting
the standard without add-on controls, "less drastic" compliance monitoring
requirements for scrubbers are reasonable. The commenter referred to
Subpart GGG, 40 CFR Part 60, as an example for this approach in which
pumps with dual mechanical seal systems that include a barrier system
fluid are exempt from monthly VOC monitoring requirements to detect
leaks. This commenter proposed that compliance be determined instead
by an initial performance test, quarterly monitoring of inlet and out-
let SOX concentration using EPA Reference Method 6 or 6B, and continuous
monitoring of wet gas scrubber process variables, such as pH, liquid-to-
gas ratios, and pressure drop, to evaluate scrubber performance in an
ongoing basis.
Response:
Monitoring and testing requirements are chosen to be appropriate
for the control technique and to meet the intent or goal of the
monitoring and testing. The relative stringency of different control
techniques has no bearing on the selection of the most appropriate
monitoring or testing requirement for each control technique. The
example in Subpart GGG referred to by the commenter is not appropriate.
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For pumps without dual seals, monthly leak detection and repair is the
control technique; that is, the monthly monitoring is not to monitor
how well the control is doing, but rather it is the control. The dual
seals for pumps are an alternative control technique. Therefore, the
"exemption" for monthly leak detection and repair is not a monitoring
exemption but a means by which an owner or operator does not have to
use two control techniques. The testing requirement for dual seals was
determined based on its appropriateness to the control technique.
The purpose of monitoring for these standards is determining
compliance on a daily basis. Therefore, the Agency must collect data
on each control technique from which compliance can be determined. The
procedure suggested by the commenter may give information on the opera-
tion of the scrubber, but it does not give information from which the
compliance status can be determined.
In summary, the Agency has determined that the monitoring
requirements for scrubbers are appropriate for determining continuous
compliance and that the arguments and the proposed change offered by
the commenter are unfounded to support a change.
Comment:
Several commenters (IV-D-2, IV-D-3, IV-D-6, IV-D-7, IV-D-16,
IV-D-20, IV-K-2, and IV-K-9) stated that continuous S02 monitors are
unreliable due to monitor operational problems. Problems noted included
generation of imprecise and Inaccurate data, zero and span drift,
intensive operator attention:, excessive sample system plugging, and
unreasonable maintenance requirements.
One commenter (IV-K-9) proposed that the requirement for continuous
monitoring of the inlet and outlet to add-on controls be eliminated.
This commenter expressed concerns about the operability of an outlet
CEMS, stating that utility FJ3D experience has shown that it is very
difficult to maintain the analyzer in a saturated gas stream. This
commenter and Commenter IV-Kt-2 also expressed concerns about the oper-
ability of an inlet CEMS, stating potential difficulties due to
particulate plugging of the analyzer. Commenter IV-K-2 stated that, to
his knowledge, EPA does not have CEMS data showing that the device can
run 24 hrs/day for one full month and give accurate results. This
commenter, referred to the gaps in the monitoring by a CEMS in each of
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the first 10 days in Figure C-l of the BID for the proposed standards.
Commenter IV-K-2 also asked how CEMS reliability was proven, and what
CEMS sample collecting and conditioning systems were used to prove CEMS
reliability.
Response:
The EPA extensively studied the reliability of SOg and diluent
CEMS during the development of Subpart D, Subpart Da, and Appendix F
of 40 CFR 60. Current studies show that state-of-the-art monitoring
systems provide precise and accurate data when proper operation and
maintenance techniques are employed on a continuous basis. Experience
has shown that approximately 2 hrs/day of manual attention is necessary
to obtain an 85 percent or greater availability. Further, as discussed
in the BID for the proposed standards, Appendix D, FCCU catalyst regene-
rator exhausts are similar to those of coal-fired steam generators;
therefore, the continuous S02 monitoring technology proven acceptable
for steam generators should be applicable to FCCU catalyst regenerators.
Sulfur dioxide monitors have been installed on some FCCU catalyst
regenerators; EPA has gathered information on the operational history
of some of these CEMS but the data were insufficient to compare directly
to Appendix F, Procedure 1, to 40 CFR Part 60, which contains quality
assurance procedures for CEMS used for compliance determinations.
The Agency has, for example, conducted tests at an Exxon wet gas
scrubber using inlet and outlet S02 CEMS (see Docket A-79-09, item
II-A-18A). The outlet monitor was on a saturated gas stream without
reheat of the flue gas. There was no particulate removal in the flue
gas prior to the inlet monitor. The duration of the testing was about
12 days. Over this time, no difficulty was experienced in obtaining
valid data. Some regular backflushing of the outlet analyzer system
occurred due to the saturated nature of the flue gas. This limited
time testing suggests that with careful maintenance of the monitors,
long term use and potential problems can be avoided. The difficulty
stated with regard to outlet monitors on a saturated gas stream can be
overcome through adequate design and maintenance of the CEMS. (The
commenter does not state that the difficulty cannot be overcome, but
rather just that it is difficult.)
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The Agency does not agree that particulate plugging will be a
"fatal" problem. In-stack filters have been redesigned with better
shields and improved outside^stack conditioning systems have been
developed that allow removal of the in-stack filter, when necessary.
Furthermore, technologies are available to circumvent CEMS plugging.
Properly designed systems usually have back-purge capabilities to
prevent particulate plugging: of the sampling probe in the stack.
Studies have also shown that1high pressure (greater than 70 psi) air in
backflushing sample lines and probes improves removal of particulate
and moisture from the in-stack probes and filters both upstream and
downstream of scrubbers. Manufacturers of the systems and installation
personnel would be responsible for designing each system for a specific
source. Proper design along with consistent and proper maintenance
should be able to prevent particulate plugging to the extent that an
owner or operator will be able to obtain the minimum data requirements.
Based on these studies, EPA has concluded that continuous $03
monitors are reliable and accurate when properly operated and main-
tained (see Docket A-79-09, item IV-J-1), and are capable of meeting
the minimum requirements for determining compliance with these standards,
Thus, the promulgated standards retain the requirement for continuous
SOg monitors. The EPA does not expect the CEMS to run nonstop for
24 hrs/day for an entire month. The minimum data requirements (i.e.,
collection of 18 valid hours;of data per day for 22 days out of every
30) provide for downtime. This provides the owner or operator time to
maintain and calibrate the CEMS and correct minor malfunctions.
Comment;
One commenter (IV-K-2) asked why EPA bases the NSPS on an
"undeveloped" continuous emission monitor. The commenter referred to
the proposed Section 60.106(e)(2) which requires S0£ CEMS's at "the
control device inlet and outlet to determine kg of S02/hr values'-, while
BID Appendix D, p. D-13, says that the accuracy of a similar CEMS used
to calculate kg of SOg/kg of coke is unknown.
Response: ' ,;
The commenter is confusing the reliability of two different CEMS's.
The "similar CEMS" referred to by the commenter that is in Appendix D
of the BID for the proposed standards, p. D-13, is a CEMS that is to
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obtain an estimate of both kg of S02 and 1,000 kg of coke burn-off. The
latter estimate requires measurement of 10 to 12 parameters and the BID
clearly states that measurement of this many variables introduces
serious questions as to the accuracy of the resulting estimate. It is
this CEMS, which tries to estimate kg S02/l,000 kg of coke burn-off,
that is considered unreliable. However, the standards for add-on
controls do not require measurement of coke burn-off. Rather, the
standard for FCCU's requires that S02 emissions be measured in parts
per million by volume (vppm) at both the inlet and outlet to the
scrubber or other add-on control device. Such a format requires the
measurement of at most two parameters, S02 emissions and diluent 02 or
C02 emissions. The reliability of the S02 and diluent 02 or C02 CEMS's
has been demonstrated and performance specifications for evaluating the
acceptability of these monitoring systems in this format are deemed
adequate as specified in 40 CFR Part 60.13 (46 FR 8352, January 26,
1981) (see Docket A-79-09, item II-J-2). In summary, the comparison
the commenter tries to make is inappropriate. Continuous emission
monitors are available that have the reliability and accuracy to meet
the needs of the standard for add-on controls.
Comment:
One commenter (IV-K-3) recommended an increased allowance for CEMS
downtime and maintenance, such as requiring data for 15 days per month
instead of 22, and 12 hrs/day instead of 18. The commenter stated
that the company has limited commercial experience on one FCCU with a
CEMS installation they believe is reasonably successful (installed less
than 1 year). The installation is downstream of a CO boiler and an ESP.
According to the commenter, a CEMS placed upstream would be subject to
much more severe service because of its exposure to hot catalyst fines
and a higher SOX concentration than that seen by a downstream analyzer.
The commenter added that sampling performed by an upstream CEMS would be
more complex, and the CEMS would be expected to have a lower operating
factor.
Response;
In requiring the use of CEMS's for determining compliance, EPA
based its selection of 18 hours of data in a 24-hour day and 22 days of
data out of 30 days on the minimum data requirements for compliance
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determinations specified for utility boilers under Subpart Da of 40 CFR
Part 60. Under these standards, EPA concluded that the required data
to be collected provided sufficient information to characterize emis-
sions, and that properly operated and maintained GEMS's were capable of
meeting these requirements. The operating conditions at the upstream
CEMS at FCCU's are similar to those found at a Subpart Da boiler CEMS
prior to the flue gas scrubber.
Comment: I
One commenter (IV-K-2) asked whether EPA planned to require an
approved manual emission test twice an hour, 18 hours a day, at times
when the CEMS fails. If a manual emission test is needed, this commenter
asked how long the revised Method 8 takes to perform.
Response;
No manual testing would:be required when the CEMS fails provided
the facility meets the minimum data requirements specified by EPA.
Minimum data requirements were established to allow for periods when
CEMS's are shut down for various reasons but limit the amount of data
permitted to be lost before supplemental sampling is required. These
requirements provide time for CEMS maintenance and calibration and
correction of minor malfunctions. Malfunctions are not likely to occur
every 30-day period. Thus, EPA expects that most CEMS's routinely
will operate better than the minimum data requirements and supplemental
sampling Will be rarely necessary to meet them.
Many methods are available for supplemental sampling; each owner
or operator would develop his approach to obtaining these minimum data
in the Quality Control Plan required by Appendix F, Procedure 1. Any
acceptable sampling scheme, such as Method 8, would have to obtain data
representing at least 18 hours of operation daily. Method 8 is unlikely
to be used, however, because it measures SOX when only S0£ data need to
be obtained. Methods 6 and 6B are more likely to be used. If Method 6
is used, the minimum sampling time is 20 minutes and the minimum sampling
volume is 0.02 dscm (0.71 dscf) for each sample. Samples are taken at
approximately 60-minute intervals. Each sample represents a 1-hour
average. To obtain one valid day from supplemental sampling requires
18 valid samples. Method 6B> if used, would also have to collect a
sample representing a minimum of 18 hours. If a back-up monitor is
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used instead, then a minimum of 18 valid hours to obtain a valid day is
still required.
Comment:
One commenter (IV-K-2) believes that neither Method 6 nor 6B can
be used to supply back-up data when the CEMS fails because: (1) Methods
6 and 6B have sampling problems and poor reliability, and (2) tempera-
tures above 120°C are forbidden when using either method (see 49 FR
9684 for Method 6A and 49 FR 9686 for Method 6B). The commenter
pointed out that the EPA has stated that at least 160°C is needed when
testing.
Response:
The commenter is concerned with the test methods (6 and 6B) that
may be used to gather supplemental data in order to meet the minimum
data requirements for the standard for add-on controls. The 160°C
temperature referred to by the commenter is required when using Method
8, which is used in determining compliance with the standard for FCCU's
without add-on controls. Thus, the commenter's concern about Methods
6A and 6B limiting probe temperature to 120°C is irrelevant to the
160°C probe temperature identified for Method 8.
The Agency believes that the commenter's concerns about sampling
problems and poor reliability have been addressed by the changes made
to these methods as reported in 49 FR 9684. These two methods are
possible means by which an owner or operator can supplement occasional
missing data and are not the only means available to the owner or
operator. Details of the actual procedure(s) chosen by the owner or
operator would be provided in the Quality Control Plan required by
Appendix F, Procedure 1.
Comment:
One commenter (IV-K-2) suggested that the 7-day average performance
of the control device be calculated using the individual daily averages
of the CEMS data, rather than all of the valid hours within the 7-day
period. The commenter felt this should be done in order to prevent an
operator from "bunching up" valid CEMS data points on "good" days and
taking minimum measurements on "bad" days.
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Response:
The deliberate actions ion the part of an owner or operator
described by the commenter would clearly be seen as an attempt to
circumvent the standard and Isuch circumvention is illegal, prohibited
by the NSPS General Provisions in Subpart A, Section 60.12 of 40 CFR
Part 60. Furthers the minimum data requirements (i.e., requirement to
collect 18 valid hours out of every 24 hours) will limit the potential
for showing a source to be in compliance when the source would actually
be out of compliance if bunching did not occur. Therefore, the Agency
does not believe it necessary to change the method of averaging data
for determining daily compliance when using the add-on controls and
has retained the averaging of all valid hours.
Comment:
One commenter (IV-K-2) suggested that the Agency require
averaging daily percent reduction values when calculating the 7-day
rolling average rather than .averaging inlet and outlet data
separately. The commenter, in making this suggestion, pointed out
that the time series model was analyzed in terms of percent values
and, through a sample calculation, that averaging percent emission
reduction values provides a more stringent emission standard.
Response:
The Agency considered both averaging daily percent reduction
values and averaging inlet and outlet data separately when calculating
the 7-day rolling average. Calculating a daily average of hourly
percent reductions requires both monitors to be operating at the same
time for a minimum of 18 hrs/day to obtain a valid day. Averaging
inlet and outlet data separately allows a little more leeway in the
time that either monitor is hot functioning before back-up measurements
or monitors are needed.
Further, the Agency found little difference (less than 0.4 percent)
in the calculated rolling 7-day percent reduction value using the two
methods described by the commenter for the data used in the time series
analysis (see Docket A-79-09:, item IV-B-13). In addition, the example
calculation provided by the commenter to show a "more stringent" standard
is insufficient as the Agency can easily construct an example showing
the opposite result.
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In summary, the Agency believes the averaging of inlet and outlet
data separately adequately and accurately determines compliance, and
does so with the potential of cost savings to affected owners and
operators by decreasing the need for using back-up measurement methods.
Comment:
Two commenters (IV-K-2 and IV-K-9) questioned the costs of GEMS's
reported by EPA. One commenter (IV-K-2) asked whether the sample
collecting and conditioning systems needed to ensure a reliable CEMS
were included in the price of the CEMS. This commenter questioned the
cost of $40,000 in the preamble for the additional CEMS, as BID Table
D-l gives a cost of a CEMS as $59,000 to $80,000 (1981 dollars), and
asked whether the Agency updated the costs from the original proposal.
The second commenter (IV-K-9) felt the Agency substantially underesti-
mated the costs of a CEMS. This commenter estimated that the total cost
(analyzer, sampling system, and installation costs) would be about
$100,000 per analyzer for an extractive system and about $150,000 to
$175,000 per analyzer for an across-the-stack system. This commenter
also estimated the annual maintenance manpower costs to be about
$16,000 for an extractive system and about $2,000 for an across-the-
stack system. The second commenter also stated that the estimate of
$40,000 for the additional monitor appears to reflect only the cost
of the analyzer and not the sampling system and installation costs.
This commenter felt that the proposed requirement for continuous .
monitoring at the inlet and outlet to add-on control devices be eli-'
minated because of the cost of CEMS's.
Response:
The cost of the additional CEMS reported in the revised proposal
notice reflected the cost of an extractive analyzer and installation
(in February 1981 dollars). The Agency updated the original 1981 costs
for the extractive analyzer system and obtained a revised fourth quarter
1984 cost estimate of $69,300 '(including installation and data acquisi-
tion system (DAS); $46,200 without the DAS).
The Agency-also recently attempted to obtain updated CEMS cost
data by contacting vendors and source owners or operators using CEMS
(see Docket A-79-09, item IV-A-1). The study found "worst-case"
vendor costs for an SOg/diluent extractive system from $43,000 to
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$100,000 (1984 dollars). (The worst-case costs included additional
costs for longer sample lines, corrosion-resistant probes, probe
backflush systems, and computer data acquisition systems capable of
generating emissions reports.) Worst-case installation costs (which
are for an S02/NOx/diluent CEMS) ranged from $2,000 to $80,000. Total
worst-case costs for an extractive analyzer would be from $45,000 to
$180,000 (including a DAS and installation). "Best-case" costs for
an extractive analyzer system, including installation, ranged from
$15,400 to $86,000. The commenter provides an estimate of about $100,000
(analyzer, sampling system, and installation). Taking out the cost of
a DAS (about $23,100) from the worst-case costs, the commenter's
estimate falls in the middle-to-upper end of the worst-case costs.
The Agency notes that its original cost estimate for an extractive
analyzer, when updated to 1984 dollars, still falls within the worst-
case costs range reported in the updated study.
The across-the-stack cost estimate ($40,460) obtained in February
1981 was for a complete outlet monitoring system to which the Agency
added a cost of $20,000 for installation and $20,000 for a DAS. Total
cost, including installation;, for the outlet monitor was, thus, $80,400
(February 1981 dollars). Updating this cost to fourth quarter 1984
dollars yields a cost estimate of about $92,900 for the analyzer, DAS,
and installation. Data on aCross-the-stack CEMS gathered more
recently show worst-case vendor estimates for an S02/diluent CEMS
(including a DAS) to range from $44,000 to $96,000, with installation
ranging from $2,000 to $80,000. Assuming a DAS cost of $23,100, total
worst-case costs without a DAS would be from $22,900 to $153,000.
Best-case condition costs were estimated to be $34,400 to $60,000 per
analyzer ($34,000 to $45,000 for the analyzer plus a DAS, plus $400 to
$15,000 installation). Commenters IV-K-9 estimated costs of about
$150,000 to $175,000 per analyzer (analyzer, sampling, and installation),
which falls in the upper range of the worst-case vendor estimates.
The annual maintenance costs estimated by the Agency in the
proposal BID Appendix D were,$11,000 for either an extractive or across-
the-stack CEMS. Updating the cost results is an estimate similar to
the commenter1s estimate of $16,000 for an extractive system and is
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more conservative than the commenter's estimate for an across-the-stack
system.
6.3 WITHOUT ADD-ON CONTROL DEVICES
Comment:
Several commenters (IV-K-3, IV-K-4, IV-K-6, and IV-K-12) stated
that EPA had underestimated the costs of daily Method 8 testing. One
commenter (IV-K-4) believes that annual expense for labor to collect
and analyze daily Method 8 samples would be about $300,000/yr. This
commenter specifically indicates that this cost assumes no automatic
traversing system is used, but all testing is accomplished manually.
The commenter estimated that daily sampling would require a full-time
3-person (supervisor and 2 assistants) stack testing crew, which
would be responsible for testing, repair, and maintenance of the trains,
calibration checks, analyses, etc. This commenter also stated that a
back-up crew would be necessary. Commenter IV-K-3 estimated the
operation and maintenance cost to be about $250,000/yr. This commenter
assumed, in part, that sixteen samples would be required each day and
analyzed at 15 minutes per sample. This commenter used vendor labor
hour rates to estimate the labor charges. Commenter IV-K-6 estimates
that daily Method 8 sampling, using a contractor, would be about
$400,000/yr. This commenter estimated daily labor hours to be 8 hours
for sampling and analysis apiece and 12 hours for preparing the reports
and project management. Commenter IV-K-12 estimated that the total
annual cost would be about $184,000 per FCCU. This commenter believes
that 4 man-years of effort would be required and based the cost on
3 technicians (each at $41,600/yr) and 1 professional (at $58,800/yr).
Another commenter (IV-K-2) asked how EPA determined yearly costs
of Method 8 to be "reasonable" when the costs are unknown? The
commenter did not think it was reasonable to claim the costs to be
"reasonable" when the costs are based, in part, on a traversing system
not yet developed. The commenter also asked the Agency to identify
the cost of revised Method 8 and what the cost would be if you did not
have an automatic traversing system. Commenter IV-K-3 questioned EPA's
assumption that an automatic traversing system can be readily developed
and implemented. This commenter noted that adding equipment such as
an automatic traversing system will increase system complexity and that
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problems with an automatic traversing system (such as binding) may be
significant and degrade on-stream factor.
Another commenter (IV-K-4) stated that the daily manual stack
testing requirement using EPA Method 8 for SOX emissions determination
is premature, pointing out that because no means of automated perfor-
mance of this test exists, it must be performed manually. According
to this commenter, future development of an automatic traversing
system is speculative and unfounded given the technical complexity
of the stack testing protocols involved.
Response:
The standard requires one 3-hour sample per day, 365 days per
year. As noted in the commeint summary, one commenter states explicitly
that they calculated their labor costs assuming no automatic traversing
system. The Agency believes that the other commenters made the same
i
assumption. After further consideration, the EPA has agreed with the
commenters that the assumption of an automatic traversing system should
not be used for evaluating and recommending daily Method 8 testing,
although the Agency still contends that it is technologically feasible.
Instead, the Agency has; revised the cost estimate assuming that a
monorail system will be installed at each of the two sampling ports
and that a single sampling train will be used, with manual movement of
the sampling train for traversing and changing ports (see Docket A-79-09,
item IV-B-12). Although not| addressed by the commenters, EPA decided
that it was appropriate to also include a cost for an enclosed sampling
area to protect the sampler and equipment from various weather condi-
tions, such as rain and snow. The capital cost of the monorail system
and enclosure is estimated to be $20,000. When the Agency originally
estimated the cost using an automated traversing system, we assumed
two sampling trains, one in each port. With the revised assumptions,
only one sampling train is used, and moved from one port to the next;
this halves the number of samples to be analyzed to 365 (1 per day).
The EPA disagrees with the commenters1 claim that 3 or more people
would be devoted full-time t6 this stack testing. Only one 3-hour
sample is required each day. The Agency believes that it would take an
average of 8 labor hours per-day to prepare the equipment, conduct the
sampling, and perform periodic maintenance on spare equipment, with an
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added labor for analysis of about 1.3 hours per sample. This estimate
is the same or similar to that assumed by Commenter IV-K-6 and, when
adjusted for the number of sample points, by Commenter IV-K-3. The
Agency estimated that the quarterly reports would take about 50 hours
each to prepare. This is equivalent to less than one hour per day.
The Agency strongly disagrees with the 12 hour per day estimate used by
Commenter IV-K-6. On the basis of the above assumptions and revisions,
the revised annualized cost per affected facility is estimated to be
$120,000.
Comment:
Many commenters (IV-K-1, IV-K-2, IV-K-3, IV-K-4, IV-K-5, IV-K-6,
and IV-K-8) stated that daily testing should be deleted from the
standard for FCCU's without add-on controls. The commenters felt
that daily testing was too costly and unduly burdensome, especially,
according to one commenter (IV-K-4), when compared to the costs of
monitoring for the scrubber or testing under the feed hydrotreat option.
One commenter (IV-K-3) stated that he knew of no other instance in
which this type of non-routine sampling is being performed on a daily
basis to satisfy compliance requirements. This same commenter also
stated that, in general, direct compliance information should not
be required if, in the course of obtaining it, an unreasonable cost
burden occurs. Commenter IV-K-3 also states that the cost of daily
Method 8 testing will impose a disproportionate hardship on small
FCCU's, as the costs are independent of unit size.
Commenter IV-K-1 stated that the cost of daily Method 8 testing
could hamper improvements in SOX reduction catalyst development and
felt that the estimated cost of $130,000/yr would put an onerous
burden on FCCU operators who choose to develop and use SOX reduction
catalysts.
A third commenter (IV-K-6) stated that the economic impact is
significant and would affect the profitability of FCCU operation.
This commenter noted that the corporation operates 9 FCCU's and
claimed that they would have to spend approximately $3.6 million/yr to
conduct daily Method 8 testing.
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Response: ;
The Agency recognizes that daily testing with Method 8 is not
inexpensive, but that it is also not an unreasonable cost. The Agency
has examined various methods available to show daily compliance with
the standards. For facilities that opt to use SOX reduction catalysts
to meet the standards, the Agency has determined that daily Method 8
testing is currently the only viable alternative that enables the
Agency to be sure that the owner or operator is in compliance on a
daily basis.
The relative costs of the various methods for determining
continuous compliance available to all affected facilities subject to
the standards is not a valid basis for rejecting one method or another,
just as the relative costs of the capital investment of the various
control options are not a basis for excluding one or the other. What
is relevant is whether the total (capital, annual, monitoring, etc.)
cost of compliance for meeting the standards for an affected facility
is reasonable or unreasonable. Similarly, the lack of other situations
requiring similar "non-routine" sampling is not a valid basis for
eliminating this requirement, Daily testing is needed for this standard
in order to show daily compliance.
The Agency disagrees that the burden is "unreasonable" or "onerous,"
the economic impact is "significant," or the profitability of FCCU
operation will be adversely affected. The Agency studied the potential
economic impact of the standards on small and large refineries and
reported and discussed the findings in the original proposal notice to
these standards (49 FR 2072). The economic impact to the small (and
large) refiner is expected to be small because most, if not all, of the
cost should be capable of being included in the prices of the refined
petroleum products and the resulting price impact is reasonable. These
results were obtained assuming compliance by all projected affected
facilities with the standard! for FCCU's with add-on controls, which
is more expensive than compliance with the standard for FCCU's without
add-on controls. Therefore,; the economic impacts of complying with
the standard for FCCU's without add-on controls will be smaller.
The Agency believes that the monitoring costs associated with
daily Method 8 testing are unlikely to affect SOX reduction catalyst
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development. Even with the higher monitoring costs, SOX reduction
catalysts are still likely to be the least expensive route to meeting
the standard. Thus, development on SOX reduction catalysts will still
continue as owners or operators try to minimize their costs in meeting
these standards.
The third commenter's estimate of $3.6 million assumes: (1) all 9
FCCU's will use SOX reduction catalysts and (2) the cost per FCCU for
daily Method 8 testing is $400,000 per FCCU. The Agency believes both
are highly unlikely to occur because: (1) we do not expect all FCCU's
(e.g., such as those with very high sulfur feed contents) to use SOX
reduction catalysts and (2) the commenter overestimates the cost of
dail| Method 8 testing (see response to the previous comment).
In conclusion, the Agency believes that the cost of daily Method 8
testing is reasonable in order to ensure daily compliance. Less expen-
sive methods that allow the Agency to make equivalently accurate daily
compliance determinations are encouraged and may be used subject to the
approval of the Administrator.
Comment:
One commenter (IV-K-4) stated that daily stack testing is an
unduly burdensome requirement and added that EPA has not provided a
sufficient basis to justify such an extraordinary requirement as daily
stack testing. According to this commenter, daily manual stack testing
using either Method 8 or a modified Method 6 is unreasonable in terms
of frequency and is inequitable to refiners using various control
options. In addition, the commenter remarked that no data have been
presented to support a thesis that emissions would vary so widely as to
necessitate monitoring on a daily basis.
Another commenter (IV-K-5) opposed the proposed daily manual
testing using Method 8 for FCCU's using sulfur reduction catalysts.
The commenter provided three reasons as the basis for his remarks:
(1) the approach is too labor-intensive; (2) EPA has not adequately
demonstrated the need for this requirement; and (3) the requirement
runs counter to the current national effort to increase the produc-
tivity of the American workforce.
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Response:' '-.
These standards require an owner or operator to determine compli-
ance status on a daily basis. For owners or operators using SOX
reduction catalysts to meet 'the standards, the Agency has thoughtfully
and thoroughly considered options by which daily compliance determina-
tions could be made accurately and with certainty. At this time, daily
testing is the only method that the Agency knows will accomplish this
goal. The Agency has "minimized" the amount of required sampling to
one 3-hour test per day to help reduce the labor burden, but still
meet the goal of daily compliance determinations. Thus, the Agency
strongly disagrees that the ^frequency of the testing is either
unreasonable or inequitable, as owners or operators subject to the
standard for add-on controls or for low-sulfur content feeds are
also required to make daily determinations. Data has been submitted by
industry (for example, see pocket A-79-09, item IV-K-8) that show wide
variation in SOX emissions from FCCU's using SOX reduction catalysts.
Even if this variation does ;not vary "so widely," an FCCU operating
right at the emission limit may go above the emission limit due to a
small variation. Thus, daily compliance determinations are appropriate.
The Agency points out that as additional data on FCCU's using SOX reduc-
tion catalysts are generated, alternatives to Method 8 testing may
become available and be used upon Administrator approval, but the daily
determination of compliance is unlikely to change. That the approach
is labor-intensive is irrelevant. The Agency has considered the cost
of the daily testing and has determined the cost to be reasonable.
Failure to make daily compliance determinations runs counter to the
national effort for ensuring a cleaner environment. Thus, the Agency
can see no merit to the comment that such testing and employment of
labor to perform the testing runs counter to the national effort to
increase the productivity of the American work force.
Comment:
One commenter (IV-K-6) believed that insufficient qualified
contractor manpower exists to conduct the Method 8 compliance sampling.
Response:
The EPA assumed that in-house personnel would be used to conduct
the Method 8 compliance sampling. The EPA believes there is sufficient
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lead time to train such personnel without requiring or solely relying
on contractor manpower.
Comment:
One commenter (IV-D-16) stated that the proposed regulation does
not supply sufficient information (calculation procedures) under
Section 60.106, "Test Methods and Procedures," to determine total SOX
emissions.
Response:
The EPA agrees with the commenter. Therefore, the regulation has
been revised to indicate that modification to the calculation procedures
specified in Reference Method 8 will be required to calculate total
SOX emissions as S02.
Comment:
One commenter (IV-D-16) asked how S03 values could be presented in
Table C-14 of the proposal BID when Section D.I.3.2 (page D-8) of the
proposal BID states, in reference to the field tests providing the data
for the values in Table C-14, "S03 could not be determined in the field
II
• • • •
Response:
The remaining portion of the statement made in Section D.I.3.2
of the proposal BID states that S03 and particulate sulfate samples
were later analyzed in a laboratory by ion chromatographic analysis.
The emission summaries in Table C-14 of the proposal BID labeled
"Sulfur Trioxide" included all sulfates collected in the isopropanol
impinger which passed through a heated (178°C) filter. This would
have included most of the sulfuric acid mist, if any were present
(see next comment). The emissions labeled "Sulfates" included all
water soluble sulfates collected in the probe and heated filter, as
determined by water leaching the probe wash residue and filter and
analysis of the leachate.
Comment:
One commenter (IV-D-16) asked if separate values for sulfuric
acid mist and sulfur trioxide can be determined.
Response:
The EPA knows of no practicable technique to determine separate
values for these two species.
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Comment:
Many commenters (IV-K-I, IV-K-3, IV-K-4, IV-K-5, IV-K-8, IV-K-10,
and IV-K-12) suggested alternatives to daily Method 8 testing for
demonstrating continuous compliance. The commenters suggested three
basic types of alternatives: (1) the use of less frequent Method 8
testing, (2) periodic testing for SOX until an $03 CEMS is developed,
and (3) the use of continuous SC>2 monitors with periodic testing for
$03. One commenter (IV-K-8); stated, in general, that the daily appli-
cation of Method 8 is cumbersome, and thus, the proposed rule should
contain provisions to allow the permittee to demonstrate continuous
compliance based on a broader spectrum of options. This commenter
pointed out that: (1) the proposed rule restricts testing options and
does not provide for flexibility with regard to future improvements in
monitoring or operating strategy; (2) more flexible language would
encourage better process understanding within the regulated community;
and (3) exclusion of such a provision would require that future changes
be made through formal rulemaking.
Less Frequent Method 8 Testing. One commenter (IV-K-10) stated
that testing for continuous compliance may not need to be performed
as frequently as proposed. This commenter suggested, for example, that
if a week of daily Method 8 testing shows that no test is over the
emission limit, then the testing frequency should be relaxed to seven
tests on consecutive days once each quarter or semi-annually. The
commenter pointed out that the tests are' too expensive to be performed
more frequently than necessary and that a history of testing data may
show that daily testing by Method 8 is not necessary if there are no
feed or operational upsets. ;
Periodic SOX Testing Until SOX CEMS Developed. Two commenters
(IV-K-4 and IV-K-5) suggested that instead of daily Method 8 testing
EPA require annual stack testing (IV-K-5) or quarterly or monthly
stack testing as determined !on a case-by-case basis (IV-K-4) until a
SOX CEMS has been developed. Commenter IV-K-5 suggested (as a second
choice recommendation to annual testing) that EPA specify a continuous
SOX monitor and develop performance standards for such a monitor. This
commenter provided literature on an S02 monitor that they thought
should be able to monitor $63 also. The other commenter (IV-K-4) felt
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less frequent compliance testing was sufficient because their general
experience with FCCU catalysts indicates that changes in emission rates
from an FCCU that can achieve the proposed standards are sufficiently
gradual to allow the less frequent compliance testing. Another
commenter (IV-K-1) simply stated that some alternative to the SOX
standard should be used until a SOX CEMS is proven to be practical in
FCCU service.
SO? Monitors with Periodic Method 8 Testing. One commenter
(IV-K-3) suggested using an S02 CEMS with an "$03 multiplier" to deter-
mine daily compliance, with the multiplier determined from a rolling
average of periodic (e.g., biannual) measurements using Method 8.
This commenter stated that the periodic tests could be run at repre-
sentative feedstock and operating conditions to ensure a fair estimate
of the $03 multiplier.
Another commenter (IV-K-12) recommended, if daily compliance
determinations are required, the use of an SOg CEMS in conjunction with
periodic comparisons of performance between the CEMS and Method 8.
This commenter made this suggestion on the basis of: (1) their belief
that S03/S02 ratios are relatively constant and predictable, and that
the 503 component of SOX is relatively insignificant; (2) EPA's data
that describe the variability in the ratio of $03 to SOX in emissions,
and on which the requirement for daily testing is based, are limited
and scattered; (3) maximum $03 emissions are most likely to occur when
the FCCU regenerator is operated in a complete combustion mode without
SOX reduction additive on the catalyst, because, as the oxygen atmosphere
increases, the conversion of S0£ to $03 is favored, and SC"3 will be
driven to maximum concentrations if SOX reduction additive is not
used to remove total sulfur; (4) a summary provided by them of emission
monitoring at one of their FCCU's operating in the complete combustion
mode without sulfur reduction additive shows reasonably good agreement
between the CEMS and a wet chemistry method, and shows an 503 concentra-
tion of only a few parts per million -- less than 1 percent of total
SOX emissions; and (5) additional FCCU test results provided by them
support their conclusion that regenerator flue gases on units not
using SOX reduction catalysts but with CO boilers contain negligible
amounts of 503.
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A third commenter (IV-K-8) proposed that the fraction of $03 not
recorded on the S02 monitor be determined periodically by a Method 8 or
modified Method 6. This would be in addition to S02 monitoring on a
continuous basis. This commenter pointed out that data provided by
them indicates that approximately 10 to 20 percent of the flue gas
sulfur occurs as $03.
Response:
The Agency has considered the alternatives suggested by the
commenters. The Agency agrees that any test should not be performed
more frequently than necessary and that a history of test data may
show that daily testing is unnecessary. However, such a "history of
test data" does not exist at this time and without such data, the
Agency does not believe any 'of the alternative monitoring or testing
schemes suggested can be implemented at this time and ensure that
accurate continuous compliance determinations are made. Further, the
commenters did not provide much data to support their arguments, and
available data show that the S03/SOX ratio can be variable.
As noted above, one of ithe commenters provided literature on an
S02 monitor that they thought should be able to monitor $03 also. The
information and literature provided were insufficient for the Agency to
evaluate this potential for this particular monitor. The Agency has
examined other monitors for :their ability to monitor SOX. To date,
none of the monitors examined has proven suitable.
The Agency does agree that many of these alternatives may be shown
acceptable as more data on SOX reduction catalyst use and SOX emissions
are generated. Therefore, the standard explicitly states that such
alternatives supported by sufficient data may be approved on a case-by-
case basis. Some of the criteria that may be considered are the S03/SOX
ratio, product feed variability, frequency of product slate changes,
operational variability in regenerator conditions (e.g., excess oxygen,
temperature), catalyst addition schedules, and FCCU operating conditions,
The development of a successful SOX monitor would also be an acceptable
alternative, upon approval by the Administrator, to Method 8 testing.
In the meantime, however, the Agency has retained daily Method 8 testing
for determining compliance on a continuous basis for the FCCU without
add-on control standard.
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Comment:
One commenter (IV-K-6) states that the use of continuous
monitors will provide a means of determining compliance for FCCU's
without add-on controls at a more reasonable cost than Method 8.
Response:
As discussed in Section 2.2, "Regulated Pollutant," the Agency
continues to believe that SOX is the most appropriate regulated pollu-
tant for FCCU's operating without add-on controls. As S02 monitors
do not measure $63, they cannot be used to provide continuous compliance
determinations when SOX reduction catalysts are being used.
Comment:
Two commenters (IV-D-6 and IV-D-9) stated that the continuous
emission monitoring requirement should be eliminated for the standard
for FCCU's without add-on controls because FCCU outlet S02 concentra-
tions are not a true indication of the SOX emission rate. The
commenters argued that variables in subsequent operations can differ
considerably from those during the performance test, making outlet
concentrations unsuitable as a gauge of compliance.
Response:
As originally proposed, EPA considered S02 monitoring as the most
reasonable means of determining excess emissions for FCCU's using SOX
reduction catalysts, recognizing that such an excess emission level
based on FCCU outlet S02 concentration does not provide a precise indi-
cation of SOX emissions per 1,000 kg of coke burn-off. This particular
concern, however, is no longer relevant as the standard now requires
daily determination of compliance using direct measurements of SOX emis-
sions (i.e., daily testing with Method 8).
Comment:
One commenter (IV-D-16) stated that since there will be catalyst
particles in the flue gas to the scrubber, how can Method 8 be used as
Method 8 requires "the absence of other particulate matter?" The com-
menter also pointed out that this problem could render Method 8 invalid
for outlet gases. This commenter also asked in a later comment letter
(IV-K-2) how EPA knows that the revised proposed Method 8 is not subject
to interference from particulates as is Method 8. In addition, the
commenter questioned whether testing of revised proposed Method 8 has
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been performed that shows no particulate interference, repeatability by
one tester, reproducibility by different testers, precision, and accuracy.
One commenter (IV-K-4) stated that EPA has failed to recognize
possible interfering effects associated with common practice for partic-
ulate control in the Method 18 stack test measurement. The commenter
believes that refiners are likely to use an ESP to comply with the FCCU
particulate standard. The oommenter stated that, according to EPA, the
injection of either ammonia or an "enhanced" amine into the ESP to
adjust particle resistivity land improve fine particle removal in the
ESP can produce significant interfering effects in SOX determinations
using Methods 6 and 8. The commenter added that more developmental
work should be done to identify and quantify these interfering effects
on the SOX emission test methodology before EPA adopts a specific test
method for NSPS SOX compliance monitoring purposes.
Response:
The EPA agrees that the presence of "other particulate matter"
could invalidate the Method 8 test results. Therefore, appropriate
changes have been made in the regulation to permit the insertion of a
heated filter and probe in the sampling train, prior to the impingers.
The heated probe and filter ;will prevent the particulate matter from
getting into the impinger solution. Filters would be required that are
at least 99.95 percent efficient, as required in Section 3.1.1 of
Method 5. There is no indication or reason to suspect these filters
would not eliminate the analysis problem. If analytical interference
because of particulates still exist, then alternative analytical tech-
niques (for example, ion chromatography) are available for use upon
approval by the Administrator.
The Agency has not conducted testing of Method 8 as modified under
these standards to specifically address the commenter's concerns.
The Agency knows of no technical reason, however, as to why the modi-
fications to Method 8 underithis subpart would adversely affect the
repeatability, reproducibility, precision, or accuracy of Method 8. In
addition, EPA is currently developing test procedures for minimizing the
sulfate interference in particulate matter measurements. The alterna-
tive of measuring both particulate matter and sulfur oxides with the
same equipment and analytical techniques will be addressed at that time.
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The EPA acknowledges that ammonia has known interfering effects on
SOX determinations. We believe there are alternative techniques to
eliminate the interference and are currently studying potential inter-
ference problems with respect to ammonia. Thus, in cases where ammonia
and/or amines are expected or are known to create problems, the owner
or operator should consult the Administrator for approval of alternative
test methods.
Comment:
One commenter (IV-K-6) stated that the collection of a grab sample
using Reference Method 8 is less reliable than a continuous on-line
analyzer, even though there could be some minor variation in the $03 to
S02 ratio in the stack gas. The commenter believed the use of Method 8
could give unrealistic results where an unscrupulous operator could
adjust the operating conditions prior to obtaining the daily sample.
Response:
The revised proposed standards specified that the measurement of
SOX emissions from FCCU's using SOX reduction catalysts would be
accomplished by conducting revised Method 8 for one shift each day.
The Agency knows of no evidence that the variation in total SOX through
the course of a day is any greater than the variation in the S02 to SOs
ratio in the stack gas and thus no evidence for the commenter's remarks.
The EPA assumes that operators will obtain valid samples that are
representative of operating conditions at the facility and, therefore,
will not alter operating conditions prior to sampling. Such deliberate
actions on the part of an owner or operator to obtain unrealistic
results clearly constitute a circumvention of the standard and is
illegal under Subpart A, the General Provisions (40 CFR Section 60.12).
Inspection of plant operating data by EPA and State personnel would
lead to detection of such alteration of plant operation.
Comment:
One commenter (IV-K-2) questioned whether 160°C (320°F) is
the appropriate temperature for the heated probe and filter in the
revised Method 8. The commenter based his question on the following
assertions:
(a) The commenter believed that the dew point for SOs can often
be above this value, especially for FCCU's running more than
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0.3 weight percent sulfur in the feed, and collecting sulfuric
acid in the heated filter will not help the revised Method 8
to yield correct results.
(b) The commenter believed that a minimum probe temperature of
200°C (400°F) was being established for Method 5, and believed
the 160°C probe temperature seems to be recreating an earlier
problem.
(c) The commenter believed that this modification would allow the
probe and heated filter to corrode and leak in a few days if
used in a flue gas with a high SOX content.
This commenter also asked how the 160°C (320°F) temperature at the
probe is reached if the staqk temperature is hotter, or if it is
colder. This commenter stated that if a "probe catch" is a deposit
in the probe, the probe would soon plug up.
Response;
The EPA based the selection of the temperature for the heated
filter and probe in the revised Method 8 on the temperature specified
in the proposed Method 5B and 5F (50 FR 21863, May 29, 1985), which are
the methods for sampling particulate matter at FCCU's. The EPA agrees
that the dew point for $03 may be higher than the temperature of the
heated filter and probe (160°C). In such instances, the filter would
pick up condensed $03 (most likely, though, as sulfuric acid mist),
thereby leading to a low estimate of 803 as measured in the impingers.
The Agency believes that this problem is small because the filter would
pick up only a small part of the sulfuric acid mist, and the rest
would pass through the filter and be collected in the impingers.
Thus, the Agency recognizes that, in such situations, a potential
bias exists to underestimate emissions, but believes that it is small
provided the 160°C is maintained.
The commenter's third assertion is neither relevant nor correct.
The materials used (glass and stainless steel) in the probes and
filter holders are not subject to corrosion from sulfuric acid.
Further, the probes and filter holder are removed each day (after the
3-hour test) for cleaning. ;In addition, FCCU operators would be
required to conduct periodic leak checks. If leaks are detected in
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the system, or if the sampling system fails, then the system would
need to be repaired.
With regard to the stack temperature being different from the
probe temperature, if the stack temperature is hotter, there is no
problem from an SOX enforcement standpoint - more SOX will be trapped
in the impingers - and thus no temperature adjustment has to be made
at the probe. However, if the stack temperature is colder, less SOX
will pass through the filter and a temperature adjustment has to be
made. It is common practice to electrically heat the probe to attain
the desired temperature.
Finally, with regard to plugging of the probe, as part of normal
operating procedures, sampling conducted using revised Method 8
requires that the probe be cleaned out after each run and that the
collected sample be discarded from the analysis. This procedure
eliminates the potential problem brought up by the commenter.
Comment:
One commenter (IV-K-2) asked why the isopropanol impinger was
deleted from Method 8.
Response:
Method 8 was designed primarily for the separate capture and
measurement of sulfuric acid and S02. The isopropanol (IPA) impinger
is used to collect sulfuric acid and 863, while the hydrogen
peroxide impinger is used to collect S02« In the absence of the IPA
impinger, the hydrogen peroxide impinger will collect all the SOX
compounds together. The current standards for SOX reduction catalysts
are based on total SOX; there is no need to separate S02 from other
sulfur emissions. Therefore, EPA eliminated the IPA impinger from
Method 8, the effect of which is to simplify the test procedure,
analysis, and calculations.
6.4 FEED SULFUR CUTOFF
Comment:
One commenter (IV-K-10) felt that the cost of testing the feed
sulfur at FCCU's using the alternative feed sulfur cut-off standard is
too expensive to be performed more often than is necessary and suggested
that such testing should be required once per week if the feed is
previously found to contain below 0.3 percent sulfur in every sample
for a week.
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Response:
For these standards, owners and operators are required to
determine compliance on a continuous basis (i.e., on a daily basis).
As described in the proposed standards, most refiners manually sample
the FCCU fresh feed once per day. Fresh feed sulfur content, however,
may change on an hourly basis. Requiring samples to be collected once
per hour is not practical using manual sampling techniques. Therefore,
the Agency selected a sampling frequency of one sample per 8-hour
shift. This frequency would measure major fluctuations in fresh feed
sulfur level and is reasonable considering current refinery sampling
practices. The sampling program suggested by the commenter would not
allow the Agency to be sure that the owner or operator is in fact
meeting the standard on a daily basis. Furthermore, past feed usage is
not a good indicator of future use; many refiners use different feeds
or feed blends for short periods of time. Therefore, the Agency has
retained daily testing for f^ed sulfur content for those operators
using this alternative standard.
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7.0 COMPLIANCE COMMENTS
7.1 SOURCE OPERATION DURING MALFUNCTIONS
Comment:
One commenter (IV-D-7) requested that EPA consider establishing
standards that allow a certain amount of scrubber downtime without
requiring a FCCU shutdown.
Response:
The General Provisions in 40 CFR 60 provide for malfunction of
control equipment. "Malfunction" means only sudden and unavoidable
failure of air pollution control equipment, process equipment, or of a
process to operate in a normal or usual manner. Failures that are
caused entirely or in part by poor maintenance, careless operation, or
any other preventable upset condition, are not considered malfunctions,
As stated in Section 60.8(c), emissions in excess of a standard due to
a malfunction do not represent a violation of the standard. In addi-
tion, scrubbers currently applied to FCCU's have demonstrated reli-
ability levels in excess of 95 percent (discussed in Section 3.1 of
this document). Thus, it is unnecessary to provide a provision in the
standards for scrubber downtime.
Comment:
One commenter (IV-D-16) asked if the affected facility is allowed
to continue operating during continuous emission monitor malfunctions.
Response:
An affected facility may continue to operate during continuous
emission monitor malfunctions. However, as prescribed under 40 CFR
60.7(b) and (c)(3) of the General Provisions, the owner or operator
shall maintain records of any periods during which a continuous moni-
toring system or monitoring device is inoperative, and the quarterly
(or semiannual, if no exceedances have occurred during a particular
quarter) compliance report shall include the date and time iden-
tifying each period during which the continuous monitoring system was
inoperative, except for zero and span checks, and the nature of the
system repairs or adjustments. It should be noted that failure to
properly operate or maintain a continuous monitoring system would be
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considered as a violation rather than a malfunction (see 40 CFR 60.105
and 60.13).
7.2 COMPLIANCE USING PARTIAL SCRUBBING
Comment;
One commenter (IV-D-3) stated that EPA should delete the
requirement that the add-on control device must be operated to reduce
SOX in the entire exhaust stream by 90 percent (or to 50 vppm). Instead,
a portion of the FCCU regenerator exhaust gas could bypass the scrubber
and rejoin with the scrubbed portion further downstream. A refiner
could then operate a smaller scrubber at or less than full capacity to
meet the 9.8 k'g SOX/1,000 kg coke burn-off level of the standard for
FCCU's without add-on controls. A smaller scrubber would mean smaller
capital and annual operating costs, energy savings, eliminate the need
for reheat, and improve nonair environmental benefits.
Response: j
The 90 percent standard is intended to reflect the capability of
scrubbers, which can achieve 90 percent control of the entire exhaust
stream. A relaxation of the standard to 9.8 kg SOX/1,000 kg coke burn-off
would cause it no longer to 'reflect the capability of scrubbers.
7.3 CHANGING COMPLIANCE METHOD
Comment:
A commenter (IV-D-16) questioned the need for a compliance test
after each change by a refiner from one method of compliance to another.
Rather, the commenter stated that one compliance test for each
compliance method the first time selected is sufficient.
Response: ;
This comment is no longer applicable as the standards now require
daily determinations of compliance. Under the standards, a compliance
test (by definition) is required every day regardless of the standard
with which the owner or operator seeks to comply or to which the owner
or operator has been previously subject.
Comment: ;
Four commenters (IV-D-2, IV-D-6, IV-D-16, and IV-D-20) wrote that
the 90-day notification prior to changing from one method of compliance
to another should be modified to allow for an immediate change in
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emergency cases. The commenters pointed out example situations, such
as an emergency shutdown of a hydrotreater or of a scrubber. According
to the commenters, in such cases a refiner would want to comply with a
different standard (e.g., change from the standard for FCCU's without
add-on controls to the feed sulfur cutoff) immediately, rather than
curtail FCCU processing until the shut-down control unit is repaired.
Two of these commenters (IV-D-6 and IV-D-20) stated that no prior
notification should be required provided that records appropriate to
demonstrate compliance are maintained, and EPA is notified in writing
of the change in compliance method.
Response:
The regulation now requires that daily compliance determinations
be made for all of the standards. Thus, EPA agrees with the commenters
and has removed the requirements for prior notification provided that
records appropriate to demonstrate compliance with the regulation are
maintained, and EPA is notified in writing of the change. However,
prior notification is required whenever an owner or operator adds any
CEMS (e.g., when an owner or operator elects to go from the 50 vppm
only compliance to 90 percent reduction or 50 vppm compliance).
Notification is also required in a quarterly report of any change in
the choice of SOX standard with which an owner or operator elects to
comply. The notification of any other changes in the standard to which
a refiner is subject may be submitted along with a quarterly (or semi-
annual) compliance report.
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8.0 MODIFICATION/RECONSTRUCTION COMMENTS
Comment:
One commenter (IV-D-2) suggested that the definition of reconstruc-
tion, as written in 60.108(a), should be modified to exclude equipment
which is replaced by equipment alike in design, shape, and metallurgy.
The commenter cited an example of an existing unit damaged by disaster
or misfortune.
Response:
Section 60.15 of the General Provisions specifies that reconstruc-
tion occurs upon replacement of components if 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
if it is technologically and economically feasible for the facility,
after the replacements, to comply with the applicable standards of
performance. The circumstances prompting the reconstruction activities
are not pertinent when determining if an existing facility has undergone
reconstruction.
Each reconstruction determination is decided on a case-by-case
basis. Section 60.15(f) sets forth the criteria which the Administrator
will use in making his determination. If the owner/operator of the
facility can provide evidence that it is not technologically or econom-
ically feasible to comply with the applicable standards, the facility
will retain its "existing" status. However, if the fixed capital cost
provision is met and it is feasible for the facility to comply with the
standards, it must comply with NSPS.
Comment:
One commenter (IV-D-3) stated that a special provision should be
included in these standards to supercede Section 60.14 regarding the
definition of modification. Specifically, the commenter referred to
the determination of whether a given "project" will increase SOX emis-
sions from an existing FCCU regenerator that is using SOX reduction
catalysts. The commenter recommended that, in determining whether an
emission increase will result, operators should be allowed to use, for
the pre-project case, the emission level which would have existed had
SOX reduction catalysts not been used. A modification would not occur
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unless the post-project emissions exceeded this adjusted pre-project
level. Operators who do not use SOX reduction catalysts would have an
advantage over those who do in preventing an emission increase in a
given "project." They can use SOX reduction catalysts concurrently
with the project and thereby avoid a net emission increase at the
affected facility.
Response: ;
The inclusion of the suggested special provision is inconsistent
with Section lll(a)(4) of the Clean Air Act, which defines "modifica-
tion" to mean "any physical change in, or change in the method of
operation of" a source that increases emissions. It is also contrary
to the intent of the modification provision and the NSPS program. The
EPA believes that the current straightforward application of the
"modification" definition best serves the intent of Section 111 of
the Clean Air Act. One key purpose of the NSPS program is to prevent
new pollution problems. One way that the statute seeks to achieve
this is by requiring compliance with NSPS at, and thereby minimizing
emissions increases from, modified facilities.
Comment:
One commenter (IV-D-7) stated that routine maintenance items, such
as standpipes, slide valves, and other regenerator internal components
should not be included in determining if a facility is modified or
reconstructed. Many of the items require routine maintenance and are
frequently repaired without a resultant emissions increase. Another
commenter (1V-D-16) stated that the affected facility should be rede-
fined to include the fractionator and gas plant because rebuilding work
in a single turnaround of an affected facility can commonly exceed
50 percent of the cost of a new unit. Also, the cost of rebuilding
work on an affected facility can represent 20 percent of the new unit
cost of an entire FCCU. To a refiner, an entire FCCU includes the
fractionator and gas plant. . These two units usually do not require any
significant rebuilding.
Response:
The reconstruction provision (40 CFR 60.15) cannot be invoked
until 50 percent of the "fixed capital cost" to replace the existing
facility with a comparable, new facility has been incurred by the owner
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or operator. The period in which the FCCU is shut down for maintenance
and repair is called a turnaround. During a typical turnaround, regen-
erator refractory linings, cyclones, and other internal components are
inspected and repaired or replaced as required. Based on information
from the refining industry, regenerator components have a useful life
ranging from 10 years to an indefinite period of time when they are
repaired and maintained during turnarounds (see Docket A-79-09 items
II-D-40, II-D-41, II-D-42, and II-D-43). The costs used in the summation
to determine the total fixed capital cost incurred are those costs
incurred to replace components. The costs incurred during maintenance
and repair of the existing facility's components (assuming components
are not replaced) are not included in the summation of expended fixed
capital costs. Thus, there is no need to specifically exempt routine
maintenance items from the reconstruction provisions.
The EPA disagrees with the comment that rebuilding work typically
can exceed 50 percent of the capital cost of a new affected facility.
The EPA examined data from Section 114 letter responses, trip reports,
literature articles, and companies who provide turnaround services to'
refineries (see Docket A-79-09, item IV-B-18). These data led EPA to
conclude that routine rebuilding is less than 50 percent of the cost of
a new affected facility. As discussed above, this is because regen-
erator components are typically repaired rather than replaced during a
turnaround. If several major changes, such as increasing the FCCU
capacity, changing to a heavier or more sour crude oil, or converting
to high-temperature regeneration, occur during a single turnaround,
the cost may approach or surpass the 50 percent point. Such major'
changes are not, however, a typical turnaround occurrence. Justifica-
tion for the choice of equipment that comprises the affected facility
as defined in 40 CFR 60.101(n), is discussed in Section 2.2 of this
document. The possibility that rebuilding work may exceed 50 percent
of the cost of a new unit is an inadequate reason to broaden the defi-
nition of the affected facility (i.e., restrict invoking the reconstruc-
ts provision). The meaning and intent of the reconstruction provision
is discussed earlier in this section.
The modification provision (40 CFR 60.14) is invoked when any
physical or operational change to an existing facility results in an
8-3
-------
increase in the emission rate to the atmosphere of any pollutant to which
a standard applies. As the actions described by the commenter do not
increase emissions, the modification provision would not be invoked. In
addition, paragraph (e) of Section 60.14 specifies that routine mainte-
nance, repair, and replacement by themselves, shall not be considered
modifications.
Comment;
One commenter (IV-D-8) stated that a 1-calendar year or a 12-month
"inclusion period" for reconstruction is more logical than a 2-year period.
A refiner with a normal 2-year turnaround could be affected by the recon-
struction provisions of the standards if a shutdown began 1 or 2 months
prematurely. A refiner would not install a sizeable process modification
during a routine shutdown period due to the excessive downtime incurred.
Response:
The EPA considered again the 2-year period and concluded that a
1-calendar year or a 12-month "inclusion period" for reconstruction is
not more logical than a 2-year period for FCCU's. Information from
industry and literature (see proposal BID, p. 5-3) indicates that the
normal turnaround schedule for revamping FCCU regenerators is every 3
years (i.e., a maximum of one turnaround would occur during each 2-year
period of operation). A process unit turnaround typically includes
maintenance and repair items that do not qualify as fixed capital costs
and therefore, a turnaround iis not likely to be a "reconstruction."
The Agency also does not expect that the 2-year period will alter
decisions by an FCCU's owner or operator on when to replace equipment.
That is, the FCCU owner or operator is not likely to unduly prolong the
useful life of the regenerator components with the intent of avoiding
this NSPS. Therefore, for this particular NSPS, EPA believes that the
2-year period provides a reasonable, objective method of determining
whether an owner/operator of an FCCU regenerator is actually "proposing"
extensive component replacement, within the original intent of Section
60.15. The Agency wil 1. consider the 2-year period again at the 4-year
review of the NSPS.
Comment: '.
One commenter (IV-D-13) questioned the methods to be used'in
determining if an emissions increase has occurred when determining
8-4
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the applicability of the modification provisions. The counter stated
that EPA should outline the specific information acceptable for an
emission factor and/or material balance approach. The commenter also
asked what specific AP-42 or other emission factor for FCCU's EPA
intends to use. Another commenter (IV-D-15) suggested taking into
consideration whether the tonnage of a coke burnoff is increased by
substantial amounts.
Response:
Specific guidelines cannot be presented to be used to determine
whether an increase in emissions has occurred due to the wide van-
ability of possible circumstances. One factor that undoubtedly would
be considered in assessing whether an emission increase had occurred or
would occur is whether the facility is or will be capable of utilizing
a new feedstock. A new feedstock will probably have a different sulfur
content than those previously used, and thus, there is a strong possi-
bility that the SOX emissions will change. If the existing facility
was designed to accommodate the alternative raw material, however then
an increase in emissions resulting from that change alone is not '
considered a modification [see 40 CFR §60.14(e) (4)]. Another factor-
that would be considered is whether the facility is or will be capable
of increased coke burn-off. Assuming no change in the feedstock, an
increase in the coke burn-off rate will undoubtedly cause SOX emis-
sions to increase because the amount of SOX emissions is directly
related to the amount of coke that is burned off.
Pollutant emission rates can be estimated for FCCU regenerators by
using emission factors described in AP-42; however, these emission
factors generally represent average emission levels and thus do not
reflect the complete range of emissions from individual FCCU regener-
ators. The range of FCCU regenerator pollutant emission rates may be
determined by considering the typical ranges in feed sulfur coke
yield, and FCCU capacity, and by evaluating the stoichiometric relation-
ships involved in regenerating FCCU catalysts.
Catalyst regeneration is simi1ar to solid fuel combustion in a
boiler. Flue gas compositions and flow rates may be calculated by
determining the coke composition and formation rate and by calculating
the amount of air required to oxidize the coke. Coke formation rates
8-5
-------
vary depending on the FCCU and how it is operated. Coke yield,
expressed as a weight percentage of the feed, varies between 4 weight
percent and 6.5 weight percent for many FCCU feeds (see Docket A-79-09,
item II-t-53). :
Coke is composed of carbon, hydrogen, sulfur, and small amounts of
nitrogen and metals. Coke may typically contain from 4 to 12 percent
hydrogen (see Docket A-79-09, items II-D-50, II-D-49, and II-D-47).
The sulfur content of the coke may range from less than 0.1 to 5 weight
percent or more, depending on the type of feed processed. Assuming
that the nitrogen and metals content of coke is negligible, carbon
would represent the balance of coke composition.
Certain regenerator coriibustion air inlet and flue gas compositions
must also be.assumed when calculating emissions. Inlet air to the
regenerator may contain from 76.0 to 78.8 volume percent nitrogen,
20 volume percent oxygen, and from 1.2 to 4.0 volume percent water.
A detailed discussion describing calculation and/or estimating tech-
niques to determine emission rates is presented in the proposal BID,
pp. 3-15 and 3-16.
Comment:
One commenter (IV-D-16) recommended that Section 60.100(b) and (c)
should be rewritten, to allow a better understanding of reconstruction.
Response:
Sections 60.100 (b) and (c) are not intended to provide the defi-
nition or clarification of the definition of reconstruction, as it
applies to 40 CFR 60; however, Section 60.100(c) was confusing and it
has been revised. A detailed discussion of the meaning of reconstruction
is provided in Subpart A, General Provisions, under Section 60.15.
Specific clarifications or additions to the definition of reconstruction,
as applicable for Subpart J, are provided under Section 60.108.
8-6
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9.0 RECORDKEEPING AND REPORTING COMMENTS
Comment;
The Office of Management and Budget commented that quarterly
reporting was too frequent, and that semiannual reporting would allow
the Agency to obtain the necessary information.
Response:
For FCCU's, EPA has concluded that quarterly reporting (or semi-
annual reporting if no exceedances have occurred during a particular
quarter) is the appropriate reporting frequency for the following
reasons. The major reason is that the reports contain direct compli-
ance information rather than indicators of the source's performance.
Therefore, enforcement action can be taken quickly because no further
testing is needed for documentation. The FCCU is one of several signif-
icant emission sources in petroleum refineries, so periods of excess
emissions could have a significant impact on the environment. This is
particularly true because refineries generally are located in clusters
near industrial, urban, populated, nonattainment areas. Because the
refinery generally does not save money by operating the control tech-
niques correctly and the pollutants cannot be recovered for resale,
there is little incentive for this source category to be self-
regulated. Therefore, to ensure that sources are not out of compliance
for long periods of time during which significant environmental impacts
could occur, quarterly reporting is appropriate for quarters when
facilities have had a period when the standard has been exceeded. In
addition, the amount of data to be provided in these cases is reasonable.
Sources complying with the proposed revised standard would need to
supply only a semiannual negative declaration statement. Only noncom-
pliant sources would be required to provide additional information in
the quarterly compliance reports.
9-1
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-------
10.0 MISCELLANEOUS COMMENTS
Comment:
One commenter (IV-D-16) wrote that since the proposal preamble
states that FCCU flue gas is similar to stationary source flue gas, the
SOX rules that apply to stationary sources should be prescribed for
FCCU's. If these rules were applied to FCCU's, regenerators with heat
releases less than 250 million BTU's per hour would be exempt.
Response:
The EPA assumes that by stationary sources, the commenter is
referring to utility boilers. Although the composition of the flue gas
from a coal-fired utility boiler is similar to that of FCCU regen-
erator exhaust gases, and some of the same control devices are appli-
cable, it is not appropriate simply to copy the standards for utility
boilers to FCCU's when significant differences could exist between
the two source categories. Whenever practical, the process operation
and economic aspects that characterize the source category or industry
for which standards are being developed should be considered. In
addition, the SOX standards for FCCU's consider the additional control
alternatives available to FCCU's that are not available to utility
boilers. The utility boiler standard applied to FCCU's would reduce a
refiner's flexibility to use high sulfur feedstocks and would not allow
the use of SOX reduction catalysts, low sulfur feedstocks, or hydro-
treating. Thus, it is not reasonable to simply copy the S02 standards
for utility boilers.
Comment:
Two commenters (IV-D-6 and IV-D-10) suggested that the proposal
package should undergo NAPCTAC review again because at the original
NAPCTAC meeting the regulation was in terms of S02 while the current
proposed standards are in terms of SOX.
Response:
The purpose for a NAPCTAC meeting is for EPA to receive comments
from an independent advisory committee regarding the need for standards,
regulatory alternatives, control techniques, control costs, and other
factors. Although the standard for FCCU's without add-on controls is
in terms of SOX, the standard is still achievable by the identified
10-1
-------
control techniques and the environmental, energy, and economic impacts
are still reasonable. Therefore, it is not necessary to conduct
another NAPCTAC review due to the change of this standard from S02 to
SOX. i
Comment: ;
One commenter (IV-K-2) asked why EPA requires dates and
explanations when fewer than 18 valid hours of continuous emissions
monitoring data have been obtained.
Response:
Facilities using add-on controls are required to obtain 18 or
more valid hours of CEMS datja for at least 22 days each month. As
pointed out by this same commenter elsewhere, there is some possibility
than an owner or operator may try to maximize the "good" days and
minimize the "bad" days in tbying to meet the standard. Such delib-
erate actions are attempts to circumvent the standard, which is
illegal under 40 CFR Part 60, Subpart A, Section 60.12. In other
words, such an owner or operator may turn off the CEMS or otherwise
invalidate its data on a "bad" day in order to generate less than 18
valid hours. With the dates and a brief explanation, the Agency can
look for patterns that indicate that an owner or operator may be
circumventing the standard and thus discourage this type of behavior.
Comment: [
One commenter (IV-K-2) suggested that EPA should not use
"monitored parameter data," but use "excess emissions" to target
inspections. :
Response:
The discussion of "Monitored Parameter Data" and "Excess
Emissions Data" in the reproposal notice was generic to the entire
NSPS/NESHAP development process and not addressed specifically to the
FCCU standards being proposed. While both types of data may not be
needed to target inspections for any one standard, in some cases,
monitored parameter data may be more appropriate to collect than excess
emission data. For example, in standards that require particular
equipment rather than beings numerical emission limit, monitoring
operating parameters would likely be the best data to collect for
targeting inspections. Thus, the Agency will continue to judge, on a
10-2
-------
case-by-case basis, the type of data that is appropriate for each NSPS
or NESHAP.
Comment:
One commenter (IV-K-2) asked what is the difference between a
"redundant" CEMS and a "spare" CEMS. The commenter pointed out that
EPA states that redundant CEMS's are not warranted because of cost, but
later discusses the use of a spare CEMS.
Response:
If EPA required a CEMS to operate close to 100 percent of the time,
then a second CEMS would be required to ensure that high percent avail-
ability. It is in this context that EPA refers to the second monitor
as a "redundant" CEMS and believes that the cost for ensuring close to
100 percent availability is not warranted. Thus, EPA proposed minimum
data requirements that could likely be met by a single CEMS, taking into
account downtime. Even still, there may be times when minimum data
requirements are not met by the (first) CEMS. The owner or operator has
at least three options in obtaining the needed data - Method 6 testing,
Method 6B testing, or a second CEMS. It is in this context that EPA
refers to the second CEMS as a "spare" monitor. Therefore, with the
minimum data requirements and the manual testing options, a second CEMS
is optional, but not required. The EPA recognizes that for an owner or
operator who chooses to purchase a second CEMS for back-up purposes
there is no meaningful difference between "redundant" and "spare."
Comment:
One commenter (IV-K-2) pointed out that the preamble example of
88 percent reduction as being an exceedance may not, in fact, be an
exceedance if the S0£ is less than 50 vppm.
Response:
The Agency agrees that the example provided in the preamble is
incomplete. An add-on control device whose outlet S02 emissions
are 50 vppm or less is not in exceedance of the standard regardless of
the add-on control percent reduction. The example implicitly assumed
that the outlet SOg vppm was greater than 50. The object of the example
was primarily to point out that for percent reduction an exceedance
would occur when the control device efficiency was less than 90 percent.
10-3
-------
Comment: ;
One commenter (IV-K-2) suggested that EPA use the words "failure
to achieve a standard" rather than "exceedance of a standard" to
describe emissions greater than those allowed by a standard. The
commenter added that "exceedance" has the connotation of being better
than or superior to, which, in the case of a percent reduction
standard, would be a reduction better than required.
Response:
The word "exceedance" is used by EPA in the context of not
achieving a prescribed emission level set by EPA. Exceedance of a
percent reduction standard means that a facility or process unit has
not achieved an emission level (in this case, 90 percent emission
reduction based on flue gas scrubbers) specified by EPA. This term
has been used by EPA in numerous standards of performance. Therefore,
to maintain consistency with other standards, the use of the word
"exceedance" has been retained.
Comment:
One commenter (IV-K-2) asked whether the words "source owner" on
page 46465, column 1, paragraph 1, of the preamble to the revised
proposed standards should be "source owner or operator." This commenter
also asked whether the word "provide" on page 46465, column 1, paragraph
1, of the preamble to the revised proposed standards means "report" or
"record." In addition, the commenter pointed out various typographical
errors in the preamble. In an earlier comment letter (IV-D-16), this
commenter provided a thorough list of editorial and typographical
changes that should be incorporated into the proposal BID and the
Federal Register notice.
Response:
The EPA inadvertently omitted the words "or operator" from the
sentence referred to by the commenter. Therefore, EPA wishes to
clarify that the requirement to provide a minimum of 22 days of data
for every 30-day period using continuous monitors or an approved
manual emission test is the responsibility of either the plant owner
or operator or an appropriate person designated by the owner or
operator.
10-4
-------
The commenter refers to the requirement to "provide" monitoring
data for determining performance of the add-on control device (using
continuous monitors or an approved manual emission test). As
explained in the preamble to the revised proposed standards on page
46467 under "Recordkeeping and Reporting Requirements," refiners sub-
ject to the standard for FCCU's with add-on controls would be required
to record the data from the continuous emission monitor at the inlet,
as well as at the outlet. Therefore, the word "provide" means to
"record" in the context of this requirement.
A listing of each typographical error and suggestion is not
provided here since the errors and suggested changes do not affect the
intent or technical discussions presented in these documents. None of
the typographical errors impairs the meaning or explanation of the
standards intended by EPA. The suggestions have been reviewed and all
appropriate changes have been made.
10-5
-------
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APPENDIX A
CONTROL EQUIPMENT COSTS
AND FIFTH YEAR IMPACTS
-------
-------
TABLE A-l. BASIS FOR DETERMINING SCRUBBER ANNUAL COSTS9
)irect Operating Costs
Laborb
Maintenance (includes materials,
labor, and overhead)
Utilities
Electricity
Water
Compressed Air
Caustic Sodac (Soda Ashd)
Steam
Polyelectrolyte6
Solid Waste Disposal^
Liquid Waste Disposalf (to sewer)
Indirect Operating Costs
Tax, Insurance, and Administration
Capital Recovery Factor
$17.51/hour
1.5 percent of total capital cost
$0.0795/kWh
$0.0763/m3
$0.861/1,000 m3
$268/Mg ($122/Mg)
$13.53/1,000 kg
$10.07/kg
$20.13/Mg
$0.16/m3
4 percent of total capital cost
13.15 percent of total capital cost
Fourth quarter 1984 dollars.
i
Includes 40 percent overhead; U.S. Department of Labor, Bureau of Labor Statistics,
'Liquid caustic soda, 100 percent; F.O.B. Gulf Coast; Docket A-79-09, item II-E-6
i
Bulk soda ash, light, 99 percent; F.O.B. Wyoming; Docket A-79-09, item II-E-6.
2
'Polymer 3300, an anionic polyacrilomide settling agent; 50-pound bags,
F.O.B. Dallas, Texas.
From industrial boilers - EPA-450/3-82-021 August 1982.
Costs of Sulfur Dioxide, Particulate Matter and Nitrogen Oxide Control on Fossil
Fuel Fired Industrial Boilers, p. 2-16.
A-l
-------
TABLE A-2. CAPITAL COST FOR SODIUM-BASED HIGH ENERGY VENTURI SCRUBBING
SYSTEM AND PURGE TREATMENT FOR MODEL UNITS3
Capital Costs
Direct Costsb
Indirect Costs
Contingency Costs0
TOTAL CAPITAL COST
ESP Capital Cost Creditd
2,500 m3/sd
Model Unit
2.9
1.3
0.8
5.0
-1.0
8,000 m3/sd
Model Unit
5.0
2.2
1.4
8.6
-1.8
Costs are reported in millions of dollars, adjusted to fourth quarter
1984 dollars, delivered to a Gulf Coast location.
Materials and labor.
'Twenty percent of total direct and indirect costs.
From Table A-9 in this appendix; cost provided for comparison purposes,
A-2
-------
TABLE A-3. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENTURI SCRUBBING FOR
2,500 m3/sd MODEL UNITS
Annual Costs
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Solid Waste Disposal
Liquid Waste Disposal0
Indirect Operating Costs
Tax, Insurance, and Administration
Capital Recovery Cost
TOTAL ANNUAL COST
Caustic Soda
(Soda Ash)
ESP Credit^
NET ANNUAL COST
Caustic Soda
(Soda Asn)
EMISSION REDUCTION
[Mg SOX removed/yr]
COST EFFECTIVENESS13
[S/Mg SOX removed]
Annual Cost,
0.3 wt. %
Sulfur Feed
53.7
75.0
22.4
10.2
0.4
. 155
(95) -
- 1.1
4.9
7.1
15.6
200
653
1,200
(1,140)
-272
930
(870)
450
2,070
In Thousands of
1.5 wt. %
Sulfur Feed
53.7
75.0
22.4
10.2
0.4
579
(355)
1.1
4.9
7.1
15.6
200
658
1,630
(1,400)
-272
1,360
(1,130)
1,670
810
Dollars3
3.5 wt. %
Sulfur Feed
53.7
75.0
22.4
10.2
0.4
1,089
(668)
1.1
4.9
7.1
15.6
200
658
2,140
(1,720)
-272
1,870
(1,440)
3,130
600
^Numbers may not add to totals due to rounding. Fourth quarter 1984 dollars.
bAssumes liquid waste disposal to sewer, 50 gal/minute.
cFrom Taole A-9 in this appendix.
dBased on net annual cost with caustic soda.
A-3
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TABLE A-4. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENTURI SCRUBBING FOR
8,000 rh3/sd MODEL UNITS
Annual Costs
Direct Operating Costs
LaDor
Maintenance
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash} :
Steam
Poly electrolyte
Solid Waste Disposal •
Liquid Waste Disposal0
Indirect Operating Costs
Tax, Insurance, and Administration
Capital Recovery Cost
TOTAL ANNUAL COST
Caustic Soda
(Soda Asn)
ESP Credit0 • ;
NET ANNUAL COST
Caustic Soda
(Soda Ash)
EMISSION REDUCTION
[Mg SOX removed/yr]
COST EFFECTIVENESS*1
CS/Mg SOX removed]
Annual Cost,
0.3 wt. %
Sulfur Feed
53.7
129
71.6
30.6
0.4
506
(313)
. 3.2
14.6
22.7
31.2 •
344
1,131
2,340
(2,150)
-429
1,910
(1,720)
1,440
1,330
in Thousands of
1.5 wt. %
Sulfur Feed
53.7
129
71.6
30.6
0.4
1,860
(1,150)
3.2
14.6
22.7
31.2
344
1,131
3,690
(2,980)
-429
3,260
(2,550)
5,350
610
Dollars3
3.5 wt. %
Sulfur Feed
53.7
129
71.6
30.6
0.4
3,480
(2,150)
3.2
14.6
22.7
31.2
344
1,131
5,310
(3,980)
-429
4,380
(3,550)
9,990
490
aNumbers may not add to totals due to rounding. Fourth quarter 1984 dollars.
^Assumes liquid waste disposal to sewer, 100 gal/minute.
cFrom Taole A-9 in this appendix. •
aBnsed on net annual cost with caustic soda.
A-4
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TABLE A-5. CAPITAL COST FOR SODIUM-BASED JET EJECTOR VENTURI SCRUBBING
SYSTEM AND PURGE TREATMENT FOR MODEL UNITS^
Capital Costs
Direct Costsb
Indirect Costs
Contingency Costs0
TOTAL CAPITAL COST
ESP Capital Cost Creditd
2,500 m3/sd
Model Unit
4.2
1:6
1.2
7.0
-1.0
8,000 m3/sd
Model Unit
7.2
3.2
2.1
12.5
-1.8
aCosts are reported in millions of dollars, adjusted to fourth quarter 1984
dollars, delivered to a Gulf Coast location.
bMaterials and labor.
cTwenty percent of total direct and indirect costs.
^From Table A-9 in this appendix; cost provided for comparison purposes.
A-5
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TABLE A-6. ANNUAL COST OF SODIUM-BASED JET EJECTOR VENTUR1 SCRUBBING FOR
2,500 m3/sd MODEL UNITS
Annual Cost, In Thousands of Dollars3
Annual Costs
Direct Operating Costs
Labor ,
Maintenance
Utilities
Electricity
.Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Solid Waste Disposal
Liquid Waste Disposal0
Indirect Operating Costs
Tax, Insurance, and Administration
Capiial Recovery Cost
TOTAL ANNUAL COST
Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
Caustic Soda
(Soda Ash)
EMISSION REDUCTION
[Mg SOX reraoved/yr]
COST EFFECTIVENESS": :
[$/Hg SOX removed]
1.5 wt. %
Sulfur Feed
53.7
105
304
10.2
0.3
568
(341)
1.1
5.2
7.1
31.1
280
921
2,290
(2,060)
-272
2.020
(1,790)
1,610
1,250
3.5 wt. %
Sulfur Feed
53.7
105
304
10.2
0.3
1,083
(650)
1.1
5.2
7.1
31.1
280
921
2.800
(2.370)
-272
2,530
(2.100)
3,070
820
^Numbers may not add to totals due to rounding. Fourth quarter 1984 dollars.
OAssuittts liquid waste disposal to sewer, 50 gal/minute.
C3ased on net annual cost with caustic soda.
A-6
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TABLE A-7. ANNUAL COST OF SODIUM-BASED JET EJECTOR VENTURI SCRUBBING FOR
8,000 m3/sd MODEL UNITS
Annual Costs
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air
, Caustic Soda
(Soda Asn)
Steam
Polyelectroiyte
Solid Waste Disposal
Liquid Waste Disposal0
Indirect Operating Costs
Tax, Insurance, and Administration
Capital Recovery Cost
TOTAL ANNUAL COST
Caustic Soda
(Soda Asn)
ESP Credit
NET ANNUAL COST
Caustic Soda
(Soda Asn)
EMISSION REDUCTION
[Mg SOX removed/yr]
COST EFFECTIVENESS^
[S/Mg SOX removed]
Annual Cost,
1.5 wt
Sulfur
53.7
188
976
. 30.7
0.4
1,818
(1.101)
3.4
15.6
22.7
62.3
500
1,544
5,310
(4,600)
-429
4,880
(4,170)
5,160
940
in Thousands of Dollars3
. % 3.5 wt. ',
Feed Sulfur Feed
53.7
188
976
30.7
0.4
3,606
(2,183)
3.4
15.6
22.7
62.3
500
1,544
7,100
(5,680)
-429
6,670
(5,250)
9,840
630
aNumoers may not add to totals due to rounding. Fourtn quarter 1984 dollars.
°Assumes liquid waste disposal to sewer, 100 gal/minute.
C8ased on net annual cost witrt caustic soda.
A-7
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TABLE A-8. DUAL ALKALI SCRUBBING SYSTEM COSTS BASED ON 1.5 WEIGHT
PERCENT SULFUR FEED3
Cost
Direct Costs
Indirect Costs
Contingency Costs
TOTAL CAPITAL COST
ESP Capital Cost Credit
Direct Operating Costs
Operating Labor
Maintenance
Utilities
Soda Ash
Li me
Electricity
Water
Waste Disposal
Indirect Operating Costs
Tax, Insurance,
and Administration
Capital Recovery Cost
TOTAL ANNUAL COSTS
ESP Credit
NET ANNUAL COST
EMISSION REDUCTION
[Mg S02 removed/yr]
COST-EFFECTIVENESS
[$/Mg of SOg removed]
2,500 m3/sd
Model Unit
CAPITAL COSTS
2,500
1,100
\ 700
4,300
(1,000)
ANNUAL COSTS
; 38
65
9
101
61
2
125
172
565
1,140
(272)
870
1,670
520
8,000 m3/sd
. Model Unit
4,400
2,000
1,300
7,700
(1,800)
75
116
33
316
191
5
393
308
1,013
2,450
(429)
2,020
5,350
380
aCosts are reported in thousands of dollars, adjusted to fourth quarter
1984 dollars,
A-8
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TABLE A-9. ELECTROSTATIC PRECIPITATOR COSTS*
(Fourth Quarter 1984 Dollars)
Costs
Equipment Costs
Control Device'3
Auxiliaries0
Instruments and Controls01
Taxes and Freight6
Installation Costs^
TOTAL CAPITAL COSTS
Direct Costs
Operating LaborS
General Maintenance"
Replacement Parts1
UtilitiesJ
Waste Disposal^
Indirect Costs
Overhead^
Property Tax, Insurance, and
Administration111
Capital Recovery Cost"
TOTAL ANNUAL COSTS
2,500 m3/sd
Model Unit
CAPITAL COSTS
324,000
43,400
36,700
29,400
611,000
1,045,000
ANNUAL COSTS
27,000
28,100
820
11,000
7,840
32,800
41,800
122,800
272,000
8,000 m3/sd
Model Unit
542,000
81,100
62,300
49,800
1,037,000
1,772,000
27,000
28,100
1,380
35,200
25,100
32,800
70,900
208,200
429,000
A-9
-------
TABLE A-9.
aFotirth quarter 1984 dollars.
FOOTNOTES
bRemoval efficiency = 95 percent; drift velocity = 0.076 m/sec; plate area
for the 2,500 m3/sd unit = 1,000 m2, for the 8,000 m3/sd unit = 3,200 m2;
air flow for the 2,500 m3/sd unit = 27 m3/sec, for the 8,000 m3/sd unit =
87 m3/sec. Docket A-79-09; item.11-1-11.
Auxiliaries include bypass ducting: 19.7 m length, 127 cm diameter,
6.4 mm carbon steel, insulated; 2 elbows 6.4 mm carbon steel, insulated;
2 expansion joints; 2 round dampers with automatic controls; and a 23 cm x
4.5 m screw conveyor. Docket A-79-09, items II-A-5, II-E-5, and II-E-95.
dlnstrument and controls calculated as 10 percent of control device.and
auxiliary equipment cost. Docket A-79-09, item II-A-5.
eTaxes and freight calculated as 8 percent of control device and auxiliary
equipment cost. Docket A-79-09, item II-A-5.
fIncludes indirect and direct installation costs and 20 percent contingency
calculated as 141 percent of purchased equipment cost. Indirect installa-
tion costs include costs for foundations and supports, erection and handling,
electrical work, piping, insulation, and piping. Docket A-79-09, item
II-A-5.
Slncludes operator and supervisor costs. Operating labor costs are based on
1.25 operator ;man-hours per shift, 3 shifts per day, 365 days per year and
$17.51 per man-hour. Supervisor labor costs are included by adding 15 per-
cent to the operator costs. Docket A-79-09, item II-A-5.
udes labor and material costs. Maintenance labor costs are based on
0.75 man-hours per shift, 3 shifts per day, 365 days per year, and $17.51
per man-hour. Material costs are equal to 100 percent of maintenance labor
costs. Docket A-79-09, item II-A-5.
"•Based on 0.078 percent of total capital costs. Docket A-79-09, item II-
A-24. :
JBased on 16.15 watts/m2 plate area, 357 days per year. $0.0795 per kWh,
and 1,000 m2 plate area for the small ESP and 3,200 m2 plate area for the
large ESP. Docket A-79-09, item II-A-5.
kCost to remove waste is based on $16.50/metric ton. Docket A-79-09, items
U-I-82, and II-A-5.
^Overhead calculated as 80 percent operating labor and maintenance (labor
only). Docket A-79-09, item II-A-5.
Calculated as 4 percent of total installed capital cost. Docket A-79-09,
item II-A-5.
"Capital recovery cost based on 20 years operating life, and 20 percent annual
interest rate. Capital recovery factor = 0.1175. Docket A-79-09,
item II-A-5.
A-10
-------
1
1
Ipresh Feed
•capacity
•(m3/sd)
B2,500b>c
•s,ooob»c
•2,500b
ls,ooob
•2,500b
•8,000b
•TOTAL CAPITAL
TABLE
A-10. FIFTH YEAR CAPITAL COST IMPACTS3
NEW FCCU CONSTRUCTION (1984-1989)
Feed Sulfur Number of Capital Cost Capital Cost:
Content Units: A Per Unit: B A x B
(wt. 55) . ($ Millions) ($ Millions)
0.3
0.3
1.5
1.5
3.5
3.5
COST IMPACT
1 5.0 5.0
1 8.6 8.6
3 5.0 15.0
3 8.6 25.8
1 5.0 5.0
1 8.6 8.6
68.0
1 MODIFIED/RECONSTRUCTED FCCU's (1984-1989)
Bpresh Feed
1 Capacity
• (m3/sd)
l2,500d
|2,500b
|8,000b
ls,oood
|8,000b
|8,000b
•TOTAL CAPITAL
Feed Sulfur
Content
(wt. %)
1.5
1.5
1.5
1.5
1.5
3.5
COST IMPACT
Number of Capital Cost Retrofit Cost Capital Cost:
Units: A Per Unit: B Adjustment6: C A x (B + C)
($ Millions) ($ Millions/Unit) ($ Millions)
1 7.0 — 7.0
1 5.0 0.8 5.8
1 8.6 — 8.6
1 12.5 — 12.5
2 8.6 1.4 20.0
1 8.6 — 8.6
62.5
a4th quarter 1984 dollars.
bHigh-energy venturi scrubber.
cAt a feed sulfur content of higher than 0.3 percent, the 90 percent emission reduction
standard would need to be met, and this cost would be incurred. At feed sulfur contents
of 0.3 percent or less, the regenerator would not be required to meet the standard, and
this cost would not be incurred.
dJet-ejector venturi scrubber.
e20 percent of direct and indirect capital cost; excludes ESP credit.
A-ll
-------
TABLE A-ll. FIFTH YEAR ANNUAL COST IMPACTS9
Fresh Feed
Capacity
(m3/sd)
2,500b»c
2,500b
2,500d
29500b»e
29500b
8»000b»c
89000b
89000d
8,000b»e
89000b
TOTAL ANNUAL
Feed Sulfur Number of
Content Units: A
(wt. X)
t
0.3
1.5
1.5
1.5
3.5
0.3
1.5
1.5
1.5
3.5
COST IMPACT
1
3
.. 1
1
1
1.
|4
;1
2
2
Annual Cost
Per Unit: B
($ 1,000's)
930
1,360
2,020
1,780
1,870
1,910
3,260
4,880
3,950
4,880
Annual Cost
A x B
($ 1,000's)
930
4,080
2,020
1,780
1,870
1,910
13,040
4,880
7,900
9,760
48,170
a4th quarter 1984 dollars.
bHigh-energy venturi scrubber.
cAt a feed sulfur content of higher; than 0.3 percent, the 90 percent emission
reduction standard would need to be met, and this cost would be incurred. At
feed sulfur contents of 0.3 percent or less, the regenerator would not
be required to meet the standard, and this cost would not be incurred.
dJet-ejector venturi scrubber.
eAnnualized capital cost includes retrofit cost; excludes ESP credit.
A-12
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Sulfur Oxides Emissions from Fluid Catalytic Cracking
Unit Regenerators - Background Information for
Promulgated Standards
5. REPORT DATE
April 1989
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Standards of performance to control emissions of sulfur oxides (SOX) from new,
modified, and reconstructed fluid catalytic cracking unit regenerators are being
promulgated under Section 111 of the Clean Air Act. This document contains a summary
of public comments, EPA responses, and a discussion of differences between the proposed
and promulgated standard.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution
Pollution Control
Standards of Performance
Industrial processes
Petroleum refineries
Fluid catalytic cracking
Sulfur Oxides
Air Pollution Control
Sulfur Oxides
Stationary Sources
13B
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
135
2O. SECURITY CLASS (This page/
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
_
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