United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Perk NC 27711
EPA-450/3-86-003
October 1986
Air
Fossil and
Nonfossil
Fuel-Fired
Industrial
Boilers —
Background
Information for
Promulgated
PM and NOx
Standards
Volume 3
Final
EIS
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EPA-450/3-86-003
Fossil and Nonfossil Fuel-Fired
Industrial Boilers —
Background Information for
Promulgated PM and NOx Standards
Volume 3
Emission Standards and Engineering Division
U.S. Environmental Protection
Region V, Library
230 South Dearborn Street
Chicago, Illinois 60604 X*
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
October 1986
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This report has been reviewed by the Emission Standards and Engineering Division of the Office of Air Quality
Planning and Standards, EPA, and approved for publication. Mention of trade names or commercial products is
not intended to constitute endorsement or recommendation for use. Copies of this report are available through
the Library Services Office (MD-35), U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711; or, for a fee, from the National Technical Information Services, 5285 Port Royal Road,
Springfield, Virginia 22161.
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EPA-450/3-86-003
FOSSIL AND NONFOSSIL FUEL-FIRED
INDUSTRIAL BOILERS -
BACKGROUND INFORMATION FOR
PROMULGATED PM AND N0x STANDARDS
VOLUME 3
Emission Standards and Engineering 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 1986
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TABLE OF CONTENTS
1.0 SUMMARY 1
1.1 SUMMARY OF IMPACTS OF PROMULGATED ACTION 1
1.1.1 Alternatives to Promulgated Action 2
1.1.2 Environmental Impacts of the Promulgated Action 2
1.1.3 Energy and Economic Impacts of the Promulgated
Action 5
1.1.4 Other Considerations 7
2.0 SUMMARY OF PUBLIC COMMENTS 9
2.1 APPLICABILITY OF THE STANDARD 20
2.1.1 General 20
2.1.2 Process Units 22
2.1.3 Mixed Fuel-Fired Units 24
2.1.4 Fuel Definitions/Exclusions 25
2.1.5 Size Cutoff 28
2.2 SELECTION/PERFORMANCE OF DEMONSTRATED NO CONTROL
TECHNOLOGY .' 29
2.2.1 General 29
2.2.2 Coal-Fired Steam Generating Units 34
2.2.3 Gas-/Oil-Fired Steam Generating Units 36
2.2.4 Other Steam Generating Units 38
2.3 STRINGENCY OF THE NO EMISSIONS LIMITS 40
A
2.3.1 Gas-/Distillate Oil-Fired Steam Generating Units 40
2.3.2 Residual Oil-Fired Steam Generating Units 41
2.3.3 Mass Feed Coal-Fired Steam Generating Units 42
2.3.4 Spreader Stoker Coal-Fired Steam Generating Units 43
2.3.5 Pulverized Coal-Fired Steam Generating Units 44
2.3.6 Multiple Fuel Units 44
2.3.7 Combined Cycle Systems 46
2.4 SELECTION/PERFORMANCE OF DEMONSTRATED PARTICULATE MATTER
CONTROL TECHNOLOGY 46
2.5 STRINGENCY OF THE PARTICULATE MATTER EMISSION LIMITS 49
2.6 COSTS/COST EFFECTIVENESS OF THE PROPOSED STANDARDS 52
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TABLE OF CONTENTS (CONTINUED)
Page
2.7 MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS '. 57
2.7.1 Continuous NO Emission Monitoring Systems 57
2.7.2 Opacity 60
2.7.3 Data Collection 63
2.7.4 Reporting Requirements 64
2.7.5 Exemptions 65
2.7.6 Enforcement/Permitting 66
2.8 EMISSION CREDITS FOR COMBINED CYCLE SYSTEMS 67
2.9 ENERGY, ENVIRONMENTAL, AND ECONOMIC IMPACTS 68
2.9.1 Energy Impacts 68
2.9.2 Environmental Impacts 69
2.9.3 Economic Impacts 71
2.10 MISCELLANEOUS COMMENTS 71
2.11 NO EMISSION LIMITS FOR WOOD RESIDUE AND NATURAL
GAS-FIRED UNITS 74
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1.0 SUMMARY
On June 19, 1984, the Environmental Protection Agency (EPA) proposed
standards of performance limiting emissions of particulate matter and
nitrogen oxides (NO ) from industrial-commercial-institutional steam
/\
generating units with heat input capacities greater than 29 MW (100 million
Btu/hour) (49 FR 25102; Subpart Db) under authority of Section 111 of the
Clean Air Act. Public comments were requested on the proposal in the
Federal Register. There were 62 commenters, composed mainly of industries,
trade associations, and State and local regulatory agencies. Also
commenting were environmental groups and one U.S. Government agency. The
comments that were submitted to the docket (A-79-02) are summarized in this
document. Revisions were made to the proposed regulations in response to
these comments. A description of these revisions and the rationale for the
final actions taken by the Administrator are presented in the preamble to
the promulgated regulations.
On December 2, 1985, EPA proposed an amendment to the standards of
performance for fossil fuel-fired steam generating units (Subpart D) that
would revise the NO emission limit for units firing mixtures of natural gas
/\
and wood (50 FR 49422). Public comments were requested in the Federal
Register. There were three commenters, composed of trade associations and
one industry. The comments that were submitted are also included in
Docket A-79-02 and are summarized in this document.
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1.1 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.1.1 Alternatives to Promulgated Action
Regulatory alternatives considered during the development of the.
proposed standards are discussed in Chapter 6 of "Fossil Fuel-Fired
Industrial Boilers - Background Information Document for Proposed Standards"
(EPA-450/3-82-006), referred to as the background information document
(BID). These regulatory alternatives reflected different levels of emission
control. After proposal, the Agency reviewed the public comments and
consequently revised the emission limits for particulate matter and NO .
/\
The Agency has recalculated the environmental, energy, and economic impacts
of the final standards, as discussed below.
1.1.2 Environmental Impacts of the Promulgated Action
The environmental impacts of the proposed regulation were presented in
the preamble to the proposed standards (49 FR 25102, June 19, 1984) and in
Chapter 10 of the BID. Additional background on the environmental impacts
of the proposed standards can be found in the docket in two documents
entitled "Regulatory Analysis of Recommended Particulate Matter New Source
Performance Standard for Industrial Fossil Fuel-Fired Boilers" and
"Documentation of National Impacts for Industrial-Commercial-Institutional
Steam Generating Units." The environmental impacts of the final regulation
are presented in two additional documents, which are contained in the
docket. These two documents are "Projected Environmental, Cost and Energy
Impacts of Alternative NSPS for Industrial Fossil Fuel-Fired Boilers" and
"National NO Impacts." The analysis of environmental impacts presented in
/\
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these documents, as modified by the changes described below, is the final
environmental impact statement for this action.
It is projected that 725 new industrial-commercial-institutional .steam
generating units subject to 40 CFR Part 60 Subpart Db will be constructed in
the 5 years following the promulgation. The environmental impacts of
reducing particulate matter and NO emissions from these steam generating
X
units are expressed as incremental differences in emissions between the
current emission regulations (referenced to as baseline) and the promulgated
regulations.
The impacts of the new source performance standards (NSPS) for
particulate matter and NO emissions are stated as a range of emission
J\
reductions. This range stems from the different regulatory requirements ,
which can be assumed to apply to new units subject to these standards. The
lower estimate of emission reductions is based on the incremental change
between the baseline regulations (State implementation plans and Subpart D
new source performance standards) and the particulate matter and NO
/\
emission limits in the promulgated standards. The upper estimate is based
on the incremental change between the baseline regulations and the
particulate matter and NO standards combined with the recently proposed new
X
source performance standards for S02 (51 FR 22384), which would also apply
to this category of steam generating units. The proposed SOp standards are
expected to increase the number of natural gas-fired steam generating units
subject to the standard from approximately 30 percent of the total number of
steam generating units subject to the standards to approximately 55 percent.
Because natural gas combustion results in lower particulate matter and NO
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emissions than either coal or oil combustion, increased particulate matter
and NO emissions control result with S07 standards in place.
A C~
Baseline emissions of particulate matter from new industrial-
commercial-institutional steam generating units are projected to be
approximately 49,000 Mg (54,000 tons) per year in 1990. Under the
promulgated standard, particulate matter emissions rates are projected to
decrease from those baseline levels by about 16,000 to 22,000 Mg (18,000 to
24,000 tons) per year. Baseline emissions of NO from new industrial-
A
commercial-institutional steam generating units are projected to be
approximately 77,000 Mg (85,000 tons) of NO per year in 1990. Under the
A
promulgated standard, NO emission rates are expected to decrease from those
A
baseline levels by about 21,000 to 24,000 Mg (23,000 to 26,000 tons) per
year. These emission reductions represent about a 35 to 45 percent
reduction in the growth of particulate matter emissions and about a 25 to 30
percent reduction in NO emissions from new steam generating units subject
A
to the standards.
The solid and liquid waste impacts associated with the promulgated
standards are minimal. The NO standards are based on the use of combustion
A
modification techniques to control NO emissions, and these techniques do
/\
not result in the production of either solid or liquid wastes. Flyash
disposal levels associated with existing State regulations and Subpart D new
source performance standards are only incrementally increased as a result of
the particulate matter standards adopted today. Further, the change in fuel
use patterns resulting from the particulate matter and NO standards, or
X
from the combined particulate matter, NO , and S09 standards, can actually
X c.
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reduce flyash levels. Overall, the standards are projected to result in
solid waste impacts ranging from a net reduction of about 9,000 Mg/year
(10,000 tons/year) to a net increase of 13,000 Mg/year (14,000 tons/year).
The liquid waste impacts of the promulgated standards are minimal and are
primarily the result of the projected use of wet scrubbing systems for the
control of particulate matter emissions from wood-fired steam generating
units. Under these regulations, liquid waste production levels would
increase from baseline by approximately 19,000 m (680,000 ft ), or
approximately 1.5 percent.
1.1.3 Energy and Economic Impacts of the Promulgated Action
The energy impacts of the proposed regulations were presented in the
preamble to the proposed standards (49 FR 25102, June 19, 1984) and in
Chapter 10 of the BID. Additional background on the energy impacts of the
promulgated standards can be found in the four documents on the
environmental impacts of the standards identified above.
Steam generating units that are projected to be affected by the
standards are expected to demand approximately 525 million GJ (498 trillion
Btu) of fossil fuels in 1990. It is projected that natural gas will provide
approximately 30 to 50 percent of the heat input to these steam generating
units, and that residual oil will provide most of the remaining steam
generating unit fuel. Coal use is projected to be limited to large units
with relatively high annual capacity factors.
The use of electrostatic precipitators (ESP's) and fabric filters to
comply with the particulate matter standards is expected to increase the
national electric energy requirements for new steam generating units by
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about 146 GWh/year in 1990. This increased electrical energy requirement
could be met by combusting an additional 524,000 GJ (497 billion Btu/year)
of fossil fuel in an electric utility steam generating plant, or less-than a
1 percent increase in the overall annual fuel consumption by new industrial-
commercial-institutional steam generating units. The use of low excess air
(LEA) for NO control will result in fuel savings which will partially
X
offset this increased fuel use.
The economic impacts of the proposed standards were presented in the
preamble to the proposed standard (49 FR 25102, June 19, 1984) and in
Chapter 9 of the BID. The economic impacts of the proposed standards, in
terms of increases in product prices or the availability of capital to the
firms purchasing steam generating units, are not expected to change
significantly from the impacts identified for the proposed standards.
Additional information on the economic impacts of the promulgated standards
can be found in the docket in the four documents described above in the
section on environmental impacts.
The projected capital and annual costs associated with the promulgated
standards vary depending on the regulatory requirements which are assumed to
apply to new steam generating units. The addition of the proposed S02
standards to the promulgated particulate matter and NO standards will
/\
result in a slight increase in the cost of NO controls. Since reductions
X
in particulate matter emissions are achieved as an incidental effect of S02
control under the proposed S02 regulation, the total costs of that proposed
standard are attributable to S02 control alone and are discussed in the
preamble to those proposed regulations (51 FR 22384).
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The promulgated standards are projected to increase the capital costs
of new steam generating units by less than 1 percent over the baseline
capital costs. Nationwide annual costs for new industrial-commercialr
institutional steam generating units will be approximately $36 million in
1990, or an increase of less than 1 percent over baseline annualized costs.
The national average cost effectiveness of the particulate matter standard
is projected to range from approximately $1,025 to $l,400/Mg ($930 to
$l,270/ton) of particulate matter removed. The national average cost
effectiveness of the NO standards is projected to range from $370 to
/\
$640/Mg ($340 to $580/ton) of NO removed.
X
1.1.4 Other Considerations
1.1.4.1 Irreversible and Irretrievable Commitment of Resources. The
long-term gains and losses in environmental resources expected to result
from the proposed regulation are discussed in Chapter 7 of the BID. These
gains and losses are not expected to change under the promulgated standards
Other than the fuels required for power generation and the materials
required for the construction of the control systems, there is no apparent
irreversible or irretrievable commitment of resources associated with this
regulation.
1.1.4.2 Environmental and Energy Impacts of Delayed Standards. The
environmental and energy impacts of delay in the promulgation of the
proposed standards are discussed in Chapter 7 of the BID. The results of
delay in the standards are that new industrial-commercial-institutional
steam generating units would be built which may not meet the emission
limitations established by these standards. This would delay the ambient
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air quality benefits, and other environmental benefits associated with this
NSPS. Further, potential improvements in energy efficiency resulting from
the adoption of LEA for NO control would also be postponed.
X
1.1.4.3 Urban and Community Impacts. Neither plant closures nor
impacts on small businesses are forecast. No significant adverse impacts on
urban areas or local communities are anticipated as the result of the
promulgation of these standards.
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2.0 SUMMARY OF PUBLIC COMMENTS
A total of 58 letters commenting on the proposed standards for control
of emissions of participate matter and NO from new industrial-commercial -
x *
institutional steam generating units were received. Comments were provided
by industry representatives, governmental entities, and environmental
groups. These comments have been recorded and placed in the docket for this
rulemaking (Docket Number A-79-02, Category IV). Table 2-1 presents a
listing of all persons submitting written comments, their affiliation and .
address, and the recorded Docket Item Number assigned to each comment.
Also, a total of three letters were received commenting on the
correction to the proposed rule. This correction proposed to revise the NO
/\
emission limit for wood residue and natural gas-fired steam generating
units. Table 2-2 presents a listing of all persons submitting written
comments, their affiliation and address, and the recorded Docket Item Number
assigned to each comment.
The comments summarized in this chapter have been organized into the
following categories:
2.1 Applicability of the Standard
2.2 Selection/Performance of Demonstrated NO Control Technology
/\
2.3 Stringency of the Proposed NO Emission Limits
A
2.4 Selection/Performance of Demonstrated Particulate Matter Control
Technology
2.5 Stringency of the Proposed Particulate Matter Emission Limits
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS FOR
PARTICULATE MATTER AND NITROGEN OXIDES EMISSIONS FROM
INDUSTRIAL-COMMERCIAL-INSTITUTIONAL STEAM GENERATING UNITS
Commenter
Jan B. Vlcek
James P. Rathvon
Sutherland, Asbill & Brennan
1666 K Street, N.W.
Washington, D. C. 20006
C. H. Fancy, P.E., Deputy Chief
Bureau of Air Quality Management
State of Florida
Department of Environmental Regulation
Twin Towers Office Building.
2600 Blair Stone Road
Tallahassee, Florida 32301
James K. Hambright, Director
Bureau of Air Quality Control
Commonwealth of Pennsylvania
Department of Environmental Resources
P. 0. Box 2063
Harrisburg, Pennsylvania 17120
Kennard F. Kosky, P.E., Vice President
Environmental Science and Engineering, Inc.
P. 0. Box ESE
Gainesville, Florida 32602
Harold E. Hodges, P.E.
Technical Secretary
Tennessee Air Pollution Control Board
Tennessee Department of Health and Environment
T.E.R.R.A. Building
150 Ninth Avenue, North
Nashville, Tennessee 37203
Bruce Blanchard, Director
Environmental Project Review
United States Department of the Interior
Office of the Secretary
Washington, D. C. 20240
Docket
Reference
IV-D-1
D-2
D-3
D-4
D-5
D-6
10
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Docket
Commenter Reference
W. T. Danker, Manager D-7
Environmental Programs
Chevron U.S.A., Inc.
P. 0. Box 7643
San Francisco, California 94120
Charles P. Blahous, J.D., Vice President D-8
Environmental Health and Safety
PPG Industries, Inc.
One PPG Place
Pittsburgh, Pennsylvania 15272
Walter Roy Quanstrom, General Manager D-9
Standard Oil Company (Indiana)
200 East Randolph Drive
Chicago, Illinois 60601
E. William Brownell D-10
Hunton & Williams
P. 0. Box 9230
Washington, D.C. 20036
John L. Festa, Ph.D. D-ll
Director, Chemical Control Programs
National Forest Products Association/
American Paper Institute
1619 Massachusetts Avenue, N.W.
Washington, D.C. 20036
Harry H. Hovey, Jr., P.E., Director D-12
Division of Air
New York State Department
of Environmental Conservation
50 Wolf Road
Albany, New York 12233
John E. Pinkerton D-13
Air Quality Program Manager
National Council of the Paper Industry
for Air and Stream Improvement, Inc.
260 Madison Avenue
New York, New York 10016
James P. Rathvon D-14
Sutherland, Asbill & Brennan
1666 K Street, N.W.
Washington, D. C. 20006
11
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Pocket
Commenter Reference
Hugh B. Barton D-15
Regulatory Affairs Manager
Production Department
Exxon Company, U.S.A.
P. 0. Box 2180
Houston, Texas 77001
A. 6. Smith, Manager D-16
Environmental Affairs
Shell Oil Company
One Shell Plaza
P. 0. Box 4320
Houston, Texas 77210
Fin Johnson, Chief D-17
Air Quality Section
North Carolina Department of Natural
Resources & Community Development
P. 0. Box 27687
Raleigh, N. C. 27611
K. M. Karch, Manager D-18
Regulatory and Environmental Affairs
Weyerhaeuser Company
Tacoma, Washington 98477
Charles 0. Velzy, P.E., President D-19
Charles 0. Velzy Associates, Inc.
Consulting Engineers
355 Main Street
Armonk, N. Y. 10504
Dal ton Yancy D-20
Executive Vice President
Florida Sugar Cane League, Inc.
P. 0. Box 1148
Clewiston, Florida 33440
James E. Walther D-21
Supervisor, Air and Noise Programs
Crown Zellerbach
Environmental Services
904 N.W. Drake St.
Camas, Washington 98607
12
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Docket
Commenter Reference
Daniel T. Skizim D-22
Manager of Contract Development
American Ref-Fuel
P. 0. Box 3151
Houston, Texas 77253
Peter W. McCallum D-23
Senior Corporate Environmental Specialist
Sohio-The Standard Oil Company
Midland Building
Cleveland, Ohio 44115
M. E. Miller, Jr., Manager D-24
Environmental Engineering Unit
R. 0. Reynolds Tobacco Company
Winston Salem, N. C. 27102
Catherine A. Marshall D-25
Vice President & Administrator,
Technical Department
United States Brewers Association, Inc.
1750 K Street, N.W.
Washington, D. C. 20006
J. J. Moon, Manager D-26
Environmental and Consumer Protection
Phillips Petroleum Company
7 D4 Phillips Building
Bartlesville, Oklahoma 74004
Donald A. Dowling D-27
Senior Vice President
Chief Operating Officer
Cogentrix of North Carolina, Inc.
Two Parkway Plaza, Suite 290
Charlotte, N. C. 28210
W. C. Wolfe, Manager D-28
Steam General Business Unit
Babcock & Wilcox
Industrial Power Generation Division
4282 Strausser Street, N.W.
P. 0. Box 2423
North Canton, Ohio 44720
13
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Docket
Commenter Reference
Mark D. Tucker D-29
Legal Department
The Dow Chemical Company
2030 Willard H. Dow Center
Midland, Michigan 48640
W. H. Axtman D-30
Executive Director
American Boiler Manufacturers Association
Suite 160
950 North Glebe Road
Arlington, Virginia 22203
William T. Burkhard, Supervisor D-31
Regional Air Pollution Control Agency
451 W. Third Street
P. 0. Box 972
Dayton, Ohio 45422
J. D. Patterson, Manager D-32
Environmental Affairs
Middle South Services, Inc.
Box 61000
New Orleans, Louisiana 70161
J. A. Barsin, Manager D-33
Boiler Components & Equipment
Babcock & Wilcox
P. 0. Box 351
Barberton, Ohio 44203
U. V. Henderson, Associate Director D-34
Environmental Affairs
Research Environmental Safety Department
Texaco, Inc.
P. 0. Box 509
Beacon, N. Y. 12508
F. William Brownell D-35
J. D. Fay
Hunton & Williams
P. 0. Box 12930
Washington, D. C. 20036
14
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Docket
Commenter Reference
Geraldine V. Cox, Ph.D. D-36
Vice President, Technical Director
Chemical Manufacturers Association
2501 M Street, N.W.
Washington, D. C. 20037
Jan B. Vlcek D-37
James P. Rathvon
Sutherland, Asbill & Brennan
1666 K Street, N.W.
Suite 800
Washington, D. C. 20006
David G. Hawkins D-38
Natural Resources Defense Council, Inc.
1350 New York Avenue, N.W.
Suite 300
Washington, D. C. 20005
J. C. Edwards D-39
Clean Environment Program
Eastman Kodak Company - Chemicals Division
P. 0. Box 511
Kingsport, Tennessee 37862
John L. Festa, Ph.D. D-40
Director, Chemical Control Program
National Forest Products Association/
American Paper Institute
1619 Massachusetts Avenue, N.W.
Washington, D. C. 20036
Jan B. Vlcek D-41
James P. Rathvon
Sutherland, Asbill & Brennan
1666 K Street, N.W.
Suite 800
Washington, D. C. 20006
J. C. de Rugter, Senior Engineer, Power Group D-42
T. A. Kittmeman, Air Quality and Hazards
Engineering Group
E.I. du Pont de Nemours & Company, Inc.
Engineering Department, Louviers Building
Wilmington, Delaware 19898
15
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Docket
Commenter Reference
Dr. William J. Vullo D-43
Environmental Project Engineer
General Electric Company
Environmental Protection Operation
One River Road
Schenectady, New York 12345
Rae E. Cronmiller D-44
Environmental Counsel
National Rural Electric Cooperative Association
1800 Massachusetts Ave., N.W.
Washington, D. C. 20036
James D. Beatty D-45
The Procter & Gamble Company
P. 0. Box 599
Cincinnati, Ohio 45201
Jan W. Mares D-46
Assistant Secretary for Policy, Safety,
and Environment
Department of Energy
Washington, D. C. 20585
Dr. John E. Pinkerton D-47
Air Quality Program Manager
National Council of the Paper Industry
for Air and Stream Improvement, Inc.
260 Madison Ave.
New York, New York 10016
S. J. Eaton D-48
Coen Company, Inc.
1510 Rollins Road
Burlingame, California 94010
Bruce P. Clinton D-49
Senior Energy Technology Specialist
Hercules, Inc.
Hercules Plaza
Wilmington, Delaware 19894
16
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Docket
Commenter Reference
Herbert Wortreich D-50
Assistant Director, Air and Noise Quality
State of New Jersey
Department of Environmental Protection
John Fitch Plaza CN 027
Trenton, New Jersey 08625
Bo 0. A. Oscarsson D-51
Technical Manager
Gotaverken Energy Systems
P. 0. Box 2147
Charlotte, N. C. 28211
Kathleen M. Bennett D-52
Director of Regulatory Affairs
Champion International Corporation
One Champion Plaza
Stamford, Connecticut 06921
Eric J. Schmidt D-53
Senior Environmental Engineer
Georgia-Pacific Corporation
P. 0. Box 105605
Atlanta, Georgia 30348
L. K. Arehart D-54
Supervisor-Regulatory Analysis
Health and Environmental Affairs Department
Diamond Shamrock Corporation
717 North Harwood Street
Dallas, Texas 75201
H. E. Cameron D-55
Plant Environment
Environmental Activities Staff
General Motors Corporation
General Motors Technical Center
30400 Mount Road
Warren, Michigan 48090
H. B. Coffman, Manager D-56
Environmental Services
Texas Utilities Generating Company
Skyway Tower
400 North Olive Street, L.B. 81
Dallas, Texas 75201
17
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Docket
Commenter Reference
Richard C. Wigger D-57
Vice President
Environmental and Safety Affairs
Champion International Corporation
One Champion Plaza
Stamford, Connecticut 06921
N. D. Fitzroy, Manager D-58
Energy and Environment Programs
General Electric Company
Gas Turbine Technology Development
& Planning Operation
One River Road
Schenectady, New York 12345
Terry McGuire, Chief D-64
Technical Support Division
California Air Resources Board
1102 Q Street
P. 0. Box 2815
Sacramento, CA 95812
Maggie Dean, Director D-65
Environmental Affairs
American Textile Manufacturers Institute, Inc.
1101 Connecticut Avenue, N.W.,
Suite 300
Washington, D.C. 20036
Larry F. Kertcher, Chief D-70
Air Compliance Branch (5AC-26)
U.S. Environmental Protection Agency
Region V
Michael Baly, III D-76
Vice President, Government Relations
American Gas Association
1515 Wilson Boulevard
Arlington, VA 22209
18
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TABLE 2-2. LIST OF COMMENTERS ON THE PROPOSED AMENDMENT
OF THE NITROGEN OXIDES STANDARD FOR NATURAL GAS/WOOD-FIRED
SUBPART D STEAM GENERATING UNITS
Docket
Commenter Reference
James D. Beatty IV-D-77
The Procter and Gamble Company
6110 Center Hill Road
Cincinnati, Ohio 45224
William B. Marx, President D-78
Council of Industrial Boiler Owners
11222 Silverleaf Drive
Fairfax Station, Virginia 22039
John L. Festa, Ph.D. D-79
Director, Chemical Control Program
National Forest Products Association/
American Paper Institute
1619 Massachusetts Avenue, N.W.
Washington, D. C. 20036
19
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2.6 Costs/Cost Effectiveness of the Proposed Standards
2.7 Monitoring, Recordkeeping, and Reporting Requirements
2.8 Emission Credits for Cogeneration/Combined Cycle Systems .
2.9 Energy, Environmental, and Economic Impacts •
2.10 Miscellaneous Comments
2.11 NO Emission Limits for Wood Residue and Natural Gas-Fired Units
A
2.1 APPLICABILITY OF THE STANDARD
2.1.1 General
1. D-17
Comment: EPA is correct in exempting modified sources from the
NO emission limits.
/\
2. D-38
Comment: EPA has no statutory authority to exempt modified steam
generating units from the NO standards. NO control
J\ /\
techniques can be retrofitted to steam generating units.
3. D-8, D-34, D-58
Comment: The proposed NO emission limits would apply to gas
~"^^^ A
turbine emissions when these turbines are employed in
cogeneration systems.
4. D-2, D-3
Comment: Steam generating units firing municipal solid waste
would be subject to both 40 CFR Part 60 Subpart Db and
40 CFR Part 60 Subpart E.
5. D-2
Comment: The applicability of the regulation to sewage sludge
incinerators which generate steam should be addressed.
20
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6. D-2
Comment:
7. D-2
Comment:
Sewage sludge incinerators and incinerators subject to
40 CFR Part 60 Subpart E should be excluded from 40 CFR
Part 60 Subpart Db.
The emission limits for solid waste-fired steam
generating units should be expressed in a concentration
format because it is difficult to accurately measure the
heat input for these steam generating units.
NO emission limits for combustion of municipal solid
A
8. D-19, D-22, D-28, D-30, D-37
Comment:
wastes should not be included in the final standard, but
treated on case-by-case basis by State and local
agencies. The composition of municipal solid waste
varies too widely to set a specific emission limit.
9. D-8, D-36
Comment: EPA has not adequately studied the emission
characteristics of chemical waste incinerators. There
is a wide variety of industrial incinerators currently
in use. The definition of incinerators is too broad and
is inconsistent with prior definitions of steam
generating units.
10. D-2
Comment:
The precise definition of a municipal solid waste
incinerator should be addressed in the regulation for
21
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purposes of defining prevention of significant
deterioration (PSD) applicability.
2.1.2 Process Units
1. D-7
Comment:
2. D-9
Comment:
3. D-9
Comment:
The definition of steam generating unit should be
modified to exclude process heaters that produce steam
in waste heat economizers for energy conservation
purposes. These sources should be covered in the NSPS
for fired heaters in the petroleum refining and
petrochemical industries.
Sources where low excess air (LEA) operation is not
appropriate should be exempted from the NO emission
/\
limits. These would include certain process units such
as carbon monoxide (CO) steam generating units where
fossil fuels are fired as supplementary fuels. Process
units are subject to variations in process conditions
and have several sources of heat input. LEA operation
may not be applicable to these units.
Sulfur recovery unit feed gas would be included in the
definition of natural gas. This would make Claus units
subject to the regulation. LEA technology is not
applicable to Claus units because the amount of air used
for combustion is only one-third of the theoretical
requirement.
22
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4. D-19
Comment:
5. 0-29
Comment:
6. D-34
Comment:
The proposed NSPS appears to unfairly penalize auxiliary
gas-fired units (energy recovery units) compared to
straight incineration and non-heat recovery units by
establishing stringent emission limits for auxiliary
gas-fired units and exempting non-heat recovery units.
EPA has not considered the operating parameters and
source characteristics of thermal heat recovery
oxidation (THROX) units. THROX units destroy toxic and
non-toxic wastes, recover hydrochloric acid and sodium
bicarbonate solution, and generate heat for use in
process plants. THROX units utilize technology which is
very different from conventional steam generating units
or incinerators. Because these units both generate
steam and destroy "hard to destroy" wastes, they should
be treated as a distinct source category. NO emissions
X
from THROX units are typically in the 25 to 50 ppm
range. In meeting the proposed NO emission limits, the
s\
ability of THROX units to destroy wastes and recover
materials would be limited.
Do the proposed standards apply to fluid catalytic
cracking units?
23
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7. D-34
Comment: EPA's treatment of CO steam generating units in
60.43b(a) and (b) is unclear. The formulas provided do
not contain any terms for NO emissions from CO burning.
X
Would CO steam generating units be required to meet the
proposed limit for natural gas firing?
2.1.3 Mixed Fuel-Fired Units
1. D-3
Comment: It is not clear whether and how the emission limits
identified as (6) or (7) in the table of 60.43b(a) would
apply to sources firing a mixture of fuels.
2. D-16, D-36, D-42
Comment: Firing of solid industrial waste in combination with
fossil fuels should be exempted from the regulations or
covered under a separate category.
3. D-18, D-37, D-40, D-47, D-49, D-53, D-57
Comment: The 5 percent annual fossil fuel capacity factor
criterion suggested by EPA for exclusion from the NO
/\
monitoring and emission standards is not realistic
because it does not account for the limitations on
system burndown ratios, or for the need to periodically
increase fossil fuel use to account for fluctuations in
load and fuel characteristics. Steam generating unit
stability requires fossil fuel use of at least 10
percent.
24
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4. D-57
Comment: Steam generating units burning combinations of
gas/oil/coal and wood should be exempt from the NOX
standards if the annual fossil fuel capacity factor is
less than 25 percent.
2.1.4 Fuel Definitions/Exclusions
1. D-30, D-37, D-42, D-45, D-49
Comment: Black liquor recovery steam generating units, coal/water
slurries, coal/oil slurries, and micronized coal should
be explicitly exempted from the regulations.
2. D-9, D-30, D-36, D-37, D-42, D-45, D-49, D-54
Comment: The existing definition of "natural gas" is too broad,
and should be revised to exclude other gaseous
materials.
3. D-30
Comment:
The definition of wood should be revised to include only
natural wood products without additives, drying, sizing,
and with a moisture content of between 40 and 50 percent
and a nitrogen content of greater than 0.4 percent
(dry).
4. D-15, D-34, D-36, D-37, D-38
Comment: The definition of "other fuels" is too vague. Emission
limits for these fuels should be determined on a
case-by-case basis.
25
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5. D-20
Comment:
6. D-18,
Comment:
7. D-18
Comment:
8. D-27,
Comment:
9. D-29
Comment:
10. D-29
Comment:
11. D-32,
Comment:
Units burning bagasse should be explicitly exempted from
the regulations.
D-37
The proposed standard appears to cover wood gasification
and combustion of that gas, but no data are presented.
Gaseous and liquid products from wood and other forms of
biomass should be excluded from the standard until data
become available.
Firing of pulverized wood fines should be exempt from
the regulations because no data are available on
emissions from units firing this fuel.
D-29, D-37, D-45, D-54
Combined cycle/cogeneration systems should be exempted
from the proposed NO emission limits.
X
No definition is provided for incinerators.
Thermal heat recovery oxidation (THROX) units should be
exempted from the proposed standards.
D-35, D-56
Auxiliary steam generating units at steam-electric
plants should be exempted from the standards. These
steam generating units are infrequently operated and do
not contribute significantly to emissions.
26
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12. D-34
Comment:
13. D-37
Comment:
14. D-37
Comment:
15. D-37
Comment:
16. D-54
Comment:
17. D-16,
Comment:
Plant produced fuel gas can contain elevated nitrogen
concentrations and a waiver should be granted by EPA for
this difference in NO emissions.
/\
Steam generating units burning any type of agricultural
wastes should be exempted from the proposed standard.
No data are available to support standards, and
emissions from burning these wastes are minimal.
The definition of coal is too broad. Data are
unavailable to support standards for units burning
coal-derived fuels. The definition of coal should be
restricted to established coal forms and firing methods.
Incinerators should be excluded from the proposed
standards.
Heat recovery steam generating units should be exempted
from the proposed regulations.
D-30, D-34, D-36, D-37, D-39, D-42, D-45, D-49
Gaseous and liquid byproduct fuels should be deleted
from the definitions of natural gas and residual oil.
The emissions and combustion characteristics of these
fuels are too variable to justify their inclusion in the
proposed standards for fossil oil and gas.
27
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2.1.5 Size Cutoff
1. D-6, D-12, D-31
Comment: EPA is correct in establishing NSPS for steam generating
units in the 29 to 73 MW (100 to 250 million Btu/hour)
heat input capacity size range because the States have
been reluctant to set stringent emission limits for
these units in the absence of NSPS.
2. D-ll, D-18, D-40, D-42, D-47, D-57
Comment: The NSPS for steam generating units in the 29 to 73 MW
(100 to 250 million Btu/hour) heat input capacity size
range are not warranted given the relatively small
contribution to emissions from these sources. State
regulations are sufficient to meet the regulatory needs
of these steam generating units.
3. D-ll, D-57
Comment: It would be "arbitrary and unlawful" for EPA to
promulgate NSPS for steam generating units in the 29 to
73 MW (100 to 250 million Btu/hour) heat input capacity
size range without first formally denying requests that
these size units be delisted.
4. D-38
Comment:
It would be unlawful for EPA to regulate steam
generating units only down to 29 MW (100 million
Btu/hour) heat input capacity because EPA has previously
28
-------
identified steam generating units as small as 2.9 MW (10
million Btu/hour) heat input capacity to be major
sources.
5. D-50
Comment: The lower limit on capacity of affected steam generating
units is too high and should be set at 15 MW (50 million
Btu/hour) heat input capacity. Steam generating units
in the 15 to 29 MW (50 to 100 million Btu/hour) heat
input capacity range are similar in design to those in
the 29 to 73 MW (100 to 250 million Btu/hour) heat input
capacity size range, make up a similar fraction of the
total steam generating unit population, and have similar
fuel use patterns.
2.2 SELECTION/PERFORMANCE OF DEMONSTRATED NO CONTROL TECHNOLOGY
/\
2.2.1 General
1. D-9, D-30, D-48
Comment: Low excess air (LEA) technology should form the
technological basis of the proposed standards for NO
J\
rather than add-on control technology. The LEA
technology results in no additional capital or operating
costs, saves energy, does not result in increased
emissions of other pollutants, and is effective at all
generating loads.
2. D-16, D-24, D-25, D-30, D-36, D-37, D-42, D-43, D-46, D-48, D-49
Comment: The EPA has made broad and sweeping conclusions as to
the performance of control technologies on the basis of
29
-------
limited test data. Sufficient data have not been
developed to support emission limits for all the fuels
and fuel combinations the proposal intends to regulate.
3. D-29, D-30, D-36, D-37, D-42, D-48
Comment: Staged combustion (SC) has not been adequately
demonstrated in reducing NO emissions from steam
X
generating units in the 29 to 73 MW (100 to 250 million
Btu/hour) heat input capacity size range, and there are
insufficient data to support emission standards based on
SC controls. Specifically, (1) SC technology has not
been adequately demonstrated for high heat release
package steam generating units burning residual oil with
a nitrogen content of 0.2 to 0.4 weight percent, (2) SC
has not been adequately demonstrated on
spreader-stokers, (3) SC has been shown to be
ineffective in reducing NO emissions under reduced load
A
operation for all steam generating unit/fuel
arrangements.
4. D-30, D-37, D-48
Comment: The correlations established for predicting the
emission reductions achievable by SC are in error
because (1) data from all different types of steam
generating units were grouped together, (2) the majority
of data are for small package units or large field
erected units, (3) a number of data points were obtained
from units operating with high excess air and the method
30
-------
used to normalize emission data to a baseline oxygen
level is subject to error, and (4) virtually all of the
data for SC operation were obtained from furnaces-with
long residence times and low heat release rates, and
these data cannot be generalized to high heat release
package steam generating units.
5. D-30
Comment: The EPA is incorrect in stating that flue gas
recirculation (FGR) achieves little reduction in NO
A
beyond that achievable with LEA. FGR is most effective
in suppressing thermal NO formation from combustion of
/\
gas and distillate oil and can achieve a reduction in
NO emissions of more than 30 percent. Drawing
A
conclusions from tests on two small FGR-equipped units
[less than 15 MW (50 million Btu/hour) heat input
capacity] is difficult, and demonstrates the need for a
larger data base in determining demonstrated technology.
6. D-25, D-29, D-30, D-33, D-36, D-37, D-42, D-48
Comment: The EPA has given inadequate consideration to variations
in steam generating unit design and the effect of these
design variations on NO emissions, particularly those
A
relating to firebox design, heat release rate, and other
factors relating to steam generating unit size.
7. D-9, D-37
Comment: The EPA was correct in mathematically correlating NO
A
emission reductions with steam generating unit operating
31
-------
8. D-9
Comment:
variables. However, EPA should demonstrate that these
correlations are representative of the actual population
of steam generating units that EPA intends to regulate.
Case-by-case determinations should be allowed for steam
generating units which are not representative.
Performance of NO controls may decline with increasing
A
equipment age. The EPA tests were probably conducted on
relatively new equipment and the emission limits may not
account for declining performance due to age.
9. D-25, D-37
Comment: Large package steam generating units may have to be
derated by up to 30 percent to meet the proposed
standard because of limitations on firebox size. The
Agency derating estimate of 7 percent is an
underestimate.
10. D-25, D-26, D-36, D-37
Comment: The "vendor guarantees" cited by EPA can not be used as
a basis for determining best demonstrated technology
because these do not represent actual contracts between
buyers and sellers, and many of these guarantees apply
only to the extreme lower size of the steam generating
units to be regulated.
11. D-32
Comment:
Only one of five vendors would guarantee a NO emission
/\
limit of 43 ng/J (0.1 ID/million Btu) heat input for a
32
-------
distillate oil-fired unit. This is insufficient for
determining best demonstrated technology and has
potential antitrust ramifications.
12. D-15, D-25
Comment: Vendors of steam generating units and burner equipment
are unable to guarantee an emission limit of 43 ng/J
(0.1 Ib/million Btu) heat input will be achieved when
firing natural gas or distillate oil.
13. D-38
Comment: The EPA has ignored the fact that various types of flue
gas treatment technologies have been demonstrated in
controlling NO emissions from oil- and coal-fired steam
X
generating units. These systems should be used as the
basis for setting the standards.
14. D-38
Comment: The proposed standards do not reflect the level of
control achievable by low excess air/staged combustion/
staged combustion burner (LEA/SC/SCB) technologies
(lower emission limits are justified).
15. D-37, D-49
Comment: Background data obtained over a 30-day test period
should not be relied upon as representative of long-term
operating conditions. NO emissions can fluctuate due
to process load swings, changes in fuel characteristics,
automatic control deviations, and time.
33
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2.2.2 Coal-Fired Steam Generating Units
1. D-16, D-25, D-30, D-36, D-37, D-42, D-49
Comment: Insufficient emission test data are available to support
the proposed NO emission limit of 301 ng/J (0.7
A
Ib/million Btu) heat input for pulverized coal-fired
steam generating units. No test data were provided for
pulverized coal-fired steam generating units of less
than 88 MW (300 million Btu/hour) heat input capacity.
Pulverized coal-fired steam generating units of less
than 73 MW (250 million Btu/hour) heat input capacity
are designed substantially differently (i.e.,
wall-fired) than larger pulverized coal-fired steam
generating units (i.e., tangentially-fired).
2. D-33
Comment:
3. D-31
Comment:
The proposed standards have not considered fluidized bed
combustion (FBC) as a demonstrated control technology.
Based on 2-year operating data with atmospheric
fluidized bed combustion (AFBC) units, NO emissions of
A
172 ng/J (0.4 Ib/million Btu) heat input are achievable
when burning eastern bituminous coal.
Pulverized coal-fired steam generating units can reduce
emissions of NO to below the proposed limit of 301 ng/J
A
(0.7 Ib/million Btu) heat input. One unit was tested
and found to emit 84 ng/J (0.195 Ib NO /million Btu)
/\
heat input.
34
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4. D-25, D-33, D-37, D-43
Comment: The NO emission limit for coal firing should allow for
~" /\
differences between firing bituminous and subbituminous
coal. Such allowances are provided in the NSPS for
steam-electric plants.
5. D-30, D-46
Comment: The EPA does not have sufficient data to substantiate
the long-term variation in NO emissions from spreader
/\
stokers of 7 percent when using a 30-day rolling
average. Only two units were equipped with continuous
monitors and both of these were operated at light loads
and high excess air.
6. D-30
Comment:
The EPA is incorrect in concluding that fuel nitrogen
content had no measurable effect on NO emissions from
/\
spreader stoker steam generating units. The test
procedures were inadequate to correlate the fuel burned
at a given moment to NO emissions.
J\
7. D-25, D-30, D-33, D-36, D-37, 0-39, D-42
Comment: The EPA is in error in concluding that combustion air
preheat has no effect on NO emissions from spreader
/\
stoker steam generating units. The test data were
incorrectly interpreted.
35
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2.2.3 Gas-/0i1-Fired Steam Generating Units
1. D-30
Comment: The relationships between fuel nitrogen content and NO
" * A
emissions is not well established for residual oils,
especially the difference between burning residual oil
in package steam generating units versus field erected
steam generating units.
2. D-7
Comment: Two new (1976) gas-fired steam generating units without
combustion air preheat and using LEA at the El Segundo
refinery have NO emissions of 116 ng/J (0.27 Ib/million
A
Btu) heat input. To achieve the proposed emission
limit, emissions would have to be reduced by about 63
percent. This exceeds the emission reduction capability
of SC/SCB technology, which is normally recognized to be
30 to 45 percent.
3. D-25, D-36, D-37, D-48
Comment: The regression formula relating NO emissions to design
*~™^^^^^ A
variables for residual oil firing does not properly
address the thermal or the fuel NO component. The
A
thermal NO component should vary according to heat
A
release to absorbing area and increase with increasing
capacity. The values used in the equation for
conversion of fuel nitrogen to NO are too low.
A
36
-------
4. D-25, D-29, D-33, D-36, D-37
Comment: Performance data for two natural gas-fired units
equipped with LEA air and overfire air capability-are
not representative because the units had large heat
input capacities [166 and 234 MW (567 and 800 million
Btu/hour)].
5. D-25, D-37, D-48
Comment: Performance data for three natural gas-fired units
equipped with LEA and SCB are not representative because
they had been slightly derated.
6. D-26, D-29, D-32, D-36, D-37
Comment: The data supporting the NO emission limit for steam
generating units firing gas and distillate oil are not
representative because only one long-term test was
available and this was on a very small unit [1.5 MW (5
million Btu/hour)] heat input capacity.
7. D-26
Comment:
The data supporting the NO emission limit for steam
/\
generating units firing gas and distillate oil are not
representative because the steam generating units with
air preheat had relatively low air preheat temperatures.
8. D-26, D-32
Comment:
generating units firing gas and distillate oil are not
representative because of the wide scatter seen among
The data supporting the NO emission limit for steam
X
37
-------
the individual data points. Given this variability, EPA
should not have relied on average values.
9. D-29, D-30, D-33, D-36, D-37, D-42, D-49
Comment: The EPA did not adequately assess the effect of
combustion air preheat on NO emissions from gas- and
A
distillate oil-fired steam generating units.
10. D-29, D-36, D-37
Comment: The EPA did not consider the effect of the nitrogen
content of distillate oil on NO emissions from
J\
distillate oil-fired steam generating units.
11. D-32, D-33, D-36, D-37, D-42
Comment: Low excess air/staged combustion burner technology has
not been demonstrated to reduce emissions from
distillate oil-fired steam generating units to 43 ng/J
(0.1 Ib/million Btu) heat input.
12. D-55
Comment:
The NO standards for gas- and oil-fired steam
A
generating units are based on a minimal amount of test
data and appear impossible to meet on a continuous
basis.
2.2.4 Other Steam Generating Units
1. D-16, D-30, D-37, D-39
Comment: Insufficient data are available to determine best
demonstrated technology for units firing combinations of
fossil and nonfossil fuels.
38
-------
2. D-22, D-28
Comment: State requirements for minimum temperatures and
residence times for destruction of organics in
incinerators burning municipal solid waste would prevent
these units from achieving the proposed limits on NO
A
emissions.
3. D-28
Comment: Municipal solid waste incinerators would have to install
scrubbers in order to reduce NO emissions to 129 ng/J
A
(0.3 Ib/million Btu) heat input. The costs of these
systems have not been addressed.
4. D-34
Comment:
NO control technologies for steam generating units may
/\
not be effective for turbines, particularly those firing
distillate oil.
5. D-8, D-30, D-54
Comment: The EPA has insufficient background information on which
to establish NSPS for combined cycle systems. No
parametric data on effects of excess air, overfire air,
system design or duct-firing have been obtained.
Combined cycle systems should be evaluated as a separate
source category.
39
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2.3 STRINGENCY OF THE N0v EMISSION LIMITS
A
1. D-23, D-42, D-57
Comment: There is no compelling reason to establish NSPS for NO
-•-~ f X
emissions from small steam generating units. Only one
area in the U.S. is not in attainment with the National
Ambient Air Quality Standards (NAAQS) for NO .
A
2.3.1 Gas-/Disti11ate Oil-Fired Steam Generating Units
1. D-29, D-30, D-37, D-48
Comment: The proposed emission limits are unrealistic and should
be raised to 86 ng/J (0.2 ID/million Btu) heat input for
distillate fuel oil (less than 0.05 percent nitrogen)
and for gas burning with ambient combustion air.
Gas-fired units with preheated combustion air should be
limited to 108 ng/J (0.25 Ib/million Btu) heat input.
2. D-7
Comment:
3. D-9
Comment:
The proposed emission limit is too stringent and should
be raised to between 65 and 86 ng/J (0.15 and 0.20
Ib/million Btu) heat input. The proposed emission limit
exceeds the emission reduction capacity of LEA/SC/SCB
control technology.
The emission limits should be set at 86 ng/J (0.2
Ib/million Btu) heat input for natural gas-fired units
and 129 ng/J (0.3 Ib/million Btu) heat input for
distillate oil-fired units. These levels can be met by
using LEA alone.
40
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4. D-15, D-26
Comment: The proposed gas/distillate oil emission limit is too
stringent and should be raised to 86 ng/J (0.2
ID/million Btu) heat input.
5. D-33
Comment:
6. D-33
Comment:
A NOY standard of 86 ng/J (0.2 Ib/million Btu) heat
/\
input for non-preheat gas/distillate oil firing would be
supported by commercial guarantees.
A NOY standard of 108 ng/J (0.25 Ib/million Btu) heat
A
input for greater than 93°C (200°F) preheat
gas/distillate oil firing would be supported by
commercial guarantees.
2.3.2 Residual Oil-Fired Steam Generating Units
1. D-29, D-30, D-37, D-48
Comment: The proposed NO emission limits for residual oil firing
/\
should be raised to 172 ng/J (0.4 Ib/million Btu) heat
input for low nitrogen oils and to 215 ng/J (0.5
Ib/million Btu) heat input for oil with a high nitrogen
content. The proposed limits would prematurely force
most residual oil-fired units to implement SC, which has
not been properly developed for large package units.
2. D-33
Comment:
A NOV emission limit of 215 ng/J (0.5 Ib/million Btu)
J\
heat input for high nitrogen (greater than 0.35 percent)
41
-------
3. D-33
Comment:
residual oil firing would be supported by commercial
guarantees.
A NO emission limit of 172 ng/J (0.4 Ib/million Btu)
/\
heat input for low nitrogen (less than 0.35 percent)
residual oil firing would be supported by commercial
guarantees.
4. D-38
Comment: The data show that even high nitrogen residual oil-fired
steam generating units could achieve a 30-day average
emission rate of 129 ng/J (0.3 Ib/million Btu) heat
input.
5. D-54
Comment:
The emission limits for residual oil firing should not
vary with the fuel nitrogen content. Fuel nitrogen
varies widely on the basis of crude oil supplies and is
expensive to monitor.
2.3.3 Mass Feed Coal-Fired Steam Generating Units
1. D-33
Comment: The proposed emission limit would be supported by
commercial guarantees.
2. D-37
Comment:
The NO emission limit for mass feed coal-fired steam
A
generating units should be 215 ng/J (0.5 Ib/million Btu)
heat input.
42
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2.3.4 Spreader Stoker Coal-Fired Steam Generating Units
1. D-27, D-29, D-30, D-37, D-39
Comment: Spreader stoker steam generating units operating with
preheated combustion air cannot achieve a NO emission
/\
limit of 258 ng/J (0.6 lb/million Btu) heat input. The
emission limit should be raised to 301 ng/J (0.7
lb/million Btu) heat input. It was noted that the
proposed limit would force spreader stokers with
preheated combustion air to be designed for very low
heat release rates, which would raise costs and thus
encourage pulverized coal (PC) firing. The proposed
emission limit for PC firing is 301 ng/J (0.7 ID/million
Btu) heat input.
2. D-33
Comment:
3. D-33
Comment:
4. D-38
Comment:
A NO emission limit of 301 ng/J (0.7 lb/million Btu)
A
heat input for air preheat spreader stoker coal firing
would be supported by commercial guarantees.
A NO emission limit of 258 ng/J (0.6 Ib/million Btu)
/\
heat input for non-air preheat [less than 93°C (200°F)]
spreader stoker coal firing would be supported by
commercial guarantees.
The 11 percent upward adjustment of the long-term test
data is not representative of the other units tested and
43
-------
The NO emission limit for pulverized coal-fired steam
/\
the emission level should be lowered to between 172 and
215 ng/J (0.4 and 0.5 Ib/million Btu) heat input.
2.3.5 Pulverized Coal-Fired Steam Generating Units
1. D-29, D-30, D-37, D-48
Comment:
generating units should be raised to 344 ng/J (0.8
Ib/million Btu) heat input. Although LEA/SC can reduce
emissions from units smaller than 73 MW (250 million
Btu/hour) heat input capacity, a reduction to 301 ng/J
(0.7 Ib/million Btu) heat input cannot be achieved. In
small units, higher flame temperatures must be
maintained to achieve complete combustion because of
smaller volume-to-surface area ratios. These conditions
2. D-33
Comment:
result in higher NO emissions.
/\
A NOV emission limit of 344 ng/J (0.8 Ib/million Btu)
A
heat input for pulverized coal firing would be supported
by commercial guarantees.
Data collected by EPA/IERL show an emission rate of 172
ng/J (0.4 Ib/million Btu) heat input can be achieved
using low NO burners.
/\
2.3.6 Multiple Fuel Units
1. D-30
Comment: More leeway must be provided in determining NO emission
A
limits for units burning multiple fossil fuels.
3. D-38
Comment:
44
-------
Multiple fuel steam generating units are designed
according to the most difficult fuel to be burned.
Because of this, NO emission control techniques are
A
compromised in a multiple fuel-firing situation. It is
unreasonable to expect optimum NO control when both
A
clean and dirty fuels are fired in a unit designed
primarily in accordance with the requirements for
burning the more difficult to burn (dirty) fuels.
Therefore, the limits should not be based on the lowest
achievable NO emissions for individual fuels in a
A
multiple fuel unit.
2. D-29, D-30, D-36, D-39, D-42, D-54
Comment: Insufficient data are available to regulate emissions
from units burning a combination of fossil fuels and
chemical byproduct gaseous and liquid wastes,
particularly waste fuels such as hydrogen gas, ammonia
bearing gas, liquids with high nitrogen content, and
high heat content fuels (greater than 1,500 Btu/ft). In
many instances, the applicable fossil fuel-based NO
A
limit could not be met.
3. D-16, D-30, D-36, D-37, D-39
Comment: Insufficient data are available to justify NO emission
/\
limits for units firing nonfossil fuels and mixtures of
nonfossil and fossil fuels.
45
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4. D-57
Comment: A nonfossil fuel steam generating unit designed to burn
gas and residual oil would be designed to fire either
fuel at the same rate. Thus, if the weighted average
were applied, the applicable emission limit would be 86
ng/J (0.2 Ib/million Btu) heat input. A steam
generating unit burning gas or residual oil in
combination with wood or solid waste should not be
restricted to 86 ng/J (0.2 ID/million Btu) heat input
when a combination with distillate oil would be allowed
to emit 129 ng/J (0.3 Ib/million Btu) heat input. A
nonfossil steam generating unit burning gas and residual
oil in combination should be allowed a NO limit
/\
equivalent to that for residual oil-fired steam
generating units.
2.3.7 Combined Cycle Systems
1. D-30, D-48
Comment: The emission limit for combined cycle units should be
raised to 86 ng/J (0.2 Ib/million Btu) heat input for
units burning gas and distillate oil and should be
deferred for units firing residual oil.
2.4 SELECTION/PERFORMANCE OF DEMONSTRATED PARTICULATE MATTER CONTROL
TECHNOLOGY
1. D-4
Comment: A specific collection area (SCA) of greater than 250
2
ft /I,000 acfm will not assure that the proposed
46
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2. D-13
Comment:
3. D-4
Comment:
4. D-4
Comment:
standard will be met. Data from one plant indicated
that a particulate matter emission level of-65 ng/J
(0.15 Ib/million Btu) heat input is achievable on.a
continuous basis with existing technology. The standard
must account for soot blowing.
Electrostatic precipitators are capable of reducing
particulate matter emissions from combination
coal-/wood-fired steam generating units to 86 ng/J (0.02
Ib/million Btu) heat input.
Insufficient data are available to set NSPS for
particulate matter emissions from municipal solid
waste/refuse derived fuel-fired steam generating units
(MSW/RDF). The EPA did not test enough facilities to
account for typical emissions variability, or test any
facilities burning up to 50 percent MSW.
Variability in fuel characteristics (moisture, ash, heat
content) which is 2 to 3 times higher for MSW/RDF than
for other fuels causes corresponding variabilities in
emissions and control device performance. Particulate
matter emissions ranged from 22 to 56 ng/J (0.05 to 0.13
Ib/million Btu) heat input and averaged 39 ng/J (0.09
Ib/million Btu) heat input (standard deviation = 0.03).
Periodic (greater than 6 min/hour) soot blowing is also
47
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5. D-31
Comment:
required which increases particulate matter emissions by
about 80 percent.
Two MSW incinerators equipped with ESP's (300 ft2/l,000
cfm) achieved emission rates of 13 and 17 ng/J (0.03 and
0.04 Ib/million Btu) heat input. State of the art
control technologies can reduce emissions from MSW
incinerators to less than 43 ng/J (0.1 ID/million Btu)
heat input.
6. D-31, D-38
Comment: The "relaxed" emission levels allowed for units
operating at capacity factors of less than 30 percent do
not represent application of best demonstrated
technology.
7. D-31, D-38
Comment: Based on EPA's own admission, ESP's are capable of
reducing emissions from units firing mixed fuels to less
than 43 ng/J (0.1 Ib/million Btu) heat input.
8. D-38
Comment:
The EPA's conclusion that fabric filters and ESP's
cannot achieve better than 22 ng/J (0.05 Ib/million Btu)
heat input on coal-fired steam generating units is
arbitrary, capricious, and is not supported by the data
available to EPA. The EPA has previously determined,
and defended in court, that emissions of 13 ng/J (0.03
Ib/million Btu) heat input are achievable based on data
48
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from both utility and industrial steam generating units.
The few test data showing emissions higher than 13 ng/J
(0.03 Ib/million Btu) heat input were from ESP's having
SCA's less than that considered to represent best
demonstrated technology (650 ft /I,000 acfm). All of
the data on the fabric filter systems support an
emission limit of 13 ng/J (0.03 Ib/million Btu) heat
input. The Unit C system was not a well designed and
operated system and test data on this system included
soot blowing cycles.
9. D-50
Comment: Particulate matter emissions from wood-fired steam
generating units can be controlled to less than 43 ng/J
(0.1 Ib/million Btu) heat input.
2.5 STRINGENCY OF THE PARTICULATE MATTER EMISSION LIMITS
1. D-24, D-57
Comment: The emission limits for particulate matter are too
stringent.
2. D-31
Comment: The emission limit for coal-fired steam generating units
of 22 ng/J (0.05 ID/million Btu) heat input is
appropriate.
3. D-31, D-38
Comment: The proposed emission limit for municipal waste
incinerators is too lenient and does not reflect best
demonstrated technology.
49
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4. D-31, D-38
Comment: The proposed emission limits for units operating at less
than 30 percent capacity factors are far too lenient. A
capacity factor of 30 percent does not reflect a
"standby" or sparingly used unit.
5. D-31
Comment:
6. D-38
Comment:
7. D-38
Comment:
8. D-38
Comment:
The proposed emission limits for mixed fuel firing as
specified in 60.42b(c) are too lenient and should be
lowered to 30 ng/J (0.07 Ib/million Btu) heat input.
The proposed emission limit of 22 ng/J (0.05 Ib/million
Btu) heat input for coal-fired steam generating units is
too lenient, and should be lowered to 13 ng/J (0.03
Ib/million Btu) heat input.
Wood-fired steam generating units equipped with
electrostatic granular filters (EGF) can achieve
emissions of 9 to 17 ng/J (0.02 to 0.04 Ib/million Btu)
heat input. The EPA has not justified setting a higher
standard.
In the absence of any theoretical or empirical data to
show that mixed solid fuel steam generating units cannot
achieve the same emission levels as coal-fired steam
generating units, EPA should not propose separate
emission limits for these sources. The 5 percent mixed
50
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9. D-50
Comment:
10. D-55
Comment:
11. D-37
Comment:
fuel criterion will encourage owners and operators to
burn these fuels in order to be subject to a less
stringent emission limit.
The proposed emission limit of 43 ng/J (0.1 Ib/million
Btu) heat input for wood-fired steam generating units is
too lenient. Although wood is not widely burned, the
proposed emission limit fails to consider the emission
impact of the proposed standard in the areas near wood
burning sources.
The particulate matter emission limit of 22 ng/J (0.05
Ib/million Btu) heat input for coal-fired steam
generating units prohibits the use of wet scrubbers
which may be required for standards covering emissions
of sulfur dioxide.
The following particulate matter emission limits are
recommended for steam generating units in the 29 to 73
MW (100 to 250 million Btu/hour) heat input capacity
size range:
Mass feed spreader stoker, 108 ng/J
(0.25 Ib/million Btu) heat input;
Pulverized coal, 43 ng/J (0.1 Ib/million
Btu) heat input.
51
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For steam generating units above 73 MW (250 million
Btu/hour) heat input capacity, a particulate matter
emission limit of 43 ng/J (0.1 Ib/million Btu) heat
input should be set for coal and residual oil firing.
12. D-12
Comment: The proposed particulate matter emission levels are
appropriate.
2.6 COSTS/COST EFFECTIVENESS OF THE PROPOSED STANDARDS
1. D-7, D-25, D-30, D-36, D-37, D-39
Comment: The EPA has used steam generating units without low
excess air (LEA) controls as the basis for calculating
the cost effectiveness of NO controls. Fuel savings
A
from LEA operation were credited to the costs of NO
/\
controls. This is inappropriate because new units will
be operated under LEA conditions even in the absence of
an NSPS. The EPA's approach understates the real cost
effectiveness of the proposed regulation.
2. D-15, D-36
Comment: The costs of meeting the proposed NO emission limits
" ™" /\
are largely undefined because manufacturers do not
presently offer steam generating units guaranteed to
meet a 43 ng/J (0.1 Ib/million Btu) heat input emission
limit.
3. D-18, D-24, D-26, D-27, D-29, D-40, D-45, D-46, D-49, D-53
Comment: The costs of NO continuous emission monitoring systems
^^^^™"--- •" /\
(CEMS) are excessive for steam generating units in the
52
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29 to 73 MW (100 to 250 million Btu/hour) heat input
capacity size range.
4. D-18, D-53
Comment: Steam generating units using between 5 and 30 percent of
fossil fuel input without a permanent NO monitor will
A
be required to perform an expensive 30-day NO
A
compliance test. The costs of this test will not be
commensurate with the air quality benefits obtained.
5. D-18, D-24
Comment: The cost effectiveness of controls for small steam
generating units is 20 to 40 times higher than that for
utility steam generating units, and represents a poor
use of limited capital for environmental protection.
6. D-23
Comment: The EPA estimates show that the cost of implementing the
standard may be as high as $2,000/Mg ($l,800/ton) of NO
A
removed, but EPA has also estimated the benefits of NO
A
control are only $150/Mg ($135/ton).
7. D-25, D-37, D-43
Comment: EPA has grossly underestimated the capital and operating
costs of CEMS equipment. Capital costs are about
$125,000 and annual costs are about $100,000.
8. D-25, D-37
Comment: The cost effectiveness of the proposed NO standard for
'"' A
a gas-fired 44 MW (150 million Btu/hour) heat input
capacity unit would be $3,000/Mg ($2,700/ton) removed,
53
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10. D-27
Comment:
11. D-31
Comment:
The cost effectiveness of the proposed NO standard for
X
assuming the use of a low NO burner, baseline LEA
A
operation, a 7 percent derating, and revised monitoring
costs. The costs are unreasonable.
9. D-25, D-37
Comment:
a residual oil-fired 44 MW (150 million Btu/hour) heat
input capacity unit would be $2,800/Mg ($2,500/ton) for
0.3 percent fuel nitrogen, and $4,400/Mg ($4,000/ton)
for 0.4 percent fuel nitrogen, assuming the use of
overfire air ports, baseline LEA operation, a 7 percent
derating, and revised monitoring costs. These costs are
unreasonable.
The costs for NO CEMS are $110,000 in capital costs and
A
$50,000 in annual operating costs. In addition, a
microprocessor would be required to calculate 30-day
rolling averages at a cost of $80,000.
The EPA has placed too much reliance on cost and
economic factors in establishing the proposed emission
1imits.
12. D-32, D-35
Comment: It is not cost effective to require low excess
air/staged combustion burner (LEA/SCB) controls on steam
generating units with capacity factors of less than 30
percent.
54
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13. D-36,
Comment:
14. D-36,
Comment:
15. D-36,
Comment:
16. D-38
Comment:
17. D-38
Comment:
D-39, D-46
The EPA has not presented cost effectiveness numbers in
Tables 9 to 14 of the proposal in a manner which is
meaningful for comparing alternative control levels.
The incremental cost effectiveness between alternative
control levels should be shown.
D-39
The cost effectiveness numbers of pulverized coal firing
in Table 9 are misleading because EPA has used the costs
of a low efficiency ESP instead of the costs for a
sidestream separator or a double mechanical collector.
D-37, D-45
The cost effectiveness of particulate matter control for
coal-fired steam generating units'are out of proportion
to the cost effectiveness for utility size units. The
EPA should justify why a cutoff in cost effectiveness of
$110/Mg ($100/ton) should not be established.
Cost effectiveness calculations should be based on the
actual expected performance of the best demonstrated
systems in reducing emissions rather than on the
emission limits themselves.
EPA has not established that operating a CEMS for NO
/\
emissions would be unreasonably costly for units
55
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operating at an annual capacity factor of less than 30
percent.
18. D-37, D-45
Comment: The NO emission limits should be revised to be of
comparable cost effectiveness as those for utility size
steam generating units.
19. D-30, D-46, D-55, D-57
Comment: The cost effectiveness of the proposed standards for
particulate matter (coal/wood) are underestimated
because the baseline emissions levels used by EPA [258
ng/J (0.6 1 fa/million Btu) heat input] are higher than
the actual emission levels generally allowed from these
sources by State regulations.
20. D-37
Comment: The EPA has grossly underestimated the costs of control
of NO . A steam generating unit derating of 30 percent
A
will be required in many cases. The monitoring
requirements were underestimated by one-half. There
will be no fuel savings with low NO burners. The
/\
actual cost effectiveness of the standard for a 44 MW
(150 million Btu/hour) heat input capacity natural
gas-fired steam generating unit is over $8,300/Mg
($7,500/ton). The actual cost effectiveness of
controlling a residual oil-fired steam generating unit
(0.4 percent nitrogen) is $5,500/Mg ($5,000/ton). The
actual cost effectiveness of controlling a residual
56
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21. D-37
Comment:
22. D-37
Comment:
oil-fired steam generating unit (0.3 percent nitrogen)
is $8,800/Mg ($8,000/ton).
The EPA must quantify the benefits of any proposed
standards.
Cost effectiveness data for residual oil-fired units are
presented for oils with 0.47 and 0.6 percent nitrogen.
Because the standard distinguishes residual oil with
less than 0.35 percent nitrogen, cost effectiveness data
for this oil should be provided.
Capital costs, including installation, for a
transmissometer for continuous opacity monitoring are
approximately $40,000. These costs are unreasonable.
2.7 MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS
2.7.1 Continuous NO.. Emission Monitoring Systems
i ..,.,.,,.-.._. j^ •* *•
1. D-5, D-39, D-40, D-47, D-54
Comment: Steam generating units having an annual capacity factor
greater than 30 percent should not be required to
install and operate a NO CEMS if, during a 30-day
/\
performance test, NO emission levels of 30 percent (or
J\
10 percent, D-47) or more below the applicable limit are
demonstrated. This would be consistent with 40 CFR Part
60 Subpart D requirements.
23. D-27
Comment:
57
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2. D-7, D-27, D-43, D-47, D-49
Comment: Monitoring of operating conditions should be allowed for
all units regardless of capacity factor. NO emissions
^\
can be reliably predicted for LEA, SC, and SCB controls
once excess oxygen, optimum staging ratios, and load
response curves are established. These parameters can
be established during the 30-day performance test and be
subject to approval by the Administrator. This approach
would avoid the financial, maintenance, and operating
problems associated with installing a NO monitor on top
J\
of the Op/CO monitors used in LEA systems.
3. D-8, D-21
Comment: NO monitors installed on combined cycle units will
^^~^^^^~ /\
measure emissions from both the steam generating unit
and the turbine unless two monitors are installed (inlet
and outlet of steam generating unit) to determine
incremental NO formed in the steam generating unit.
A
The EPA has not investigated costs or accuracy of twin
monitoring systems.
4. D-18, D-24, D-47, D-49, D-53, D-55
Comment: Most smaller manufacturing facilities which would be
subject to the NSPS do not have personnel capable of
operating, calibrating, and maintaining NO CEMS.
/\
5. D-23, D-33, D-49, D-54
Comment: Continuous NO monitors are unreliable.
~ A
58
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6. D-23, D-24, D-29, D-37, D-40, D-43, D-49, D-53, D-55
Comment:
7. D-24,
Comment:
8. D-24,
Comment:
9. D-26
Comment:
10. D-50
Comment:
11. D-53
Comment:
The continuous monitoring requirements for NO emissions
A
are unnecessary and excessive.
D-26, D-27, D-33, D-37, D-55
EPA Reference Method 7 is sufficient for determining
compliance with the NO emission limits.
/\
D-39
The proposed requirement that malfunctioning CEMS
equipment must be repaired within 15 days is unrealistic
because of the sophisticated nature of this equipment,
and the possible need to return the device to the
manufacturer.
If CEMS are required, provisions should be made to allow
owners/operators to remove CEMS if after a sufficient
period (2 years) emissions have not exceeded the limits.
The proposed NO monitoring requirements should be
A
retained in the promulgated standards because major
increases in NO emissions in the future will create the
X
need for better information on NO control.
The language currently in 40 CFR 60.45(b)(3) and (4)
would provide adequate assurance that a new source was
designed, manufactured, installed, and operated in a
manner to achieve the proposed NO emission limits.
/\
59
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12. D-54
Comment:
13. D-9
Comment:
14. D-21
Comment:
2.7.2 Opacity
1. D-3
Comment:
It is not clear why EPA chose to adopt the 30-day
rolling average for NO compliance. The data seem to
/\
support a figure more than 8 percent above the 43 ng/J
(0.1 Ib/million Btu) heat input emission limit. If this
is true, EPA should set the limit at 52 ng/J (0.12
Ib/million Btu) heat input or greater and retain the
existing compliance methods.
A NO CEMS should not be required for gas and/or
A
oil-fired steam generating units with less than 73 MW
(250 million Btu/hour) heat input capacity. Stack
testing at suitable intervals should be an alternative
to installation of continuous NO monitors.
X
An exemption from the NO CEMS requirement is
X
recommended for combined cycle supplementary-fired gas
turbine systems with less than 30 percent total heat
input from low NO duct burners.
X
The opacity span values of 60 to 80 percent would not
allow a determination of the severity of exceedances
above the span value. A span value of 100 percent is
recommended.
60
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2. D-4
Comment:
3. D-5
Comment:
4. D-5
Comment:
The opacity limit of 20 percent cannot be achieved
continuously for units firing municipal solid waste and
refuse derived fuel. Company test data show 6-minute
opacity readings from 0 to 60 percent. At average
particulate matter emissions of 327 ng/J (0.76
Ib/million Btu) heat input, opacity averaged 42 percent
for one test run. The EPA data also show greater than
20 percent opacity with particulate matter emissions of.
43 ng/J (0.1 1 fa/mill ion Btu) heat input. Soot blowing
increases opacity by 154 percent over non-soot blowing
periods.
Opacity values from in-stack monitoring devices should
be used for purposes of determining compliance instead
of Reference Method 9. Use of transmissometers would be
contingent on proper installation and operation of the
device. They would not be applicable for situations
where exhaust gases contain condensed water vapor, or
where a reaction or condensation plume is noted above
the stack.
When proper reading techniques are utilized, visible
emissions evaluations may be obtained from steam
generating units equipped with wet scrubbing devices.
61
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5. D-13,
Comment:
6. D-18
Comment:
7. D-18,
Comment:
8. D-27
Comment:
9. D-31
Comment:
10. D-31
Comment:
D-18, D-47
An opacity limit of 20 percent cannot be achieved
continuously by units burning coal/wood mixtures. -
The 6-minute average opacity limits would not be
consistent with the limits on particulate matter
emissions expressed as a 3-hour average.
D-30, D-37
Site-specific opacity limits should be established.
Visual determination of opacity using Reference Method 9
is an adequate indicator that a particulate matter
control device is being properly operated and
maintained.
The proposed opacity limit of 20 percent is too lenient
for coal-fired units. Properly operating control
devices should result in visible emissions of no more
than 5 to 10 percent opacity.
The proposed opacity limits are assumed to apply to all
phases of equipment operation: startup, shutdown, soot
blowing, ash removal.
62
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12. D-38
Comment:
11. D-31
Comment: Control devices operating at elevated temperatures to
avoid dew point related problems will have difficu-lty in
meeting the proposed opacity limits during startup and
shutdown.
Fabric filters and ESP's which are well operated and
maintained can achieve an opacity limit of 1 percent.
Accordingly, EPA should adopt an opacity limit of
1 percent.
13. D-37, D-57
Comment: There is no justification of establishing a "not to be
exceeded" limitation of opacity of 20 percent. Opacity
cannot be correlated to mass emission rates. Opacity
limits should only be used as an indicator of possible
exceedance for reporting purposes.
14. D-54
Comment:
Facilities burning gas and oil should be exempt from the
continuous opacity monitoring requirement.
2.7.3 Data Collection
The NO averages based on 720 hours of operation would
/\
1. D-3, D-23
Comment:
not be consistent with data collected for calendar time
periods, and will be administratively burdensome. The
30-day averages should be calculated on rolling calendar
time periods.
63
-------
2. D-3
Comment: The data availability requirement in 60.45b(f) is too
lenient because it allows a source to be in compliance
while collecting less than 0.3 percent valid data
(1 hour valid data for every 16 days). A required
percent (75 percent is recommended) valid data should be
specified for each 30-day period.
3. D-5, D-53
Comment: To be consistent with 40 CFR Part 60 Subpart D, the
proposed minimum sampling time (for particulate matter
emissions) of 120 minutes, and the minimum sampled
volume of 120 dscf, should be lowered to 60 minutes and
60 dscf, respectively.
2.7.4 Reporting Requirements
1. D-3, D-31, D-38
Comment: Submittal of reports on a semiannual basis is too
infrequent for tracking CEMS operation, maintenance, and
quality assurance data. Reports should be submitted
quarterly and include emissions, data validation, and
calibration information.
2. D-31
Comment:
Affected facilities located in States to which EPA has
delegated enforcement authority should not be required
to submit reports to EPA. In these cases, the reporting
requirements would be duplicative and should be waived.
64
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4. D-38
Comment:
3. D-31
Comment: It is unclear in 60.46b(h).what specific items should be
reported on excessive opacity in order to fulfill.the
reporting requirement.
Reports should be required, regardless of whether an
excess emission has occurred, in order to ensure that
some sources do not neglect to file a report.
2.7.5 Exemptions
1. D-3
Comment: The exemptions allowed in 60.44b(a) would not encourage
efforts to minimize emissions during startup, shutdown,
and malfunction. Rather than granting a blanket
exemption, EPA should specify a percentage of each
reporting period when exceedances during startup,
shutdown, and malfunction would be allowed.
2. D-5, D-24, D-25, D-36, D-37, D-40, D-47, D-49
Comment: One 6-minute per hour exemption should be allowed for
opacity. The 27 percent opacity allowance under 40 CFR
Part 60 Subpart D should be extended to the smaller
units covered in the proposed regulations.
3. D-13, D-39, D-47, D-57
Comment: The EPA should revise the proposed standard to allow for
a number of 6-minute average opacity readings of above
20 percent to account for rapidly changing fuel feed
rates or fuel quality.
65
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4. D-29
Comment: The existing pro-visions for petitioning the
Administrator for an exemption from the proposed -
standards are inadequate. Meeting the NO emission
X
limits for some type of units (e.g., THROX) may not
result in non-compliance with other Federal, State or
local regulations, although it would still result in
diminished destruction efficiencies and interference
with process operation. The petitioning procedures
would cause substantial delay, expense, and uncertainty.
5. D-36, D-43
Comment: An allowance for soot blowing in residual oil- and solid
fuel-fired units should be included.
6. D-39
Comment: The provisions for petitioning the Administrator for
units burning hazardous wastes should be expanded to
allow these units to "maintain the appropriate
destruction efficiency."
7. D-37, D-45, D-49, D-53
Comment: Sources equipped with wet scrubbers for particulate
matter control should be exempted from the opacity
monitoring requirements.
2.7.6 Enforcement/Permitting
1. D-17
Comment: If EPA delegates to a State the authority to enforce the
proposed regulations, would a permit which limits the
66
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capacity factor have to be adopted as part of the State
implementation plan (SIP)?
2. D-54
Comment: The rationale for the "capacity factor basis" appears
designed to accommodate those who permit multiple and/or
standby fuels. The problem with the Agency's approach
is that, while a facility may be permitted to burn
residual oil 25 percent of the time, the facility
actually burns 100 percent oil during those 90 days per
year. This proposal would leave such an operation with
permit limits that could be met only by burning 25
percent oil all year long. Thus, this approach does not
appear to be appropriate for use with the EPA's proposed
30-day rolling average limits.
2.8 EMISSION CREDITS FOR COMBINED CYCLE SYSTEMS
1. D-16, D-29, D-34, D-36, D-39, D-40, D-44, D-54
Comment: Emission credits should be provided for combined cycle
and other cogeneration systems.
2. D-16, D-29, D-40, D-44
Comment: The EPA should defer to State and local agencies in
determining on a case-by-case basis specific emission
limits to ensure that emission credits do in fact lead
to net reductions in emissions.
3. D-34, D-36
Comment: Emission reduction credits are often the difference
between making or breaking a cogeneration project.
67
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4. D-36, D-39
Comment: Site-specific factors should not prevent EPA from
allowing emission credits for cogeneration systems.. A
credit equivalent to about 50 percent of the credit that
would be given on a one-to-one basis should be allowed.
5. D-36, D-39, D-46
Comment: The EPA's decision not to provide emission credits for
cogeneration systems is contrary to Congressional intent
in passing PURPA and other energy/environmental
legislation.
6. D-44
Comment: Emission credits could be granted on a system-wide basis
for an electric utility based on system-wide reductions
in emissions achieved by avoidance of new conventional
technologies or replacement of older sources.
7. D-39, D-44,, D-54
Comment: The EPA has exaggerated the potential for cogeneration
systems to displace cleaner sources of energy such as
hydroelectric or nuclear facilities.
2.9 ENERGY, ENVIRONMENTAL, AND ECONOMIC IMPACTS
2.9.1 Energy Impacts
1. D-25, D-30, D-48, D-49
Comment: The proposed NO standards will not promote energy
__^«^_«^H__ ^
efficiency. The use of staged combustion (SC) will
result in operation of units at unnecessarily high
excess air rates.
68
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2. D-29
• Comment: The proposed NO standards may limit the use of hydrogen
™™^~«— J\
and other wastes as fuel and lead to increased usage of
natural gas.
3. D-30, D-36
Comment: The proposed NO standards will decrease energy
1 •-— X
efficiency by limiting the use of combustion air
preheat.
2.9.2 Environmental Impacts
1. D-25, D-30, D-37, D-47, D-48, D-55, 0-57
Comment: The EPA has overestimated the environmental benefits
associated with this NSPS. The number of new steam
generating units projected is too high and the
"baseline" emission levels used by EPA in calculating
national impacts are too high.
2. D-30, D-48
Comment: The use of SC will result in many units being out of
compliance with State regulations for particulate
matter.
3. D-16, D-25, D-29, D-30, D-36, D-37, D-43, D-48, D-49, D-54
Comment: The EPA has not investigated the impacts of higher
carbon monoxide, particulate, and hydrogen emissions
resulting from use of SC.
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4. D-18, D-57
Comment: The EPA estimates of the total emission reductions which
would be achieved under the proposed NSPS are only a few
tenths of a percent of total national emissions. The
EPA has greatly overstated the benefits of the proposed
NSPS by not distinguishing steam generating units larger
than 73 MW (250 million Btu/hour) heat input capacity
from those in the 29 to 73 MW (100 to 250 million
Btu/hour) heat input capacity size range.
5. D-18, D-37, D-57
Comment: The EPA should perform a more thorough examination of
the impacts of the proposed NSPS versus the benefits
achieved under State regulations in order to determine
whether the proposed standard will result in a
significant improvement in air quality.
6. D-18, D-37, D-55
Comment: The proposed standards may result in delays in
replacement of existing steam generating units,
resulting in higher emissions. Most new steam
generating units are likely to be replacements for older
units.
7. D-57
Comment:
The tightening of the existing particulate matter
emission limit for coal-fired steam generating units
would provide no discernible environmental benefit in
maintaining the NAAQS.
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2.9.3 Economic Impacts
1. D-30, D-48
Comment: By forcing the premature use of SC, the financially
depressed steam generating unit/burner market will be
subjected to "excessive risk." The steam generating
unit/burner market is in no position to shoulder this
risk because of recent declines in the market.
2. D-23, D-33
Comment: The proposed regulations for particulate matter
emissions could raise the cost of a coal-fired steam
generating unit by as much as 10 percent, which would
discourage the transition from oil or gas to coal. They
may encourage more industries to locate overseas.
3. D-36
Comment:
The 15 percent steam generating unit derating required
for package residual oil-fired steam generating units to
meet the NO emission limits would increase the cost of
/\
these steam generating units by 10 percent.
4. D-57
Comment:
The proposed emission limits for particulate matter
would increase capital costs and result in reduced
operating flexibility and increased downtime.
2.10 MISCELLANEOUS COMMENTS
1. D-17
Comment: The wording in 60.42b(c) is cumbersome and unclear.
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2. D-26
Comment:
3. D-38
Comment:
4. D-38
Comment:
5. D-47
Comment:
The phrase "after initial startup" should be deleted
from 60.44b(e)(2) in order to eliminate possible •
confusion with the requirements set forth in 60.8(a).
In calculating the achievable emission levels for
various technologies, EPA appears to have relied on
statistical techniques that specify an emission level
that will be exceeded only once every 10 years. This
implies that enforcement action will result for one
exceedance in a 10-year period. The EPA should
calculate the achievable emission levels based on one .
assumed exceedance every year, every 2 years, and every
5 years.
The EPA has ignored the potentially important emission
reductions of both particulate matter and NO that could
/\
be achieved by the selective use of natural gas and
distillate oil. The EPA should examine the emissions,
costs, and energy implications of standards for coal-
and residual oil-fired steam generating units that
assume the proportional use of these cleaner fuels at
several alternative levels of use.
Section 60.43b needs to be clarified. Paragraph (a)
entry (6) in the table indicates that mixtures of gas or
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oil with wood or solid waste have an emission limit of
129 ng/J (0.3 Ib/million Btu) heat input. Entry (7)
conflicts with this limit. The reference to entry (5)
apparently should be to entry (6). Otherwise, the
formula in paragraph (b) would have to be used to
calculate the NO emission limit for gas/oil/wood
/\
combinations, and this would be incorrect. Also, there
is a problem with the formula in paragraph (b) as it
applies to mixtures of wood/coal/gas/oil. A 29 MW (100
million Btu/hour) heat input capacity steam generating
unit with a heat input of 5.9 MW (20 million Btu/hour)
from wood, 2.9 MW (10 million Btu/hour) from gas, and
21 MW (70 million Btu/hour) from coal would have an
emission limit of 275 ng/J (0.64 Ib/million Btu) heat
input. This problem could be corrected by changing the
definition of Ht to include heat input from wood when
wood is burned with gas and coal or with oil and coal.
The definition of Hu should be modified to include
mixtures of distillate oil and wood.
6. D-50
Comment: The equation used for the NO limit for mixed fossil/
A
nonfossil fuel burning needs to include a term for the
heat input from nonfossil fuels in the denominator.
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7. D-57
Comment: The EPA should not propose any new rules governing
particulate matter emissions while revisions to the
NAAQS for participates are still being considered.
8. D-30
Comment: 60.43b(d) refers to modification of a facility as
defined in §60.15. However, §60.15 covers
reconstruction, and §60.14 covers modification. Which
is correct?
9. D-30
Comment:
In 60.44b(a), the reference should be 60.43b, not
60.42b.
2.11 NO EMISSION LIMITS FOR WOOD RESIDUE AND NATURAL GAS-FIRED UNITS
J\
1. D-77, D-78, D-79
Comment: The proposed rule that corrects the NSPS for units
firing mixtures of wood residue and natural gas to
129 ng/J (0.30 Ib/million Btu) heat input is strongly
endorsed.
2. D-77, D-78, D-79
Comment: The correction to the proposed rule should be adopted as
soon as possible (before May 31, 1986, D-77).
U.S. Environmental Protection Agency
Region V, Library *
230 South Dearborn Street
Chicago, Illinois 60604
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