United States
Environmental Protection
Agency
Off ice of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA 450 3-86-005
June 1986
Air
Summary of
Regulatory Analysis for
New Source
Performance
Standards:
Industrial-
Commercial-
Institutional Steam
Generating Units of
Greater than 100
Million Btu/hr
Heat Input
IIl-B-l
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P.3
EPA-450/3-86-005
Summary of Regulatory Analysis for New
Source Performance Standards: Industrial-
Commercial-Institutional Steam
Generating Units of Greater than 100
Million Btu/hr Heat Input
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, NC 27711
June 1986
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P.4
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 of use. Copies of the report are available through the Library Services Office
(MD-35), U.S. Environmental Protection Agency, Research Triangle Park, N.C. 27711, or from National Technical
Information Services, 5285 Port Royal Road, Springfield, Virginia 22161.
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P.5
TABLE OF CONTENTS
Chapter Page
1.0 INTRODUCTION 1-1
2.0 SELECTION OF SOURCE CATEGORY 2-1
3.0 SELECTION OF POLLUTANTS, FUELS, AND AFFECTED FACILITIES 3-1
4.0 SELECTION OF DEMONSTRATED EMISSION CONTROL TECHNOLOGIES 4-1
4.1 SULFUR DIOXIDE EMISSIONS FROM COAL AND OIL
COMBUSTION 4-1
4.1.1 Low Sulfur Coal 4-5
4.1.2 Low Sulfur Oil 4-7
4.1.3 Combustion Modification 4-9
4.1.4 Post-Combustion Technologies 4-13
4.2 PARTICULATE MATTER EMISSIONS FROM OIL COMBUSTION 4-22
4.2.1 Low Sulfur Oil 4-23
4.2.2 Post-Combustion Control 4-24
4.3 PARTICULATE MATTER EMISSIONS FROM COAL COMBUSTION 4-26
5.0 PERFORMANCE OF DEMONSTRATED EMISSION CONTROL TECHNOLOGIES 5-1
5.1 LOW SULFUR COAL 5-6
5.2 LOW SULFUR OIL 5-20
5.3 COMBUSTION MODIFICATION AND FLUE GAS DESULFURIZATION 5-21
5.3.1 Fluidized Bed Combustion 5-23
5.3.2 Lime Spray Drying 5-28
5.3.3 Lime/Limestone Wet Scrubbing 5-36
5.3.4 Dual Alkali Scrubbing 5-41
5.3.5 Sodium Wet Scrubbing 5-47
5.4 PARTICULATE MATTER EMISSIONS FROM OIL COMBUSTION 5-51
5.4.1 Low Sulfur Oil 5-52
5.4.2 Add-On Control Techniques 5-55
5.5 PARTICULATE MATTER EMISSIONS FROM COAL COMBUSTION 5-57
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_PJ_
TABLE OF CONTENTS (CONTINUED)
Chapter Page
6.0 CONSIDERATION OF DEMONSTRATED EMISSION CONTROL TECHNOLOGY
COSTS 6-1
6.1 COSTS OF SULFUR DIOXIDE EMISSION CONTROL FOR COAL-FIRED
STEAM GENERATING UNITS 6-4
6.1.1 Range of Percent Reduction Requirements 6-14
6.1.2 90 Percent Reduction Requirement 6-26
6.1.3 Summary of Analysis 6-35
6.2 COSTS OF SULFUR DIOXIDE EMISSION CONTROL FOR OIL-FIRED
STEAM GENERATING UNITS 6-42
6.2.1 Range of Percent Reduction Requirements 6-49
6.2.2 90 Percent Reduction Requirement 6-57
6.2.3 Summary of Analysis 6-61
6.3 COSTS OF SULFUR DIOXIDE EMISSION CONTROL FOR MIXED
FUEL-FIRED STEAM GENERATING UNITS 6-68
6.4 COSTS OF PARTICULATE MATTER EMISSION CONTROL FOR
OIL-FIRED STEAM GENERATING UNITS 6-70
6.5 COSTS OF PARTICULATE MATTER EMISSION CONTROL FOR COAL-FIRED
STEAM GENERATING UNITS EQUIPPED WITH FGD SYSTEMS 6-74
7.0 CONSIDERATION OF SECONDARY ENVIRONMENTAL IMPACTS 7-1
7."1 AIR QUALITY IMPACTS 7-1
7.2 WATER QUALITY AND SOLID WASTE IMPACTS 7-4
7.2.1 Low Sulfur Fuels 7-4
7.2.2 Percent Reduction 7-11
8.0 CONSIDERATION OF NATIONAL IMPACTS 8-1
8.1 FOSSIL FUEL-FIRED STEAM GENERATING UNITS 8-1
8.1.1 Selection of Regulatory Alternatives 8-7*
8.1.2 Analysis of Regulatory Alternatives 8-18
IV
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P.7
TABLE OF CONTENTS (CONTINUED)
Chapter Page
8.2 MIXED FUEL-FIRED STEAM GENERATING UNITS 8-27
8.2.1 Selection of Regulatory Alternatives 8-30
8.2.2 Analysis of Regulatory Alternatives 8-33
9.0 CONSIDERATION OF INDUSTRY-SPECIFIC ECONOMIC IMPACTS 9-1
10.0 CONSIDERATION OF EMISSION CREDITS 10-1
10.1 COGENERATION STEAM GENERATING UNITS 10-1
10.1.1 Steam Generator-Based Cogeneration Systems 10-1
10.1.2 Combined Cycle or Gas Turbine-Based
Cogeneration Systems 10-9
10.2 MIXED FUEL-FIRED STEAM GENERATING UNITS 10-21
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P.8
LIST OF TABLES
Table Page
4-1 FUEL SULFUR CONTENT AND S0? EMISSION RATES FOR COAL AND
OIL TYPES 7 4-6
5-1 CONTINUOUS EMISSION MONITORING (CEM) DATA 5-9
5-2 MAXIMUM EXPECTED EMISSION RATES FOR COAL COMBUSTION 5-16
5-3 EMISSION RATES FOR OIL COMBUSTION 5-22
6-1 COSTS OF DEMONSTRATED FLUE GAS DESULFURIZATION SYSTEMS 6-5
6-2 S0? EMISSION CEILINGS ASSOCIATED WITH VARIOUS PERCENT
REDUCTION REQUIREMENTS 6-9
6-3 ALTERNATIVE CONTROL LEVELS FOR COAL-FIRED INDUSTRIAL-COMMERCIAL-
INSTITUTIONAL STEAM GENERATING UNITS - RANGE OF PERCENT
REDUCTION REQUIREMENTS 6-12
6-4 ALTERNATIVE CONTROL LEVELS FOR COAL-FIRED INDUSTRIAL-COMMERCIAL-
INSTITUTIONAL STEAM GENERATING UNITS - 90 PERCENT REDUCTION
REQUIREMENT 6-13
6-5 COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION V - RANGE OF PERCENT
REDUCTION REQUIREMENTS 6-16
6-6 COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION VIII - RANGE OF
PERCENT REDUCTION REQUIREMENTS 6-17
6-7 COST IMPACTS OF SO. CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT SIZE IN EPA REGION V - RANGE OF PERCENT REDUCTION
REQUIREMENTS 6-20
6-8 COST IMPACTS OF SO- CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT SIZE IN EPA REGION VIII - RANGE OF PERCENT REDUCTION
REQUIREMENTS 6-21
6-9 COST IMPACTS OF S09 CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V - RANGE OF
PERCENT REDUCTION REQUIREMENTS 6-24
6-10 COST IMPACTS OF S09 CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION VIII - RANGE
OF PERCENT REDUCTION REQUIREMENTS 6-25
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LIST OF TABLES (CONTINUED)
Table Page
6-11 COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION V - 90 PERCENT REDUCTION
REQUIREMENT 6-27
6-12 COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION VIII - 90 PERCENT
REDUCTION REQUIREMENT 6-28
6-13 COST IMPACTS OF S02 CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT SIZE IN EPA REGION V - 90 PERCENT REDUCTION REQUIREMENT 6-30
6-14 COST IMPACTS OF S02 CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT SIZE IN EPA REGION VIII - 90 PERCENT REDUCTION
REQUIREMENT 6-31.
6-15 COST IMPACTS OF S09 CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V - 90 PERCENT
REDUCTION REQUIREMENT 6-33
6-16 COST IMPACTS OF SO, CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION VIII - 90
PERCENT REDUCTION REQUIREMENT 6-34
6-17 COST EFFECTIVENESS OF S0? PERCENT REDUCTION REQUIREMENTS FOR A
44 MW (150 MILLION BTU/HOUR) COAL-FIRED STEAM GENERATING UNIT... 6-37
6-18 COST IMPACTS FOR COAL-FIRED STEAM GENERATING UNITS IN REGIONS V
AND VIII - 90 PERCENT REDUCTION REQUIREMENT 6-39
6-19 IMPACTS OF FUEL SWITCHING ON COST ANALYSIS 6-40
6-20 S09 EMISSION CEILINGS ASSOCIATED WITH VARIOUS PERCENT
REDUCTION REQUIREMENTS 6-44
6-21 ALTERNATIVE CONTROL LEVELS FOR OIL-FIRED INDUSTRIAL-COMMERCIAL-
INSTITUTIONAL STEAM GENERATING UNITS - RANGE OF PERCENT
REDUCTION REQUIREMENTS 6-46
6-22 ALTERNATIVE CONTROL LEVELS FOR OIL-FIRED INDUSTRIAL-COMMERCIAL-
INSTITUTIONAL STEAM GENERATING UNITS - 90 PERCENT REDUCTION
REQUIREMENT 6-48
6-23 COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED
STEAM GENERATING UNIT IN EPA REGION V - RANGE OF PERCENT
REDUCTION REQUIREMENTS 6-50
vn
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P.10
LIST OF TABLES (CONTINUED)
Table Page
6-24 COST IMPACTS OF SO, CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT SIZE IN EPA REGION V - RANGE OF PERCENT REDUCTION
REQUIREMENTS 6-53
6-25 COST IMPACTS OF S09 CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V - RANGE OF
PERCENT REDUCTION REQUIREMENTS 6-55
6-26 COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED STEAM
GENERATING UNIT IN EPA REGION V - 90 PERCENT REDUCTION
REQUIREMENT 6-58
6-27 COST IMPACTS OF SO, CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT SIZE IN EPA REGION V - 90 PERCENT REDUCTION REQUIREMENT.... 6-60
6-28 COST IMPACTS OF S0? CONTROL AS A FUNCTION OF STEAM GENERATING
UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V - 90 PERCENT
REDUCTION REQUIREMENT 6-62
6-29 COST EFFECTIVENESS OF A RANGE OF PERCENT REDUCTION REQUIREMENTS
FOR A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED STEAM GENERATING
UNIT IN REGION V 6-64
6-30 COST IMPACTS FOR OIL-FIRED STEAM GENERATING UNITS IN REGION V -
90 PERCENT REDUCTION REQUIREMENT 6-67
6-31 COST IMPACTS OF PARTICULATE MATTER CONTROL FOR A 44 MW
(150 MILLION BTU/HOUR) OIL-FIRED STEAM GENERATING UNIT IN
REGION V 6-73
6-32 COST IMPACTS OF PARTICULATE MATTER CONTROL FOR A 44 MW (150
MILLION BTU/HOUR) COAL-FIRED STEAM GENERATING UNIT IN
REGION V 6-76
7-1 S02 DISPERSION ANALYSIS 7-3
7-2 TYPICAL COMPONENTS OF FLY ASH 7-6
7-3 TRACE CONSTITUENTS IN FLY ASH AND BOTTOM ASH FROM VARIOUS
UTILITY STEAM GENERATING UNITS 7-7
7-4 ELEMENTAL COMPOSITION OF CRUDE OIL 7-10
7-5 QUANTITY OF WASTE PRODUCED BY VARIOUS FGD SO^ CONTROL SYSTEMS... 7-12
vm
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P.11
LIST OF TABLES (CONTINUED)
Table Page
7-6 CONCENTRATIONS OF MAJOR AND MINOR SPECIES IN LIME SPRAY DRYING
WASTE 7-15
7-7 TYPICAL ELEMENTAL COMPOSITION OF LIME SPRAY DRYING WASTE 7-17
7-8 TYPICAL LEVELS OF CHEMICAL SPECIES IN WET FGD WASTE SOLIDS AND
LIQUORS 7-19
7-9 TYPICAL LEVELS OF CHEMICAL SPECIES IN SODIUM SCRUBBING
WASTEWATER STREAMS 7-22
8-1 LEVELIZED INDUSTRIAL FUEL PRICES: HIGH OIL PENETRATION ENERGY
SCENARIO 8-4
8-2 NATIONAL IMPACTS: FOSSIL FUEL-FIRED STREAM GENERATING UNITS -
REGULATORY BASELINE (BASE CASE) 8-6
8-3 LEVELIZED INDUSTRIAL FUEL PRICES: HIGH COAL PENETRATION
ENERGY SCENARIO 8-8
8-4 ALTERNATIVE CONTROL LEVELS - FOSSIL FUEL-FIRED STEAM
GENERATING UNITS 8-11
8-5 PRELIMINARY ANALYSIS OF NATIONAL IMPACTS - FOSSIL FUEL-FIRED
STEAM GENERATING UNITS 8-13
8-6 REGULATORY ALTERNATIVES - FOSSIL FUEL-FIRED STEAM GENERATING
; UNITS 8-19
8-7 NATIONAL IMPACTS OF REGULATORY ALTERNATIVES - FOSSIL FUEL-FIRED
STEAM GENERATING UNITS 8-20
8-8 POTENTIAL NATIONAL NATURAL GAS MARKET IMPACTS 8-23
8-9 NATIONAL IMPACTS: FOSSIL FUEL-FIRED STEAM GENERATING UNITS -
POTENTIAL COAL MARKET IMPACTS 8-24
8-10 NATIONAL IMPACTS: MIXED FUEL-FIRED STEAM GENERATING UNITS -
REGULATORY BASELINE (BASE CASE) 8-31
8-11 REGULATORY ALTERNATIVES - MIXED FUEL-FIRED STEAM GENERATING
UNITS 8-32
IX
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P.12
LIST OF TABLES (CONTINUED)
Table Page
8-12 NATIONAL IMPACTS OF REGULATORY ALTERNATIVES - MIXED FUEL-FIRED
STEAM GENERATING UNITS 8-34
8-13 NATIONAL IMPACTS: MIXED FUEL-FIRED STEAM GENERATING UNITS -
IMPACTS AS A FUNCTION OF FOSSIL FUEL UTILIZATION FACTOR 8-37
9-1 SUMMARY OF CHANGE IN PRODUCT COST AND RETURN ON ASSETS FOR
MODEL PLANTS AND FIRMS IN SELECTED INDUSTRIES 9-4
10-1 COST AND COST EFFECTIVENESS OF S09 CONTROL FOR CONVENTIONAL
AND COGENERATION COAL-FIRED STEAM^GENERATING UNITS IN
REGION V 10-6
10-2 COST AND COST EFFECTIVENESS OF S09 CONTROL FOR CONVENTIONAL
AND COGENERATION COAL-FIRED STEAM^GENERATING UNITS IN
REGION VIII 10-7
10-3 INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR COAL-FIRED COGENERATION UNITS 10-8
10-4 COSTS AND COST EFFECTIVENESS OF SO, CONTROL FOR CONVENTIONAL
AND COGENERATION OIL-FIRED STEAM GENERATING UNITS 10-10
10-5 INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR OIL-FIRED COGENERATION UNITS 10-11
10-6 COST AND COST EFFECTIVENESS OF S09 CONTROL FOR CONVENTIONAL
AND COMBINED CYCLE STEAM GENERATING UNITS IN REGION V -
FULLY-FIRED COAL 10-15
10-7 COST AND COST EFFECTIVENESS OF S09 CONTROL FOR CONVENTIONAL
AND COMBINED CYCLE STEAM GENERATING UNITS IN REGION VIII -
FULLY-FIRED COAL 10-16
10-8 INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR COMBINED CYCLE UNITS - FULLY-FIRED COAL 10-17
10-9 COST AND COST EFFECTIVENESS OF SO, CONTROL FOR CONVENTIONAL •
AND COMBINED CYCLE OIL-FIRED STEAM GENERATING UNITS 10-19
10-10 INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR OIL-FIRED COMBINED CYCLE STEAM GENERATING UNITS 10-22
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LIST OF TABLES (CONTINUED)
Table Page
10-11 COST AND COST EFFECTIVENESS OF S0? CONTROL FOR MIXED
FUEL-FIRED STEAM GENERATING UNITS^FIRING COAL 10-25
10-12 COST AND COST EFFECTIVENESS OF SO. CONTROL FOR MIXED
FUEL-FIRED STEAM GENERATING UNITS^FIRING OIL 10-26
10-13 INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR MIXED FUEL-FIRED STEAM GENERATING UNITS
FIRING COAL 10-28
10-14 INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR MIXED FUEL-FIRED STEAM GENERATING UNITS
FIRING OIL 10-30
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LIST OF FIGURES
Figure Page
5-1 Typical SCL emissions data for low sulfur coal
combustion 5-2
5-2 Impact of averaging period on SCL emissions data
variability 5-4
5-3 Map showing sulfur isolines for "E" seam of Helvetia
No. 6 reserves... 5-7
5-4 Coal lot size versus SCL emissions variability for
utility and industrial-commercial-institutional steam
generating units 5-17
6-1 Cost effectiveness of SCL control for coal-fired and
mixed fuel-fired steam generating units 6-71
8-1 Annualized costs and SCL emission reductions for
regulatory alternatives 8-17
xi i
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1.0 INTRODUCTION
This document summarizes the results of various analyses performed in
support of proposed new source performance standards limiting emissions of
sulfur dioxide and particulate matter from industrial-commercial-
institutional steam generating units with heat input capacities greater than
2.9 MW (100 million Btu/hour). It is intended to serve as an overview of the
analyses and regulatory alternatives considered in developing the proposed
standards and, as such, includes only the highlights of the many regulatory,
technical, and economic analyses considered during the decision-making
process. These analyses are supported and discussed in detail by various
other documents and reports contained in the docket for this rulemaking
(Docket No. A-83-27). This includes, but is not limited to, the following:
1. Fossil Fuel-Fired Industrial Boilers - Background Information,
Volumes 1 and 2 (EPA-450/3-82-006a and b), March 1982;
2. Nonfossil Fuel-fired Industrial Boilers - Background Information
(EPA-450/3-82-007), March 1982;
3. Industrial Boiler S02 Technology Update Report (EPA-450/3-85-009),
July 1984;
4. Fluidized Bed Combustion: Effectiveness as an S02 Control
Technology for Industrial Boilers (EPA-450/3-85-010),
September 1984;
5. Industrial Boiler S02 Cost Report (EPA-450/3-85-011), November
1984;
6. Projected Impacts of Alternative Sulfur Dioxide New Source
Performance Standards for Industrial Fossil Fuel-Fired Boilers,
March 1985;
1-1
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P.16
7. An Analysis of the Costs and Cost Effectiveness of SCL Control for
Mixed Fuel-Fired Steam Generating Units (EPA-450/3-86-001),
January 1986;
8. An Analysis of the Costs and Cost Effectiveness of Allowing SCL
Emission Credits for Cogeneration Systems (EPA-450/3-85-030),
December 1985.
1-2
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2.0 SELECTION OF SOURCE CATEGORY
On August 21, 1979, a priority list for development of additional new
source performance standards (NSPS) was published in accordance with
Sections lll(b)(l)(A) and lll(f)(l) of the Clean Air Act. This list
identified 59 major stationary source categories that were judged to
contribute significantly to air pollution that could reasonably be expected
to endanger public health or welfare. Fossil fuel-fired industrial steam
generating units ranked eleventh on this priority list of sources for which
new source performance standards would be established in the future.
Of the 10 sources ranked above fossil fuel-fired industrial steam
generating units on the priority list, nine were major sources of volatile
organic compound (VOC) emissions. Because there are many areas which have
not attained the national ambient air quality standard for ozone, major
sources of VOC emissions were accorded a very high priority. The remaining
source category ranked above fossil fuel-fired industrial steam generating
units was stationary internal combustion engines, a major source of nitrogen
oxides (NO ) emissions. Fossil fuel-fired industrial steam generating units
A
were the highest ranked source of particulate matter and sulfur dioxide
(S09) emissions, and the second highest ranked source of NO emissions when
C. A
the priority list of source categories not previously regulated by NSPS was
published.
Wood and solid waste are widely used as fuel in industrial steam
generating units. As a result, industrial-commercial-institutional steam
generating units firing these fuels could also be significant contributors
to future air pollution. In addition, large commercial and institutional
steam generating units have essentially the same design, fuel capability,
and emissions potential as industrial steam generating units. Consequently,
on June 19, 1984, an amendment to the priority list was proposed that would
expand the source category of industrial fossil fuel-fired steam generating
units to cover all steam generating units, including both fossil fuel-fired
and nonfossil fuel-fired steam generating units, as well as steam generating
units used in commercial and institutional applications (49 FR 25156,
2-1
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June 19, 1984). Consistent with this proposed amendment of the priority
list, the source category for the proposed standards includes both fossil
fuel- and nonfossil fuel-fired industrial, commercial and institutional
steam generating units.
Fossil and nonfossil fuel-fired steam generating units are significant
sources of emissions of three major pollutants: particulate matter, S(L, and
NO . The expected construction of new coal-, oil-, and fossil/nonfossil
/\
fuel-fired steam generating units as a result of plant expansions and
replacements of existing steam generating units is expected to result in a
growth in emissions from this source category. A number of these new
facilities will fire coal and high sulfur oil. Combustion of wood and solid
waste in combination with coal or oil is also projected to increase due to
the lower cost of these nonfossil fuels. These developments could result in
significant increases in S02 emissions if standards of performance are not
established for new industrial-commercial-institutional steam generating
units.
National ambient air quality standards have been established for SCL
because of its known adverse effects on public health and welfare. Impacts
of this pollutant have been documented in a criteria document prepared under
Section 108 of the Clean Air Act. These effects are a major basis for
concluding that emissions from industrial-commercial-institutional steam
generating units constitute a potential danger to public health and welfare.
Also significant is the fact that many new industrial-commercial-
institutional steam generating units will be located in urban areas where a
large population will be exposed to the emissions.
2-2
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P.19
3.0 SELECTION OF POLLUTANTS, FUELS, AND AFFECTED FACILITIES
Particulate matter emissions from the combustion of oil, and sulfur
dioxide (SOp) emissions from the combustion of oil, coal and mixed fuels
(i.e., combustion of mixtures of fossil fuels or fossil and nonfossil fuels)
would be the pollutants regulated under the proposed standards. New source
performance standards have already been proposed that would limit
particulate matter emissions from industrial-commercial-institutional steam
generating units firing coal, wood, or solid waste and NO emissions from
A
steam generating units firing mixtures of fossil or fossil and nonfossil
fuels (49 FR 25102, June 19, 1984).
The potential impacts associated with this "phased" approach to
rulemaking were considered prior to proposing standards for particulate
matter and NO . The standards being proposed today are not retroactive and
/\
affect only new steam generating units built after this date. No potential
problems have been identified that might result from this phased approach to
rulemaking and no unreasonable impacts are anticipated to occur.
The proposed standards would limit emissions of S02 from steam
generating units firing oil, coal, and fuel mixtures containing any of these
fuels and emissions of particulate matter from oil-fired steam generating
units. The proposed standards would cover industrial-commercial-
institutional steam generating units with heat input capacities greater than
29 MW (100 million Btu/hour). Analyses of the projected new steam
generating unit population indicate that nearly all new steam generating
units larger than 29 MW (100 million Btu/hour) heat input capacity will be
industrial steam generating units, with only a few commercial and
institutional steam generating units in this size range. The steam
generating unit size limit of 29 MW (100 million Btu/hour) heat input
capacity would, therefore, include only the largest commercial and
institutional steam generating units and would concentrate the scope of the
proposed standards on industrial steam generating units. Utility steam
generating units larger than 73 MW (250 million Btu/hour) heat input
capacity remain subject to Subpart Da. Utility auxiliary steam generating
3-1
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P.20
units smaller than 73 MW (250 million Btu/hour) heat input capacity but
larger than 29 MW (100 million Btu/hour) heat input capacity would be
subject to the proposed standards.
Development of new source performance standards limiting emissions of
sulfur oxides, nitrogen oxides, and particulate matter from steam generating
units with heat input capacities of 29 MW (100 million Btu/hour) or less is
currently underway. The type of unit used, the physical design
characteristics of these units, the cost impacts of emission control systems
on steam production costs, and the application of steam are often different
for smaller steam generating units than for larger steam generating units.
Because these factors have been found to be materially different, separate
study of smaller steam generating units is appropriate. This will assure
that an adequate evaluation is conducted of the technical and economic
factors associated with applying emission controls to smaller steam
generating units.
3-2
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4.0 SELECTION OF DEMONSTRATED EMISSION CONTROL TECHNOLOGIES
4.1 SULFUR DIOXIDE EMISSIONS FROM COAL AND OIL COMBUSTION
Sulfur dioxide (SO,,) is formed in industrial-commercial-institutional
steam generating units by the oxidation of sulfur contained in the fuels.
Uncontrolled emissions of SOp depend primarily on the sulfur content of the
fuel. The type of firing mechanism, or the type of industrial-commercial-
institutional steam generating unit, does not affect S0? emissions.
However, variations in fuel properties other than sulfur content also affect
uncontrolled S0? emissions. The concentration of alkaline species in the
fuel ash, for example, affects the amount of sulfur retained in the fly ash
and the bottom ash formed during combustion. Oil, which has low ash and low
alkalinity, retains little, if any, fuel sulfur in the fly ash and bottom
ash. On the other hand, western subbituminous coals, which have a highly
alkaline ash, can retain up to 20 percent of the sulfur in fly ash and
bottom ash.
Approaches for reducing SO^ emissions from industrial-commercial-
institutional steam generating units can be divided into three categories:
low sulfur fuels, combustion modification techniques, and post-combustion or
flue gas desulfurization (FGD) techniques. Combustion of low sulfur fuel
reduces S0? emissions by reducing the amount of sulfur available for $02
formation during combustion. Combustion modification reduces S0~ emi$sions
by reacting S02 with an alkaline material (usually limestone) within the
combustion chamber as the SO^ is formed. Flue gas desulfurization reduces
SOp emissions by "scrubbing" or "washing" the combustion gases downstream
from the steam generating unit with aqueous solutions or slurries of
alkaline reagents.
Low sulfur fuels may be produced from high sulfur fuels or they may be
obtained from naturally occurring low sulfur coal or low sulfur oil
deposits. Methods of producing low sulfur fuels from high sulfur fuels
include coal gasification, coal liquefaction, physical coal cleaning, and
oil hydrodesulfurization.
4-1
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P.22
Coal gasification produces a low sulfur fuel by converting coal to a
gas, which can be cleaned and then fired in a steam generating unit. In
coal gasification, pretreated coal is reacted with a steam/air or a
steam/oxygen mixture at high temperatures and pressures. The resultant gas
is then treated to remove particulate matter, sulfur, and nitrogen. Part of
the sulfur is removed in a gas quenching and cooling section, but most of it
is removed in an acid gas removal (AGR) system. In applications where the
product gas is used as a chemical plant feedstock, AGR systems have been
used to reduce sulfur concentrations in the gas to one part per million or
less.
Despite its potential for producing a low sulfur fuel, few coal
gasifiers have been designed specifically for industrial-commercial -
institutional steam generating units. These gasifiers generally'do not
include an AGR section in the gas treatment step. As a result, the gas
produced contains only about 10 percent less sulfur than the original coal.
Since conversion of coal to gas results in a 10 to 25 percent decrease in
the heating value, the product gas from gasifiers without an AGR system
actually has a higher sulfur content, in terms of heat content, than the
original coal. In these applications, therefore, the use of coal.
gasification actually results in an increase in S0? emissions.
Coal gasification is not likely to achieve widespread application to
new industrial-commercial-institutional steam generating units in the near
future. These systems generally have not been economically competitive when
compared with the use of natural gas. As a result, coal gasification is not
considered a demonstrated control technology for the purpose of developing
new source performance standards limiting S0£ emissions from new, modified,
or reconstructed industrial-commercial-institutional steam generating units.
The major processes for coal liquefaction are Solvent Refined Coal-I
(SRC-I), Solvent Refined Coal-II (SRC-II), H-Coal, and the Exxon Donor
Solvent (EDS) process. All of these processes involve the direct conversion
of coal into liquid form through the addition of hydrogen to coal at
elevated temperatures and pressures.
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P-23
All of the coal liquefaction processes mentioned above reduce the
concentrations of nitrogen, ash, and sulfur in the liquid fuel produced from
the concentrations in the original coal. All except SRC-I produce fuels
that can be substituted for petroleum-based fuels in oil-fired steam
generating units. The SRC-I process produces a solid fuel that can only be
used in pulverized coal-fired steam generating units.
Several pilot-scale coal liquefaction plants have been built and
tested. However, to date no commercial coal liquefaction plants have been
constructed, nor are any planned or under construction. In view of the long
lead time associated with the design, construction, and startup of coal
liquefaction plants, it seems certain that these fuels will not be available
for use in industrial-commercial-institutional steam generating units in the
near future. As a result, coal liquefaction is not considered a
demonstrated control technology for the purpose of developing new source
performance standards limiting S(L emissions from new, modified, or
reconstructed industrial-commercial-institutional steam generating units.
Physical coal cleaning (PCC) reduces the sulfur content of coal while
increasing its heat content. In a modern PCC plant, coal is subjected to
size reduction and screening before it is washed, dewatered, and dried. The
coal is separated from its impurities primarily during the washing phase.
In this phase, the impurities separate from the coal because of the
differences in specific gravities and surface properties between the
"fuel-rich" organic matter and the "fuel-lean" mineral matter in the coal.
The extent of sulfur reduction in PCC depends primarily on the form of
the sulfur in the coal. Sulfate sulfur, which is present in most coals in
trace amounts, is usually water soluble and is readily removed by washing
the coal. Organic sulfur, on the other hand, is chemically bonded to the
organic carbon in the coal and cannot be removed by PCC. Pyritic sulfur,
which may comprise between 30 and 70 percent of the coal sulfur content, is
much denser than coal and is best removed by gravity separation. PCC can
typically remove about 50 percent of the pyritic sulfur in coal. Since PCC
increases the heat content of coal, the net sulfur removal on a heat content
4-3
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P.24
[nanograms SCL/Joule (ng/J) or Ib SCL/million Btu] basis is typically
between 20 and 40 percent.
Approximately one-third of the domestically produced bituminous and
lignite coal underwent PCC in 1978. PCC is readily applicable to these two
types of coal because they have relatively high pyritic sulfur contents.
Subbituminous coal, on the other hand, contains little pyritic sulfur and
has generally not been subjected to PCC.
Physical coal cleaning became attractive not so much for environmental
reasons, but for economic reasons. PCC produces a higher grade of coal,
having a higher heat content. This results in a reduction in transportation
costs, ash disposal costs, and steam generating unit maintenance costs.
Higher grades of coal can also improve steam generating unit efficiency and
reliability.
Physical coal cleaning is considered a demonstrated emission control
technology for reducing emissions of S02 from combustion of bituminous and
lignite coals. However, this technology requires too much space and is too
expensive to be employed at individual industrial-commercial-institutional
steam generating units. Consequently, this technology is not employed
directly by industrial-commercial-institutional steam generating units. Low
sulfur coal, however, may be purchased from PCC plants supplying utility
steam generating units. As a result, while the use of PCC is included in
the analyses below, it is only included indirectly in the sense that, where
appropriate, the cost of low sulfur coal includes the costs of PCC to
produce that coal.
Hydrotreating or hydrodesulfurization (HDS) processes can substantially
reduce the concentrations of sulfur, nitrogen, and ash in fuel oils. HDS
processes involve contacting the oil with hydrogen over a catalyst to
convert much of the chemically bonded sulfur to gaseous hydrogen sulfide
(HpS). The waste gas is then separated from the fuel and the sulfur is
reclaimed as elemental sulfur or sulfuric acid.
HDS technology has been in commercial use for approximately 20 years.
As of 1975, over 30 HDS processes were actively in use, and over 250
processes had been described in patent literature. Not only is HDS
4-4
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P.25
effective in reducing SCL emissions from oil combustion in steam generating
units, but it also improves the performance of steam generating units by
reducing the potential for corrosion and particulate matter deposit.
HDS is considered a demonstrated emission control technology for
reducing emissions of SCL from oil combustion. As with PCC, however, HDS
requires too much space and is much too costly to be employed at individual
industrial-commercial-institutional steam generating units. Hydrodesulfur-
ization is employed by petroleum refineries to produce low sulfur fuel oil.
As with PCC, this technology is also included indirectly in the analyses
below, in the sense that, where appropriate, the cost of low sulfur fuel oil
includes the costs of HDS to produce that oil.
4.1.1 Low Sulfur Coal
Fuels may be broadly classified by any number of schemes. However,
from the standpoint of S(L emissions, it is useful to classify fuels with
respect to their sulfur content.
The coal classification scheme that has been adopted to represent coals
that are combusted in steam generating units is presented in Table 4-1, with
each coal type represented by a range of sulfur content. This
classification scheme has its origin in classifications used by the U. S.
Bureau of Mines to report available coal reserves. In a subsequent series
of studies based on Bureau of Mines data, the classification scheme evolved
to reflect existing coal reserves and supplies more accurately. For
example, the number of classifications was reduced and the range of sulfur
content for each coal type was adjusted, resulting in the classification
scheme presented in Table 4-1.
The sulfur contents of the low sulfur coal types generally represent
coals that can meet the existing new source performance standards (40 CFR
Part 60, Subpart D) that apply to steam generating units with a heat input
capacity greater than 73 MW (250 million Btu/hour). The sulfur contents of
the medium sulfur coal types generally represent coals that meet SOp
emission limits in many existing State Implementation Plans (SIP's).
4-5
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TABLE 4-1. FUEL SULFUR CONTENT AND S0£ EMISSION RATES FOR COAL AND OIL TYPES
Midpoint Fuel Midpoint S0?
Fuel Type Fuel Sulfur Content Sulfur Content Emission Rate
ng S/J (Ib S/million Btu) ng S/J (Ib S/million Btu) ng S02/J (Ib S02/million Btu)
COAL:
Very Low Sulfur <172.0 (<0.40) 86 (0.20) 172 (0.40)
Low Sulfur 172-232 (0.40-0.54) 202 (0.47) 404 (0.94)
Low Sulfur 232-357 (0.54-0.83) 295 (0.69) 590 (1.37)
Medium Sulfur 357-538 (0.83-1.25) 447 (1.04) 894 (2.08)
Medium Sulfur 538-718 (1.25-1.67) 628 (1.46) 1,254 (2.92)
High Sulfur 718-1,075 (1.67-2.50) 897 (2.09) 1,793 (4.17)
High Sulfur >1,075.0 (>2.50) 1,075 (2.50) 2,150 (5.00)
OIL:
Very Low Sulfur 65 (0.15) 65 (0.15) 129 (0.3)
Low Sulfur 172 (0.40) 172 (0.40) 344 (0.8)
Medium Sulfur 344 (0.80) 344 (0.80) 688 (1.6)
High Sulfur 645 (1.50) 645 (1.50) 1,290 (3.0)
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P.27
Finally, the high sulfur coal types represent coals that must be processed
or blended with lower sulfur coals to meet current S(L emission limits.
This classification scheme can be simplified by using the midpoints of each
sulfur content range to represent the sulfur content of these coal types.
The midpoints for each coal type are also shown in Table 4-1.
Most of the sulfur contained in coal is converted to SOp during
combustion. However, 5 to 20 percent of the coal sulfur is typically
retained in bottom ash and fly ash. The degree of sulfur retention depends
on several factors, such as the type of steam generating unit and the
chemical properties of the coal, particularly the concentration of alkaline
constituents. Because sulfur retention is quite variable and dependent on a
number of factors, for this analysis it is assumed that 100 percent of the
sulfur present in coal is converted to SOp. Because sulfur dioxide (SOp)
has twice the mass of sulfur (S), the SOp emission rates presented in Table
4-1 for each coal type are double the coal sulfur content.
As shown by the emission rates in Table 4-1, low sulfur coal can be
used to reduce SOp emissions. Combustion of low sulfur coal reduces $0?
emissions by 30 to 50 percent compared to combustion of medium sulfur coal,
and by as much as 60 to 80 percent compared to combustion of high sulfur
coal.
Low sulfur coal is widely used in both industrial and utility steam
generating units to reduce SOp emissions from coal combustion. For example,
in 1982 the utility sector consumed 14,100,000 Mg (15,500,000 tons) of low
sulfur coal. Low sulfur coal, therefore, is considered demonstrated for the
purpose of developing new source performance standards limiting SOp
emissions from new, modified, and reconstructed industrial-commercial-
institutional steam generating units.
4.1.2 Low Sulfur Oil
As with coal, fuel oil can be classified by sulfur content. Table 4-1
presents the oil classification scheme that has been adopted to represent
oils that are combusted in industrial-commercial-institutional steam
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P.28
generating units. In this classification scheme, each type of oil is
represented by a typical sulfur content. This classification scheme had its
origin in the classifications used by the U. S. Department of Energy to
report refinery production data, and in studies of fuel oil use patterns.
The classifications reflect the fact that many distillate and residual
oils are produced to meet market demands created by existing SCL emission
regulations. Accordingly, low sulfur fuel oils represent those oils that
can be fired to meet the existing new source performance standards (40 CFR
Part 60, Subpart D) for steam generating units with a heat input capacity
greater than 73 MW (250 million Btu/hour). The sulfur content of medium
sulfur fuel oils represents oils that can be combusted to comply with SO^
emission limits included in many existing SIP's. The sulfur content of high
sulfur fuel oils represents oils that comply with S02 emission limits
included in the remaining SIP's.
Most of the sulfur contained in oil is converted to SO^ during
combustion, with only one to four percent of the sulfur typically retained
in the fly ash. The degree of sulfur retention depends on several factors,
including the oil type and its chemical composition, especially the
concentration of metal constituents. Because sulfur retention in fly ash is
relatively minimal and varies among fuel oils, 100 percent of the fuel
sulfur has been assumed to be converted to S0?. Consequently, the emission
rates represented in Table 4-1 for each oil type are twice the oil sulfur
content.
As shown by the emission rates in Table 4-1, low sulfur oil can be used
to reduce emissions of SOp. Combustion of low sulfur oil reduces SO^
emissions by 50 to 80 percent compared to combustion of medium sulfur oil,
and by 70 to 90 percent compared to combustion of high sulfur oil.
Low sulfur oil is widely used in industrial and utility steam
generating units to reduce S02 emissions from oil combustion. Low sulfur
oil, therefore, is considered demonstrated for the purpose of developing new
source performance standards limiting S0? emissions from new, modified, and
reconstructed industrial-commercial-institutional steam generating units.
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P.29
4.1.3 Combustion Modification
Combustion modification techniques for the control of S(L involve the
capture of S0? by an alkaline species, usually limestone, within the
combustion zone of the steam generating unit. The result is that the S0?
formed during combustion reacts with the alkaline species to form sulfite
and sulfate salts. These salts exit the steam generating unit with the flue
gas and are removed downstream by a particulate matter control device such
as a fabric filter, electrostatic precipitator, or mechanical collector.
Several combustion modification techniques are currently under development,
including coal/limestone pellets, limestone injection multistaged burners,
and fluidized bed combustion.
Coal/limestone pellet (CLP) technology is a combustion modification
technique in which pellets formed from coal and limestone are burned
together in stoker coal-fired steam generating units. Coal/limestone
pellets can be manufactured on-site by pellet milling, briquette production,
auger extrusion, or disk production. The SCL formed during combustion
reacts with the limestone present in the fuel pellets to form calcium
sulfite and sulfate salts. A major portion of these sulfite and sulfate
salts remains in the ash and is removed from the steam generating unit along
with the bottom ash. The remaining sulfite and sulfate salts accompany the
fly ash in the flue gas and are removed by a particulate matter control
device.
The calcium-to-sulfur (Ca/S) ratio in the CLP is the primary factor
affecting sulfur capture during combustion. Tests using pellets with a Ca/S
ratio of seven-to-one have yielded SCL removal efficiencies as high as 70
percent. This technology is not being used commercially at this time,
however, and future applications are expected to be limited because of the
adverse effects that CLP's can have on the operation of a steam generating
unit. The use of CLP's, for example, is expected to reduce the rated
capacity of a steam generating unit by about 20 percent. Furthermore, the
increase in bottom ash could decrease the reliability of the steam
/•
generating unit and increase its maintenance costs. Consequently, the CLP
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P.30
technology must be considered an emerging technology and cannot be
considered demonstrated for the purpose of developing new source performance
standards limiting SCL emissions from new, modified, and reconstructed
industrial-commercial-institutional steam generating units.
The limestone injection multistaged burner (LIMB) technology is a
combustion modification technology that is capable of reducing SCL emissions
from pulverized coal-fired steam generating units. In this process, dry,
finely ground sorbent (such as dolomite) is injected into the furnace
through burners or through separate injection ports installed in the furnace
wall. The limestone reacts with SCL formed during combustion to form
calcium sulfite and sulfate salts, which are entrained in the flue gas and
collected along with the fly ash in a downstream particulate matter control
device.
The primary factors affecting sulfur capture are the reactivity of'the
sorbent (as measured by surface area), the Ca/S ratio during combustion, the
sorbent injection technique, and the residence time of the sorbent in that
part of the steam generating unit where reaction with SCL can occur.
Initial tests of the LIMB technology on small scale equipment have been
promising, achieving more than a 70-:Jp'ercertt reduction in SCL emissions when
highly reactive sorbents are used.
No long-term commercial data are available, however, on the performance
or economics of LIMB as applied to industrial-commercial-institutional steam
generating units. LIMB, therefore, must be considered an emerging control
technology and not demonstrated for the purpose of developing new source
performance standards limiting S(L emissions from new, modified, and
reconstructed industrial-commercial-institutional steam generating units.
Fluidized bed combustion (FBC) is a third type of combustion
modification technology. In conventional steam generating units, fuel is
combusted either on a grate or in suspension and a significant portion of
the heat exchange takes place outside of this combustion zone. In fluidized
bed systems, fuel is combusted in a fluidized bed maintained by a stream of
air blowing upwards from a distribution plate. This design permits the
watertubes in which steam is generated to be submerged in the fluidized bed
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P.31
or combustion zone of burning fuel. Submersion of the watertubes directly
into the combustion zone improves heat transfer. FBC systems can be
operated at much lower temperatures to achieve the same steam quality as
conventional steam generating units operating at higher temperatures. This
enables FBC systems to burn lower quality fuels than are typically burned in
conventional steam generating units and still generate the same steam
quality. It also permits limestone to be added to the fluidized bed to
capture SCL without impairing combustion performance.
At the combustion temperatures achieved by FBC systems, 760°C to 870°C
(1,400°F to 1,600°F), limestone releases carbon dioxide and is transformed
into lime. Lime then reacts with SCL and excess oxygen to form anhydrous
calcium sulfate. The calcium sulfate, ash, and unreacted lime are removed
from the system through a drain as overflow from the fluidized bed. Those
solids that are entrained in the combustion gases are removed in a
particulate matter control device.
Sulfur dioxide removal efficiencies depend primarily on the Ca/S ratio
in the combustion zone. Sulfur dioxide removal efficiency will also be
improved by recycling part of the elutriated lime and limestone, decreasing
the limestone particle size, using limestone which is highly reactive, using
coals with high ash alkalinity, and increasing the amount of time that lime
and SCL are allowed to react.
The SCL removal efficiency increases as the Ca/S ratio increases. The
recycle of elutriated bed material can have a significant effect on SCL
removal at a given Ca/S ratio because the recycled material typically
contains unreacted sorbent. Increasing the solids recycle ratio increases
SCL removal efficiency at a given Ca/S ratio or lowers the Ca/S ratio
necessary to achieve a given percent SCL reduction. Circulating bed FBC
units, which feature a recirculating entrained bed, are an extension of the
solids recycle approach. Use of a coal that has a highly alkaline ash has
the effect of reducing the amount of limestone necessary to maintain a
constant Ca/S ratio or raising the Ca/S ratio if the amount of limestone is
held constant.
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P.32
Increasing the gas-phase residence time (the ratio of expanded bed
height to the superficial gas velocity) improves SOp removal efficiency.
This is because the time available for calcination and sulfation reactions
within the bed increases. However, some coal is combusted above the bed due
to elutriation of smaller coal particles. Thus, SOp is also formed above
the bed. As calcined limestone particles are also elutriated, SOp removal
can still occur if sufficient time for gas and sorbent contact is available.
One way to increase the gas and sorbent contact time, and therefore percent
SOp removal, is to increase the freeboard height. While this may be
infeasible for retrofit applications, new FBC units could be designed with
higher freeboard.
As the particle size of a given sorbent decreases, the calcium
utilization increases. Thus, with the same Ca/S ratio, the SOp removal
efficiency can be increased significantly by decreasing the sorbent particle
size. However, the particles should not be sized so small that they are
elutriated from the steam generating unit before adequate reaction time is
achieved.
The FBC technology is well developed and widely applied throughout the
world. In the United States, approximately 80 FBC systems are currently
operating or scheduled to begin operation in the near future. Most of the
FBC systems in the United States have been installed to recover the fuel
value of process wastes which do not contain significant quantities of
sulfur. About 20 existing or planned FBC systems in the United States are
designed to burn coal or mixtures of coal and other fuels. Nearly all of
these FBC systems use limestone for SOp control. Existing and planned
coal-fired FBC systems encompass steam generating unit sizes of from 7 to
53 MW (25 to 180 million Btu/hour) heat input capacity and fire coals
ranging in sulfur content from about 430 to 3,010 ng SOp/J (1.0 to 7.0 Ib
S02/million Btu).
The FBC systems described above are currently achieving average S0?
removal efficiencies ranging from 55 to 90 percent. They are capable of
higher efficiencies, but in order to minimize costs, these systems are
currently operated at the lowest SOp removal efficiencies required by
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P-33
existing air pollution control regulations. Emission test data have shown
that, with sufficiently high Ca/S ratios, FBC units can achieve S(L removal
efficiencies of 90 percent or more. Consequently, FBC is considered
demonstrated for the purpose of developing new source performance standards
limiting SCL emissions from new, modified, and reconstructed industrial-
commercial-institutional steam generating units.
4.1.4 Post-Combustion Technologies
Post-combustion technologies remove SCL from steam generating unit flue
gases by "scrubbing" them with an alkaline reagent. These technologies are
more commonly labeled flue gas desulfurization (F6D) technologies and can be
divided into two broad groups: dry scrubbing and wet scrubbing. In dry
scrubbing, SCL is absorbed by and reacts with an alkaline material to
produce a dry particulate powder consisting of sulfite and sulfate salts
that is then removed from the scrubber flue gas by a particulate matter
control device. In wet scrubbing, S02 is absorbed by and reacts with
alkaline reagents in either an aqueous solution or slurry. In sodium-abased
wet scrubbing systems, the sulfur is discharged as dissolved sodium sulfite
and sulfate in a wastewater stream. In calcium-based wet scrubbing systems,
the sulfur is discharged as a calcium sulfite and sulfate sludge.
Dry scrubbing processes include electron beam irradiation, dry alkali
injection, and lime spray drying. In the electron beam irradiation process,
the combustion flue gases are first cooled and humidified in a water quench
tower. Ammonia is then injected into the cooled flue gas and the resulting
mixture is passed through an electron beam reactor. In the reactor, the
flue gas is irradiated with an electron beam that ionizes oxygen and water.
The hydrogen and oxygen radicals that are formed react with SCL to produce
sulfuric acid. The acid is then neutralized by the ammonia and water in the
flue gas to form solid ammonium sulfate which is then collected in a
particulate matter control device such as an electrostatic precipitator or
fabric filter.
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P.34
At present, there are no commercial applications of electron beam
irradiation for removing SCL from steam generating unit flue gases.
Research projects are underway in the United States and in Japan to
investigate the technology's effectiveness in controlling S0? emissions.
Since the electron beam irradiation process is in the very early stages of
development, it is not considered demonstrated for the purpose of developing
new source performance standards limiting SCL emissions from new, modified,
and reconstructed industrial-commercial-institutional steam generating
units.
In the dry alkali injection process, a dry alkaline material is
injected into the combustion flue gases as they leave the steam generating
unit. This alkaline material is usually a naturally occurring sodium
compound such as nacholite or trona ore. The sodium reacts with S0? to form
solid sodium sulfate particles that are collected along with the fly ash in
a particulate matter control device. Although both electrostatic
precipitators and fabric filters have been used in dry alkali injection
processes, fabric filters are preferred because of the continuation of the
reaction between the SCL in the flue gas and the dry alkali reagent in the
filter cake deposited on the fabric filter surface.
The primary factors which affect the performance/of dry alkali
injection systems are the amount of alkaline reagent added, the temperature
at the point of injection, and the size of the alkaline reagent particles.
The removal of SOp increases as the ratio of alkaline reagent to flue gas
S02 increases. In limited tests, a dry alkaline injection system applied to
a 22 MW electric output utility steam generating unit combusting a low
sulfur coal achieved SCL removal efficiencies of 70 and 80 percent with
nacholite, at alkaline reagent-to-flue gas sulfur ratios of approximately
0.8 and 1.1, respectively. With trona ore, the same system achieved SO^
removal efficiencies of 70 and 90 percent at reagent-to-flue gas sulfur
ratios of 1.3 and 2.4, respectively.
In addition to the tests conducted on this electric utility
demonstration unit, numerous other pilot and laboratory scale studies have
been conducted on dry alkali injection with similar results. Because the
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P-35
technology is simple in both design and operation, it is expected to be
highly reliable. However, dry alkali injection has not yet been
commercially applied to industrial-commercial-institutional steam generating
units, primarily due to the high cost and limited availability of nacholite
and trona ore. As a result, dry alkali injection is not considered
demonstrated for the purpose of developing new source performance standards
limiting SO^ emissions from new, modified, and reconstructed industrial-
commercial-institutional steam generating units.
Lime spray drying is a dry scrubbing technology in which the flue gases
from a steam generating unit are sprayed with a finely atomized lime slurry
in a spray dryer. Although sodium carbonate can be used instead of lime, it
is not currently being used in commercial applications because it is much
more expensive.
In lime spray drying systems, flue gas SCL is absorbed by and reacts
with the fine mist of slurried lime in the spray dryer to form calcium
sulfite and sulfate salts. At the same time, the hot flue gas evaporates
the water contained in the slurry to produce a dry powder. The powder
generally has a moisture content of less than one percent. Absorption,
reaction, and drying occur within the ten-second gas residence time in the
spray dryer. The evaporation of water from the slurry mist cools the
combustion flue gases to within 10 to 20°C (20 to 40°F) of their saturation
temperatures. The flue gas from the spray dryer, along with its entrained
solids (consisting of sulfite and sulfate salts, unreacted reagent, and fly
ash), passes into a particulate matter collection device such as an
electrostatic precipitator or fabric filter. The collected solids are then
typically transported to a solid waste disposal site.
The key factors affecting the S02 removal efficiency of lime spray
drying are reagent ratio, approach to saturation temperature, and the type
of particulate matter control device used. Other factors include solids
recycling and the temperature of the combustion flue gases entering the
spray dryer.
The S02 removal efficiency increases with increasing reagent ratio
(defined as the ratio of calcium-to-sulfur present in the combustion flue
4-15
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gases). However, recycling a portion of the solids collected by the
participate matter control device to the spray dryer can recover unreacted
reagent and thus lower the lime reagent ratio required to achieve a given
SCL removal efficiency.
The approach to saturation temperature is the difference between the
actual temperature of the flue gas leaving the spray dryer and the
temperature that is observed if the flue gas is cooled to the point at which
it is saturated with water. Operating closer to the saturation temperature
allows more lime slurry to be sprayed into the dryer and delays the drying
of the lime slurry droplets, increasing the amount of S0? absorption and
reaction. There is a practical limit, however, to how closely the spray
dryer flue gas can approach the saturation temperature without condensation
occurring in the downstream flue gas ducts and in the particulate matter
control device. Condensation can result in caking of fabric filters and
corrosion of metal surfaces. As a result, the approach to saturation
temperature for lime spray drying systems typically ranges from 10 to 28°C
(20 to 50°F). Operation at or near a 10°C (20°F) approach to saturation
temperature is common where S02 removal requirements are high. It should be
noted, however, that increasing the temperature of the combustion flue gases
entering the spray dryer, by removing less heat from those gases in the
convection section of the steam generating unit, will improve S02 removal
efficiency by allowing more lime slurry to be sprayed into the dryer without
operating any closer to the flue gas saturation temperature.
The performance of lime spray,drying systems can also be affected by
the type of particulate matter collection device that is used. In most
commercial lime spray drying systems, fabric filters have been chosen over
electrostatic precipitators. With fabric filters, the flue gas passing
through the unreacted lime in the filter cake that builds up on the filter
fabric reacts with the remaining S02 in the flue gas, increasing overall S02
removal. Studies have shown that SOp removal in the fabric filter can
account for as much as 15 to 30 percent of the total S02 removal.
To date, 21 lime spray drying systems have been sold for application to
coal-fired industrial-commercial-institutional steam generating units
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P37
ranging in size from 30 to 150 MW (100 to 530 million Btu/hour) heat input
capacity. The sulfur content of the coal combusted in these units ranges
from 600 to 2,600 ng S02/J (1.5 to 6.0 15 S02/million Btu).
The lime spray drying systems described above are currently achieving
S02 removal efficiencies in the range of 60 to 80 percent. They are capable
of much higher efficiencies, but in order to minimize costs, these systems
are currently operated at the lowest SOp removal efficiencies required by
existing air pollution control regulations. However, most of these systems
have been designed and guaranteed by their vendors to achieve a 90 percent
reduction in S02 emissions, and short-term tests have substantiated their
claims. Because lime spray drying has been operated successfully and has
been shown and guaranteed to be capable of achieving high S02 removal
efficiencies, it is considered demonstrated for the purpose of developing
new source performance standards limiting S0? emissions from new, modified,
and reconstructed industrial-commercial-institutional steam generating
units.
Wet scrubbing processes include lime, limestone, dual alkali, and
sodium wet scrubbing. Wet scrubbing techniques use alkaline solutions or
slurries that are more dilute than those used in dry scrubbing. In
addition, wet scrubbing techniques produce a liquid waste byproduct while
dry scrubbing techniques produce a dry powder or solid waste byproduct. In
lime, limestone, and dual alkali systems, the liquid waste byproduct is
converted to a sludge for disposal. In sodium scrubbing, the liquid waste
byproduct is generally treated and discharged directly to surface waters or
discharged to publicly owned treatment works for disposal.
Lime and limestone wet scrubbing technologies use very similar
processes for controlling S02. Lime wet scrubbing systems use calcium oxide
(lime) in an aqueous slurry to remove S02 from the flue gas, whereas
limestone systems use a calcium carbonate (limestone) slurry. 'In both
systems, S02 is absorbed into the slurry where it reacts with the calcium
reagents to form calcium sulfite and calcium sulfate. These components are
less soluble in water than lime or limestone and precipitate out of
solution, thus increasing the suspended solids concentration of the slurry.
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P.38
From the scrubber, the slurry flows to a holding tank where make-up lime or
limestone and water are added. Most of the slurry is pumped back to the
scrubber for further absorption of SCL. A fraction of the slurry, however,
is pumped from the holding tank to a solids concentrating section where it
is dewatered and converted to a sludge that is approximately half calcium
solids and half water. The liquid removed by dewatering in the solids
concentrating section is pumped back to the holding tank. The sludge is
disposed of in a solid waste disposal facility.
In both lime and limestone wet scrubbing systems, there are four system
parameters that have a major influence on SCL removal efficiency. These
parameters are the scrubber liquid-to-flue gas ratio (L/G), the contact area
in the scrubber, the calcium-to-sulfur ratio (Ca/S), and the pH. Increasing
any one or all of these parameters will improve the SCL removal efficiency
of the scrubber. Since limestone is less soluble in water and less reactive
than lime, all of these parameters, except pH, must collectively be higher
for limestone wet scrubbing systems than for lime wet scrubbing systems.
The pH of limestone systems will be lower than the pH in lime systems
because of the natural carbonate/bicarbonate buffer. Recently, the use of
mass transfer additives such as adipic acid and dibasic acid has been shown
to improve the performance of limestone wet scrubbing systems dramatically,
thus enabling them to operate with L/G ratios, Ca/S ratios, and contact
areas similar to those of lime wet scrubbing systems. When the system
parameters listed above are properly controlled, both lime wet scrubbing
systems and limestone wet scrubbing systems with mass transfer additives can
achieve short-term SO,, removal efficiencies in excess of 90 percent.
Lime and limestone wet scrubbing systems together comprise over 70
percent of the flue gas desulfurization systems installed on electric
utility steam generating units in the United States. However, only one lime
wet scrubbing system and one limestone wet scrubbing system are currently
treating the combustion flue gases of industrial-commercial-institutional
steam generating units. The lime wet scrubbing system began operation in
1978. The steam generating unit has a heat input capacity of 73 MW (250
million Btu/hour) and combusts a coal with a sulfur content of 2,925 ng
4-18
-------
P.39
S02/J (6.8 Ib S02/million Btu) heat input. At least part of the reason for
installing this lime wet scrubbing system was to use the lime slurry waste
byproduct to neutralize and precipitate metal ions out of wastewater streams
generated by other processes within the plant.
The limestone wet scrubbing system began operation in 1976. The steam
generating unit has a heat input capacity of 40 MW (130 million Btu/hour)
and combusts a coal with a sulfur content of 2,880 ng S02/J (6.7 Ib
S02/million Btu) heat input. However, this system operates only 6 months
out of the year because the steam generating unit is used only during the
winter months for space heating.
Due to the greater ease of operation of other wet scrubbing
technologies, such as dual alkali and sodium wet scrubbing, lime and
limestone wet scrubbing systems have not been widely applied to industrial-
commercial-institutional steam generating units. However, lime wet
scrubbing and limestone wet scrubbing systems using mass transfer additives
have been successfully applied to numerous utility steam generating units to
achieve high S02 removal efficiencies. Because the mechanisms for
controlling S02 emissions from utility steam generating units are
essentially the same as for industrial-commercial-institutional steam
generating units, these two control technologies are considered demonstrated
for the purpose of developing new source performance standards limiting SOp
emissions from new, modified, and reconstructed industrial-commercial-
institutional steam generating units.
Dual alkali wet scrubbing systems, like lime and limestone wet
scrubbing systems, produce a waste sludge composed of calcium sulfite and
sulfate salts. However, unlike lime and limestone wet scrubbing systems,
dual alkali systems use aqueous solutions of sodium hydroxide or sodium
carbonate to absorb SOp.
In dual alkali wet scrubbing, the combustion flue gases are contacted
with an aqueous solution of sodium hydroxide or sodium carbonate in an
absorber or scrubber. The S02 contained in the flue gases is absorbed in
the liquid. The liquid flows from the scrubber to a holding tank where
make-up water and sodium hydroxide or sodium carbonate are added. Most of
4-19
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P.40
the liquid in the holding tank is recycled to the scrubber, while a small
fraction of it is diverted to a lime reaction tank. Lime is added to the
liquid and reacts with the sodium sulfites and sulfates in solution to
produce calcium sulfite and sulfate, which precipitate from the liquid. The
precipitate is separated from the liquid and concentrated to a sludge using
the same dewatering techniques that are used in lime and limestone wet
scrubbing systems. Liquid from the lime reaction tank, along with liquid
from the dewatering processes, is recycled to the holding tank for
recirculation to the scrubber.
As with the lime and limestone wet scrubbing systems, scrubber
liquid-to-gas ratio, scrubber contact area, reagent-to-sulfur ratios [in
this case sodium-to-sulfur (Na/S) rather than calcium-to-sulfur (Ca/S)], and
pH are important factors affecting S(L removal efficiency. As each of these
factors is increased, the S(L removal efficiency will also be increased.
However, the scrubber liquid-to-gas ratio and scrubber contact area are not
as important as the Na/S ratio in dual alkali scrubbing because sodium
alkaline reagents are much more soluble in water than calcium alkaline
reagents. At sufficiently high Na/S ratios (between 1.6 and 2.0), SCL
removal efficiencies in excess of 90 percent are achievable over a
relatively wide range of liquid-to-gas ratios and scrubber contact areas.
Since 1974, 13 dual alkali wet scrubbing systems have been installed on
industrial-commercial-institutional steam generating units. The sizes of
these units range from 10 to 400 MW (40 to 1,400 million Btu/hour) heat
input capacity. All but one of these dual alkali wet scrubbing systems have
been installed on coal-fired steam generating units, and the range of fuel
sulfur content has been from 350 to 1,300 ng S02/J (1.6 to 6.0 Ib
SO^/million Btu). Consequently, dual alkali wet scrubbing is considered
demonstrated for the purpose of developing new source performance standards
limiting S02 emissions from new, modified, and reconstructed
industrial-commercial-institutional steam generating units.
Sodium scrubbing, like dual alkali scrubbing, removes S0? from the flue
gases by absorbing the SOp in aqueous solutions of sodium hydroxide or
sodium carbonate. As with dual alkali systems, the liquid from the scrubber
4-20
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P.41
is mixed in a holding tank with water and make-up sodium reagent and most of
the liquid is recycled to the scrubber. A portion of the liquid, however,
is removed from the holding tank for disposal as wastewater.
In most areas, the wastewater byproduct from sodium wet scrubbing can
either be treated at the plant site or discharged to a publicly owned
treatment facility for treatment prior to discharge. The treatment and
disposal of wastewater to surface waters has been widely permitted pursuant
to Federal and State water quality regulations, and does not present an
obstacle to the use of this technology for S(L control. The character of
the waste stream can be rendered relatively inert through the simple
oxidation of all sulfur-bearing compounds to sulfate which eliminates the
potential chemical oxygen demand of the waste on the receiving waters*,
Similarly, these waste streams have been found in practice to be compatible
with the operation of publicly owned treatment works, and have been readily
accepted by those systems. In arid areas, the wastewater stream is usually
discharged to an evaporation pond. In California it is sometimes injected
with the steam used in thermally-enhanced oil recovery operations.
As with dual alkali systems, the major factor affecting SO^ removal
efficiency for sodium wet scrubbing systems is the Na/S ratio. Since sodium
is highly soluble in water, high alkalinities in the scrubbing liquor are
easily maintained and consistently high S(L removal efficiencies are
achievable. Removal efficiencies in excess of 90 percent are typical for
many currently operating sodium wet scrubbing systems.
There are over 500 sodium wet scrubbing systems currently in use on
industrial-commercial-institutional steam generating units. These systems
are primarily operating on oil-fired steam generating units, although there
are more than 10 sodium wet scrubbing systems operating on coal-fired units.
These steam generating units range in size from 5 to 230 MW (20 to
800 million Btu/hr) heat input capacity, and the range of fuel sulfur
content is 344 to 2,580 ng S02/J (0.8 to 6.0 Ib S02/million Btu) heat input.
Therefore, sodium wet scrubbing is considered demonstrated for the purpose
of developing standards of performance limiting SOp emissions from new,
4-21
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P.42
modified, and reconstructed industrial-commercial-institutional steam
generating units.
4.2. PARTICULATE MATTER EMISSIONS FROM OIL COMBUSTION
Particulate matter emissions from the combustion of fuel oils in
industrial-commercial-institutional steam generating units are composed of
ash, various sulfates, carbonaceous material and, occasionally, additives.
The ash component is comprised of non-combustible metals and salts
present in the fuel oil. Fuel oil ash content generally increases with
increasing sulfur content.
The sulfur component of the particulate matter is composed primarily of
various sulfate salts. They are the product of fuel sulfur interaction with
the combustion air, metals present in the fuel ash, and the internal
surfaces of the steam generating unit. The contribution of the sulfur
component to particulate matter emissions is proportional to the sulfur
content of the fuel oil.
The third major component of particulate matter emissions from fuel oil
combustion is carbonaceous compounds. These compounds are tar-like
substances resulting from incomplete fuel combustion. Although carbonaceous
compounds can be the most significant component of particulate matter from
oil under conditions of poor combustion, these compounds will be negligible
with good burner operation and maintenance.
An occasional component of particulate matter emissions is fuel
additives. These additives are anti-corrosion and anti-slagging compounds
that are blended into high sulfur, high ash residual fuel oils to protect
the steam generating unit from corrosion and slagging. Additives are not
commonly required with low sulfur, low ash fuel oils.
A variety of methods can be employed to reduce particulate matter
emissions from oil combustion in industrial-commercial-institutional steam
generating units. These methods can be grouped into pre-combustion control
(i.e., the use of low ash/low sulfur fuel oil) and post-combustion control
4-22
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P.43
(i.e., add-on equipment such as wet scrubbers and electrostatic
precipitators).
4.2.1 Low Sulfur Oil
Pre-combustion control, or the use of low sulfur fuel oil, is an
effective means of controlling particulate matter emissions because of the
relationship that generally exists between fuel sulfur content and
particulate matter emissions. Many studies, such as those supporting the
development of the manual, "Compilation of Air Pollutant Emission Factors"
(AP-42), have established that particulate matter emissions from fuel oil
combustion are generally proportional to fuel sulfur content.
As discussed previously, a well operated and maintained steam
generating unit firing oil will have very little carbonaceous material in
its particulate matter emissions. Because the other three components of
particulate matter emissions - ash, sulfur oxides, and additives - are each
generally proportional to the sulfur content of the fuel oil, the use of low
sulfur fuel oil is a very effective means of reducing particulate matter
emissions from fuel oil combustion. When compared to firing a high sulfur
fuel oil in a steam generating unit, medium sulfur fuel oils can reduce
particulate matter emissions by as much as 40 percent, and low sulfur fuel
••#•
oils can reduce particulate matter emissions by as much as 65 to 80 percent.
As discussed previously, low sulfur fuel oils are available and are
currently widely used in industrial-commercial-institutional and utility
steam generating units to reduce S0? emissions from oil combustion. Low
sulfur fuel oils, therefore, are considered demonstrated for the purpose of
developing new source performance standards limiting particulate matter
emissions from new, modified, and reconstructed oil-fired industrial-
commercial-institutional steam generating units.
4-23
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P-44
4.2.2 Post-Combustion Control
Post-combustion control is the most widely employed approach used for
the control of particulate matter emissions. Post-combustion control
techniques employed to control particulate matter emissions from steam
generating units include various types of mechanical collectors, sidestream
separators, fabric filters, wet scrubbers, and electrostatic precipitators.
Mechanical collection is a well established technology that employs
centrifugal separation to remove particles from the flue gas stream.
Although mechanical collectors have been widely used to control particulate
matter emissions, they have seen limited application to oil-fired steam
generating units. The majority of the particulate matter emitted from
oil-fired steam generating units is less than 10 ym in diameter. Mechanical
collectors, however, are principally effective on particulate matter larger
than 10 ym in diameter. Because of the general ineffectiveness of
mechanical collectors in reducing particulate matter emissions from
oil-fired steam generating units, they are not considered demonstrated for
the purpose of developing these new source performance standards.
Fabric filtration is a particulate matter control technology that has
been used very effectively to control particulate matter emissions from
coal-fired steam generating units. A fabric filter system (also known as a
baghouse) is one which directs particle-laden flue gas through a number of
fabric bags where the particles are collected as a filter cake on the bag
surface. The filter cake is dislodged from the bag surface by various sonic
and mechanical shaking techniques, and is removed from the floor of the
fabric filter structure for disposal.
Although fabric filters have been frequently applied to coal-fired
steam generating units, they have seen limited application to oil-fired
steam generating units. Many fuel oils produce a particulate matter with a
sticky or tar-like property. This physical .property has caused difficulties
in dislodging the filter cake from the fabric filter surface and has
resulted in filter plugging and short filter life. Consequently, the
general incompatibility of fabric filters with particulate matter emitted
4-24
-------
P.45
from oil combustion precludes their consideration as demonstrated for the
purpose of developing new source performance standards limiting particulate
matter emissions from new, modified, and reconstructed oil-fired industrial-
commercial-institutional steam generating units.
Sidestream separators are modified mechanical collectors in which a
fraction of the flue gas stream is withdrawn from the mechanical collector
ash hopper and is passed through a small fabric filter. Although sidestream
separators have not been applied to oil-fired steam generating units, they
are expected to exhibit the same ineffectiveness exhibited by mechanical
collectors and the same incompatibility exhibited by fabric filters.
Consequently, sidestream separators are not considered demonstrated for the
purpose of developing new source performance standards limiting particulate
matter emissions from new, modified, and reconstructed oil-fired
industrial-commercial-institutional steam generating units.
Electrostatic precipitators (ESP's) are in commercial use for the
control of particulate matter emissions from utility steam generating units
firing fuel oils. Electrostatic precipitators remove particulate matter
from flue gases by electrically charging the suspended particles and
precipitating them onto an oppositely charged collection plate. The
principal design factor affecting the performance of ESP's is the specific
collection plate area, expressed as the ratio of the collection plate area
to the flue gas flow rate. For a given steam generating unit and fuel type,
a larger specific collection plate area will provide improved particulate
matter collection efficiency. Consequently, the performance of a given ESP
design will be independent of the steam generating unit size as long as the
specific collection area remains constant.
A study of 20 utility steam generating units equipped with ESP's
demonstrated that the particulate matter emission control efficiency of
ESP's ranges from 40 to over 80 percent, and averages over 50 percent.
Furthermore, these ESP's have been in service for many years and do not
exhibit the incompatibility problems exhibited by fabric filters.
Consequently, electrostatic precipitators are considered demonstrated
for the purpose of developing new source performance standards limiting
4-25
-------
participate matter emissions from new, modified, and reconstructed oil-fired
industrial-commercial-institutional steam generating units.
Wet scrubbers are a second post-combustion control technique that has
been effectively applied to oil-fired steam generating units. Wet scrubbers
remove particulate matter from flue gases by contacting the flue gas with an
aqueous liquor. The particulate matter is entrained in the aqueous liquor
and removed from the scrubber. The performance of wet scrubbers in
controlling particulate matter is proportional to the turbulence generated
in the scrubber. By designing the wet scrubber with a long residence time
and extended surface area, the wet scrubber will be an effective particulate
matter control device in addition to controlling SCL emissions.
Over 250 wet scrubbers have been identified that are in use on
oil-fired industrial-commercial-institutional steam generating units. The
vast majority of these wet scrubbers are designed for the removal of 50^
emissions in conjunction with the removal of particulate matter emissions.
The particulate matter removal efficiency of these wet scrubbing systems
generally ranges from 65 to over 90 percent.
Consequently, wet scrubbers are considered demonstrated for the purpose
of developing these new source performance standards.
4.3 PARTICULATE MATTER EMISSIONS FROM COAL COMBUSTION
The June 19, 1984 proposed standards for industrial-commercial-
institutional steam generating units (49 FR 25102) discussed various methods
for controlling particulate matter emissions from coal-fired steam
generating units. The particulate matter emission limits established in the
proposed standard for coal-fired steam generating units were based on the
performance of fabric filters and ESP's.
As discussed above concerning control of particulate matter emissions
from oil-fired steam generating units, however, flue gas desulfurization
(FGD) systems are also capable of reducing particulate matter emissions from
coal-fired steam generating units. Most FGD systems inherently employ some
type of particulate matter control system as an integral part of their
4-26
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P.47
design. In the case of lime spray drying systems, for example, the
participate matter control system is generally a fabric filter. In the case
of wet FGD systems, such as lime or limestone, dual alkali, or sodium
scrubbing systems, the wet scrubber results in some reduction in particulate
matter emissions.
As discussed in the June 19, 1984 proposal notice, wet scrubbing
systems as well as fabric filters and ESP's are considered demonstrated.
FGO systems, therefore, are also considered demonstrated for purposes of
developing these new source performance standards.
4-27
-------
P.48
5.0 PERFORMANCE OF DEMONSTRATED EMISSION CONTROL TECHNOLOGIES
As discussed below, SO^ emission data gathered to assess the
performance of low sulfur fuel combustion, combustion modification, and FGD
technologies in reducing SO^ emissions from industrial-commercial-
institutional steam generating units exhibit significant variation about the
mean or average performance level. As an example, 5 days of SO^ emission
data from the combustion of low sulfur coal in an industrial steam
generating unit are shown in Figure 5-1; the variability in emissions about
the mean is apparent. Data on emissions and S0? removal efficiency from
steam generating units using combustion modification and FGD systems follow
a similar pattern.
For low sulfur coal, this variability is due to many factors, including
the lack of uniformity in sulfur deposits in coal seams, as well as coal
mining techniques and coal handling procedures. These same factors
influence the variability in SOp emissions observed from combustion
modification and FGD systems. Other factors affecting performance
variability associated with combustion modification and FGD systems are the
performance characteristics of individual equipment components and the
interactions of these components. Although oil exhibits variability in
sulfur content among reservoirs, this variation is minimized through the
processing, refining, storage, and handling of fuel oil prior to combustion
in a steam generating unit.
As a result of this variability, no single data point can be considered
representative of performance. Rather, data must be averaged over some
period of time to assess performance. The longer the averaging period
selected, the less variability remains in the data and the more accurate, or
more representative, the average performance level becomes as an assessment
of long-term performance.
Statistically, variability may be measured in terms of standard
deviation and autocorrelation. The standard deviation may be generally
described as a measure of the deviation or scatter exhibited by a set of
measurements around the mean or average of those measurements. The standard
5-1
-------
516 (1.20)
en
ro
495 (1.15)
473 (1.10) +
i
§ 452 (1.05) t
430 (1.00) t
i
410 (0.95) +
i
I 387 (0.90) +
LU ,
C\J
o
to
366 (0.85) +
344 (0.80)
323 (0.75)
10 20 30 40 50 60 70
Elapsed Time, Hours
80
90
100
110
120
Figure 5-1. Typical S02 Emissions Data for Low Sulfur Coal Combustion
•o
CO
-------
P.50
deviation is sometimes expressed as the relative standard deviation by
dividing the standard deviation by the mean. The larger the relative
standard deviation, the greater the variability exhibited by the data. The
lower the relative standard deviation, the less the variability exhibited by
the data.
Autocorrelation is a measure of the association or dependence between
successive measurements. An autocorrelation near 1.0 indicates that
successive measurements are similar in magnitude. An autocorrelation near
zero indicates there is little relationship between successive measurements.
The variability exhibited by SOp emission data tends to decrease as the
period over which the data are averaged increases. As discussed below, when
emission data from low sulfur coal combustion are averaged over a 24-hour
period, a relative standard deviation of about 20 percent and an
autocorrelation of about 0.7 are representative of much of the data gathered
to assess performance. Using these estimates of relative standard deviation
and autocorrelation, Figure 5-2 illustrates the effect of averaging period
length on SOp emissions variability.
Figure 5-2 assumes that the mean SO^ emission rate or long-term
performance level is 430 ng SO^/J (1.0 Ib SO^/million Btu) heat input. The
solid lines represent the outer limits or extreme values of the S02 emission
rates contained within two standard deviations of the mean of the data
(i.e., approximately 95 percent of the data lies between the two solid
lines).
Figure 5-2 clearly shows that the longer the period selected for
averaging S0? emissions data, the lower the variability exhibited by the
data. For example, if a 24-hour period were selected for averaging the
data, the variability observed in the data would range from as low as 258 ng
S02/J (0.6 Ib S02/million Btu) heat input to as high as 602 ng S02/J (1.4 Ib
S02/million Btu) heat input, a range of ± 40 percent around the mean. If a
30-day period were selected for averaging the data, on the other hand, the
variability observed in the data would range from 366 ng S02/J (0.85 Ib
S02/million Btu) heat input to 495 ng S02/J (1.15 Ib S02/million Btu) heat
input, a range of ± 15 percent. Compared to a 24-hour averaging period,
5-3
-------
688 (1.6)
602 (1.4)
c 516 (1.2)
430 (1.0) —
01 £ 344 (0.8)
CVJ
o
258 (0.6)
172 (0.4)
+2 Standard
Deviations
-2 Standard
Deviations
(1 hr){24 hrs) (7 day)
(30 day)
Averaging Period, hr
Figure 5-2. Impact of Averaging Period on S02 Emissions Data Variability
-------
P.52
therefore, a 30-day averaging period reduces the variability exhibited by
the data by somewhat more than half.
When considering what averaging period to use to minimize data
variability, it is important to recognize that the averaging period selected
for assessing the performance of SCL control technologies will also be the
averaging period selected for determining compliance with standards based on
these technologies. For a shorter averaging period, the performance level
required by the standard may be less stringent (or the emission limit to
accommodate a given performance level may be higher). This is because
greater variability is observed in performance measured over short averaging
periods. Conversely, for a longer averaging period, the mean performance
level required by the standard may be more stringent (or the emission limit
to accommodate a given performance level may be lower). This is because
lower variability is observed in performance measured over longer averaging
periods.
As mentioned above, the longer the averaging period used to measure
performance, the more realistic this measure of performance is in terms of
accurately reflecting the long-term or average performance of the system.
From the point of view of enforcing compliance with standards, however, the
longer the averaging period selected to measure performance, the longer the
period can be between the time a source begins to operate and the time an
initial assessment can be made of whether that source is in compliance with
the standards. An averaging period of one year, for example, would require
a year of operation before it could be determined if the source was in
compliance. An averaging period should be selected, therefore, that is long
enough to minimize variability, but short enough to permit timely
enforcement of the standards after a new source commences operation.
As shown in Figure 5-2, variability declines rapidly between averaging
periods of 1 hour and 30 days and then declines much more slowly beyond
30 days. An averaging period of 30 days, therefore, is long enough to yield
results representative of long-term performance. Similarly, an averaging
period of 30 days is also short enough to permit timely enforcement of a
standard after a new source begins operation. In addition, use of a 30-day
5-5
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P.53
rolling average, as opposed to a 30-day discrete average, allows enforcement
of standards on a daily basis following the first 30-day period. As a
result, a 30-day rolling average was selected for assessing the performance
of low sulfur fuels, combustion modification, and FGD technologies for the
purpose of developing standards of performance limiting S0? emissions from
new, modified, and reconstructed industrial-commercial-institutional steam
generating units.
5.1 LOW SULFUR COAL
As discussed in "Selection of Demonstrated Emission Control
Technologies," the use of low sulfur coal is considered demonstrated for the
purpose of developing standards of performance for coal-fired
industrial-commercial-institutional steam generating units. Low sulfur
coals include both those with naturally occurring low sulfur content and
those that have had sulfur removed by processing.
Sulfur dioxide emissions resulting from the combustion of coal in steam
generating units vary considerably because the sulfur content of coal is not
homogeneous. Coal produced from a single seam by the same mine may vary
substantially in sulfur content. In addition to sulfur content, the heat
content of coal also varies. Therefore, when expressing fuel sulfur content
on a heat content basis (ng/J or Ib/million Btu), sulfur content variability
is actually a measure of the joint variability of these two coal properties.
For these reasons, there will be substantial variation in the SO^ emissions
(ng/J or Ib/million Btu) resulting from the combustion of coal.
The amount of variation is influenced by variation in the natural
distribution of sulfur throughout the seam from which the coal is mined, and
can also be influenced by the manner in which the coal is mined. To
represent the distribution of sulfur deposits in a coal seam, lines of
constant sulfur content (called isolines) can be drawn on a map of a coal
deposit as shown in Figure 5-3. Mining coal in a direction parallel to a
sulfur isoline will produce coal with less variation in sulfur content than
mining coal in a direction perpendicular to the sulfur isolines. In
5-6
-------
r'"\
RESERVE
BOUNDARY v
O PRODUCTION AREAS
Figure 5-3. Map Showing Sulfur Isolines for "E" Seam of Helvetia No. 6 Reserves
-------
P.55
addition, coal may be mined simultaneously from several locations within the
same seam. The sulfur content of the coal from each location and the degree
of mixing the coals undergo will influence overall variability in the sulfur
content of the coal produced from the mine.
The amount of variation is also influenced by the extent to which coal
is cleaned prior to shipment (see "Selection of Demonstrated Emission
Control Technologies"). Physical coal cleaning (PCC) removes a large
portion of the impurities normally found in raw coal and reduces the
variation in the sulfur content of the coal. It has been reported that PCC
reduces coal sulfur variability by approximately 50 percent.
Finally, the amount of variation is also influenced by coal handling
practices at the mine, at the PCC plant, or at the steam generating unit
site. Coal handling, for example, may involve blending coals to produce a
coal blend that is more uniform in sulfur content than the individual coals.
Three coal blending methods are commonly employed. These include bed
blending, bunker blending, or a combination of the two. Bed blending
involves spreading coals from various sources over a large area in series of
horizontally layered beds. Bunker blending involves taking coals from
various storage facilities (bunkers, silos, or open piles) in fixed
proportions to create a coal blend that is more uniform. One combination
method involves taking coals from various storage facilities in fixed
proportions and then blending them using the bed blending method described
above.
Coal blending decreases the variability in coal sulfur content by
physically averaging the sulfur contents of coals. The degree of reduction
in variability, however, depends on the properties of the coals blended and
the specific blending method.
To assess the performance of low sulfur coal as an emission control
technique, S02 emission data were gathered to identify the variation in
emissions typically observed during the combustion of coal. These data,
which are summarized in Table 5-1, were gathered from industrial-commercial-
institutional steam generating units and electric utility steam generating
units. For all data sets except CEM-5, the data were collected by
5-8
-------
TABLE 5-1. CONTINUOUS EMISSION MONITORING (CEM) DATA
Data Set No.
CEM-1
CEM-2
CEM-3
CEM-4
CEM-5
CEM-6
CEM-7
en
10 CEM-8
CEM-9
CEM-10
CEM- 11
Type of Unit
Industrial
Industrial
Industrial
Industrial
Institutional
Utility
Utility
Utility
Utility
Utility
Utility
Number
of Hourly
Data Points
1,914
1,848
1,152
1,368
792J,
864b
1,896
2,712
1,944
1,200
1,392
612
Raw or
Washed Coal
-
Raw
Raw
Washed
Washed
Washed
Raw
Raw
Raw
Washed and
Raw
Raw
-
Type of Coal
Bituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Bituminous
Subbituminous
Subbituminous
Bituminous
Subbituminous
Subbituminous
Daily Coal
Lot Size
(tons)
500
500
330
175
150
150
3,500
6,500
7,500
5,000
4,500
900
Mean Emissions
(Ib S02/million Btu)
0.92
0.64
0.79
0.99
1.44
1.48
0.92
0.45
0.78
0.83
0.80
1.06
Daily RSD
(Percent)
10
32
29
11
9
11
9
17
15
8
9
11
Daily
Autocorrelation
0.49
0.66
0.63
0.67
-
0.67
0.79
0.59
0.72
0.73
-
aTotal hours for which data are available; i.e., the total number of hours spanned by the test multiplied by the data capture rate.
These data are based on Test Method 6B; therefore, only daily averages are available. For consistency with other data sets, the number of hours
reported in this column reflects 24 hourly data points for the days for which daily averages were available.
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P.57
continuous emission monitoring systems (CEMS) that had successfully
completed CEMS performance specification tests. The data for data set CEM-5
were collected using Reference Method 6B.
Data set CEM-1 is based on hourly SOp emission measurements from an
industrial steam generating unit for the period November 1983 through
January 1984. This unit has a heat input capacity of 226 MW (780 million
Btu/hour). The coal burned at the plant is primarily from the Upper Banner
and Elkhorn seams of Virginia and western Kentucky. For a 6-day period in
December 1983, data were not available due to steam generating unit outage.
The data were collected with CEMS equipment that had passed certification
tests in November 1982. Daily coal lot size determined from the steam flow
rate data is 450 Mg (500 tons). This is based on several assumptions: steam
enthalpy of 2,560 kJ/kg (1,100 Btu/lb); steam generating unit efficiency of
83 percent, and coal heating value (as received) of 31,500 KJ/kg (13,540
Btu/lb).
Data sets CEM-2 and 3 are based on data from two industrial pulverized
coal-fired steam generating units. These data were collected from March
through July 1979 using continuous S02 analyzers that were certified in
September 1978. There were numerous gaps in the data for both steam
generating units, although the gaps did not necessarily occur at the same
time. Operating personnel at these two steam generating units could not
recall the reasons for the data gaps. These steam generating units
typically fire a western subbituminous coal with a heating value of 29,560
kJ/kg (12,710 Btu/lb) on a dry basis. Daily coal lot sizes for these steam
generating units, which have heat input capacities of about 171 MW (583
million Btu/hour) and 256 MW (875 million Btu/hour), are estimated at 300
and 454 Mg (330 and 500 tons), respectively. These estimates assume an
average steam generating unit load of 60 percent, an efficiency of 83
percent, and steam enthalpy of 2,560 kJ/kg (1,100 Btu/lb).
Data set CEM-4 is based on data from a 78 MW (265 million Btu/hour)
heat input capacity pulverized coal-fired steam generating unit located at
an industrial facility. Data were collected from July through September
1982 using a CEMS certified in early 1982. The steam generating unit is
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shut down each Friday night at midnight and restarts at 7 A.M. each Monday
morning. For this reason, there are numerous gaps in the data. This steam
generating unit fires eastern bituminous coal, which may be raw, washed, or
blended to produce a compliance coal. Daily coal lot sizes are estimated at
159 Mg (175 tons). This estimate assumes an average load of 60 percent, a
steam generating unit efficiency of 83 percent, and a steam enthalpy of
2,560 kJ/kg (1,100 Btu/lb).
Data set CEM-5 consists of 24-hour SO^ values (Reference Method 6B)
from a 36 MW (125 million Btu/hour) heat input capacity institutional
electric power generating plant. The data collected from this unit are for
a 70-day period in August through November 1979. During this period the
plant was burning washed eastern Kentucky coal with an average heating value
of 31,400 kJ/kg (13,500 Btu/lb). The daily data capture rates for two
parallel data collection operations were 46 (33 days) and 51 (36 days)
percent. Based on coal consumption rate data for this period, daily coal
lot size is about 135 Mg (150 tons).
Data set CEM-6 is from a 1,290 MW (4,450 million Btu/hour) heat input
capacity pulverized coal steam generating unit and spans the period January
1 through April 1, 1984. The data were collected with CEMS equipment that
had passed certification tests in October 1983. During the period of data
collection, the unit was firing an unwashed low sulfur bituminous coal from
three different seams at three mines in Utah. This unit is equipped with an
FGD system and data were collected at the inlet to the FGD. All coal is
transported by truck at a rate of 13,650 Mg (14,000 tons) per day. Some
limited blending takes place at the plant site.
Data set CEM-7 is from a 2,100 MW (7,250 million Btu/hour) heat input
capacity pulverized coal utility steam generating unit. This data set spans
the period October 3, 1983 through February 29, 1984. The data were
collected with CEMS equipment that had passed certification tests in
November 1981. During this period, the unit was firing an unwashed
subbituminous coal from one coal seam in the Powder River Basin in Wyoming
and was shipped by unit train [approximately 10,000 Mg/train (11,000
tons/train)] approximately three times per week. No coal blending is
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performed intentionally. The average steam generating unit load was 60
percent.
Data from a 1,680 MW (5,800 million Btu/hour) heat input capacity
pulverized coal steam generating unit make up data set CEM-8. The time
period covered by this data set is May 1 through July 31, 1983. The data
were collected with CEMS equipment that had passed certification tests in
August 1981. Unwashed subbituminous coal from two coal seams in the Powder
River Basin of Wyoming is fired in this steam generating unit. The coal is
shipped by unit train [approximately 10,000 Mg/train (11,000 tons/train)]
approximately three times per week. No coal blending is performed. The
average steam generating unit load was 80 percent.
Data set CEM-9 is from a 795 MW (7,950 million Btu/hour) heat input
capacity pulverized coal utility steam generating unit for the period
November 21, 1983 through January 18, 1984. The data were collected with
CEMS equipment that had passed certification tests in March 1983. Coal is
received both by barge [approximately 12,250 Mg/barge (13,500 tons/barge)]
and by unit train [approximately 6,500 Mg/train (7,200 tons/train]. The
coal fired is supplied by six suppliers and is a low sulfur bituminous coal
from mines in different seams in southern Appalachia. All but a small
fraction of the coal is washed, achieving up to a 15 percent reduction in
sulfur content. No intentional coal blending program is followed. During
the data collection period, the average steam generating unit load was 66
percent.
Data set CEM-10 is from a 1,600 MW (5,500 million Btu/hour) heat input
capacity pulverized coal utility steam generating unit and covers the period
February 1 through April 10, 1984. The data were collected with CEMS
equipment that had passed certification tests in May 1983. All coal is
unwashed subbituminous coal from a single mine in the Powder River Basin of
Wyoming. The coal is shipped by unit train [approximately 10,000 Mg/train
(11,000 tons/train)] on a daily basis. No coal blending takes place at the
plant, although some takes place at the supplier. Data were collected at
the inlet to the FGD.
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Daily coal lot sizes determined for the data sets CEM-7, 8, and 9 are
based on daily average steam generating unit load data, 6-month average heat
rate, and 6-month average coal heating value. The daily coal lot sizes for
data sets CEM-6 and 10 are based on the average load data, heat rate, and
coal heating value derived from data contained in data sets CEM-7, 8, and 9.
Data contained in data set CEM-11 were gathered at a pulverized coal
utility steam generating unit rated at 360 MW (1,250 million Btu/hour) heat
input capacity burning low sulfur subbituminous Wyoming coal with an average
sulfur content of 0.5 percent and a reported heating value of 2,325 kJ/kg
(1,000 Btu/lb). During these tests, conducted in January and February of
1979, S02 concentrations were monitored concurrently at the inlet and outlet
of the FGD system. The data were collected with CEMS equipment that had
passed certification tests in January 1979. The data are comprised of 612
hourly SOp emission values collected over a 30-day period. Daily coal lot
size was calculated as 820 Mg (900 tons) based on daily steam generating
unit load data. In this calculation the heat rate for the plant is a$sumed
to be 10,545 kJ/KW-hour (10,000 Btu/KW-hour).
Several studies of the variability of SO,, emissions resulting from coal
combustion and the variability of coal sulfur content indicate that a time
series statistical model, referred to as an AR(1) model, generally fits
actual data quite well. In addition, a normal data distribution generally
fits actual data as well as other data distributions, such as lognormal,
when focusing on emissions performance averaged over a 30-day period.
Consequently, an AR(1) model with a normal data distribution was used to
determine the variability in each data set summarized in Table 5-1.
As mentioned earlier, two common statistical measures of variability
are relative standard deviation (RSD) and autocorrelation (AC). Standard
deviation is a measure of the spread of a set of data on either side of the
mean. The relative standard deviation is calculated by dividing the
standard deviation of a set of measurements by their mean. Autocorrelation
is a measure of association between successive periodic measurements taken
over a span of time.
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Analysis of the data sets discussed above using an AR(1) time series
statistical model yields the RSD and AC values presented in Table 5-1.
These values represent the variability observed in SOp emissions in each
data set for the amount of coal typically combusted in a 24-hour period
(i.e., lot size). These values vary considerably because, as discussed
above, many factors affect variability in SOp emissions. The RSD values
range from 8 to 32 percent and the AC values range from 0.49 to 0.79.
This assessment of the variability in SOp emissions can be used to
determine the performance of low sulfur coal as an emission control
technique. Given values for RSD and AC, the AR(1) model can be used to
estimate the ratio between the maximum expected 30-day rolling average SOp
emission rate, assuming this maximum expected 30-day rolling average
emission rate would only be exceeded once in 10 years, and the mean or
long-term average SOp emission rate resulting from combustion of a
particular coal. Multiplying this ratio by the long-term average emission
rate yields the once in 10-year maximum expected 30-day rolling average S0?
emission rate.
The data in Table 5-1 indicate that an RSD of 20 percent and an AC of
0.7 are reasonable assumptions to characterize the 24-hour variability in
SOp emissions resulting from combustion of a coal with a high variability in
SOp emissions. These values are conservative assumptions, particularly when
combined with the statistical assumption that the resulting maximum expected
30-day rolling average S0? emission rate may only be exceeded once in
10 years. Assuming an RSD of 10 percent and an AC of 0.5, or an exceedance
frequency of once a year rather than once in 10 years, would result in
higher ratios between the maximum expected 30-day rolling average emission
rate and the long-term average emission rate.
Using values of 20 percent and 0.7 for RSD and AC, respectively, the
AR(1) model projects a ratio of 1.25 between the once in 10-year maximum
expected 30-day rolling average emission rate and the long-term average
emission rate.
Multiplying the long-term average emission rates associated with each
coal type discussed in "Selection of Demonstrated Emission Control
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Technologies" (see Table 4-1) by 1.25 yields the once in 10-year maximum
expected 30-day rolling average emission rate resulting from combustion of
each coal type. As shown in Table 5-2, SOp emissions could be reduced to or
below an emission rate between 215 and 731 ng SOp/J (0.5 and 1.7 Ib
SOp/million Btu) heat input through the combustion of the low sulfur coal
types. Similarly, SOp emissions resulting from the combustion of the medium
sulfur and high sulfur coal types would not exceed an emission rate between
1,120 and 1,590 ng S02/J (2.6 and 3.7 Ib S02/million Btu) heat input and
between 2,240 and 2,710 ng S02/J (5.2 and 6.3 Ib S02/million Btu) heat
input, respectively. Standards of performance based on the combustion of
low sulfur coals, therefore, could reduce or limit S0? emissions to the
emission rates associated with low sulfur coals shown in Table 5-2.
As mentioned above, the data summarized in Table 5-1 were gathered from
both industrial-commercial-institutional steam generating units and utility
steam generating units. A utility steam generating unit, however, consumes
much more coal than an industrial-commercial-institutional steam generating
unit over a given period of time. As a result, the variability observed in
S02 emissions from coal combustion in a utility steam generating unit
reflects a much larger lot size than the variability observed in emissions
from coal combustion in an industrial-commercial-institutional steam
generating unit.
When samples are taken to estimate the value of a parameter, such as
coal sulfur content, statistical theory indicates that smaller sample sizes
should exhibit greater variability in the measured values of the parameter.
On this basis, the question is frequently raised whether differences in lot
size significantly influence the variability in S02 emissions resulting from
coal combustion. Following this reasoning, industrial-commercial-
institutional steam generating units might exhibit greater variability in
SOp emissions than utility steam generating units.
As illustrated in Figure 5-4, however, when the data summarized in
Table 5-1 are examined to determine if lot size has a significant influence
on variability, no relationship between lot size and variability is
observed. Figure 5-4 does not necessarily indicate that lot size has no
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TABLE 5-2. MAXIMUM EXPECTED EMISSION RATES
FOR COAL COMBUSTION
Long-Term Average Maximum Expected
S02 Emissions Emission Rate
Type ng
Very Low Sulfur
Low Sulfur
Low Sulfur
Medium Sulfur
Medium Sulfur
High Sulfur
High Sulfur
S02/J(lb S02/million Btu)
172 (0.40)
404 (0.94)
589 (1.37)
894 (2.08)
1,256 (2.92)
1,793 (4.17)
2,150 (5.00)
ng S02/J(lb S02/million Btu)
215 (0.5)
516 (1.2)
731 (1.7)
1,120 (2.6)
1,590 (3.7)
2,240 (5.2)
2,710 (6.3)
aOnce in 10-year maximum expected 30-day S02 rolling average (long-term
average emission rate times 1.25, rounded to nearest tenth).
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O Industrial-commercial-institutional
en
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steam generating units
• Utility steam generating units
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5 10 15 20 25 30 35 40 45 50 55 60 65 70 7
COAL LOT SIZE ( X 100 TONS)
Figure 5-4. Coal Lot Size Versus S02 Emissions Variability for Utility and
Industrial-Commercial-Institutional Steam Generating Units
TJ
CD
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influence on variability, but that the cumulative effect of other factors
that also influence variability overshadows the effect of lot size.
From a purely statistical and theoretical point of view, the magnitude
of the effect of lot size on emissions variability can be estimated.
Assuming that an RSD of 20 percent typically reflects the variability in
emissions from utility size boilers, then theoretically the smaller lot size
associated with industrial size boilers would result in a typical RSD of
21.5 percent. Using values of 21.5 percent and 0.7 for RSD and AC,
respectively, the AR(1) model projects a ratio of 1.26 between the once in
10-year maximum expected 30-day rolling average emission rate and the
long-term average emission rate.
A ratio of 1.26 results in a slight increase in the once in 10-year
maximum expected 30-day rolling average emission rates presented in
Table 5-2. The once in 10-year maximum expected 30-day rolling average
emission rate for a low sulfur coal with a long-term average emission rate
of 413 ng/J (0.96 Ib/million Btu) heat input, for example, would increase
from 516 ng/J (1.20 Ib/million Btu) to 521 ng/J (1.21 Ib/million Btu) heat
input.
As mentioned above, if less conservative values of 10 percent and 0.5
were assumed for RSD and AC, the ratio between the once in 10-year maximum
expected 30-day rolling average emission rate and the long-term average
emission rate decreases to 1.10. Use of this ratio would result in a
decrease in the once in 10-year maximum expected emission rates presented in
Table 5-2. The once in 10-year maximum expected 30-day rolling average
emission rate for a low sulfur coal with a long-term average emission rate
of 413 ng/J (0.96 Ib/million Btu), for example, would decrease to 456 ng/J
(1.06 Ib/million Btu) heat input. Thus, the conservative nature of the
assumptions included in the analysis is more than sufficient to account for
whatever small influence lot size has on the variability in SOp emissions
resulting from coal combustion. Therefore, the maximum expected emission
rates presented in Table 5-2 represent the emission limits that could be
achieved by combustion of low sulfur coal in industrial-commercial-
institutional steam generating units.
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One of the concerns that must be addressed if standards are based on
the use of low sulfur coal is the availability of such coals. If the low
sulfur coals upon which the standards are based are not generally or widely
available, many industrial-commercial-institutional steam generating units
would be unable to comply with such standards through the use of low sulfur
coals. Under these circumstances, operators of these steam generating units
would be forced to employ alternative measures to reduce SCL emissions, such
as the use of FGD systems. Thus, the impacts associated with the standards
could be greater or more severe than those envisioned in developing the
standards. It is important, therefore, to consider the availability of low
sulfur coals in determining the emission rates that can be achieved by the
use of low sulfur coals.
Coal-fired utility steam generating units currently consume about
85 percent of all the coal combusted in steam generating units in the United
States. Utility steam generating units generally negotiate long-term
contracts to secure coal supplies. Most operators of industrial-commercial-
institutional steam generating units, on the other hand, typically secure
coal supplies from the "spot" market. For these reasons, large coal mines
and large coal companies are primarily oriented to supply utility customers,
and will undertake substantial capacity expansions or will invest in coal
cleaning facilities in response to utility coal demands.
Large coal mines and companies will not do the same for industrial-
commercial-institutional steam generating units, however, because their fuel
demand is small in relation to utility demand and they do not typically
engage in long-term contracts. Hence, much of the industrial-commercial-
institutional coal market is supplied by excess stocks available through the
spot market from companies that provide coal to utilities. Therefore,
standards for industrial-commercial-institutional steam generating units
based on the use of low sulfur coals must reflect the coals that are
currently available in existing coal markets.
The promulgation of new source performance standards (40 CFR Part 60
Subpart D) for steam generating units of more than 73 MW (250 million
Btu/hour) heat input in 1971 created a demand by utilities and large
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industrial-commercial-institutional steam generating units for low sulfur
coal that can achieve an emission limit of 516 ng SCL/J (1.2 Ib S0?/million
Btu) heat input or less. Over half of the steam generating units currently
complying with these standards do so by the use of low sulfur coal. In
response to this demand, coal markets have developed that are able to supply
coals with a sulfur content of 516 ng SCL/J (1.2 Ib SCL/million Btu) heat
input or less throughout the nation. While lower sulfur coals are available
in some areas, they are not widely available throughout the United States.
In addition, demand for coal by industrial-commercial-institutional steam
generating units is not sufficient to significantly alter this coal supply
situation. Consequently, an SCL emission limit included in standards of
performance based on the use of low sulfur coals for industrial-commercial-
institutional steam generating units should be no lower than 516 ng SCL/J
(1.2 Ib S02/million Btu) heat input.
5.2 LOW SULFUR OIL
As discussed above in "Selection of Demonstrated Emission Control
Technologies," the use of low sulfur oil is considered demonstrated for the
purpose of developing standards of performance for oil-fired
industrial-commercial-institutional steam generating units. Low sulfur oils
include both those with naturally occurring low sulfur content and those
that have had sulfur removed by hydrodesulfurization techniques (HDS).
Unlike solid fuels such as coal, which have their sulfur-bearing
constituents unevenly distributed because of geological and physical
properties, sulfur constituents in fuel oil are not locked in place and,
therefore, are distributed more evenly throughout the fuel. Moreover, other
factors such as refining techniques, storage and transportation methods, and
fuel handling at the steam generating unit site serve to make fuel oils
relatively homogeneous with respect to fuel sulfur content. Thus, there is
little variability in S0? emissions resulting from the combustion of a
specific fuel oil.
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Table 5-3 summarizes the SCL emission rates associated with the
combustion of the various types of oils discussed in "Selection of
Demonstrated Emission Control Technologies." The emission rates that can be
achieved with low sulfur oils range from 129 to 344 ng SCL/J (0.3 to 0.8 Ib
SOp/million Btu) heat input. Standards of performance limiting SOp
emissions from new, modified, and reconstructed industrial-commercial -
institutional steam generating units based on the use of low sulfur oil,
therefore, could reduce emissions of SOp to these levels or less.
5.3 COMBUSTION MODIFICATION AND FLUE GAS DESULFURIZATION
The combustion modification and flue gas desulfurization (FGD)
technologies which are considered demonstrated for the purpose of developing
standards of performance for industrial-commercial-institutional steam
generating units are: fluidized bed combustion (FBC), lime spray drying,
lime/limestone wet scrubbing, dual alkali wet scrubbing, and sodium wet
scrubbing. All of these technologies have been applied to coal-fired
industrial-commercial-institutional steam generating units. Only sodium wet
scrubbing, however, has been applied to oil-fired industrial-commercial-
institutional steam generating units. Fluidized bed combustion and lime
spray drying have not been applied to oil-fired units due to the "sticky"
nature of the fly ash produced from oil combustion, which could interfere
with the operation of particulate matter control devices, generally fabric
filters, which are an integral part of FBC and lime spray drying systems.
Lime/limestone and dual alkali wet scrubbing FGD systems have not been
applied to oil-fired steam generating units due primarily to non-competitive
economics. There are no technical barriers, however, to successful
application of lime/limestone and dual alkali FGD systems to oil-fired steam
generating units.
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TABLE 5-3. EMISSION RATES FOR OIL COMBUSTION
Emissions
Oil Type ng S02/J (Ib S02/mi11ion Btu)
Very Low Sulfur 129 (0.3)
Low Sulfur 344 (0.8)
Medium Sulfur 688 (1.6)
High Sulfur 1,290 (3.0)
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5.3.1 Fluidized Bed Combustion
The combustion modification technology that is considered a
demonstrated SCL emission control technology is the use of fluidized bed
combustion (FBC). The system parameters that influence SO,, removal
efficiency in FBC units include the calcium-to-sulfur (Ca/S) ratio (the
amount of calcium added per unit of sulfur in the fuel, on a molar basis);
the solids recycle ratio (the amount of entrained solids returned to the
combustion zone, on a weight basis); the gas-phase residence time (the ratio
of expanded bed height to the superficial gas velocity); the sorbent (i.e.,
limestone) particle size; the sorbent reactivity; the fuel ash alkalinity;
and the amount of freeboard (the space between the top of the bed and the
point at which the flue gas exits the combustion unit). Each parameter also
affects the sorbent utilization.
Westinghouse Research and Development Center has developed a model
which projects sorbent requirements to attain certain levels of S02 removal
efficiency. This is a simplified model for fluidized bed desulfurization
which makes projections using kinetic rate constants developed from
laboratory thermogravimetric data. For limestone with medium reactivity and
an approximate 500 ym particle size, the model projects increases in SOp
removal efficiency from about 40 percent to about 95 percent as the Ca/S
ratio increases from 2 to 6.
The effect of varying the Ca/S ratio on S02 removal was examined during
a 16-day parametric test at site A. Certified continuous SOp emission
monitors were used for data collection on the outlet of the FBC system, and
periodic sampling and analysis of feed coal was performed at the inlet in
accordance with Reference Method 19A. This two-stage FBC unit had a heat
input capacity of 26 MW (88 million Btu/hour) and burned a bituminous coal
with a sulfur content of 2,910 ng SO?/J (6.8 Ib SOp/million Btu). The unit
load ranged from 46 to 79 percent of full load and averaged 60 percent.
Solids recycle was not employed. As the Ca/S ratio increased from 0.5 to
3.2, the SOp removal efficiency increased from 55 to 89 percent.
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The effect of varying the solids recycle ratio was examined during
tests conducted at the Babcock & Wilcox Co. 1.8 m x 1.8 m (6 ft x 6 ft) FBC
test unit. This FBC had a heat input capacity of about 7 MW (24 million
Btu/hour). At a Ca/S ratio of 2.5 to 2.9, with no solids recycle, the S02
removal efficiency was about 70 percent. For the same Ca/S ratio and a
solids recycle ratio of 1.0, the SO* removal efficiency increased to
approximately 85 percent.
To assess the performance of FBC units, general information concerning
the overall long-term performance of this technology was obtained from two
sites. Site B was a bubbling bed FBC unit with a heat input capacity of
50 MW (171 million Btu/hour). This FBC unit burned bituminous coal with an
average sulfur content of 2,150 ng S02/J (5.0 Ib S02/million Btu). During a
680-day period, the unit operated with a system reliability of 93 percent.
The percent removal of S02 for the entire 680 days could not be accurately
determined because of two extended periods of continuous emission monitor
malfunction.
However, during a 30-day period within this 680-day period, when the
uncertified continuous emission monitors were functioning, the S02 removal
of the unit ranged from 55 to 93 percent and averaged 82 percent. It should
be noted that the FBC unit was required under State regulations to reduce
S02 emissions by only 76 percent to achieve an emission limit of 516 ng
SO?/J (1.2 Ib S02/million Btu). During this 30-day period, the system was
operated at a unit load ranging from 51 to 83 percent of full load and
averaging 71 percent; the Ca/S ratio ranged from 0.9 to 3.0 and averaged
2.4. The system reliability for the 30 days was greater than 99 percent.
Site C was a bubbling bed FBC unit with a heat input capacity of 23 MW
(80 million Btu/hour). This unit burned bituminous coal with a sulfur
content of 470 ng S02/J (1.1 Ib S02/million Btu). During a 416-day period,
the unit operated with a system reliability of 92 percent. The system was
operated at about 45 percent of full load during this period. It should be
noted that the FBC unit was scheduled to be out of service for approximately
95 days during this period for inspection, maintenance, and testing of a
stand-by boiler. The instrument technicians were not trained in the
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P.72
awd maintenance of the continuous emission monitors until the
latter part of the 416-day period. Reliable SCL emissions data were,
therefore, not available for the entire 416 days, even though the monitors
were certified. However, during a 67-day period within the 416-day period,
when the continuous SCL emission monitor was properly maintained and
operated, the percent SCL removal ranged from 74 to 95 percent and averaged
86 percent. The unit was required under State regulations to reduce SCL
emissions by 70 percent. The unit load during this period ranged from 43 to
77 percent of full load and averaged 56 percent. The unit had a system
reliability of 97 percent during the 67 days. The Ca/S ratio could not be
accurately determined because the coal and limestone feed rate measuring
devices were inaccurate. Solids were not recycled during this period.
In addition to the information outlined above, SCL emission data were
obtained from five sites to further assess the performance and emissions
reduction potential of FBC systems. These data consist of four short-term
tests and two long-term tests.
The first short-term test was conducted over a 2-day period at site A
described above using certified continuous monitors to measure SCL emissions
at the FBC outlet. Feed coal was periodically sampled and analyzed at the
inlet in accordance with Reference Method 19A. The FBC system burned a
bituminous coal with a sulfur content of 2,910 ng S02/J (6.8 Ib SOp/million
Btu). The unit load ranged from 57 to 60 percent of full load during the
test and averaged 59 percent.
The FBC unit was operated at a Ca/S ratio ranging from 2.4 to 3.3 with
an average of 2.8. Solids recycle was not used. During the testing period,
the S02 removal of the system ranged from 53 to 94 percent and averaged 84
percent.
The second short-term test, conducted at site B described above, was a
compliance test consisting of three 65-minute test periods using Reference
Method 6 for S02 emissions measurements. (Certified continuous monitors
were not available at the plant at the time of testing.) The FBC unit
burned bituminous coal with a sulfur content of 2,450 ng SOp/J (5.7 Ib
SOp/million Btu). During each of the three testing periods, the system was
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operated at 100 percent of full load. Solids were recycled at an unknown
rate.
The Ca/S ratio was maintained at approximately 2.7 for the first two
testing periods and was increased to about 2.8 for the third testing period.
The S02 removal for the three testing periods was 72, 81, and 81 percent,
respectively. The FBC unit was required under State regulations to reduce
SOp emissions by 79 percent to achieve an emission limit of 516 ng SO?/J
(1.2 Ib S02/million Btu).
The third test was conducted at site D, which was a large pilot plant
operated to demonstrate the feasibility of FBC technology for utility-type
applications. Continuous SCL emission monitors were used for data
collection on the outlet of the system. Feed coal was periodically sampled
and analyzed at the inlet in accordance with Reference Method 19A. The
bubbling bed FBC unit had a heat input capacity of 59 MW (200 million
Btu/hour) and burned bituminous coal. Only the average Ca/S ratio for each
testing period was reported.
The duration of the first testing period at site D was 15 hours.
During this period, the feed coal sulfur content was 3,270 ng SO^/J (7.6 Ib
S02/million Btu). The unit load averaged 77 percent of full load. Solids
were not recycled during this test period. The FBC system was operated at
an average Ca/S ratio of about 3.0. Sulfur dioxide removal ranged from 75
to 91 percent and averaged 87 percent.
The duration of the second testing period was 12 hours. The sulfur
content of the feed coal was 3,140 ng S02/J (7.3 Ib S02/million Btu).
During this period, the unit load averaged 75 percent of full load. Solids
were not recycled. The FBC unit was operated at an average Ca/S ratio of
3.9 and achieved an average 95 percent S02 removal.
The duration of the third testing period was 12 hours. Feed coal with
a sulfur content of 2,880 ng S02/J (6.7 Ib S02/million Btu) was burned. The
unit load averaged 80 percent of full load. During this period, the solids
recycle ratio was 1.5. The average Ca/S ratio for this period was
approximately 3.0. Sulfur dioxide removal averaged 98 percent.
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The duration of the fourth testing period was 10 hours. The sulfur
content of the feed coal was 3,050 ng S02/J (7.1 Ib SOp/million Btu).
During this period, the FBC unit was operated at about 76 percent of full
load. The solids recycle ratio was 1.5. The system operated at an average
Ca/S ratio of about 2.9. Sulfur dioxide removal ranged from 76 to 99
percent and averaged 97 percent.
It should be noted that this FBC unit has a high freeboard zone. The
high freeboard results in increased flue gas and sorbent contact time and,
thus, contributes to the high S02 removal efficiencies achieved by this FBC
system.
The fourth test was a compliance test conducted at site E. The test
consisted of three 1-hour runs, and Reference Method 6 was used for SOp
emissions measurements. This bubbling bed FBC unit had a heat input
capacity of 30 MW (102 million Btu/hour) and burned bituminous coal with a
sulfur content of 2,618 ng S02/J (6.1 Ib S02/million Btu). The unit was
operated at 72 percent of full load during the test. For the three test
runs, the percent S02 removal was 89, 95, and 85 percent. The Ca/S ratios
used to achieve these levels of removal were not available.
The first long-term test was conducted over a 30-day period at site C
described above. Certified continuous SOp emission monitors were used for
data collection on the outlet of the system. The unit burned bituminous
coal with a sulfur content of 470 ng S02/J (1.1 Ib S02/million Btu). During
the test, the unit load ranged from 43 to 60 percent of full load and
averaged 51 percent. The system operated at greater than 99 percent
reliability during the test.
The Ca/S ratio could not be accurately determined because the coal and
limestone feed rate measuring devices were inaccurate. Solids were not
recycled during the test. Sulfur dioxide removal ranged from 81 to 95
percent and averaged 90 percent.
The second long-term test was conducted over a 25-day period at site E
described above. Certified continuous SOp emission monitors were used for
data collection on the outlet of the system. The unit burned bituminous
coal with a sulfur content of 1,891 ng S02/J (4.4 Ib S02/million Btu).
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Sulfur dioxide removal ranged from 78 to 95 percent during the test and
averaged 87 percent. It should be noted that this unit was only required
under existing State regulations to reduce S(L emissions by 73 percent while
burning this coal, to meet an emission limit of 516 ng SCL/J (1.2 Ib
S02/million Btu).
Several vendors of FBC units were also contacted regarding the
performance capabilities of new FBC units. One vendor indicated that
although SOp emissions guarantees are given on a case-by-case basis,
depending on fuel type and limestone reactivity, FBC units can be designed
to achieve well above 90 percent SOp removal. This would require a reactive
limestone and increased limestone feed rates. However, FBC units can be
designed to accommodate the increased solids loading with no adverse effects
on system reliability. Another vendor stated that their circulating bed FBC
units could reduce SOp emissions by 90 percent when burning coal containing
3 weight percent sulfur and operating at a Ca/S ratio of 2.0.
In light of the above information, there appear to be no technical
barriers to achieving greater than 90 percent SOp removal with an FBC system
on a sustained basis at higher (90 percent) reliabilities.
5.3.2 Lime Spray Drying
The first FGD technology that is considered to be demonstrated is lime
spray drying. The two system parameters that have a major influence on S0?
removal efficiency in lime spray drying systems are the reagent ratio
(amount of reagent added per unit of inlet S0?) and the approach to
saturation temperature. The choice of particulate matter (PM) control
device will also influence overall system SOp removal. Other parameters
such as solids recycle, inlet SOp concentration, inlet flue gas temperature,
and PM loading have less effect on SOp removal, but may have an impact on
reagent utilization.
To assess the performance of lime spray drying applied to coal-fired
industrial-commercial-institutional steam generating units, general
information concerning the overall long-term performance of this technology
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was obtained from three sites. At the first site, the lime spray drying
system operated on a coal-fired spreader stoker steam generating unit with a
heat input capacity of 34 MW (115 million Btu/hour). The steam generating
unit burned bituminous coal with a sulfur content that ranged from 400 ng
S02/J (0.93 Ib S02/million Btu) to 850 ng S02/J (1.99 Ib Stymillion Btu),
and averaged 570 ng S02/J (1.32 Ib S02/million Btu). The steam generating
unit load was maintained near 100 percent. The lime spray drying system
employed a fabric filter downstream of the spray dryer for particulate
matter emission control. Information on reagent ratio and the approach to
saturation temperature was not available. During a period of over 450 days,
the lime spray drying system operated at an average S02 removal level of 60
percent with a system reliability of 93 percent.
During a different period at this same site, the steam generating unit
burned bituminous coal with a sulfur content that ranged from 1,300 ng S02/J
(3.03 Ib S02/million Btu) to 3,580 ng S02/J (8.33 Ib S02/million Btu) and
averaged 1,960 ng S02/J (4.55 Ib S02/million Btu). The steam generating
unit load was again maintained near 100 percent. Over a 555-day period, the
lime spray drying system operated at an average 70.4 percent S0n removal
efficiency and a reliability level of 78 percent.
At the second site, the lime spray drying system operated on a
pulverized coal-fired steam generating unit with a heat input capacity of 69
MW (235 million Btu/hour). The steam generating unit burned bituminous coal
with a sulfur content that ranged from 330 ng S02/J (0.76 Ib S02/million
Btu) to 420 ng S02/J (0.98 Ib S02/million Btu) and averaged 390 ng S02/J
(0.91 Ib SOp/million Btu). The steam generating unit load varied from 71 to
91 percent of full load and averaged 82 percent. The lime spray drying
system operated at a reagent ratio that varied from 1.3 to 1.5 and averaged
1.4. Information on the approach to saturation temperature was not
available. The system employed a fabric filter downstream of the spray
dryer for particulate matter emissions control. Over a 795-day period, the
lime spray drying system operated at an average 75.8 percent S02 removal and
a reliability level of 83 percent.
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At the third site, the lime spray drying system serviced a coal-fired
spreader stoker steam generating unit with a heat input capacity of 69 MW
(235 million Btu/hour). The steam generating unit combusted bituminous coal
with a sulfur content that ranged from 2,280 ng SCL/J (5.30 Ib SOp/million
Btu) to 2,470 ng S02/J (5.75 Ib S02/million Btu) and averaged 2,300 ng S02/J
(5.35 Ib S02/million Btu). The steam generating unit load varied from 53 to
71 percent of full load and averaged 61 percent. The lime spray drying
system operated at an average reagent ratio of 1.07 and employed a fabric
filter for particulate matter emissions control. Information on the
approach to saturation temperature was not available. Over an 864-day
period, the system operated at an average 79.6 percent S02 removal
efficiency and a reliability level of 45 percent.
In addition to the general information outlined above, S02 emission
data were obtained from six sites to assess the performance of lime spray
drying systems. These data consist of four short-term and three long-term
tests. The first short-term test was a compliance test conducted over
approximately 2 hours using Reference Method 6 for S02 emission
measurements. The test results were used to determine compliance with
applicable S02 emission regulations for the new lime spray drying system
shortly after system startup and commissioning. The lime spray drying
system treated flue gas from a pulverized coal-fired steam generating unit
with a heat input capacity of 82 MW (280 million Btu/hour). The steam
generating unit burned bituminous coal with an average sulfur content of
1,430 ng S02/J (3.33 Ib S02/million Btu). The steam generating unit
operated at 100 percent of full load.
The S02 absorber was operated at an average 19°C (35°F) approach to
saturation temperature. Reagent ratio during the test was not recorded.
The system employed a fabric filter downstream of the spray dryer for
particulate matter collection. The SO,, removal efficiencies during six
sampling periods were 68.5, 73.3, 75.4, 76.0, 76.9, and 77.5 percent, for an
overall average of 74.5 percent.
The second short-term test was also conducted over approximately
2 hours using Reference Method 6 for S02 emission measurements. The lime
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P.78
spray drying system treated flue gas from a coal-fired spreader stoker steam
generating unit with a heat input capacity of 34 MW (115 million Btu/hour).
This unit was fired with a mixture of bituminous coal with an average sulfur
content of 2,530 ng SCL/J (5.89 Ib SCL/million Btu) and oil with an average
sulfur content of 410 ng S02/J (0.96 Ib S02/ million Btu). The steam
generating unit operated at approximately 75 percent of full load. Of the
total heat input to the unit, 94.2 percent was derived from coal and the
remainder from oil.
The spray dryer was operated at an average 14°C (25°F) approach to
saturation temperature. Reagent ratio was not recorded during the test. A
fabric filter was used downstream of the spray dryer for particulate matter
control. S02 removal efficiencies achieved during the six sampling periods
were 90.1, 90.3, 91.6, 92.3, 93.6, and 96.7 percent, for an overall average
of 92.4 percent.
A series of three short-term performance tests was conducted at a third
site. The three tests were performed over 8 hours using Reference Method 6
for S02 emission measurements. The steam generating unit at this site was a
coal-fired spreader stoker unit with a heat input capacity of 69 MW (235
million Btu/hour). The steam generating unit fired bituminous coal with an
average sulfur content of 2,190 ng S02/J (5.09 Ib S02/million Btu). During
the three test periods, the steam generating unit load was maintained at 35,
70, and 82 percent of full load.
The approach to saturation temperature for this lime spray drying
system was maintained at 13°C (23°F). A fabric filter was employed at this
site downstream of the spray dryer for particulate matter control. The
reagent ratio was varied during each testing period to obtain the following
results: 79.7 percent S02 removal at 0.6 reagent ratio; 89.9 percent S02
removal at 1.4 reagent ratio; and 95.6 percent S02 removal at 1.9 reagent
ratio.
- A second series of short-term performance tests was also conducted over
a 4-hour period at this same site. Reference Method 6 was used for S02
emission measurements as in the above tests. For this test series, the
steam generating unit fired bituminous coal with an average sulfur content
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of 2,840 ng S02/J (6.61 Ib S02/million Btu). During the test period, the
steam generating unit operated at loads that varied between 50 and 74
percent of full load.
Both the reagent ratio and approach to saturation temperature were
varied during the testing. At a 17°C (30°F) approach to saturation
temperature, S02 removal efficiencies of 64, 78, and 74 percent were
achieved with reagent ratios of 1.1, 1.2, and 1.3, respectively. Lowering
the approach to saturation temperature to 12°C (22°F) resulted in 80.8
percent SOp removal at a reagent ratio of 1.0. At a 11°C (20°F) approach to
saturation temperature, SOp removal efficiencies of 83, 87, 90, and 96
percent were achieved with reagent ratios of 1.1, 1.2, 1.3, and 1.6,
respectively.
The fourth short-term test was a compliance test conducted over three
1-hour periods using Reference Method 6 for S02 emission measurements. The
lime spray drying system treated flue gas from a pulverized coal-fired steam
generating unit with a heat input capacity of 69 MW (235 million Btu/hour).
The steam generating unit burned bituminous coal with an average sulfur
content of 410 ng SO^/J (0.96 Ib SO^/million Btu). The steam generating
unit operated at 100 percent of full load.
The spray dryer was operated at an approach to saturation temperature
that varied between 28° and 39°C (50° and 70°F). The reagent ratio was
approximately 3.3. The system employed a fabric filter downstream of the
spray dryer for particulate matter collection. The S02 removal efficiencies
during the three test periods were 95.8, 96.8, and 97.0 percent, for an
overall average of 96.6 percent.
The first long-term test was conducted over a 30-day period using
Reference Method 19A continuous SOp emission monitors for data collection on
both the inlet and outlet of a lime spray drying system. The system at this
site treated flue gas from a coal-fired industrial spreader stoker steam
generating unit with a heat input capacity of 44 MW (150 million Btu/hour).
The sulfur content of the bituminous coal fired by the steam generating unit
ranged from 1,040 ng S02/J (2.42 Ib S02/million Btu) to 1,830 ng S02/J (4.25
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P.80
lb SOp/million Btu) and averaged 1,330 ng S02/J (3.09 Ib S02/million Btu).
The steam generating unit load varied from 53 to 68 percent of full load.
The lime spray drying system employed a fabric filter for particulate
matter control downstream of the spray dryer. Reagent ratio and approach to
saturation temperature were not recorded during the test. Approximately 10
to 20 percent of the flue gas from the steam generating unit was bypassed
around the FGD system. During the 23 days on which SOp data were collected,
the overall SOp removal efficiency ranged from 56 to 82 percent and averaged
70 percent. Numerous operating problems were encountered with the steam
generating unit and the lime spray drying system during the first 17 days of
data collection. These operational problems were corrected and the lime
spray drying system operated in a normal manner during the final 6 days of
testing. The overall performance level averaged 78.5 percent S0? removal
during these last 6 days of testing.
Assuming a 10 percent flue gas bypass, the SOp removal efficiency
across the lime spray drying system would be about 78 and 87 percent during
the 23-day and 6-day periods, respectively. Assuming a 20 percent flue gas
bypass, the SOp removal efficiency across the lime spray drying system would
be about 88 and 98 percent during the 23-day and 6-day periods,
respectively. During the entire CEMS data collection period, the lime spray
drying system operated at an average reliability level of 73 percent* For
the last 6 days of testing, the lime spray drying system reliability was 97
percent.
The second long-term test was conducted over 28 days using Reference
Method 6B for SOp emission measurements on both the inlet and outlet of a
lime spray drying system. The steam generating unit at this site was a
coal-fired industrial spreader stoker steam generating unit with a heat
input capacity of 69 MW (235 million Btu/hour). The steam generating unit
fired subbituminous coal with a sulfur content that ranged from 2,200 ng
S02/J (5.12 lb S02/million Btu) to 2,350 ng S02/J (5.47 Ib S02/million Btu)
and averaged 2,280 ng S02/J (5.30 lb S02/million Btu). The steam generating
unit load ranged from 53 to 71 percent.
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The spray dryer was operated at a reagent ratio of 1.1 and an approach
to saturation temperature that varied between 9° and 16°C (17° and 29°F) and
averaged 15°C (27°F). The system included a fabric filter downstream of the
spray dryer for particulate matter control. During the 28 days over which
data were collected, S(L removal efficiency ranged from 82.2 to 92.1
percent, for an,average of 86.6 percent. The lime spray drying system
operated at a reliability level of 75 percent, excluding an electrical
problem not related to the FGD system.
The third long-term test was conducted over approximately 12 days using
Reference Method 19A continuous SCL emission monitors for data collection on
both the inlet and outlet of a lime spray drying system. The system
serviced a utility pulverized coal-fired steam generating unit with a heat
input capacity of approximately 300 MW (1,025 million Btu/hour). Although
utility steam generating units are significantly different in design and
operation than their smaller industrial-commercial-institutional
counterparts, the design and operation of lime spray drying systems for
these two applications are essentially the same. For this reason, utility
steam generating unit lime spray drying system performance is directly
applicable to industrial-commercial-institutional steam generating units.
The sulfur content of the bituminous coal burned during the test ranged from
2,330 ng S02/J (5.43 Ib S02/million Btu) to 2,580 ng S02/J (6.01 Ib
S02/million Btu) and averaged 2,510 ng S02/J (5.85 Ib S02/million Btu). The
steam generating unit operated at an average of 82 percent of full load.
The spray dryer at the utility steam generating unit was operated at an
average reagent ratio of 1.33 and an approach to saturation temperature
which averaged 10°C (18°F). The system included a fabric filter downstream
of the spray dryer for particulate matter control. During the 174-hour
period during which continuous S02 emission monitoring data were collected,
S02 removal efficiency averaged 88.1 percent. During the test period, the
lime spray drying FGD system operated at a reliability level of
approximately 85 percent.
The S02 removal performance data from the last 6 days of testing at the
second long-term test site discussed above were analyzed to determine their
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variability [i.e., relative standard deviation (RSD) and autocorrelation
(AC)] using an AR(1) time series statistical model as discussed earlier.
These data were selected for analysis because they represent the longest
period of Reference Method 19A continuous SOp emission monitoring data for a
lime spray drying system operating at normal conditions on an industrial
steam generating unit.
The 24-hour RSD and AC values of the data were found to be 18.6 percent
and 0.18, respectively, based on controlled S0? emissions. Using a 30-day
rolling average to determine performance (i.e., percent reduction in
emissions), the AR(1) model was used to project the maximum expected
variation in performance, assuming this maximum variation would only be
exceeded once in ten years. This once in ten years maximum expected
variation in performance on a 30-day rolling average basis was found to be
less than 3 percentage points.
Thus, SOp removal efficiency can be expected to vary by less than 3
percentage points above and below the mean SOp removal efficiency using a
data averaging period of 30 days. Consequently, to ensure that S02 removal
efficiency for a given lime spray drying system is consistently above a
minimum performance level, the system should be operated at a long-term
average performance level 3 percentage points above the minimum performance
level. If the system is operated in this manner, SOp removal performance
would be expected to fall below the minimum level only once in a ten-year
period. It follows, therefore, that a lime spray drying system should be
operated at a long-term average performance level of 93 percent or above to
ensure that the SO- emissions reduction for the system is consistently at or
above 90 percent.
All of the long-term performance data discussed above for lime spray
drying systems range from 60 to 80 percent reduction in SOp emissions. The
short-term performance data, however, indicate that lime spray drying
systems are capable of achieving performance levels in excess of 93 percent
reduction in SOp emissions.
The effect of operation at such a high level of performance on system
reliability is not clear. A review of the available data shows an apparent
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P.83
decrease in system reliability with increased system performance. However,
an examination of the reasons for decreased reliability shows that failures
were generally not the result of increased system stress, such as increased
solids flow rates resulting from higher reagent ratios or increased solids
recycle rates due to operation at higher performance levels. In fact, most
failures examined to date on one existing industrial lime spray drying
system appear to have been preventable. Improved operating and maintenance
procedures, maintaining an inventory of spare parts, and having parallel or
redundant key process components would have prevented most failures.
Conversations with the vendor of this system indicate that the majority of
industrial systems sold to date do not have the spare components inventory
and preventable maintenance program necessary to maintain high system
reliability.
This vendor believes high reliability can be achieved at high
performance levels and is prepared to offer a 95 percent reliability
guarantee on lime spray drying systems, irrespective of coal sulfur content
and SCL removal guarantees. Such a guarantee, however, would require the
customer to maintain a spare components inventory and follow the vendor's
recommended preventive maintenance program.
As a result, there appear to be no technical barriers to achieving
greater than 90 percent SOp removal with a lime spray drying system on a
sustained basis at high (90 percent) reliabilities.
5.3.3 Lime/Limestone Met Scrubbing
The second FGD technology that is considered to be demonstrated is
lime/limestone wet scrubbing. The five system parameters that have a major
influence on SO,, removal efficiency in lime and limestone FGD systems are
the contact area in the scrubber (determined primarily by scrubber type and
internal design), liquid-to-gas ratio, calcium-to-sulfur ratio, pH, and the
concentration of mass transfer additives in the absorber feed liquor. The
data gathered to assess the performance of lime and limestone wet scrubbing
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applied to coal-fired industrial-commercial-institutional steam generating
units consist of a short-term and a long-term emission test.
The short-term test was a performance test on a lime wet scrubbing
system conducted over three 1-hour periods using Reference Method 6 for SCL
emission measurements. The lime wet scrubbing system serviced two
coal-fired spreader stoker steam generating units with heat input capacities
of approximately 18 and 53 MW (60 and 180 million Btu/hour). The steam
generating units fired bituminous coal with an average sulfur content of
2,670 ng S02/J (6.2 Ib SO^million Btu). The steam generating unit load
ranged from approximately 75 to 84 percent of full load.
The S02 absorber design in this system was based on a configuration
consisting of a curtain of chains attached to the wall of a rotating kiln.
The lime slurry flow through the horizontal kiln was countercurrent to the
flue gas flow. No lime slurry recycle was employed; instead, the $pent
slurry was sent directly to an industrial wastewater pretreatment plant
after passing through the kiln. This scrubber operated at a liquid-to-gas
ratio of 67 £/m3 (0.5 gallon/1,000 actual ft3) and a feed slurry pH of 12 to
13. No mass transfer additive was used during this test, and the
calcium-to-sulfur ratio was not recorded.
During the performance test, SO,, emissions were measured at the outlet
of the FGD system but not at the inlet to the system. Thus, SOp removal
efficiency across the FGD system could not be calculated directly. However,
coal fed to the steam generating units was sampled and analyzed during the
performance test period. The three areas in this system where sulfur in the
feed coal could be removed are with the bottom ash from the steam generating
unit, with the fly ash captured by the particulate matter control device,
and in the FGD system. It is unlikely that significant amounts of sulfur
would be removed in the first two areas because of the low alkalinity
generally associated with ash from bituminous coal. Consequently, almost
all of the S02 removal would be by the wet lime scrubbing system.
Based on the sulfur and heat content of the feed coal, the average S02
removal efficiency across the entire plant (including steam generating
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units, participate matter control devices, and wet lime scrubbing system)
was 96 percent during the testing period.
The reliability of this system over several years of operation was
reported by the operator to be 95 percent. The long-term average steam
generating unit loads were reported to be 75 percent for the larger unit and
50 percent for the smaller unit, which translates to an average FGD system
load of approximately 71 percent.
The long-term test was conducted on a lime/limestone wet scrubbing
system using continuous SOp emission monitors for data collection at both
the inlet and outlet of the FGD system. Data were collected for a 30-day
period while the system used a limestone reagent and for 29 days during a
55-day period while the system used a lime reagent.
This scrubbing system serviced six coal-fired stoker steam generating
units with a total rated capacity of 62 MW (210 million Btu/hour). The wet
scrubbing system was designed to remove approximately 80 percent of inlet
SOp from combustion of a Midwestern bituminous coal having a sulfur content
between approximately 2,370 ng S02/J (5.5 Ib S02/million Btu) and 3,140 ng
SOp/J (7.3 Ib SOp/million Btu) using either lime or limestone reagent. The
SOp absorber was a vertical tower consisting of two inverted venturi
scrubbing stages. A unique feature of this system was the maintenance of
constant liquid and gas flow rates to the SOp absorber. This was done to
minimize the need for operator attention and response to changing process
conditions. Constant flows were achieved by fixing the lime slurry feed
pumps and induced draft fan upstream of the absorber at preset levels. At
reduced steam generating unit load conditions, tempering air was added via a
make-up stack upstream of the induced draft fan to offset reduced flue gas
flow from the steam generating units. The result was that gas flow to the
absorber was independent of load conditions, but SOp inlet concentration
varied with load.
During the 29-day data collection period when lime was used as the
reagent in the wet scrubbing system, the sulfur content of the bituminous
coal fired averaged 2,150 ng S02/J (5.0 Ib SOp/million Btu), with a range of
1,890 to 2,490 ng SOp/J (4.4 to 5.8 Ib S02/million Btu). During this period
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,£,88.
the steam generating unit load varied from 34 to 65 percent of full load.
The pH of the feed slurry averaged 7.3 during the testing period and ranged
on a daily average basis from 4.3 to 8.5. No mass transfer additives were
used during this test. The liquid-to-gas ratio and calcium-to-sulfur ratio
were not recorded during the test period. Over the 29-day data collection
period, the SOp removal efficiency ranged from 86.7 to 96.0 percent and
averaged 91.5 percent. During the entire 55-day test period, the lime wet
scrubbing FGD system operated at a reliability level of over 91 percent.
During the 30-day test period when limestone was used as the reagent in
the wet scrubbing system, the sulfur content of the bituminous coal burned
averaged about 2,150 ng SOp/J (5.0 Ib SOp/million Btu). During this period
the steam generating unit load varied from 30 to 67 percent of full load.
The pH of the feed slurry averaged 5.0 during the testing period and ranged
on a daily average basis from 4.6 to 5.5. Adipic acid was used as the mass
transfer agent during this test. It was added at an average rate of 4
kg/hour (9 Ib/hour), which resulted in an average concentration of 2,260
parts per million (ppm) in the feed slurry. The liquid-to-gas ratio and
calcium-to-sulfur ratio were not recorded during the test period. Over the
30-day data collection period, the SOp removal efficiency ranged from 90.0
to 97.4 percent and averaged 94.3 percent. The system operated at a
reliability level of 94 percent during the test period.
Lime and limestone wet scrubbing FGD SOp removal efficiencies at this
site were insensitive to changes in steam generating unit load over the
range observed. On utility FGD systems using lime or limestone, some
decrease in SOp removal performance has been observed with increased SOp
inlet concentration or increased load. To overcome full load effects, the
liquid-to-gas ratio, reagent ratio, or feed slurry pH could be adjusted.
At this site, increases in SOp inlet concentrations and increased load
occur simultaneously. The FGD system at this site, however, was not
designed to make adjustments in liquid-to-gas ratio, reagent ratio, or feed
slurry pH. Thus, the experience gained from the tests discussed above shows
that 91.5 and 94.3 percent SOp removals on high sulfur coal using lime and
limestone reagents, respectively, have been reliably and consistently
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achieved on an industrial steam generating unit operated at normal, but less
than maximum, load.
New lime or limestone wet scrubbing systems could be designed and
operated to maintain these high levels of performance by adjusting the
liquid-to-gas ratio upward at higher loads. In addition, a spray tower or
turbulent contactor absorber would likely be selected as the absorber vessel
in place of the two-stage venturi scrubber to provide sufficient mass
transfer area and gas residence time for increased S02 absorption. While
this type of system would inevitably require more operator attention to
process fluctuations, such systems have been successfully employed on
utility steam generating units and could be used on industrial-commercial-
institutional steam generating units.
These long-term data for lime and limestone wet scrubbing systems were
analyzed to determine their variability (i.e., RSD and AC) using an AR(1)
time series statistical model as discussed earlier. The 24-hour RSD and AC
values were found to be 42 percent and, 0.08, respectively, based on
controlled SO^ emissions. Using a 30-day rolling average to determine
performance (i.e., percent reduction in emissions), the AR(1) model was used
to project the maximum expected variation in performance, assuming this
maximum variation would only be exceeded once in ten years. This once in
ten years maximum expected variation in performance on a 30-day rolling
average basis was found to be less than 2 percentage points.
Thus, S0? removal efficiency can be expected to range by less than 2
percentage points above and below the mean S0? removal efficiency using a
data averaging period of 30 days. Consequently, to ensure that SOp removal
efficiency for a given lime or limestone wet scrubbing system is
consistently above a minimum performance level, the system should be
operated at a long-term average performance level 2 percentage points above
the minimum performance level. If the system is operated in this manner,
SOp removal performance would be expected to fall below the minimum level
only once in a ten-year period. It follows, therefore, that a lime or
limestone wet scrubbing system should be operated at a long-term average
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P.88
performance level of 92 percent or above to ensure that the SOp emissions
reduction for the system is consistently at or above 90 percent.
The long-term data presented above for lime and limestone FGD systems
show SOp removal efficiencies of 91.5 and 94.3 percent, respectively, which
are near or above the long-term average required to meet consistently a once
in ten year 30-day rolling average minimum performance level of 90 percent
emission reduction. Although these results were obtained at less than
maximum load conditions, new systems could achieve this level of performance
at full load by operating at a higher liquid-to-gas ratio. In addition, new
systems would likely be equipped with a spray tower or turbulent contact
absorber to provide increased mass transfer area and gas residence time for
improved SOp absorption.
Based on these analyses of system performance and system variability,
the lime wet scrubbing FGD technology is capable of reducing SOp emissions
from coal-fired industrial-commercial-institutional steam generating units
by 90 percent using a 30-day rolling average to calculate emission
reductions.
5.3.4 Dual Alkali Scrubbing
The third FGD technology that is considered to be demonstrated is dual
alkali wet scrubbing. The five system parameters which have a major
influence on SOp removal efficiency in dual alkali systems are contact area
in the scrubber (determined primarily by scrubber type and internal design),
liquid-to-gas ratio, calcium-to-sulfur ratio, sodium-to-sulfur ratio, and
pH. The data gathered to assess the performance of dual alkali scrubbing
applied to coal-fired industrial-commercial-institutional steam generating
units consist of four short-term and two long-term emission tests.
The first short-term test was an acceptance test conducted over three
1-hour periods using an SOp emission measurement method developed by the
Pennsylvania Department of Environmental Resources (PADER). An acceptance
test consists of a series of short-term emission measurements conducted
shortly after an FGD system has been commissioned to determine whether
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P.89
system performance conforms to design expectations or vendor guarantees.
The PADER method is similar to Reference Method 6 except that it captures
and analyzes SCL as well as S(L in the flue gas; Reference Method 6 captures
and analyzes only SCL. Because SCL is not readily absorbed in most FGD
systems, including dual alkali systems, the S0? removal efficiency measured
with the PADER method will be slightly lower than the efficiency measured
with Reference Method 6 under identical conditions.
The dual alkali wet scrubbing system at this site serviced two
pulverized coal-fired steam generating units, each with a heat input
capacity of 156 MW (531 million Btu/hour). Flue gas from each unit was
directed to a separate SCL absorber. The spent scrubbing solution from each
absorber was sent to a single regeneration section. This acceptance test
was conducted on the first absorber serving a single steam generating unit.
The steam generating unit fired bituminous coal with a sulfur content of
2,260 ng SCL/J (5.25 Ib SCL/million Btu). The steam generating unit load
was approximately 97 percent of full load.
The SCL absorber in this system was a vertical tower in which flue gas
flowed upward through four stages of disc and doughnut baffles. Scrubbing
liquor flowed countercurrent to the flue gas at a design liquid-to-gas ratio
of 1,340 fc/m3 (10 gall on/1,000 ft3). The dual alkali FGD system operated at
a calcium-to-sulfur molar ratio of 1.0 and a ratio of 0.065 mole of sodium
(as sodium carbonate) per mole of S02 absorbed. The pH of the scrubbing
liquor was controlled near 6.5. The S02 removal efficiencies were 83.3,
86.1, and 86.8 percent during the three 1-hour tests, for an average of 85.4
percent.
The second short-term test was a 3-hour acceptance test conducted on
the second absorber at the same facility. The second absorber serviced a
single steam generating unit operated at 93 percent of full load. All other
conditions were the same except that the scrubbing liquor pH was reported to
be higher than normal. The S02 removal efficiencies of this system were
90.5, 90.8, and 91.0 percent during the three 1-hour tests, for an average
of 90.8 percent.
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P.90
The overall reliability of this system (including both the first
absorber, the second absorber, and a third absorber installed in the system
subsequent to the acceptance tests described above) during the 12 months of
1981 was reported by the operator to be over 97 percent.
The third short-term test was a performance test conducted over three
1-hour periods using Reference Method 6 for SCL emission measurement. The
dual alkali wet scrubbing system serviced three coal-fired stoker steam
generating units with heat input capacities of 14 MW (25 million Btu/hour)
for Units No. 3 and 4 and 49 MW (85 million Btu/hour) for Unit No. 5. The
dual alkali system consisted of two SCL absorbers and a single regeneration
section. During the performance test, only steam generating Units No. 3 and
5 were operated. Flue gas from Unit No. 3 was directed to Absorber A while
flue gas from Unit No. 5 was directed to Absorber B. Steam generating Unit
No. 3, the subject of this performance test, was fired with bituminous coal
with an average sulfur content of 2,360 ng SC^/O (5.49 Ib S02/million Btu).
The steam generating unit load was approximately 78 percent of full load.
This corresponded to approximately 43 percent of the Absorber A design
capacity.
The SCL absorber in this system was a venturi-type scrubber. The
33
liquid-to-gas ratio was maintained near 4,700 £/m (35 gallon/1,000 ft ).
The pH of the scrubbing liquor averaged 6.0. The calcium-to-sulfur and
sodium-to-sulfur ratios were not reported. The SOp removal efficiency was
85.6, 86.4, and 91.9 percent during the three 1-hour tests, for an average
of 88.1 percent.
The fourth short-term test was a 3-hour performance test conducted on
Unit No. 5 of the same facility immediately following the above test. Steam
generating Unit No. 5 combusted the same coal as Unit No. 3 and operated at
approximately 65 percent of full load. This corresponded to approximately
59 percent of the Absorber B design capacity.
Absorber B was also a venturi-type scrubber. The liquid-to-gas ratio
was maintained near 5,400 £/m3 (40 gallon/1,000 ft ). The pH of the
scrubbing liquor averaged 7.1. The calcium-to-sulfur and sodium-to-sulfur
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P.91
ratios were not reported. The SCL removal efficiencies were 87.7, 96.9, and
97.9 percent during the three 1-hour tests, for an average of 94.2 percent.
The first long-term test was conducted over 17 days using continuous
SOp emission monitors for data collection on both the inlet and outlet of
the FGD system. The dual alkali wet scrubbing system at this site serviced
two coal-fired spreader stoker steam generating units with heat input
capacities of 40 MW (135 million Btu/hour) for Unit No. 1 and 23 MW (77
million Btu/hour) for Unit No. 3. The dual alkali system consisted of two
SOp absorbers, each serving a separate steam generating unit, and a single
regeneration section. The sulfur content of the bituminous coal received at
the plant during the test averaged 1,490 ng 50,,/J (3.47 Ib S02/million Btu)
with a range of 1,340 to 1,670 ng S02/J (3.12 to 3.88 Ib S02/million Btu).
During the test, the steam generating units also burned oil with an average
sulfur content of 320 ng S02/J (0.74 Ib S02/million Btu) and a range of 270
to 370 ng S02/J (0.62 to 0.86 Ib S02/million Btu), based on deliveries
received during the testing period. On a thermal input basis, coal
represented 92.5 percent of the fuel burned during this period for both
steam generating units; the balance of the heat input was supplied by oil.
Steam generating Unit No. 1, the subject of this test, operated at an
average load of 67 percent of full load. The load varied between 42 and 96
percent during the testing period.
In the Unit No. 1 scrubber, flue gases flowed countercurrent to the
aqueous scrubbing solution. The two streams were brought into contact by
means of two absorption trays fitted with self-adjusting bubble caps. The
absorber operated at a design liquid-to-gas ratio of 2,680 &/m (20
gallon/1,000 ft ). The calcium-to-sulfur ratio ranged from 1.32 to 1.90
mole of calcium per mole of sulfur in the filter cake. The sodium-to-sulfur
ratio varied between 0.028 and 0.05 mole of sodium carbonate (Na9CO,) per
£ O
mole of SOp removed. The pH of the scrubbing liquor ranged from 5.7 to 6.5
and averaged 6.0. Over the 17-day data collection period, the S0? removal
efficiency ranged from 87.6 to 95.2 percent and averaged 91.6 percent.
During the test period, the dual alkali scrubbing FGD system operated at a
reliability level of 100 percent.
5-44
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The second.long-term test was conducted on steam generating Unit No. 3
of the same facility shortly after the above test. Data were collected over
a 24-day period using continuous SOp emission monitors on both the inlet and
outlet of the FGD system. The fuel analysis for coal and oil burned during
the test and the heat input ratio of coal and oil were the same as that for
Unit No. 1. Steam generating unit load varied between 5 and 95 percent
during the testing period and averaged 62 percent of full load based on
coal-fired heat input capacity.
The SO- absorber design, liquid-to-gas ratio, calcium-to-sulfur ratio,
and sodium-to-sulfur ratio were the same as that for Unit No. 3. The pH of
the scrubbing liquor ranged from 4.7 to 6.5 and averaged 6.0. Over the
24-day collection period, the SOp removal ranged from 73.6 to 97.1 percent
and averaged 92.2 percent. During the test period, the dual alkali
scrubbing FGD system operated at a reliability level of 100 percent.
During both of the long-term performance tests, the S02 removal
efficiency was insensitive to changes in steam generating unit and FGD
system load over the range observed. Dual alkali wet scrubbing systems,
however, operate with a scrubbing liquor sodium concentration that is
greatly in excess of the theoretical amount required for SOp absorption. As
a result, S02 removal performance is not mass transfer limited, but is
determined by the equilibrium conditions of the scrubbing liquor. These
conditions are governed primarily by the concentration of active sodium
species. Consequently, increasing the SOp loading on the system, either by
increasing the flue gas flow rate or SOp concentrations, would not seriously
deplete excess active sodium species nor affect feed liquor pH in the short
run. Thus, SO- removal performance will be relatively independent of load
and inlet SO- concentration if vigorous gas-liquid contact is maintained in
the absorber and the sodium-to-sulfur and liquid-to-gas ratios are
maintained at a constant level.
This is verified by statistical analysis of the SOp performance data
from the 17- and 24-day tests showing that SOp removal efficiency was
independent of SOp inlet concentration. It follows, therefore, that
variations in steam generating unit load would similarly not affect SOp
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P.93
removal. The 24-day test shows that 92.2 percent SOp removal on high sulfur
coal can be reliably and consistently achieved on an industrial steam
generating unit operated at normal, but less than maximum, load. A dual
alkali wet scrubbing system could also operate at this level of performance
under full load conditions by adjusting the reagent addition rate and
scrubbing liquor feed rate upward to maintain constant sodium-to-sulfur and
liquid-to-gas ratios.
These long-term data for dual alkali wet scrubbing systems were
analyzed to determine their variability (i.e., RSD and AC) using an AR(1)
time series statistical model as discussed earlier. The 24-hour RSD and AC
values of the data were found to be 33 percent and 0.13, respectively, based
on controlled SOp emissions. Using a 30-day rolling average to determine
performance (i.e., percent reduction in emissions), the AR(1) model was used
to project the maximum expected variation in performance, assuming this
maximum variation would only be exceeded once in ten years. This once in
ten years maximum expected variation in performance on a 30-day rolling
average basis was found to be less than 2 percentage points.
Thus, SOp removal efficiency can be expected to vary by less than 2
percentage points above and below the mean SOp removal efficiency using a.
data averaging period of 30 days. Consequently, to ensure that SOp removal
efficiency for a given dual alkali wet scrubbing system is consistently
above a minimum performance level, the system should be operated at a
.long-term average performance level 2 percentage points above the minimum
performance level. If the system is operated in this manner, SOp removal
performance would be expected to fall below the minimum level only once in a
ten-year period. It follows, therefore, that a dual alkali wet scrubbing"
system should be operated at a long-term average performance level of 92
percent or above to ensure that the SOp emissions reduction efficiency for
the system is consistently at or above 90 percent.
The dual alkali system average performance during the second long-term
test was 92.2 percent, which is equivalent to the long-term average required
to meet consistently a once in ten year 30-day rolling average minimum
performance level of 90 percent emission reduction. Although this
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P.94
performance level was achieved at a steam generating unit and FGD system
load of only 62 percent, this same level of performance can be achieved by a
new dual alkali wet scrubbing system at full load conditions if vigorous
gas-liquid contact is maintained in the absorber and the sodium-to-sulfur
and liquid-to-gas ratios are maintained at a level sufficient to provide an
adequate supply of active sodium species.
Based on these analyses of system performance and system variability,
the dual alkali wet scrubbing FGD technology is capable of reducing S(L
emissions from coal-fired industrial-commercial-institutional steam
generating units by 90 percent using a 30-day rolling average to calculate
emission reductions.
5.3.5 Sodium Wet Scrubbing
The fourth FGD technology that is considered to be demonstrated for
industrial-commercial-institutional steam generating units is sodium wet
scrubbing. The three system parameters that have a major influence on S02
removal efficiency in sodium scrubbing systems are contact area in the
scrubber (determined primarily by scrubber type-' and internal design),
sodium-to-sulfur ratio, and pH. The data gathered to assess the performance
of sodium wet scrubbing applied to coal-fired and oil-fired industfial-
commercial-institutional steam generating units consist of 12 short-term
emission tests, one long-term emission test, and reliability data from two
sites accounting for a total of 16 sodium wet scrubbers.
A long-term emission test was conducted over a 30-day period at a
coal-fired industrial-commercial-institutional steam generating unit using
continuous SCL emission monitors for data collection on both the inlet and
outlet of the scrubber. The FGD system was designed to service two
coal-fired steam generating units with a total rated heat input capacity of
94 MW (320 million Btu/hour). During the test period, flue gas from only
one unit, a pulverized coal-fired steam generating unit, was directed to the
FGD system. The sulfur content of the subbituminous coal burned during the
test ranged between 3.55 and 3.73 weight percent. This corresponded to a
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P.95
flue gas SCL concentration at the1 scrubber inlet that ranged from 1,980 ng
S02/J (4.6 Ib S02/million Btu) to 2,7-10 ng S02/J (6.3 Ib S02/million Btu).
During this period, the pulverized coal-fired steam generating unit load
varied from 33-to 80 percent of full load. This corresponded to 22 to 52
percent of FGD system design capacity.
The S02 absorber in this system was a tray and quench liquid scrubber.
Sodium hydroxide was used as the absorption reagent and was added in the
form of a 50 percent solution with water at a rate of 132 £/minute (35
gallon/minute). This corresponded to a sodium-to-sulfur molar ratio of
approximately 27 to 1 based on the inlet flue gas S0? loading. The pH of
the feed liquor averaged 8.1 during the testing period and ranged on a daily
average basis from 7.8 to 8.8. Over the 30-day data collection period, the
S02 removal efficiency ranged from 95.4 to 97.7 percent and averaged 96.3
percent. The sodium wet scrubbing FGD system operated at a reliability
level of 100 percent during the test period.
The S02 removal efficiency was insensitive to changes in steam
generating unit and FGD system load over the range observed during the test.
Sodium wet scrubbing systems, however, operate with a scrubbing liquor
sodium concentration that is greatly in excess of the theoretical amount
required for S02 absorption. As a result, S02 removal performance is not
mass transfer limited, but is determined by the equilibrium conditions of
the scrubbing liquor. These conditions are governed primarily by the
concentration of active sodium species. Consequently, increasing the S02
loading on the system, either,by increasing the flue gas flow rate or S02
concentrations, would not seriously deplete excess active sodium species nor
affect feed liquor pH in the short run. thus, S0? removal performance will.
be relatively independent of load and inlet S02 concentration if vigorous
gas-liquid contact is maintained in the absorber and the sodium-to-sulfur
and liquid-to-gas ratios are maintained at a constant level.
This is verified by statistical analysis of the S02 performance data
from the 30-day test showing that S0? removal efficiency was independent of
S02 inlet concentration. It follows, therefore, that variations in steam
generating unit load would similarly not affect S02 removal.
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P.96
This test shows that 96.3 percent SO,, removal on high sulfur coal can
be reliably and consistently achieved on an industrial steam generating unit
operated at normal, but less than maximum, load. A sodium wet scrubbing
system could also operate at this level of performance under full load
conditions by adjusting the reagent addition rate and scrubbing liquor feed
rate to maintain constant sodium-to-sulfur and liquid-to-gas ratios.
These long-term data for sodium wet scrubbing systems were analyzed to
determine their variability (i.e., RSD and AC) using an AR(1) time series
statistical model as discussed earlier. The 24-hour RSD and AC values of
the data were found to be 34 percent and 0.13, respectively, based on
controlled SOp emissions. Using a 30-day rolling average to determine
performance (i.e., percent reduction in emissions), the AR(1) model was used
to project the maximum expected variation in performance, assuming this
maximum variation would only be exceeded once in ten years. This once in
ten years maximum expected variation in performance on a 30-day rolling
average basis was found to be less than 1 percentage point.
Thus, SOp removal efficiency can be expected to vary by less than 1
percentage point above and below the mean SOp removal efficiency using a
data averaging period of 30 days. Consequently, to ensure that SOp removal
efficiency for a given sodium wet scrubbing system is consistently above a
minimum performance level, the system should be operated at a long-term
average performance level 1 percentage point above the minimum performance
level. If the system is operated in this manner, SOp removal performance
would be expected to fall below the minimum level only once in a ten-year
period. It follows, therefore, that a sodium wet scrubbing system should be
operated at a long-term average performance level of 91 percent or above to
ensure that the SOp emissions reduction efficiency for the system is
consistently at or above 90 percent.
The sodium wet scrubbing system average performance during the 30-day
test was 96.3 percent, which is well above the long-term average required to
meet consistently a once in ten year 30-day rolling average minimum
performance level of a 90 percent reduction in SOp emissions. Although this
performance level was achieved at an FGD system load of only 22 to 52
5-49
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percent of design capacity, this same level of performance can be achieved
by a new sodium wet scrubbing system at full load conditions if rigorous
gas-liquid contact is maintained in the absorber and the sodium-to-sulfur
and liquid-to-gas ratios are maintained at the same level to provide an
adequate supply of active sodium species.
In addition to long-term performance data from coal-fired steam
generating units, short-term performance data have also been gathered for
sodium wet scrubbing systems applied to oil-fired industrial-commercial -
institutional steam generating units. Short-term performance data are
available from 12 sites where data were collected by Reference Method 8,
typically over a 3-hour period. In each case, a sodium wet scrubbing system
serviced an oil-fired steam generating unit ranging in size from 15 MW (50
million Btu/hour) to 63 MW (210 million Btu/hour) heat input capacity. The
sulfur contents of the oils burned ranged from about 260 to 650 ng SOp/J
(0.6 to 1.5 Ib S02/million Btu). Steam generating unit load information was
not recorded.
A number of different absorber designs were represented by these tests,
including a tray absorber, venturi scrubber, spray baffle, and liquid jet
eductor. Sodium-to-sulfur ratios and pH levels were not recorded. The S02
removal efficiencies of the 12 sodium wet scrubbing systems ranged from 90.0
to 99.4 percent.
In addition to these data, other data have also been reported for
sodium wet scrubbing systems applied to oil-fired industrial steam
generating units. At one site, a single sodium wet scrubbing unit reduced
SOp emissions from the combined flue gases of 5 package steam generating
units, each rated at 17 MW (57 million Btu/hour) heat input capacity. The
steam generating units burned crude oil with a sulfur content that ranged
from 960 to 1,810 ng S02/J (2.22 to 4.22 Ib S02/nrillion Btu). Two of the
units were idle during the performance period, two operated at 50 percent
average load, and one operated at 95 percent average load. The combined
average load on the FGD system was approximately 40 percent. The S02
absorber in this system consisted of a venturi eductor followed by a spray
tower. The scrubbing liquor pH was maintained at 7.0. The sodium-to-sulfur
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P.98
ratio was not reported. The sodium wet scrubbing system performed at 95
percent S(L removal on average. Over an approximate 4-year period, this
system operated at a reliability level near 98 percent.
At a second site, a total of 15 sodium wet scrubbers serviced a total
of 19 package oil-fired steam generating units. The steam generating units
ranged in size from 7 to 15 MW (25 to 50 million Btu/hour) heat input
capacity. However, since in some cases multiple steam generating units were
ducted to a single sodium wet scrubbing system, the size of the FGD systems
ranged from 7 to 73 MW (25 to 250 million Btu/hour) equivalent heat input
capacity. The steam generating units burned crude oil with a sulfur content
which ranged from 720 to 830 ng S02/J (1.67 to 1.94 Ib S02/million Btu)*
All the steam generating units operated at an average load near 85 percent
of capacity. The S02 absorbers in these systems included tray absorbers,
horizontal spray towers, and venturi scrubbers. The scrubber liquor pH was
maintained near 7.0 in all cases. Sodium-to-sulfur ratios were not
reported. The sodium wet scrubbing systems all operated at approximately 95
percent SO^ removal on average. All systems operated at reliability levels
in excess of 99 percent over time periods ranging from 6 to 12 months.
Based on these analyses of system performance and system variability,
sodium wet scrubbing FGD technology is capable of reducing S02 emissions
from coal-fired and oil-fired industrial-commercial-institutional steam
generating units by 90 percent using a 30-day rolling average to calculate
emission reductions.
5.4 PARTICULATE MATTER EMISSIONS FROM OIL COMBUSTION
Currently, the performance of particulate matter control techniques is
measured with Reference Method 5. However, Reference Method 5 has been
found to be subject to interference with sulfur oxides, which effectively
increases measured particulate matter emissions above true values. As a
result, a new reference method is under development - Reference Method 5b -
that greatly reduces the problem of sulfur oxide interference. This new
reference method was proposed on May 29, 1985 (50 FR 21863).
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P.99
Reference Method 5b consistently results in equivalent or lower
particulate matter emission measurements, with the most significant
reduction being observed when measuring particulate matter emissions from
the combustion of high sulfur fuels. A comparative analysis shows a 35 to
50 percent reduction in measured particulate matter emissions when Reference
Method 5b is used in place of Reference Method 5 to measure the performance
of electrostatic precipitation in reducing particulate matter emissions from
combustion of high sulfur fuel oils.
Most of the emission performance data discussed below, however, was
collected prior to the development of Reference Method 5b. Consequently,
the performance of wet scrubbers and electrostatic precipitators (and to
some extent, the performance of low sulfur oil) for the control of
particulate matter emissions from oil-fired steam generating units may be
somewhat greater than that discussed below based on the use of Reference
Method 5.
The three emission control technologies considered demonstrated for the
purpose of developing standards of performance limiting particulate matter
emissions from oil-fired industrial-commercial-institutional steam
generating units are the use of low sulfur oil and the use of "add-on"
control techniques, such as electrostatic precipitators or wet scrubbers.
5.4.1 Low Sulfur Oil
As discussed earlier, fuel oils are generally classified by sulfur
content (see Table 4-1). This classification scheme based on sulfur content
has its origins in the classifications used by the U.S. Department of Energy
to report refinery production data and in studies for fuel oil use patterns.
To determine the performance of low sulfur oil in reducing particulate
matter emissions, data were collected using Reference Method 5 from three
steam generating units burning a fuel oil having a fuel sulfur content of
129 ng S02/J (0.3 Ib S02/million Btu) or less. The heat input capacities of
these three units were 320, 355, and 600 MW (1,096, 1,215 and 2,055 million
5-52
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P.1
Btu/hour). Each of the three steam generating units exhibited participate
matter emission rates of 9 ng/J (0.02 Ib/million Btu) heat input.
A review of the data from over 100 steam generating units that were
used to establish the relationship between fuel oil sulfur content and
emissions of particulate matter from oil combustion presented in the manual,
"Compilation of Air Pollutant Emission Factors" (AP-42), indicates that fuel
oils having a sulfur content of 129 ng S02/J (0.3 Ib S02/million Btu) or
less are capable of reducing emissions of particulate matter to levels of 17
ng/J (0.04 Ib/million Btu) heat input or less.
As a result, the use of fuel oils having sulfur contents less than or
equal to 129 ng S02/J (0.3 Ib S02/million Btu) will reduce particulate
matter emissions from industrial-commercial-institutional steam generating
units to 17 ng/J (0.04 Ib/million Btu) heat input or less.
Emission test data using Reference Method 5 were collected for fifteen
steam generating units with heat input capacities ranging from 41 to 400 MW
(140 to 1,360 million Btu/hour). When combusting fuel oils with a sulfur
content of 129 to 344 ng S02/J (0.3 to 0.8 Ib S02/million Btu), the
particulate matter emissions from thirteen of the steam generating units
ranged from 9 to 43 ng/J (0.02 to 0.10 Ib/million Btu) heat input.
Particulate matter emissions from the remaining two steam generating units
were 65 and 82 ng/J (0.15 and 0.19 Ib/million Btu) heat input. Contacts
with the personnel at,these two units revealed that the measured particulate
matter emissions were uncharacteristically high and were the result of
injection nozzle problems that led to poor combustion conditions. This was
supported by the existence of two other steam generating units burning the
same residual fuel oil and exhibiting particulate matter emissions of 17 and
30 ng/J (0.04 and 0.07 Ib/million Btu) heat input.
Review of the data from over 100 steam generating units that were used
to establish the relationships between fuel oil sulfur content and emissions
of particulate matter in the manual, "Compilation of Air Pollutant Emission
Factors" (AP-42), indicates that fuel oils having a sulfur content between
129 and 344 ng S02/J (0.3 and 0.8 Ib S02/million Btu) are capable of
5-53
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P.2
reducing emissions of participate matter to levels of approximately 30 ng/J
(0.07 ID/million Btu) heat input.
The use of low sulfur fuel oils having sulfur contents less than or
equal to 344 ng SOp/J (0.8 Ib S02/million Btu), therefore, will reduce
particulate matter emissions from industrial-commercial-institutional steam
generating units to 43 ng/J (0.10 Ib/million Btu) heat input or less.
Emission test data using Reference Method 5 were collected from
twenty-three steam generating units ranging in heat input capacities from 28
to 400 MW (94 to 1,360 million Btu/hour). When combusting fuel oils having
sulfur contents between 344 and 645 ng SOp/J (0.8 and 1.5 Ib SOp/million
Btu), the particulate matter emissions from twenty-two of the steam
generating units ranged from 17 to 60 ng/J (0.04 to 0.14 Ib/million Btu)
heat input. The particulate matter emissions from one of the twenty-three
units were 73 ng/J (0.17 Ib/million Btu) heat input. Close examination of
the other steam generating units at this site, however, indicated that
average particulate matter emission rates of 52 ng/J (0.12 Ib/million Btu)
heat input were achieved while combusting the same type of fuel oil. These
observations indicate that the steam generating unit emitting 73 ng/J (0.17
Ib/million Btu) heat input was experiencing problems with poor combustion,
and that proper combustion conditions would reduce the particulate matter
emissions to 52 ng/J (0.12 Ib/million Btu) heat input.
Review of the data from over 100 steam generating units that were used
to develop the relationship between fuel oil sulfur content and emissions of
particulate matter presented in the manual, "Compilation of Air Pollutant
Emission Factors" (AP-42), indicates that fuel oils having sulfur contents
less than 645 ng SOp/J (1.5 Ib SOp/million Btu) are capable of reducing
emissions of particulate matter to levels of approximately 52 ng/J (0.12
Ib/million Btu) heat input.
As a result, the use of an intermediate sulfur fuel oil having a sulfur
content of less than or equal to 645 ng SO?/J (1.5 Ib SOp/million Btu) will
reduce particulate matter emissions from industrial-commercial-institutional
steam generating units to 60 ng/J (0.14 Ib/million Btu) heat input or less.
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P.3
5.4.2 Add-On Control Techniques
To determine the performance of electrostatic precipitators in reducing
particulate matter emissions from oil combustion, emission data were
collected from eight steam generating units equipped with electrostatic
precipitators using Reference Method 5. Two of these steam generating units
had heat input capacities of 28 MW (94 million Btu/hour) and burned a fuel
oil with a sulfur content of 301 ng S02/J (0.7 Ib S02/million Btu). The
particulate matter emission rates as measured by Reference Method 5 averaged
24 and 30 ng/J (0.055 and 0.07 Ib/million Btu) heat input.
Three steam generating units were tested which had individual heat
input capacities of 1,611 MW (5,500 million Btu/hour) and burned a fuel oil
with a sulfur content of 946 ng S02/J (2.2 Ib S02/million Btu). The
particulate matter emission rates as measured by Reference Method 5b
averaged 18, 19, and 21 ng/J (0.041, 0.045, and 0.049 Ib/million Btu) heat
input for the three units.
Finally, three steam generating units with individual heat input
capacities of 322 MW (1,100 million Btu/hour) were tested with Reference
Method 5 while burning a fuel oil with a sulfur content of 796 ng S02/J
(1.85 Ib S0?/million Btu). The particulate matter emissions from these
three units averaged 25, 29, and 30 ng/J (0.057, 0.067, and 0.070 Ib/million
Btu) heat input.
Electrostatic precipitators, therefore, will reduce particulate matter
emissions from oil-fired industrial-commercial-institutional steam
generating units to 30 ng/J (0.07 Ib/million Btu) heat input or less.
To determine the performance of wet scrubbers in reducing particulate
matter emissions from oil combustion, emission data were collected from
seven steam generating units equipped with wet scrubbers using Reference
Method 5. All seven of these wet scrubbers were designed for control of
both particulate matter emissions and sulfur oxide emissions. Two steam
generating units with a heat input capacity of 17 MW (57 million Btu/hour)
were equipped with steam venturi eductors followed by spray tower wet
scrubbers. The steam generating units burned fuel oils with fuel sulfur
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contents of 473 and 1,204 ng S02/J (1.1 and 2.8 Ib S02/million Btu), and
achieved participate matter emission levels of 22 and 43 ng/J (0.05 and 0.1
Ib/million Btu) heat input, respectively.
Two steam generating units, with a heat input capacity of 15 MW (50
million Btu/hour), equipped with venturi scrubbers that operated at a
liquid-to-gas ratio of 21,400 £/m3 (160 gallons/1,000 ft3) were tested. The
steam generating units burned fuel oils with fuel sulfur contents of 560 and
730 ng S02/J (1.3 and 1.7 Ib S02/million Btu) and achieved particulate
matter emission levels of 38 and 30 ng/J (0.09 and 0.07 Ib/million Btu) heat
input, respectively.
Two spray tower wet scrubbers were also tested, one serving a 7 MW (25
million Btu/hour) heat input steam generating unit and one serving five 15
MW (50 million Btu/hour) heat input steam generating units. Both scrubbers
employed three trays and operated at a liquid-to-gas ratio of 2,675 £/m (20
gallons/1,000 ft ). The smaller steam generating unit burned fuel oil with
a sulfur content of 645 ng S02/J (1.5 Ib S02/million Btu) and the five
larger steam generating units burned fuel oil with a sulfur content of 473
ng S02/J (1.1 Ib S02/million Btu). These two tray scrubbers achieved
particulate matter emission rates of 34 and 26 ng/J (0.08 and 0.06
Ib/million Btu) heat input.
Finally, a single steam generating unit with a heat input capacity of
15 MW (50 million Btu/hour) and equipped with a horizontal spray-baffle wet
3
scrubber was tested. The liquid-to-gas ratio during the test was 6,000 £/m
(45 gallons/1,000 ft ). During the combustion of fuel oil with a sulfur
content of 645 ng S02/J (1.5 Ib S02/million Btu), the horizontal
spray-baffle wet scrubber reduced emissions of particulate matter to 34 ng/J
(0.08 Ib/million Btu) heat input.
Each of the seven wet scrubbers discussed above achieved SOp emission
reductions of 92 percent or greater while achieving particulate matter
emission levels of 43 ng/J (0.1 Ib/million Btu) heat input or less. As a
result, wet scrubbing systems, including those designed for S0? emission
control, are capable of reducing particulate matter emissions from oil-fired
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industrial-commercial-institutional steam generating units to 43 ng/J (0.1
Ib/million Btu) heat input or less.
5.5 PARTICULATE MATTER EMISSIONS FROM COAL COMBUSTION
The use of a flue gas desulfurization system to control particulate
matter emissions from coal combustion is considered a demonstrated
particulate matter emission control technology. The performance of FGD
systems in controlling particulate matter emissions was assessed for both
coal-fired stoker steam generating units and pulverized coal-fired steam
generating units.
As discussed above, Reference Method 5 has been found to be subject to
interference from sulfur oxides. Thus, a new reference method that
minimizes this problem of interference - Reference Method 5b - is,currently
under development. Measurements obtained through the use of Reference
Method 5b can be as much as 50 percent lower than measurements obtained
through the use of Reference Method 5.
To assess the performance of wet scrubber FGD systems in reducing
particulate matter emissions, data were gathered from three industrial
coal-fired stoker steam generating units. At the time these data were
gathered, the problem mentioned above of sulfur oxide interference
associated with the use of Reference Method 5 was recognized. Because the
problem results, in part, from the condensation of sulfuric acid mist on the
particulate matter collection filter, an attempt was made to minimize
condensation, and hence sulfur oxide interference, by maintaining the
collection filter at a temperature above the sulfuric acid dew point. Thus,
the filter was maintained at a temperature of 177°C (350°F).
Although this was found to reduce sulfur oxide interference, subsequent
testing during the development of Reference Method 5b indicated that
condensation in the probe can also be a significant contributor to this
problem of interference. Consequently, Reference Method 5b also maintains
the probe as well as the filter at elevated temperatures. Reference
Method 5b is also somewhat different from Reference Method 5 in several
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P.6
other aspects. Thus, even though the temperature of the collection filter
was maintained at an elevated temperature during these tests, the use of
Reference Method 5b would yield lower particulate matter emission levels.
The three coal-fired stoker steam generating units tested ranged in
size from 24 to 69 MW (80 to 236 million Btu/hour) heat input capacity, and
operated at loads of from 73 to 92 percent of capacity. The coals fired
during the tests had sulfur contents ranging from 1.3 to 2.6 weight percent,
and ash contents ranging from 4.4 to 11.4 weight percent. With operating
pressure drops in the FGD scrubbers of 7.5 to 19.3 inches of water,
particulate matter emission levels were reduced to 30 to 43 ng/J (0.7 to
0.10 lb/million Btu) heat input.
Data were also gathered to assess the performance of wet scrubber FGD
systems applied to pulverized coal-fired steam generating units. Two
pulverized coal-fired steam generating units equipped with venturi scrubber
FGD systems were tested. At the time these data were being gathered, the
problem of sulfur oxide interference associated with the use of Reference
Method 5 was not recognized. As a result, these data were gathered through
the use of Reference Method 5. The use of Reference Method 5b, therefore,
would yield lower particulate matter emission levels.
The two pulverized coal-fired steam generating units tested had heat
input capacities of 29 and 40 MW (100 and 137 million Btu/hour) and were
both operated at a load of 100 percent. The coals fired during the tests
had sulfur contents ranging from 3.5 to 3.9 weight percent, and ash contents
ranging from 12 to 15 weight percent. With operating pressure drops in the
FGD scrubbers of 9 and 21 inches of water, average particulate matter
emissions from each steam generating unit were reduced to less than 30 ng/J
(0.07 lb/million Btu) heat input.
These data are representative of the performance of wet scrubber FGD
systems on stoker and pulverized coal-fired steam generating units firing
high ash coals at high steam generating unit loads. Both of these
conditions contribute to relatively high uncontrolled particulate matter
emission rates and thus represent the performance of wet scrubber FGD
systems under relatively adverse conditions. Therefore, wet scrubbing FGD
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P.7
systems installed on coal-fired industrial-commercial-institutional steam
generating units are capable of reducing particulate matter emissions from
these units to 43 ng/J (0.10 Ib/million Btu) heat input or less.
Fabric filters and ESP's, as well as other FGD systems, such as lime
spray drying systems, which incorporate these particulate matter control
technologies in their design and operation, are also demonstrated
technologies for controlling particulate matter emissions from coal-fired
steam generating units. The performance of fabric filters and ESP's was
discussed in the new source performance standards proposed on June 19, 1984
(49 FR 25102). Both fabric filters and ESP's, as well as those FGD systems
that incorporate fabric filters and ESP's in their design and operation, are
capable of reducing particulate matter emissions from coal-fired
industrial-commercial-institutional steam generating units to 21 ng/J (0.05
Ib/million Btu) heat input or less.
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6.0 CONSIDERATION OF DEMONSTRATED EMISSION CONTROL TECHNOLOGY COSTS
The cost impacts associated with the use of the various demonstrated
emission control technologies to reduce emissions of S02 from coal-fired,
oil-fired, and mixed fuel-fired (i.e., mixtures of fossil or fossil and
nonfossil fuels) industrial-commercial-institutional steam generating units
and emissions of particulate matter from oil-fired industrial-commercial -
institutional steam generating units were evaluated in three ways:
increases in capital costs; increases in annualized costs, including both
annual fixed capital charges and annual operating and maintenance costs; and
the cost effectiveness of emission control, or the cost per unit quantity of
pollutant removed. In each case, absolute costs of emission control were
examined, as well as incremental increases in cost.
Costs were estimated using cost algorithms to project capital costs and
annual operating and maintenance costs. Capital costs include the cost of
the equipment and its installation, indirect expenses such as engineering
fees and startup costs, and interest during construction. Annual operating
and maintenance costs include labor, utilities, raw materials, and waste
treatment and disposal. These cost algorithms are based on actual plant
cost data and vendor quotes.
Capital costs of flue gas desulfurization (FGD) systems reflect the
current practice of owners of industrial-commercial-institutional steam
generating units to design and install FGD systems capable of achieving 90
percent S02 removal with no flue gas bypass in order to provide maximum fuel
flexibility. This conservative design practice permits the steam generating
unit to fire the least expensive coal or oil available to minimize operating
costs. Annual operating and maintenance costs, however, reflect operation
at the minimal percent S0? removal necessary to comply with regulatory
requirements considering the sulfur content of the actual fuel fired.
The prices and specifications for various coals, oils, and natural gas
that were used in this analysis are discussed in "Consideration of National
Impacts." All fuel prices were levelized at a 10 percent discount rate over
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P.9
a 15-year period beginning in 1987, and were adjusted to January 1983
dollars.
The financial parameters used in this analysis include an amortization
period of 15 years and a real cost of capital of 10 percent in constant
dollars. A real rather than a nominal cost of capital is used in order to
avoid having to make adjustments for varying inflation rates. For example,
an assumed inflation rate of 8 percent and a 10 percent real cost of capital
is equivalent to an 18 percent nominal cost of capital. All costs are
presented in January 1983 dollars.
Costs presented in this analysis also include costs of demonstrating
compliance with applicable regulations through the use of continuous
emission monitoring devices. Costs to maintain compliance during periods of
FGD system malfunction are also included and are based on the firing of
natural gas during periods of FGD malfunction.
To analyze the potential cost impacts associated with the use of
various emission control technologies to reduce S02 emissions from new
industrial-commercial-institutional steam generating units, a regulatory
baseline must be selected for the analysis. The regulatory baseline
reflects the general level of emission control that would be required in the
absence of new source performance standards (NSPS).
Emissions of SOp from most steam generating units covered by the
proposed standards are currently controlled under existing State
implementation plans (SIP's). The level of S02 control required under
current SIP regulations varies considerably by location. In addition,
regulatory requirements associated with the prevention of significant
deterioration (PSD) and new source review (NSR) programs also limit
emissions of S00 from the steam generating units covered by the proposed
standards. Furthermore, emissions of S02 from new steam generating units
with heat input capacities greater than 73 MW (250 million Btu/hour) are
currently limited to 516 ng SOp/J (1.2 Ib SO^/million Btu) heat input under
the existing NSPS (40 CFR 60 Subpart D) promulgated in 1971.
An analysis of SIP requirements limiting SO^ emissions from both
coal-fired and oil-fired industrial-commercial-institutional steam
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P.10
generating units indicates that the "average" SIP SCL emission limit is
approximately 1,075 ng S02/J (2.5 Ib S02/million Btu) heat input. This
average SIP limit corresponds to the emissions generated during the
combustion of a medium sulfur coal or the combustion of a high sulfur oil.
The use of this average SIP emission limit as the regulatory baseline for
coal- and oil-fired steam generating units tends to overstate the cost
impacts associated with the use of various emission control technologies.
Approximately 40 percent of SIP's for steam generating units with heat input
capacities of 73 MW (250 million Btu/hour) or less, for example, are more
stringent than this average SIP emission limit.
Also, as mentioned earlier, regulatory requirements associated with the
PSD and NSR programs are often more stringent than SIP's. A review of
recent PSD and NSR permits for coal-fired industrial-commercial-
institutional steam generating units, for example, indicates that
approximately 50 percent of all PSD/NSR permits for units with heat input
capacities of 73 MW (250 million Btu/hour) or less, and all permits for
units with heat input capacities greater than 73 MW (250 million Btu/hour),
limit S02 emissions to 516 ng S02/J (1.2 Ib SOp/million Btu) heat input or
less.
A regulatory baseline reflecting the average SIP emission limit,
however, better illustrates the comparative costs of different SOp emission
control technologies than a regulatory baseline based on the more stringent
PSD/NSR programs. For purposes of this analysis, therefore, average SIP
emission limits of 1,075 ng S02/J (2.5 Ib S02/million Btu) and 1,290 ng
S02/J (3.0 Ib S02/million Btu) heat input were selected as the regulatory
baselines for coal- and oil-fired steam generating units, respectively. [As
discussed in "Consideration of National Impacts," the projected coal prices
used in this analysis include a coal type containing 1,075 ng SO?/J (2.5 Ib
S0?/million Btu) heat input. The projected oil prices, however, include oil
types containing 688 ng S02/J (1.6 Ib S02/million Btu) and 1,290 ng S02/J
(3.0 Ib S02/million Btu) heat input. Thus, the regulatory baseline for oil
was assumed to be 1,290 ng S02/J (3.0 Ib S02/million Btu) heat input, rather
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P.11
than 688 ng S02/J (1.6 Ib S02/million Btu), to reflect combustion of high
sulfur oil rather than medium sulfur oil.]
In addition to being based on the use of average SIP emission limits to
represent the regulatory baseline, the cost impacts discussed below
represent the maximum impacts associated with an NSPS on a specific
industrial-commercial-institutional steam generating unit. In many cases,
the actual cost impacts associated with an NSPS will be lower because steam
generating unit operators have the option of firing relatively sulfur-free
fuels to avoid many of the costs associated with compliance with an NSPS.
For example, rather than install an FGD system to reduce S02 emissions from
combustion of coal, an operator may elect to avoid the costs of such a
system by firing natural gas.
6.1 COSTS OF SULFUR DIOXIDE EMISSION CONTROL FOR COAL-FIRED STEAM .
GENERATING UNITS
As discussed in "Selection of Demonstrated Emission Control
Technologies," there are two basic approaches that can be used to reduce S02
emissions from coal-fired steam generating units: the combustion of low
sulfur coals, or the use of FGD systems. The FGD systems that are
considered demonstrated for the purposes of developing an NSPS for
coal-fired industrial-commercial-institutional steam generating units are
sodium, dual alkali, lime, limestone, and lime spray drying. Table 6-1
presents the costs of SO,, control for these technologies achieving 90
percent S02 removal on high and low sulfur coals on a 44 MW (150 million
Btu/hour) heat input capacity steam generating unit in EPA Region V. As
shown, the annualized costs of S0? control for the various FGD technologies
are generally within 30 percent of each other. These differences in costs
are minimal in terms of the total annualized cost of a steam generating unit
with an FGD system. The variation in costs among the different FGD
technologies, in terms of the total annualized costs for the steam
generating unit with an FGD system, is generally less than 4 percent.
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P.12
TABLE 6-1. COSTS OF DEMONSTRATED FLUE GAS DESULFURIZATION SYSTEMS0
Uncontrol led
Sodium
Scrubbing
FGD
S02C Total
Dual
Alkali
FGD
S02C Total
Dry
Lime
FGD
S02C Total
Capital Cost ($1,000)
High Sulfur Coald 14,020
Low Sulfur Coal6 14,070
Annualized Cost ($l,000/year)
High Sulfur Coald 5,700
Low Sulfur Coal6 6,340
920 14,940 2,410 16,430 1,550 15,570
830 14,900 2,350 16,420 1,480 15,550
920 6,620 1,170 6,870 1,090 6,790
490 6,830 910 7,250 740 7,080
aBased on 90 percent SOp removal on a 44 MW (150 million Btu/hour) steam
generating unit in EPA Region V.
Costs include NO control and particulate matter control.
X
GCost of S02 control is incremental cost over uncontrolled steam generating
unit.
dSulfur content = 2380 ng S09/J (5.54 Ib S0?/million Btu);
fuel price = $2.37/GJ ($2.56/million Btu)/
eSulfur content = 409 ng SO?/J (0.95 Ib S0?/million Btu);
fuel price = $3.14/GJ ($3.32/million Btu):
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P.13
In any particular situation, the lowest cost FGD technology will vary
depending on the size and capacity utilization factor of the steam
generating unit, sulfur content of the coal, and percent removal achieved by
the FGD system. For small steam generating units operating at low capacity
utilization factors and firing low sulfur coal, sodium scrubbing is
generally significantly less costly than the other FGD technologies.
However, as steam generating unit size and capacity utilization factor
increase, and as the sulfur content of the coal and SCL removal requirements
increase, the costs of other FGD technologies become more favorable. At the
larger steam generating unit sizes and capacity utilization factors, the
costs of all the FGD technologies examined are generally comparable.
Sodium scrubbing is currently the most widely used FGD technology for
industrial-commercial-institutional steam generating units. In addition, as
outlined above, its costs can be considered representative of FGD technology
costs in general. Consequently, sodium scrubbing was used to represent the
costs of FGD systems in this analysis.
A separate analysis of the relative competitiveness of fluidized bed
combustion (FBC) versus the use of conventional coal-fired steam generating
units was performed to examine the potential impact that new source
performance standards might have on the use of FBC technology. The results
of this analysis indicate that FBC systems, operated to control SCL
emissions, are slightly more expensive than conventional coal-fired steam
generating units that fire a low sulfur fuel to achieve the same level of
SCL control.
On the other hand, the results of the analysis also indicate that the
costs associated with an FBC system and a conventional coal-fired steam
generating unit using an FGD system to reduce SCL emissions are currently
about the same. Under these conditions, FBC systems are competitive with
conventional steam generating units.
This is essentially no different than the situation as it presently
exists regarding the relative competitiveness of FBC systems and
conventional coal-fired steam generating units. Even in the absence of
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considerations regarding control of S(L emissions, FBC systems are usually
slightly more expensive than conventional steam generating units. As a
result, the application of FBC systems has generally been limited to those
situations where concerns relating to fuel flexibility, or the need to
combust low-grade fuels, are paramount. As a result, the proposed new
source performance standards will neither preclude nor hinder the use of FBC
technology.
The costs and cost impacts associated with a given alternative control
level for a specific coal-fired steam generating unit vary depending on its
geographic location. This variation is due primarily to regional
differences in the prices of coal. This analysis focuses on the costs
associated with the various alternative control levels for coal-fired steam
generating units located in EPA Region V and EPA Region VIII. Region V
includes the states of Minnesota, Wisconsin, Illinois, Indiana, Michigan,
and Ohio. The coal types available in Region V include high and low sulfur
eastern bituminous coals, and low sulfur western subbituminous coals. The
prices and types of coals available in Region V are representative of those
in the eastern and midwestern states. Region VIII includes the states of
Colorado, Wyoming, Utah, Montana, North Dakota, and South Dakota. The coal
types available in Region VIII include low and medium sulfur bituminous and
subbituminous coals. The prices and types of coal available in Region VIII
are typical of those in other western states. In addition, Region VIII has
the lowest coal prices in the country and, therefore, the cost impacts of
alternative control levels requiring a specific percent reduction in SCL
emissions through the use of FGD are the highest in Region VIII.
Finally, the costs presented in this analysis for each of the
alternative control levels discussed below are based on the use of the
"least cost" approach for complying with that alternative. For example, to
comply with an alternative of 50 percent SOp emission reduction and an
emission ceiling of 387 ng/J (0.9 To/million Btu) heat input, it may be less
costly to operate an FGD system at 90 percent SOp removal on a high sulfur
coal than it is to operate an FGD system at 50 percent removal on a low
sulfur coal. In other words, the savings that result from firing less
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expensive high sulfur coal rather than more expensive low sulfur coal may be
more than enough to compensate for the increased cost of operating an FGD
system at 90 percent emission reduction rather than at 50 percent emission
reduction.
A number of alternative control levels could be examined to assess the
potential cost impacts associated with new source performance standards
based on the use of low sulfur coal and new source performance standards
requiring a percent reduction in S0? emissions. As discussed in
"Performance of Demonstrated Emission Control Technologies," SOp emissions
could be reduced to 731 ng SOp/J (1.7 Ib SOp/million Btu) heat input and 516
ng S02/J (1.2 Ib S02/million Btu) heat input through the use of low sulfur
coals. Therefore, each of these alternatives merits consideration.
There are two viewpoints from which the analysis of potential cost
impacts associated with alternative SOp percent reduction requirements could
be approached. One viewpoint is that, because FGD systems can be operated
over a wide range of SOp removal efficiencies, a range of SOp percent
reduction requirements merit consideration. Achieving a percent reduction
in SOp emissions of much less than 50 percent, however, would not reduce
emissions to less than 516 ng SOp/J (1.2 Ib SOp/million Btu) heat input on
most coal types. Consequently, the lowest percent reduction requirement
that merits serious consideration under this viewpoint is 50 percent. As
discussed in "Performance of Demonstrated Emission Control Technologies,"
FGD technologies are capable of reducing S0? emissions by 90 percent. This,
therefore, is the highest percent reduction requirement that merits
consideration. To examine an intermediate percent reduction requirement
between 50 and 90 percent, a requirement of 70 percent reduction can be
considered.
Combining these three alternative percent reduction requirements with
the maximum expected SOp emission rates associated with combustion of the
various coals discussed earlier in "Performance of Demonstrated Emission
Control Technologies" results in the various SOp emission ceilings
summarized in Table 6-2. As shown, for a minimum percent reduction
requirement of 50 percent, there are only two alternatives with SOp emission
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10
TABLE 6-2. S02 EMISSION CEILINGS ASSOCIATED WITH VARIOUS PERCENT REDUCTION REQUIREMENTS
Coal Type
Low Sulfur
Low Sulfur
Medium Sulfur
Medium Sulfur
High Sulfur
High Sulfur
Maximum Expected
S02 Emission Rate
516 (1.2)
731 (1.7)
1,118 (2.6)
1,592 (3.7)
2,237 (5.2)
2,710 (6.3)
S
50 Percent Reduction
258 (0.6)
387 (0.9)
559 (1.3)
817 (1.9)
1,118 (2.6)
1,376 (3.2)
Oy Emission Ceiling3
70 Percent Reduction
172 (0.4)
215 (0.5)
344 (0.8)
473 (1.1)
688 (1.6)
817 (1.9)
90 Percent Reduction
65 (0.15)
86 (0.2)
129 (0.3)
172 (0.4)
215 (0.5)
258 (0.6)
Emission rates and emission ceilings in ng SO^/J (lb SO^/million Btu) heat input.
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P.17
ceilings below 516 ng SO?/J (1.2 Ib S0?/million Btu) heat input - 387 n.g
S02/J (0.9 Ib S02/million Btu) and 258 ng S(yj (0.6 Ib S02/million Btu)
heat input. As mentioned above, the use of low sulfur coal could reduce S02
emissions to 516 ng S02/J (1.2 Ib S02/million Btu) heat input.
Consequently, these two alternatives are the only two associated with a
percent reduction requirement of 50 percent that would be more effective in
reducing S02 emissions than the use of low sulfur coal, and they are the
only two that merit consideration.
Assuming that a 70 percent reduction requirement should be more
effective in reducing S02 emissions than a 50 percent reduction requirement,
there are also only two alternatives associated with a 70 percent reduction
requirement that merit consideration. As shown in Table 6-2, these two
alternatives have emission ceilings of 215 ng S02/J (0.5 Ib S02/million Btu)
heat input and 172 ng S02/J (0.4 Ib S02/million Btu) heat input.
Finally, assuming that a 90 percent reduction requirement should be
more effective in reducing S02 emissions than a 70 percent reduction
requirement, there are only three alternatives associated with a 90 percent
reduction requirement that merit consideration. As shown in Table 6-2,
these three alternatives have emission ceilings of 129 ng S02/J (0.3 Ib
S02/million Btu), 86 ng S02/J (0.2 Ib S02/million Btu), and 65 ng S02/J
(0.15 Ib S02/million Btu) heat input.
This viewpoint, that a range of percent reduction requirements should
be considered, therefore, leads to seven alternative percent reduction
requirements: two alternatives associated with a 50 percent reduction
requirement, two alternatives associated with a 70 percent reduction
requirement, and three alternatives associated with a 90 percent reduction
requirement. Rather than examine all seven percent reduction requirements,
however, the following four alternatives were selected for analysis:
1. 50 percent reduction - 387 ng S02/J (0.9 Ib S02/million Btu)
2. 50 percent reduction - 258 ng S02/J (0.6 Ib S02/million Btu)
3. 70 percent reduction - 172 ng S02/J (0.4 Ib S02/million Btu)
4. 90 percent reduction - 86 ng S02/J (0.2 Ib S02/million Btu)
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P.18
These four alternative percent reduction requirements are representative of
the range of alternative percent reduction requirements discussed above.
Combining these four alternative percent reduction requirements with
the two alternatives mentioned above based on the use of low sulfur coal, in
addition to the regulatory baseline, results in seven alternative control
levels for analysis, as summarized in Table 6-3.
As mentioned, however, there is another viewpoint from which the
analysis of potential cost impacts associated with alternative percent
reduction requirements could be approached. This viewpoint is that since
FGD technologies are capable of achieving a 90 percent reduction in
emissions, and FGD systems for industrial-commercial-institutional steam
generating units are currently designed to achieve this level of
performance, 90 percent reduction is the only percent reduction requirement
that merits consideration.
As shown in Table 6-2, combining a 90 percent reduction requirement
with the maximum expected S02 emission rates associated with combustion of
the various coals discussed in "Performance of Demonstrated Emission Control
Technologies" results in six alternatives, all with S02 emission ceilings of
less than 516 ng SO^/J (1.2 Ib S02/million Btu) heat input. Rather than
examine all six of these alternatives, however, the following three were
selected for analysis:
1. 90 percent reduction - 258 ng S02/J (0.6 Ib S02/million Btu)
2. 90 percent reduction - 172 ng S02/J (0.4 Ib S02/million Btu)
3. 90 percent reduction - 86 ng S02/J (0.2 Ib S02/million Btu)
These three percent reduction requirements are representative of the range
of alternative percent reduction requirements discussed.
Combining these three alternative percent reduction requirements with
the two alternatives based on the use of low sulfur coal, in addition to the
regulatory baseline, results in six alternate control levels for analysis
under this viewpoint, as shown in Table 6-4.
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P.19
TABLE 6-3. ALTERNATIVE CONTROL LEVELS FOR COAL-FIRED
INDUSTRIAL-COMMERCIAL-INSTITUTIONAL STEAM GENERATING UNITS
Range of Percent Reduction Requirements
Percent Reduction/
Emission Ceiling,
ng S02/J (Ib S02/million Btu)
Control Method
None / 1075 (2.5)a
None / 731 (1.7)
None / 516 (1.2)
50% / 387 (0.9)
50% / 258 (0.6)
70% / 172 (0.4)
90% / 86 (0.2)
Medium Sulfur Coal
Low Sulfur Coal
Low Sulfur Coal
FGD with 50% Removal
FGD with 50% Removal
FGD with 70% Removal
FGD with 90% Removal
Represents regulatory baseline.
6-12
-------
P.20
TABLE 6-4. ALTERNATIVE CONTROL LEVELS FOR COAL-FIRED
INDUSTRIAL-COMMERCIAL-INSTITUTIONAL STEAM GENERATING UNITS
90 Percent Reduction Requirement
Percent Reduction/
Emission Ceiling,
ng/J (Ib/miTlion Btu)
Control Method
None / 1075 (2.5)a
None / 731 (1.7)
None / 516 (1.2)
90% / 258 (0.6)
90% / 172 (0.4)
90% / 86 (0.2)
Medium Sulfur Coal
Low Sulfur Coal
Low Sulfur Coal
FGD with 90% Removal
FGD with 90% Removal
FGD with 90% Removal
Represents regulatory baseline.
6-13
-------
P.21
Each viewpoint, therefore, results in a somewhat different set of
alternative control levels for analysis. This analysis examined both sets
of alternative control levels. For convenience, the alternative control
levels resulting from the first viewpoint are referred to as "range of
percent reduction requirements" and the alternative control levels resulting
from the second viewpoint are referred to as "90 percent reduction
requirement."
Before presenting and discussing the results of this analysis, however,
one additional point should be mentioned. A percent reduction requirement
with a low SOp emission ceiling may preclude combustion of certain coals.
Although an SO,, emission ceiling of 258 ng S02/J (0.6 Ib S02/million Btu)
heat input does not preclude combustion of any coal in this analysis, coals
containing more than 2,580 ng SO?/J (6.0 Ib SOp/million Btu) heat input
could not be burned and SOp emissions reduced to 258 ng S02/J (0.6 Ib
SOp/million Btu) heat input, assuming that 90 percent SOp emission reduction
is the maximum percentage reduction in SOp emissions that can be achieved
with any FGD system.
Similarly, the SOp emission ceilings of 172 ng S02/J (0.4 Ib
S02/mi11ion Btu) and 86 ng S02/J (0.2 Ib S02/million Btu) heat input
associated with the 90 percent reduction requirement discussed above would
generally preclude combustion of coals containing more than 1,720 ng S02/J
(4.0 Ib S02/million Btu) and 860 ng S02/J (2.0 Ib S02/million Btu) heat
input, respectively. Thus, an SOp emission ceiling of 172 ng SOp/J (0.4 Ib
SOp/million Btu) heat input would generally limit steam generating units to
combustion of low or medium sulfur coals, even with the use of FGD systems
to reduce S02 emissions. Similarly, an S02 emission ceiling of 86 ng S02/J
(0.2 Ib SOp/million Btu) heat input would generally limit steam generating
units to combustion of low sulfur coals.
6.1.1 Range of Percent Reduction Requirements
The cost impacts associated with each alternative control level were
examined for a typical industrial-commercial-institutional coal-fired steam
6-14
-------
P.22
generating unit. This steam generating unit has a heat input capacity of 44
MW (150 million Btu/hour) and an annual capacity utilization factor of 0.60.
The annual capacity utilization factor of a steam generating unit is defined
as the actual annual heat input to the unit divided by the maximum annual
heat input to the unit if it were operated at design capacity for 24 hours
per day, 365 days per year (8,760 hours per year). Table 6-5 summarizes the
results for Region V and Table 6-6 summarizes the results for Region VIII.
Tables 6-5 and 6-6 show that the increase in capital costs associated
with each of the alternative control levels based on the use of low sulfur
coal are essentially the same as those for a steam generating unit at the
regulatory baseline. An increase in the capital costs ranging from $0.7 to
$0.8 million, however, is associated with the various alternative control
levels that require a percent reduction in S02 emissions. This represents
an increase of about 5 percent in the capital costs for a typical 44 MW (150
million Btu/hour) heat input capacity coal-fired industrial-commercial-
institutional steam generating unit.
The additional annualized costs for a typical 44 MW (150 million
Btu/hour) heat input capacity coal-fired steam generating unit associated
with the various alternative control levels based on the use of low sulfur
coal would range from $70,000 to $180,000 per year, representing an increase
of less than 3 percent over the regulatory baseline. The additional
annualized costs associated with the various alternative control levels that
require a percent reduction in emissions would range from about $440,000 to
$610,000 per year, depending on the percent removal required and location
(i.e., Region V or Region VIII). This represents an increase in steam
generating unit annualized costs of 7 to 12 percent over the annualized
costs at the regulatory baseline.
The average cost effectiveness of emission control is calculated as the
difference in costs between a particular control level and the regulatory
baseline, divided by the difference in emission reductions between that
control level and the regulatory baseline. Tables 6-5 and 6-6 show that the
average cost effectiveness of SOp emission control associated with the
various alternative control levels based on the use of low sulfur coal
6-15
-------
TABLE 6-5. COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION V
Range of Percent Reduction Requirements
Alternative Control Level
"Least Cost" Approach
Percent
Reduction
None
None
None
50
50
70
90
Annual
SO, Emission Emissions
Ceiling Percent Coal Sulfur Content Mg/yr
ng/J (Ib/million Btu) Removal ng S02/J (Ib S02/million Btu) (ton/yr)
1,075
731
516
387
258
172
86
(2.5)
(1.7)
(1.2)
(0.9)
(0.6)
(0.4)
(0.2)
0
0
0
83
89
92
90
894
589
404
1,793
1,793
1,793
589
(2.08)
(1.37)
(0.94)
(4.17)
(4.17)
(4.17)
(1.37)
750 (830)
520 (570)
340 (370)
240 (260)
150 (170)
110 (120)
50 (60)
Capital
Cost
$million
14.1
14.1
14.1
14.9
14.9
14.9
14.9
Annual ized
Cost
$l,000/yr
6,160
6,230
6,340
6,600
6,630
6,640
6,770
Average
Cost
Effectiveness
$/Mg($/ton)
300 (270)
430 (390)
850 (770)
780 (710)
750 (680)
870 (790)
Incremental
Cost
Effectiveness
$/Mg ($/ton)
300
610
2,600
360
220
2,390
(270)
(550)
(2,360)
(330)
(200)
(2,170)
cr>
i
ro
co
-------
TABLE 6-6. COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION VIII
Range of Percent Reduction Requirements
Alternative Control Level
"Least Cost" Approach
Percent
Reduction
None
None
None
50
50
70
90
SO, Emission
^Ceiling
ng/J (Ib/million Btu)
1.075 (2.5)
731 (1.7)
516 (1.2)
387 (0.9)
258 (0.6)
172 (0.4)
86 (0.2)
Percent
Removal
0
0
0
50
70
90
84
Coal Sulfur Content
ng S02/J (Ib S02/million Btu)
894 (2.08)
589 (1.37)
404 (0.94)
894 (2.08)
404 (0.94)
404 (0.94)
404 (0.94)
Annual
Emissions
Mg/yr
(tons/yr)
750 (830)
520 (570)
340 (370)
240 (260)
150 (170)
110 (120)
50 (60)
Capital
Cost
Smillion
15.2
15.2
15.2
15.9
15.9
15.9
15.9
Annual i zed
Cost
$l,000/yr
4,950
5,040
5,050
5,510
5,510
5,530
5,540
Average
Cost
Effectiveness
$/Mg($/ton)
390 (350)
240 (220)
1,080 (980)
940 (850)
900 (820)
850 (770)
Incremental
Cost
Effectiveness
$/Mg ($/ton)
390 (350)
60 (50)
4,600 (4,180)
0 (0)
440 (400)
190 (170)
cr>
i
-------
P.25
ranges from approximately $240 to $430/Mg ($220 to $390/ton) for a typical
44 MW (150 million Btu/hour) heat input capacity steam generating unit. The
average cost effectiveness of alternative control levels requiring a percent
reduction in SOp emissions ranges from about $750 to $l,080/Mg ($680 to
$980/ton) of S02 removed.
The incremental cost effectiveness of SO,, control was also examined.
Incremental cost effectiveness is defined as the difference in cost between
two alternative control levels divided by the difference in emission
reductions achieved by the two alternative control levels. Tables 6-5 and
6-6 show that the incremental cost effectiveness of S0? emission control
between alternative control levels based on the use of low sulfur coal
varies from $610/Mg ($550/ton) in Region V to $60/Mg ($50/ton) in Region
VIII. This difference is due to the differences in price between the two
types of low sulfur coal in Region V and Region VIII. In Region V there is
a significant difference in the price of these two types of low sulfur coal.
In Region VIII, however, there is little difference. Thus, the incremental
cost effectiveness of control is higher in Region V than in Region VIII.
For an alternative control level requiring a 50 percent reduction in
S0? emissions and an alternative control level based on the use of low
sulfur coal to meet an emission level of 516 ng SO?/J (1.2 Ib S02/million
Btu), the incremental cost effectiveness also varies substantially between
Regions V and VIII. In Region V, the incremental cost effectiveness is
about $2,600/Mg ($2,360/ton) of SO,, removed; in Region VIII, the incremental
cost effectiveness is about $4,600/Mg ($4,180/ton).
This difference in incremental cost effectiveness is also explained by
differences in the availability of various coal types and coal prices
between the two regions. Steam generating units in Region V will fire a
high sulfur coal in response to a control level requiring a 50 percent
reduction in SO^ emissions with an emission ceiling of 387 ng SOp/J (0.9 Ib
SOp/million Btu) heat input. This high sulfur coal is much lower in price
than low sulfur coal in Region V. The savings from firing this less
expensive coal, compared to firing the more expensive low sulfur coal,
6-18
-------
P.26
minimizes the cost impacts associated with the use of F6D to achieve a 50
percent reduction in SCL emissions.
Steam generating units in Region VIII will fire a medium sulfur coal to
meet this same alternative control level. There is little difference in
price between low and medium sulfur coals in Region VIII. Consequently, the
cost impacts of requiring a 50 percent reduction in SOp emissions are not
mitigated by lower fuel prices resulting from firing a higher sulfur coal.
The incremental cost effectiveness of increasingly more stringent
alternative control levels requiring a percent reduction in SOp emissions is
also shown in Tables 6-5 and 6-6. In each case, the incremental cost
effectiveness of more stringent alternative control levels is less than
$440/Mg ($400/ton), with one exception.
In Region V, the incremental cost effectiveness of requiring a 90
percent SOp emission reduction with an emission ceiling of 86 ng SOp/J (0.2
Ib S02/million Btu) heat input is about $2,390/Mg ($2,170/ton). When a 90
percent reduction is required with an emission ceiling of 86 ng SOp/J (0.2
Ib SOp/million Btu) heat input, a steam generating unit must fire a low
sulfur coal, whereas a high sulfur coal can be fired to meet the less
stringent alternatives. The high price of low sulfur coal compared to high
sulfur coal in Region V, therefore, increases the costs and leads to a less
favorable cost effectiveness value for SOp emission control.
In Region VIII, however, the price differential between various coal
types is small. The incremental cost effectiveness of increasingly more
stringent alternative control levels is determined primarily by differences
in FGD operating costs. Because FGD operating costs increase only slightly
with increasing SOp removal efficiency, but substantial emission reductions
are achieved at more stringent control levels, the incremental cost
effectiveness is less than $440/Mg ($400/ton) in Region VIII.
The cost impacts of alternative control levels were also examined as a
function of steam generating unit size. The results are summarized in Table
6-7 for Region V and Table 6-8 for Region VIII. These tables present the
increases in capital costs, the increases in annualized costs, and the cost
effectiveness of control for typical 29, 44, 73, and 117 MW (100, 150, 250,
6-19
-------
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-7.
STEAM GENERATING UNIT SIZE IN EPA REGION V
Range of Percent Reduction Requirements
I
ro
o
Percent Reduction/
Emission Ceiling, None/
ng/J (Ib/million Btu) 731(1.7)
None/
516(1.2)
50%/ 50%/
387(0.9) 258(0.6)
70%/
172(0.4)
90%/
86(0.2)
Increase in Capital Cost Over Baseline, percent
29 MW (100 million Btu/hour) 0
44 MW (150 million Btu/hour) 0
73 MW (250 million Btu/hour) 0
117 MW (400 million Btu/hour) 0
Increase in Annual ized Cost Over Baseline,
29 MW (100 million Btu/hour) 1
44 MW (150 million Btu/hour) 1
73 MW (250 million Btu/hour) 1
117 MW (400 million Btu/hour) 1
Average Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour) 320(290)
44 MW (150 million Btu/hour) 300(270)
73 MW (250 million Btu/hour) 330(300)
117 MW (400 million Btu/hour) 340(310)
Incremental Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour) 320(290)
44 MW (150 million Btu/hour) 300(270)
73 MW (250 million Btu/hour) 330(300)
117 MW (400 million Btu/hour) 340(310)
0
0
0
0
percent
3
3
3
3
470(430)
430(390)
460(420)
460(420)
670(610)
610(550)
640(580)
630(570)
7 7
6 6
5 5
5 5
8 8
7 8
6 6
6 6
1,010(920) 940(850)
850(770) 780(710)
720(650) 660(600)
620(560) 580(530)
3,120(2,840) 390(350)
2,600(2,360) 360(330)
1,710(1,550) 310(280)
1,210(1,100) 340(310)
7
6
5
5
8
8
7
6
880(800)
750(680)
630(570)
550(500)
300(270)
220(200)
230(210)
220(200)
7
6
5
4
10
10
9
9
1,000(910)
870(790)
780(710)
700(640)
2,480(2,250)
2,390(2,170)
2,530(2,300)
2,480(2,250)
-------
en
i
r\>
TABLE 6-8. COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
STEAM GENERATING UNIT SIZE IN EPA REGION VIII
Range of Percent Reduction Requirements
Percent Reduction/
Emission Ceiling,
ng/J (Ib/million Btu)
None/
731(1.7)
None/
516(1.2)
50%/
387(0.9)
50%/
258(0.6)
70%/
172(0.4)
90%/
86(0.2)
Increase in Capital Cost Over Baseline, percent
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
Increase in Annual ized Cost Over
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
0
0
0
0
Baseline,
2
2
2
2
0
0
0
0
percent
2
2
2
2
5
5
4
4
11
11
10
10
5
5
4
4
12
11
10
10
5
5
4
4
12
12
10
11
5
5
4
4
12
12
11
11
Average Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour) 390(350)
44 MW (150 million Btu/hour) 390(350)
73 MW (250 million Btu/hour) 390(350)
117 MW (400 million Btu/hour) 390(350)
Incremental Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour) 390(350)
44 MW (150 million Btu/hour) 390(350)
73 MW (250 million Btu/hour) 390(350)
117 MW (400 million Btu/hour) 390(350)
250(230) 1,220(1,110) 1,060(960) 1,000(910) 950(860)
240(220) 1,080(980) 940(850) 900(820) 850(770)
250(230) 940(850) 840(760) 790(720) 750(680)
250(230) 860(780) 760(690) 730(660) 690(630)
90(80) 4,970(4,520) 0(0) 300(270) 280(250)
60(50) 4,610(4,180) 0(0) 440(400) 190(170)
70(60) 3,640(3,310) 150(140) 230(210) 330(300)
90(80) 3,200(2,910) 140(130) 300(270) 280(250)
-------
P.29
and 400 million Btu/hour) heat input capacity steam generating units. As
shown, the results and trends discussed above for a 44 MW (150 million
Btu/hour) heat input capacity steam generating unit generally apply to other
steam generating unit sizes as well. Cost impacts of alternative control
levels based on the use of low sulfur coals change very little with respect
to unit size. Cost impacts of alternative control levels requiring a
percent reduction in SO^ emissions, however, decrease with increasing steam
generating unit size due to the economies of scale of FGD systems.
Steam generating unit size has the greatest impact on the incremental
cost effectiveness between alternative control levels requiring a percent
reduction in emissions and alternative control levels based on the use of
low sulfur coal. For example, in Region V the incremental cost
effectiveness of the least stringent alternative control level requiring a
percent reduction in emissions over the most stringent alternative control
level based on the use of low sulfur coal is about $3,120/Mg ($2,840/ton) of
S02 removed for a 29 MW (100 million Btu/hour) heat input capacity steam
generating unit. The incremental cost effectiveness decreases to $l,210/Mg
($l,100/ton) of S02 removed for a 117 MW (400 million Btu/hour) heat input
capacity steam generating unit in Region V. Similarly, in Region VIII the
incremental cost effectiveness decreases from $4,970/Mg ($4,520/ton) to •
$3,200/Mg ($2,910/ton) as steam generating unit heat input capacity
increases from 29 MW to 117 MW (100 to 400 million Btu/hour).
Finally, the cost impacts of the alternative control levels were
examined as a function of steam generating unit annual capacity utilization
factor. The variations in cost impacts with annual capacity utilization
factor were examined for 44 MW (150 million Btu/hour) heat input capacity
steam generating units in Regions V and VIII. Cost impacts were examined
for annual capacity utilization factors of 0.15, 0.30, and 0.60.
Capital costs for a given steam generating unit are fixed, regardless
of the annual capacity utilization factor of the unit. However, operation
and maintenance costs, such as labor, fuel, utilities, raw materials, and
waste disposal, decrease with decreasing annual capacity utilization factor.
Therefore, at low annual capacity utilization factors capital charges
6-22
-------
P.30
represent a large percentage of the total annualized cost of control. As
annual capacity utilization factor increases, however, capital charges
become less important. Annual emissions, of course, are directly
proportional to the annual capacity utilization factor of the steam
generating unit.
Cost impacts associated with alternative control levels based on the
use of low sulfur coal are essentially constant with respect to annual
capacity utilization factor, since differences in fuel prices are
independent of annual capacity utilization factor. However, the cost
impacts associated with alternative control levels requiring a percent
reduction in SCL emissions generally increase with decreasing annual
capacity utilization factor because the fixed cap.ital costs associated with
the FGD system must be borne by a lower level of operation. Thus, cost
impacts per unit of operation increase as annual capacity utilization factor
decreases.
Tables 6-9 and 6-10 show that the steam generating unit annual capacity
utilization factor has a significant impact on the average cost
effectiveness of alternative control levels requiring a percent reduction in
SOp emissions. For example, in Region V the average cost effectiveness of
alternatives requiring a percent reduction in S02 emissions increases from
$750 to $870/Mg ($680 to $790/ton) at an annual capacity utilization factor
of 0.60 to $2,100 to $2,550/Mg ($1,910 to $2,320/ton) at an annual capacity
utilization factor of 0.15. Similarly, in Region VIII the average cost
effectiveness of alternative control levels based on a percent reduction in
S02 emissions increases from $850 to $l,080/Mg ($770 to $980/ton) at an
annual capacity utilization factor of 0.60 to $1,940 to $2,550/Mg ($1,760 to
$2,320/ton) at an annual capacity utilization factor of 0.15.
Tables 6-9 and 6-10 also show that annual capacity utilization factor
has a significant impact on the incremental cost effectiveness of
alternative control levels requiring a percent reduction in S02 emissions
compared to alternative control levels based on the use of low sulfur coal.
For example, the incremental cost effectiveness of the least stringent
alternative control level requiring a percent reduction in S02 emissions
6-23
-------
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-9.
STEAM GENERATING UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V
Range of Percent Reduction Requirements
ro
Percent Removal/
Emission Ceiling,
ng/J (Ib/million Btu)
Increase in
CUF =
CUF =
CUF =
Increase in
CUF =
CUF =
CUF =
None/
731(1.7)
None/
516(1.2;
50%/
) 387(0.9)
50%/ 70%/
258(0.6) 172(0.4)
90%/
86(0.2)
Capital Cost Over Baseline, percent
0.15
0.30
0.60
Annual ized Cost
0.15
0.30
0.60
Average Cost Effectiveness,
CUF =
CUF =
CUF =
Incremental
CUF =
CUF =
CUF =
0.15
0.30
0.60
0
0
0
Over Baseline,
1
1
1
$/Mg($/ton)
340(310)
250(230)
300(270)
0
0
0
percent
1
2
3
480(440)
440(400)
430(390)
6
6
6
9
8
7
2,550(2,320) 2
1,390(1,260) 1
850(770)
6
6
6
9
9
8
,290(2,080)
,280(1,160)
780(710)
6
6
6
9
9
8
2,100(1,910)
1,180(1,070)
750(680)
6
6
6
10
10
10
2,170(1,970)
1,290(1,170)
870(790)
Cost Effectiveness, $/Mg($/ton)
0.15
0.30
0.60
340(310)
250(230)
300(270)
670(610)
670(610)
610(550)
10,620(9,650)
5,120(4,650)
2,600(2,360)
510(460)
510(460)
360(330)
0(0)
0(0)
220(200)
2,940(2,670)
2,570(2,340)
2,390(2,170)
TJ
co
-------
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-10.
STEAM GENERATING UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION VIII
Range of Percent Reduction Requirements
ro
en
Percent Reduction/
Emission Ceiling,
ng/J (Ib/million Btu)
None/
731(1.7)
None/
516(1.2)
50%/
387(0.9)
50%/
258(0.4)
70%/
172(0.6)
9055/
86(0.2)
Increase in Capital Cost Over Baseline, percent
CUF = 0.15
CUF = 0.30
CUF = 0.60
Increase in Annual ized Cost
CUF = 0.15
CUF = 0.30
CUF = 0.60
Average Cost Effectiveness,
CUF = 0.15
CUF = 0.30
CUF = 0.60
Incremental Cost
CUF = 0.15
CUF = 0.30
CUF = 0.60
0
0
0
Over Baseline,
1
1
2
$/Mg($/ton)
340(310)
340(310)
390(350)
0
0
0
percent
1
1
2
300(270)
240(220)
240(220)
5
5
5
9
11
11
2,550(2,320) 2
1,580(1,440) 1
1,080(980)
5
5
5
9
11
11
,210(2,010)
,380(1,250)
940(850)
5
5
5
10
11
12
2,100(1,910)
1,270(1,150)
900(820)
5
5
5
10
11
12
1,940(1,760)
1,200(1,090)
850(770)
Effectiveness, $/Mg($/ton)
340(310)
340(310)
390(350)
220(200)
220(100)
60(50)
11,370(10,340)
6,820(6,200)
4,610(4,180)
0(0)
0(0)
0(0)
780(710)
0(0)
440(400)
0(0)
360(330)
190(170)
TJ
•o
-------
P.33
over the most stringent alternative control level based on the use of low
sulfur coal is approximately $2,600/Mg ($2,360/ton) for an annual capacity
utilization factor of 0.60 in Region V, but increases to $10,610/Mg
($9,650/ton) at an annual capacity utilization factor of 0.15. Similarly,
in Region VIII the incremental cost effectiveness increases from $4,600/Mg
($4,180/ton) to $ll,370/Mg ($10,340/ton).
6.1.2 90 Percent Reduction Requirement
The costs and cost impacts associated with each alternative control
level were first examined for a coal-fired steam generating unit having a
heat input capacity of 44 MW (150 million Btu/hour) and an annual capacity
utilization factor of 0.60. This unit is representative of a typical
industrial-commercial-institutional coal-fired steam generating unit.
Table 6-11 summarizes the results of this cost analysis for Region V and
Table 6-12 summarizes the results for Region VIII.
The alternative control levels based on the use of low sulfur coal to
meet emission ceilings of 731 ng/J (1.7 Ib/million Btu) or 516 ng/J (1.2
Ib/million Btu) heat input are identical to those presented previously in
Table 6-4. Therefore, the cost impacts of alternative control levels based
on the use of low sulfur coal are not discussed in detail below. This
discussion focuses mainly on the costs and cost impacts of alternative
control levels based on a 90 percent reduction in SOp emissions.
Tables 6-11 and 6-12 show that the increase in capital costs associated
with each alternative control level based on a 90 percent reduction in SOp
emissions is about $0.7 to $0.8 million over the cost at the regulatory
baseline. This represents an increase of about 5 percent in the capital
costs for a typical 44 MW (150 million Btu/hour) heat input capacity
coal-fired industrial-commercial-institutional steam generating unit.
The additional annualized costs for a typical 44 MW (150 million
Btu/hour) heat input capacity coal-fired steam generating unit associated
with the various alternative control levels requiring a 90 percent reduction
in S02 emissions range from about $460,000 to $610,000 per year, depending
6-26
-------
TABLE 6-11. COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION V
90 Percent Reduction Requirement
Alternative Control Level
"Least Cost" Approach
Percent
Reduction
None
None
None
90
90
90
SO, Emission
Ceiling
ng/J (Ib/million Btu)
1,075 (2.5)
731 (1.7)
516 (1.2)
258 (0.6)
172 (0.4)
86 (0.2)
Percent
Removal
0
0
0
90
90
90
Coal Sulfur Content
ng S02/J (Ib S02/million Btu)
894 (2.08)
589 (1.37)
404 (0.94)
2,150 (5.00)
1,256 (2.92)
589 (1.37)
Annual
Emissions
Mg/yr
(tons/yr)
750 (830)
520 (570)
340 (370)
150 (170)
70 (80)
40 (40)
Capital
Cost
Smillion
14.1
14.1
14.1
14.9
14.9
14.9
Annual ized
Cost
$l,000/yr
6,160
6,230
6,340
6,620
6,710
6,770
Average
Cost
Effectiveness
$/Mg($/ton)
300 (270)
430 (390)
770 (700)
800 (730)
850 (770)
Incremental
Cost
Effectiveness
$/Mg ($/ton)
300 (270)
610 (550)
1,540 (1,400)
1,100 (1,000)
1,650 (1,500)
cr>
ro
-------
TABLE 6-12. COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED
STEAM GENERATING UNIT IN EPA REGION VIII
90 Percent Reduction Requirement
Alternative Control Level
"Least Cost" Approach
Percent
Reduction
None
None
None
90
90
90
SO, Emission
Ceiling
ng/J (Ib/million Btu)
1,075 (2.5)
731 (1.7)
516 (1.2)
258 (0.6)
172 (0.4)
86 (0.2)
Percent
Removal
0
0
0
90
90
90
Coal Sulfur Content
ng S02/J (Ib S02/million Btu)
894 (2.08)
589 (1.37)
404 (0.94)
404 (0.94)
404 (0.94)
404 (0.94)
Annual
Emissions
Mg/yr
(tons/yr)
750 (830)
520 (570)
340 (370)
30 (30)
30 (30)
30 (30)
Capital
Cost
$million
15.2
15.2
15.2
15.9
15.9
15.9
Annuali zed
Cost
$l,000/yr
4,950
5,040
5,050
5,550
5,550
5,550
Average
Cost
Effectiveness
$/Mg($/ton)
390 (350)
240 (220)
830 (750)
830 (750)
830 (750)
Incremental
Cost
Effectiveness
$/Mg ($/ton)
390 (350)
60 (50)
1,620 (1,470)
0 (0)
0 (0)
I
fsj
CO
TJ
co
-------
P.36
on the emission ceiling and steam generating unit location (i.e., Region V
or Region VIII). This represents an increase in steam generating unit
annualized costs of 7 to 12 percent over the annualized costs at the
regulatory baseline.
Tables 6-11 and 6-12 show that the average cost effectiveness of
alternative control levels requiring a 90 percent reduction in SCL emissions
ranges from about $770 to $850/Mg ($700 to $770/ton) for a typical 44 MW
(150 million Btu/hour) heat input capacity steam generating unit.
The incremental cost effectiveness of an alternative control level
based on a 90 percent reduction in S0? emissions with an emission ceiling of
258 ng SO^/J (0.6 Ib SO^/million Btu) heat input compared to a control
alternative based on the use of low sulfur coal to meet an emission ceiling
of 516 ng S02/J (1.2 Ib S02/million Btu) is about $l,540/Mg ($l,400/ton) in
Region V and about $l,620/Mg ($l,470/ton) in Region VIII. The incremental
cost effectiveness to meet increasingly more stringent emission ceilings for
alternative control levels based on a 90 percent reduction in S02 emissions
is about $1,100 to $l,650/Mg ($1,000 to $l,500/ton) in Region V. In Region
VIII, this incremental cost effectiveness is zero because coal with the same
sulfur content would be used under all alternative control levels requiring
a 90 percent reduction in SO^ emissions.
The cost impacts of alternative control levels were also examined as a
function of steam generating unit size. The results are summarized in Table
6-13 for Region V and Table 6-14 for Region VIII. These tables present the
increases in capital costs, the increases in annualized costs, and the cost
effectiveness of S02 control for typical 29, 44, 73, and 117 MW (100, 150,
250, and 400 million Btu/hour) heat input capacity steam generating units.
As shown, the results and trends discussed above for a 44 MW (150 million
Btu/hour) heat input capacity steam generating unit generally apply to other
steam generating unit sizes as well. As discussed previously, cost impacts
of alternative 'S02 control levels based on the use of low sulfur coals
change very little with respect to unit size. Cost impacts of alternative
control levels requiring a 90 percent reduction in S02 emissions, however,
6-29
-------
TABLE 6-13.
STEAM GENERATING UNIT SIZE IN EPA REGION V
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
90 Percent Reduction Requirement
cr>
i
CO
O
Percent Reduction/
Emission Ceiling, None/ None/
ng/J (Ib/million Btu) 731(1.7) 516(1.2)
Increase in Capital Cost Over Baseline, percent
29 MW (100 million Btu/hour) 0
44 MW (150 million Btu/hour) 0
73 MW (250 million Btu/hour) 0
117 MW (400 million Btu/hour) 0
Increase in Annual ized Cost Over Baseline, percent
29 MW (100 million Btu/hour) 1
44 MW (150 million Btu/hour) 1
73 MW (250 million Btu/hour) 1
117 MW (400 million Btu/hour) 1
Average Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour) 320(290)
44 MW (150 million Btu/hour) 300(270)
73 MW (250 million Btu/hour) 330(300)
117 MW (400 million Btu/hour) 340(310)
Incremental Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour) 320(290)
44 MW (150 million Btu/hour) 300(270)
73 MW (250 million Btu/hour) 330(300)
117 MW (400 million Btu/hour) 340(310)
0
0
0
0
3
3
3
3
470(430)
430(390)
460(420)
460(420)
670(610)
610(550)
640(580)
630(570)
90%/
258(0.6)
7
6
5
5
8
7
6
6
930(840)
770(700)
650(590)
560(510)
1,910(1,730)
1,540(1,400)
1,050(950)
770(700)
90%/
172(0.4)
7
6
5
4
10
9
8
7
960(870)
800(730)
720(650)
640(580)
1,230(1,120)
1,100(1,000)
1,230(1,120)
1,230(1,120)
90%/
86(0.2)
7
6
5
4
11
10
9
9
990(900)
850(770)
770(700)
690(630)
1,580(1,430)
1,650(1,500)
1,730(1,570)
1,680(1,520)
-------
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-14.
STEAM GENERATING UNIT SIZE IN EPA REGION VIII
90 Percent Reduction Requirement
O»
i
CO
Percent Reduction/
Emission Ceiling,
ng/J Ob/million Btu)
Increase in Capital Cost Over Baseline,
29 MW (100 million Btu/hour)
44 MW (ISO million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
None/
731(1.7)
percent
0
0
0
0
None/
516(1.2)
0
0
0
0
90%/
258(0.6)
5
5
4
4
90%/
172(0.4)
5
5
4
4
90%/
86(0.2)
5
5
4
4
Increase in Annual i zed Cost Over Baseline, percent
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
Average Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
2
2
2
2
390(350)
390(350)
390(350)
390(350)
2
2
2
2
250(230)
240(220)
240(220)
250(230)
12
12
11
11
930(840)
830(750)
740(670)
670(610)
12
12
11
11
930(840)
830(750)
740(670)
670(610)
12
12
11
11
930(840)
830(750)
740(670)
670(610)
Incremental Cost Effectiveness, $/Mg($/ton)
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
390(350)
390(350)
390(350)
390(350)
90(80)
60(50)
70(60)
90(80)
1,820(1,650)
1,620(1,470)
1,380(1,250)
1,210(1,100)
0(0)
0(0)
0(0)
0(0)
0(0)
0(0)
0(0)
0(0)
-------
P.39
decrease with increasing steam generating unit size due to the economies of
scale of FGD systems. . , .
Steam generating unit size has the greatest impact on the incremental
cost effectiveness between alternative control levels requiring ,a 90 percent
reduction in SCL emissions and alternative control levels based on the use
of low sulfur coal. For example, in Region V the incremental cost
effectiveness of the least stringent alternative control level requiring a
90 percent reduction in S02 emissions over the most stringent alternative
control level based on the use of low sulfur coal is about $l,900/Mg
($l,730/ton) of S0? removed for a 29 MW (100 million Btu/hour) heat input
capacity steam generating unit. The incremental cost effectiveness
decreases to $770/Mg ($700/ton) of S02 removed for a 117 MW (400 million
Btu/hour) heat input capacity steam generating unit in Region V. Similarly,
in Region VIII the incremental cost effectiveness decreases from $l,810/Mg
($l,650/ton) to $l,200/Mg ($l,100/ton) as steam generating unit size :
increases. . ..
Finally, the cost impacts of the alternative control levels were '•••
examined as, a function of the steam generating unit annual capacity
utilization factor. The variations in cost impacts with annual capacity
utilization factor were examined for 44 MW ,(150 million Btu/hour) heat input
capacity steam generating units with annual capacity'utilization factors of*
0.15, 0.30, and 0.60 in Regions V and VIII. The results are summarized in \
Tables 6-15 and 6-16, respectively.
Cost impacts associated with alternative S02 control levels based on
the use of low sulfur'.coal are essentially constant with respect to annual
capacity utilization factor, because differences in fuel prices are <:
independent of annual • capacity utilization factor. However, the cost ;
impacts associated with alternative control levels requiring a 90 percent
reduction in S02 emissions generally increase with decreasing annual
capacity utilization factor, as explained earlier. ' •;,
Tables 6-15 and 6-16 show that steam generating unit annual capacity
utilization factor has a significant impact on the average cost
effectiveness of alternative control levels requiring a 90 percent reduction
6-32
-------
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-15.
STEAM GENERATING UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V
90 Percent Reduction Requirement
I
CO
CO
Percent Reduction/
Emission Ceiling,
ng/J (Ib/million Btu)
Increase in Capital Cost Over Baseline,
CUF = 0.15
CUF = 0.30
CUF = 0.60
None/
731(1.7)
percent
0
0
0
None/
516(1.2)
0
0
0
90%/
258(0.6)
6
6
6
90%/
172(0.4)
6
6
6
90%/
86(0.2)
6
6
6
Increase in Annual ized Cost Over Baseline, percent
CUF = 0.15
CUF = 0.30
CUF = 0.60
1
1
1
1
2
3
9
9
8
10
10
9
10
10
10
Average Cost Effectiveness, $/Mg($/ton)
CUF = 0.15
CUF = 0.30
CUF = 0.60
Incremental Cost
CUF = 0.15
CUF = 0.30
CUF = 0.60
340(310)
250(230)
300(270)
480(440)
440(400)
430(390)
2,130(1,930)
1,270(1,150)
770(700)
2,140(1,940)
1,240(1,130)
800(730)
2,140(1,940)
1,270(1,150)
850(770)
Effectiveness, $/Mg($/ton)
340(310)
250(230)
300(270)
670(610)
670(610)
610(550)
5,110(4,640)
3,080(2,790)
1,540(1,400)
2,260(2,050)
1,370(1,240)
1,100(1,000)
2,100(1,910)
1,580(1,430)
1,650(1,560)
TJ
o
-------
COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-16.
STEAM GENERATING UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION VIII
90 Percent Reduction Requirement
CTl
I
CO
Percent Reduction/
Emission Ceil ing,
ng/J (Ib/million Btu)
Increase in
CUF =
CUF =
CUF =
Increase in
CUF =
CUF =
CUF =
None/
731(1.7)
None/
516(1.2)
90«/
258(0.6)
90%/
172(0.4)
90%/
86(0.2)
Capital Cost Over Baseline, percent
0.15
0.30
0.60
Annual ized Cost
0.15
0.30
0.60
Average Cost Effectiveness,
CUF =
CUF = -
CUF =
Incremental
CUF =
CUF =
CUF =
0 . 15
0.30
0.60
0
0
0
Over Baseline,
1
1
2
$/Mg($/ton)
340(310)
340(310)
390(350)
0
0
0
percent
1
1
2
300(270)
240(220)
240(220)
5
5
5
10
11
11
1,870(1,700)
1,190(1,080)
830(750)
5
5
5
10
11
11
1,879(1,700)
1,190(1,080)
830(750)
5
5
5
10
11
12
1,870(1,700)
1,190(1,080)
830(750)
Cost Effectiveness, $/Mg($/ton)
0.15
0.30
0.60
340(310)
340(310)
390(350)
220(200)
110(100)
60(50)
3,950(3,580)
2,420(2,200)
1,590(1,440)
0(0)
0(0)
0(0)
0(0)
0(0)
0(0)
-------
P.42
in S(L emissions. For example, in Region V the average cost effectiveness
of alternatives requiring a 90 percent reduction in S(L emissions increases
from about $770 to $850/Mg ($700 to $770/ton) at an annual capacity
utilization factor of 0.60 to about $2,130/Mg ($l,940/ton) at an annual
capacity utilization factor of 0.15. In Region VIII, the average cost
effectiveness increases from about 830/Mg ($750/ton) at an annual capacity
utilization factor of 0.60 to $l,870/Mg ($l,700/ton) at an annual capacity
utilization factor of 0.15.
Tables 6-15 and 6-16 also show that the annual capacity utilization
factor has a significant impact on the incremental cost effectiveness of
alternative control levels requiring a 90 percent reduction in S02 emissions
compared to alternative control levels based on the use of low sulfur coal.
For example, the incremental cost effectiveness of the least stringent
alternative control level requiring a 90 percent reduction in SOp emissions
over the most stringent alternative control level based on the use of low
sulfur coal is approximately $l,540/Mg ($l,400/ton) at an annual capacity
utilization factor of 0.60 in Region V, but increases to $5,100/Mg
($4,640/ton) at an annual capacity utilization factor of 0.15. Similarly,
in Region VIII the incremental cost effectiveness increases from $l,580/Mg
($l,440/ton) at an annual capacity utilization factor of 0.60 to $3,940/Mg
($3,580/ton) at an annual capacity utilization factor of 0.15.
6.1.3 Summary of Analysis
The results of this cost analysis indicate that the impacts associated
with alternative control levels based on the use of low sulfur coal are
lower than those associated with alternative control levels requiring a
percent reduction in SOp emissions. Furthermore, the impacts associated
with alternative control levels based on the use of low sulfur coal are
fairly constant with respect to steam generating unit size and annual
capacity utilization factor because fuel prices do not change with respect
to unit size or annual capacity utilization factor.
6-35
-------
P.43
The impacts associated with alternative control 'levels requiring a
percent reduction in SCL emissions, however, do vary as a function of steam
generating unit location, size, and annual capacity utilization factor.
Location and annual capacity utilization factor are the most important of
these factors in determining these cost impacts. In locations where
significant differences exist between the price of high or medium sulfur
coal and low sulfur coal, the incremental cost effectiveness of alternative
control levels based on a percent reduction in S0? emissions over
alternative control levels based on the use of low sulfur coal is less than
in locations where only small differences exist between the prices of high
or medium sulfur coals and low sulfur coals. In locations where significant
differences in prices exist, the fuel savings realized by switching from
firing low sulfur coal to firing medium or high sulfur coal offsets, to some
extent, the costs of the FGD systems installed to comply with a percent
reduction requirement.
As annual capacity utilization factor decreases, the cost impacts
associated with alternative control levels based on a percent reduction
requirement increase significantly. The large capital costs associated with
FGD systems installed to comply with a percent reduction requirement must be
borne by a lower level of operation. The cost impacts of alternative
control levels requiring a percent reduction in emissions also increase as
steam generating unit size decreases.
In addition, the predicted cost impacts vary depending on the viewpoint
used in developing alternative control levels based on percent reduction
requirements. In this analysis, two viewpoints were examined. The first
viewpoint resulted in a range of SOp percent reduction requirements; the
second resulted in only a 90 percent reduction requirement. The average and
incremental cost effectiveness of alternative control levels based on a 90
percent reduction in SO^ emissions are generally lower than those based on a
50 or 70 percent reduction in S0? emissions. Table 6-17 illustrates this
for various coal types in Regions V and VIII for a 44 MW (150 million
Btu/hour) heat input capacity steam generating unit. Table 6-17 shows that
the differences in annualized costs among FGD systems operated at various
6-36
-------
TABLE 6-17. COST EFFECTIVENESS OF S02 PERCENT REDUCTION REQUIREMENTS FOR A 44 MW (150 MILLION BTU/HR)
COAL-FIRED STEAM GENERATING UNIT
01
i
CO
Coal Sulfur
Content
Percent ng S02/J
Reduction (Ib S02/miflion Btu)
Region V:
Low Sulfur Coal 516(1.2)
50 Percent
70 Percent
90 Percent
Medium Sulfur Coal 1,075(2.5)
50 Percent
70 Percent
90 Percent
High Sulfur Coal 2,580(6.0)
50 Percent
70 Percent
90 Percent
Region VIII:
Low Sulfur Coal 516(1.2)
50 Percent
70 Percent
90 Percent
Medium Sulfur Coal 1,075(2.5)
50 Percent
70 Percent
90 Percent
Annual i zed
Cost
$l,000/yr
6,340
6,800
6,820
6,830
6,160
6,680
6,720
6,760
5,700
6,410
6,520
6,620
5,050
5,510
5,530
5,550
4,950
5,470
5,520
5,560
Annual S02
Emissions,
Mg/yr
(tons/yr)
340(370)
150(170)
90(100)
30(30)
750(830)
350(380)
200(220)
50(60)
1,980(2,180)
910(1,000)
530(580)
150(170)
340(370)
150(170)
90(100)
30(30)
750(830)
350(380)
200(220)
50(60)
Cost Effectiveness,
$/Mg ($/ton)
Average3
2,480(2,250)
1,930(1,750)
1,560(1,420)
1,270(1,150)
1,010(920)
860(780)
660(600)
560(510)
510(460)
2,480(2,250)
1,930(1,750)
1,600(1,450)
1,260(1,150)
1,030(940)
880(800)
Incremental
2,480(2,250)
310(280)
150(140)
1,270(1,150)
280(250)
280(250)
660(600)
260(240)
300(270)
2,480(2,250)
310(280)
310(280)
1,260(1,150)
350(320)
280(250)
Cost effectiveness compared to uncontrolled steam generating unit firing identical coal.
-------
P.45
percent removal efficiencies are minimal, especially when compared to the
increase in cost associated with the use of an FGD system over the use of
medium or low sulfur coal to reduce S0? emissions. However, there is a
substantial difference between the annual S0? emission reductions achieved
by an FGD system operated at 90 percent emission reduction and one operated
at 50 percent emission reduction. Thus, the cost effectiveness of achieving
a 90 percent reduction in S02 emissions on any given coal type is lower than
the cost effectiveness of achieving a 50 percent reduction in SO^ emissions.
Table 6-18 summarizes the cost impacts associated with a 90 percent
reduction requirement on coals with various sulfur contents in Regions V and
VIII. As shown, the average cost effectiveness over the regulatory baseline
of requiring a 90 percent reduction in SO,, emissions ranges from about
$560/Mg ($510/ton) to $l,050/Mg ($950/ton). The incremental cost
effectiveness over the use of low sulfur coal to achieve an emission level
of 516 ng/J (1.2 Ib/million Btu) heat input ranges from $770/Mg ($700/ton)
to $2,050/Mg ($l,860/ton).
Finally, it should be noted that the cost impacts discussed in the
above analysis represent the "worse case" impacts that might be incurred by
industrial-commercial-institutional steam generating units. As discussed
earlier, steam generating unit operators may switch fuels in response to
different S02 emission control requirements, thus avoiding many of the costs
associated with the control of SO,, emissions. The effect of fuel switching
on the cost effectiveness of emission controls can be dramatic, as outlined
below.
The costs presented above are presented on a before-tax annualized cost
basis. The fuel choice decision for new industrial-commercial-institutional
steam generating units, however, will most likely be made by determining the
lowest after-tax net present value (NPV) of the cash outlays for capital,
operating and maintenance, and fuel expenses over a fixed investment period.
Thus, the effects of fuel switching must be examined on an after-tax NPV
basis.
Table 6-19 illustrates the impact of fuel switching on costs, annual
emissions, and cost effectiveness of emission controls. For example,
6-38
-------
TABLE 6-18. COST IMPACTS FOR COAL-FIRED STEAM GENERATING UNITS IN REGIONS V AND VIII
90 Percent Reduction Requirement
REGION V
Cost Effectiveness,
$/Mg($/ton)
Coal Sulfur Content
ng S02/J (1b S02/million Btu)
29 MW (100 million Btu/hr):
903(2.5)
516(1.2)
2,580(6.0)
903(2.5)
516(1.2)
«* 44 MW (150 million Btu/hr):
(!o 903(2.5)
^> 516(1.2)
2,580(6.0)
903(2.5)
516(1.2)
73 MW (250 million Btu/hr):
903(2.5)
516(1.2)
2,580(6.0)
903(2.5)
516(1.2)
117 MW (400 million Btu/hr):
903(2.5)
516(1.2)
2,580(6.0)
903(2.5)
516(1.2)
Percent
Reduction
Required
0
0
90
90
90
0
0
90
90
90
0
0
90
90
90
0
0
90
90
90
Annual
Emissions
Mg/yr (tons/yr)
500(550)
230(250)
100(110)
35(40)
20(20)
750(830)
350(380)
150(170)
50(60)
30(30)
1,250(1,380)
560(620)
250(280)
90(100)
45(50)
2,010(2,210)
910(1,000)
400(440)
150(170)
70(80)
Annual i zed
Cost
$l,000/yr
4,430
4,560
4,800
4,890
4,940
6,160
6,340
6,620
6,760
6,840
10,430
10,750
11,080
11,300
11,440
15,200
15,700
16,100
16.460
16.680
Over Baseline
-
450(410)
910(830)
980(890)
1,050(950)
-
450(410)
770(700)
860(780)
940(850)
-
460(420)
640(580)
750(680)
840(760)
-
460(420)
560(510)
680(620)
760(690)
Over Low
Sulfur Coal
-
-
1,900(1,730)
1,760(1,600)
1,830(1,660)
_
-
1,450(1,320)
1,450(1,320)
1,560(1,420)
_
-
1,030(940)
1,180(1,070)
1,310(1,190)
_
.
770(700)
1,000(910)
1,160(1.050)
Annual ized
Cost
$l,000/yr
3,640
3,710
NAa
4,090
4,090
4,950
5,050
NA
5,560
5,550
8,200
8,370
NA
9,090
9,090
11,560
11,840
NA
12,860
12,860
REGION VIII
Cost Effectiveness,
$/Mg($/ton)
Over Basel ine
.
240(220)
.
970(880)
920(840)
-
230(210)
.
870(790)
810(740)
-
250(230)
.
770(700)
730(660)
-
250(230)
-
700(640)
670(610)
Over Low
Sulfur Coal
'
.
-
2,050(1,860)
1,820(1,650)
-
-
-
1,780(1,620)
1.580(1,440)
-
-
.
1,510(1,370)
1,350(1,230)
-
-
-
1,350(1,230)
1,220(1,110)
aNA = coal type not available.
-------
TABLE 6-19. IMPACTS OF FUEL SWITCHING ON COST ANALYSIS0
CT>
O
Alternative Control Level
Before-Tax
After-Tax Annualized Annual Cost
Net Present Value Cost Emissions Effectiveness
($1,000) ($l,000/year) Mg/year (tons/year) $/Mg($/ton)
516 ng/J (1.2 1 fa/mill ion Btu)
90 Percent Removal
Natural Gas
17,840
18,990
18,660
5,360
5,570
4,440
250 (280)
120 (130)
0 (0)
—
1,540 (1,400)
0 (0)
Based on a 44 MW (150 million Btu/hour) heat input capacity steam generating unit
in EPA Region V with an annual capacity utilization factor of 0.45.
-------
P.48
assuming that fuel choice decisions are based on the lowest cost after-tax
NPV, a 44 MW (150 million Btu/hour) heat input capacity steam generating
unit in Region V operating at an annual capacity utilization factor of 0.45
would fire low sulfur coal under an alternative control level based on the
use of low sulfur coal. However, in response to an alternative control
level requiring a 90 percent reduction in SOp emissions, this steam
generating unit would switch to firing natural gas, since this represents
the strategy with the lowest after-tax NPV which complies with this
alternative control level.
The annualized costs of firing a low sulfur coal to meet an alternatve
control level of 516 ng S02/J (1.2 Ib S02/million Btu) heat input would be
$5.36 million per year and annual SOp emissions would be 250 Mg SOp/year
(280 tons SOp/year). The annualized costs of installing an FGD on a
coal-fired steam generating unit in response to an alternative control level
requiring a 90 percent reduction in SOp emissions would be $5.57 million and
the annual SOp emissions would be 120 Mg SOp/year (130 tons SOp/year). The
annualized costs of firing natural gas, however, would be $4.44 million per
year and annual emissions would be zero. Thus, switching from coal to
natural gas in response to an alternative control level requiring a 90
percent reduction in SOp emissions would result in a significant reduction
in both annualized costs and annual SOp emissions. The incremental cost
effectiveness of control would be reduced from $l,540/Mg ($l,400/ton) of SOp
removed to zero due to this fuel switching.
This example shows that, under certain circumstances, steam generating
unit owners and operators can avoid certain costs associated with SOp
emission reduction requirements by switching to a cleaner fuel, rather than
installing FGD control equipment. For this model steam generating unit cost
analysis, however, it was assumed that all such owners and operators would
install control technology. Consequently, the costs and cost effectiveness
values cited should be viewed as "worse case" values.
6-41
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P.49
6.2 COSTS OF SULFUR DIOXIDE EMISSION CONTROL FOR OIL-FIRED
STEAM GENERATING UNITS
As with coal-fired steam generating units, there are two basic
approaches that can be used to reduce S02 emissions from oil-fired steam
generating units: the combustion of low sulfur oils, or the use of flue gas
desulfurization (FGD) systems. Although sodium, dual alkali, lime, and
limestone FGD systems are considered demonstrated for the purpose of
developing NSPS for oil-fired industrial-commercial-institutional steam
generating units, sodium scrubbing systems are the only FGD systems that
have received widespread application to oil-fired steam generating units.
Consequently, sodium scrubbing was used to represent the costs of FGD
systems in this analysis.
In addition, this cost analysis focuses only on EPA Region V. The
price of oil with a specific sulfur content varies on a regional basis;
however, the price differential among oils with various sulfur contents
remains essentially constant across all regions. For example, the price of
a 344 ng S02/J (0.8 Ib S02/million Btu) oil may vary substantially from one
regi-on to another, but the difference in price between a 344 ng SO?/J (0.8
Ib S02/million Btu) oil and a 688 ng S02/J (1.6 Ib S02/million Btu) oil
remains essentially the same. Therefore, although this analysis focuses
only on Region V, the impacts associated with various alternative S02
control levels are representative of impacts in all regions.
Finally, as in the analysis discussed above for coal-fired steam
generating units, the costs presented in this analysis for each of the
alternative control levels discussed below are based on the "least cost"
approach for complying with the requirements of that alternative. For
example, to comply with an alternative control level based on the use of low
sulfur oil, it may be less costly in some cases to fire a high sulfur oil
and install an FGD system to reduce S02 emissions than it is to fire a low
sulfur oil. In other words, the savings in annualized costs resulting from
firing less expensive high sulfur oil may compensate for the cost of the FGD
system.
6-42
-------
As discussed in "Performance of Demonstrated Emission Control
Technologies," SCL emissions could be reduced to 688 ng SCL/J (1.6 Ib
S02/million Btu), 344 ng Styj (0.8 Ib S02/million Btu), and 129 ng S02/J
(0.3 Ib SOp/million Btu) heat input through the use of low sulfur oils. To
reduce emissions to less than 129 ng S02/J (0.3 Ib S02/million Btu) heat
input, however, the use of FGD is necessary.
As discussed previously, there are two viewpoints from which to
approach the analysis of potential cost impacts associated with percent
reduction requirements based on the use of FGD systems. One is that a range
of percent reduction requirements merit consideration because FGD systems
can be operated over a wide range of S02 removal efficiencies. Another is
that a 90 percent reduction is the only percent reduction requirement that
merits serious consideration because all of the demonstrated FGD systems are
capable of achieving a 90 percent reduction in S0? emissions and current
practice for industrial-commercial-institutional steam generating units is
to design and install FGD systems capable of achieving this level of
performance.
As mentioned above, the use of very low sulfur oil could reduce S0?
emissions to 129 ng S02/J (0.3 Ib S02/million Btu). Achieving a percent
reduction of much less than 70 percent, however, would not reduce SOp
emissions to less than 129 ng S02/J (0.3 Ib S02/million Btu) on most oil
types. Consequently, from the viewpoint that a range of percent reduction
requirements should be considered, the lowest percent reduction requirement
that merits consideration is 70 percent. As discussed earlier in
"Performance of Demonstrated Emission Control Technologies," FGD systems are
capable of reducing S02 emissions by 90 percent. This, therefore,
represents the highest percent reduction requirement that merits
consideration.
Combining these two percent reduction requirements with the maximum
expected SOp emission rates associated with combustion of the various oils
discussed in "Performance of Demonstrated Emission Control Technologies"
results in the various S02 emission ceilings summarized in Table 6-20. As
shown in this table, there are only two alternatives with SOp emission
6-43
-------
TABLE 6-20. S02 EMISSION CEILINGS ASSOCIATED WITH VARIOUS PERCENT REDUCTION REQUIREMENTS
Oil Type
Very Low Sulfur
Low Sulfur
Medium Sulfur
High Sulfur
Maximum Expected
S0? Emission Rate
129 (0.3)
344 (0.8)
688 (1.6)
1,290(3.0)
S02 Emission Ceiling
70 Percent Reduction
43 (0.1)
86 (0.2)
215 (0.5)
387 (0.9)
90 Percent Reduction
22 (0.05)
43 (0.1)
86 (0.2)
129 (0.3)
aEmission rates and emission ceilings in ng SO^/J (Ib SO^/million Btu) heat input.
-------
P.52
ceilings associated with a 70 percent reduction requirement that would be
more effective in reducing SCL emissions than the use of low sulfur oil: 86
ng S02/J (0.2 Ib S02/million Btu) and 43 ng S02/0 (0.1 Ib S02/million Btu)
heat input. These two alternatives, therefore, are the only two associated
with a percent reduction requirement of 70 percent that merit consideration.
Assuming that a 90 percent emission reduction requirement should be
more effective in reducing S02 emissions than a 70 percent emission
reduction requirement, there is only one alternative associated with a 90
percent reduction requirement that merits consideration. As shown in
Table 6-20, this alternative has an S02 emission ceiling of 22 ng S02/J
(0.05 Ib S02/million Btu) heat input.
This viewpoint that a range of percent reduction requirements should be
considered, therefore, leads to three alternative percent reduction
requirements: two alternatives associated with a 70 percent reduction
requirement and one alternative associated with a 90 percent reduction
requirement. The difference in the S02 emission ceilings associated with
these three percent reduction requirements, however, is very small, only
about 43 ng SO^/J (0.1 Ib S02/million Btu) heat input. Consequently, rather
than examine all three alternative percent reduction requirements, only the
70 percent reduction requirement with an S02 emission ceiling of 43 ng S02/J
(0.1 Ib S02/million Btu) heat input was examined. This alternative is
generally representative of all three percent reduction requirements.
Combining this alternative percent reduction requirement with the three
alternatives mentioned above based on the use of low sulfur oil, in addition
to the regulatory baseline, results in five alternative control levels for
analysis under this viewpoint as summarized in Table 6-21.
As shown in Table 6-20, the alternative viewpoint that a 90 percent
reduction requirement is the only percent reduction requirement that merits
consideration results in only three alternatives with S02 emission ceilings
of less than 129 ng S02/J (0.3 Ib S02/million Btu) heat input. The S02
emission ceilings associated with these three alternatives happen to be the
same as those discussed above: 86 ng S02/J (0.2 Ib S02/million Btu), 43 ng
6-45
-------
P.53
TABLE 6-21. ALTERNATIVE CONTROL LEVELS FOR OIL-FIRED
INDUSTRIAL-COMMERCIAL-INSTITUTIONAL STEAM GENERATING UNITS
Range of Percent Reduction Requirements
Percent Reduction/
Emission Ceiling
ng/J Ob/million Btu)
None / 1290 (3.0)a
None / 688 (1.6)
None / 344 (0.8)
None / 129 (0.3)
70% / 43 (0.1)
Represents regulatory baseline.
Control Method
High Sulfur Oil
Medium Sulfur Oil
Low Sulfur Oil
Very Low Sulfur Oil
FGD with 70% Removal
6-46
-------
P.54
S02/J (0.1 Ib Stymillion Btu), and 22 ng S02/J (0.05 Ib S02/million Btu)
heat input. Again, since the difference among these S02 emission ceilings
is very small, only a 90 percent reduction requirement with an SO,, emission
ceiling of 43 ng SO^/O (0.1 Ib S02/million Btu) heat input was examined.
As summarized in Table 6-22, combining this alternative percent
reduction requirement with the three alternatives mentioned above based on
the use of low sulfur oil, in addition to the regulatory baseline, leads to
essentially the same alternative control levels for analysis as those
developed under the viewpoint that a range of percent reduction requirements
merits consideration. The only difference between these two sets of
alternative control levels is that a 70 percent reduction requirement is
included in one set and a 90 percent reduction requirement is included in
the other set. The S02 emission ceiling associated with these two percent
reduction requirements, however, is the same. Thus, the difference in
alternative control levels resulting from these two viewpoints for oil-fired
steam generating units is minimal. As in the analysis of cost impacts on
coal-fired steam generating units discussed above, however, both sets of
alternative control levels were examined. For convenience, the alternative
control levels resulting from the first viewpoint are referred to as "range
of percent reduction requirements" and the alternative control levels
resulting from the second viewpoint are referred to as "90 percent reduction
requirement."
Finally, as mentioned in the above discussion of the cost impacts on
coal-fired steam generating units, an S02 emission ceiling may preclude the
combustion of certain oils. In this analysis of the cost impacts on
oil-fired steam generating units, only one S02 emission ceiling was examined
- 43 ng S02/J (0.1 Ib S02/million Btu) heat input. This emission ceiling
would preclude combustion of both high sulfur and medium sulfur oils, and
would essentially require combustion of low sulfur oils.
6-47
-------
P.55
TABLE 6-22. ALTERNATIVE CONTROL LEVELS FOR OIL-FIRED
INDUSTRIAL-COMMERCIAL-INSTITUTIONAL STEAM GENERATING UNITS
90 Percent Reduction Requirement
Percent Reduction/
Emission Ceiling,
ng/J (Ib/million Btu)
None / 1290 (3.0)c
None / 688 (1.6)
None / 344 (0.8)
None / 129 (0.3)
90% / 43 (0.1)
Represents regulatory baseline,
Control Method
High Sulfur Oil
Medium Sulfur Oil
Low Sulfur Oil
Very Low Sulfur Oil
FGD with 90% Removal
6-48
-------
P.56
6.2.1 Range of Percent Reduction Requirements
The cost impacts associated with each alternative S02 control level
were examined for an oil-fired steam generating unit having a heat input
capacity of 44 MW (150 million Btu/hour) and an annual capacity utilization
factor of 0.55. This unit is representative of a typical oil-fired
industrial-commercial-institutional steam generating unit. Table 6-23
summarizes the results of this cost analysis.
Table 6-23 shows that the least cost approach to meeting an alternative
S02 control level of 129 ng S02/J (0.3 Ib S02/million Btu) is to fire a high
sulfur oil and install an FGD system, rather than burn a very low sulfur
oil. This result is explained by the high cost of a very low sulfur oil
compared to high sulfur oil. The cost savings associated with firing a high
sulfur oil outweigh the costs of an FGD system.
Table 6-23 also shows that the capital costs associated with
alternative control levels based on the use of medium and low sulfur oil
(but not for very low sulfur oil) are essentially the same as those for a
steam generating unit at the regulatory baseline. An alternative control
level requiring a percent reduction in SOp emissions, however, would
increase the capital costs for a 44 MW (150 million Btu/hour) heat input
capacity steam generating unit by about $0.8 million. This represents an
increase in capital cost of about 25 percent over the regulatory baseline.
For the reasons mentioned above, an alternative SOp control level based on
the use of very low sulfur oil has essentially the same impact on capital
costs as an alternative control level requiring a percent reduction in
emissions.
An alternative control level of 688 ng S02/J (1.6 Ib S02/million Btu)
heat input, based on the use of medium sulfur oil, would increase the
annualized costs for a typical 44 MW (150 million Btu/hour) heat input
capacity steam generating unit by about $220,000 per year. This represents
an increase in annualized costs of about 5 percent over the regulatory
baseline. An alternative control level of 344 ng S02/J (0.8 Ib S02/million
Btu) heat input, based on the use of low sulfur oil, would increase the
annualized costs by about $500,000 per year, an increase in annualized cost
6-49
-------
TABLE 6-23. COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED
STEAM GENERATING UNIT IN EPA REGION V
Range of Percent Reduction Requirements
cr>
en
o
Alternative Control
Level
Percent Reduction/
S07 Emission Ceiling
ng/J (Ib/million Btu)
None/1290 (3.0)a
None/ 688 (1.6)
None/344 (0.8)
None/129 (0.3)
70 Percent/43 (0.1)
"Least Cost" Approach
Percent
Removal
0
0
0
90
90
Oil Sulfur Content
ng/S02/J
(Ib S02/miflion Btu)
1,290 (3.0)
688 (1.6)
344 (0.8)
1,290 (3.0)
344 (0.8)
Annual
Emissions
Mg/yr
(tons/yr)
980 (1,080)
530 (580)
260 (290)
90 (100)
30 (30)
Capital
Cost
Smillion
3.2
3.3
3.3
4.0
4.0
Annual ized
Cost
$l,000/yr
4,640
4,860
5,140
5,220
5,500
Average
Cost
Effectiveness
$/Mg ($/ton)
-
480 (440)
690 (630)
650 (590)
900 (820)
Incremental
Cost
Effectiveness
$/Mg ($/ton)
-
480 (430)
1,070 (970)
460 (420)
4,400 (4,000)
Represent regulatory baseline.
TJ
Ol
-------
of about 11 percent over the regulatory baseline. An alternative control
level of 129 ng S02/J (0.3 Ib SO^/million Btu), based on the use of very low
sulfur oil, would increase the annualized costs by about $580,000 per year,
an increase of about 12 percent over the regulatory baseline.
An alternative control level requiring a 70 percent reduction in S0?
emissions with an S02 emission ceiling of 43 ng SOp/J (0.1 Ib SOp/million
Btu) heat input would increase annualized costs by about $860,000 per year.
This represents an increase of 18 percent over the regulatory baseline. An
alternative control level requiring a 70 percent reduction in emissions with
an S02 emission ceiling of 43 ng S02/J (0.1 Ib SO^/million Btu) heat input
would require that a low or very low sulfur oil be fired. The cost of the
FGD system coupled with the high cost of low or very low sulfur oil results
in a substantial increase in cost over the regulatory baseline.
The average cost effectiveness of each alternative control level is
also shown in Table 6-23. The average cost effectiveness is calculated as
the difference in costs between an alternative control level and the
regulatory baseline, divided by the difference in emissions between the
alternative control level and the regulatory baseline. The average cost
effectiveness associated with an alternative control level of 688 ng S02/J
(1.6 Ib SOp/million Btu) heat input based on the use of medium sulfur oil is
$480/Mg ($440/ton) of S02 removed. The average cost effectiveness
associated with an alternative control level of 344 ng S02/J (0.8 Ib
SOp/million Btu) heat input based on the use of low sulfur oil is
approximately $690/Mg ($630/ton) of SOp removed. The average cost
effectiveness associated with an alternative control level of 129 ng SOp/J
(0.3 Ib SOp/million Btu) heat input based on the use of very low sulfur oil
is about $650/Mg ($590/ton) of S0? removed. The average cost effectiveness
of an alternative control level requiring a 70 percent reduction in
emissions with an SOp emission ceiling of 43 ng SOp/J (0.1 Ib SOp/millioh
Btu) heat input is about $900/Mg ($820/ton) of S02 removed.
The incremental cost effectiveness of S02 control was also examined*
Incremental cost effectiveness is defined as the difference in cost between
two alternative control levels divided by the difference in emissions
6-51
-------
P.59
between the two alternative control levels. The incremental cost
effectiveness of an alternative control level of 344 ng S00/J (0.8 Ib
SOp/million Btu) heat input, based on the use of low sulfur oil, compared to
an alternative control level of 688 ng SCL/J (1.6 Ib SCL/million Btu) heat
input, based on the use of medium sulfur oil, is about $l,070/Mg ($970/ton)
of SOp removed. The incremental cost effectiveness of an alternative
control level of 129 ng SCL/J (0.3 Ib S02/million Btu) heat input, based on
the use of very low sulfur oil, compared to an alternative control level of
344 ng SO^/J (0.8 Ib SO^/million Btu) heat input, based on the use of low
sulfur oil, is about $460/Mg ($420/ton) of SOp removed. As mentioned above,
it is less costly to fire a high sulfur oil and install an FGD system to
meet an S02 emission limit of 129 ng SOp/J (0.3 Ib SOp/million Btu) heat
input than it is to fire a very low sulfur oil.
The incremental cost effectiveness of an alternative control level
requiring a 70 percent reduction in S0? emissions with an SOp emission
ceiling of 43 ng SOp/J (0.1 Ib SOp/million Btu) heat input, compared to an
alternative control level of 129 ng S02/J (0.3 Ib S02/million Btu) heat
input based on the use of very low sulfur oil, is about $4,400/Mg
($4,000/ton) of S02 removed. The high incremental cost effectiveness of an
alternative S02 control level requiring a 70 percent reduction in S02
emissions is due to the S0? emission ceiling of 43 ng SO?/J (0.1 Ib
SOp/million Btu) heat input associated with this percent reduction
requirement. This SOp emission ceiling is so low that it requires firing a
low or very low sulfur oil in addition to installing an FGD system. If this
SOp emission ceiling were increased to 129 ng SOp/J (0.3 Ib SOp/million Btu)
heat input, the incremental cost effectiveness of an alternative control
level requiring a 70 percent reduction in SOp emissions would decrease to
$0/Mg ($0/ton) of S0? removed. This alternative would then be the same as
the alternative control level of 129 ng SOp/J (0.3 Ib SOp/million Btu) heat
input based on the use of very low sulfur oil.
The cost impacts of alternative control levels were also examined as a
function of steam generating unit size. The results are summarized in
Table 6-24. Table 6-24 presents the increase in capital costs, the increase
6-52
-------
TABLE 6-24. COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
STEAM GENERATING UNIT SIZE IN EPA REGION V
Range of Percent Reduction Requirements
Percent Reduction/Emission Ceiling None/688 None/344 None/129 70 Percent/43
ng/J (Ib/million Btu) (1.6) (0.8) (0.3) (0.1)
Increase in Capital Cost Over Baseline, Percent
29 MW (100 million Btu/hour) 1 1 23 23
44 MW (150 million Btu/hour) 1 1 23 22
73 MW (250 million Btu/hour) 1 1 22 22
117 MW (400 million Btu/hour) 1 1 17 17
o> Increase in Annualized Cost Over Baseline, Percent
S 29 MW (100 million Btu/hour) 4 10 13 19
44 MW (150 million Btu/hour) 5 11 12 18
73 MW (250 million Btu/hour) 5 11 11 17
117 MW (400 million Btu/hour) 5 9 10 16
Average Cost Effectiveness, $/Mg ($/ton)
29 MW (100 million Btu/hour) 460 (420) 680 (620) 730 (660) 980 (890)
44 MW (150 million Btu/hour) 480 (440) 690 (630) 650 (590) 900 (820)
73 MW (250 million Btu/hour) 480 (440) 620 (560) 550 (500) 800 (740)
117 MW (400 million Btu/hour) 480 (440) 550 (500) 500 (450) 770 (700)
Incremental Cost Effectiveness, $/Mg ($/ton)
29 MW (100 million Btu/hour) 460 (420) 1,050 (950) 910 (830) 4,190 (3,800)
44 MW (150 million Btu/hour) 480 (440) 1,070 (970) 460 (420) 4,400 (4,000)
73 MW (250 million Btu/hour) 480 (440) 840 (760) 260 (240) 4,710 (4,270)
117 MW (400 million Btu/hour) 480 (440) 680 (620) 240 (220) 4,640 (4,220)
TJ
o>
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P.61
in annualized costs, and the cost effectiveness of control for typical 29
MW, 44 MW, 73 MW, and 117 MW (100, 150, 250, and 400 million Btu/hour) heat
input capacity steam generating units. As shown, the results and trends
discussed above for a 44 MW (150 million Btu/hour) heat input capacity steam
generating unit generally apply to other steam generating unit sizes as
well. Cost impacts of alternative control levels based on the use of medium
or low sulfur oil change very little with respect to unit size. Cost
impacts of alternative control levels based on the use of very low sulfur
oil or alternative control levels requiring a 70 percent reduction in SOp
emissions, however, decrease slightly with increasing steam generating unit
size due to the economies of scale of FGD systems.
Finally, the cost impacts of alternative control levels were examined
as a function of steam generating unit annual capacity utilization factor
for a 44 MW (150 million Btu/hour) heat input capacity oil-fired steam
generating unit. The results of this analysis are shown in Table 6-25.
Cost impacts are examined for annual capacity utilization factors of 0.15,
0.30, and 0.55.
Capital costs for a given steam generating unit are fixed, regardless
of the annual capacity utilization factor of the unit. However, operating
and maintenance costs such as fuel costs, utility costs, raw materials, and
waste disposal costs decrease with decreasing annual capacity utilization
factor. Therefore, at low annual capacity utilization factors capital
charges represent a larger percentage of the total annualized cost of
control. As annual capacity utilization factor increases, however, capital
charges become less important. Annual emissions, of course, are directly
proportional to the annual capacity utilization factor of the steam
generating unit.
The cost effectiveness associated with alternative S02 control levels
based on the use of medium or low sulfur oil are essentially constant with
respect to annual capacity utilization factor, because differences in fuel
prices are independent of annual capacity utilization factor. However, the
cost impacts associated with an alternative control level based on the use
of very low sulfur oil or an alternative control level requiring a 70
6-54
-------
cn
tn
TABLE 6-25. COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
STEAM GENERATING UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V
Range of Percent Reduction Requirements
Percent Reduction/Emission
ng/J (Ib/million Btu)
Ceiling None/688
(1.6)
None/344
(0.8)
None/129
(0.3)
70 Percent/43
(0.1)
Increase in Capital Cost Over Baseline, Percent
CUF = 0.15
CUF = 0.30
CUF = 0.55
Increase in Annual ized Cost
CUF = 0.15
CUF = 0.30
CUF = 0.55
Average Cost Effectiveness,
CUF = 0.15
CUF = 0.30
CUF = 0.55
0
0
1
Over Baseline, Percent
3
4
5
$/Mg ($/ton)
470 (430)
480 (440)
480 (440)
0
1
1
7
9
11
700 (640)
690 (630)
690 (630)
23
23
23
11
14
12
860 (780)
850 (770)
650 (590)
23
23
22
22
20
18
1,550 (1,410)
1,100 (1,000)
900 (820)
Incremental Cost Effectiveness, $/Mg ($/ton)
CUF = 0.15
CUF = 0.30
CUF = 0.55
470 (430)
480 (440)
480 (440)
1,100 (1,000)
1,040 (940)
1,070 (970)
1,540 (1,400)
1,540 (1,400)
460 (420)
11,000 (10,000)
4,410 ( 4,000)
4,400 ( 4,000)
-------
P.63
percent reduction in SCL emissions generally increase with decreasing annual
capacity utilization factor.
The method of control used to comply with an alternative control level
of 129 ng SCL/J (0.3 Ib SCL/million Btu) heat input also changes with
decreasing annual capacity utilization factor. At an annual capacity
utilization factor of 0.55, it is less costly to fire a high sulfur oil and
install an FGD system to reduce S02 emissions than it is to fire a very low
sulfur oil to comply with this alternative control level. However, at
annual capacity utilization factors of 0.15 and 0.30, this situation
reverses, and it is less costly to fire a very low sulfur oil. At these
lower annual capacity utilization factors, the capital cost charges
associated with the use of an FGD system are more significant than the
differences in fuel costs between high and very low sulfur oils.
The cost impacts associated with an alternative SOp control level
requiring a 70 percent reduction in S0? emissions increase with decreasing
capacity utilization factor because the fixed capital costs associated with
the FGD system must be borne by a lower level of operation.
The incremental cost effectiveness of the alternative control levels
also tends to improve as annual capacity utilization factor increases.
Again, this trend is most apparent for the alternative SO,, control level
based on the use of very low sulfur oil or the alternative S02 control level
requiring a 70 percent reduction in S02 emissions. For example, the
incremental cost effectiveness of the alternative control level based on the
use of very low sulfur oil to meet an emission limit of 129 ng SO^/J (0.3 Ib
SOp/million Btu) heat input ranges from about $460/Mg ($420/ton) of S02
removed at an annual capacity utilization factor of 0.55 to $l,540/Mg
($l,400/ton) of S02 removed at an annual capacity utilization factor of
0.15. Similarly, the incremental cost effectiveness of the alternative
control level requiring a 70 percent reduction in S02 emissions with an
emission ceiling of 43 ng SO?/J (0.1 Ib S02/million Btu) heat input ranges
from about $4,400/Mg ($4,000/ton) of S02 removed at an annual capacity
utilization factor of 0.55 to about $ll,000/Mg ($10,000/ton) of S02 removed
at an annual capacity utilization factor of 0.15.
6-56
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£64,
6.2.2 90 Percent Reduction Requirement
The cost impacts associated with each alternative control level were
examined for an oil-fired steam generating unit having a heat input capacity
of 44 MW (150 million Btu/hour) and an annual capacity utilization factor of
0.55. As mentioned above, this unit is representative of a typical
industrial-commercial-institutional steam generating unit. Table 6-26
summarizes the results of this cost analysis.
The alternative control levels based on the use of medium, low, and
very low sulfur oils to meet emission limits of 688, 344, and 129 ng SO?/J
(1.6, 0.8 and 0.3 Ib S02/million Btu) heat input, respectively, are
identical to those presented previously in Table 6-22. Therefore, the cost
impacts of alternative control levels based on the use of low sulfur oil
will not be discussed in detail below. This discussion will focus mainly on
the costs and cost impacts of an alternative control level based on a 90
percent reduction in S02 emissions.
An alternative control level requiring a 90 percent reduction in S0?
emissions coupled with an emission ceiling of 43 ng S02/J (0.1 Ib
S02/million Btu) heat input would increase the capital costs for a 44 MW
(150 million Btu/hour) heat input capacity steam generating unit by about
$0.8 million. This represents an increase in capital cost of about 25
percent over the regulatory baseline.
An alternative control level requiring a 90 percent reduction in SOp
emissions with an emission ceiling of 43 ng S02/J (0.1 Ib SOp/million Btu)
heat input would increase the -annualized costs of the steam generating unit
by about $860,000 per year. This represents an increase of about 18 percent
over the regulatory baseline.
The average cost effectiveness of S02 emission control associated with
each of the alternative control levels is also shown in Table 6-26. The
average cost effectiveness associated with an alternative control level
requiring a 90 percent reduction in S02 emissions with an emission ceiling
of 43 ng S02/J (0.1 Ib S02/million Btu) heat input is about $900/Mg
($820/ton) of S02 removed.
6-57
-------
en
00
TABLE 6-26. COST IMPACTS OF A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED
STEAM GENERATING UNIT IN EPA REGION V
90 Percent Reduction Requirement
Alternative Control
Level
Percent Reduction/
SO, Emission Ceiling
ngXJ (Ib/million Btu)
None/1290 (3.0)a
None/ 688 (1.6)
None/344 (0.8)
None/129 (0.3)
90 Percent/43 (0.1)
"Least Cost" Approach
Percent
Removal
0
0
0
90
90
Oil Sulfur Content
ng/S02/J
(1b S00/miflion Btu)
c.
1,290 (3.0)
688 (1.6)
344 (0.8)
1,290 (3.0)
344 (0.8)
Annual
Emissions
Mg/yr
(tons/yr)
980 (1,080)
530 (580)
260 (290)
90 (100)
30 (30)
Capital
Cost
$million
3.2
3.3
3.3
4.0
4.0
Annual ized
Cost
$l,000/yr
4,640
4,860
5,140
5,220
5,500
Average
Cost
Effectiveness
$/Mg ($/ton)
-
480 (440)
690 (630)
650 (590)
900 (820)
Incremental
Cost
Effectiveness
$/Mg ($/ton)
-
-
1,070 (970)
460 (420)
4,400 (4000)
Represents regulatory baseline.
CD
Ol
-------
P.66
The incremental cost effectiveness of SCL control was also examined.
The incremental cost effectiveness of an alternative control level requiring
a 90 percent reduction in S0? emissions with an emission ceiling of 43 ng
SOp/J (0.1 Ib SOp/million Btu) heat input, compared to an alternative
control level based on the use of very low sulfur oil is about $4,400/Mg
($4,000/ton) of SOp removed. As mentioned above, the high incremental cost
of the alternative control level requiring a 90 percent reduction in SOp
emissions is due to the SO- emission ceiling of 43 ng SOp/J (0.1 Ib
SOp/million Btu) heat input associated with this percent reduction
requirement. This SOp emission ceiling is so low that it requires the
firing of a low or very low sulfur oil in addition to the use of an FGD
system. If the SOp emission ceiling were increased to 129 ng SOp/J (0.3 Ib
SOp/million Btu) heat input, the incremental cost effectiveness of an
alternative control level requiring a 90 percent reduction in SOp emissions
would decrease to $0/Mg ($0/ton). This alternative would then be the same
as the alternative control level of 129 ng SOp/J (0.3 Ib SOp/million Btu)
heat input based on the use of very low sulfur oil.
The cost impacts of alternative SOp control levels were also examined
as a function of steam generating unit size. The results are summarized in
Table 6-27. Table 6-27 presents the increase in capital costs, the increase
in annualized costs, and the cost effectiveness of control for typical 29
MW, 44 MW, 73 MW and 117 MW (100, 150, 250 and 400 million Btu/hour) heat
input capacity steam generating units. As shown, the results and trends
discussed above for a 44 MW (150 million Btu/hour) heat input capacity steam
generating unit generally apply to other steam generating unit sizes as
well. Cost impacts of alternative control levels based on the use of low
sulfur oil change very little with respect to unit size. Cost impacts of
alternative control levels based on the use of very low sulfur oil or on a
90 percent reduction requirement, however, decrease slightly with increasing
steam generating unit size due to the economies of scale of FGD systems.
Finally, the cost impacts of alternative S02 control levels were
examined as a function of steam generating unit annual capacity utilization
factor for a 44 MW (150 million Btu/hour) heat input capacity oil-fired
6-59
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COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-27.
STEAM GENERATING UNIT SIZE IN EPA REGION V
90 Percent Reduction Requirement
Percent Reduction/Emission Ceiling
ng/J (Ib/million Btu)
None/688
(1.6)
None/344
(0.8)
None/129
(0.3)
90%/43
(0.1)
en
i
CD
o
Increase in Capital Cost Over Baseline, Percent
29 MW (100 million Btu/hour) 0
44 MW (150 million Btu/hour) 1
73 MW (250 million Btu/hour) 1
117 MW (400 million Btu/hour) 1
Increase in Annualized Cost Over Baseline, Percent
29 MW (100 million Btu/hour) 5
44 MW (150 million Btu/hour) 5
73 MW (250 million Btu/hour) 5
117 MW (400 million Btu/hour) 5
Average Cost Effectiveness, $/Mg ($/ton)
10
11
11
9
23
23
22
17
12
11
10
10
23
22
22
17
19
18
17
16
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73'MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
Incremental Cost Effectiveness, $/Mg
29 MW (100 million Btu/hour)
44 MW (150 million Btu/hour)
73 MW (250 million Btu/hour)
117 MW (400 million Btu/hour)
460 (420)
480 (440)
480 (440)
480 (440)
($/ton)
460 (420)
480 (440)
480 (440)
480 (440)
680 (620)
690 (630)
620 (560)
550 (500)
1050 (950)
1070 (970)
840 (760)
680 (620)
730 (660)
650 (590)
550 (500)
500 (450)
910 (830)
460 (420)
260 (240)
240 (220)
980 (890)
900 (820)
800 (740)
760 (690)
4180 (3800)
4400 (4000)
4700 (4270)
4640 (4220)
-------
P.68
steam generating unit. The results of this analysis are shown in
Table 6-28. , Cost impacts were examined for annual capacity utilization
factors of 0.15, 0.30, and 0.55.
The cost impacts associated with an alternative control level based on
the use of very low sulfur oil or an alternative control level requiring a
90 percent reduction in S02 emissions generally increase with decreasing
annual capacity utilization factor. As discussed previously, the least cost
approach to comply with an alternative control level based on the use of
very low sulfur oil changes with respect to annual capacity utilization
factor. At an annual capacity utilization factor of 0.55, it is less costly
to install an FGD system and fire high sulfur oil than it is to fire a very
low sulfur oil to meet an emission limit of 129 ng SO?/J (0.3 Ib S0?/million
Btu); at annual capacity utilization factors of 0.15 and 0.30, it is less
costly to fire very low sulfur oil. The impacts associated with an
alternative control level based on a 90 percent reduction in S02 emissions
increase with decreasing annual capacity utilization factor because the
fixed capital costs associated with the FGD system must be borne by a lower
level of operation.
The averge cost effectiveness of an alternative control level requiring
a 90 percent reduction in SOp emissions with an SOp emission ceiling of 43
ng S02/J (0.1 Ib S02/million Btu) heat input increases from $880/Mg
($800/ton) to $l,550/Mg ($l,410/ton) of SO^ removed as annual capacity
utilization factor decreases.
The incremental cost effectiveness of the alternative control levels
also tends to improve as annual capacity utilization factor increases.
Again, this trend is most apparent for the alternative S02 control level
requiring a 90 percent reduction in S02 emissions, compared to the
alternative control level based on the use of very low sulfur oil.
6.2.3 Summary of Analysis
The results of this cost analysis indicate that the impacts associated
with alternative S02 control levels based on the use of medium or low sulfur
6-61
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COST IMPACTS OF S02 CONTROL AS A FUNCTION OF
TABLE 6-28.
STEAM GENERATING UNIT CAPACITY UTILIZATION FACTOR IN EPA REGION V
90 Percent Reduction Requirement
ro
Percent Reduction/Emission Ceiling
ng/J (Ib/million Btu)
None/688
(1.6)
None/344
(0.8)
None/129
(0.3)
90%/43
(0.1)
Increase in Capital Cost Over Baseline, Percent
CUF = 0.15
CUF = 0.30
CUF = 0.55
Increase in Annual ized Cost Over Baseline,
CUF = 0.15
CUF = 0.30
CUF = 0.55
Average Cost Effectiveness, $/Mg ($/ton)
CUF = 0.15
CUF = 0.30
CUF = 0.55
Incremental Cost Effectiveness, $/Mg ($/ton
CUF = 0.15
CUF = 0.30
CUF = 0.55
0
0
0
Percent
3
4
5
470 (430)
480 (440)
480 (440)
)
470 (430)
480 (440)
480 (440)
0
1
1
7
9
11
704 (640)
690 (630)
690 (630)
1100 (1000)
1030 (940)
1070 (970)
23
23
23
17
15
12
860 (780)
850 (770)
650 (590)
1540 (1400)
1540 (1400)
460 (420)
23
23
22
22
20
18
1550 (1410)
1100 (1000)
900 (820)
11000 (10000)
4410 (4000)
4400 (4000)
O)
CO
-------
P.70
oil are lower than those associated with alternative control levels based on
the use of very low sulfur oil or requiring a 90 percent reduction in SO,
emissions. Furthermore, the impacts associated with alternative control
levels based on the use of medium or low sulfur oil are fairly constant with
respect to steam generating unit size and annual capacity utilization factor
because fuel prices do not change with respect to unit size or annual
capacity utilization factor.
Unlike the analysis of cost impacts on coal-fired steam generating
units discussed above, the cost impacts on oil-fired steam generating units
do not vary depending on the viewpoint used in developing alternative
control levels based on percent reduction requirements. No matter which
viewpoint is adopted, either a range of percent reduction requirements or a
90 percent reduction requirement, the cost impacts associated with
alternative control levels based on percent reduction requirements are the
same. This results from the fact that the SO,, emission ceiling associated
with the two percent reduction requirements examined in this analysis was
the same. In addition, it was also low enough to effectively preclude
combustion of medium and high sulfur oils and require combustion of low
sulfur oil. As a result, the impacts associated with both the 70 percent
and 90 percent reduction requirements were found to be the same.
In addition, there are only minimal cost differences among alternative
control levels based on a percent reduction in S02 emissions even when
considered independently of an associated emission ceiling. Table 6-29
shows that the differences in annualized costs among FGD systems operated
over a range of percent removal efficiencies are minimal for low, medium,
and high sulfur oils. However, there is a substantial difference between
the annual SO,, emission reductions achieved by a FGD system operated at 90
percent removal and one operated at 50 percent or 70 percent removal. As
was found in the analysis of cost impacts for coal-fired steam generating
units, an alternative control level based on a 90 percent reduction in S02
emissions is, therefore, more cost effective than alternative control levels
requiring either a 50 percent or 70 percent reduction in S02 emissions.
6-63
-------
TABLE 6-29. COST EFFECTIVENESS OF A RANGE OF PERCENT REDUCTION REQUIREMENTS FOR A 44 MW
(150 MILLION BTU/HR) OIL-FIRED STEAM GENERATING UNIT IN REGION V
Percent
Reduction
Oil Sulfur Content
ng S02/J (Ib S02/10b Btu)
Annualized Cost
$l,000/yr
Annual Emissions
Mg/yr (tons/yr)
Cost Effectiveness
$/Mg ($/ton) Removed
Average
Incremental
cr>
i
Low Sulfur Oil
50
70
90
Medium Sulfur Oil
50
70
90
High Sulfur Oil
50
70
90
344 (0.8)
688 (1.6)
1,290 (3.0)
5,140
5,470
5,485
5,500
4,860
5,250
5,280
5,310
4,640
5,100
5,160
5,220
262 (289)
100 (110)
60 (66)
20 (22)
524 (578)
200 (220)
120 (132)
40 (44)
983 (1,084)
372 (410)
223 (246)
74 (82)
2,040 (1,850)
1,710 (1,550)
1,490 (1,350)
1,205 (1,090)
1,060 (960)
930 (840)
760 (680)
685 (620)
640 (580)
2,040 (1,850)
375 (340)
375 (340)
1,205 (1,070)
375 (340)
375 (340)
760 (680)
400 (365)
400 (365)
-------
P.72
For the typical oil-fired steam generating unit, unlike the typical
coal-fired steam generating unit, the analysis also found that an
alternative control level based on the use of very low sulfur fuel has
essentially the same impact as an alternative control level based on a
percent reduction requirement and having the same emission ceiling. This
results from the fact that it is less costly to fire high sulfur oil and
install an F6D system to reduce SCL emissions than to fire very low sulfur
oil.
The cost effectiveness of alternative control levels based on percent
reduction requirements, however, can be quite different from the cost
effectiveness of an alternative control level based on the use of very low
sulfur oil. If the S02 emission ceiling associated with the percent
reduction requirement is low enough to effectively require the use of medium
or low sulfur oil and preclude the use of high sulfur oil, the cost
effectiveness of an alternative control level based on a percent reduction
requirement is less attractive than that of an alternative control level
based on the use of very low sulfur oil.
On the other hand, if the S(L emission ceiling is the same as that
associated with the use of very low sulfur oil, then the average cost
effectiveness of an alternative control level based on a percent reduction
requirement is the same as that of an alternative control level based on the
use of very low sulfur oil. In addition, the incremental cost effectiveness
between an alternative control level based on a percent reduction
requirement and an alternative control level based on the use of very low
sulfur oil is zero.
For steam generating units with low annual capacity utilization
factors, however, the impacts of an alternative control level based on a
percent reduction requirement and the impacts of an alternative control
level based on the use of very low sulfur oil are quite different. In this
case, it is less costly to fire a very low sulfur oil than to fire a high
sulfur oil and install an FGD system to reduce SCL emissions. Consequently,
for oil-fired steam generating units with low annual capacity utilization
factors, as with coal-fired steam generating units with low annual capacity
6-65
-------
P.73
utilization factors, the cost effectiveness of alternative control levels
based on percent reduction requirements are always significantly less
attractive than the cost effectiveness of an alternative control level based
on the use of low sulfur fuels.
Table 6-30 summarizes the cost impacts associated with a 90 percent
reduction requirement on high and low sulfur oils. The average cost
effectiveness over the regulatory baseline ranges from approximately $500 to
$950/Mg ($450 to $860/ton) of S02 removed. The incremental cost
effectiveness of a 90 percent reduction requirement over the use of low
sulfur oil to meet an emission limit of 344 ng SO?/J (0.8 Ib S02/million
Btu) heat input ranges from $0 to $750/Mg ($0 to $680/ton) on high sulfur
oil and from $970 to $l,740/Mg ($880 to $l,580/ton) on low sulfur oil.
The results of this cost analysis also show that at steam generating
unit annual capacity utilization factors of 0.55 or greater, it is less
costly to fire a high sulfur oil and install an FGD system to reduce S02
emissions than to fire a very low sulfur oil to meet an emission limit of
129 ng SOp/J (0.3 Ib S02/million Btu) heat input. At lower annual capacity
utilization factors, however, it is less costly to fire very low sulfur oil.
For an alternative control level requiring a 90 percent reduction in
SOp emissions or, in many cases, an alternative control level based on the
use of very low sulfur oil, the cost impacts vary as a function of steam
generating unit size and annual capacity utilization factor. Annual
capacity utilization factor is the most important of these factors in
determining the impacts. As the annual capacity utilization factor
decreases, the cost impacts increase significantly. In addition, the cost
impacts generally decrease with increasing steam generating unit size.
Finally, as mentioned above in the analysis of cost impacts on
coal-fired steam generating units, the cost impacts discussed above
represent the "worse case" impacts that might be incurred by oil-fired
industrial-commercial-institutional steam generating units. As discussed
previously, steam generating unit operators may switch fuels in response to
an NSPS, thus avoiding many of the costs associated with control of S02
emissions. For example, a steam generating unit operator switching from oil
6-66
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TABLE 6-30. COST
IMPACTS FOR OIL-FIRED
STEAM GENERATING UNITS
IN REGION V
90 Percent Reduction Requirement
Oil Sulfur Content
ng S02/J (Ib S02/million Btu)
29 MW (100 million Btu/hr):
1,290(3.0)
344(0.8)
1,290(3.0)
344(0.8)
44 MW (150 million Btu/hr):
1,290(3.0)
344(0.8)
1,290(3.0)
^ 344(0.8)
^ 73 MW (250 million Btu/hr):
1,290(3.0)
344(0.8)
1,290(3.0)
344(0.8)
117 MW (400 million Btu/hr):
1,290(3.0)
344(0.8)
1,290(3.0)
344(0.8)
Percent
Reduction
Required
0
0
90
90
0
0
90
90
0
0
90
90
0
0
90
90
Annual
Emissions
Mg/yr (tons/yr)
650(720)
170(190)
50(60)
20(20)
980(1080)
260(290)
70(80)
20(20)
1,630(1800)
440(480)
130(140)
40(40)
2,620(2890)
700(770)
200(220)
50(60)
Annualized
Cost
$l,000/yr
3,260
3,580
3,680
3,870
4,640
5,140
5,200
5,480
7,380
8,220
8,210
8,680
11,950
13,270
13,140
13,890
Cost Effectiveness, $/Mq ($/ton)
Over Baseline
.
680(620)
690(630)
950(860)
-
680(620)
620(560)
870(790)
.
690(630)
550(500)
810(740)
-
680(620)
500(450)
760(690)
Over Low Sulfur Oil
-
-
750(680)
1,740(1,580)
-
-
340(310)
1,430(1,300)
-
-
0(0)
1,140(1,040)
-
-
0(0)
970(880)
—
-------
to natural gas to avoid the costs of installing an FGD system would not only
reduce the annualized costs associated with control of SOp emissions, but
would also achieve greater reductions in SOp emissions. As a result, fuel
switching can have a significant impact on the cost effectiveness of SCL
emission control. Consequently, because the above discussion does not
consider the possibility of fuel switching in response to alternative
control levels, the costs and cost effectiveness values cited should be
viewed as "worse case."
6.3 COSTS OF SULFUR DIOXIDE EMISSION CONTROL FOR MIXED FUEL-FIRED
STEAM GENERATING UNITS
The SOp emissions resulting from combustion of wood, solid waste, and
natural gas are negligible. As a result, SOp emissions from industrial-
commercial-institutional steam generating units firing mixtures of coal or
oil with nonfossil fuels such as wood or municipal solid waste, or even
nonsulfur-bearing fossil fuels such as natural gas, are lower than SOp
emissions from coal- or oil-fired steam generating units.
To comply with an alternative control level based on the use of; low
sulfur fuel, a coal- or oil-fired steam generating unit would be required to
fire a low sulfur fuel or install an FGD system to reduce SOp emissions. As
discussed in the analysis presented above, a coal- or oil-fired steam
generating unit will generally choose to minimize costs and fire low sulfur
fuel.
A mixed fuel-fired steam generating unit will also choose to minimize
costs to comply with this same alternative control level. Because of the
"dilution" of the SOp emissions resulting from combustion of coal or oil
with the exhaust gases resulting from combustion of a nonsulfur-bearing
fuel, however, a mixed fuel-fired steam generating unit will not fire a low
sulfur fuel, if an emission credit is granted for the heat input to the
steam generating unit from the nonsulfur bearing fuel. This steam
generating unit will fire a medium or even high sulfur fuel.
6-68
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P.76
A similar situation arises with alternative control levels requiring a
percent reduction in SCL emissions. A coal- or oil-fired steam generating
unit would be required to achieve the specific percent reduction requirement
included in an alternative control level requiring such a reduction in S0o
emissions. With an emission credit, however, a mixed fuel-fired steam
generating unit would not be required to achieve this percent reduction
requirement, but would be permitted to achieve a lower percent reduction
requirement.
The merits of emission credits for mixed fuel-fired steam generating
units, as well as the merits of emission credits for other types of steam
generating units, are discussed in "Consideration of Emission Credits."
Assuming emission credits are not granted for mixed fuel-fired steam
generating units, a mixed fuel-fired steam generating unit firing a mixture
of coal or oil and other nonsulfur-bearing fuels can be considered a type of
low annual capacity utilization factor coal- or oil-fired steam generating
unit. To do this, the fossil fuel utilization factor of mixed fuel-fired
steam generating units is defined as the actual annual heat input to the
steam generating unit from coal or oil divided by the total maximum annual
heat input to the unit.if the unit were operated at design capacity for 24
hours per day, 365 days per year. For example, a steam generating unit
firing 50 percent coal and 50 percent wood, and having an annual capacity
.utilization factor of 0.60, would have a fossil fuel utilization factor of
0.30. Emissions of SO,, from a coal-fired steam generating unit operating at
an annual capacity utilization factor of 0.3 and a mixed fuel-fired steam
generating unit (e.g., coal/wood) operating at a fossil fuel utilization
factor of 0.3 would be the same.
Without emission credits, the costs associated with alternative control
levels based on the use of low sulfur fuels would be essentially the same
for both fossil fuel-fired and mixed fuel-fired steam generating units.
Both types of steam generating units would be required to fire low sulfur
fuels or install FGD systems to reduce S02 emissions.
The costs associated with alternative control levels based on percent
reduction requirements would also be essentially the same. In both cases,
6-69
-------
the FGD system would be designed and installed to handle the total exhaust
gas volume from the steam generating unit. This would be necessary for the
mixed fuel-fired steam generating unit, as well as the coal- or oil-fired
steam generating unit, because the coal or oil fired in the mixed fuel-fired
steam generating unit would represent 100 percent of the heat input when
other fuels, such as wood, solid waste, and natural gas, are unavailable.
Similarly, the operating and maintenance costs would also be the same.
These costs are primarily a function of the amount of S02 removed by the FGD
system. This would be the same for both the mixed fuel-fired steam
generating unit and the coal- or oil-fired steam generating unit.
Figure 6-1 illustrates these similarities in terms of the incremental
cost effectiveness of a percent reduction requirement over a requirement
based on the use of low sulfur fuel. As shown, the incremental cost
effectiveness of S02 control for coal-fired steam generating units and mixed
fuel-fired steam generating units are within the same range at all fossil
fuel utilization factors. The variation in the incremental cost
effectiveness shown in this figure for mixed fuel-fired steam generating
units located in Regions I, IV, and X is the result of the wide variation in
fuel types and prices among these regions and is not due to differences in
the costs of flue gas desulfurization systems.
Without emission credits, therefore, the cost impacts on mixed
fuel-fired steam generating units associated with alternative control levels
based on the use of low sulfur fuels or requiring a percent reduction in S02
emissions are essentially the same as those discussed above for low annual
capacity utilization factor coal- or oil-fired steam generating units.
6.4 COSTS OF PARTICULATE MATTER EMISSION CONTROL FOR OIL-FIRED
STEAM GENERATING UNITS
As discussed in "Selection of Demonstrated Emission Control
Technologies," there are three approaches that can be used to reduce
particulate matter emissions from oil-fired industrial-commercial-
6-70
-------
,£78
8,000-
7,000-
6,000-
e
e
*» 5,000-
« 4,000-
*•
•>
u
o
o
« 3,000-
o
c
2,000-
1,000-
Fossil Fuel-Fired Steam
Generating Units
Mixed Fuel-Fired Steam
Generating Units
Raglon IV
R*glon I
R*glon V^\
\
\
\
\
\
\
Region VIII
Rtglon X
\
\
\
0.15 0.30
Fottll Fu«l Utilization Factor
o.eo
Figure 6-1. Incremental Cost Effectiveness of a Percent Reduction Requirement
Over a Low Sulfur Fuel Requirement for 44 MW (150 Million Btu/
Hour) Heat Input Capacity Coal-Fired and Mixed Fuel-Fired Steam
Generating Units
6-71
-------
P.79
institutional steam generating units. The'se are: the use of low sulfur oil
to reduce both SCL and particulate matter emissions; the use of wet flue gas
desulfurization (FGD) systems to reduce both S(L and particulate matter
emissions; and the use of wet scrubbers or electrostatic precipitators
(ESP's) to reduce particulate matter emissions only.
To analyze the potential cost impacts associated with limiting
particulate matter emissions from new oil-fired industrial-commercial-
institutional steam generating units, a regulatory baseline was developed.
The regulatory baseline reflects the level of emission control that would be
required in the absence of new source performance standards. An analysis of
existing State implementation plans (SIP's) indicates that the average
particulate matter emission limit for oil-fired industrial-commercial-
institutional steam generating units is approximately 108 ng/J (0.25
Ib/million Btu). This emission limit can generally be met even when firing
high sulfur oil with no add-on controls. Therefore, the regulatory baseline
selected was 108 ng/J (0.25 Ib/million Btu) heat input, based on an
uncontrolled oil-fired steam generating unit firing a high sulfur oil.
Costs for particulate matter controls were examined for a 44 MW (150
million Btu/hour) heat input capacity oil-fired steam generating unit with
an annual capacity utilization factor of 0.55. This unit represents a
typical oil-fired industrial-commercial-institutional steam -generating unit.
Table 6-31 presents the results of this cost analysis.
Table 6-31 shows that the capital cost for an oil-fired steam
generating unit at the regulatory baseline is about $3.2 million and the
annualized cost is about $4.66 million. Annual particulate matter emissions
from a 44 MW (150 million Btu/hour) heat input capacity steam generating
unit at the regulatory baseline are about 81 Mg/year (90 tons/year).
Costs associated with the use of low sulfur oil and the use of wet FGD
systems to reduce S02 emissions are discussed above. Since these costs are
all included under the cost of S0? control, the additional cost for
particulate matter control is negligible. Thus, the average cost
effectiveness of particulate matter control associated with use of these
6-72
-------
,£80.
TABLE 6-31. COST IMPACTS OF PARTICULATE MATTER CONTROL
FOR A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED STEAM
GENERATING UNIT IN REGION V
Control Technique
Annual
Emissions Capital Annualized Average Cost
Mg/year Cost Cost Effectivene$s
(tons/year) SMillion $l,000/year $/Mg ($/ton)
High Sulfur Oil'
Low Sulfur Oilb
81 (90)
33 (36)
Flue Gas Desulfurizationb 33 (36)
Wet Scrubber 33 (36)
Electrostatic Precipitator 23 (25)
3.2 4,660
3.2 5,150 0 (0)
4.0 5,220 0 (0)
3.8 4,870 4,290 (3,900)
4.8 5,000 6,930 (6,300)
Regulatory baseline.
The cost of control can be attributed to SOp control; additional cost
associated with particulate matter control is negligible.
6-73
-------
P.81
emission control techniques is essentially zero. This is true regardless of
steam generating unit size or annual capacity utilization factor.
Because control of S(L emissions also results in control of particulate
matter emissions, the use of other particulate matter emission control
technologies, such as wet scrubbers or ESP's, would not be necessary to
reduce particulate matter emissions from oil-fired steam generating units.
For completeness, however, the costs associated with these particulate
matter control technologies are outlined below.
Installation of a wet scrubber or ESP to reduce particulate matter
emissions from a 44 MW (150 million Btu/hour) heat input capacity oil-fired
steam generating unit would increase capital costs over the regulatory
baseline by about $550,000 for a wet scrubber and by about $1.6 million for
an ESP. The increase in annualized costs over the regulatory baseline would
be about $210,000 and about $340,000 per year, respectively. The average
cost effectiveness of particulate matter control associated with the use of
a wet scrubber would be about $4,280/Mg ($3,900/ton), and the average cost
effectiveness associated with the use of an ESP would be about $6,940/Mg
($6,300/ton).
6.5 COSTS OF PARTICULATE MATTER EMISSION CONTROL FOR COAL-FIRED STEAM
GENERATING UNITS EQUIPPED WITH FGD SYSTEMS
There are two alternatives that could be used to reduce particulate
matter emissions from coal-fired steam generating units equipped with flue
gas desulfurization systems for control of SO^ emissions. These are: use of
the FGD system to reduce emissions of particulate matter; or use of a fabric
filter or an electrostatic precipitator upstream of the FGD system to reduce
emissions of particulate matter.
The potential cost impacts associated with each of these alternatives
were assessed. Costs were developed for a sodium FGD system and compared to
the costs of installing a fabric filter upstream of this FGD system. As
discussed in "Performance of Demonstrated Emission Control Technologies,"
wet scrubbing FGD systems are capable of reducing particulate matter
6-74
-------
P.82
emissions to 43 ng/J (0.1 Ib/million Btu) heat input. A fabric filter, on
the other hand, is capable of reducing particulate matter emissions to 21
ng/J (0.05 Ib/million Btu) heat input. Costs of particulate matter control
were examined for a typical 44 MW (150 million Btu/hour) heat input capacity
steam generating unit operating at an annual capacity utilization factor of
0.6 in EPA Region V and firing coal with an average sulfur content of 2,380
ng S02/J (5.54 Ib S02/million Btu) heat input.
The results of this analysis are presented in Table 6-32. The
incremental annualized costs of installing and operating a fabric filter
compared to using the FGD system alone to control particulate matter
emissions are about $20,000. The incremental cost effectiveness of
installing and operating a fabric filter for particulate matter control,
therefore, compared to using the FGD system alone for particulate matter-
control, would be about $l,275/Mg ($l,160/ton) of particulate matter
removed.
6-75
-------
TABLE 6-32. COST IMPACTS OF PARTICULATE MATTER CONTROL FOR A 44 MW (150 MILLION BTU/HOUR)
COAL-FIRED STEAM GENERATING UNIT IN REGION V
I
*-J
CT>
Control Technique
FGD, Combined PM/
S02 Control
FGD, S09 Control Alone
FF, PM Control
Annual i zed
PM Emissions,
Mg/yr (tons/yr)
36 (39)
18 (20)
Incremental
Annual ized Costs, $l,000/yr Cost Effectiveness,
-------
P.84
7.0 CONSIDERATION OF SECONDARY ENVIRONMENTAL IMPACTS
Secondary environmental impacts associated with standards based on the
use of low sulfur fuels or requiring a percent reduction in S02 emissions
(i.e., based on the use of FGD systems) result primarily from the decrease
in S02 emissions and the increase in liquid or solid wastes that may be
generated from the use of various S0? control technologies. A related
impact is an increase in the consumption of water resulting from the use of
FGD systems.
As discussed in "Consideration of National Impacts," one of the results
of a sulfur dioxide standard requiring a percent reduction in S02 emissions
is fuel switching from coal and oil to natural gas. The secondary
environmental impacts resulting from the increased liquid and solid wastes
generated from the use of FGD discussed in this section would not occur at
those facilities switching to natural gas. In addition, this fuel switching
would result in a reduction in emissions of particulate matter and nitrogen
oxides due to the lower emission levels of these pollutants resulting from
combustion of natural gas.
7.1 AIR QUALITY IMPACTS
A dispersion analysis was performed to assess the ambient air quality
impacts associated with standards based on the use of low sulfur fuel and
standards requiring a percent reduction in SOp emissions. This analysis
used the single source (CRSTER) model to estimate the ambient air
concentrations of S0« resulting from each control alternative for model
coal- and oil-fired steam generating units. Estimated maximum downwind
ambient air SOp concentrations were calculated on an annual average and
24-hour average basis for a typical steam generating unit with a heat input
capacity of 44 MW (150 million Btu/hour).
As a basis for the dispersion analysis, it was assumed that: (1) the
pollutants displayed the dispersion behavior of a non-reactive gas; (2) all
sources were located on flat or gently rolling terrain in urban areas;
7-1
-------
P 85
(3) the model coal-fired steam generating unit was operated at a capacity
utilization factor of 0.6 and the model oil-fired steam generating unit was
operated at a capacity utilization factor of 0.55; (4) the stack height of
each model steam generating unit was 53 meters (175 feet); (5) the stack gas
temperature was 150°C (300°F) for units without FGD and 52°C (125°F) for
units with FGD; (6) all model steam generating unit stacks were modeled as
continuous point sources of emissions; (7) receptors were located at the
same elevation as the base of the stack; and (8) 1964 meteorological data
for St. Louis were used.
Table 7-1 presents the maximum downwind ambient air S02 concentrations
as predicted by the single source (CRSTER) model and compares them to the
ambient air SOp concentrations allowed under the National Ambient Air
Quality Standards (NAAQS) and the Prevention of Significant Deterioration
(PSD) Class II deterioration increments. The predicted ground level ambient
air concentrations resulting from S02 control under both regulatory
alternatives were all below the NAAQS, with maximum annual S0? concentra-
tions ranging from 1.1 to 2.1 percent of the annual standard and maximum
24-hour S02 concentrations ranging from 3.3 to 6.2 percent of the 24-hour
standard. The ambient air S02 concentrations resulting from SOp control
under both regulatory alternatives were also below the PSD Class II
deterioration increments, with maximum annual ambient air SOp concentrations
ranging from 4.3 to 8.3 percent of the annual PSD increment and maximum
24-hour SOp concentrations ranging from 13.3 to 25 percent of the 24-hour
PSD increment.
The data for both coal- and oil-fired steam generating units also
indicate that ambient air concentrations of SOp decrease significantly in
going from baseline control levels to control levels reflecting either the
use of low sulfur fuel or a percent reduction in SOp emissions. If a steam
generating unit equipped with FGD achieved the same SOp emission rate as a
steam generating unit firing low sulfur fuel, higher ambient air S02
concentrations would result from the steam generating unit equipped with
FGD. The lower gas temperature associated with the use of FGD reduces the
gas plume buoyancy, thereby reducing dispersion of the pollutants emitted
7-2
-------
TABLE 7-1. S02 DISPERSION ANALYSIS
Maximum Downwind Ambient Concentration, pg/m (10" gr/dscf)
Fuel Regulatory Alternative
Coal Regulatory Baseline ,
1,076 ng S02/J (2.5 Ib S02/10° Btu)
Low Sulfur Coal ,
516 ng S02/J (1.2 Ib S02/10° Btu)
Percent Reduction
90% Reduction and 258 ng SO,/J
(0.6 Ib S02/10° Btu) *
Oil Regulatory Baseline ,
1,291 ng S02/J (3.0 Ib S02/10b Btu)
^j Low Sulfur Oil ,
<|0 344 ng S02/J (0.8 Ib S02/10° Btu)
Percent Reduction
90% Reduction and 129 ng SO,/J
(0.3 Ib S02/10° Btu) i
Annual Mean
3.46 (1.49)
1.66 (0.72)
1.59 (0.69)
4.50 (1.94)
1.20 (0.52)
0.86 (0.37)
Percent of
NAAQSa
4.3
2.1
2.0
'• • >~
5.6
1.5
1.1
Percent of PSD
Increment
17.3
8.3
7.9
22.5
6.0
4.3
24-Hour
43.85 (18.93)
21.05 (9.09)
22.74 (9.82)
55.99 (24.17)
14.93 (6.45)
12.10 (5.22)
Percent of
NAAQSC
12.0
5.8
6.2
15.3
4.1
3.3
Percent of BSD
Increment
48.2
23.1
25.0
61.5
16.4
13.3
-6
dS02 NAAQS (annual mean) = 80 pg/nT (34.54x10"° gr/dscf).
PSD Class II increment (annual mean) = 20 pg/m (8.64x10 gr/dscf).
CS02 NAAQS (maximum 24-hr) = 365 wg/m3 (157.60xlO"6 gr/dscf).
dPSD Class II increment (maximum 24-hr) = 91 pg/m3 (39.29xlO~6 gr/dscf).
-------
P.87
from the stack. However, as shown in Table 7-1, ambient air SCL
concentrations are reduced to approximately the same level through the use
of either SCL control alternative. This is because standards requiring a
percent reduction in SCL emissions through the use of FGD generally achieve
lower SCL emission rates than can be achieved through the use of low sulfur
fuel. In addition, the positive air quality benefits associated with the
larger SCL emission reductions achievable at the national level through
standards requiring a percent reduction in SCL emissions should also be
considered when assessing the secondary air quality impacts of alternative
standards.
7.2 WATER QUALITY AND SOLID WASTE IMPACTS
Industrial-commercial-institutional steam generating units are
generally part of a manufacturing plant and serve primarily in an auxiliary
role. The plant's production processes typically result in the generation
of substantial amounts of various wastes as well as the utilization of large
amounts of water. Therefore, the amount of waste generated by control of
SCL emissions from the steam generating unit(s) and the amount of water
demanded by the FGD system(s) required to comply with percent reduction
requirements frequently would represent only a small portion of the total
plant waste generation and water demand.
7.2.1 Low Sulfur Fuels
The wastes generated from the combustion of low sulfur fuel to reduce
SCL emissions are generally in dry ash form. The type and quantity of
wastes produced vary depending on the type of fossil fuel fired, its ash
content, and the method of producing and refining the fuel prior to firing.
The waste produced by coal-fired steam generating units consists of two
fractions, fly ash and bottom ash. Fly ash, which accounts for the majority
of the waste, is the fine ash fraction that is carried out of the steam
generating unit in the flue gas. Fly ash is collected along with other
7-4
-------
P.88
particulate emissions by mechanical collectors, electrostatic precipitators,
fabric filters, or wet scrubbers such as high pressure venturi scrubbers.
The bottom ash, consisting of the larger and heavier combustion products arid
unburned residuals, drops to the bottom of the steam generating unit and is
collected either as dry bottom ash or as slag.
For both fly ash and bottom ash, more than 80 percent of the total ash
weight consists of silica, alumina, iron oxide, and lime (calcium oxide).
Table 7-2 presents typical compositions of fly ash from eastern and western
bituminous coals and western subbituminous coal. As shown in the table, the
two most prominent components are silicon dioxide and aluminum oxide, which
together comprise over 75 percent of the total ash by weight of the eastern
and western bituminous coals. For western subbituminous coal, these two
components plus calcium oxide (lime) make up over 80 percent of the total
ash by weight.
Fly ash and bottom ash also contain small amounts of trace metals, as
shown in Table 7-3. The types and amounts of these elements will vary
greatly depending on the type of fuel fired, fuel handling procedures, and
steam generating unit operating parameters. For coal-fired steam generating
units, certain elements such as boron, chlorine, selenium, and arsenic may
be present at levels greater than the average concentration in the earth's
crust. These elements tend to collect in greater quantities in the fly ash
than in the bottom ash. In general, elemental concentrations tend to be
higher in eastern coals than in western coals.
Both bottom ash and fly ash are frequently disposed of in a pond
disposal area. Typically, the ash is sluiced to a central disposal pond
where the ash is allowed to settle out and the overflow liquor discharged or
returned for sluicing. This pond liquor generally has a dissolved solids
content on the order of hundreds of ppm, with the major constituents being
calcium, magnesium, sodium, sulfate, and chloride, and lesser amounts of
silicates, iron, manganese, and potassium.
As much as 20 percent of fly ash can be water soluble, raising the
potential for leaching of certain constituents, notably calcium, magnesium,
potassium, sulfate, and chloride. This, however, can be prevented by using
7-5
-------
P.89
TABLE 7-2. TYPICAL COMPONENTS OF FLY ASH
Mean Weight Percent
Eastern
Compound Bituminous Coal
Si02 48.76
A1202 23.26
Fe20 16.44
CaO 2.88
P2°5 2'73
K20 2.53
Ti02 1.45
MgO 1.24
S03 0.78
Na20 0.53
Western
Bituminous Coal
49.69
23.04
6.48
13.81
0.38
0.99
1.09
2.96
1.66
1.04
Western
Subbituminous Coal
40.2
21.8
9.7
19.4
0.4
0.3
0.8
5.4
2.0
7-6
-------
TABLE 7-3. TRACE CONSTITUENTS IN FLY ASH AND BOTTOM ASH
FROM VARIOUS UTILITY STEAM GENERATING UNITS
Element
Arsenic
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Fluoride
Lead
Mercury
Manganese
Nickel
Selenium
Vanadium
Zinc
#1
12
4.3
266
0.5
20
7
54
140
70
0.07
267
10
6.9
90
63
Fly
#2
8
7
200
0.5
50
20
128
100
30
0.01
150
50
7.9
150
50
Ash Concentration
#3
15
3
300
0.5
150
15
69
610
30
0.03
150
70
18.0
150
71
#4
6
7
700
1.0
30
15
75
250
70
0.08
100
20
12.0
100
103
#5
8.4
8.0
NR
6.44
206
6.0
68
624
32
20.0
249
134
26.5
341
352
(ppm)
#6
110
NRa
NR
8.0
300
39
140
NR
8.0
0.05
298
207
25
440
740
Bottom
Mean
27
5.9
367
2.8
126
17
89
345
40
3.37
202
82
16.1
212
230
#1
i
3
143
0.5
15
7
37
50
27
0.01
366
10
0.2
70
24
#2
1
7
125
0.5
30
12
48
50
30
0.01
700
22
0.7
85
30
Ash Concentration
#3
3
2
70
0.5
70
7
33
100
20
0.01
150
15
1.0
70
27
#4
2
5
300
1.0
30
7
40
85
30
0.01
100
10
1.0
70
45
#5
5.8
7.3
NR
1.08
124
3.6
48
10.6
8.1
0.51
229
62
5.6
353
150
(ppm)
#6
18
NR
NR
1.1
152
20.8
20
NR
6.2
0.03
295
85
0.1
260
100
Mean
5
4.9
160
0.8
70
10
38
59
20
0.10
307
34
1.4
151
63
NR = not reported.
-------
P.91
a lined disposal pond. In addition, fly ash possesses a high pozzolanic
potential; it tends to aggregate and harden when moistened and compacted
with lime and water. Due to this pozzolanic activity, a significant
fraction (approximately 10 percent) of the fly ash generated is used for
such purposes as soil or sludge stabilization, ice control, or as
ingredients in cement, concrete, and blasting compounds. Bottom ash does
not exhibit pozzolanic properties.
Dry ash can also be disposed of in managed landfills or dry
impoundments. In this method, the wastes are collected and transported to
the disposal area, then spread and compacted by physical means (e.g.,
bulldozing). Surface mine disposal may also be used for dry ash wastes.
This may be done in one of three ways: disposal on the working pit floor
prior to the return of overburden, dumping in spoil banks prior to
reclamation, or mixing with overburden before returning it to the pit.
The constituents of coal ash are not considered a hazardous waste under
the Resource Conservation and Recovery Act (RCRA). These wastes have been
specifically exempted from characterization as hazardous by 40 CFR 261.4(b).
As mentioned above, the high solubility of some fly ash constituents
creates a potential for the leaching of these constituents from the settling
pond or landfill. This can be controlled, however, by the use of
impermeable liners in the pond or landfill. After the settling out of the
ash, the pond liquor typically contains total dissolved solids in the
hundreds of ppm range, which consist primarily of calcium, magnesium,
sodium, sulfate, and chloride with lesser amounts of silicates, iron,
manganese, and potassium. When this pond liquor is diluted by combining it
with other plant wastes prior to disposal, the concentrations of these
substances are negligible.
In the absence of new source performance standards limiting emissions
'of SOp from new industrial-commercial-institutional steam generating units,
most new coal-fired steam generating units in the east would probably fire
medium sulfur eastern bituminous coals. Secondary environmental impacts in
the east resulting from standards based on the use of low sulfur coal would
depend on the source of the low sulfur coal fired. Firing low sulfur
7-8
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P.92
bituminous coal in the east would result in no additional secondary
environmental impacts over the combustion of medium sulfur coal, as the
types of waste generated and the method of disposal would remain the same.
The process of cleaning medium sulfur coal to produce a low sulfur coal
*•
would also result in no additional secondary environmental impacts.
Cleaning the coal would essentially move some of the wastes from the steam
generating unit to the coal cleaning plant, but would generate no new
wastes.
, *,<*•
In the absence of standards, most new coal-fired steam generating units
in the west would fire low sulfur subbituminous coal. Therefore, there
would be little or no secondary environmental impacts associated with
standards based on the use of low sulfur coal in the west.
Fuel oils fired by industrial-commercial-institutional steam generating
units are processed in refineries to meet specifications set forth by the
American Society for Testing and Materials (ASTM). Table 7-4 presents
typical concentrations of various elements in unprocessed crude oil. Crude
oil has a low ash content, and the amounts of trace metals present in fuel
oil fired at a steam generating unit are much less than the Bevels at a
coal-fired steam generating unit. At the refinery, fuel oils are typically
processed using hydrodesulfurization to remove much of the sulfur content.
In the absence of standards, most steam generating units would fire
medium sulfur fuel oil. The differences in refinery processing to produce a
low sulfur oil compared to a medium sulfur oil would result in some
additional waste generation at the refinery, but the amount of this
additional waste would be extremely small compared to the total waste output
at a typical refinery producing gasoline, home heating oil, diesel fuel, and
other products in addition to the fuel oil supplied to industrial-
commercial-institutional steam generating units. The removal of sulfur from
oil in this manner is a routine practice and will not result in the
generation of a new waste. Therefore, the secondary environmental impacts
associated with standards based on the use of low sulfur oil would be
negligible.
7-9
-------
P.93
TABLE 7-4. ELEMENTAL COMPOSITION OF CRUDE OIL
Element Range (%)
Carbon 83-87
Hydrogen 11-14
Sulfur 0-5
Nitrogen 0 - 0.88
Oxygen J "'•> * 0-2
Asha: 0.01 - 0.05
Iron
Calcium
Magnesium
Silicon \'-|p?.
Aluminum
Vanadium
Nickel
Copper
Manganese
Strontium
Barium
Boron
Cobalt
Zinc
Molybdenum
Lead
Tin
Sodium
Potassium
Phosphorus
Lithium
Elements present in the ash fraction are presented in decreasing
concentrations.
7-10
-------
P.94
7.2.2 Percent Reduction
The quantity of wastes associated with standards requiring a percent
reduction in S(L emissions depends on several factors, including the sulfur
and ash content of the fuel, applicable emission limits, the types of ash
collection and FGD systems employed, and the FGD and steam generating unit
operating conditions. Table 7-5 presents estimated quantities of waste that
would be produced annually by various FGD systems on a steam generating unit
with a heat input capacity of 44 MW (150 million Btu/hour) and an annual
capacity utilization factor of 0.60 and the amount of waste produced by
uncontrolled steam generating units.
The quantities of waste produced by FGD systems are small compared with
the total amount produced by a typical industrial plant. For example, a
typical iron and steel manufacturing plant would produce between 2.7 million
and 11.5 million cubic meters (96 million and 410 million cubic feet) of
wastewater per year and a typical petroleum refinery would produce
approximately 1.2 million cubic meters (43 million cubic feet) of wastewater
per year. In comparison, the use of sodium scrubbing to control SOp
emissions from the steam generating units at a typical iron and steel
manufacturing plant with a total steam generating unit heat input capacity
of 215 MW (736 million Btu/hour) would produce approximately 252,000 cubic
meters (9 million cubic feet) of wastewater per year if high sulfur coal is
fired and 56,000 cubic meters (2 million cubic feet) of wastewater per year
if low sulfur coal is fired. The use of sodium scrubbing to control SO,,
emissions from the steam generating units at a typical petroleum refinery
with a total steam generating unit heat input capacity of 380 MW (1,300
million Btu/hour) would produce approximately 336,000 cubic meters (12
million cubic feet) of wastewater per year if high sulfur oil is fired and
98,000 cubic meters (3.5 million cubic feet) of wastewater per year if low
sulfur oil is fired. Thus, the wastewater produced from sodium scrubbing
would constitute from 0.5 to 9 percent of the total wastewater from a
typical iron and steel manufacturing plant and from 8 to 28 percent of the
total wastewater from a typical petroleum plant.
7-11
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P.95
TABLE 7-5. QUANTITY OF WASTE PRODUCED BY VARIOUS FGD S02
CONTROL SYSTEMS
Quantity of Waste Produced'
Fuel Type
FGD System
Mass
Volume
Mg/yr (tpy) 1,000 nr/yr (1,000 fr/yr)
High Sulfur Coalc
Low Sulfur Coald
High Sulfur Oil6
Low Sulfur Oilf
None^
Sodium
Dual Alkali
Dry Lime
None^1
Sodium
Dual Alkali
Dry Lime
None^
Sodium
None^1
Sodium
3
56
6
6
3
11
1
2
31
9
,630
,000
,810
,600
,180
,000
,170
,090
18
,000
18
,300
(4
(61
(7
(7
,000)
,700)
,500)
,270)
(3,500)
(12
(1
(2
(34
(10
,150)
,290)
,310)
(20)
,100)
(20)
,300)
9.
56.
5.
5.
9.
11.
0.
1.
9.
31.
9.
9.
0
0
2
5
0
0
8
8
0
0
0
3
(315)
(1,980)
(180)
(200)
(315)
(390)
(30)
(60)
(315)
(1,090)
(315)
(330)
Based on a 44 MW (150 million Btu/hour) heat input capacity steam
generating unit with an annual capacity utilization factor of 0.60.
Sodium = liquid waste
Dual alkali = sludge waste
Dry lime = dry solid waste
C2580 ng S02/J (6.0 Ib S02/million Btu).
d516 ng S02/J (1.2 Ib S02/million Btu).
e!290 ng S02/J (3.0 Ib S02/million Btu).
f344 ng S02/J (0.8 Ib S02/minion Btu).
^Includes wastes produced by steam generating unit blowdown and ash.
7-12
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P.96
Flue gas desulfurization systems do not consume water in the sense that
a large quantity of the water circulating within the system is lost to
evaporation or inclusion in a product. The water taken in by the FGD system
during operation, or makeup water, is typically about 3 percent of the
amount circulating within the system. About half of the makeup water is
discharged as wastewater or in scrubber sludge, with the remaining half
being lost to evaporation. Consequently, the amount of water needed by an
FGD system can be assumed to be approximately double the quantity of
wastewater discharged by the system.
Using the conservative assumption that total water consumption by a
typical plant would be approximately equal to wastewater production (i.e.,
no water is being lost to evaporation or inclusion in a product), water
consumption by an FGD system at a typical iron and steel plant would
constitute approximately 1 to 18 percent of the total water consumption by
the plant. For a typical petroleum refinery, water consumption by the FGD
system would constitute 16 to 55 percent of the total plant consumption.
These figures represent the "extreme" since some types of industry may
experience substantial water loss through evaporation (such as sugar
refining) or inclusion of water in the product (such as bottling or food
processing). In these instances, the proportion of total plant water
consumption attributable to the FGD system would be even less than that
indicated by the wastewater production figures.
The form of the waste byproducts generated by the use of FGD systems
varies from solid wastes, in the form of dry powders (from lime spray
drying) or sludges (from lime/limestone or dual alkali wet scrubbing), to
liquid wastes (from sodium wet scrubbing). While the form of the wastes
generated by the various FGD systems may differ, the composition of these
wastes are similar. They consist primarily of calcium sulfite/sulfate salts
(in the case of lime spray drying, lime/limestone wet scrubbing, and dual
alkali wet scrubbing) or sodium sulfite/sulfate salts (in the case of sodium
wet scrubbing). Other constituents may also be present in FGD wastes.
However, the source of these constituents is the fly ash resulting from
7-13
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P.97
combustion of the fuel. To the extent that disposal of the wastes generated
by FGD systems may require treatment or disposal in ponds or landfills with
impermeable liners, the same treatment or disposal would also be required
for the fly ash.
Thus, while the wastes resulting from standards requiring a percent
reduction in SOp emissions increase the volume of waste that must be
disposed of, the nature of the environmental impacts which might result from
disposal of these wastes are similar to those associated with disposal of
wastes generated by combustion of fossil fuels in the absence of such
standards.
Because coal-fired steam generating units produce greater quantities
and a wider range of wastes than do oil-fired steam generating units,
coal-fired steam generating units were used for analyzing the potential
secondary environmental impacts associated with the use of lime spray
drying, dual alkali, and lime/limestone FGD systems. Oil-fired steam
generating units, however, were used for analyzing the potential secondary
environmental impacts associated with the use of sodium scrubbing. Although
the constituents of the wastewater stream from a sodium scrubber-equipped
coal-fired steam generating unit can be calculated, as in Table 7-9 below,
no actual data are readily available on the characteristics of sodium
scrubbing wastewater streams from coal-fired steam generating units.
Lime spray drying FGD systems generate a dry waste byproduct. Because
this dry waste byproduct is collected in a particulate matter collection
device (fabric filter or electrostatic precipitator), it contains fly ash in
addition to the spray drying byproducts.
As mentioned above, wastes produced by lime spray drying systems
consist primarily of calcium sulfite, calcium sulfate, and unreacted lime
(calcium oxide). Table 7-6 presents typical concentration ranges for the
species generally present in lime spray drying FGD waste. This waste
product may be more alkaline than those produced by wet scrubbing processes,
favoring formation of the more stable sulfate species over the less stable
sulfite. In addition, lime spray drying wastes contain trace elements
similar to those described above for fly ash. The quantities of trace
7-14
-------
P.98
TABLE 7-6. CONCENTRATIONS OF MAJOR AND MINOR SPECIES
IN LIME SPRAY DRYING WASTE
Weight Percent Range
Compound With Recycle Without Recycle
Si02 18 - 51 (32)b 6 - 66 (25)
A1203 7.7 - 21 (13) 3.4 - 14 (7.7)
Ti02 0.51 - 1.1 (0.75) 0.17 - 0.75 (0.54)
Fe203 2.8 - 6.7 (4.5) 1.4 - 7.8 (4.3)
CaO 9.9 - 28 (20.3) 15 - 48 (32)
MgO 1.4 - 3.6 (2.5) 0.51 - 3.0 (1.7)
Na20 0.35 - 2.0 (1.36) 0.096 - 2.0 (0.91)
K20 0.40 - 1.1 (0.5) 0.26 - 0.99 (0.50)
S03 1.4 - 7.0 (4.2) 0.4 - 6.6 (3.4)
S02 1.5 - 11.5 (6.1) 1.7 - 14 (6.2)
C02 0.44 - 6.6 (2.67) 0.13 - 15 (5.0)
H20a 0.4 - 6.0 (2.3) 0.4 - 10 (3.6)
aEstimate of hydroxide concentrations.
Mean in parentheses.
7-15
-------
P.99
elements present are a function of the type of fuel fired in the steam
generating unit. Table 7-7 presents typical elemental concentrations in
lime spray drying waste. These concentrations are less than those present
in fly ash. In addition, these wastes have been specifically exempted from
characterization as hazardous under the Resource Conservation and Recovery
Act (RCRA) by 40 CFR 261.4(b).
The predominant disposal techniques for lime spray drying wastes are
ponding and landfill ing, as described above for fly ash disposal. The waste
products are in the form of a dry, free-flowing powder with physical
properties and handling characteristics similar to fly ash. Analyses of
waste products from several facilities employing dry scrubbing indicate that
the waste products possess enough structural strength to be suitable for
landfill applications without additional stabilization or fixation. Another
alternative that is currently under investigation is commercial utilization
of the dry waste solids in concrete mixtures, in the same manner that fly
ash is currently being used.
Again, the solubility of many of the dry scrubbing waste constituents
in water could lead to the possibility of leaching of those constituents
from the disposal pond or landfill. The structural integrity of the waste
prevents any significant leaching from occurring, however, and the
possibility can be completely eliminated by the use of an impermeable liner
in the pond or landfill.
Dual alkali and lime/limestone wet scrubbing systems generate a waste
byproduct that consists primarily of calcium sulfite, bisulfite, and sulfate
salts in precipitate form suspended in the scrubbing liquor. The effluent
from dual alkali systems also contains sodium sulfite and sulfate in
dissolved form. Other substances making up the solid phase of these
scrubber wastes include calcium carbonate, unreacted lime or limestone, and
fly ash.
In lime/limestone wet scrubbing wastes, the ratio of calcium sulfite to
sulfate depends primarily on the extent of oxidation that takes place - the
greater the oxidation level, the greater the conversion of sulfite to
sulfate. The percentage of sulfate produced is generally greater when
7-16
-------
TABLE 7-7. TYPICAL ELEMENTAL COMPOSITION OF LIME SPRAY DRYING WASTE
Element
Antimony
Arsenic
Barium
Beryllium
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Molybdenum
Nickel
Potassium
Selenium
Silver
Strontium
Thai! ium
Tin
Titanium
Vanadium
Zinc
Concentration
1
<8
30
350
4.3
<1.0
52
4.9
16
20,000
<20
15,000
16
215
4,300
<20
<0.5
1,900
<25
<36
3,100
580
37
(ppm mass)
2
<8
28
820
4.0
<1.0
39
4.8
33
21,000
<20
15,000
16
220
4,600
<20
<0.5
1,960
<25
<30
3,200
610
23
7-17
-------
P.2
firing low sulfur western coal than with higher sulfur eastern coals, and
more sulfate is generated from limestone wet scrubbing systems than from
lime wet scrubbing systems. The lower pH levels at which limestone wet
scrubbers operate and the lower pH of western coals favor oxidation of
sulfite to the more stable sulfate.
Most lime/limestone and dual alkali wet scrubbing systems include a
dewatering device to concentrate the suspended solids into a sludge prior to
treatment and disposal. This leads to the formation of two separate
disposal products: a wet sludge containing most of the solid or insoluble
waste components, and an aqueous liquor containing the soluble waste
components and free ions. Table 7-8 presents typical concentrations of
various chemical species in both the liquor and sludge phases. These
concentrations may vary widely depending on-the type of fuel and FGD system
used, and especially on the ash content of the fuel. In almost all cases,
well over 90 percent of the total trace element mass is found in the solid
phase. This distribution is explained by the very low solubilities of trace
metal hydroxides, oxides, and carbonates.
Table 7-8 also lists the maximum concentrations of certain contaminants
that are identified under RCRA as toxic and therefore subject to regulation
under RCRA (40 CFR 261.24). Under the Extraction Procedure (EP) Toxicity
Regulations for identifying toxic wastes, the solid and liquid portions of a
waste stream are separated and the solid portion crushed before being
dissolved in deionized water at a controlled pH level. The liquid waste and
the solid waste solutions are then recombined and analyzed to determine the
concentrations of the contaminants listed in 40 CFR 261.24, using standard
analytical procedures. If the concentrations of contaminants are revealed
by analysis to be in excess of the levels cited in Table 7-8, the treatment,
handling and disposal procedures required under RCRA would have to be
followed. These RCRA contamination levels have been established at 100
times the contamination levels established for drinking water under the Safe
Drinking Water Act. As shown in Table 7-8, the levels of these contaminants
found in the sludge and wastewater formed by FGD systems are well below the
limitations established by RCRA. Consequently, the disposal of these wastes
7-18
-------
, ^
TABLE 7-8. TYPICAL LEVELS OF CHEMICAL SPECIES
IN WET FGD
WASTE SOLIDS AND LIQUORS
Species
Antimony
Arsenic
Beryllium
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sodium
Zinc
Chloride
Fluoride
Sulfate
TDS
pH
aFor FGD systems
mg/Ji values.
FGD Waste Solids
(ppm)
—
0.06 - 63
0.05 - 11
0.08 -,350
NDb
3 - 250
ND
1 - 76
ND
0.02 - 21
11 - 120
0.001 - 6
-
6 - 27
0.2 - 19
ND
10 - 430
—
_
—
_
-
EPA EP
FGD Waste Liquor Toxicity Criteria
(ppm) (mg/£)a
0.09 - 1.6
<0.004 - 1.8 5.0
<0.0005 - 0.14
0.004 - 0.1 1.0
240 - 45,000C
0.001 - 0.5 5.0
<0.002 - 0.17
0.002 - 0.6
0.02 - 8.1
0.001 - 0.55 5.0
<0.01 - 9.0
<0.001 - 0.07 0.2
0.9 - 5.3
0.005 - 1.5
<0.001 - 2.7r 1.0
36 - 20,000C
0.01 - 27
470 - 43,000C
0.7 - 70 -
720 - 30,000°
2,500 - 95,000°
2.8 - 12.8
, ppm concentration values are very nearly equal to
ND - not determined.
GHighest values
be representati
based on single
ve.
worst-case measurements and may not
7-19
i
-------
should not deter steam generating unit owners and operators from using FGD
systems.
The major constituents of the waste liquor phase are calcium, chloride,
magnesium, sodium, sulfate, and sulfite. Chloride is released from the coal
as it is fired and enters the flue gas as hydrochloric acid (usually at
concentrations less than 5,000 ppm). Sodium concentrations range from less
than 100 ppm to over 10,000 ppm for some sodium-based dual alkali systems.
The amount of sodium present in the waste liquor depends on the degree of
dewatering and the extent of washing of filtered wastes. Calcium sulfite
and sulfate are relatively insoluble, so most of these constituents remain
in the solid phase of the waste. Calcium concentrations in the waste liquor
are generally on the order of 1,000 ppm or less. The sulfate concentrations
are limited by the level of calcium present. In conventional direct
lime/limestone wet scrubbing systems, sulfate levels are generally under
5,000-8,000 ppm. In dual alkali wet scrubbing systems, or where soluble
alkali or alkaline earth compounds are added to lime/limestone wet scrubbing
systems to improve performance, sulfate levels may exceed 10,000 ppm.
Magnesium sulfite and sulfate are more soluble than the calcium salts, and
their concentrations are dependent on the amount of magnesium entering the
system. Magnesium concentrations are pH sensitive. If the pH of the waste
liquor is raised to 10.5 or greater, magnesium hydroxide will precipitate
out and the magnesium levels in the liquor will be negligible.
In general, the sludges from lime/limestone and dual alkali wet
scrubbing systems are relatively inert and can be disposed of using
conventional methods. The predominant disposal techniques used for these
sludges are ponding and landfill ing.
Depending on its initial handling properties, the sludge from dual
alkali wet scrubbing systems may be disposed of directly, or it may be
stabilized with fly ash or fixated with lime prior to disposal. The
addition of fly ash reduces the moisture content of the sludge, as well as
reducing the permeability of the waste and the pollutant mobility. This
assists in mitigating the possibility of pollutant leaching and reduces the
solubility of trace metals present in the sludge, thereby reducing the
7-20
-------
P.5
concentrations of these trace metals in the liquor phase. Adding lime to
the fly ash/sludge mixture initiates a pozzolanic action which is similar to
cement curing, increasing the strength of the mixture and making it more
suitable for landfill ing.
Lime wet scrubbing systems produce a sludge that is composed primarily
of calcium sulfite. Sulfite-rich wastes are more difficult to dewater than
are sulfate-rich wastes. Because sulfite sludges retain large amounts of
water, they remain very fluid and can only be disposed of by ponding.
However, the dewatering properties of this sludge can be improved by the
presence of fly ash and unreacted lime. In addition, forced oxidation is
being employed at several facilities to oxidize calcium sulfite to calcium
sulfate or gypsum. This improves the dewatering and handling properties of
the sludge and increases its load-bearing strength, making it more suitable
for landfill disposal. The use of an impermeable liner in the waste
disposal pond or landfill or waste fixation by mixing it with fly ash or
lime will mitigate any potential for leaching of soluble waste components.
Limestone wet scrubbing systems generally operate at lower pH levels
than do lime wet scrubbing systems. This enhances the solubility of the
sulfite components of the waste and increases its oxidation to sulfate. The
higher sulfate concentrations present in limestone wet scrubbing system
wastes produce a sludge that is much more easily dewatered than that from
lime wet scrubbing systems. Limestone wet scrubbing system waste sludges
are amenable to either ponding or landfill ing and, depending on local
disposal requirements, may be disposed of with or without fixation or
stabilization.
Unlike the wet scrubbing systems described above, which convert SCL to
solid calcium sulfite and calcium sulfate, sodium wet scrubbing systems
convert S02 to aqueous sodium sulfite and sulfate. The aqueous waste
byproduct produced by sodium wet scrubbing systems also contains varying
concentrations of other dissolved solids and trace metals. Table 7-9
compares typical constituents of untreated sodium wet scrubbing wastewater
streams from oil-fired steam generating units to the EP toxicity
contamination levels established under RCRA (40 CFR 261.24). Table 7-9 also
7-21
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TABLE 7-9. TYPICAL LEVELS OF CHEMICAL SPECIES IN SODIUM SCRUBBING WASTEWATER STREAMS
I
ro
ro
Species
Oil-Fired System
Effluent
(mg/£)
Coal-Fired System
Effluent0
(mg/i)
RCRA EP
Toxicity Criteria
(mg/£)
Arsenic
Barium
Beryl 1 i um
Boron
Cadmium
Chromium
Copper
Iron
Lead
Manganese
Mercury
Nickel
Phosphorus
Selenium
Silver
Zinc
Sulfate (SO."2)
Chloride (Cl~) -
Total Sulfite (SO ~ and HSO ~)
Sodium (Na+)
Total Dissolved Solids
Chemical Oxygen Demand
Total Suspended Solids
pH
0.01-0.60
0.01-1.0
-
-
0.005-0.20
0.06-0.36
0.08-0.30
4.2-14
0.01-0.62
0.22-0.40
0.002-0.006
0.05-37.0
-
0.19-0.54
0.05-0.70
0.21-12
8,500-67,500
130-34,000
7,200-130,000
11,500-67,500
27,300-300,000
1,400-26,000
670-3,300
5.0-8.1
0.12-0.92
0.41-3.22
0.01-0.077
0.40-3.14
0.008-0.061
0.26-1.99
0.11-4.84
38.9-301.3
0.089-0.69
0.18-1.38
0.009-0.005
0.28-2.22
0.48-3.76
0.03-0.23
_•
0.19-1.53
-
-
-
-
-
-
7-7.5
5.0
100.0
-
-
1.0
5.0
-
-
5.0
-
0.2
-
-
1.0
5.0
-
a
includes values for high and low sulfur coal, and pulverized coal and spreader stoker steam
generating unit.
-------
P.7
compares the calculated characteristics of sodium scrubbing wastewater
streams from coal-fired stream generating units to the EP toxicity levels.
No actual data are readily available on the characteristics of sodium wet
scrubbing wastewater streams from coal-fired steam generating units.
This scrubber wastewater is generally diluted prior to disposal by
mixing with other plant wastewater streams. The combined wastewater stream
is then oxidized and treated for suspended solids. Alternatively, because
the sodium wet scrubbing wastewater stream exerts a high oxygen demand, it
is sometimes oxidized separately before mixing with other plant wastes.
These steps reduce the solids content of the scrubber waste stream to
negligible amounts when compared to total plant wastes.
As shown in Table 7-9, the aqueous component of the sodium wet
scrubbing wastewater stream may also contain small quantities of trace
metals and minerals. The specific concentrations of these elements are a
function of the type of fuel fired in the steam generating unit, the amount
of ash present in the wastewater stream, and the solubility of the trace
metal compounds. Many of the trace elements can precipitate out as
hydroxides during treatment of the wastewater to remove suspended solids.
Therefore, the concentrations shown in Table 7-9 represent conservatively
high estimates. After dilution and treatment, the trace elements in the
plant effluent attributable to the sodium wet scrubbing wastewater stream
would be well below the RCRA toxicity limits shown in Table 7-9.
The trace metal composition of the sodium wet scrubber wastewater from
coal-fired steam generating units will depend primarily on the type of coal
fired and its ash content. The fly ash resulting from coal combustion, as
previously shown in Table 7-2, has greater concentrations of trace elements
than those resulting from oil combustion (shown in Table 7-9). However,
unlike oil-fired steam generating units, coal-fired steam generating units
will be equipped with fabric filters upstream of the FGD system. The fabric
filter will remove 98 to 99 percent of the fly ash (and therefore the trace
elements) from the wastewater stream, reducing the concentration of most of
these trace elements to 1 to 2 percent of their potential concentration. In
addition, due to the low solubility of many trace metal hydroxides, oxides,
7-23
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P.8
and carbonates, a large percentage of the trace elements remaining in the
wastewater stream after fabric filter collection will precipitate out.
Therefore, the trace metal concentrations for coal-fired steam generating
units would be expected to fall within the range given in Table 7-9.
Sodium wet scrubbing wastewater may in many cases be discharged
directly to a receiving water body or to a publicly owned treatment works
(POTW). In arid areas where net evaporation exceeds net precipitation, the
wastewater stream is usually discharged to an evaporation pond. Other
possible disposal methods include deep well injection and injection with the
steam used in thermally enhanced oil recovery operations, two techniques
that are used to some extent in California and other western states.
California regulations for evaporation ponds and deep well injection do not
consider sodium wet scrubbing wastes to be hazardous.
There is a possibility that aqueous sulfur species discharged to a
receiving water body or sewer may be re-emitted as S(L in aerobic receiving
waters or hydrogen sulfide (H^S) in anaerobic environments (sewers). This
may be prevented in aerobic environments by raising the pH of the wastewater
during oxidation and by providing enough oxygen transfer capabilities to
ensure high conversion of sulfite to the more stable sulfate. Oxygen
depletion of wastewater in anaerobic environments, which promotes H?S i .
formation, can be prevented by injecting air at various points along the
sewer main and by preventing the sewer flow from becoming stagnant. Oxida-
tion of the sulfur species prior to disposal and maintenance of a high pH
will also help prevent formation of HS.
7-24
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8.0 CONSIDERATION OF NATIONAL IMPACTS
The potential national impacts associated with various new source
performance standards (NSPS) were analyzed. The analysis examined the
incremental national environmental and cost impacts in the fifth year
following proposal of standards compared to a regulatory baseline. The
regulatory baseline represents the level of control required by existing
State implementation plans and the existing NSPS (40 CFR Part 60, Subpart D)
applicable to steam generating units of more than 73 MW (250 million
Btu/hour) heat input. National impacts were examined for fossil fuel-fired
steam generating units (i.e., coal, oil or natural gas) and for mixed
fuel-fired steam generating units (i.e., mixtures of fossil fuels or fossil
and nonfossil fuels).
8.1 FOSSIL FUEL-FIRED STEAM GENERATING UNITS
National impacts on new industrial fossil fuel-fired steam generating
units were analyzed through the use of a computer model called the
Industrial Fuel Choice Analysis Model (IFCAM). IFCAM is an energy demand
model developed to evaluate fuel choice decisions among coal, oil, and
natural gas by the industrial sector. The population of new industrial
steam generating units in 1990 is projected in IFCAM and the total cost of
each alternative fossil fuel, including the costs imposed by environmental
regulations, is compared on an after-tax discounted cash flow basis for each
steam generating unit over a 15-year investment period. The lowest cost
combination of fossil fuel and emission control system is determined for
each steam generating unit. These results are then aggregated to yield
national projections in 1990 of fossil fuel consumption by fuel type,
capital and annualized costs, sulfur dioxide emissions, and solid and liquid
wastes.
The magnitude of the economic, environmental, and energy impacts
associated with alternative control levels for new industrial steam
generating units in IFCAM is a function of two major variables. These are
8-1
-------
P.10
the number of new fossil fuel-fired steam generating units projected and the
type of fuel selected for each of these steam generating units.
The number of new industrial steam generating units projected in 1990
is a function of the projected growth in industrial fossil fuel energy-
demand. Based on the "Annual Energy Outlook 1983," issued by the Department
of Energy, fossil fuel energy demand by new industrial steam generating
units installed between 1985 and 1990 with a heat input capacity of more
than 29 MW (100 million Btu/hour) is projected by IFCAM to be about 525
million GJ/year (498 trillion Btu/year). This compares to a 1982 fossil
fuel energy consumption of about 18 billion GJ (17.3 quadrillion Btu) by the
industrial sector, of which about 7.4 billion GJ (7.0 quadrillion Btu) were
consumed by existing industrial steam generating units. Based on this
projected fossil fuel energy demand, IFCAM projects construction of about
600 new fossil fuel-fired industrial steam generating units with a heat
input capacity greater than 29 MW (100 million Btu/hour) between 1985 and
1990.
The type of fossil fuel selected for each new steam generating unit in
IFCAM is a function of the projected prices for coal, oil, and natural gas.
Several economic models were used to develop these projections. Coal prices
were projected with the Coal and Electric Utilities Model (CEUM), a
proprietary model developed by ICF, Incorporated. The model can be used to
translate assumptions about growth in electric utility energy demand and
global energy and economic conditions into projections of future coal
prices.
In generating coal price forecasts, several assumptions were made
concerning energy demand and economic conditions. Annual growth in GNP was
assumed to be 3 percent between 1985 and 1990 and 2.5 percent between 1991
and 2000. World oil prices were assumed to increase from $32 per barrel in
1985 to $46 per barrel in 2000 (mid-1982 dollars). In addition, the Natural
Gas Policy Act was assumed to be implemented in its current form with
natural gas deregulation occuring in 1985. The growth in electricity demand
was assumed to be 2.7 percent per year between 1985 and 2000.
8-2
-------
Table 8-1 summarizes the coal prices projected by CEUM. While coal
prices are projected to increase modestly during the timeframe of the
forecast, the prices presented in Table 8-1 have been levelized and
expressed in terms of 1982 dollars. Levelized prices are calculated by
discounting prices in each year over the 15-year investment period to a
present value, and multiplying this present value by a capital recovery
factor to obtain a single price that represents the entire 15-year price
forecast.
These coal prices are higher than those experienced by electric
utilities. Industrial steam generating units do not generate sufficient
demand to command either long-term contracts or bulk transportation rates.
Consequently, industrial steam generating units generally purchase coal on
the spot market at higher prices than utility steam generating units.
Additionally, these projected coal prices exhibit "sulfur premiums" ranging
from a negligible amount to about $0.72/GJ ($0.76/million Btu) for purchase
of low sulfur coal over purchase of high sulfur coal.
In addition to coal prices, prices were forecast for residual fuel oil
and natural gas. No prices were forecast for distillate fuel oil. Prices
for this fuel are higher than for residual fuel oil and natural gas. Hence,
distillate oil is not expected to be widely used as a fuel in new
industrial-commercial-institutional steam generating units.
Residual fuel oil prices were projected with the World Oil (WOIL)
forecasting model developed by EEA, Incorporated for the Department of
Energy. The model generates projections of free world energy production,
demand, and prices for five world regions. Energy consumption is projected
by fuel type and sector from assumptions about economic growth, growth in
energy demand, and OPEC oil production capacity. The model assumed a
free-world economic growth rate of 3 percent per year between 1983 and 2000
in real terms. Growth in energy demand was assumed to be about 1.5 percent
per year. This energy demand growth is less than the economic growth rate
because of increases in energy conversion efficiency. Non-OPEC oil
production was assumed to fall by about 3 percent per year between 1990 and
1995 with the shortfall in production met by rapidly increasing OPEC
production. These assumptions lead to projections of a firm oil market
8-3
-------
TABLE 8-1. LEVELIZED INDUSTRIAL FUEL PRICES: HIGH OIL PENETRATION ENERGY SCENARIOa
(1982 I/Million Btu)
Co
i
Fuel
Natural
Type
gas
New
England
5.82
New York/
New Jersey
5.78
Middle
Atlantic
5.73
South
Atlantic
6.02
Midwest
5.88
Southwest
5.41
Central
5.45
North
Central
4.91
West
5.44
Northwest
5.57
Residual fuel oil
(Ib S02/million Btu)
3.0 4.80 4.79
1.6 5.12 5.11
0.8 5.50 5.49
0.3 5.87 5.85
Bituminous Coal
(Ib S02/million Btu)
1.2-1.7
1.7-2.5
2.5-3.4
3.4-5.0
>5.00 3.26 2.85
Subbituminous coal
(Ib S02/million Btu)
K2-1.7
1.7-2.5
.76
.71
.65
,46
.16
52
45
29
13
82
4.79
5.11
4.49
5.85
14
94
85
75
42
2.39
4.77
5.09
5.46
5.83
19
98
96
88
79
2.62
4.94
5.25
5.63
6.01
32
18
08
93
67
2.50
3.38
3.34
3.30
4.79
5.11
5.49
5.85
34
21
20
19
09
2.96
3.49
3.39
3.33
4.91
5.22
5.60
5.98
14
08
04
92
62
2.47
2.74
2.69
2.72
4.60
4.93
5.29
5.67
1.99
1.86
1.87
1.40
1.39
1.29
4.39
4.71
5.11
5.45
2.79
2.82
2.77
2.84
2.74
2.65
4.35
4.67
5.07
5.41
3.18
2.97
2.84
2.66
2.60
2.09
aTen percent discount rate. Fifteen-year period beginning in 1987.
-------
characterized by crude oil prices increasing at an average real rate of
2.8 percent annually.
The residual oil prices are shown in Table 8-1. As was done for coal
prices, these prices are presented as levelized prices. Additionally, these
projected residual oil prices exhibit "sulfur premiums" of about $1/GJ
($1.05/million Btu) for purchase of low sulfur residual oil over purchase of
high sulfur oil.
Natural gas prices were projected with the Hydrocarbon Supply Model.
This model was developed by EEA, Incorporated for the Strategic Analysis and
Energy Forecasting Division of the Gas Research Institute. The model
translates assumptions about economic growth, growth in energy demand, world
oil prices, regulation of natural gas prices, and natural gas imports into
projections of future natural gas prices. The model assumed the projected
world oil prices discussed above. Energy demand and economic growth were
assumed to be the same as those discussed above in forecasting residual oil
prices. In addition, the model assumed that the Natural Gas Policy Act will
be implemented in its current form, that contract pricing issues will be
resolved to allow the market to determine prices, that Canadian and Mexican
imports will track the lower-48 states market prices after decontrol, that
two trillion cubic feet of Canadian gas will be imported by 1987, and that
the gas industry will establish an effective dual pricing system. Natural
gas prices are also shown in Table 8-1. As was done for coal and residual
oil prices, the natural gas prices are presented as levelized prices.
This energy scenario reflects a "best guess" of future coal, oil, and
natural gas prices. Oil prices are relatively low and natural gas prices
are generally at or above the price of low sulfur residual oil. As shown in
Table 8-2, under this energy price scenario residual oil and natural gas
compete for the industrial steam generating unit energy market, with
residual oil achieving a slightly larger share. Coal does not effectively
compete in this market due to the relatively low oil and natural gas prices.
Thus, this energy pricing scenario is referred to as the high oil
penetration scenario.
8-5
-------
TABLE 8-2. NATIONAL IMPACTS3
Fossil Fuel-Fired Steam Generating Units
Regulatory Baseline (Base Case)
1990
Energy Pricing Scenario
High Oil Penetration High Coal Penetration
Emissions, thousand tons/year 279 326
Annualized Costs, million $/year 3,350 3,725
Fuel Use, trillion Btu/year
Coal 23 284
Oil 323 / 7
Natural Gas 152 207
aNew fossil fuel-fired steam generating units with a heat input capacity of
more than 29 MW (100 million Btu/hour) installed between 1985 and 1990.
b!982 dollars.
8-6
-------
P 15
In response to concerns that this energy pricing scenario might
underestimate coal penetration in the new industrial steam generating unit
energy market, an alternative energy scenario was developed to yield higher
coal penetration. In this energy scenario, coal prices were assumed to
remain the same as those discussed above for the high oil penetration energy
scenario. Alternative residual oil prices were developed according to the
method discussed above except that higher world oil prices were used. The
world oil prices used were those developed by the Department of Energy and
used in The National Energy Policy Plan, 1983 (NEPP-IV) projections.
NEPP-IV contains three world oil price projections reflecting high, middle,
and low price levels. The middle world oil price level contained in NEPP-IV
was used in the high coal penetration energy scenario. These world oil
prices are higher than the world oil prices used in the high oil penetration
energy scenario and range from about 3.5 percent higher in 1985 to about 45
percent higher in 1995. All other assumptions used to forecast residual oil
prices are the same in this energy scenario as in the high oil penetration
energy scenario.
In a similar manner, the NEPP-IV world oil prices were used to project
alternative natural gas prices. All other assumptions used to forecast
natural gas prices are the same in this energy scenario as in the high oil
penetration energy scenario.
The oil and natural gas prices used for this energy scenario are
presented in Table 8-3. As shown in Table 8-2, in this scenario coal and
natural gas compete for the steam generating unit energy market with coal .
capturing a slightly larger share than natural gas. Oil does not
effectively compete in this market due to the relatively low coal and
natural gas prices. This energy scenario, therefore, is referred to as the
high coal penetration scenario.
8.1.1 Selection of Regulatory Alternatives
In order to assess the "sensitivity" of IFCAM projections, a number of
alternative control levels based on the use of low sulfur fuels to reduce
8-7
-------
CO
I
CO
TABLE 8-3. LEVELIZED INDUSTRIAL FUEL PRICES: HIGH COAL PENETRATION ENERGY SCENARIO0
(1982 $/Million Btu)
Fuel
Natural
Residual
(3.0 Ib
(1.6 Ib
(0.8 Ib
(0.3 Ib
Type
gas
fuel oil
S02/million Btu)
SOp/million Btu)
S02/million Btu)
S02/niillion Btu)
New
England
6.39
6.00
6.42
6.90
7.38
New York/
New Jersey
6.38
5.99
6.41
6.89
7.37
Middle
Atlantic
6.37
5.99
6.41
6.89
7.37
South
Atlantic
6.52
5.97
6.39
6.87
7.35
Midwest
6.48
6.12
6.54
7.02
7.50
Southwest
6.01
5.99
6.41
6.89
7.37
Central
5.87
6.09
6.51
6.99
7.47
North
Central
5.26
5.82
6.23
6.71
7.19
West
5.82
5.58
6.00
6.52
6.96
Northwest
5.79
5.55
5.96
6.48
6.62
aTen percent discount rate. Fifteen-year period beginning in 1987.
TJ
CD
-------
S0~ emissions, or the use of flue gas desulfurization (FGD) systems to
achieve a percent reduction in S0? emissions, were examined in a preliminary
analysis and compared to the regulatory baseline. As stated previously, the
regulatory baseline is defined by existing State implementation plans and
the existing NSPS (40 CFR, Part 60, Subpart D) for large steam generating
units of more than 73 MW (250 million Btu/hr) heat input capacity.
As mentioned earlier, under the regulatory baseline, oil and natural
gas are responsible for about 96 percent of fuel use under the high oil
penetration scenario. As a result, IFCAM projects minimal impacts
associated with alternative control levels limiting S0? emissions from coal
combustion under this energy scenario. In the high coal penetration
scenario, coal and natural gas are responsible for about 99 percent of fuel
use under the regulatory baseline. IFCAM, therefore, projects minimal
impacts associated with alternative control levels limiting SO,, emissions
from oil combustion under this energy scenaro. Thus, in the high oil
penetration scenario, impacts are determined primarily by the limits placed
on SOp emissions from oil-fired steam generating units, and in the high coal
penetration scenario, impacts are determined by the limits placed on SOp
emissions from coal-fired steam generating units.
As discussed earlier in "Consideration of Demonstrated Emission Control
Technology Costs," requirements to achieve percent reductions of much less
than 70 percent in SOp emissions resulting from combustion of oil would
generally not reduce emissions to levels below that achieved by the
combustion of low sulfur oil. Similarly, requirements to achieve percent
reductions of much less than 50 percent in S02 emissions resulting from
combustion of coal would generally not reduce emissions to levels below
those achieved by the combustion of low sulfur coal. Consequently, the
alternative control levels examined for limiting S02 emissions from oil
combustion included alternatives based on the use of low sulfur oils and
alternatives requiring a reduction in S0? emissions of 70 percent or more.
The alternative control levels examined for limiting SOp emissions from coal
combustion included alternatives based on the use of low sulfur coal and
alternatives requiring a reduction in S02 emissions of 50 percent or more.
8-9
-------
P.18
The alternative control levels examined in the preliminary analysis are
summarized in Table 8-4. Alternative control levels I and II are based on
the use of low sulfur fuel to reduce emissions to 688 and 344 ng S02/J (1.6
and 0.8 Ib SOp/million Btu) heat input from oil combustion and to 731 and
516 ng S02/J (1.7 and 1.2 Ib S02/million Btu) heat input from coal
combustion. Alternative control level III is based on the use of FGD
systems to achieve a 50 percent reduction in S02 emissions from coal
combustion and reduce emissions to 344 ng S02/0 (0.8 Ib SOp/million Btu)
heat input from oil combustion. As mentioned above, a requirement to
achieve a percent reduction in SOp emissions from oil combustion of less
than 70 percent would generally not reduce emissions to levels below that
achieved through the combustion of low sulfur oil. Thus, an alternative
control level of 50 percent reduction in S0? emissions was not examined for
oil combustion in the analysis of national impacts.
Alternative control level IV is based on the use of FGD systems to
achieve a 90 percent reduction in S02 emissions, with an exemption from this
requirement if S02 emissions are 258 ng SOp/J (0.6 Ib SOp/million Btu) heat
input or less from coal combustion or 129 ng SO?/J (0.3 Ib SOp/million Btu)
heat input or less from oil combustion.
Alternative control level V is based on the use of FGD systems to.
achieve a 90 percent reduction in SOp emissions and reduce emissions from
coal combustion to less than 516 ng SOp/J (1.2 Ib S02/million Btu) heat
input and from oil combustion to less than 344 ng S02/J (0.8 Ib S02/million
Btu) heat input. If emissions can be reduced to less than 258 ng SOp/J
(0.6 Ib SOp/million Btu) heat input for coal or 129 ng SOp/J (0.3 Ib
SOp/million Btu) heat input for oil, alternative control level V would only
require a minimum percent reduction of 70 percent. This alternative control
level represents the existing NSPS under Subpart Da for utility steam
generating units.
Finally, alternative control level VI, the most stringent alternative,
is based on the use of FGD systems to achieve a 90 percent reduction in SOp
emissions from both oil and coal combustion and reduce emissions from coal
combustion to less than 258 ng/J (0.6 Ib S02/million Btu) heat input and
8-10
-------
P.19
TABLE 8-4. ALTERNATIVE CONTROL LEVELS
Fossil Fuel-Fired Steam Generating Units
Alternative Oil Combustion Coal Combustion
Low Sulfur Fuel
I 1.6 Ib S02/million Btu 1.7 Ib S02/million Btu
II 0.8 Ib S02/million Btu 1.2 Ib S02/million Btu
Percent Reduction
III -a . 50% and 0.9 Ib SO./million
c Btu
IV 90% or 0.3 Ib S09/million Btu 90% or 0.6 Ib S0,/million
* * Btu
V 90% and 0.8 Ib S09/million Btu 90% and 1.2 Ib S09/million
* * Btu
or or
70% and 0.3 Ib S09/million Btu 70% and 0.6 Ib S09/million
* i Btu
VI 90% and 0.3 Ib 50,,/million Btu 90% and 0.6 Ib S09/m1ll1oii
* * Btu
aS02 emissions from oil combustion limited to 0.8 Ib S02/million Btu.
8-11
-------
from oil combustion to less than 129 ng/J (0.3 Ib SCL/million Btu) heat
input.
The results of the preliminary analyses under the high oil penetration
and high coal penetration energy scenarios are summarized in Table 8-5.
Before discussing the results of this preliminary analysis, there is one
point that should be mentioned. As shown in Table 8-5, the cost impacts
associated with alternative control levels limiting S(L emissions from oil
combustion under the high oil penetration scenario are greater than the cost
impacts associated with alternative control levels limiting S(L emissions
from coal combustion under the high coal penetration scenario. This is
explained by the type and amount of fuel switching that occurs under each
energy scenario in response to limits on SCL emissions, as well as the
greater number of steam generating units affected under the high oil
penetration scenario than under the high coal penetration scenario.
In response to progressively more stringent standards, under the high
coal penetration scenario, coal-fired units switch to natural gas, and under
the high oil penetration scenario, oil-fired units switch to natural gas.
As discussed below and illustrated in Table 6-19, because IFCAM summarizes
annualized cost impacts on a before-tax basis, but makes fuel selection
decisions on an after-tax basis, fuel switching from coal to natural gas can
result in negative before-tax levelized cost impacts (i.e., decreased
costs). This tends to mitigate the apparent cost impacts under the high
coal penetration scenario. Under the high oil penetration scenario,
however, fuel switching from oil to natural gas always results in positive
cost impacts (i.e., increased costs). Thus, fuel switching does not
mitigate the apparent cost impacts under the high oil penetration scenario.
As also mentioned, a larger number of steam generating units are
impacted under the high oil penetration scenario than under the high coal
penetration scenario. Consequently, more FGD systems are installed under
the high oil penetration scenario than under the high coal penetration
scenario. This also contributes to the higher cost impacts under the high
oil penetration scenario than under the high coal penetration scenario.
8-12
-------
00
I
I—'
CO
TABLE 8-5. PRELIMINARY ANALYSIS OF NATIONAL IMPACTS
Fossil Fuel-Fired Steam Generating Units9
Alternative Control Level
High Oil Penetration Scenario
S09 Emissions, thousand ton/yr
C- L
Annuali zed Costs, $million/yr
Fuel Use, trillion Btu/yr
o Coal
o Oil
o Gas
Cost Effectiveness, $/ton
o Average
o Incremental
High Coal Penetration Scenario
S09 Emissions, thousand ton/yr
K
Annual i zed Costs, $million/yr
Fuel Use, trillion Btu/yr
o Coal
o Oil
o Gas
Cost Effectiveness, $/tonb
o Average
o Incremental
Base Case
279
3,349
23
323
152
-
326
3,725
284
7
207
-
I
205
3,357
17
328
153
110
148
3,735
261
0
237
60
II
106
3,406
17
257
224
330
490
114
3,743
248
0
- 250
80
240
III
102
3,408
9
257
232
330
500
46
3,754
153
0
345
100
160
IV
39
3,476
26
205
267
530
1,080
34
3,757
153
0
345
110
250
V
47
3,474
26
205
267
540
30
3,758
153
0
345
110
250
VI
16
3,482
26
178
294
510
260
16
3,757
147
0
351
100
0
National impacts in 1990 of new fossil fuel-fired steam generating units installed between 1985 and
1990 of more than 29 MW (100 million Btu/hour) heat input capacity.
b!982 dollars.
-------
P.22
The results obtained under the high oil penetration scenario indicate
that alternative control levels I and II, based on low sulfur oil and
limiting SCL emissions from oil combustion to 688 and 344 ng SCL/J (1.6 and
0.8 Ib SCL/million Btu) heat input, respectively, would achieve reductions
in SCL emissions of 68,000 to 159,000 Mg/year (75,000 to 175,000 tons/year),
with increases in annualized costs of $10 to $60 million/year. The average
cost effectiveness of emission control under each of these alternatives is
$121 to $364/Mg ($110 to $330/ton) of S02 removed. The control of S02
emissions under these alternatives also results in a shift of up to 74
million GJ/year (70 trillion Btu/year) from oil combustion to natural gas
combustion.
Table 8-5 also shows that the impacts under the high oil penetration
scenario associated with alternative control level III, which requires a
percent reduction in emissions of 50 percent and a reduction in emissions to
387 ng SO^/J (0.9 Ib SO^/million Btu) heat input from coal combustion and to
344 ng SO^/J (0.8 Ib S02/million Btu) heat input from oil combustion, are
essentially the same as the impacts associated with alternative control
level II which limits SO,, emissions from coal combustion to 516 ng S02/J/
(1.2 Ib SOp/million Btu) and from oil combustion to 344 ng S02/J (0.8 Ib
SOp/million Btu) heat input. This result shows, as mentioned above, that
impacts under the high oil penetration energy scenario are determined
primarily by the SOp emission limits placed on oil combustion.
Alternative control levels IV, V, and VI require a percent reduction in
SOp emissions from oil combustion to achieve emission reductions of 200,000
to 236,000 Mg/year (220,000 to 260,000 tons/year), at increases in
annualized costs of $120 to $130 million/year over the regulatory baseline.
The average cost effectiveness of alternative control levels requiring a
percent reduction in S02 emissions ranges from $560 to $600/Mg ($510 to
$540/ton) of S02 removed.
The incremental cost effectiveness of alternative control level IV over
alternative control level III (i.e., percent reduction over low sulfur fuel)
is approximately $l,190/Mg ($l,080/ton) of S02 removed. Note, however, that
the incremental cost effectiveness decreases, rather than increases, in
8-14
-------
P.23
progressing from alternative IV to alternative VI. Alternative control
level VI, therefore, is more cost effective in reducing S(L emissions than
either alternatives IV or V. This is consistent with the analysis discussed
in "Consideration of Demonstrated Emission Control Technology Costs," which
also indicates that a percent reduction requirement of 90 percent is more
cost effective than other percent reduction requirements.
The most cost effective alternative requiring a percent reduction in
emissions should be used to calculate the incremental cost effectiveness of
alternative control levels requiring a percent reduction in S(L emissions
over alternative control levels based on the use of low sulfur fuels.
Consequently, alternative control level VI, rather than alternative control
level IV, should be used in this calculation. Thus, the incremental cost
effectiveness of alternatives which require a percent reduction in SCL
emissions over alternatives based on the use of low sulfur fuels should be
viewed as $945/Mg ($860/ton) of S02 removed.
Finally, there is a shift of about 116 to 153 million GJ/year (110 to
145 trillion Btu/year) from oil combustion to coal or natural gas combustion
under alternative control levels IV, V, and VI.
The results obtained under the high coal penetration scenario indicate
that alternative control levels limiting S02 emissions from coal combustion
to 731 and 516 ng SO?/J (1.7 and 1.2 Ib SOp/million Btu) heat input would
achieve a reduction in SO,, emissions of 163,000 to 191,000 Mg/year (180,000
to 210,000 tons/year) at increases in annualized costs of $10 to $20
million/year. The average cost effectiveness of emission control is $66 to
$88/Mg ($60 to $80/ton) of S02 removed. The control of S02 emissions under
these alternatives also result in a shift of up to 42 million GJ/year (40
trillion Btu/year) from coal combustion to natural gas combustion.
Alternative control levels III through VI require a percent reduction
in SOp emission from coal combustion. As a result, these alternatives would
achieve reductions in S02 emissions of about 281,000 Mg/year (310,000
tons/year), at increases in annualized costs of about $30 million/year. The
average cost effectiveness of alternative control levels requiring a percent
reduction in emissions is about $110/Mg ($100/ton) of SOp removed. The
G-15
-------
incremental cost effectiveness over alternatives based on the use of low
sulfur coal is about $276/Mg ($250/ton) of SCL removed. Fuel switching from
coal to natural gas combustion, however, increases to 137 to 148 million
GJ/year (130 to 140 trillion Btu/year).
The results of this preliminary analysis are presented graphically in
Figure 8-i. Several conclusions may be drawn from these results. First,
there is little difference in annualized costs among alternative control
levels requiring a percent reduction in S0« emissions. National cost
impacts projected by IFCAM are relatively insensitive to variations in the
level of the percent reduction requirement. Thus, little insight is gained
from analysis of a number of alternatives requiring various percent
reductions in S02 emissions. Consequently, the regulatory analysis
discussed below used a single percent reduction alternative control level of
90 percent to represent the range of percent reduction requirements that
could be included in the NSPS. As mentioned above and discussed in
"Consideration of Demonstrated Emission Control Technology Costs," a percent
reduction requirement of 90 percent is the most cost effective percent
reduction alternative.
Second, under the high oil penetration scenario, there is a significant
difference in annualized costs among alternative control levels based on the
use of various low sulfur fuels. IFCAM, therefore, is sensitive under this
energy scenario to different alternative control levels limiting S02
emissions from oil combustion based on the use of various low sulfur fuels.
Consequently, the regulatory analysis examined two alternative control
levels based on the use of low sulfur fuel under the high oil penetration
energy scenario. One alternative limits S02 emissions from oil combustion
to 688 ng SO^/J (1.6 Ib S02/million Btu) heat input and from coal combustion
to 731 ng S00/J (1.7 Ib SOp/million Btu) heat input. Another alternative
limits SO- emissions from oil combustion to 344 ng S02/J (0.8 Ib SO^/million
Btu) heat input and from coal combustion to 516 ng SO?/J (1.2 Ib S02/million
Btu) heat input.
Third, under the high coal penetration scenario, there is little
difference in annualized costs among alternative control levels based on the
8-16
-------
3800
o oo o
Percent Reduction
Low Sulfur Fuel
3600-
High Coal Penetration
m
•9
e
o
E
Percent Reduction
00
I
3400.
•o
e
N
Low Sulfur Fuel
0
3200
High OH Penetration
50
100
150
200
250
SO2 Emission* (1,000 tone/year)
300
Figure 8-1. Annualized Costs and S02 Emission Reductions
for Regulatory Alternatives
-------
P.26
use of various low sulfur fuels. As a result, the national cost impacts
projected by IFCAM are relatively insensitive to alternatives based on the
use of various low sulfur fuels under this energy scenario. Consequently,
the regulatory analysis examined only one alternative control level based on
the use of low sulfur fuel under the high coal penetration scenario:
reducing SCL emissions from oil combustion to 344 ng SCL/J (0.8 Ib
SCL/million Btu) and from coal combustion to 516 ng SCL/J (1.2 Ib
SCL/million Btu) heat input.
As a result, IFCAM was used to examine the potential impacts associated
with six regulatory alternatives limiting S02 emissions from steam
generating units firing fossil fuels under the high oil penetration energy
scenario and five regulatory alternatives under the high coal penetration
energy scenario. These regulatory alternatives are summarized in Table 8-6.
As shown in Table 8-6, the population of steam generating units was
divided into four size categories. As mentioned above, under the high oil
penetration scenario, the impacts of two alternative control levels based on
the use of low sulfur fuels were examined. Under the high coal penetration
scenario, the impacts of only one alternative control level based on the use
of low sulfur fuels were examined. The regulatory alternatives under both
energy scenarios result from first applying the alternative control level(s)
based on the use of low sulfur fuels to all steam generating units, and then
applying the alternative control level requiring a percent reduction in SCL
emissions, first to large steam generating units, and then to smaller and
smaller steam generating units. This leads to a succession of regulatory
alternatives, each one more stringent than the previous alternative.
8.1.2 Analysis of Regulatory Alternatives
The national impacts projected by IFCAM for each of the regulatory
alternatives under the high oil penetration energy scenario are summarized
in Table 8-7. An anomaly appears to arise under the high oil penetration
energy scenario in progressing from alternative 2 to alternative 3 and then
to alternatives 4 through 6 in the incremental cost effectiveness of
8-18
-------
P.27
TABLE .8-6,
. REGULATORY ALTERNATIVES
i
(F250
Base
0.8/1.2
0.8/1.2
90% Reduction
90% Reduction
90% Reduction
90% Reduction
Base
0.8/1.2
90% Reduction
90% Reduction
90% Reduction
90% Reduction
emission
or a
1
-------
TABLE 8-7. NATIONAL IMPACTS OF REGULATORY ALTERNATIVES
Fossil Fuel-Fired Steam Generating Units
Annual Annual ized
Regulatory Emissions Costs
Alternative (1,000 tons/yr)($/yr million)
00
i
ro
o
High Oil Penetration
Baseline
Alternative 1
Alternative 2
Alternative 3
Alternative 4
Alternative 5
Alternative 6
High Coal Penetration
Baseline
Alternative 1
Alternative 2
Alternative 3
Alternative 4
Alternative 5
279
205
106
72
61
4G
16
326
114
66
49
26
16
3,349
3,357
3,406
3,445
3,450
3,464
3,482
3,725
3,743
3,771
3,768
3,754
3,757
Cost Effectiveness
($/ton)
Average
108
330
460
460
480
510
_
80
180
160
100
100
Incremental
-
500
1,150
450
670
750
_
-
580
-180
-610
300
Fuel Use
(trillion Btu/yr)
Coal
23
17
17
30
30
29
26
284
248
223
197
159
147
Oil
323
329
257
217
215
204
178
7
0
0
0
0
0
Gas
152
153
224
251
253
265
294
207
250
275
301
339
351
Quantity of
Fuel Scrubbed
(trillion Btu)
Liquid Waste
Coal
4
4
4
26
26
26
26
17
23
101
118
141
147
Oil (million ft3/yr
23
23
64
96
117
151
178
0
0
0
0
0
0
228
225
240
284
301
328
352
223
229
330
351
381
396
Solid
Waste
) (1000 tons/yr)
110
75
80
150
150
140
130
1,350
1,150
1,050
950
820
770
-------
P.29
emission control. The incremental cost effectiveness increases from $550/Mg
($500/ton) to $l,270/Mg ($l,150/ton), decreases to $495/Mg ($450/ton) and
then increases steadily to $825/Mg ($750/ton) of S02 removed.
This anomaly is explained by the difference in the amount of fuel
switching that occurs among steam generating units above and below 73 MW
(250 million Btu/hour) heat input capacity in response to requirements to
achieve a percent reduction in S0? emissions. For steam generating units
above 73 MW (250 million Btu/hour) heat input capacity, there is relatively
little fuel switching from oil or coal to natural gas. Below 73 MW
(250 million Btu/hour) heat input capacity, there is a substantial amount of
fuel switching. Consequently, for steam generating units above 73 MW
(250 million Btu/hour) heat input capacity, FGD systems are installed in
response to requirements to achieve a percent reduction in S02 emissions.
Below 73 MW (250 million Btu/hour) heat input capacity, however, a
substantial number of steam generating units switch from oil or coal to
natural gas to avoid the costs of FGD systems.
Fuel switching, therefore, tends to mitigate the costs of S0? control
associated with requirements to achieve a percent reduction in emissions for
steam generating units below 73 MW (250 million Btu/hour) heat input
capacity, but not for steam generating units above 73 MW (250 million
Btu/hour) heat input capacity. The result is that the incremental cost
effectiveness of emission control increases significantly in progressing
from regulatory alternative 2 to regulatory alternative 3, due to the
requirement associated with alternative 3 to achieve a percent reduction in
emissions from steam generating units above 73 MW (250 million Btu/hour)
heat input capacity. It then decreases significantly in progressing from
regulatory alternative 3 to regulatory alternative 4 as this requirement is
extended from steam generating units above 73 MW (250 million Btu/hour) heat
input capacity to steam generating units below 73 MW (250 million Btu/hour)
heat input capacity.
As shown, the various regulatory alternatives examined under the high
oil penetration scenario could reduce national S02 emissions by about 68,000
to 236,000 Mg/year (75,000 to 260,000 tons/year). National annualized
8-21
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costs, however, could be increased by about $57 to $133 mil lion/year. The
average cost effectiveness of emission control would range from about $121
to $562/Mg ($110 to $510/ton) of S(L removed and the incremental cost
effectiveness between regulatory alternatives would generally be in the
range of $550 to $l,270/Mg ($500 to $l,150/ton) of S02 removed.
Fuel switching of about 70 to 153 million GJ/year (66 to 145 trillion
Btu/year) from oil or coal to natural gas could occur. This would result in
an increase in natural gas combustion in new industrial-commercial-
institutional steam generating units of about 45 to 95 percent. While this
increase in natural gas combustion may seem high when .expressed in this
manner, it is negligible when compared to the current level of natural gas
combustion in the industrial sector. As shown in Table 8-8, an increase of
153 million GJ/year (145 trillion Btu/year) in natural gas combustion in new
industrial steam generating units, for example, represents an increase of
only about 2 percent in total natural gas combustion over 1983 levels in the
industrial sector. In addition, this increase in natural gas consumption by
the industrial sector represents only a 1.5 percent increase over projected
industrial gas consumption in 1990. The projected total natural gas
production in 1990 is 22 billion GJ (21 quadrillion Btu). This production
level is expected to be more than sufficient to meet the projected demand in
1990. Considered from this perspective, this fuel switching impact is
minor.
The potential impact on coal combustion of all regulatory alternatives
under the high oil penetration energy scenario is negligible. As shown in
Table 8-7, coal combustion represents about 4.5 percent of new industrial
steam generating unit energy consumption under the regulatory baseline.
Regulatory alternative 2, which is based on the combustion of low sulfur
fuels, could reduce this to 3.5 percent. Under regulatory alternative 6,
which requires a percent reduction in S02 emissions, coal combustion could
increase to about 5.5 percent. As shown in Table 8-9, whether the potential
impacts of regulatory alternatives on coal markets under the high oil
penetration scenario are considered in terms of national or Midwestern coal
8-22
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TABLE 8-8. POTENTIAL NATIONAL NATURAL GAS MARKET IMPACTS
Industrial
Utility
Total
1983 Consumption
trillion Btu/yeara
6,700
3,000
9,700
oo aTotal Energy Resource Analysis Model;
^ industrial and utility sectors.
w h_. .
Maximum Increase
in Consumption
trillion Btu/year Percent
145 2.1
145 1.5
American Gas Association; March
Projected 1990
Consumption,
trillion Btu/year
9,500
2,400
11,900
1985. Total natural gas
Maximum Increase
in Consumption
trillion Btu/year Percent
145 1.5
145 1.2
consumption in the
Change in consumption over baseline as a result of alternative SO^ control levels.
-------
P.32
TABLE 8-9. NATIONAL IMPACTS
Fossil Fuel-Fired Steam Generating Units
Potential Coal Market Impacts3
National Coal Markets
o Coal Consumption
- Utility
- Industrial
- Total j
V
O.i Potential NSPS Impact
- Baseline
- Low Sulfur Fuel
- Percent Reduction
Midwest Coal Markets
o Coal Consumption (1982)b
o Potential NSPS Impact (1990)
- High Oil Penetration
Baseline
Low Sulfur Fuel
Percent Reduction
- High Coal Penetration
Baseline
Low Sulfur Fuel
Percent Reduction
1982b
12,500
2,600
15,100
High Oil Penetration
23
17
26
Eastern Coal
Local Other
1545 1795
1 3
0 0
6 5
21 36
0 42
19 17
High
Western
Coal
885
0
0
0
4
11
0
1990C
18,300
3,700
22,000
Coal Penetration
284
248
147
Total
4225
4
0
11
61
53
36
Impacts in trillion Btu/year.
bCoal Data 1981/1982; National Coal Association; 1983.
°Looking Ahead to 1995; National Coal Association; April 1982.
8-24
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markets, the amount of coal involved is so small that all impacts are
i
negligible.
The national impacts projected by IFCAM for each of the regulatory
alternatives under the high coal penetration energy scenario are also
summarized in Table 8-7. As shown, an anomaly appears to arise in
progressing from regulatory alternative 2 to alternatives 3 and 4. The
average cost effectiveness of emission control decreases and the incremental
cost effectiveness becomes negative. This is a reflection of the lower
costs associated with regulatory alternatives 3 and 4. Even though these
alternatives are more stringent than regulatory alternative 2, as reflected
by the emission decreases in progression from regulatory alternative 2 to
regulatory alternatives 3 and 4, annualized costs decrease.
This anomaly is explained by the difference between the methodology
used by IFCAM to select the least cost means of complying with regulatory
alternatives and that used to calculate the national annualized costs
resulting from compliance with regulatory alternatives. IFCAM selects the
least cost means of complying with regulatory alternatives on an after-tax
basis. Thus, factors such as depreciation and investment tax credits are
considered in selecting the least cost means of compliance. In calculating
national annualized costs, however, IFCAM compiles these costs on a
before-tax basis. Thus, factors such as depreciation and investment tax
credits are not considered.
As a result, as is often the case when the economics of two
alternatives are very close, tax considerations may be sufficient to
determine which of the two alternatives is more attractive. What may be
more attractive in the absence of tax considerations may be less attractive
in the presence of tax considerations.
For a number of steam generating units under the high coal penetration
energy scenario, the economics of the decision to fire coal or to fire
natural gas is very close in IFCAM, particularly for steam generating units
below 73 MW (250 million Btu/hour) heat input. On an after-tax basis, the
economics favor coal; on a before-tax basis, the economics favor natural gas
(see Table 6-19).
8-25
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P.34
In response to standards based on the use of low sulfur fuels, many
steam generating units fire coal. When a requirement to achieve a percent
reduction in SCL emissions from coal combustion is imposed, however, the
economics of firing coal and installing an FGD system to reduce S(L
emissions, compared to firing natural gas, favor the selection of natural
gas. Thus, a number of steam generating units switch from firing coal to
firing natural gas. For these steam generating units, coal, the fuel choice
under low sulfur fuel standards, is less expensive than natural gas on an
after-tax basis but more expensive than natural gas on a before-tax basis.
Under standards based on achieving a percent reduction in emissions, IFCAM
selects natural gas as the fuel choice because it is less expensive than
firing coal and installing an FGD system (both before and after taxes).
Firing natural gas has lower costs on a before-tax basis than those
associated with firing coal under the low sulfur fuel alternative. Because
IFCAM compiles annualized cost impacts on a before-tax basis, annualized
costs decrease in this comparison rather than increase.
Under the high coal penetration scenario, this situation of a
coal-fired steam generating unit being less expensive than a natural
gas-fired steam generating unit on an after-tax basis, but more expensive on
a before-tax basis, is sufficiently widespread for steam generating units
below 73 MW (250 million Btu/hour) heat input capacity that in progressing
from regulatory alternative 2 to regulatory alternatives 3 and 4, annualized
costs, as well as S02 emissions, decrease. As a result, the incremental
cost effectiveness of emission control between regulatory alternatives 2 and
3 and regulatory alternatives 3 and 4 is negative rather than positive.
As shown in Table 8-7, under the high coal penetration energy scenario,
the various regulatory alternatives examined could reduce national emissions
of S02 by about 191,000 to 281,000 Mg/year (210,000 to 310,000 tons/year).
Annualized costs, however, could be increased by about $20 to $30
million/year. The average cost effectiveness of emission control would
range from $88 to $198/Mg ($80 to $180/ton) of S02 removed and the
incremental cost effectiveness of control would not exceed $331/Mg
($.300/ton) of S02 removed.
8-26
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P.35
Fuel switching from coal to natural gas, however, of about 40 to 143
million GJ/year (36 to 137 trillion Btu/year) could occur. This would
result in an increase in natural gas combustion ranging from 20 to 70
percent and a decrease in coal combustion ranging from 13 to 48 percent in
new steam generating units. As discussed earlier, if these fuel shifts are
compared to current industrial sector energy demands, however, they are
negligible. A shift of 148 million GJ/year (140 trillion Btu/year), for
example, represents only about 2 percent of natural gas combustion, about 5
percent of coal combustion, and less than a 1 percent fuel shift in the
total existing industrial sector energy market (see Table 8-9).
Unlike the high oil penetration scenario, under the high coal penetra-
tion scenario all regulatory alternatives result in projected decreases in
coal combustion. Regulatory alternative 1, which is based on the combustion
of low sulfur fuels, could reduce coal combustion from about 57 percent to
about 50 percent of the total fuel combusted in new industrial-commercial -
institutional steam generating units. Regulatory alternative 5, which
requires a percent reduction in S02 emissions, would reduce this coal
combustion from 57 percent to about 30 percent.
In terms of national or Midwestern coal markets, however, the magnitude
of these potential impacts is minimal, as shown in Table 8-9. Even under
the regulatory baseline, which yields the highest levels of projected coal
combustion, coal combustion in new industrial-commercial-institutional steam
generating units only represents about 1 percent of projected national coal
combustion in 1990 and only about 7.5 percent of projected industrial steam
generating unit coal combustion. The same is true in Midwestern coal
markets, where projected coal combustion in new industrial-commercial-
institutional steam generating units in 1990 only represents about 1.5
percent of actual coal combustion in the Midwest in 1982.
8.2 MIXED FUEL-FIRED STEAM GENERATING UNITS
As mentioned above, national impacts were also examined for mixed
fuel-fired industrial-commercial-institutional steam generating units.
8-27
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Mixed fuel-fired steam generating units may fire mixtures of fossil fuels
but generally fire mixtures of fossil and nonfossil fuels.
As in the analysis discussed above for fossil fuel-fired steam
generating units, the population of new industrial-commercial-institutional
mixed fuel-fired steam generating units in 1990 was projected. The total
costs of alternative fuel mixtures, including the costs of complying with
environmental regulations, were then compared on an after-tax discounted
cash flow basis for each steam generating unit over a 15-year investment
period. The lowest cost combination of fuel mixture and emission control
system was then determined for each steam generating unit. These results
were then aggregated to yield national projections in 1990 of annualized
costs, sulfur dioxide emissions, and solid and liquid wastes.
The magnitude of the national impacts associated with alternative
control levels for new mixed fuel-fired steam generating units is a function
of two major variables. These are the projected population of new mixed
fuel-fired steam generating units (i.e., the overall number and size
distribution of these units) and the projected fuel mixtures fired.
Little data and information are readily available concerning the
current population, historical sales, or projected growth of mixed
fuel-fired steam generating units. What little data and information are
available, however, indicate that wood is the most common fuel fired in
combination with various fossil fuels in mixed fuel-fired steam generating
units. This is expected to be the case for new mixed fuel-fired steam
generating units as well. Consequently, the limited data and information
available for mixed fuel-fired steam generating units firing mixtures of
wood and various fossil fuels were used to represent mixed fuel-fired steam
generating units in general.
Data provided by the National Council of the Paper Industry for Air and
Stream Improvement (NCASI) indicate that 35 mixed fuel-fired steam
generating units were constructed during the five-year period from 1980
through 1984. These steam generating units had a combined heat input
capacity of 5,850 MW (20.1 billion Btu/hour). This estimate of growth over
the past five years is generally consistent with information also available
8-28
-------
from the American Boiler Manufacturers Association and the Department of
Energy. In the absence of growth projections to the contrary, therefore,
this was assumed to be the growth in new mixed fuel-fired steam generating
units over the five years from 1985 through 1990. Data and information
available from NCASI were also used to project the distribution of new mixed
fuel-fired steam generating units by steam generating unit size, by
composition of fuel mixture fired, and by the 'geographical location of new
mixed fuel-fired steam generating units.
Prices for coal, residual oil, and natural gas are the same as those
discussed previously. Data are generally unavailable on the cost or price
of nonfossil fuels. In some cases these fuels could be "free," in the sense
that they could not otherwise be sold in the open marketplace and there are
negligible costs associated with their use as a fuel. In most cases,
however, there is a real cost associated with the use of nonfossil fuels.
It is unlikely, however, that the cost of these fuels would be higher than
that of coal on a heating value basis. Consequently, two costs for
nonfossil fuels were considered: zero cost; and the same cost, on a heating
value basis, as the least expensive coal available.
As in the analysis discussed in "Consideration of Demonstrated Emission
Control Technology Costs," this analysis of the national impacts for mixed
fuel-fired steam generating units assumes no emission credits for dilution
of the SCL emissions from combustion of fossil fuels with exhaust gases from
the combustion of nonsulfur-bearing fuels. Consequently, to comply with an
alternative control level based on the use of low sulfur.fuels, a mixed
fuel-fired steam generating unit would be required to fire a low sulfur fuel
or install an FGD system to reduce SCL emissions.
Similarly, to comply with an alternative control level requiring a
percent reduction in SCL emissions, a mixed fuel-fired steam generating unit
would be required to achieve the specific percent reduction requirement
included in the alternative control level. Dilution of the SCL emissions
with exhaust gases resulting from the combustion of nonsulfur-bearing fuels
would not permit a mixed fuel-fired steam generating unit to achieve a lower
percent reduction requirement.
8-29
-------
P.38
The merits of emission credits for mixed fuel-fired steam generating
units, as well as emission credits for other types of steam generating
units, are examined and discussed in "Consideration of Emission Credits."
Table 8-10 summarizes projected SCL emissions, annualized costs, and
fuel consumption for new industrial-commercial-institutional mixed
fuel-fired steam generating units in 1990. Given the relative prices
projected for coal, residual oil, and natural gas, all new mixed fuel-fired
steam generating units are projected to fire coal in combination with
various nonfossil fuels.
8.2.1 Selection of Regulatory Alternatives
The "sensitivity" analysis of various alternative control levels for
fossil fuel-fired steam generating units discussed above concluded that
there is little difference in annualized costs among alternative control
levels based on the use of low sulfur coal and little difference among
alternative control levels requiring a percent reduction in S02 emissions
under the high coal penetration scenario. Consequently, under this energy
scenario the regulatory analysis examined only one alternative based on the
use of low sulfur fossil fuel - that of reducing S02 emissions from coal
combustion to 516 ng SO^/J (1.2 Ib SOp/million Btu) heat input. Similarly,
the regulatory analysis examined a single percent reduction requirement of
90 percent to represent the range of percent reduction requirements that
could be included in new source performance standards.
As mentioned above, all new mfxed fuel-fired steam generating units are
projected to fire coal as the fossil fuel. Consequently, these two
alternative control levels were selected as the basis of the regulatory
alternatives examined. The potential impacts associated with four
regulatory alternatives limiting S02 emissions from industrial-commercial-
institutional mixed fuel-fired steam generating units were examined. These
regulatory alternatives are presented in Table 8-11.
8-30
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TABLE 8-10. NATIONAL IMPACTS
Mixed Fuel-Fired Steam Generating Units
Regulatory Baseline (Base Case)
1990
S02 emissions, thousand tons/year 69
Annualized costs, million $/year 425
Fuel use, trillion Btu/year
o Coal/nonfossil . 99
o Oil/nonfossil 0
o Natural gas/nonfossil 0
8-31
-------
P.40
TABLE 8-11. REGULATORY ALTERNATIVES
Mixed Fuel-Fired Steam Generating Units
Regulatory Alternative'
Steam Generating Unit Heat Input Capacity
(Million Btu/hr)
100-250 >250
Baseline
Alternative 1
Alternative 2
Alternative 3
Alternative 4
Base
Base
1.2 Ib S0? million Btu
1.2 Ib S02/million Btu
90% Reduction
Base
1.2 Ib S02/million Btu
1.2 Ib S02/million Btu
90% Reduction
90% Reduction
Control levels shown for each regulatory alternative are SOp emission
limits in Ib S02/million Btu or a required percent reduction in SO^
emissions. Emission limits and percent reduction requirements are
based on fossil fuel heat input only.
8-32
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,£.41,
8.2.2 Analysis of Regulatory Alternatives
The national impacts projected for each of the regulatory alternatives
are summarized in Table 8-12. The total annualized costs presented in
Table 8-12 are based on a zero cost or price for nonfossil fuels. The total
annual ized costs are higher when the cost or price of nonfossil fuels is
assumed to be equal to that of coal. The incremental costs or cost impacts
between alternatives, however, remain the same.
Table 8-12 shows that under the regulatory baseline the annualized
costs for mixed fuel-fired steam generating units are about $425 million per
year and the annual emissions are about 62,700 Mg/year (69,100 tons/year).
Under regulatory alternative 1, annualized costs would be about $446
million/year, and annual emissions would be reduced to about 22,000 Mg/year
(24,300 tons/year). Similar impacts result under regulatory alternative 2;
annualized costs would be about $446 million/year, and annual emissions
would be reduced to 25,600 Mg/year (23,200 tons/year). The actual cost
increase of regulatory alternative 2 over regulatory alternative 1 would be
about $400,000 per year. This increase is small because only five new steam
generating units with heat input capacities of less than 73 MW (250 million
Btu/hour) are projected. Furthermore, because these five steam generating
units are projected to fire 20 percent fossil fuel, the cost impacts of
firing a more expensive fossil fuel are minimized.
As discussed previously in the analysis of national impacts on fossil
fuel-fired steam generating units, many fossil fuel-fired steam generating
units electing to fire coal under the regulatory baseline, or under
regulatory alternatives requiring the use of low sulfur fuel, would switch
fuels and fire natural gas under a regulatory alternative requiring a
percent reduction in SO,, emissions. In these cases, natural gas firing
represents the least cost means of complying with a regulatory alternative
requiring a percent reduction in SO^ emissions.
The results of this analysis, however, show that mixed fuel-fired steam
generating units firing mixtures of coal and nonfossil fuels do not switch
to firing natural gas under a regulatory alternative requiring a percent
8-33
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TABLE 8-12. NATIONAL IMPACTS OF REGULATORY ALTERNATIVES
Mixed Fuel-Fired Steam Generating Units
CO
1
00
-p>
Regulatory
Alternative
Baseline
Alternative 1
Alternative 2
Alternative 3
Alternative 4
Annual
Emissions
(1,000 tons/yr)
69.1
24.3
23.2
8.2
7.9
Annual ized
Costs
$ Million/yr
424.8
445.9
446.3
470.0
471.6
Cost Effectiveness
$/ton
Average
-
470
470
740
765
Incremental
-
-
360
1,580
5,330
Fuel Use
Trillion Btu/yr
Coal
49
49
49
49
49
Nonfossil
50
50
50
50
50
Quantity of
Fuel Scrubbed
Trillion Btu/yr
-
-
_
95
99
Liquid Waste
Million ftj/yr
40
40
40
149
151
Solid Waste
1,000 tons/yr
284
281
281
286
286
c.
•o
-------
P.43
reduction in S0? emissions. Mixed fuel-fired steam generating units
continue to fire mixtures of coal and nonfossil fuels under both the high
oil and high coal penetration scenarios, even when the cost of nonfossil
fuel is assumed to be equal to that of coal.
The large savings in capital costs that accrue by selecting a natural
gas-fired steam generating unit instead of a coal-fired unit are not accrued
when natural gas is fired in place of coal in a mixed fuel-fired steam
generating unit. As a result, the choice of fossil fuels in mixed
fuel-fired steam generating units is determined primarily by relative fuel
prices. Because natural gas is projected to cost much more than coal under
both of the energy price scenarios considered, no switching to natural gas
occurs in mixed fuel-fired steam generating units even in response to
standards that require a percent reduction in SCL emissions.
Under regulatory alternative 3, annualized costs would be about $470
million/year and annual emissions would be reduced to about 7,400 Mg/year
(8,200 tons/year). Under regulatory alternative 4, annualized costs would
be about $472 million/year and annual emissions would be reduced to 7,200
Mg/year (7,900 tons/year).
The average cost effectiveness of the various regulatory alternatives
over the regulatory baseline ranges from about $520/Mg to $830/Mg ($470/ton
to $765/ton) of SOp removed. The incremental cost effectiveness of
regulatory alternative 2 over regulatory alternative 1 is about $400/Mg
($360/ton) of SOp removed. The incremental cost effectiveness of regulatory
alternative 3 over regulatory alternative 2 is $l,740/Mg ($l,580/ton) of SO,,
removed. The incremental cost effectiveness of emission control increases
significantly due to the requirement associated with regulatory alternative
3 to achieve a percent reduction in emissions from mixed fuel-fired steam
generating units with heat input capacities above 73 MW (250 million
Btu/hour). The large cost increase of a percent reduction requirement
compared to a requirement based on the use of low sulfur coal results in a
large increase in the incremental cost effectiveness value. The incremental
cost effectiveness of regulatory alternative 4 over regulatory alternative 3
is $5,860/Mg ($5,330/ton) of S02 removed.
8-35
-------
The high incremental cost effectiveness of regulatory alternative 4
over regulatory alternative 3 can be explained by examining the alternatives
themselves. Under regulatory alternative 3, only steam generating units
with heat input capacities greater than 73 MW (250 million Btu/hour) would
be required to achieve a percent reduction in SCL emissions. Under
regulatory alternative 4, steam generating units with heat input capacities
between 29 and 73 MW (100 and 250 million Btu/hour) would also be required
to achieve a percent reduction in SOp emissions. As mentioned previously,
all of the projected new mixed fuel-fired steam generating units with heat
input capacities in this range are expected to fire very small amounts of
fossil fuel in relation to nonfossil fuel (on the order of 20 percent). As
discussed previously, the incremental cost effectiveness of achieving a
percent reduction in SOp emissions over the use of low sulfur fuel increases
as the amount of fossil fuel fired decreases. Consequently, this high
incremental cost effectiveness is not due to the smaller size of steam
generating units included under regulatory alternative 4, but is due to the
small amount of fossil fuel fired in mixed fuel-fired steam generating units
with heat input capacities between 29 and 73 MW (100 and 250 million
Btu/hour).
As discussed previously, the amount of fossil fuel fired on an annual
basis compared to the rated annual heat input capacity for a particular
steam generating unit is referred to as the fossil fuel utilization factor.
Table 8-13 illustrates the relationship between incremental cost
effectiveness values and fossil fuel utilization factors. A set of .
regulatory alternatives was structured, ranging from establishing an
emission limit based on the use of low sulfur fuel for all mixed fuel-fired
steam generating units to requiring all mixed fuel-fired steam generating
units to achieve a percent reduction in S0£ emissions. Within this range
were alternatives requiring percent reduction for steam generating units
with fossil fuel utilization factors above 0.48 and the use of low sulfur
fuels for units with fossil fuel utilization factors of 0.48 or less;
percent reduction for steam generating units with fossil fuel utilization
factors above 0.30 and the use of low sulfur fuels for units with fossil
8-36
-------
TABLE 8-13. NATIONAL IMPACTS: MIXED FUEL-FIRED STEAM GENERATING UNITS -
IMPACTS AS A FUNCTION OF FOSSIL FUEL UTILIZATION FACTOR
CO
I
co
Alternative
Baseline
(2.5 Ib S02/million Btu)
Low Sulfur Fuel
(1.2 Ib S02/million Btu)
Percent Reduction for
Fossil Fuel Utilization
Factors >0.48a
Percent Reduction for
Fossil Fuel Utilization
Factors >0.30a
Percent Reduction for
Fossil Fuel Utilization
Factors >0.12a
Percent Reduction
Annual Emissions, Annual i zed
1,000 Mg/year Costs,
(1,000 tons/year) $ million
62.7 (69.1) 424.8
21.0 (23.2) 446.3
21.0 (23.2) 446.3
11.5 (12.7) 457.2
-
9.7 (10.7) 460.2
7.2 (7.9) 471.6
Average Cost
Effectiveness,
$/Mg ($/ton)
_
520 (470)
520 (470)
630 (570)
670 (605)
840 (765)
Incremental Cost
Effectiveness,
$/Mg ($/ton)
_
0 (0)
1,150 (1,040)
1,610 (1,460)
4,575 (4,150)
aSteam generating units with fossil fuel utilization factors at or below the specified level are
not required to achieve a percent reduction in S0? emissions but must meet an emission limit of
516 ng S02/J (1.2 Ib S02/million Btu). i
Over less stringent alternative.-
-------
P.46
fuel utilization factors of 0.30 or less; and percent reduction for steam
generating units with fossil fuel utilization factors above 0.12 and the use
of low sulfur fuels for units with fossil fuel utilization factors of 0.12
or less.
As shown in Table 8-13, the incremental cost effectiveness of a percent
reduction requirement for steam generating units with fossil fuel
utilization factors above 0.48 over a low sulfur fuel requirement is $0/Mg
($0/ton) of SOp removed. This is because no steam generating units were
projected to fire fossil fuel in amounts exceeding 48 percent of their rated
annual capacity. Therefore, no impacts were projected. The incremental
cost effectiveness of a percent reduction requirement for steam generating
units with fossil fuel utilization factors above 0.30 and a low sulfur fuel
requirement for units with fossil fuel utilization factors of 0.30 or less,
over a percent reduction requirement for only those units with fossil fuel
utilization factors above 0.48, is $l,150/Mg ($l,040/ton) of SO,, removed.
The incremental cost effectiveness of a percent reduction requirement for
steam generating units with fossil fuel utilization factors above 0.12 and a
low sulfur fuel requirement for units with fossil fuel utilization factors
of 0.12 or less, over a percent reduction requirement for only those units
with fossil fuel utilization factors above 0.30, is $l,610/Mg ($l,460/ton)
of S0? removed. The incremental cost effectiveness of requiring all steam
generating units to achieve a percent reduction in SO^ emissions over
exempting units with fossil fuel utilization factors of 0.12 or less from a
percent reduction requirement increases to $4,575/Mg ($4,150/ton) of SO^
removed. Thus, as stated previously, the fossil fuel utilization factor at
which a mixed fuel-fired steam generating unit operates directly affects the
incremental cost effectiveness of achieving a percent reduction in $62
emissions compared to firing a low sulfur fuel to comply with an emission
limit. As the fossil fuel utilization factor decreases, the incremental
cost effectiveness increases.
8-38
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P.47
9.0 CONSIDERATION OF INDUSTRY-SPECIFIC ECONOMIC IMPACTS
An analysis was undertaken to assess the potential industry-specific
economic impacts associated with new source performance standards limiting
SOp emissions from new industrial-commercial-institutional steam generating
units. This analysis, however, focused on the potential impacts associated
with a regulatory alternative requiring a percent reduction in S0?
emissions. The industry-specific impacts associated with other regulatory
alternatives, therefore, would be less than those discussed below.
The potential industry-specific economic impacts were analyzed in two
phases. The first phase focused on aggregate economic impacts for major
steam-using industries and estimated the potential impact on steam costs and
product prices based on industry-wide averages for eight large industry
groups. The groups selected for analysis account for approximately 70
percent of domestic industrial steam consumption. These eight industry
groups were: food; textiles; paper; chemicals; petroleum refining; stone,
clay, and glass; iron and steel; and aluminum.
To determine the potential product price impacts of a percent reduction
requirement, estimates were made of steam consumption per dollar of product
sales by industry group. Projected growth in product sales and the
resulting increased steam demands were then estimated by industry group.
Next, steam cost increases attributable to the percent reduction requirement
were estimated based on annualized steam generating unit and pollution
control costs. Assuming full cost pass-through of these increased costs to
product prices, the potential impact of this regulatory alternative on
product prices was estimated.
Growth projections indicate that from less than 1 to 9 percent of the
steam consumption in the eight major steam-using industries would be
generated in new steam generating units subject to the proposed standards by
1990. Average steam costs in these industry groups would increase about
$0.09 to $0.25/GJ ($0.09 to $0.24/million Btu) of heat input. Assuming full
cost pass-through of increased steam costs, product prices in the major
industry groups would increase by less than 0.03 percent. This potential
9-1
-------
P.48
impact represents a maximum product price increase because of the full cost
pass-through assumption. In some instances, increased steam costs would not
be completely passed through to product prices, and, therefore, the impact
on product prices would be less.
The second phase of the analysis focused :0n selected industries that
were considered likely to experience the most severe impacts. Seven
industries were selected due to the steam-intensive nature of their
operation or the low utilization of their steam generating unit capacity.
These industries were beet sugar refining, fruit and vegetable canning,
rubber reclaiming, automobile manufacturing, petroleum refining, iron and
steel manufacturing, and liquor distilling.
The economic impact analysis examined potential impacts on prices,
value added, profitability, and capital availability. This analysis was
based on "model" plants and "model" firms representative of each industry.
Model plants were defined for each industry based on historical plant
locations, fuel use, and steam generating unit construction patterns.
Annual plant sales, plant product output, product costs, and return on
assets were estimated for each model plant. Then, based on recent trends in
each industry, a scenario was developed involving existing steam generating
unit replacement, or construction of additional steam generating unit
capacity for plant expansion at each model plant. Based on these scenarios,
increased steam costs imposed on model plants by requirements to achieve a
percent reduction in S0? emissions were calculated.
Assuming full cost pass-through of steam cost increases, the potential
impact of a percent reduction requirement on product prices and value added
could be estimated. To estimate the potential impact on profitability, or
return on assets, an analysis was also conducted assuming full cost
absorption of increased steam costs with no pass-through.
Based on scenarios involving replacement of from 25 to 90 percent of
existing steam generating unit capacity with new steam generating unit
capacity at model plants for the seven industries selected, product prices
were projected to increase from less than 0.01 to 0.5 percent in 1990 for
all except the beet sugar refining industry, assuming full cost pass-through
9-2
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P.49
of increased steam costs. As shown in Table 9-1, the fruit and vegetable
canning industry showed no impacts due to the assumption that all new steam
generating unit capacity in this industry would be natural gas-fired.
For these same seven industries, value added was projected to increase
by about 0.01 to 0.9 percent in 1990 for all except the beet sugar refining
industry, assuming full cost pass-through of increased steam costs.
For both product price and value added impacts, the highest increases
are projected for the beet sugar refining industry. In the case of product
prices, this is due to the fact that the product price is low and steam
costs represent an unusually high proportion of manufacturing costs in the
beet sugar refining industry, compared to the other industries examined.
Similarly, value added impacts are higher since steam costs represent an
unusually high proportion of the non-raw material costs of manufacturing the
product in the beet sugar refining industry, compared to the other
industries examined.
Based on the same scenarios outlined above, but assuming full cost
absorption of increased steam costs, return on assets was projected to
decrease by 0.03 to 2.8 percentage points. Again, these potential impacts
represent "worse case" projections because of the assumption of full cost
absorption of the increased steam costs.
The analysis of potential impacts on capital availability examined the
impact of a percent reduction requirement on the ability of "model" firms to
finance pollution control expenditures. Corporate annual reports and
Securities and Exchange Commission Forms 10-K were reviewed to formulate a
hypothetical financial position and to identify the number of operating
plants for each model firm. Each plant operated by the model firm was
assumed to be identical to the corresponding model plant used in the
analysis discussed above. The potential impact of a percent reduction
requirement on each model firm's cash flow, coverage ratio, and debt/equity
ratio under two debt/equity financing strategies was estimated based on the
amount of financing needed to construct replacement or expansion steam
generating units.
9-3
-------
TABLE 9-1. SUMMARY OF CHANGE IN PRODUCT COST AND RETURN .ON ASSETS
FOR MODEL PLANTS AND FIRMS IN SELECTED INDUSTRIES
Industry
Beet Sugar Refining
Fruit ancLVegetable
Canning
vo
i. Rubber Reclaiming
Auto Manufacturing
Petroleum Refining
Iron and Steel
Manufacturing
Liquor Distilling
Model Plant
Increase in
Product Cost
(Percent)
1.50
0.50
<0.01
0.02
0.10
0.12
Model Plant
Increase in
Value Added
(Percent)
5.00
0.90
0.01
0.14
0.25
0.24
Model Firm Return on Assets
Base Case1
(Percent)
2.30
3.80
9.17
5.98
3.36
0.68
S09 Alternative
2
Control Level
(Percent)
1.50
1.00
9.14
5.93
3.28
0.37
Base case includes proposed PM/NO NSPS and current S09 SIP regulations.
A <_
2
The S0? alternative control level is a percent reduction requirement for all steam generating units
greater than 100 million Btu/hour.
3
Fruit and vegetable canning have no .impacts, since new steam generators are natural
gas-fired units. '
-------
Cash flow coverage ratios and book debt/equity ratios showed
essentially no change for any of the model firms under the two different
debt/equity financing strategies. Consequently, a percent reduction
requirement would not impair the ability of firms to raise sufficient
capital to construct new steam generating units.
The industry-specific economic impacts analysis, therefore, indicates
that a percent reduction requirement would generally increase product prices
and value added by less than 1 percent if all steam cost increases were
passed through to product prices. In addition, assuming absorption of all
steam cost increases, return on assets would generally decrease by about 3
percentage points or less. Cash flow coverage and book debt/equity ratios
showed essentially no change. Therefore, a percent reduction requirement
would not impose any capital availability constraints on firms.
As mentioned earlier, a percent reduction requirement is the most
stringent regulatory alternative considered. Consequently, the
industry-specific economic impacts associated with other regulatory
alternatives would be less severe than those discussed above.
9-5
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P.52
10.0 CONSIDERATION OF EMISSION CREDITS
Emission credits have been suggested for two general types of
industrial-commercial-institutional steam generating units: cogeneration
steam generating units and mixed fuel-fired steam generating units.
Emission credits would permit higher emissions from these units.
10.1 COGENERATION STEAM GENERATING UNITS
Cogeneration systems are defined as energy systems that simultaneously
produce both electrical (or mechanical) energy and thermal energy from the
same primary energy source. Cogeneration systems are efficient
electric/thermal energy production technologies with a potential for local
and regional energy savings and emission reductions.
Following adoption of the Public Utility Regulatory Policies Act of
1978 (PURPA), there has been increasing interest in the cogeneration of
electricity at industrial, commercial, and institutional sites. Under
PURPA, qualifying cogenerators may sell their excess electrical power
directly to electric utility companies at the utilities' avoided cost, which
makes on-site cogeneration economically attractive in many cases.
10.1.1 Steam Generator-Based Cogeneration Systems
In a steam generator-based cogeneration system, the simultaneous-
production of electric power and process heat is achieved by supplying the
steam produced by an industrial-commercial-institutional steam generating
unit to a steam turbine/electric generator set for electric power generation
and then recovering process or space heat from the steam turbine exhaust.
The steam generating unit used for an on-site cogeneration system would be
slightly larger than otherwise required. However, the total fuel use by a
cogeneration system is less than the combined total of the fuel used at a
utility steam generating unit to generate electricity and the fuel used by
10-1
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P.53
an industrial-commercial-institutional steam generating unit to provide
process or space heat.
The potential for regional energy savings through the use of a steam
generator-based cogeneration system, compared to the use of separate steam
generating units for electric power generation and process or space heat
production, can range from 5 percent to almost 30 percent depending on the
specific industry using the cogeneration system and the type of fuel used.
This reduced regional fuel consumption can translate into regional air
pollution emission reductions under certain conditions. For example, if a
cogeneration system reduces regional fuel use by 15 percent and displaces a
utility steam generating unit firing the same fuel, and subject to the same
emission limitation, regional emissions would also be reduced by 15 percent.
Because of this emission reduction potential, it has been suggested
that new source performance standards for industrial-commercial -
institutional steam generating units should include some type of "emission
credit" for the higher efficiencies achieved by cogeneration systems. Such
a credit, according to its proponents, would reduce the cost of air
pollution control at a cogeneration site, result in equivalent regional
emissions, and encourage the use of cogeneration systems.
If an emission credit were allowed for cogeneration systems, it would
adjust (increase) the emission limitation for cogeneration steam generating
units, offsetting any regional emission reduction that might occur from the
use of the cogeneration system. For example, for a coal-fired steam
generating unit subject to an $62 emission limit of 516 ng/J (1.2 Ib/million
Btu) heat input, a 15 percent emission credit reflecting the potential
decrease in regional emissions would increase the emission limit to 593 ng
S02/J (1.38 Ib S02/million Btu) heat input. Similarly, for a coal-fired
steam generating unit subject to a percent reduction requirement of 70 or 90
percent reduction in emissions, a 15 percent emission credit would decrease
the percent reduction requirement to 65.5 or 88.5 percent, respectively.
In addition, it may be quite difficult to identify the appropriate
emission credit for specific cogeneration systems. In cases where different
emission standards are applicable to the displaced fuel at a utility steam
10-2
-------
.£54.
generating unit and the fuel used in the cogeneration system, or different
fuels are fired in the utility steam generating unit than in the
cogeneration system, the environmental and fuel use impacts of cogeneration
become less clear. For example, in cases where a new cogeneration system
achieves emission levels that are lower than those from the utility steam
generating unit, a 15 percent regional energy savings may result in more
than a 15 percent reduction in regional emissions. Conversely, if the
cogeneration system results in emissions higher than the utility steam
generating unit, a 15 percent regional energy savings may result in less
than a 15 percent emission reduction. If hydroelectric or nuclear power
generation capacity is being replaced by cogeneration, regional emissions
increase.
Also of importance to local emissions is the fact that a larger
industrial-commercial-institutional steam generating unit is used in the
cogeneration system than would otherwise be used. Consequently, local
emissions at the cogeneration site increase in all cases.
To assess the reasonableness of emission credits for steam
generator-based cogeneration systems, the cost effectiveness of SOp emission
control associated with not providing emission credits was examined. This
analysis compared the cost effectiveness of SCL control among a conventional
industrial-commercial-institutional steam generating unit, a cogeneration
steam generating unit without emission credits, and a cogeneration steam
generating unit with emission credits, and calculated the incremental cost
effectiveness of not providing emission credits.
As discussed earlier, the annual capacity factor at which a steam
generating unit operates can have a significant influence on the cost
effectiveness of emission control. Conventional industrial-commercial -
institutional steam generating units generally operate at annual capacity
factors in the range of 0.6. Cogeneration steam generating units, however,
operate at much higher annual capacity factors, generally in the range of
0.9. Therefore, an annual capacity factor of 0.9 was used in the analysis
of emission credits for cogeneration steam generating units.
10-3
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P.55
As mentioned above, the potential for regional energy savings, reduced
fuel consumption, and reduced air pollutant emissions resulting from
cogeneration is in the range of 5 to 30 percent. If standards based on the
use of low sulfur fuels limited S(L emissions from coal-fired steam
generating units to 516 ng/J (1.2 Ib/million Btu) heat input and S02
emissions from oil-fired units to 345 ng/J (0.8 Ib/million Btu) heat input,
an emission credit of 30 percent would effectively increase these emission
limits to 670 and 450 ng/J (1.56 and 1.04 Ib/million Btu) heat input,
respectively.
Fuel pricing data are not available for low sulfur fuels that could
reduce S02 emissions to these levels, but not to 516 and 345 ng/J (1.2 and
0.8 Ib/million Btu) heat input. Pricing data are available, however, for
low sulfur fuels that could reduce SO,, emissions to 730 and 690 ng/J (1.7
and 1.6 Ib/million Btu) heat input for coal and oil, respectively. As a
result, emission limits of 730 and 690 ng S02/J (1.7 and 1.6 Ib S02/million
Btu) heat input were used to represent the effect of emission credits.
These emission levels, however, represent emission credits greater than 30
percent. For example, an emission limit of 730 ng S02/J (1.7 Ib SOp/million
Btu) heat input'represents a credit of 42 percent compared to an emission
limit of 516 ng S02/J (1.2 Ib S0?/million Btu) heat input for coal-fired
steam generating units. Similarly, an emission limit of 690 ng S02/J (1.6
Ib S02/million Btu) heat input represents an emission credit of 100 percent
compared to an emission limit of 345 ng S02/J (0.8 Ib S02/million Btu) heat
input for'Oil-fired steam generating units.
An emission credit of 30 percent was used to assess the reasonableness
of emission credits for standards which require a percent reduction in
emissions. For a standard requiring a 90 percent reduction in emissions, a
30 percent emission credit would reduce this percent reduction requirement
to 87 percent. Thus, percent reduction requirements of 90 and 87 percent
were used to assess the reasonableness of emission credits for coal- and
oil-fired cogeneration steam generating units under standards requiring a
percent reduction in emissions.
10-4
-------
As shown in Tables 10-1 and 10-2, the cost effectiveness of SO,, control
for standards based on the use of low sulfur coal are similar for a
conventional industrial-commercial-institutional steam generating unit, a
cogeneration steam generating unit without an emission credit, and a
cogeneration unit with an emission credit. For example, the average cost
effectiveness of SOp emission control in Region V is $454/Mg ($412/ton) for
a conventional steam generating unit, $460/Mg ($417/ton) for a cogeneration
unit without an emission credit, and $340/Mg ($309/ton) of SOp removed for a
cogeneration unit with an emission credit. Similarly, in Region VIII the
average cost effectiveness of emission control is $243/Mg ($221/ton) for a
conventional steam generating unit, $242/Mg ($220/ton) for a cogeneration
unit without an emission credit, and $359/Mg ($326/ton) of SO,, removed for a
cogeneration unit with an emission credit.
The same is true for the cost effectiveness of SOp control for
standards requiring a percent reduction in emissions from coal-fired steam
generating units. The incremental cost effectiveness of SOp emission
control associated with standards requiring a percent reduction in emissions
over standards based on the use of low sulfur fuels in Region V is $961/Mg
($871/ton) for a conventional steam generating unit, $863/Mg ($784/ton) for
( * >
a cogeneration unit without an emission credit, and $819/Mg ($742/ton) of
SO,, removed for a cogeneration unit with an emission credit. Similarly, in
I ^
Region VIII the incremental cost effectiveness of emission control is
$l,314/Mg ($l,192/ton) for a conventional steam generating unit, $l,261/Mg
($l,145/ton) for a cogeneration unit without an emission credit, and $838/Mg
($760/ton) of SOp removed for a cogeneration unit with an emission credit.
As shown in Table 10-3, the incremental cost effectiveness of not
i providing emission credits with standards based on the use of low sulfur
coal is $614/Mg ($556/ton) in Region V and $92/Mg ($83/ton) of S02 removed
in Region VIII. Similarly, the incremental cost effectiveness of not
providing emission credits with standards requiring a percent reduction in
emissions is only $300/Mg ($273/ton) in Region V and $556/Mg ($500/ton) of
SOp removed in Region VIII.
10-5
-------
TABLE 10-1. COST AND COST EFFECTIVENESS OF SO- CONTROL FOR CONVENTIONAL
AND COGENERATION COAL-FIRED STEAM GENERATING UNITS IN REGION Va
o
en
Fuel Type,
ng S02/J
Steam Generating Unit (Ib SO^/milfion Btu)
Conventional Unit, 44 MW (150 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Cogeneration Unit W/0 Credit, 53 MW (180 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 516^ ng/J (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Cogeneration Unit W/Credit, 53 MW (180 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 731 ng/J (1.7 Ib/nillion Btu)e
Percent Reduction (87 Percent)f
904 (2.10)
409 (0.95)
2,384 (5.54)
904 (2.10)
409 (0.95)
2,384 (5.54)
904 (2.10)
624 (1.45)
2,384 (5.54)
Annualized
Costs,
$l,000/yr
8,710
8,990
9,260
10,088
10,430
10,720
10,088
10,230
10,690
Average
Annual Cost
Emissions, Effectiveness,
Mg/yr (tons/yr) $/Mg ($/ton)
1,125 (1,240)
508 (560)
227 (250)
1,352 (1,490)
608 (670)
272 (300)
1,352 (1,490)
934 (1,030)
372 (410)
-
454 (412)
612 (556)
-
460 (417)
585 (531)
340 (309)
614 (558)
Incremental
Cost .
Effectiveness,
$/Mg ($/ton)
-
-
961 (871)
-
-
863 (784)
819 (742)
Based on a capacity factor of 0.9.
Average.,uncontrolled SO- emissions.
°Compared to regulatory baseline.
Compared to low sulfur fuel alternative.
eWith a 30 percent emission credit, a low sulfur coal emission limit of 516 ng SO?/J (1.2 Ib S02/million Btu) would increase to 671 ng S02/J
(1.56 Ib S02/nrillion Btu). Pricing data are not available, however, for a coal capable of meeting this emission limit. Therefore, this
analysis assumed an emission credit of 42 percent in order to use available pricing data for a coal meeting a 731 ng SO^/J (1-7 Ib
S0,/million Btu) emission limit.
f '
Based on a 30 percent emission credit.
TJ
Ol
-------
o
i
TABLE 10-2. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL
AND COGENERATION COAL-FIRED STEAM GENERATING UNITS IN REGION VIIIa
Steam Generating Unit
Fuel Type,
ng SO,/J
(Ib S02/milfion Btu)
Annualized
Costs,
$l,000/yr
Annual
Emissions,
Mg/yr (tons/yr)
Average
Cost
Effectiveness,
$/Mg ($/ton)
Incremental
Cost .
Effectiveness,
$/Mg ($/ton)
Conventional Unit, 44 MW (150 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu) 904 (2.10) 6,710 1,125 (1,240)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu) 409(0.95) 6,860 508(560) 243(221)
Percent Reduction (90 Percent) 409 (0.95) 7,480 36 (40) 707 (642) 1,314 (1,192)
Cogeneration Unit W/0 Credit, 53 MW (180 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu) 904 (2.10) 7,680 1,352 (1,490)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu) 409 (0.95) 7,860 608 (670) 242 (220)
Percent Reduction (90 Percent) 409 (0.95) 8,570 . 45 (50) 681 (618) 1,261 (1,145)
Cogeneration Unit W/Credit, 53 MW (180 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 731 ng/J (1.7 Ib/million Btu)e
Percent Reduction (87 Percent)
904 (2.10)
624 (1.45)
409 (0.95)
7,680
7,830
8,560
1,352 (1,490)
934 (1,030)
63 (70)
-
359 (326)
683 (620)
-
.
838 (760)
Based on a capacity factor of 0.9.
Average uncontrolled SO- emissions.
cCompared to regulatory baseline.
Compared to low sulfur fuel alternative.
eWith a 30 percent emission credit, a low sulfur coal emission limit of 516 ng SOp/J (1.2 Ib S02/mil1ion Btu) would increase to 671 ng S02/J
(1.56 Ib SOp/million Btu). Pricing data are not available, however, for a coal capable of meeting this emission limit. Therefore, this
analysis assumed an emission credit of 42 percent in order to use available pricing data for a coal meeting a 731 ng S02/J (1.7 Ib
S0,/million Btu) emission limit.
t <-
Based on a 30 percent emission credit.
Tl
3>
-------
TABLE 10-3. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING
EMISSION CREDITS FOR COAL-FIRED COGENERATION UNITS
REGION V
REGION VIII
Annualized
Cost
$l,000/yr
Annual
Emissions
Mg/yr (tons/yr)
Incremental Cost
Effectiveness
$Mg ($/ton)
Annualized Annual Incremental Cost
Cost Emissions Effectiveness
$l,000/yr Mg/yr (tons/yr) $/Mg ($/ton)
o
i
00
Low Sulfur Coal
With emission credit
Without emission credit
Percent Reduction
With emission credit
Without emission credit
10,230
10,430
10,690
10,720
934 (1,030)
608 (670)
372 (410)
272 (300)
614 (556)
300 (273)
7,830
7,860
8,560
8,570
934 (1,030)
608 (670)
63 (70)
45 (50)
92 (83)
556 (500)
Ol
CO
-------
Table 10-4 summarizes the cost effectiveness of SCL control for
oil-fired steam generating units. For standards based on the use of low
sulfur oil, the average cost effectiveness of SCL control for a conventional
steam generating unit is $562/Mg ($510/ton), compared with $544/Mg '
($494/ton) for a cogeneration steam generating unit without an emission
credit and $487 Mg ($442/ton) of S02 removed for a cogeneration steam
generating unit with an emission credit.
For standards requiring a percent reduction in SCL emissions, the
incremental cost effectiveness of emission control over standards based on
• the use of low sulfur fuel is $275/Mg ($250/ton) for a conventional steam
generating unit, $254/Mg ($231/ton) for a cogeneration unit without an
emission credit, and $506/Mg ($459/ton) of SCL removed for a cogeneration
unit with an emission credit.
As shown in Table 10-5, the incremental cost effectiveness of not
providing emission credits is $640/Mg ($581/ton) for standards based on the
! use of low sulfur fuel and $182/Mg ($167/ton) of SCL removed for standards
! requiring a percent reduction in S0? emissions.
10.1.2 Combined Cycle or Gas Turbine-Based Cogeneration Systems
Combined cycle systems represent another type of cogeneration
technology and consist of a gas turbine which discharges its exhaust into a
steam generating unit. The steam generating unit is used to recover heat
from the gas turbine exhaust. Steam generating units used in combined cycle
systems fall into one of three categories, depending on how much fuel is
fired in the steam generating unit: unfired, supplementary-fired, and
fully-fired.
In the unfired arrangement, all of the heat input to the steam
generating unit is supplied by the gas turbine exhaust. In the
supplementary-fired arrangement, the gas turbine exhaust provides
approximately 70 percent of the heat input to the steam generating unit,
with the remaining 30 percent being supplied by the fuel fired in the steam
generating unit. In the fully-fired arrangement, the gas turbine exhaust
10-9
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TABLE 10-4. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL
AND COGENERATION OIL-FIRED STEAM GENERATING UNITS3
O
i
Steam Generating Unit (Ib
Conventional Unit, 44 MW (150 million Btu/hr)
Regulatory Baseline, 1,291 ng/J (3.0 Ib/million Btu)
Low Sulfur Oil, 344 ng/J (0.8 Ib/million Btu)e
Percent Reduction (90 Percent)
Cogeneration Unit W/0 Credit, 53 MW (180 million Btu/hr)
Regulatory Baseline, 1,291 ng/J (3.0 Ib/million Btu)
Low Sulfur Oil, 344 ng/J (0.8 Ib/million Btu)e
Percent Reduction (90 Percent)
Cogeneration Unit W/Credit, 53 MW (180 million Btu/hr)
Regulatory Baseline, 1,291 ng/J (3.0 Ib/million Btu)
Low Sulfur Oil, 688 ng/J (1.6 Ib/million Btu)f
Percent Reduction (87 Percent)9
Fuel Type,
ng SO-/J
S02/milfion Btu)
1,291 (3.0)
1,291 (3.0)
1,291 (3.0)
1,291 (3.0)
1,291 (3.0)
1,291 (3.0)
1,291 (3.0)
688 (1.6)
1,291 (3.0)
Annual i zed
Costs,
$l,000/yr
"7,190
7,860
7,940
8,490
9,270
9,360
8,490
8,930
9,350
Average
Annual Cost
Emissions, Effectiveness,0
Mg/yr (tons/yr) $/Mg ($/ton)
1,606 (1,770)
413 (455)
122 (135)
1,932 (2,130)
499 (550)
145 (160)
1,932 (2,130)
1,030 (1,135)
200 (220)
562 (510)
505 (459)
544 (494)
487 (442)
487 (442)
497 (450)
Incremental
Cost .
Effectiveness,
$/Mg (S/ton)
-
275 (250)
-
254 (231)
506 (459)
aAssumes a capacity factor of 0.9.
Average uncontrolled SO- emissions.
GCompared to regulatory baseline.
Compared to low sulfur fuel alternative.
eLess expensive to fire a high sulfur oil [1,291 ng SO-/J (3 Ib S0?/million Btu)] and install an FGD system to achieve 73 percent reduction
than to purchase a low sulfur oil [344 ng SO,/J (0.8 7b S0,/million Btu)].
f
With a 30 percent emission credit, a low sulfur oil emission limit of 344 ng SO-/J (0.8 Ib S02/million Btu) would increase to 447 ng S02/J
1.04 Ib S02/million Btu. Pricing data are not available, however, for an oil capable of meeting this emission limit. Therefore, this
analysis assumed an emission credit of 100 percent in order to use available pricing data for an oil meeting a 688 ng SO-/J (1.6 Ib
S02/million Btu) emission limit.
"Based on a 30 percent emission credit.
TJ
CD
-------
.£62.
TABLE 10-5. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING
EMISSION CREDITS FOR OIL-FIRED COGENERATION UNITS
Annualized Annual Incremental Cost
Cost Emissions Effectiveness
$l,000/yr Mg/yr (tons/yr) $/Mg ($/ton)
Low Sulfur Oil
With emission credit 8,930
Without emission credit 9,270e
1,030 (1,135)
499 (550)a
640 (581)
Percent Reduction
With emission credit
Without emission credit
9,350
9,360
200 (220)
145 (160)
-
182 (167)
aBased on firing a high sulfur oil [1,291 ng S02/J (3.0 Ib S02/million Btu)]
and using an FGD system to achieve 73 percent reduction.
10-11
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P.63
provides approximately 25 percent of the heat input to the steam generating
unit, with the remaining 75 percent being supplied by fuel fired in the
steam generating unit.
The steam generating unit in an unfired and supplementary-fired
combined cycle system is typically a modular finned-type heat exchanger. In
a supplementary-fired combined cycle system, a duct burner is generally
located upstream of the heat exchanger. Thermal limitations inherent in
modular-type heat exchangers limit the amount of supplementary fuel fired in
the duct burner. Also, because of potential fouling problems, only clean
fuels such as natural gas or fuel oil are used in supplementary-fired
combined cycle systems.
Fully-fired combined cycle systems employ a conventional steam
generating unit and the firing rate in the steam generating unit is not
restricted by thermal limitations. Sufficient fuel is fired in the steam
generating unit to reduce the oxygen content of the gas turbine exhaust to
approximately 3 percent or less, as is typically achieved in conventional
steam generating units.
To date, as a result of both technical and economic considerations,
both supplementary-fired and fully-fired combined cycle steam generating
units have been constructed to fire either natural gas or fuel oil. Coal
has not been fired in a combined cycle steam generating unit. The
combustion of coal in an atmosphere of 15 percent or less ^oxygen (gas
turbine exhaust) could lead to combustion stability problems. In addition,
the handling, preparation, and firing of coal greatly increase the
complexity and cost of a combined cycle steam generating unit. If coal were
fired in a combined cycle steam generating unit it would be fired in a
fully-fired system, rather than a supplementary-fired system, because of the
fouling and erosion problems that would be experienced by modular heat
exchangers used in supplementary-fired steam generating units.
To assess the reasonableness of emission credits for combined cycle
cogeneration systems, the cost effectiveness of SCL control for combined
cycle steam generating units was analyzed. This analysis compared the cost
effectiveness of SOp control between conventional steam generating units,
10-12
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P.64
combined cycle steam generating units without emission credits, and combined
cycle steam generating units with emission credits. In addition, the
incremental cost effectiveness of SO,, control as a result of not providing
emission credits for combined cycle steam generating units examined.
As mentioned earlier, the typical cogeneration system operates at a
much higher capacity factor than the typica'i conventional steam generating
unit. Consequently, as In the analysis of emission credits for steam-based
cogeneration discussed above, a capacity factor of 0,9 used in
the analysis of emission credits for combined cycle cogeneration systems.
The emission credit for each type of combined cycle system on
the of heat provided by the gas turbine exhaust to the
generating unit. The magnitude of the emission credit, therefore,
determined by dividing the total heat input to the steam generating unit,
(i.e., gas turbine exhaust; plus fuel fired in the generating unit) by
the heat input to the steam generating unit provided by the fuel fired in
the steam generating unit. For fully-fired combined cycle systems, the
emission credit is in the range of 30 to 35 percent, depending on whether
coal or oil is the fuel fired in the steam generating unit. For
supplementary-fired combined cycle systems, the emission credit, is
greater 200 percent, because most, of the heat input to the steam
generating unit in this type of combined cycle system is provided by the yas
turbine exhaust.
As in the analysis discussed above for steam-based cogeneration
systems, however, these emission credits were increased in several cases to
reflect the fuel pricing available. As a result, the analysis of the
reasonableness of emission credits for combined cycle systems under
standards based on the use of low sulfur fuel actually examined emission
credits of 42 percent for fully-fired combined cycle systems using coal, IOC1
percent for fully-fired combined cycle systems using oil, and 275 percent
for supplementary-fired combined cycle systems using oil. For standards
requiring a percent reduction in S0,? emissions, the actual emission credits
examined 40 percent for fully-fired combined cycle systems using coal,
-------
P. 65
30 percent for fully-fired combined cycle systems using oil, and 215 percent
for supplementary-fired combined cycle systems using oil.
Tables 10-6 and 10-7 summarize the cost effectiveness of SOp control
for a fully-fired coal-fired combined cycle steam generating unit. For
standards based on the use of low sulfur fuel, the average cost
effectiveness of SO,, control in Region V is $456/Mg ($413/ton) for both a
conventional steam generating unit and a combined cycle steam generating
unit without an emission credit. For a combined cycle steam generating unit
with an emission credit, the average cost effectiveness is $339/Mg
($308/ton) of S02 removed. In Region VIII, the average cost effectiveness
of SOp control for both a conventional steam generating unit and a combined
cycle steam generating unit without an emission credit is $216/Mg
($196/ton). For a combined cycle steam generating unit with an emission
credit, the average cost effectiveness of SOp control is $381/Mg ($346/ton).
^ i
For standards which require a percent reduction in SOp emissions, the
incremental cost effectiveness of SOp control over standards based :on the
use of low sulfur fuels in Region V is $l,264/Mg ($l,150/ton) fojr a
conventional steam generating unit, $l,429/Mg ($l,300/ton) for a combined
cycle steam generating unit without an emission credit, and $l,207/Mg
($l,094/ton) of SOp removed for a combined cycle steam generating unit with
an emission credit. In Region VIII the incremental cost effectiveness of
SOp control is $l,521/Mg ($l,382/ton) for a conventional steam generating
unit, $l,618/Mg ($l,471/ton) for a combined cycle steam generating unit
without an emission credit, and $l,019/Mg ($925/ton) of SOp removed for a
combined cycle steam generating unit with an emission credit.
The incremental cost effectiveness of not providing an emission credit
for fully-fired coal combined cycle systems is shown in Table 10-8. For
standards based on the use of low sulfur coal, the incremental cost
effectiveness is $608/Mg ($550/ton) of SOp removed in Region V. In Region
VIII the incremental cost effectiveness of not providing an emission credit
is $0/Mg ($0/ton) of S0? removed. Although SOp emissions increase as a
result of providing an emission credit, costs do not decrease and, as a
result, the incremental cost effectiveness of not providing an emission
10-14
-------
o
I
TABLE 10-6. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL
AND COMBINED CYCLE STEAM GENERATING UNITS IN REGION Va
Fully-Fired Coal
Steam Generating Unit
Fuel Type,
ng SO-/J
(Ib S0?/minion Btu)
Annualized
Costs ,
$l,000/yr
Annual
Emissions,
Mg/yr (tons/yr)
Average
Cost
Effectiveness,
$/Mg ($/ton)
Incremental
Cost
Effectiveness,
$/Mg ($/ton)
Conventional Unit, 29 MW (100 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu) 904 (2.10) 2,430 753 (830)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu) 409 (0.95) 2,620 336 (370) 456 (413)
Percent Reduction (90 Percent) 2,384 (5.54) 2,850 154 (170) 701 (636) 1,264 (1,150)
Combined Cycle Unit W/0 Credit, 40 MW (137 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu) 904 (2.10) 2,430 753 (830)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu) 409 (0.95) 2,620 336 (370) 456 (413)
Percent Reduction (90 Percent) 2,384 (5.54) 2,880 154 (170) 751 (682) 1,429 (1,300)
Combined Cycle Unit W/Credit, 40 MW (137 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu) 904 (2.10) 2,430 753 (830)
Low Sulfur Coal, 731 ng/J (1.7 Ib/million Btu)f 624 (1.45) 2,510 517 (570) 339 (308)
Percent Reduction (86 Percent)9 2,384 (5.54) 2,860 227 (250) 817 (741) 1,207 (1,094)
Based on a capacity factor of 0.9.
Average uncontrolled S02 emissions.
GAnnual cost only includes cost of fuel fired plus annualized cost of SO- control device and does not include other steam generating
unit operating and maintenance costs or annualized cost of the steam generating unit.
Compared to regulatory baseline.
eCompared to low sulfur fuel alternative.
Based on the heat input supplied by the gas turbine exhaust. Credit is calculated as 137/100, or 37 percent. This would translate into an
emission limit of 706 ng SO-/J (1.64 Ib S02/million Btu). Pricing data are not available, however, for a coal capable of meeting this
emission limit. Therefore, this analysis assumed an emission credit of 42 percent in order to use available pricing data for a coal
meeting a 731 ng S02/J (1.7 Ib S02/million Btu) emission limit.
"Based on a 40 percent emission credit.
O)
CD
-------
o
I
TABLE 10-7. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL
AND COMBINED CYCLE STEAM GENERATING UNITS IN REGION VIII3
Fully-Fired Coal
Fuel Type,
ng S02/J
Steam Generating Unit (Ib S02/milTion Btu)
Conventional Unit, 29 MW (100 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Combined Cycle Unit W/0 Credit, 40 MW (137 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 516 ng/J (1.2 Ib/million Btu)
Percent Reduction (90 Percent)
Combined Cycle Unit W/Credit, 40 MW (137 million Btu/hr)
Regulatory Baseline, 1,076 ng/J (2.5 Ib/million Btu)
Low Sulfur Coal, 731 ng/J (1.7 Ib/million Btu)f
Percent Reduction (86 Percent)9
904 (2.10)
409 (0.95)
409 (0.95)
904 (2.10)
409 (0.95)
409 (0.95)
904 (2.10)
624 (1.45)
409 (0.95)
Annual ized
Costs0,
$l,000/yr
1,010
1,100
1,570
1,010
1,100
1,600
1,010
1,100
1,590
Annual
Emissions,
Mg/yr (tons/yr)
753 (830)
336 (370)
27 (30)
753 (830)
336 (370)
27 (30)
753 (830)
517 (570)
36 (40)
Average
Cost .
Effectiveness,
$/Mg ($/ton)
-
216 (196)
771 (700)
-
216 (196)
813 (738)
381 (346)
809 (734)
Incremental
Cost
Effectiveness,
$/Mg ($/ton)
-
-
1,521 (1,382)
-
-
1,618 (1,471)
1,019 (925)
Based on a capacity factor of 0.9.
Average uncontrolled SO,, emissions.
cAnnual cost only includes cost of fuel fired plus annualized cost of S0« control device and does not include other steam generating
unit operating and maintenance costs or annualized cost of the steam generating unit.
Compared to regulatory baseline.
eCompared to low sulfur fuel alternative.
Based on the heat input supplied by the gas turbine exhaust. Credit is calculated as 137/100, or 37 percent. This would translate into an
emission limit of 706 ng SO~/J (1.64 Ib S02/million Btu). Pricing data are not available, however, for a coal capable of meeting this
efore, this analysis assumed an emission credi
emission limit. Therefore,
meeting a 731 ng S02/J (1.7 Ib S02/million Btu) emission limit.
^Based on a 40 percent emission credit.
credit of 42 percent in order to use available pricing data for a coal
-------
TABLE 10-8. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING
EMISSION CREDITS FOR COMBINED CYCLE UNITS
Fully-Fired Coal
REGION V
REGION VIII
Annual ized
Cost
$l,000/yr
Annual
Emissions
Mg/yr (tons/yr)
Incremental Cost
Effectiveness
$/Mg ($/ton)
Annual ized
Cost
$l,000/yr
Annual
Emissions
Mg/yr (tons/yr)
Incremental Cost
Effectiveness
$/Mg ($/ton)
o
Low Sulfur Coal
With emission credit 2,510
Without emission credit 2,620
Percent Reduction
With emission credit 2,860
Without emission credit 2,880
517 (570)
336 (370)
227 (250)
154 (170)
608 (550)
274 (250)
1,100
1,100
1,590
1,600
517 (570)
336 (370)
36 (40)
27 (30)
0 (0)
1,111 (1,000)
•o
»
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P.69
credit is $0/Mg ($0/ton). For standards requiring a percent reduction in
emissions, the incremental cost effectiveness of not providing an emission
credit is $274/Mg ($250/ton) in Region V and $l,lll/Mg ($l,000/ton) of S02
removed in Region VIII.
Table 10-9 summarizes the cost effectiveness of SCL control for fully-
fired and supplementary-fired oil-fired combined cycle systems. For
standards based on the use of low sulfur fuels, the average cost
effectiveness of S(L control is $705/Mg ($640/ton) for a conventional steam
generating unit, $705/Mg ($640/ton) for a fully-fired combined cycle steam
generating unit without an emission credit, and $502/Mg ($455/ton) of SOp
removed for a fully-fired combined cycle steam generating unit with an
emission credit. For standards requiring a percent reduction in SCL
emissions, the incremental cost effectiveness of S0? control over standards
based on the use of low sulfur fuels is $48/Mg ($44/ton) for a conventional
steam generating unit, $144/Mg ($130/ton) for a fully-fired combined cycle
steam generating unit without an emission credit, and $691/Mg ($628/ton) of
SOp removed for a fully-fired combined cycle steam generating unit with an
emission credit.
The cost effectiveness of SCL control is generally higher for
supplementary-fired combined cycle steam generating units than for
fully-fired combined cycle steam generating units, particularly in the case
of standards requiring a percent reduction in SOp emissions, regardless of
whether or not emission credits are provided. As shown in Table 10-9, for
standards based on the use of low sulfur fuels the average cost
effectiveness of SCL control is $705/Mg ($640/ton) for a supplementary-fired
combined cycle steam generating unit without an emission credit, and $0/Mg
($0/ton) of S02 removed for a supplementary-fired steam generating unit with
an emission credit. With an emission credit, the credit is so large that no
emission reduction is required beyond the regulatory baseline. As a result,
the cost effectiveness is $0/Mg ($0/ton) of SOp removed.
For standards requiring a percent reduction in S0? emissions, the
incremental cost effectiveness of SO,, control over standards based on the
use of low sulfur fuels is $l,779/Mg ($l,609/ton) for a supplementary-fired
10-18
-------
TABLE 10-9. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL
AND COMBINED CYCLE OIL-FIRED STEAM GENERATING UNITS3
o
Steam Generating Unit
Conventional Unit, 29 HW (100 million Btu/hr)
Regulatory Baseline, 1.291 ng/J (3.0 Ib/nllllon Btu)
Lot) Sulfur Oil, 344 ng/J (0.8 Ib/mllllon Btu)
Percent Reduction (90 Percent)
Fuel Type.b
ng SO./J
(Ib S02/mil1ion Btu)
1,291 (3.0)
344 (0.8)
1,291 (3.0)
Annual ized
Costsc,
Jl.OOO/yr
3,890
4,440
4.450
Annual
Emissions,
Mg/yr (tons/yr)
1.070 (1.180)
290 (320)
82 (90)
Average
Cost H
Effectiveness.
$/Hg ($/ton)
-
705 (640)
567 (514)
Incremental
Cost
Effectiveness.
$/Hg ($/ton)
-
.
48 (44)
Fully-Fired
Combined Cycle Unit H/0 Credit, 38 MU (129 million Btu/hr)
Regulatory Baseline, 1.291 ng/J (3.0 Ib/mllllon Btu) 1,291 (3.0)
Low Sulfur Oil. 344 ng/J (0.8 Ib/mllllon Btu) 344 (0.8)
Percent Reduction (90 Percent) 1,291 (3.0)
Combined Cycle Unit W/Credlt, 38 HW (129 million Btu/hr)
Regulatory Baseline. 1.291 ng/J (3.0 Ib/million Btu) 1,291 (3.0)
Low Sulfur Oil. 688 ng/J (1.6 Ib/million 8tu)f 688 (1.6)
Percent Reduction (87 Percent)9 1.291 (3.0)
Supplementary-F1red
Combined Cycle Unit H/0 Credit. 92 HW (313 million Btu/hr)
Regulatory Baseline, 1.291 ng/J (3.0 Ib/mllllon Btu) 1.291 (3.0)
Low Sulfur Oil. 344 ng/J (0.8 Ib/mllllon Btu) 344 (0.8)
Percent Reduction (90 Percent) ~ 1.291 (3.0)
Combined Cycle Unit H/Credit. 92 MM (313 million Btu/hr)
Regulatory Baseline, 1.291 ng/J (3.0 Ib/million Btu) 1.291 (3.0)
Low Sulfur Oil. 1,291 ng/J (3.0 Ib/million Btu)h 1.291 (3.0)
Percent Reduction (69 Percent)1 1,291 (3.0)
3.890
4,440
4,470
3,890
4,140
4.460
1,070 (1.180)
290 (320)
82 (90)
1.070 (1,180)
572 (630)
109 (120)
-
705 (640)
587 (532)
_
502 (455)
593 (538)
3,890 1.070 (1.180)
4.440 290 (320) 705 (640)
4.810 82 (90) 931 (844)
3.890 1,070 (1.180)
3,890 1,070 (1.180) 0 (0)
4,740 299 (330) 1.102 (1,000)
144 (130)
691 (628)
1.779 (1.609)
1.102 (1.000)
'Based on a capacity factor of 0.9.
Average uncontrolled S0; emissions.
cArmuaI cost only Includes cost of fuel fired plus annual(zed cost of SO. control device and does not include other steam generating unit
operating and maintenance costs or annualized cost of the steam generating unit.
Compared to regulatory baseline.
eCompared to low sulfur fuel alternative.
Based on the heat input supplied by the gas turbine exhaust. Credit Is calculated as 129/100. or 29 percent. This would translate into an
emission limit of 443 ng SO./J (1.03 Ib SO./milllon Btu). Pricing data are not available, however, for an oil capable of meeting this
emission limit. Therefore, this analysis assumed an emission credit of 100 percent in order to use available pricing data for an oil
meeting a 688 ng S02/J (1.6 Ib SOg/million Btu) emission limit.
'Based on a 30 percent emission credit.
'Based on the heat Input supplied by the gas turbine exhaust. Credit Is calculated as 313/100, or 213 percent. This would translate Into an
emission licit of 1.076 ng SO./J (3.5 Ib SO./nlllion Btu). Pricing data are not available, however, for an oil capable of meeting this
emission limit. Therefore, tnis analysis assumed an emission credit of 275 percent in order to.use available pricing data for an oil meeting
a 1.291 ng SO?/J (3.0 Ib SO^/million Btu) emission limit.
Based on a 210 percent emission credit.
h,
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P.71
steam generating unit without an emission credit, and $l,102/Mg ($l,000/ton)
of SCL removed for a supplementary-fired steam generating unit with an
emission credit.
As discussed earlier, in a supplementary-fired combined cycle steam
generating unit the heat input of the gas turbine exhaust represents about
70 percent of the total heat input to the steam generating unit.
Consequently, assuming the gas turbine fires natural gas, the gas turbine
exhaust acts as a diluent, significantly increasing the volume of the flue
gases from the steam generating unit without increasing the SCL emissions
contained in these flue gases. In a fully-fired combined cycle system, the
heat input of the gas turbine exhaust only represents about 30 percent of
the total heat input to the steam generating unit and the diluent effect of
the gas turbine exhaust is not as significant. Consequently, assuming the
gas turbine fires natural gas, the cost effectiveness of S02 control is
higher for supplementary-fired combined cycle steam generating units than
for fully-fired combined cycle steam generating units.
If, however, the analysis assumed that oil was combusted in the gas
turbine, rather than natural gas, the difference in the cost effectiveness
of S02 control between supplementary-fired and fully-fired combined cycle
steam generating units would narrow. If, for example, the analysis assumed
oil of the same sulfur content was combusted in the gas turbine as in the
steam generating unit (which probably represents a more realistic
assumption) there would be no difference in the cost effectiveness of SO^
control between supplementary-fired and fully-fired combined cycle steam
generating units, other than that which might exist due to economies of
scale.
Because the analysis kept the heat input from the fuel fired in the
steam generating unit constant, the supplementary-fired steam generating
unit is much larger than the fully-fired steam generating unit. As a
result, under standards requiring a percent reduction in S0? emissions, the
analysis would indicate that the cost effectiveness of S02 control is lower
for a supplementary-fired combined cycle steam generating unit than for a
fully-fired combined cycle steam generating unit due to economies of scale.
10-20
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P.72
Table 10-10 summarizes the incremental cost effectiveness of S02
control associated with not providing emission credits for fully-fired and
supplementary-fired combined cycle steam generating units firing oil. For
standards based on the use of low sulfur fuels, the incremental cost
effectiveness of S02 control is $l,064/Mg ($968/ton) for a fully-fired steam
generating unit and $705/Mg ($640/ton) of S02 removed for a
supplementary-fired steam generating unit. For standards requiring a
percent reduction in S02 emissions, the incremental cost effectiveness of
not providing emission credits is $370/Mg ($333/ton) for a fully-fired steam
generating unit and $323/Mg ($292/tbn) of S02 removed for a supplementary-
fired steam generating unit.
10.2 MIXED FUEL-FIRED STEAM GENERATING UNITS
The S02 emissions resulting from the combustion of nonsulfur-bearing
fuels, such as wood, municipal solid waste, natural gas, and agricultural
waste products, are negligible. As a result, SCu emissions from mixed'
fuel-fired steam generating units are lower than S02 emissions from coal- or
oil-fired steam generating units operating at the same heat input.
It has been suggested, therefore, that an emission credit should be
included in new source performance standards for mixed fuel-fired steam
generating units. Such an emission credit would permit higher S(L emission
levels from mixed fuel-fired steam generating units by including the heat
input supplied by the nonsulfur-bearing fuel in determining compliance with
the standards. The magnitude of the credit would vary with the amount'of
heat input provided by the nonsulfur-bearing fuel.
As discussed above under "Consideration of Demonstrated Emission
Control Technology Costs," to. comply with a standard based on the use of low
sulfur fuel, a fossil fuel-fired steam generating unit would be required to
fire a low sulfur fuel or install an FGD system to reduce S02 emissions.
Because of the dilution of the S02 emissions resulting from combustion of a
fossil fuel with the gases resulting from combustion of a nonsulfur-bearing
fuel, a mixed fuel-fired steam generating unit would not be required to fire
10-21
-------
TABLE 10-10. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR OIL-FIRED COMBINED CYCLE STEAM GENERATING UNITS
Annual!zed Annual Incremental Cost
Cost Emissions Effectiveness
$l,000/yr Mg/yr (tons/yr) $/Mg ($/ton)
Fully-Fired
Low Sulfur Oil
With emission credit 4,140
Without emission credit 4,440
Percent Reduction
With emission credit 4,460
Without emission credit 4,470
Supplementary-Fired
Low Sulfur Oil
With emission credit 3,890
Without emission credit 4,440
Percent Reduction
With emission credit 4,740
Without emission credit 4,810
572 (630)
290 (320)
109 (120)
82 (90)
1,070 (1,180)
290 (320)
299 (330)
82 (90)
1,064 (968)
370 (333)
705 (640)
323 (292)
10-22
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P.74
a low sulfur fuel or install an FGD system to reduce SCL emissions if an
emission credit is provided.
If, for example, a standard based on the use of low sulfur fuels
limited S(L emissions from coal combustion to 516 ng SOp/J (1.2 Ib
SOp/million Btu), a coal-fired steam generating unit would be required to
fire a low sulfur coal or install an FGD system to reduce SO,, emissions to
this level. A mixed fuel-fired steam generating unit firing a 50/50 mixture
of coal and a nonsulfur-bearing fuel on a heat input basis, however, would
only have to fire a medium sulfur coal containing 1032 ng SO^/J (2.4 Ib
SOp/million Btu) or less to comply with this emission limit if an emission
credit is provided for the heat input supplied by the nonsulfur-bearing
fuel. Only if an emission credit is not provided for the heat input
supplied by the nonsulfur-bearing fuel, would the mixed fuel-fired steam
generating unit also be required to fire a low sulfur coal or install an FGD
system to reduce S02 emissions.
A similar situation arises with a standard requiring a percent
reduction in SOp emissions. A fossil fuel-fired steam generating unit would
be required to achieve whatever specific percent reduction requirement is
included in such a standard. With an emission credit, however, a mixed
fuel-fired steam generating unit would not be required to achieve the
specific percent reduction requirement, but would be permitted to achieve a
lower percent reduction requirement.
If, for example, a standard included a requirement to achieve a 70
percent reduction in SOp emissions, a mixed fuel-fired steam generating unit
firing a 50/50 mixture of coal and a nonsulfur-bearing fuel would only be
required to achieve a 40 percent reduction in S02 emissions. If, on the
other hand, a standard required a 90 percent reduction in S02 emissions,
this mixed fuel-fired steam generating unit would only be required to
achieve an 80 percent reduction in S02 emissions.
To assess the reasonableness of emission credits for mixed fuel-fired
steam generating units, the cost effectiveness of S02 control for these
units was analyzed. This analysis compared the cost effectiveness of S02
control for mixed fuel-fired steam generating units without emission credits
10-23
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P.75
and the cost effectiveness of these same units with emission credits. In
addition, the incremental cost effectiveness of SOp control associated with
not providing emission credits for mixed fuel-fired steam generating units
was also examined.
The results of this analysis are summarized in Table 10-11 for mixed
fuel-fired steam generating units firing coal and Table 10-12 for mixed
fuel-fired steam generating units firing oil. In both cases, costs are
presented only for a 44 MW (150 million Btu/hour) heat input capacity mixed
fuel-fired steam generating unit firing a 20 percent coal or oil/80 percent
nonsulfur-bearing fuel mixture. Larger mixed fuel-fired steam generating
units were examined, as well as fuel mixtures with a higher percentage of
coal or oil. This combination, however, results in the largest emission
credit as well as the highest cost effectiveness of S0« control. Other
cases involving either larger mixed fuel-fired steam generating units or a
higher coal or oil content in the fuel mixture result in lower emission.
credits and a lower cost effectiveness of S02 control. The results for
Region X are also presented for mixed fuel-fired units firing coal because,
of the three regions examined where mixed fuel-fired steam generating units
are expected to be constructed in significant numbers, the projected coal
prices in Region X result in the highest cost effectiveness of S0~ control.
As shown in Table 10-11, the average cost effectiveness of S02 control
for standards based on the use of low sulfur coal is $l,098/Mg ($989/ton)
for a mixed fuel-fired steam generating unit without an emission credit and
$0/Mg ($0/ton) for a mixed fuel-fired steam generating unit with an emission
credit. For a mixed fuel-fired steam generating unit with an emission
credit, a coal with a sulfur content of 904 ng SO?/J (2.10 Ib S0?/million
Btu) is combusted under both the regulatory baseline and a standard based on
the use of low sulfur coal. With an emission credit, therefore, a standard
based on the use of low sulfur coal results in no emission reduction.
The average cost effectiveness of S0? control for standards requiring a
percent reduction in emissions is $2,568/Mg ($2,333/ton) for a mixed
fuel-fired steam generating unit without an emission credit and $4,241/Mg
($3,895/ton) of SOp removed for the same unit with an emission credit.
10-24
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TABLE 10-11. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR MIXED FUEL-FIREO STEAM GENERATING UNITS FIRING COAL
o
1
f\>
cr.
Steam Generating Unit/Regulatory Alternative
Mixed Fuel-Fired Unit Without Credit (44 MW)a
Regulatory Baseline - 1075 ng S02/J (2.5 Ib S02/million Btu)b
Low Sulfur Fuel - 516 ng S02/J (1.2 Ib S02/million Btu)
Percent Reduction - 90 percent
Mixed Fuel-Fired Unit With Credit (44 MW)a
Regulatory Baseline - 1075 ng S02/J (2.5 Ib S02/million Btu)b
Low Sulfur Fuel - 516 ng S02/J (1.2 Ib S02/million Btu)
Percent Reduction - 50 percentc
Fuel Type
ng SO,/J
(Ib S02/milfion Btu)
904 (2.1)
409 (0.95)
904 (2.1)
904 (2.1)
904 (2.1)
904 (2.1)
Annual ized
Costs
$1 ,000/yr
3,587
3,677
3,944
3,587
3,587
3,922
Annual
Emissions
, Mg/yr
(tons/yr)
151 (166)
68 (75)
12 (13)
151 (166)
151 (166)
72 (80)
Average
Cost
Effectiveness
$/Mg
($/ton)
-
1,098 (989)
2,568 (2,333)
-
0(0)
4,241 (3,895)
Incremental
Cost
Effectiveness
$/Mg
($/ton)
-
-
4,684 (4,306)
-
-
4,241 (3,895)
aResults are for a 44 MW (150 million Btu/hr) mixed fuel-fired steam generating unit firing an 80 percent nonsulfur-bearing fuel/20 percent coal
mixture in Region X.
Emission credits are allowed in the regulatory baseline, reflecting existing standards and practice.
cFor this fuel mixture, only 50 percent SO,, reduction is required with an emission credit to meet a 90 percent reduction requirement.
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TABLE 10-12. COST AND COST. EFFECTIVENESS OF S02 CONTROL FOR MIXED FUEL-FIRED STEAM GENERATING UNITS FIRING OIL
o
i
Gi
Steam Generating Unit/Regulatory Alternative
Mixed Fuel-Fired Unit Without Emission Credit (44 MW)a
Regulatory Baseline - 1290 ng S02/J (3.0 Ib S02/million Btu)b
Low Sulfur Fuel - 344 ng S02/J (0.8 Ib S02/million Btu)
Percent Reduction - 90 percent
Mixed Fuel-Fired Unit With Emission Credit (44 MW)a
Regulatory Baseline - 1290 ng S02/J (3.0 Ib S02/mi 1 1 i on Btu)b
Low Sulfur Fuel - 344 ng S02/J (0.8 Ib S02/million Btu)
Percent Reduction - 50 percent0
Fuel Type
ng SOp/J
(Ib S02/milfion Btu)
1,290 (3.0)
344 (0.8)
1,290 (3.0)
1,290 (3.0)
1,290 (3.0)
1,290 (3.0)
Annual ized
Costs
$l,000/yr
3,713
3,821
4,041
3,713
3,713
4,002
Annual
Emissions
Mg/yr
(tons/yr)
215 (237)
57 (63)
17 (19)
215 (237)
215 (237)
103 (114)
Average
Cost
Effectiveness
$/Mg
($/ton)
-
684 (621)
1,657 (1,505)
-
0 (0)
2,580 (2,350)
Incremental
Cost
Effectiveness
$/Mg
($/ton)
-
-
5,500 (5,000)
-
-
2,580 (2,350)
aResults are for a 44 MW (150 million Btu/hr) mixed fuel-fired steam generating unit firing an 80 percent nonsulfur-bearing fuel/20 percent oil
mixture in Region I.
Emission credits are allowed in the regulatory baseline, reflecting existing standards and practice.
cFor this fuel mixture, only 50 percent S02 reduction is required with an emission credit to meet a 90 percent reduction requirement.
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P.78
The incremental cost effectiveness of SOp emission control associated
with standards requiring a percent reduction in emissions over standards
based on the use of low sulfur coal is $4,684/Mg ($4,306/ton) for a mixed
fuel-fired steam generating unit without an emission credit and $4,241/Mg
($3,895/ton) of SOp removed for a mixed fuel-fired steam generating unit
with an emission credit. As shown in Table 10-13, the incremental cost
effectiveness of not providing emission credits for mixed fuel-fired steam1
generating units under a standard based on the use of low sulfur coal is
$l,084/Mg ($989/ton) of S02 removed. Similarly, the incremental cost
effectiveness of not providing emission credits under a standard requiring a
percent reduction in emissions is $367/Mg ($328/ton) of SO,, removed.
Table 10-12 summarizes the cost effectiveness of SOp control for mixed
fuel-fired steam generating units firing oil as the fossil fuel. Mixed
fuel-fired steam generating units were only examined for Region I because
the sulfur premium for low sulfur oil compared to a high sulfur oil is
essentially constant for all regions. For a standard based on the use of
low sulfur oil, the average cost effectiveness of SOp control for a mixed
fuel-fired steam generating unit without an emission credit is $684/Mg
($621/ton) compared to $0/Mg ($0/ton) of SOp removed for the same unit with
an emission credit. As in the analysis discussed above for mixed fuel-fired
steam generating units firing coal, including an emission credit, in a
standard based on the use of low sulfur fuel results in no emission
reduction. With an emission credit, a high sulfur oil is fired under both
the regulatory baseline and a standard based on the use of low sulfur oil.
The average cost effectiveness of SO,, control for standards requiring a
percent reduction in emissions is $l,657/Mg ($l,505/ton) for a mixed
fuel-fired steam generating unit without an emission credit and $2,580/Mg
($2,350/ton) of SOp removed for the same unit with an emission credit.
The incremental cost effectiveness of S02 emission control associated
with standards requiring a percent reduction in emissions over standards -
based on the use of low sulfur oil is $5,500/Mg ($5,000/ton) for a mixed
fuel-fired steam generating unit without an emission credit and $2,580/Mg;
($2,350/ton) of SOp removed for a mixed fuel-fired steam generating unit
10-27
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TABLE 10-13. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR MIXED FUEL-FIRED STEAM GENERATING UNITS FIRING COAL3
Low Sulfur Coal
With Emission Credit
Without Emission Credit
Percent Reduction
With Emission Credit
Without Emission Credit
Annual ized
Cost
$l,000/yr
3,587
3,677
3,922
3,944
Annual
Emissions
Mg/yr
(tons/yr)
151 (166)
68 (75)
72 (80)
12 (13)
Incremental
Cost
Effectiveness
$/Mg
($/ton)
-
1>,084 (989)
-
367 (328)
aFor a 44 MW (150 million Btu/hr) heat input capacity mixed fuel-fired steam
generating unit firing a 20 percent coal/80 percent nonsulfur-bearing fuel
mixture in Region X.
10-28
-------
with an emission credit. An emission credit, therefore, appears to reduce
substantially the incremental cost effectiveness of a standard requiring a
percent reduction in SC^ emissions. This is not really the case, however.
This substantially lower incremental cost effectiveness is the result of
including an emission credit in a standard based on the use of low sulfur
oils, not in a standard requiring a percent reduction in SCL emissions*
As mentioned above, with an emissions credit, a standard based on the
use of low sulfur oils results in no S(L emission reduction. Thus,
regardless of whether a standard requiring a percent reduction in S02
emissions includes an emissions credit or not, when compared to this
alternative the large incremental reduction in S02 emissions achieved by any
standard requiring a percent reduction in emissions results in a
substantially lower incremental cost effectiveness.
If, for example, the alternative of a standard requiring a percent
reduction in SCL emissions without an emission credit is compared to the
alternative of a standard based on the use of low sulfur oil with an
emission credit, the resulting incremental cost effectiveness of SCL control
is $l,657/Mg ($l,505/ton) of SCL removed. This is lower than the
incremental cost effectiveness of $2,580/Mg ($2,350/ton) of SCL removed
cited above and shown in Table 10-12 for a standard requiring a percent
reduction in SCL emissions with an emission credit. Thus, the substantially
lower incremental cost effectiveness which may appear to be the result of
including an emission credit in a standard requiring a percent reduction in
SCL emissions is not the result of including an emission credit, but the
result of comparing this alternative to a standard based on the use of low
sulfur oil with an emission credit.
As shown in Table 10-14, the incremental cost effectiveness of not
providing emission credits is $684/Mg ($621/ton) for standards based on the
use of low sulfur oil and $453/Mg ($411/ton) of SOp removed for standards
requiring a percent reduction in S0? emissions.
10-29
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P.81
TABLE 10-14. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION
CREDITS FOR MIXED FUEL-FIRED STEAM GENERATING UNITS FIRING OIL3
Low Sulfur Oil
With Emission Credit
Without Emission Credit
Percent Reduction
With Emission Credit
Without Emission Credit
Annual ized
Cost
$l,000/yr
3,713
3,821
4,002
4,041
Annual
Emissions
(tons/yr)
215 (237)
57 (63)
103 (114)
17 (19)
Incremental
Cost
Effectiveness
($/ton)
-
684 (621)
-
453 (411)
aFor a 44 MW (150 million Btu/hr) heat input capacity mixed fuel-fired steam
generating unit firing a 20 percent oil/80 percent nonsulfur-bearing fuel
mixture in Region I.
10-30
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P.82
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA 450/3-86-005
3. RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE
Summary of Regulatory Analysis -(New
Source Performance Standards for Industrial-Commercial
Institutional Steam Generating Units of Greater Than
29 MW (100 Million Btu/Hour) Heat Input Capacity
5. REPORT^DAJ/
June
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
Radian Corporation
Research Triangle Park,
North Carolina 27709
PERFORMING ORGAf
NIZATtQN NAME AN.D ADDRESS. . . ,
ice of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3816
2. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of A>rr and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/200/04
5. SUPPLEMENTARY NOTES
6. ABSTRACT
This document summarizes the environmental, economic, and cost analyses that were
conducted to support the development of new source performance standards limiting
emissions of S02 from industrial-commercial-institutional steam generating units.
Alternative S02 control technologies and regulatory options are analyzed in terms of
S02 emission reduction capability, costs of control, secondary environmental impacts,
national impacts, and industry-specific economic impacts. In addition, the impacts
of allowing emission credits for cogeneration and mixed fuel-fired steam generating
units are discussed. This document is intended to serve as an overview of the
analyses and regulatory alternatives considered during the standards development
process.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATl l-'iclcJ/Group
Air pollution
Pollution control
Standards of performance
Steam generating units
Fossil fuel-fired
industrial boilers
Mixed fuel-fired
industrial boilers
Cogeneration systems
Air pollution control
13B
18. DISTRIBUTION STATEMENT
Release unlimited.
19. SECURITY CLASS (This Report!
Unclassified
21. NO. OF PAGES
276
20. SECURITY CLASS /This page/
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDI TION i s OBSOLETE
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