EPA 450-1-75-001
r
PB-241 021
REPORT TO CONGRESS ON CONTROL OF SULFUR
OXIDES
Environmental Protection Agency
Prepared for:
Air Pollution Technical Information Center
February 1975
DISTRIBUTED BY:
National Technical Information Service
U. S. DEPARTMENT OF COMMERCE
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4.rirLE
9. PERFORMING ORGANIZATION NAME AND ADDRESS -
U.S. Environmental Protection Agency
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
TECHNICAL REPORT DATA
sr rrail Instructions on the reverse before comi>leiinsl
HI PORT NO.
EPA-450/ -75-001
Report to Congress on Control of Sulfur Oxides
5. REPORT DATE
February 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFOHMING ORGANIZATION REPORT NO.
17. SPONSORING AGENCY NAMh AND ADDRESS
PB 241 021
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
13. TYPE OF REPORT AND PERIOD COVERED.
14. SPONSORING AGENCY CODE
15. -SUPPLEMENTARY NOTES
16 A BST R A CT •
Energy shortages, primarily of oil and natural gas, have increased the importance
of our domestic coal reserves. Although coal is our most abundant source of fossil
fuel energy, its increased use without adequate environmental safeguards could
aggravate the nation's already serious environmental problems. This report focuses
on the compliance status of existing coal-fired steam electric power plants and on
alternative methods for compliance with applicable emission regulations. Compliance
alternatives include the use of low^sulfur coal, physical coal desulfurization, flue-
gas desulfurization, coal gasification, fluidized-bed boilers, supplementary control
systems, and energy recovery from solid waste. A review is presented showing the
current status of existing coal-fired plants in terms of the sulfur content of coal
purchased during the first half of 1974, the involvement of power companies in
litigation challenging the applicable regulations, and the programs for achieving
compliance with sulfur regulations in State Implementation Plans.
17.
KEY WORDS AND DOCUMENT ANALYSIS
Air pollution
Coal
Control technology
Electric power plants
Energy Supply and Environmental
Coordination Act
Flue-gas desulfurization
Fluidlzed-bed boilers
Sulfur dioxide (air pollution)
Sulfur oxides
Supplementary control systems
(air pollution)
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (This Report)
UNCLASSIFIED
20. SECURITY CLASS (This page)
UNCLASSIFIED
21. NO. OF
•• .7
EPA Form 2220-1 (9-73)
I
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EPA-450/1-75-001
REPORT TO CONGRESS
ON
CONTROL OF SULFUR OXIDES
Required by Section 119(k) of
PL 93-319, "Energy Supply and
Environmental Coordination Act
of 1974"
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of A1r and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
February 1975
I fl.
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REVIEW NOTICE
This report has been reviewed by the Office of Air Quality Planning
and Standards, Office of Air and Waste Management, EPA, and approved
for publication. Mention of trade names or commercial products does
not constitute endorsement or recommendation for use.
AVAILABILITY
Copies of this document are available free of charge to Federal
employees, current contractors and grantees, and nonprofit organiza-
tions—as supplies permit—from the Air Pollution Technical Infor-
mation Center, Environmental Protection Agency, Research Triangle
Park, North Carolina 27711. This document is available for sal a
to the public through the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22161.
11
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TABLE OF CONTENTS
Chapter Page
LIST OF TABLES 1v
1. EXECUTIVE SUMMARY 1
Compliance Status, 1974 1
Projected Compliance Status, 1980 1
Compliance Alternatives 3
Factors Affecting Compliance 6
Conclusions 6
2. SCOPE OF REPORT . 7
Impact of Fuel Shortages 7
Pollution Control—Compliance Alternatives 8
Pr1or1t1zat1on of Pollutant Control Technology and Other Issues. 8
Other Requirements 9
3. COMPLIANCE STATUS OF COAL-FIRED POWER PLANTS, 1974 to 1980 ..... 11
Introduction 11
Compliance Status, 1974 11
Conforming Coal by Sulfur Content . 14
Compliance Status Through 1980 ;. 15
The Clean Fuels Policy ... 16
4. COMPLIANCE ALTERNATIVES FOR SULFUR DIOXIDE CONTROL . '. . 17 .
Continuous Strategies 17
Noncontlnuous Strategies . 33
Energy Recovery from Solid Waste . 39
References for Chapter 4 44
5. FACTORS AFFECTING COMPLIANCE . . . 46
Conversions from 011 to Coal by Electric Utility Plants . . . . 46
Coal Requirements in NonutlHty Sectors 48
Coal Requirements for the Electric Utility Industry 49
Use of Allocation Authorities 51
Use of Enforcement Authority 53
TECHNICAL APPENDIX A: STATUS OF LOW- AND INTERMEDIATE-Btu
COAL GASIFICATION SYSTEMS 57
TECHNICAL APPENDIX B: OPERATING SUMMARY FOR FLUE-GAS
DESULFURIZATION SYSTEMS 60
111
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LIST OF TABLES
Table Page
1-1 Coal-fired Power Plant Compliance Status and Alternatives
through 1980 2
1-2 Control Strategy Alternatives 4
3-1 Coal Used in Power Plants, 1974 12
3-2 State Sulfur Regulations Involved in Litigation, 1974 12
3-3 Known Compliance Plans of Plants Not Meeting State
Implementation Plans, 1974 . 14
3-4 1980 Preliminary Estimate for All Coal-fired Plants of Coal
Sulfur Content Requirements or Equivalent Flue-gas
Desulfurizatlon Capacity 15
4-1 Potential Coal Production in 1980 20
4-2 Approximate Distribution of Coals by Coal Type and Washability
of Coals to Equivalent Sulfur Dioxide Emission Levels 25
4-3 Comparison of Various Flue-gas Desulfurization Processes .... 28
4-4 Status of Flue-gas Desulfurization Systems, October 1974 .... 30
4-5 Vendor Capacity for Flue-gas Desulfurization 30
4-6 Thermal Efficiency of Fluidized-bed Boilers . . 33
4-7 Comparative Operating Costs for Conventional and
Fluidized-bed Coal-fired Power Plants 34
4-8 Reliability of Noncontinuous Control System at the Tennessee
Valley Authority's Paradise Steam Plant in Protecting
3-hour and 24-hour Ambient Air Quality Standards 35
5-1 Estimated Coal Demand by Sulfur Content for Steam Electric
Power Plants Reconverting from Oil . 47
5-2 Coal Demand in 1973 by Sector 48
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CHAPTER 1. EXECUTIVE SUMMARY
\
Energy shortages, primarily of oil and natural gas» have Increased
the Importance of our domestic coal reserves. Although coal 1s our most
abundant source of fossil fuel energy, Us Increased use without adequate
environmental safeguards could aggravate the nation's already serious
environmental problems, This report focuses on the compliance status of
existing coal-fired steam electric power plants and on alternative methods
for compliance with applicable emission regulations. 1ft review 1s presented
showing the current status of existing coal-fired plants 1n terms of the
sulfur content of coal purchased during the first half ©f 1974, the Irivolve-
ment of power companies 1n litigation challenging the applicable regulations,
and the programs for achieving compliance with sulfur regulations In State
Implementation Plans. Also discussed are a number of factors whose potential
effect on compliance efforts cannot be accurately predicted.
COMPLIANCE STATUS, 1974
In 1974, nearly 390 million tons of coal was consumed by steam
electric power plants. Half of this coal, 194 million tons, would comply
with sulfur regulations applicable on July 1, 1975. An additional 85
million tons of the coal consumed by power plants was used 1n plants cur-
rently Involved 1n legal actions. Although most of these plants are
technically out of compliance, resolution of their compliance problems
awaits conclusion of litigation. Of the remaining 111 million tons, roughly
40 percent was consumed 1n plants that, although not presently In compliance
with 1975 State emission regulations, have known plans to comply through
the use of flue-gas desulfurlzatlon (15.4 million tons), Substitution of
lower sulfur coal (29.2 million tons), or conversion to oil (1.7 million
tons).
Compliance plans are not yet known for plants that burned the remaining
65 million tons (16 percent) of coal consumed 1n 1974. However, as will
be discussed, sufficient supplies of either lower' sulfur coal or control
systems appear to be available to meet the needs of these plants, as
well as those subject to regulations now under legal challenge, and, thus,
effect compliance before 1980.
PROJECTED COMPLIANCE STATUS. 1980
Table 1-1 summarizes the compliance status of existing and 'new coal-
fired steam electric power plants through 1980. Also shown are projections
of the availability of flue-gas desulfurlzatlon systems* the supplies of
low-sulfur coal that conform to New Source Performance Standards, and
the potential use of supplementary control systems for certain power
1.
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Table 1-1. COAL-FIRED POWER PLANT COMPLIANCE STATUS
AND ALTERNATIVES THROUGH 1980
(million tons of coal)
Compliance
status
Already in
compliance
Legal disputes,
compliance
requirements
unknown
Nonconforming,
plans known
Nonconforming,
plans unknown
New plants,
plans known
New plants,
plans unknown
Total coal
requirements
Existing
plants
1974
194
85
46
65
-
-
390
Total
requirements
in 1980
194
05
46
65
28
207
625
Control
options
not known
-
85
-
65
-
207
357
Potential availability of major compliance
alternatives (excluding coal cleaning) by 1980
Flue-gas desulfurization 250 - 390a
Low-sulfur coal (<1.2 Ib S02/million Btu) 80 - 200b
Supplementary control systems 15 - 35C
Total available 345 - 625
Total required, control option not known 357
aBased on Environmental Protection Agency survey in the fall
of 1974. Estimates have been adjusted to reflect scheduled
installations.
Estimates adjusted downward to reflect low-sulfur coal
consumption 1n 1974.
C0oint study performed by the Environmental Protection Agency
and the Federal Energy Administration during the fall of
1974 showed this value to be 40 - 120. After subtracting out
the plants involved in legal disputes and those having
acceptable compliance plans, the estimate reduces to 15 - 35.
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plants with specific problems. The potential availability of these
options 1s more than adequate to satisfy the requirements of existing and
new steam electric coal-fired power plants for which compliance requirements
or plans are unknown. It should be noted that some factors can limit the
achievement of this potential. These Include legislative constraints,
availability of capital, and uncertainty that long-term demand will
warrant expansion or supply commitments by Industry.
Coal requirements for steam electric power plants are expected to
grow rapidly through 1980. Based on Information developed by the Federal
Power Commission, coal consumption 1s expected to Increase by 60 percent,
approaching 625 million tons 1n 1980. Of this 235-mlllion-tori increase,
approximately 50 million tons will be consumed in plants..that become
operational 1n 1975 or 1976. These plants, in general, will be required
to comply with sulfur regulations 1n State Implementation Plans, but not
with New Source Performance Standards. The remaining 185 million tons
of additional coal requirements 1s associated with plants projected to
be built between 1977 and 1980. Most of these plants will be required ' •
to comply with the New Source Performance Standards.
The rapid growth 1n new coal-fired steam electric capacity will tend
to lower the allowable average sulfur content of steam coal because many
of these plants will be required to meet New Source Performance Standards for
sulfur. The primary options available to ensure conformance with the Mew
Source Performance Standards are either the use of low-sulfur coal or''
the.application of flue-gas desulfurlzatlon systems. Current projections
regarding the availability of these options indicate that they can be
supplied In volumes exceeding projected requirements* Estimates of the
availability of low-sulfur coal by 1980 range from 80 to 200 million
tons, and the capacity of vendors to Install flue-gas desiilfurization
systems, based on recent surveys, is between 250 and 390 million tons.
COMPLIANCE ALTERNATIVES
The major compliance alternatives through 1980 are the application
of flue-gas desulfurlzatlon systems, the use of coal with the appropriate
sulfur content, and the application of supplementary control systems . ' V
(for plants not subject to New Source Performance Standards). In addition,
other technological processes, most of which are presently in the developmental.
stage, could make substantial contributions after 1980. Among the most ,
Important of these options are flu1dized-bed combustion; coal conversion
Including solvent refining, gasification, and liquefaction; and solid waste
combustion as an energy source.
Table 1-2 summarizes data on the availability, incremental cost, and
environmental Impact of these compliance options. To develop incremental
costs, a baseline cost was derived from the fuel cost for operating a plant
on high-sulfur coal without flue-gas desulfurlzatlon. High-sulfur coal costs
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Table 1-2. CONTROL STRATEGY ALTERNATIVES
Alternative
Low-sulfur coal
Physical coal
desulfurization
Flue-gas
desulfurization
Coal gasification
(low Btu)
Fluidized-bed
boi 1 ers
Supplementary
control systems
Tall stacks
Energy recovery
from solid
waste
Date of
commercial
availability
Today
Today
Today
1980-83
1983-85
Today
Today
1975-78
Large-scale
supply availability
Date
1978-80
1977
1978-79
1985
1985
1975-77
1975-77
1980
Capacity,
million
tons
80-200b
c
250-390
-
-
d
d
23.5006
Annualized
costs a
mills/kWh
0.5-3.0
1.0-2.0
2.5-4.0
10.0-15.0
2.0-3.0
0.5-1.0
0.15-0.3
of
Major
environmental
impacts
Parti cul ate emissions
(controllable)
Residue disposal and
water pollution
Sludge disposal
(commercial treat-
ment available)
Air and water pollu-
tion
Less severe than
conventional boilers
Pollutant loadings;
sulfate risk
Avoids conventional
waste disposal
problems
Incremental cost above current practices (high-sulfur coal without flue-gas
desulfurization).
Increment over present levels of low-sulfur coal production.
cFourteen percent of reserves can be cleaned to meet New Source Performance Standards.
Limited only by regulations defining enforceability and reliability.
Equivalent oil savings potential of 236,000 barrels per day by 1980.
Experience suggests power plants would not accept higher prices for solid waste fuel
than for conventional fuels; solid waste costs might be less in some instances.
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of $0.80 per million British thermal units (Btu) or approximately 8 mills per
kilowatt-hour (kWh) have been used In the analysis. As shown 1n Table 1-1,
Increased production of low-sulfur coal above that produced 1n 1974 could
range from 80 to 200 million tons by 1980. The incremental cost of
compliance by this method, including the cost of plant alterations required
to burn low-sulfur coal, 1s between 0.5 and 3.0 mills/kWh. In some cases,
conversion to low-sulfur coal might lead to an increase in partlculate
emissions from degradation of the collection efficiency of electrostatic
precipitators. Additional precipitator capacity or flue-gas conditioning
may be required to overcome the resulting efficiency reduction.
Coal cleaning techniques that physically separate Inorganic sulfur from
combustion coal are available. Based on the average sulfur content of
known coal reserves 1n the United States, coal cleaning techniques could
reduce the sulfur content of 14 percent of the reserves to the levels required
by the New Source Performance Standards. The Incremental cost of coal
cleaning is approximately 1.6 mills/kWh.
The capacity of vendors of flue-gas desulfurlzation equipment to
Install systems by 1980 1s equivalent to 250 to 390 million tons of coal-
flred capacity. Incremental costs range from 2.5 to 4.0 mills/kWh. The most
important potential environmental problem is the disposal of sludge from
nonregenerable systems.
Supplementary control systems and tall stacks are available today and
are the least expensive of all the options. Environmental problems.associated
with supplementary control systems include Increased atmospheric loadings
of pollutants and the risk of adverse health effects associated with
suspended sulfates..
As mentioned earlier, compliance alternatives over the longer term may
be expanded to Include fluidized-bed combustion systems, gasified- or
Hquefied-coal products, and in some cases the use of solid waste as a fuel..
source. With the exception of energy recovery from solid waste, these
options must be considered to be 1n the developmental stage. Coal gasifi-
cation entails large capital expenditures and potentially serious air and water
pollution problems. In addition, the total cost of a gaseous power plant
fuel will probably fall in the range of 20 mills/kWh, which is not competitive
with the. use of flue-gas desulfurization and high-sulfur coal at 10 to 12
mills/kWh. One of the most promising options for the 1980's is fluidized-
bed combustion. Preliminary bench-scale testing indicates that the cost
of fluldized-bed combustion may be less than conventional systems equipped
with flue-gas desulfurlzation and could potentially improve the energy.
efficiency of steam electric power plants. ,
The use of these options compares favorably with the use of low-sulfur
oil at current prices. At $11 per barrel, the cost of oil per kilowatt-hour
generated is roughly equivalent to 21 mills. Even coal gasification Systems
would be competitive with low-sulfur oil at these prices. c
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The compliance alternatives discussed above relate to existing sulfur
regulations in State Implementation Plans and to the New Source Performance
Standards. In addition to these options, the Environmental Protection Agency
expects its efforts to assist the States in revising sulfur regulations or
timetables for compliance to significantly contribute to the resolution
of existing compliance problems. Efforts by the Environmental Protection
Agency and the individual States have already resulted in allowing the
legal use of 42 million tons of coal that originally could not have been
used in compliance with State sulfur emission requirements. An additional
70 million tons should be legally acceptable by the summer of 1975 as a
result of expected revisions to State regulations.
FACTORS AFFECTING COMPLIANCE
This review of the compliance status of coal-fired electric power
plants 1n 1974 and 1980 1s based on announced changes in fuel requirements
and a projected rate of construction of new facilities. A number of factors
that could affect compliance cannot be forecast accurately. These factors
Include possible o1l-to-coal conversions of power plants, slower growth
rates for electricity consumption through 1980, Increased demand by the
Industrial sector for steam coal, and potentially severe natural gas
curtailments. In addition, further legislative action by the Congress may
alter the authorities now available to resolve potential conflicts between
the nation's energy and environmental goals. The factors mentioned and
the possible use of new authorities granted by Congress make it extremely
difficult to forecast how both existing and new plants may choose to
comply with sulfur oxide emission regulations.
With regard to a priority system for installation of sulfur removal
equipment, the Environmental Protection Agency does not believe that it
1s necessary to invoke its authority to prioritize sales at this time.
This is based on the conclusion that the availability of compliance alter-
natives is sufficient to meet power plant control requirements in a free
market.
CONCLUSIONS
This report provides the most recent information available on the
compliance status of coal-fired steam electric power plants (based on coal
purchased during the first half of 1974), on the availability and cost of
compliance alternatives, and on the position of the Environmental Protection
Aqency regarding the use of priority allocation systems for sulfur removal
equipment. The report shows that, although significant compliance problems
now exist, the availability of existing compliance alternatives is more
than adequate to satisfy projected requirements. Low-sulfur coal, flue-gas
desulfurlzatlon systems, the temporary use of supplementary controls in
limited circumstances, and possible revisions of State sulfur regulations
hold the potential for achieving compliance by 1980. However, larger-than-
expected natural gas curtailments, substitution of coal for oil by the
Industrial sector, and delays 1n nuclear plant construction could significantly
Increase the demand for coal beyond current expectations. If these changes
are significant, requirements may exceed the available supplies of low-
sulfur coal or flue-gas desulfurlzatlon systems.
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CHAPTER 2. SCOPE OF REPORT
This report 1s submitted to Congress In conformance with the require-
ments of Section 119 (k) (1) of the Clean A1r Act as amended by the Energy
Supply and Environmental Coordination Act of 1974 (ESECA). Section 119
(k) (1) requires the Environmental Protection Agency to report to Congress
on nine issued within 6 months of enactment. This report responds to1
seven of these nine Issues as outlined below. The two Issues not discussed
will be addressed 1n a subsequent report to Congress required under the
Energy Supply and Environmental Coordination Act. ix*
j • >. . •
IMPACT OF FUEL SHORTAGES " ;
Section 119 (k) (1) (A) requires the Environmental Protection Agency
to report to Congress on:
t ' j • ' '
"(A) the present and projected Impact of fuel shortages and fuel
allocation programs on the program under this act."
There are two basic types of fuel shortages. First, existing supplies can
be less than adequate to satisfy domestic energy requirements. Second,
existing supplies can fall to conform to sulfur regulations established
pursuant to the Clean A1r Act. This report 1s concerned primarily with
this second type of fuel "shortage," often referred to as the clean fuel
deficit. - •, • :-• ;
t • • • . '*'*'.
Although some sources needing to convert to low-sulfurjoil to meet
sulfur emission requirements have been unable to obtain sufficient
supplies of conforming oil, compliance problems for oil-fired sources
are not as serious as those affecting coal-fired units. To date, the
shortages of conforming 'oil have been temporary and have been adequately
handled on a case-by-case basis with short-term variances. An insight
Into the relative Importance of coal and oil to the conforming fuels
problem may be gajned from noting that Federal Power Commission data
show (1) that coal accounted for 48 percent and oil 17 percent (Including
the oil used 1n peaking units) of the fossil fuel burned in steam electric
power plants 1n 1973, and (2) that the average sulfur content of the
coal was 2.3 percent while the average sulfur content of the oil was 0.9
percent. M6reover, pre-combust1on oil desulfurlzatlo'n technology is
well developed and therefore not controversial. -
Consequently, this report focuses on compliance alternatives for
coal-fired steam electric power plants. Tfrese plants account for over,
60 percent of the total sulfur oxide emissions from dll sources and
consume 85 percent of the combustion coal used 1n the nation. Coal
consumption in these plants will continue to be Important in the future
with coal use projected to grow at a rate approaching 8 percent per year
through 1980.
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Chapter 3 of this report reviews the compliance status of coal-
fired electric utilities. Compliance data are based on coal purchases
for the first 6 months of 1974 (data supplied by the Federal Power
Commission), and national projections are based on expected requirements
for 1980.
POLLUTION CONTROL-COMPLIANCE ALTERNATIVES
Section 119 (k) (1) (B), (E), and (F) address issues related to
compliance alternatives:
"(B) availability of continuous emission reduction technology
(including projections respecting the time, cost and
number of units available) and the effects that continuous
emission reduction systems would have on the total environ-
ment and on supplies of fuel and electricity...
"(E) evaluation of availability of technology to burn municipal
solid waste in electric power plants or other major fuel
* burning installations, including time schedules, priorities,
analysis of pollutants which may be emitted (including
those for which national ambient air quality standards have
not been promulgated), and a comparison of health benefits
and detriments from burning solid waste and of economic
costs;
"(F) evaluation of alternative control strategies for the attain-
ment and maintenance of national ambient air quality
standards for sulfur oxides within the time for attainment
prescribed in this Act, including associated considerations
of cost, time for attainment, feasibility, and effectiveness
of such alternative control strategies as compared to
stationary source fuel and emission regulations..."
Chapter 4 of this report discusses available control strategies that
can be used to assure compliance with sulfur regulations. The discussion
covers both continuous and noncontinuous methods of control, including
utilization of solid wastes as fuel. As requested by the Congress, the
control alternative section includes the status of commercial availability,
potential supply, technical effectiveness, costs, and environmental
Impacts. The Environmental Protection Agency 1s continuing to analyze
various problems related to the cost and availability of emission control
systems, including Intermittent control systems. As these studies
progress, the Agency will provide pertinent results to Congress.
PRIORITIZATION OF POLLUTION CONTROL TECHNOLOGY AND OTHER ISSUES
Section 119 (k) (1) (C), (D), and (G) address the issue of authority
to allocate pollution control technology:
8
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"(C) the number of sources and locations which must use such
technology based on projected fuel availability data;
"(D) a priority schedule for Installation of continuous emission
reduction technology, based on public health or air quality...
"(G) proposed priorities for continuous emission reduction systems
which do not produce solid waste, for sources which are
least able to handle solid waste by-products of such systems..."
Two Issues are of Importance here. First, the ability of the Environmental
Protection Agency to forecast how plants may choose to comply with
applicable emission regulations, and, second, the availability of continuous
emission reduction technology. With regard to the first Issue, the
Environmental Protection Agency cannot project which continuous emission
control technologies a source may choose to use. This choice is left
with the utility. The Environmental Protection Agency can enforce
regulations affecting plants that are not in compliance, but the ultimate
choice of compliance alternatives is the utility's responsibility. As
will be shown 1n Chapters 3 and 4 of this report, vendor capacity is more
than adequate to satisfy maximum requirements, and therefore it is unlikely
that priority schedules will be required.
Chapter 5 of this report addresses these Issues in more depth and pro-
vides a qualitative discussion of some Issues not raised by Congress but which
could affect compliance problems. These general energy issues include: the
rate of growth 1n the demand for electric power, the growth of nuclear ca-
pacity, the potential impact of reversion to coal from oil or gas on the
demand for low-sulfur coal or control equipment, and the effect of natural gas
curtailments. Also contained 1n Chapter 5 1s a description of the various
Federal energy allocation authorities and how they could be used to enhance
environmental objectives.
OTHER REQUIREMENTS
Section 119 (k) (1) (H) and (I) relate to the Environmental Protection
Agency's steps to monitor the air quality Impact of the Energy Supply and
Environmental Coordinator Act and Its review of State Implementation
Plans.
"(H) plans for monitoring or requiring sources to which this sec-
tion applies to monitor the Impact of actions under this sec-
tion on concentrations of sulfur dioxide in the ambient air;
and
"(I) steps taken pursuant to authority of section 110 (a) (3) (B)
of this Act..."
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The Environmental Protection Agency's response to these two subsections
will be included in its report to Congress to satisy the provisions of
Section 7 of the Energy Supply and Environmental Coordination Act.
10
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CHAPTER 3. COMPLIANCE STATUS OF COAL-FIRED
POWER PLANTS, 1974 to 1980
INTRODUCTION
This chapter addresses the compliance status of coal-fired power
plants, as derived from coal purchased during the first 6 months of \
1974. Data are presented on the compliance status of existing coal-
fired power plants with State Implementation Plan regulations for sulfur
and with plans by utilities for plants constructed after 1974. The
Information provided in this chapter 1s based on reports submitted tq
the Environmental Protection Agency and other Federal agencies by
utilities concerning their current coal consumption.and their plan's to
comply with applicable sulfur regulations. Although these data are the
best available, in some Instances the plans submitted by utilities are
not legal commitments. It is also possible that, for some plants, en-' J
forceable compliance schedules have been negotiated by State agencies but
have not yet been reported to the Environmental Protection Agency.
COMPLIANCE STATUS, 1974
• • ' • •' .'•<
In 1974, steam electric power plants consumed approximately 390 •;
million tons of coal. As shown in Table 3*1, roughly 50 percent of this"
coal could be burned 1n compliance with exfstlng sulfur regulations of
State Implementation Plans, An additional 85 million1tons, or approximately
22 percent of the coal consumed 1n 1974, was used in plants Involved in
legal disputes. Forty-six million tons could not be burned t,n compliance
with the applicable regulations, but 1n these cases, plans for achieving
compliance are known to the Environmental Protection Agency. The remaining
65 million tons could not be used in compliance with existing regulations,
and compliance plans have not been submitted to the Environmental Protection
Agency. The compliance categories listed fn Table 3-1 are discussed below.
Conforming Coal
««m^^B^HM.^B«^*>MWM^HB» ?
This category is based on a pi ant-by-plant evaluation 1n which the
sulfur content of the coal used 1n the first 6 months of 1974 1s com-
pared with the July 1, 1975, sulfur regulations 1n State Implementation
Plans. In some cases, the average sulfur content of the coal consumed
exceeded the applicable regulation. In such instances, the quantity of
coal that fell below the sulfur limit was Included in this category With
the portion exceeding standards added to the "Non-complying, plans
unknown" category.
11
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Table 3-1. COAL USED IN POWER PLANTS, 1974
Status
Conforming coal
Legal disputes
Nonconfomring, plans
known
Nonconforming, plans
unknown
Total
Coal use,
mi lions of tons
194
85
46
65
390
Percent
of total
49.7
21.8
11.8
16.7
100,0
The "Conforming coal" category should be viewed as a minimum estimate
of the amount of coal that could be used in compliance with the July 1,
1975, regulations. Excluded from this category are power plants that
may have received a variance, plants involved in litigation, and plants
1n regions where regulations are being revised.
Legal Disputes
Legal issues are of importance because the largest coal consuming
States, as shown in Table 3-2, are involved and, in some cases, no legally
enforceable regulations exist. Although most of the plants in this
category are legally out of compliance, the ultimate status of the use
of this coal is dependent upon the resolution of the legal issues involved.
A brief review of some of these problems follows.
Table 3-2. STATE SULFUR REGULATIONS
INVOLVED IN LITIGATION, 1974
(thousand tons of coal)
State
Indiana
Missouri
Ohio
Pennsylvania
Total
Coal use affected
by legal actions
28,890
8,700
45,900
2,350
85,840
Total 1974
consumption
28,890
16,670
45,900
27,370
118,830
12
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Section 307(b) of the Clean Air Act allows for a petition for review
of action of the Administrator including the approval or promulgation of
any implementation plan under Section 110. Any such petition must be
filed within 30 days from the date of such promulgation, approval, or
action; or after such date if such petition is based solely(oh grounds
arising after the 30th day, A source may seek and obtain a stay of en-
forcement proceedings pending a resolution of the underlying Section 307
challenge.
This si tuition is best demonstrated 1n Indiana where two power , .,
companies (Northern Indiana Public Service Company and Public Service
Company of Indiana) have successfully stayed further.enforcement by the
Environmental Protection Agency pending a decision on a motion to stay
enforcement. The Environmental Protection Agency is unable at this time
to estimate when a decision in this casa will be rendered. ' .
In Ohio,, thi Environmental Protection Agency approved ;the perticulate
matter portion of the State Implementation Plan and Initiated a few ,
enforcement actions. The utilities and the steel industries, however,
have challenged the Administrator's approval of the State plan.. Also,
in September 1974, the Ohio utility hearing examiners issued adverse
findings and recommendations concerning the sulfur dioxide control
strategy. The .examiners concluded that scrubber technology presently V
does, not exist ind 1s not reliable and recommended that further $tudjies
be done before any final action 1s taken on a sulfur dioxide plan in
Ohio. In December 1974, however0 the Director of the Ohio Environmental. ,
Protection Agency, who Is empowered with making the final decisions at
the State level, concluded that, although control technology does exist,
the hearing record did not contain air quality data that demonstrated a
need for controls. Because of these recent actions by the State of .
Ohio, the Environmental Protection Agency does not anticipate any Imminent
Stati action on the sulfur dioxide control strategy. To correct this
deficiency 1n the Ohio plan, the Environmental Protection Agency is
presently completing the technical studies necessary for a Federal .promulga-
tion by the early spring of 1975. .
Moneonformlng,, Plans Known • ."
Although not presently in compliance with applicable emission regula-
tions,, the coal-burning power plants in this category have submitted plans
showing an acceptable program. Table 3-3 summarizes the compliance, plans
submitted to the Environmental Protection Agency.
13
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Table 3-3. KNOWN COMPLIANCE PLANS OF PLANTS
NOT MEETING STATE IMPLEMENTATION PLANS, 1974
Compliance strategy
Low-sulfur coal
Flue-gas desulfurizatlon
Switching to oil
Total
Coal use,
thousand tons
29,230
15,430
1 ,740
46,410
Percent
of total
63.0
33.2
3.8
100.0
Nonconfornrinq, Plans Unknown
A significant percentage of the coal consumed in 1974 did not meet
applicable sulfur regulations, and a number of the plants consuming this
coal have not submitted compliance plans to the Environmental Protection
Agency. These plants, however, may be operating under variances to State
Implementation Plans or have enforceable plans that are in the review pro-
cess. This group accounted for approximately 65 million tons of coal
consumed in 1974, or slightly over 16.7 percent of the total.
CONFORMING COAL BY SULFUR CONTENT
The 1974 plant-by-plant analysis of coal used by plants in compliance
with sulfur emission requirements showed that a substantial portion of
the coal exceeded 1 percent sulfur by weight. Sixty-eight percent of the
194 million tons of conforming coal contained more than 1 percent sulfur
by weight, and 37 percent of the total contained more than 2 percent sulfur
by weight.
It is not possible to estimate accurately the sulfur contents of con-
forming coal for 1975 or later years. A significant number of State regula-
tions are subject to legal challenges, others are being revised. In addition,
several different strategies are available for compliance. One estimate
(the maximum in terms of shifts to lower sulfur coal) can be derived from
the assumptions that (1) nonconforming plants now opting for a shift to
lower sulfur coal make that change and (2) nonconforming plants with
no indicated strategy also shift to lower sulfur coal. Under these
assumptions the 94 million tons of nonconforming coal would be replaced
hy conforminq coal (29 million tons from the first assumption and 65
from the second). Sixty-six percent of this conforming coal could exceed
1 percent sulfur by weight, and 21 percent could exceed 2 percent sulfur
by weight.
These data show that, both for plants using conforming coal in 1974
and for a substantial portion of the plants not now using conforming coal,
continuous emission control alternatives are not necessarily limited to low-
sulfur Western coal or flue-gas desulfurizatlon.
14
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COMPLIANCE STATUS THROUGH 1980
Coal use in electric utilities is expected to qrow rapidly throughout
the remainder of this decade. The Federal Power Commissi.on projects that
the demand growth rate for electricity will approach 6.5 percent per annum.
The energy required to satisfy this incremental demand will fall almost
entirely on new coal-fired and nuclear facilities. The present status
of the capital market and the financial situation of many utilities, however,
is forcing delays in nuclear installations. The combined effect of these
factors is expected to result in an 8 percent per annum rate^of growth.
1n coal consumption by electric utilities. J !v . . , /
•i • • » • ••-•*•• ••••>;''• i •
By 1980, approximately 40 percent of the total .coal demand by,utilities
will come from power plants constructed after 1974. 'Approximately 50
million tons of coal will be consumed in plants coming on-line in 1975
and 1976. These plants are subject to sulfur regulations in State Implemen-
tation Plans that apply to facilities constructed prior to 1975. More •
significant are the plants scheduled to come on-line after 1976. These
plants must comply with New Source Performance Standards (1.2 pounds of
sulfur dioxide per million Btu, or roughly 0.7 percent suifu.ir by weight).
At present, the primary compliance options for these plants are the use,'
of either low-sulfur coal or high-sulfur coal with flue-gas desulfuri?at1on.
Table 3-4 provides a preliminary estimate of the sulfur distribution, ,
required by 1980. Plants coming on-Hne after 1976, based o'ri Federal •
Power Commission estimates of required power generation capacity, wliU,,
consume approximately 185 million tons of coalk.Total coal requ;J£emen;ts
of existing and new plants are estimated to be roughly 625 million tons.
The actual amount,consumed will depend on a number of factor? including .
capacity utilization, the demand growth rate for electricity^ delays in
nuclear power plant construction, and oil-to-coal conversion. These issues.
will be discussed 1n Chapter 5. ;
Table 3-4. 1980 PRELIMINARY ESTIMATE FOR ALL COAL-
FIRED PLANTS OF COAL SULFUR CONTENT REQUIREMENTS '
.OR EQUIVALENT FLUE-GAS DESULFURIZATION CAPACITY.
. Percent sulfur
Less than 1.0
• 1.0 to 2.0
Greater than 2.0
Total
Distribution
57.7
17.7
24.6
100.0
15
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The Environmental Protection Anency cannot project how these new plants
will choose to comply with State sulfur regulations and with the New Source
Performance Standards. However, information based on recent surveys and
studies performed by the Environmental Protection Agency demonstrates that
the availability of low-sulfur coal and capacity of vendors to Install
flue-gas desulfurization equipment 1s sufficient to satisfy projected
requirements. New source review procedures at the State level will verify
that the plants comply as they come on-line.
Table 1-1 summarized known information on the compliance status of
existing or new coal-fired electric utilities through 1980. Also shown
was the projected availability of flue-gas desulfurization vendor capacity,
of low-sulfur coal, and coal requirements of utilities that could potentially
use supplementary control systems. These estimates were adjusted to
reflect current coal consumption and compliance plans that rely on flue-gas
desulfurization and low-sulfur coal. Table 1-1 shows that the availability
pf compliance alternatives 1s sufficient to satisfy the requirements of
coal-fired plants that, at present, have not submitted compliance plans.
THE CLEAN FUELS POLICY
The preceding discussion on the compliance status of coal-fired power
plants has focused on existing State sulfur regulations. The Environmental
Protection Agency, other Federal agencies, and many States recognized
the problems coal-fired utilities would have 1n complying with the State
sulfur regulations promulgated in.1972. Studies performed by the Environ-
mental Protection Agency subsequent to the adoption of State sulfur
regulations Identified roughly 110 million tons of coal that could continue
to be used 1n 1975 without violating health-related ambient air quality
standards. In recognition of the problems that might result from significant
quantities of coal not conforming with State regulations, the Environmental
Protection Agency adopted its Clean Fuels Policy 1n the fall of 1972.
This policy relied on cooperative efforts by the Environmental Protection
Agency and State environmental agencies to extend compliance timetables
for secondary standards or to revise emission regulations where primary
standards would not be jeopardized. This program has thus far resulted
in 42 million tons of coal being made legally acceptable through revisions
in the sulfur regulations of State Implementation Plans. The Environmental
Protection Agency expects that an additional 70 million tons will be
realized by July 1, 1975. These changes in compliance requirements will
allow those power plants that are affected by legal problems and those
that have not submitted compliance plans to use a substantial portion of
the coal they are presently consuming without significant changes in its
sulfur content. Additional information on this will be reported in a
subsequent report to the Congress.
16
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CHAPTER 4. COMPLIANCE ALTERNATIVES
FOR SULFUR DIOXIDE CONTROL
there is a wide spectrum of opinion on the availability of control
systems that can enable compliance with sulfur dioxide emission regulations.
This chapter will discuss a range of alternatives in ferms of their charac- s
teHstics in each of the following areas: commercial availability, sulfur
removal effectiveness, range of anplicablHty, associated costs of compliance,
environmental impact, and energy Impact. Pertinent time frames and solutions
to potential problems are noted where applicable.
Sulfur emission control options are classified as either continuous or
noncontlnuous. Continuous control systems reduce sulfur o^ide emissions to
permanent, s1 pacified levels that would be consistent with ^Jhieving State
Implementation Plan emission limitations apd with achlevlng^amblent alr^
quality standards under worst case meteorological conditions. Nonconjtinuous
systems depend on meteorological forecasting to determine when normal
emission rates must be reduced to ensure compliance with .anfcient air quality
standards.. The distinction here is that continuous systems operate ..indepen-
dently of meteorological conditions, while noncontiguous .systems,are only
used during periods of poor atmospheric dispersion.
Continuous control systems are divided Into precombustlon and post-
combustion alternatives. Precombustlon alternatives include substitution of .
low-sulfur for high-sulfur fuels, physical coal cleaning, and coal conversion
options such as gasification, liquefaction, and solvent refining. Post-
combustion systems cover flue-gas desulfurizatlon, both regenerate and non-
regenerable, and fluidlzed-bed combustion systems. The noncontlnuous systems
discussed include fuel switching, load shifting, and the use of "tall"
stacks. The alternatives mentioned thus far relate to the.use of fossil
fuels. The final section of this chapter addresses the use of municipal
solid waste as an alternative fuel.
CONTINUOUS STRATEGIES
Precombustlon Alternatives
The set of control strategies which comprises methods ;bf removing sulfur
from the fuel before combustion is included 1n this section. Both naturally
occurring low-sulfur fuels and preprocessed fuels are discussed.
Low-sulfur Fuel—Low-sulfur fuels include low-sulfur coal, natural gas, and
low-sulfur oil. Natural gas does not present any significant potential for
fuel switching due to the current and projected nationwide.shortage of gas. The
higher price and concern with dependence on Imported oil limits the usefulness
17
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of shifting to oil until domestic reserves can be developed. However, develop-
ment of domestic oil reserves is expected to be accomplished only at steadily
increasing costs. Therefore, only low-sulfur coal is addressed as an alterna-
tive clean fuel.
Two different grades of low-sulfur coal are of interest: one that con-
forms to State Implementation Plan requirements and the other that conforms to
New Source Performance Standard requirements. In most of the sections below,
these categories have similar attributes; however, where necessary, distinc-
tions are noted.
Commercial avail ability--The extent to which low-sulfur coal is
available as a control strategy is dependent upon the rate at which our
domestic resources of low-sulfur coal are developed and can be transported
to utility coal markets.
The discussion of compliance in Chapter 3 of this report implies a
growth rate for coal use by the electric utility industry of slightly more
than 8 percent per annum over the 1973-1980 period. The critical issues are
whether this volume of coal can be produced in an environmentally safe and
economically profitable manner, and whether its quality (sulfur content) will
match demand.
Total coal production in 1973 was approximately 600 million tons. The
recent demand forecasts made by the Federal Energy Administration in Its
Project Independence Blueprint ranged from 775 to over 840 million tons by
1980.
The report of the Coal Task Force of the Federal F.nergy Administration
concluded that:
1. By 1980, coal production could equal or exceed 900 million
tons per year.
2. The supply of coal is relatively price-elastic in this
time frame, i.e., the additional coal could be produced
at prices only slightly above existing production costs.
This report indicated that constraints on production existed due to
financial limitations, lack of trained manpower, environmental limitations,
possible shortages of equipment and materials, and the lack of appropriate
transportation facilities, especially rail transport. However, the Task
Force concluded that under appropriate financial Incentives, coal production
on the order of 900 million tons could be forthcoming. Certain policy fac-
tors could also have important Impacts, especially:
1. Uncertainty over sulfur regulations and the use of
Intermittent control methods.
2. Restrictions that might result from strip mining
legislation now being debated by the Congress.
18
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If these problems can be resolved, large Increases in coal supply are
possible.
The largest economically recoverable reserves of low-sulfur coal are in
the Northern Great Plains, the Four Corners area (where Utah, Colorado,
Arizona, and New Mexico meet), the Southwest, and Appalachia. Coal in the
Four Corners and Southwest 1s probably too far from the major markets to be an
Important source of new supplies except for the localized markets 1n the
Southwest and Far West. There are significant reserves of strippable low-
sulfur coal in the East. However9 low-sulfur coal in Appalachia has been
largely committed for coking coal uses and.export. Output expansion for these
reserves could be sensitive to strip mining legislation since much of the low-
sulfur reserve is located on steep slopes. By far the most significant
potential for low-sulfur coal supplies 1s the Northern Great Plains area.
The most economical sources of medium-sulfur coal production for markets
east of the Mississippi River are in Appalachia and the Northern Great Plains.
Actual low-sulfur coal production 1n 1980 is dependent on the resolution
of present disputes over the timetable for compliance and the level of State
sulfur regulations. Also Important are the relative economics of low-sulfur
coal use versus the use of high-sulfur coal and flue-gas desulfurlzation.
Some estimates suggest that low-sulfur coal from the West may be competitive
with high-sulfur coal and flue-gas desulfurlzation in Illinois and even 1n
Ohio.(l) The choice of coals will depend on these costs as well as political
and economic decisions in Midwestern states as to how much Western coal will
be utilized 1n existing and new plants. Significant reliance on Western
coal for existing power plants would result in dislocations to Eastern coal
mining production.
Table 4-1 presents two forecasts of coal production availability in
1980 by sulfur content. The Bureau of Mines estimates are simply extrapo-
lations of past patterns of production by sulfur content. In effect, these
estimates do not reflect changes in coal demand structure resulting from
efforts to comply with more stringent sulfur regulations, . .'"
The other estimates in Table 4-1, developed for the Environmental
Protection Agency by Sobotka and Company, Inc., assume the most economic
production of coal 1n order to meet presently applicable sulfur regulations.
The Sobotka estimates apply only to steam coal, while the Bureau of Mines
estimates Include coking coal. Thus, the Sobotka estimates exclude low-sulfur
Eastern coal for coking and export. The Sobotka estimates emphasize low-
sulfur coal production from the Great Plains on the assumption that, in most
areas, 1t 1s cheaper than high-sulfur coal plus flue-gas desulfurlzatlon. Only
42 million tons of coal below 1.2 pounds of sulfur per million Btu were produced
1n 1973. The estimates Imply that it is possible to boost low-sulfur coal
production by three to almost seven times current levels by 1980. Medium-
sulfur coal production could be 2.5 times as great as in 1973. Higher sulfur
coal production could rise by 50 percent, or remain constant 1f sulfur regu-
lations are not relaxed and flue-gas desulfurlzation is not used by the utilities,
19
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Table 4-1
POTENTIAL COAL PRODUCTION IN 1980
(thousand tons)
Region
Appalanchian
Bureau of Mines
Sobotkad
Midwestern
Uureau of Mines
Sobotka
Montana, Idaho,
Wybmi ng
Bureau of Mines
Sobotka
Rocky Mountain
Bureau of Mines
Sobotka
Pacific
Bureau of Mines
Sobotka
Totals
Bureau of Mines
Sobotka
Sulfur content
Low3
103,006
38,000
1,512
1,860
194,000
11,116
36,000
12,629
130,123
268,000
Medium5
262,744
166,000
15,613
57,000
79,540
49,000
20,284
34,000
19,799
30,000
397,980
336,000
Highc
160,350
146,000
205,375
118,000
-
—
1,172
366,897
264,000
Total
526,100
350,000
222,500
175,000
81,400
243,000
31,400
70,000
33,600
30,000
895,000
868,000
Coal that would conform to New Source Performance Standards
(less than 1.2 pounds of sulfur dioxide per million Btu).
Coal in the range of 1.21 to 3.2 pounds of sulfur dioxide
per million Btu.
cCoal greater than 3.21 pounds of sulfur dioxide per million
Btu.
Developed for the Environmental Protection Agency by Sobotka
and Company, Inc., October 1974.
20
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Demands for low-sulfur coal, or its equivalent 1n high-sulfur coal with
flue-gas desulfurization will rise markedly by 1980 due to the construction
of new plants subject to New Source Performance Standards. Nevertheless,
while low-sulfur coal demands will rise rapidly as new power plants come on
line, there will still be a major market for higher sulfur coal; 1n 1980 about
one-fourth of utility coal requirements can be relatively high in sulfur
content—at or above 2 percent sulfur—and still comply with existing regu-
lations without flue-qas desulfurization.
There is considerable potential for large Increases of low- and medium-
sulfur coal production by 1980. Whether this production is realized depends
on: (1) factors affecting demands such as resolution of litigation In
several States on sulfur regulations, the degree of reliance on Intermittent
control approaches, and the economic competitiveness and acceptance by the
utility industry of flue-gas desulfurization technology; and (2) factors
affecting supply such as transportation facility development, possible strip
mining regulations, and the cost and availability of mining .equipment. .
j ' . . .
Effectiveness—All continuous control strategies involve compliance with
a specified pollutant emission rate. The sulfur content limitation defined
by New Source Performance Standards is a maximum of 1.2 pounds of sulfur
dioxide per million Btu. For all other facilities, the emission limitation
1s determined through consideration of the following factors: (1) dispersion
characteristics of the source and the surrounding area, (2) background concen-
tration of the pollutant, (3) total emissions rate of all sources 1n the area,
and (4) expected rate of growth in emissions. The applicable sulfur content
limitation 1s based on allowable emission rates. If the determination of the
allowable emission rate is correct and the supply of coal with the necessary
sulfur content 1s assured, this alternative is better than 99 percent effective
1n assuring that air quality goals are achieved.
Appl 1 cabl 1 ity—There are three categories of existing plants to which
conversion to low-sulfur coal 1s potentially applicable as a compliance
strategy: oil-fired plants, coal-fired plants using high-sulfur coal, and
dual-fired plants burning natural qas. Conversion of oil- and gas-fired
plants is limited to those plants that have been previously converted from
coal to oil or gas, or those plants that were designed for dual oil/coal or
gas/coal operation. All other oil-fired plant conversions would result in unit
deratlngs of 30 to 50 percent. Due to design limitations, some plants cur-
rently using high-sulfur coal would encounter unit deratlngs'of 10 to 30 per-
cent If converted'to low-sulfur coal.
Environmental Impact—The environmental impacts associated with the use
of low-sulfur coal include the effects of mining and transport as well as coal
usage. Factors of concern in mine development Include soil.erosion, add mine
drainage, disturbance of wildlife, and land reclamation. Since the presence
•of sulfur decreases the resistivity of particles and heightens precipltator
efficiency, the principal combustion impact of burning low-sulfur coal in
plants designed for high-sulfur coal 1s that particulate emissions increase,
sometimes by a factor of ten.(2) This efficiency reduction can be overcome
by increasing pracipltator capacity or conditioning flue gases.
21
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Coal combustion also creates a substantial fly ash disposal problem.
If this waste is not properly disposed of, serious water pollution problems
may result. Fugitive dust emissions may also result from coal-handling
activities.
4
t
Energy impact—Energy impacts of converting units designed exclusively
for oil-firing to coal can be prohibitive. Conversion of these units
causes unit derating and reduced thermal efficiency. Energy requirements
at coal-fired facilities are increased through the requirements for long-
distance coal transportation and additional coal-handling and pulverizing
requirements. However, this impact is highly variable and, for most plants,
is not expected to be significant. Transportation is expected to increase
the thermal energy (Btu) required to produce a kilowatt-hour of electricity
by 1 to 3 percent.
Cost of compliance—The cost of complying with sulfur oxide standards
through the use of low-sulfur coal includes the cost of necessary facility
modifications, the cost of the fuel, and the cost of transoorting the fuel.
Facility modifications include both boiler modifications and associated
costs of unit deratings.
The unit deratings associated with conversion of a plant designed to
burn only oil necessitate replacement power at a cost of $250 to $350/kW.
The combustion system modifications would also be costly, $60 to $90/kW.
Therefore, costs and energy considerations practically eliminate this tyoe
of conversion.
The capital costs of converting a plant from high-sulfur to low-sulfur
coal vary with plant design, averaging approximately $20/kW. This expense
includes minor combustion system modifications and upgrading of the partic-
ulate emission control system.
Although low-sulfur coal is generally more expensive than high-sulfur
coal, the price differential is highly variable, depending on plant location
and resultant fuel transportation costs. Differential cost estimates range
from zero to $0.25/million Btu. With the inclusion of amortized costs, the
incremental cost of compliance by conversion from high- to low-sulfur coal
would range from 0.5 to 3.0 mills/kWh. The incremental cost of compliance
represents the increase above the cost of plant operation on high-sulfur coal
without any sulfur dioxide control eguipment. The cost includes any differ-
ences in fuel cost, operating and maintenance costs, and amortized capital
costs.
Coal Gas i fication and Liquefaction—Numerous processes of converting high-
sulfur coal to a liquid or gaseous form are either available or under
development. The products which would potentially supply power plants include
liquid fuels and low- to intermediate-Btu gas. The nonutility demand for and
expense of high-Btu gas reduce the significance of this option as a practical
22
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compliance alternative for utilities. Since gasification 1s 1n a more advanced
stage of development than liquefaction, most of the following discussion
relates to experience with, or estimates concerning, gasification processes.
j
Commercial availability—While coal gasification processes,are currently
1n commercial use, the wide-scale commercial application of coal conversion
1s dependent upon Improvements 1n technology, as well as easing of constraints
on the construction and expansion of a synthetic fuels Industry. Technological
advances that Increase gaslfler efficiencies, ameliorate snyironmental Impacts
of the process, and decrease costs must occur. On the construction side, it
1s estimated that a full-scale plant would require 3 to 5 years and T;5 million
man-hours to construct. This 1s a substantial commitment of manpower. Addi-
tional manpower with special training Is required to operate, the plant. There-
fore, 1t 1s concluded that coal conversion processes will have little Impact
between now and 1985. Technical Appendix A lists various, processes and discusses
the status of their commercial availability. ; .-,. ,
Effectiveness—The liquefaction and gasification processes convert high-
sulfur coal to clean fuels with negligible sulfur content.
Applicability--The applicability of coal gasification ar>d liquefaction
1s limited by plant siting considerations. Plants must be located; near .a mine
or must provide transportation for 5 to 6 million tons of coal annually.
Location of mine-mouth, low- to med1um-Btu gasification plants 1n ;the West 1s
constrained by water availability and pipeline transportation costs to distant
markets. Siting of plants 1n the East will be difficult because of potential
environmental Impacts 1n these populated areas.
* ' *
Energy Impact—At present, systems to produce low Btu gas realize 65 to
85 percent thermal conversion efficiencies, or only a 20 to 30 percent elec-
trical energy conversion efficiency. Higher pressure combined cycle systems
are under development that have the potential for overall cycle efficiencies
competitive with those of conventional fossil-fuel-fired power plants.
Environmental impact—The potential environmental impacts of converting
coal to liquid or gaseous forms are associated with the scale and nature of
the conversion process and the conventional pollution problems associated
with coal use. Full-scale systems are expected to process 15,000 tons of
coal per day; this processing will emit all compounds emitted by coke-ovens
as well as trace metals present in coal. Because conversion processes emit
"conventional" pollutants, many would be required to use water scrubbers and
Would have the problems associated with properly treating, the effluent. In
addition, large quantities of water are needed to support mining, reclamation,
and coal processing. Ash from the coal oreparation plant, as well as hydro-
carbon emissions and odors from sulfur recovery and other auxiliary plants,
would be significant problems. ;. .,
23
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Cost of cpmpl1ance--The cost of compliance through use of synthetic fuels
1s determined by the output fuel product cost and the transportation cost from
producer to utility. The cost of the fuel output 1s„ in turn9 Influenced by
the associated raw material and conversion process costs. Current cost esti-
mates suggest that substantial technological progress is needed before coal
conversion could successfully compete with other compliance options.
There are various estimates of the capital cost of a gasification plant,
ranging from $164/kW for a low-Btu gas plant to $460/kW for a high-Btu gas
plant. (Cost per kilowatt refers to the gasification plant capital outlay
necessary to service 1 kW of power plant capacity.) Most estimates for a
low-Btu gas plant fall in the $200 to $300/kW range,(3,4)
The cost of the conversion product is sensitive to the price of coal,
plant load factors,, capital charges, and the availability of markets. In
additions cost is sensitive to improvements that could be made in the effi-
ciency of the gasification process. A range of $1.50 to $2.00/million Btu
is considered a reasonable approximation of the output cost for a low- to
madium=Btu low-sulfur fuel. The resultant incremental cost of compliance
would be 10 to 15 mills/kWh.
Physical Coal Desulfurization°°Physica1 cleaning of coal is accomplished
through size reductions sorting by specific gravity„ and separation through
flotation to remove sulfur and other impurities from raw coal. The degree
of removal is dependent on inorganic sulfur content find extent of physical
processing. Tabl® 4-2 presents washability data for U.S. coal reserves.
Commarcial aval 1abi11ty°°Al1 coal used in the production of metallurgical
coke is presently cleaned in a coal preparation plant. Since the technology for
use on utility coal would be similar;, both the technology and equipment are
commercially available. Existing facilities are primarily designed for ash
removal and are operating at or near capacity. Hence0 increased use by the
utility industry of the coal-cleaning process would require installation of
new coal-cleaning capacity. Dtsign and construction of a coal preparation
plant requires 24 months; a larg® increase in demand could cause delays because
the number of companies designing and constructing these plants is small.
EffectlI veness°°Sulfur occurs in coal in three forms: organically bound
sulfur, sulfate sulfur8 and pyritic sulfur. Although organic sulfur is not
affected by physical clean1!ng0 as much as 80 percent of the pyritic sulfur
can be removed. The pyritic sulfur content of different coals is variable
(20 to 60 percent of total sulfur content)0 with the effectiveness of physical
cleaning being highest for coals with a high percentage of pyritic sulfur
relative to total sulfur content.
Applicability—It is estimated that 13.6 percent of U.S. coal reserves
can be cleaned to conform to New Source Performance Standards (1.2 pounds of
sulfur dioxide per million Btu). An additional 54.6 percent could be cleaned
24
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Table 4-2. APPROXIMATE DISTRIBUTION OF COALS BY COAL TYPE AND HASHABILITY OF COALS
TO EQUIVALENT SOfcFUR XHflttflE EWSSIOU
tfftal tt.S.,pQdl.reserves)
Coal category
Percent of total reserves
Naturally low-sulfur
coals (c 1.2 ID/million
Btu)
Washable coals
< 1.2 1 fa/mill ion Btu
1.2 to 1.5 Ib/million
Btu
1.5 to 2.0 Ib/million
Btu
2.0 to 4.0 Ib/miniort
Btu
>4.0 Ib/milHon Btu
Lignite
10.97
0
0
0
0
10.97
0
Subbi-
tuminous
19.38
15.20
2.49
0.60
-0.70^
-0.39
0
Bltwrinous
Pa.,
H.Va.,
E.ty.
25.46
7.93
5.00
2.00
2.79
6.20
1.54
111.,
Ind.,
W.Ky.
22.82
0
0
0
0.5
10.97
11.35
Western
states
6.32
3.00
2.83
0.1
O.I
0.19
0.1
All
other
15.05
2.00
r~ *••**
3.24
1.50
2.00
2.00
4.31
Sub- '
total
100
28.13
13.56
4,20
6.09
30.72
17.30
Cumulative
total
28.13
41.69
45.89
51.96
82.7
100.0
ro
in
Based on analysis performed for the Environmental Protection Agency by Pedco
Environmental Specialists, Inc^;,-Cincinnati,, Ohio, 1974.
Coal may be washed to conform with these*emission requirements.
-------
to emit less than 4.0 pounds per million Btu (see Table 4-2). Coal cleaning
results in improved combustion characteristics and reduced boiler maintenance
requirements.
Environmental impact—The principal environmental problem associated with
coal cleaning is the disposal of coal refuse; 10 to 30 percent of the coal by
weight is disposed of as refuse. This refuse can be disposed of in landfills
or refuse piles without creatinq environmental problems, using daily compac-
tion, intermittent coverinq with clay, and final covering with soil and
plantinqs. Contaminated drainage must be collected and treated; drainage can
be minimized by proper design of the refuse pile. Particulate emissions and
water pollution problems are present but controllable.
: Energy impact—The primary drawback of coal cleaning is the potential
less of combustible portions of the coal. Easily cleaned coals are not a
problem, but deep cleaning to remove fine pyrite can cause high losses of
heat value. In general, these Btu losses can be held to 5 to 7 percent. The
consumption of energy in the coal preparation plant itself is modest.
Cost of compliance—The costs to wash* coal depend upon the type of coal,
siting costs, and costs for refuse disposal. Capital costs for ,a complete
coal-cleaning operation, including environmental controls, landi the prepara-
tion plant, and handling facilities, is estimated to be $20,000 to $30,000
per ton of raw coal feed per hour capacity. Coal cleaning results in a cost
increase of $0.10 to $0.20/million Btu over unprocessed, coal. This translates
to an incremental compliance cost of 1.0 to 2.0 mllls/kWh. Further cost
increases may result from a need to upgrade power plant electrostatic precipi-
tators.
Chemical Coal Desul furizati on—Another precombustion alternative is sol vent-
refined coal, a chemical desulfurization process. The discussion is necessarily
brief because this process is still under development; economic, energy, and
environmental problems have not fully surfaced and cannot be quantified.
Commercial avallabi 1 ity—This process is currently in the pilot-plant
stage and commercial availability is not projected until the 1980's.
Effectiveness--The solvent refining process removes 60 to 70 percent of
the organic sulfur and all of.the inorganic sulfur in coal.
Applicability—This process produces a uniformly high-grade low-sulfur
product from various grades of coal; therefore, it should have wide applica-
bility.
Environmental impact—This process produces a clean fuel not requiring
treatment for sulfur dioxide or particulates.
Energy impact—The solvent-refining process upgrades the heating value of
any feed coal significantly to a uniform 16,000 Btu/pound.
26
-------
Cost of compliance—HHtman Associates estimated in 1973 that solvent
refining would add approximately $0.35/mill1on Btu, or the equivalent of 3.5
m1lls/kWh, to raw fuel cost for a plant, processing 10,000 tons/day.
Postcombustlon Alternatives
Another class of compliance alternatives Involves removal of sulfur
oxides from combustion gases. Flue-gas desulfuHzation processes are
fled as regenerable or nonregenerable based on the marketability of the by-v;
products. Another compliance alternative discussed in this section 1s !
fluldlzed-bad combustion, a modification of current combustion practices. <
Flue-gas DesulfuHzation—Both regenerable and nonregenerable flue-gas desul- r
furlzatlon (?5b") processes are discussed 1n this section. The major areas
of differing Impact will be clearly defined. The most common FGD process
Is the nonregenerable lime or limestone scrubbing system. The most common
regenerable processes are magnesium oxide scrubbing (Mag-Ox), catalytic
oxidation (Cat-Ox), and sodium solution scrubbing (Wellman Lord). Table
4-3 lists various, FGD processes and categorizes their stage of development
and1 performance characteristics.
Commerglal aval 1abil1ty--Many FGD systems are in operation, under con-
struction, or 1n planning stages in this country. Table 4-4 gives the numbers
of plants 1n each phase as of October 1974} Technical Appendix B summarizes
the operating experience of plants equipped wi^h FGD systems as of
October 1974. i ;v.
There has been some controversy over the reliability of FGD $ysterns.
Early systems encountered numerous chemical and mechanical problems, including
scaling, plugging, corrosion, and mechanical failures. MorfJ recently, the v
chemical problems have been largely solved by control of the process .chem-
istry. While some mechanical problems remain, unit availability factors of
90 percent have been achieved in some Instances. Newer units-are expected ta
realize 95 to 99 percent availability over long time periods.
Another important consideration in commercial availability is vendor
capacity. Table'4-5 indicates the industry capacity to design, supply, and ,•.
install FGD systems. In addition to the projections in this table, some
companies have indicated a willingness to license their process, which would
significantly expand capacity,
The lime/limestone scrubbing, Mag-Ox, and Cat-Ox processes are the most.
advanced and hold the greatest promise for near-term commendal. application,,
as Indicated 1n Table 4-3. Approximately 30 to 36 months, is required to
design, fabricate, and install an FGD system; a phased approach can require
6 to 12 months longer.
Effectiveness—There are two parameters that define the effectiveness
of an FGD system: removal efficiency and availability. FGD systems are gen-
erally attaining removal efficiencies of 80 to 95 percent, and 1n some cases
over 98 percent. These removal efficiencies are equivalent to emission rates
27
-------
Table 4-3. COMPARISON OF VARIOUS FLUE-GAS DESULFURIZATION PROCESSES.
ro
oo
Process
Limestone
scrubbing
Lime scrubbing
Sodium
carbonate
Chiyoda thoro-
bred 101
Calsox
Magnesium
oxide
scrubbi ng
Catalytic
oxidation
Well man Lord
Citrate
process
Type
Nonregenerable
Nonregenerable
Nonregenerable
Nonregenerable
Nonregenerable
Regenerable
Regenerable
Regenerable
Regenerable
Typical
sulfur
dioxide
removal
efficiency,
percent
90
92
90
90
90
91
85
90
95
End product/
waste product
Calcium sulfite and
calcium sulfate
sludge
Calcium sulfite and
calcium sulfate
sludge
Calcium sulfite and
calcium sulfate
Gypsum
Calcium sulfite and
calcium sulfate
Sulfur dioxide to
sulfuric acid or
sulfur
78 percent sulfuric
acid
Sulfur dioxide/
sodium sulfate
Elemental sulfur/
sodium sulfate
Stage of
development
Commercial
Commercial
-
Demonstration unit
planned
Pilot plant in USA
commercial in Japan
Demonstration unit
planned
Commercial
Commercial on coal-
fired units
Demonstration unit
under construction
Pilot plant
-------
Table 4-3 (continued). COMPARISON OF VARIOUS FLUE-GAS DESULFURIZATION PROCESSES
IN3
Process
Phosphate
process
Armonium
bl sulphate
Charcoal
adsorption
S&W/ Ionics
SEGD system
Type
Regenerable
Regenerable
Regenerable
Regenerabl e
Regenerabl e
Typical
sulfur
dioxide
removal
efficiency,
percent
95
84
95
. '90
88
End product/
waste product
Elemental sulfur/
sodium sulfate
Sulfur dioxide for
sulfur ic acid
production
Elemental sulfur/
vent gas from
sulfur production
step
Sulfur dioxide/di-
lute sulfuric add
Sulfur dioxide to
produce sulfur or
sulfuric acid
Stage of
development
Demonstration unit
Pilot plant
Pilot plant
Pilot plant, demon-
stration unit planned
Demonstration unit
under construction
-------
Table 4-4. STATUS OF FLUE-GAS DESULFURIZATION
SYSTEMS, OCTOBER 1974
Status
Operational
Under construction
Planned
Contract awarded
Letter of Intent
signed
Requestl ng/eval uati ng
bids x
Considering flue-gas
desulfurlzatlon
systems
Total
Number
of units
19
18
9
3
13
37
99
Capacity, MW
3,291
6,877
3,904
530
6,902
16,472
37,966
Table 4-5. VENDOR CAPACITYFOR FLUE-GAS
DESULFURIZATION3
Year
1977
1979
1981
Cumulative potential capacity, MW
With present
facilities
30,600
76,400
131,800
With expanded
facilities
45,400
128,900
197,700
Capacity, Including design and Installation,
based on Environmental Protection Agency
survey conducted 1n the fall of 1974.
Vendors responding to survey Included:
Universal Oil Products, Atomics International,
Catalytic Inc., Chlyoda International, Com-
bustion Engineering, Envlrotech Systems,
Krebs Engineers, Monsanto Environmental
Services, Peabody Engineering Corp., Research-
Cottrell, Stauffer Chemical, and Joy
Manufacturing.
30
-------
of 0.2 and 1.0 pound of sulfur dioxide per million Btu, depending upon the
sulfur content of the coal. As stated ab@v§0 early FGD processes were unre-
liable because of chemical and mechanical problems. Recent installationss
rc ar® operating at over 90 percent availability. . ..,":"
Agpl 1 cjibj 1 1 tj(°°Th(2 factors Influencing applicability include plant age,
plant spaee"0 an^Tpl ant size0 all of which affect the economic viability of FGD
processes » These considerations are dealt with in wore depth in the cost of.
compliance discussion below. Nonregenerable processes create the additional
eoneera ©f availability ©f suitable iludga disposal techniques. A parallel
concern for regdntgrable pr©e@siisD although not as critical 0- is the presence
©f a fey<=pr©dyet market, , ,
F6D systems are applicable to a wide variety of plant types 0 the
te@nei?)1©s of seait are more easily realign^ at rulaitvely Adw plants. These
plants have sufficient r@maininf life to amartign the Iarg@.tnp1tal ©Kpdnd-
1ture naquirdd to install FSD systems.
Thiitre ars a1r0 water 0 and solid waste impacts.
©i, Tte air Impacts arQ largely posit1v®8 with
sulfur dioxide emissions reduedd by 80 t© 15 pgrc©int0 and associated parti c-
ulate removal efficiencies 1n Q«e@ss of 99 percent. In additions nitrogen
0x1 di ©missions are mdyeed by approximately 10 to 20 percent by the scrub-
bin. (The Cat-=0x process does not entail scrubbiinigj therefor©0 nitrogen
im1isii©n§ are not reduced. This process way convert nitrous mddtg to
©xidio) A negative impact occurs 1f staek gases are siot reheated;
of acid m1it ar© formsd by condensation of sulfur dioxide
and sulfur fcploxlde rumalnlng in th@ flu® gas. In addition^ minor Rs@at1v@
Impacts @eeyr at regenerable plants^ sulfur r@(tiov@ry plants may emit from
0.17 t@ 0.3S pound of sylfyr dioxide par .million Btu and associated sylfuric
acid plants my esnlt approximately 0.2 pound p©r million
Sludge diiposal is the major environsrantal problem of nonregenerable
systeis. Th© amount of sludge generated ig dependent upon sulfur and ash
content of the coal „ sulfur dioxide removal effie1®ney9 coal ysage^ load
faetorj, molo ratio ©f additlvig;, and mQlityr© and composition of the sludgd.
A 100=1%! coal =f1 red unit w@yld prodyeg ab©yt 3^0SOO ^ans/year of wet FSQ
sludge. Proper disposal of syeh larp qyantltte 1i requlmd to prevent a
tlhreat of e@ntam1.iniQt1on t© bo^h water and land thpoygh porc^lation of sludge
liquor and unsettling ehara€ter1st1ei.§f ilydg© raater1§lB p
Scrubbir sludge is most aommonly disposed ©f through ppndlng and/or
landfill. For tn® 100=!^ txamplQ given above 0 about O.S acre of ponding at
a depth of 10 feet would be r@qu1r@d for sludgn dUspsgal pur year0 Sludge
ean also be dewaterid ©r stab11l2@d to f©ra i §01 •id ^or knielflll. Physical
itab1l'l2at1©n or fixation 1s required t© unsure that slydgQ dogs not regain
Its ©f1g1na1 watgr eentgnt. Altirnat1velyD Japan ha§ oxidised
corona re1 ally i^rketable gypsum fiber.
|nfrgy. 1mpaet°°The ultctrlelty needid to run F©0 prdcess iqyip?v©nt and
= i tae S~la § riheating requires about 3 t© S percent of a plant's
31
-------
gross energy input (Btu/hour). This penalty may or may not result in a
derating of plant capacity depending upon whether power production is turbine-
or boiler-limited. If a plant is turbine-limited, the excess steam from the
boiler can be used to reheat stack gases. Regenerable processes require addi-
tional energy for the sulfur recovery process. The additional energy require-
ment for the regeneration facility is approximately 3 percent of the total
heat input to the boiler for each of the three most common processes.
Cost of compliance—The costs of installing and operating a FGD system
are important constraints to application of this control strategy. Capital
costs for new installations vary from $60 to $100/kW depending upon plant
layout, FGD process design, unit capacity, plant location, amount of reheat
required, and other site-specific factors. Retrofit costs typically run 12
to 20 percent higher than new installation costs. In difficult retrofit
cases, installation costs could increase by 50 percent or more.
The remaining plant life and capacity factors are important since they
determine the number of kilowatt-hours over which the cost of the FGD system
can be amortized. For older plants with limited life and lower utilization
factors, high capital charges may be prohibitive.
For nonregenerable systems, annualized sludge disposal costs are esti-
mated at $7/kW. FGD operating and maintenance costs are estimated at 0.3 to
1.5 mills/kWh. With capital costs amortized over 20 years of remaining plant
life, the cost of compliance would typically range between 2.5 and 4.0 mills/
kWh. Average plant power production cost 1s about 20 mills/kWh, although
this cost is highly variable. Furthermore, since cost accounting is done on
a system-wide basis, the Impact on power production costs also must be calcu-
lated on a system-wide basis, with consideration of such factors as type of
plants, average capacity factors, and number of plants requiring FGD systerns;
Flujdjzed-bed Combustion—There are two types of fluidized bed combustion:
atmospheric-pressure systems and elevated-pressure systems. Both systems
employ a sorbent that reacts Immediately with sulfur dioxide formed in the
combustion process. The fuel 1s burned in a bed of granular, noncombustlble
material such as coal ash or Hme. A1r 1s passed up through a grid plate
under the bed, causing the suspension of granular bed particles. This air
serves as the combustion air. Fuel is Injected near the base of the bed above
the grid plate and burns very rapidly. Flue gases pass over an additional
heat transfer surface before being exhausted. Many fuels can be used in this
process, including municipal refuse.
Commercial aval lability—The atmospheric-pressure process 1s currently in
the pilot-plant design and construction phase, whereas the pressurized process
is just entering the demonstration plant phase sponsored by the Environmental
Protection Agency. Full-scale atmospheric utility boilers should be demon-
strated by 1979-1980; operation of the pressurized pilot plant should be
completed by 1982. Commercial availability of the atmospheric unit is pro-
jected in the time frame of 1981-1982. Vendor capacity should be at least as
great as that for conventional units since flu1dized-bed boilers are amenable
to a greater degree of shop fabrication.
32
-------
Effectiveness—Bench-scale and pilot-scale data Indicate sulfur dioxide ,.,
removal efficiencies of 90 to 95 percent. Flu1d1zed-bed combustion should
also be reliable since changes 1n the type of fuel burned 1n the boiler do not
affect the removal of sulfur dioxide.
Appl 1 cabl 11 ty—Flu1 d1 zed-bed boilers may have slightly broader appH-
catlon than conventional boilers due to low environmental Impacts and potential
to use a wide range of fuels. These units are principally applicable to new
Installations, although some limited specialized retrofit applications are
being considered. '
Environmental Impact—Environmental Impacts of fluidlzed-bed units are
positive In terms of sulfur dioxide, nitrogen oxides, and particulate emis-
sions. Nitrogen dioxide emissions can be controlled to 0.2 pound per million
Btu, well below the New Source Performance Standard of 0.7 pound per million
Btu. Preliminary Indications show that particulate emissions are more coarse,
and therefore are easier to collect. Emissions of carbon monoxide and hydro-
carbons are also low.
Energy Impact—The fluidized-bed boilers should generate power at least
as efficiently as conventional power boilers with scrubbers. Table 4-6 pre-
sents comparative estimates of overall thermal efficiencies.(5)
Table 4-6. THERMAL EFFICIENCY OF FLUIDIZED-BED.BOILERS
(percent)
Boiler type
Fluldized bed
Atmospheric
Pressurized
Conventional and stack
gas scrubber
First generation
36
38
37
Second generation
40;
47
: 37
'.*
Cost of compliance—Fluidized-bed boilers may offer a lower cost alter-
natlve to conventional boilers. Current estimates indicate that fluid1zed-bed
boiler systems offer an Installed capital cost saving of 15 to 20 percent over
conventional boilers with stack gas scrubbing. Table 4-7 details comparative
operating costs for fluldized-bed and conventional boilers'at a 635-MW plant
using 4.3 percent sulfur coal and operating at a load factor of 70 percent.(5)
To summarize, the Increment 1n cost of a fluidlzed-bed system over a new non-
controlled conventional coal-fired system, and hence the incremental cost of
compliance, would be 2.5 to 3.0 mills/kWh, which would be competitive with
flue-gas desulfurlzatlon at 2.5 to 4.0 m1lls/kWh.
NONCONTINUOUS STRATEGIES
Noncontlnuous compliance strategies rely on the dispersion capacity of
the air to meet ambient air quality standards. When meteorological condi-
tions cause a reduction In assimilative capacity, noncontlnuous strategies
33
-------
Table 4-7. COMPARATIVE OPERATING COSTS FOR CONVENTIONAL
AND FLUIDIZED-BED COAL-FIRED POWER PLANTS
(mills/kWh)
Cost category
Fixed charges
Fuel
Dolomite or
limestone
Operating and
maintenance
Total
Conventional
boiler,
once-through
TO. 45
8.20
0.10
0.99
19.74
Atmospheric-pressure
fluidi zed-bed boiler
Regenerative
9.88
9.18
0.05
0.86
19.97
Once-through
9.32
8.58
0.29
0.67
18.86
Pressurized fluidized-bed
boiler, combined cycle
Regenerative
8.74
8.68
0.12
0.90
18.44
Once-through
8.37
8.06
0.52
0.71
17.66
CO
-------
call for reducing emission rates of the source. Emission rates are varied
through fuel switching and load shifting. Tall stacks, which are normally
incorporated into load shifting or fuel switching "supplementary control
systems" are used to enhance the dispersion of pollutants;
The basic elements of a noncontinuous control system are air quality
monitoring, meteorological data, scheduled emission rates, a predictive air
quality model, and the necessary means to vary emissions. The monitoring
network is used as an indication of a potential air quality problem period,
as a source of data input to the model, and as a check on the effectiveness
of the strategy. The model also uses other Inputs to predict periods in
which emission rates should be varied. The reliability of these elements
largely determines the effectiveness of the noncontinuous control alternative.
In the discussion, "effectiveness" of these alternatives refers to the effec-
tiveness in assuring that ambient air quality standards are not violated.
Fuel Switching
Fuel switching requires a utility to provide for storage and firing of
an alternative low-sulfur fuel. The alternative fuel would be used when the
monitoring instrumentation and/or the predictive model indicated that air
quality standards would be violated under normal fuel operation.
Commercial Availability—All of the necessary components of a fuel switching
program are currently available. A certain amount of lead time, usually 1
to 2 years, Is required to set up the monitoring network and to develop and
refine the model. Changes in storage and handling facilities could require
1.5 to 2.5 years, depending on the magnitude of modification required.
Effectiveness—The effectiveness of fuel switching as a control strategy is
largely determined by the reliability of the prediction mechanism. System
reliability is dependent upon the accuracy of meteorological and emissions
forecasting, as well as air quality modeling. Control reliability can be
Improved through the Inclusion of a safety factor in the air quality thresh-
old value for initiating fuel switching. Control reliability would also be
expected to Improve as the predictive model is refined through operating
experience. Table 4-8 presents data on the operating experience of the
Tennessee Valley Authority's Paradise steam plant.
The time required to switch fuels, varying from 20 minutes for a dual-
flred plant with divided bunkers to 3 hours for a plant with no capability
to bypass coal already in the bunkers, also plays a role 1n effectiveness.
In general, noncontinuous strategies are most effective in attaining the
24-hour primary standard because of this time requirement. These methods
have been approximately 90 percent effective 1n meeting the 3-hour secondary
standard.(6,7)
35
-------
Table 4-8. RELIABILITY OF NONCONTINUOUS CONTROL SYSTEM AT THE TENNESSEE
VALLEY AUTHORITY'S PARADISE STEAM PLANT IN PROTECTING 3-HOUR AND 24-HOUR
AMBIENT AIR QUALITY STANDARDS9
Time period
Violations of 3-hour
secondary standard
(0.5 ppm)
Violations, 24-hour
primary standard
(0.14 ppm)b
Before control
(1/1/68 to 9/18/69)
After control
(9/19/69 to 3/31/74)
10
8
Based on Tennessee Valley Authority and Environmental Protection
Agency data.
At any of the 14 sulfur dioxide air quality monitors around the plant.
Appl 1 cabi 1 ity—AIthough fuel switching is technically applicable to a wide
range of plaints, application is limited by operational and practical environ-
mental considerations. Prolonged use of low-sulfur coal over 6 hours in /
boilers designed for high-sulfur coal reduces predpitator performance and
Increases .partlculate emissions. Increased slagging and decreased generator
capacity are also potential problems. However, interim use of low-sulfur
oil does not create these problems.
Practical enforcement considerations may dictate that fuel switching be
used on isolated plants so that the source of air quality violations is
Identifiable. In addition, fuel switching 1s not applicable to a rough ter-
rain that is not conducive to dispersion. Fuel switching is most readily
applicable to dual-fired plants due to the absence of need for boiler and
fuel-feed modifications and to the reduced time required for the switching.
Environmental Impact—The use of low-sulfur coal 1n boilers burning high-
sulfur coal can cause Increased particulate emissions and ash production.
This impact is negligible for control periods of less than 6 hours; the
small amount of increased ash does not create a disposal problem.
A more serious potential problem is the contribution of noncontinuous
systems to levels of suspended sulfate while they are burning high-sulfur
fuels. Some of the sulfur dioxide and hydrogen sulfide emitted is converted
to sulfate, and Environmental Protection Agency assessments show that existing
sulfate concentrations in some areas of the country may adversely affect human
health. However, national ambient air quality standards for acid sulfate
aerosol have not been set. For the present, continuous control of sulfur
dioxide emissions is thought to be the best approach to sulfate control, but
additional researches needed to determine an optimal approach. EPA believes,
however, that a number of Isolated power plants can use supplementary control
systems, which require additional emission reduction on an intermittent basis,
as an interim strategy for a number of years without increasing the risk to
public health.
36
-------
Energy Impact—The most significant energy impacts of this alternative are
transportation and use of the low-sulfur fuel. In general, intermittent use
cf low-sulfur fuel represents an efficient use of a scarce and enerc(y-
intensive fuel.
Cost of Compliance—The cost of a fuel-switching program includes capital
expenditures for 1nstal1at1on, operating expenses, and extra surveillance
and enforcement costs to the control agency. Capital costs for a 7'50-MW
boiler are estimated at $16/kW. While operating costs would vary consid-
erably among installations, a reasonable annualized cost estimate might be
0.5 to 1.0 mills/kWh. If low-sulfur oil is the auxiliary fuel, an additional
cost of boiler conversion and storage facilities would be necessary for a
coal-fired plant not equipped to burn low-sulfur oil. This cost would range
from $12/kW to $40/kW for large and small units, respectively.
Load Shifting
Load shifting is a procedure that reduces the rate of emissions from a
specific plant by shifting scheduled generation to another plant on an Inter-
connected electrical transmission system. This system is similar in concept
and operation to the fuel-switching system.
Commerci al Aval 1abi1ity—The components of a load-shifting program correspond
to fuel-switching requirements and are commercially available. Lead time to
develop the predictive system is also similar. Additional system capacity
could be required, and transmission lines may need to be constructed. Time
requirements vary from 1 to 4 years according to the magnitude of the modi-
fication and institutional arrangements necessary. It is currently common
practice to use load shifting for other reasons, such as forced outages.
Effectiyeness—Problems with the reliability of the predictive mechanism are
parallel for load shifting and fuel switching. In addition, allowances must
be made in the transmission system and generating reserve for concurrent load
reductions and/or frequent shift requirements. The reliability can be
increased by Incorporating the additional potential to switch fuels or use
tall stacks. Emission reduction from load shifting may require from 30
minutes to 2 hours to accomplish.
Applicability—Load shifting is generally more suitable on a system with a
greater number of generating units for a given installed capacity; in the
event of forced outage, a small amount of capacity 1s out of service at one
time. This method is also less applicable to locations where numerous plants
were built 1n close proximity or locations where a large percentage of total
capacity 1s subject to areawide air pollution episodes.
Environmental Impact—Environmental Impacts of load shifting may be greater
than those of fuel switching because of the necessary acreage for trans-
mission line construction and because of possible construction requirements
for additional generation units. Other environmental impacts parallel those
mentioned under fuel switching.
37
-------
Energy Impact—Energy requirements will vary depending upon the units involved
in the load shift and upon transmission system losses. Additional energy
input requirements are not considered to be a problem.
Cost of Compliance—The cost of a load-shifting operation varies with the
number of generating plants whose loads must be shifted. The principal
components of this cost are program development, additional reserve gener-
ating capacity, addition of transmission capacity, and displaced pov/er cost.
Program development is estimated at $200,000 to $600,000. Additional reserve
capacity costs, depending on the type and size of unit, are from $80 to $100/
kW less than the average cost of original capacity. Transmission costs are
$200,000 per gigawatt (1000 MW) per mile at an operating cost of $200 per
mile. The cost of displaced power is about $500 per hour. This figure
assumes a load shift of 100 MW with a cost difference of 5 mills/kWh.
Tall Stacks
A stack whose physical height exceeds that required to eliminate the
effects of local terrain on plume rise is classified as a tall stack. These
stacks are designed to prevent high ground-level pollutant concentrations in
the vicinity of the source, and can considerably alter 'the dispersive charac-
teristics of the plume. " "
Commercial Availability—The current annual construction rate is 10 to 20
per year. Complete construction requires 4 to 5 months-, and neither manpower
nor materials are currently constraints to construction.
Effe cti veness—Whi1e tall stacks are effective in reducing the severity and
number of excess pollutant concentrations near the source,, they distribute
emissions over a larger area and add to the overall pollutant burden. Load
switching in combination with tall stacks yields increased availability of
generators, but as indicated earlier, it is difficult to define accurate
criteria for determining when load switching should occur. Tall stacks dp
present the advantage of 100 percent availability. Both of the discussions
below also include issues that limit the effectiveness of this approach.
Applicability—The number, height, size, and distribution of both terrain
and buildings that affect dispersion determine the applicability of tall
stacks. In addition, other considerations, such as structural requirements
in earthquake-prone areas or height restrictions in airport flight patterns,
are practical limits.
Environmental Impacts—While tall stacks may generally prevent high ground-
level pollutant concentrations, there are meteorological circumstances that
inhibit their effectiveness. Atmospheric inversions frequently limit upward
dispersion even when emission occurs at a high level; tall stacks provide no
control mechanism for such occurrences. Persistent wind direction can also
cause long-term impact on a limited area. The sulfate problem is also of
concern with tall stacks because such stacks disperse sulfur oxide emissions
over a larger area rather than reducing atmospheric emissions.
38
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Energy Impact—Tall stacks require no additional energy expenditure and, due
to additional draft provided, may reduce the plant's overall energy requirement.
Cost of Compliance—Costs of tall stacks are figured in terms of thousands of
dollars per foot of stack height. Current costs range from $3500 to $7000/
foot, depending on company and construction method. A 1000-foot stcck would
probably cost roughly $6 million. The amortized cost for a large boiler would
run approximately 0.15 to 0.30 mills/kWh.
ENERGY RECOVERY FROM SOLID WASTES
In 1973, about 135 million tons of solid waste per year were generated
by residential and commercial sources in the United States. About 70 to
80 percent of that waste was combustible and convertible to energy.
Not all waste is available for energy recovery. Because energy recovery
systems must be large enough to achieve enconomies of scale, energy recovery
appears feasible only in more densely populated areas, such as Standard
Metropolitan Statistical Areas. If energy recovery had been practiced 1n all
such areas in 1973, the equivalent of almost 425,000 barrels of oil per day
(bbl/day) could have been saved. This is a significant amount of energy.
For example, 425,000 bbl/day is equivalent to 10 percent of all the coal used
by electric utilities 1n 1973 and is enough energy to light every home and
office in the nation. More significantly, solid waste can satisfy large
percentages of the energy needs of individual users, such as Industrial
plants, thereby reducing dependence on fossil fuels.
Based on energy recovery systems planned or under development at the
present time, it 1s projected that by 1980 energy recovery systems should be
operating 1n almost 30 cities and counties and recovering the equivalent of
40,000 bbl/day, assuming continuation of current levels of Federal financial
and technical assistance. With greatly expanded levels of Federal assistance,
this projection could be as high as 236,000 bbl/day. The following discussion
covers energy recovery systems that are available or under development,
associated environmental Impacts, and the economic issues.
Availability of Technology
Solid waste disposal systems must be operationally reliable and involve
a minimum of technical risk. Furthermore, such systems must operate at a
reasonable cost without degrading the environment. Risk and reliability are
usually evaluated through examination of existing full-size systems 1n actual
operation. Although no technology is presently risk-free, two energy recovery
methods are commonly considered "commercially available." Other, and
possibly better, methods are presently being developed and are projected to
become commercially available throughout the 1977 to 1982 time period.
39
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Available Methods—The methods commercially available include: (1) the
generation of steam (for district heating and cooling or for industrial
processing) in a waterwall incinerator fueled solely by unprocessed solid
waste and (2) the use of prepared (shredded and classified) solid waste as a
supplement to pulverized coal 1n electric utility boilers. There are many
existing waterwall incinerators in the United States, and new steam genera-
tion systems are being built in Nashville, Tennessee (district heating and
cooling) and in Saugus, Massachusetts (industrial process steam). The use of
prepared solid waste as a supplementary boiler fuel is being demonstrated in
St. Louis, Missouri with demonstration grant support from the Environmental
Protection Agency and with the cooperation of and additional funding by the
Union Electric Company. Several other supplementary fuel systems are being
implemented by communities across the country, including Chicago, Illinois;
Bridgeport, Connecticut; Ames, Iowa; Wilmington, Delaware (with Environmental
Protection Agency demonstration grant support); and Monroe County, New York
(Rochester area).
These methods are defined as commercially available because they have
been demonstrated in large-scale facilities and because private industry is
offering these technologies for sale. Waterwall incinerators are already in
widespread use in this country. While there is little risk of technical
failure, the long-term reliability of these systems has not yet been estab-
lished. Solid waste has been used as a supplement to coal or oil in steam or
electric boilers in Europe for about 20 years. However, the practice is
relatively new in the United States, because, unlike European boilers, most
steam-electric boilers in the United States fire fuels in, suspension, re-
quiring that solid waste be processed before it is fired as a supplementary
fuel in the boiler. The St. Louis project has provided the only experience
with this technology. While several other cities, are Implementing similar
systems, to date there has been relatively little experience in this area.
Consequently, until more systems are built, there will still be some risk
associated with implementing such energy recovery systems.
Developi ng Technology--0ther, and possibly better, methods are presently
being developed.Pyrolysis, which converts solid waste into gaseous or liquid
fuels, is being demonstrated with Environmental Protection Agency demonstra-
tion grant support in Baltimore, Maryland, and San Diego County, California,
and, without agency grant support, in South Charleston, West Virginia.
These systems are expected to become fully operational during the 1975 to
1977 time period and commercially available during the 1977 to 1980 period.
In addition to pyrolysls, the production of methane gas through con-
trolled biological decomposition (anaerobic digestion) of solid waste is about
to be performed at pilot-plant scale. Commercial implementation of this
technology is projected for the 1980 to 1982 period.
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Environmental Impact
The Impact on the environment of implementing systems to recover energy
and materials from solid waste can be assessed in two areas:
1. Avoidance of solid waste disposal impacts.
2. Environmental impact of energy recovery facilities.
Solid Waste Disposal—Communities in the United States usually process and
dispose of waste in the following ways:
1. Open dumping of solid waste on the land is the most prevalent
and cheapest method used in the United States. Open dumps
cause pollution of ground water through leachate and air pol-
lution through open burning. In addition, dumps are notorious
as breeding grounds for disease carrying vectors.
2. Conventional incineration can reduce the volume of municipal
solid waste for disposal by as much as 90 percent. However,
residue is frequently put in open dumps and not disposed of
properly. Most Incinerators were built before today's air
quality standards were implemented; consequently, they are
unable to meet the requirements of the Clean Air Act of 1970.
New incinerators can meet air quality standards but are very
expensive in the absence of revenues from steam sales to off-
set costs.
3. Acceptable land disposal of solid waste involves dumping of raw,
baled,"or shredded waste in a manner that safeguards against
adverse environmental and health effects. Operation is relatively
inexpensive.
Waste management is a choice between two options: disposal (in the three
forms described) or recycling. If the wastes cannot be returned to the
economy, they must go back into the environment, the consequences of which
are still only vaguely understood. Land deposition of wastes exposes them
to natural mechanisms. Rain soaks into disposal sites until, like a
saturated sponge, the site can hold no more. At that point, leachate
develops and, loaded with pollutants picked up from the waste, it percolates
through the soil toward groundwater acquifers (the drinking water of nearly
half the population) or runs off into rivers and lakes.
Where precipitation rates and groundwater tables are high, leachate
formation presents a potentially serious problem. Too little is known today
;about the ability of soil to purify leachate before or after 1t reaches
'acquifers; it is known that wells have been polluted by leachate. Typical
leachate contains chemicals and minerals in concentrations too high for
drinking water.
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Conventional sanitary landfilling techniques .minimizV;the impact of
leachate generation. In some areas, however, more control may be needed,
including leachate collection and treatment (techniques are not well
developed). But the most disturbing fact is that, ofVthe nation's/17,000
to 20,000 disposal sites, only a handful qualify as sa^tary landfills in
a true sense, where site selection, operation, and monitoring all contri-
bute to acceptable land disposal practices. Methane gas nxjgration from ,
land disposal sites, sublimation of toxic chemicals into the atmosphere,
and open burning of wastes are other examples of environmental degradation ',•-
from poor solid waste disposal practices. \ 'V
v\ \
Although land disposal will always be necessary, energy recovery, when
combined with recovery of recyclable materials, can reduce disposal^require-
ments up to 90 percent and can have a significant role in reducing the pol-
lution from inadequate disposal practices. \
Energy Recovery Facilities—The environmental impact of energy recovery
facilities will vary with different energy recovery systems, which can be
analyzed in two parts: feedstock preparation and energy conversion. Feed-
stock preparation refers to the handling (receiving, conveying, and storage)
and processing (shredding, pulping, and classification) that prepares the
waste for energy conversion. Energy conversion refers to the chemical
process (combustion, pyrolysis, or biodecomposition) that converts the waste
into energy.
Feedstock preparation—Feedstock preparation Involves receiving, size
reduction (shredding or pulping), classification, and storage facilities.
Potential emissions to the air, water, and land, including noise and odor,
are similar to other light Industry and can be controlled by relatively
simple techniques. The most significant emissions are: (1) dust emitted to
the air from cyclone separators, (2) water-borne contaminants resulting from
wash-down of waste-handling areas, (3) noise from delivery truck traffic and
from processing equipment, and (4) odors. These emissions are controlled,
respectively, by dust collectors, filters and discharge to sanitary sewers,
selective routing of trucks and enclosures for equipment, and enclosures for
all areas handling waste.
Energy conversion—There are four predominant types of energy conver-
sion units: (1) waterwall incinerators, (2) power plant boilers, (3) pyrolysis
reactors, and (4) anaerobic digestors for production of methane gas.. Water-
wall Incinerators are subject to, and can be designed to meet, New Source
Performance Standards. The other types of units are not now subject to such
standards or have not been tested for compliance at full scale.
Power plant boilers firing solid waste in combination with fossil fuels
are not now subject to New Source Performance Standards. The standards under
development for such facilities will not constitute an impediment to the in-
creased use of solid waste as a fuel. Emission tests have been conducted at
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one location to date, Union Electric Company's Meramec Plant, where solid
waste 1s burned with coal as part of the Environmental Protection Agency's
solid waste energy recovery demonstration grant to the city of St. Louis.
The tests Indicate that:
1. Particulate emissions increased slightly when solid waste was
fired with coal, probably because of decreases in the efficiency
of the electrostatic precipltator. There was no discernible
change in particle size or resistivity. Decrease in precipi-
tator performance may result from increases in gas velocity and
changes in precipltator electrical conditions (spark rate).
2. Gaseous emissions (sulfur oxides, nitrogen oxides, hydrogen
chloride, and mercury vapor) were not significantly affected
by combined firing of waste and coal.
3. Uncontrolled particulate emissions per cubic foot of exhaust
gas were not changed by combined firing; however, total uncon-
trolled partlculate emissions did Increase because of increases
in the gas flow rate.
4. Additional air pollution testing is required to complete the
characterization of particulate emissions resulting from com-
bined firing.
Additional tests will be conducted 1n late 1974 and early 1975. The test
results will be available 1n the spring of 1975. If preliminary indica-
tions of Increased particulate emissions are confirmed, an Increase in the
capacity of the pollution control devices will be required.
Pyrolysis reactors were developed to convert waste to energy using little
or no ambient (excess) air, thus minimizing or precluding any discharge of
gases to the environment. Test of pilot-scale systems Indicate that New
Source Performance Standards can be met; all full-scale systems will be
required to meet the standards for incinerators.
Anaerobic dlgestors have not been developed on a scale large enough to
test the potential air and water emissions. Based upon laboratory experience,
however, air emissions appear to be negligible, and water emissions appear
to be controllable.
Economics of Energy Recovery
Energy recovery must compete with the three other processing and disposal
methods mentioned earlier: open dumping, conventional Incineration, and
sanitary landfUHng. Capital Investment would be $15 to $30 million for a
plant designed to process 1000 tons of solid waste per day. Operating
costs ($10 to $15/ton, Including amortization) can be offset by revenue
from sale of energy and materials ($4 to $12/ton) and by disposal fees.
Thus, for a reasonable capital Investment, energy recovery can compete
economically with other environmentally sound disposal methods.
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Already some communities, especially densely populated areas, have
estimated that energy recovery would cost less than their present disposal
method. Moreover, trends in relative economics favor energy recovery, as
indicated by the following considerations:
1. Enforcement of land disposal regulations by State and local
governments is expected to become more vigorous. This will
tend to eliminate open dumping and to increase the cost of
land disposal.
2. Increasing land costs and citizen opposition to land disposal
in urban areas will tend to push landfills farther from centers
of waste generation, thus necessitating additional transporta-
tion, an increased cost.
3. Rising costs of energy and materials will increase the potential
for revenues from an energy recovery system.
4. Installing air pollution control equipment on incinerators
appears to be very costly. Very few incinerators have been
upgraded or built in the past 10 years.
5. Innovations in technology are expected to make available
systems less expensive and to result in more economical alter-
natives.
Even where energy recovery does cost more than land disposal, economic
cost is not the only consideration. Several communities have already
elected to pay more for energy recovery than their current disposal costs
because it represents a positive step in the direction of environmental
protection and resource conservation.
REFERENCES FOR CHAPTER 4
1. Draft Report on Steam Coal Availability. Sobotka and Company, Inc.
Stamford, Connecticut. October 1974.
2. Oglesby, S. and G. B. Nichols. A Manual of Electrostatic Precipitation
Technology. Southern Research Institute. Birmingham, Alabama. 1970.
p. 369.
3. Ad Hoc Panel on Evaluation of Coal-gasification Technology: Part II,
Low- and Intermediate-Btu Fuel Gases. National Academy of Engineering-
National Research Council, Division of Engineering. Washington, D. C.
1973.
4. Perry, H. Coal Conversion Technology, Chem. Eng. 81:88-102, July 22,
1974.
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5. Assessment of Alternative Strategies for the Attainment and Mainten-
ance of National Ambient Air Quality Standards. Pedco Environmental
Specialist, Inc. Cincinnati, Ohio. December 1974.
6. Gaertner, J. P. et al. Analysis of the Reliability of a Supplementary
Control System for Sulfur Dioxide Emissions from a Point Source.
Environmental Research and Technology, Inc. Lexington, Massachusetts.
Project Report 0669. June 1974.
7. Preliminary Assessment of Alternative Sulfur Oxide Control Strategies
for TVA Steam Plants. Prepared jointly by Environmental Protection
Agency and Tennessee Valley Authority. June 1974.
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CHAPTER 5
FACTORS AFFECTING COMPLIANCE
The review of the status of compliance with environmental regulations of
coal-fired power plants that 1s given in Chapter 3 of this report is based
on announced changes 1n fuel requirements and on a projected rate of con-
struction of new facilities. A number of other factors could affect com-
pliance, however, including possible conversions of power plants from oil
to coal, decreased demand for electricity through 1980, nonutility demands
for coal, and curtailments 1n allotments of natural gas. These issues
are discussed below, largely 1n qualitative terms.
This section of the report also covers the various allocation authorities
of Federal agencies that must coordinate energy resources and demands with
environmental needs. This brief discussion covers the nature of these author-
ities and their use and issues related to the new authorities provided by the
Energy Supply and Environmental Coordination Act.
CONVERSIONS FROM OIL TO COAL BY ELECTRIC UTILITY PLANTS
The Federal Power Commission has estimated that plants having 24,000 mega-
watts of steam electric generation capacity had converted from coal to oil by
the end of 1974. These plants presently account for nearly 40 percent of the
heavy oil consumption by electric utilities 1n the United States. Many of
these plants, which are located largely on the east coast, had converted
because of the availability of low-cost, Imported oil. Restrictions on the
sulfur content of fuels issued pursuant to local laws and the Clean Air Act
have provided major Incentives 1n recent years for plants to switch from
coal to oil.
Two factors of recent origin will probably tend to reverse this trend
toward the use of oil. One factor is the sharp rise in oil prices over the
last few years from $3 per barrel for residual oil to $10 to $12 per barrel.
This price shift will create strong economic incentive for plants to switch
back to coal. The second factor is the passage of the Energy Supply and
Environmental Coordination Act, which authorizes the Federal Energy Adminis-
tration to prohibit the use of oil and natural gas as the primary energy
sources for electric utility plants.
Although the number of plants that may switch back to the use of coal is
unknown at this time, these plants clearly constitute a potentially significant
addition to the demand for coal. Since these units are exempted from New
Source Performance Standards by Section 119 (d) (5) of the Clean Air Act, they
would have to comply with State Implementation Plan regulations not later than
January 1, 1979. The maximum potential Impact of their reversion to coal would
46
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amount to additional coal demands of 40 to 50 million tons per year by 1980 if
all plants went back to the use of coal. The range, 40 to 50 million tons,
reflects different degrees of utilization of the power-generating capacity of
the reconverted plants.
Shifting these plants back to coal will create new demands for low-sulfur
coal and sulfur removal equipment, inasmuch as the majority of these plants are
located in regions having more restrictive regulations on the sulfur content of
fuels than those that affect most existing coal-fired plants. The maximum
demand for low-sulfur coal would occur if all reconverting plants relied upon
the use of low-sulfur coal rather than flue-gas desulfurization to meet emis-
sion limitations. To illustrate this maximum demand for low-sulfur coal, the
respective capacities of reconverted plants (24,000 megawatts total) were
classified by currently applicable State Implementation Plans to determine the
allowable sulfur content of the coal that would be needed. The results are
shown in Table 5-1.
Table 5-1. ESTIMATED COAL DEMAND BY SULFUR CONTENT
FOR STEAM ELECTRIC POWER PLANTS RECONVERTING FROM OIL
Sulfur content of coal,
percent sulfur by weight
<0.7
0.7 to 1.5
1.5 to 3.0
>3.0
Amount of coal ,
million tons/year
21.6
21.8
5.4
1.2
50
Percent
of total
43.2
43.6
10.8
2.4
100
The actual demand for low-sulfur coal will undoubtedly be less than shown
in Table 5-1, however, for two reasons:
1. Plants that face the most stringent sulfur regulations in order
to be in compliance may not convert to coal at all.
2. Use of sulfur removal equipment will permit the use of higher-
sulfur Appalachian coal.
Although neither the overall quantity nor quality of coal required for the
conversion of some of these plants can yet be accurately predicted, reversion
to use of coal by a significant number of these plants, especially by plants
governed by stringent sulfur regulations, would add to the demands for low-
sulfur coal and for sulfur removal equipment.
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COAL REQUIREMENTS IN NONUTILITY SECTORS
Rising oil prices and the lack of availability of natural gas is likely
to boost the use of coal by 1980 in industries that consume large amounts of
fuel. Table 5-2 illustrates the uses of coal in 1973.
Table 5-2. COAL DEMAND IN 1973 BY SECTOR
Use
Electric power plants
Coke plants
Industries (other than
coke plants) and
retail sales
Export sales
Total
Millions of tons
388
94
79
53
614
Percent
of total
63.2
15.3
12.9
•8.6
100.0
Of the total demand, 24 percent was largely for low-sulfur, metallurgical coal
for use 1n the steel Industry or for export. Only 13 percent, or roughly 80
million tons, was steam coal used by Industrial and commercial establishments.
The most recent projection of nonutility demand for coal was made by the
Federal Energy Administration 1n their Project Independence Blueprint. In that
study, the projected Increase 1n nonutility demands was only 15 million tons
by 1980; however, this estimate would appear to be too low.
Coal for export is expected to remain roughly at present levels. Demand
by the steel Industry for coking coal depends on the rate at which output is
expanded, the amount of energy conserved in blast furnace operations, and
whether the past trend toward substitution of oil and natural gas for coke
will be reversed. A rough estimate of coking coal demand may be derived by
assuming that 1t grows at the same pace as steel output, which is forecast by
the American Iron and Steel Institute to Increase 2.5 percent per annum.
Coking coal needs would then grow to 112 million tons by 1980, which is 18
million tons more than was used 1n 1973 (Table 5-2).
Combustion uses of coal amounted to 79 million tons in 1973, which
reflects a continuing decrease resulting from economic factors and environ-
mental restrictions. Whether these industrial and commercial users will need
more coal 1n the future 1s purely conjectural. Industrial uses provide
another area 1n which reconversion to coal could result in a substantial
Increase by 1980 1n the demand for coal. A recent estimate Indicated that
combustion coal demands could Increase by as much as 28 million tons by 1985
1f industrial boilers that once used coal were to use coal again. As in the
case of utility boilers, this potential will not fully be realized because of
economic and environmental constraints.
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Although precise estimates of nonutmty coal demand cannot be made, it
1s important to recognize that the 37 percent of coal supplies used for non-
utility consumers (Table 5-2) tends to be very low in sulfur content. Sixty-
five percent of nonutility demands is largely in the form of metallurgical
quality coal, which must also be very }o\fi in sulfur content. In addition,
Industrial and commercial uses of steam coal tend to be subject to stiff sulfur
restrictions.
Thus, nonutility uses of coal constitute a potentially important source of
demands on the nation's capacity to provide low-sulfur coal. Because indus-
trial boilers are generally too small to be outfitted economically with flue-
gas desulfurizatlon systems, these nonutHUy demands gain added significance.
Therefore, added demands by these nonutility consumers will tend to increase
the consumption of low-sulfur coal.
COAL REQUIREMENTS FOR THE ELECTRIC UTILITY INDUSTRY
A
Chapter 3 of this report reviewed the status of compliance with regula-
tions Issued pursuant to the Clean Air Act that are In force through 1980.
However, coal requirements for utilities depend, initially on the rate of
growth In electricity demand, the rate of installation of nuclear electricity-
generating capacity, the availability and price ^f natural gas and oil, and
the availability and price of coal. The Interplay,, of these factors will
determine the actual demand for coal by electric pqwer plants,''
\
Impact of Changes in Demand for Electricity •
Generation of electric power has historically grown at a ratfe of approxi-
mately 7 percent per annum. The most recent estimatja by the Technical Advisory
Committee to the Federal Power Commission projected a demand for electricity
equal to 3245 billion kilowatt hours (kWh) 1n 1980 compared with the 1973
demand of 1844 billion kWh. Recent experience suggests, however, that these
forecasts were much too high. Based on nearly complete data for 1974, the
Federal Power Commission estimates that power generation in 1974 was about
0.6 percent less than in 1973. If power growth resumes its historical growth
pattern in 1975, power generation will be 2855 billion kWh by 1980. No one
yet knows the impact skyrocketing energy prices will have on the demand for
electricity. Should the conservation ethic continue to prevail, then demand
for electricity could be even lower by 1980. This could lead to a slower rate
of growth in coal demand by electric power plants.
Impact of Expansion of Nuclear Power Plant Capacity
Several years ago, experts predicted a rapid expansion of nuclear capa-
city by 1980. It was anticipated that 125,000 megawatts of nuclear capacity
would be operating at a baseload level of 80 percent of capacity by 1980.
Instead, the Atomic Energy Commission is now projecting a probable level of
69,000 megawatts of nuclear capacity in 1980. Furthermore, operating problems
have plagued existing installations so that projected 1980 levels of power
production are 55 to 57 percent of capacity, instead of 80-percent.
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A number of policy measures are now being considered that would reinstate
time tables for delayed construction of nuclear plants, which would boost
capacity to over 100,000 megawatts by 1980. Operating performance of nuclear
power plants is also expected to improve. These measures could increase
power from nuclear generation in 1980 by 220 billion kWh. A great deal of any
expansion that occurs in power generation by nuclear plants will probably
replace power generation from coal-fired plants. The recent Project Indepen-
dence Blueprint analysis by the Federal Energy Administration indicated that
expanded use of nuclear fuels to generate power would largely displace coal.
This would reduce the load on existing coal-fired plants and would apply pres-
sure to delay construction of some new coal-fired plants. It is clear that
expanded nuclear-fueled power plants will not simply replace oil-fired power
plants since many nuclear power plants would be part of utility systems that do
not rely on oil. Recent estimates by the Federal Power Commission indicate
that at least half of the potential 30,600 megawatts of nuclear capacity that
might be accelerated to become operational by 1980 is located in utility systems
that do not use oil.
One factor that would militate against expansion of nuclear power-gener-
ating capacity 1s the serious financial situation faced by many utility
systems. The slower growth in demand for electricity (discussed in the previ-
ous section) jeopardizes future utility earnings and makes it difficult for
utilities to meet existing debt service commitments. Thus, utilities are
tending to delay large financial outlays for new electricity-generating capa-
city, especially for nuclear-fueled capacity with its much higher capital
costs. This has led some utilities to choose coal-fired capacity, which is
cheaper and more reliable. These actions will stimulate the demand for coal
and Increase requirements for low-sulfur coal and sulfur removal equipment.
Impact of Natural Gas Shortages
Natural gas 1s a premium fuel that has accounted for roughly 22 percent of
the energy used by the electric utility Industry. However, the regulated
pricing system for natural gas has led to declining production rates. It is
anticipated that natural gas supplies available to the utility industry will
decline during the 1970's. Under the current gas curtailment system, utilities
are the lowest-priority customers for this premium fuel and thus will feel
the brunt of supply shortages. Even if prices were to be deregulated and/or
leasing of natural-gas-rlch offshore tracts speeded up, it 1s doubtful
that new supplies would be sufficient to offset the declining trend until the
early 1980's. Gas consumption by utilities is already dropping at an alarming
rate, having declined from about 4 trillion cubic feet in 1972 to an estimated
3.3 trillion cubic feet 1n 1974. Forecasts by the utilities and by government
agencies indicate that further declines 1n natural gas usage to 2.2 to 2.5
trillion cubic feet by 1980 can be anticipated.
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The lack of availability of natural gas, even to maintain existing power
plant capacity, will lead to efforts by the utilities to shift power loads to
other fuels, especially coal and nuclear fuels. This shift could accelerate
the construction of new coal-fired plants (which have to rnest New Source
Performance Standards) and will certainly tend to raise capacity utilization
factors (and coal usage) in existing coal-fired power plants.
If the shortage in natural gas is as serious as the forecasts would indi-
cate, this shift to coal could result in significant increases in sulfur and
particulate emission loadings in localized areas that are hard hit by natural
gas curtailments. It is Important to recognize that the sulfur regulations
adopted by the States and approved by the Environmental Protection Agency in
1971-1972 were predicated upon increased usage of natural gas. Substitution
of coal for gas can lead to significant increases in emissions, thus jeopar-
dizing the effectiveness of the environmental regulations in achieving ambient
air quality goals. As curtailments occur, the Environmental Protection Agency
will have to reevaluate the adequacy of the regulations, especially those for
sulfur.
USE OF ALLOCATION AUTHORITIES: EMERGENCY PETROLEUM ALLOCATION ACT
AND ENERGY SUPPLY AND ENVIRONMENTAL COORDINATION ACT
Oil Allocations
There are three authorities through which the environmental impacts of oil
shortages can be addressed. The Emergency Petroleum Allocation Act authorizes
the Federal Energy Administration to allocate oil by its quality characteris-
tics, such as sulfur content. To our knowledge, this authority has never been
used explicitly by the Federal Energy Administration. However, during the Arab
oil embargo, the Environmental Protection Agency and the Federal Energy Admin-
istration established a system by which to monitor the sulfur content of oil
delivered to utilities, providing a basis for allocations by sulfur content if
necessary. When viewed 1n conjunction with reduced fuel usage during the
embargo, the greater use of fuels with higher sulfur content did not seriously
jeopardize air quality.
The Federal Energy Administration in April 1974 issued Section 215 of its
regulations under the Emergency Petroleum Allocation Act, which prohibits
coal-fired sources from converting to oil unless health standards will be
jeopardized or undue economic hardships will occur as a result of continued
use of coal. Exceptions may be granted only when suitable alternative fuels
are not available and a State certifies that the use of petroleum is essential
to meet health standards. This regulation continues to be, along with Section
119 of the Clean A1r Act, a regulatory check on the energy Implications of
compliance with the Clean Air Act.
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Fuel allocation authority has been granted under the Energy Supply and
Environmental Coordination Act to minimize harmful environmental effects of
fuel combustion. Insofar as this authority relates to oil allocation, it
provides a mechanism through which the Environmental Protection Agency could
initiate allocations on the basis of the sulfur content of oil. It also makes
explicit (and provides a further legal basis for) the authority of the Federal
Energy Administration to exercise its existing authorities under the Energy
Supply and Environmental Coordination Act to allocate oil on the basis of
sulfur content.
This allocation authority would be used in the event of another fuel-oil
crisis to ensure that areas with poor air quality do not become the dumping
ground for poor-quality imported fuel oil. This authority obviously must be
adapted to the existing oil distribution system. Residual oil would probably
be the most Important fuel to reallocate by sulfur content, should such reallo-
catlon become necessary. From a logistical standpoint it ivill also be the
most practicable since 90 percent of the heavy oil used on the east coast is
Imported and, therefore, can be reallocated by diverting oil tankers.
Coal Allocations, Fuel Exchanges, and Control Equipment Deliveries
New authorities relating to coal were provided by the Congress in the
Energy Supply and Environmental Coordination Act. These relate to fuel
exchange orders for coal, authority delegated to the Federal Energy Adminis-
tration for coal allocation, and discretionary authority to set priorities for
deliveries by manufacturers of sulfur removal equipment.
It is clear that real location of coal would be far more complicated and
difficult than similar actions for petroleum products, as the following reasons
Illustrate:
1. Coal mines are normally opened on the basis of long-term
contracts for most of the expected production. If coal
is reallocated, these contracts will become problematic
and will have to be broken or transferred.
2. Coal supply systems are far more inflexible than oil supply
systems. It will be logistlcally difficult to redirect supplies.
3. Access to Information from coal suppliers will be more
difficult to obtain than from oil suppliers because of
the multiplicity of producing companies.
4. Differences in coal quality are far more important than
differences in oil quality, for coal gives rise to multiple
pollutants and has many combustion properties that vary
significantly.
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If exchange orders were Invoked to minimize environmental problems resulting
from coal conversion, logistical problems would be minimized 1f the swap were
made with a nearby plant, preferably owned by the same utility company to
minimize force majeure problems. Unfortunately, most of the plants capable of
fuel switching are in the Northeast where relatively little coal 1s now being
used.
The Environmental Protection Agency does not presently believe that its
discretionary authority to set priorities for the delivery of sulfur removal
equipment should be used. In order to assure that the national ambient air
quality standards for sulfur dioxide are attained in an expeditious manner
commensurate with the availability of low-sulfur coal and flue-gas desulfuri-
zation systems, the Environmental Protection Agency is concentrating its
enforcement efforts on power plants in violation of the primary standards. As
shown 1n Chapter 3, approximately 150 million tons of coal 1s expected to be
consumed by plants that are involved in litigation or that will not be in
compliance with State Implementation Plan requirements for sulfur dioxide by
the specified attainment dates. Of this total, the Environmental Protection
Agency has so far Identified about 90 plants, having a total capacity of about
68,000 megawatts, that probably do not meet primary standards. Two-thirds of
these plants, with total coal-fired electricity-generating capacity of about
50,000 megawatts, will need to reduce sulfur dioxide emissions substantially,
by means of flue-gas desulfurization or the use of low-sulfur coal. The rest
of the plants can attain the standards by using coal having moderate sulfur
content or by using techniques such as coal washing or blending.
USE OF ENFORCEMENT AUTHORITY: CLEAN AIR ACT
Exercising Its authority under Section 113 of the Clean Air Act, the
Environmental Protection Agency intends to issue enforcement orders that
include schedules for achieving compliance in an expeditious but reasonable
time. In some cases, these orders may run beyond the attainment dates speci-
fied 1n the applicable State Implementation Plans 1f earlier compliance is not
possible, with adequate Interim requirements to minimize the adverse effects
on human health of the extended period of noncompllance. Earlier this year the
Administrator submitted proposals for revising the Clean Air Act that included
a provision which clarifies the authority of the Environmental Protection
Agency to issue enforcement orders extending beyond the approved attainment
dates. In Implementing enforcement policy, the Agency is attempting, to the
maximum extent possible, to allow for the time actually required to comply,
Including considerations of control system design and lead times and the
capacity of manufacturers to supply flue-gas desulfurization systems. The
relative Impact of the power plants on air quality 1s also taken into account.
Plants that will come into compliance by switching to low-sulfur coal without
plant modifications will normally be given less time than plants using flue-
gas desulfurization systems. If flue-gas desulfurization is the compliance
technique, adequate time is allowed for the utility to phase-in the scrubbers
on each unit. In the case of a second generation system with which there has
been little operating experience, the Agency will allow adequate time at the
front end of the schedule for the company to gain the experience required with
a prototype unit before installing the additional units.
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A good example of this approach can be seen in the consent agreement
signed between the Environmental Protection Agency and the Philadelphia
Electric Company for the installation of magnesium oxide scrubbers at the
company's Cromby plant, Unit 1, and its Eddystone plant, Units 1 and 2. The
magnesium oxide system, which generates products used in the manufacture of
sulfuric acid, has not been widely used on coal-fired power plants, and at the
time the order was signed it was determined that the company needed time to
gain experience with the adaption of the system to boiler operation. For this
reason, the compliance schedule allows for the phasing-in of the scrubbers in
two major stages. During the first phase of the schedule, the company is to
complete the Installation of the flue-gas desulfurization system already begun
at Eddystone, Unit 1, and it 1s to be in compliance by March 1, 1975. On or
before June 1, 1975, the company is to submit an evaluation of the performance
of the system to the Environmental Protection Agency.
During the second phase of the schedule, the company is to initiate design
procedures for installation of the additional flue-gas desulfurization systems
required at Eddystone, Unit 1, and for sulfur oxide and participate control
systems for Eddystone, Unit 2, and Cromby, Unit 1. Detailed p"!ans of these
systems are to be submitted to the Environmental Protection Agency by August 15,
1975. The company is to place purchase orders or contracts for major component
parts of the phase-two control equipment by September 15, 1975. The company
is to operate Eddystone, Units 1 and 2, and Cromby, Unit 1, 1n compliance by
May 1, 1978. Provisions are included for reducing the impact on air quality
of these plants during episodes of high air pollution and for periodically
reporting to the Environmental Protection Agency on the progress being made in
meeting the compliance plan. The Agency believes that this agreement adequately
assures achievement of air quality goals while taking Into account the practi-
cal considerations of Installing flue-gas desulfurization systems.
If State Implementation Plan requirements for particular plants are more
stringent than required to meet the primary standards for sulfur dioxide, it
1s the Agency's policy generally to include schedules in enforcement orders
that allow for more time at the beginning of the schedule than is given to
plants that contribute to concentrations in excess of the standards. This
allows States time to consider revising their implementation plans and helps
assure, as well, that priority plants can get low-sulfur coal or flue-gas
desulfurization systems.
The Environmental Protection Agency believes that this approach is ade-
quate at the present time for dealing with compliance problems arising out of
delays 1n obtaining flue-gas desulfurization equipment. At the present time
the capacity of scrubber vendors to supply control equipment generally exceeds
the demand for these systems by the utility industry and the Environmental
Protection Agency believes that there is no need to restrict orders for new
systems by establishing a rigid system of priorities. Even with an increase
In enforcement activities, 1t 1s the judgment of the Agency that a reversal of
this situation 1n the near future is unlikely, especially since over half of
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the power plants identified by the Agency for priority enforcement actions are
involved in litigation challenging the Agency's approval of applicable State
Implementation Plans, or are under State Implementation Plans that are being
revised, thereby hampering the Agency's ability to initiate enforcement actions.
The situation obviously could change in the longer run, however, as these
particular enforcement impediments are resolved and also as new power plants
become operational; but probably the greatest factor that will cause an in-
creased demand for flue-gas desulfurization equipment is the number of plants.
mandated to convert from petroleum products or natural gas pursuant to Section
2 of the Energy Supply and Environmental Coordination Act. Since no con-
version orders have been issued to date, the effect of this Act on availa-
bility of flue-gas desulfurization equipment 1s not yet clear. However,
flue-gas desulfurization could be required on perhaps as much as 10,000 to
15,000 megawatts of capacity 1f these plants converted back to coal.
In assuring that these plants achieve compliance in accordance with the
requirements of Section 119(c) of the Clean Air Act, the Environmental Protec-
tion Agency has authority pursuant to Section 119(e) to establish oriorities
under which manufacturers of continuous emission-reduction systems would be
required to provide such systems first to plants in Air Quality Control Regions
1n which the national primary ambient air quality standards have not yet been
achieved. This authority is to be used only if it is found to be necessary in
carrying out the requirements of Section 119(c). The Environmental Protection
Agency considers the use of such allocation authority as highly undesirable
because it causes serious dislocations in the control system market and,
therefore, the Agency will not use this authority unless it is absolutely
clear that there are no other alternatives. There are a number of ways in
which the authority under this Section could be Implemented should the need
arise. At one extreme, the Agency could designate by rule specific Air Quality
Control Regions that would receive priority for obtaining flue-gas desulfuri-
zation systems. Control system manufacturers would then be prohibited from
selling such systems to all other existing plants until the control needs of
plants within these priority Regions were satisfied. In order to prevent such
a priority designation from blocking attainment of primary standards in Air
Quality Control Regions not affected by implementation of Section 2 of the
Energy Supply and Environmental Coordination Act, the Agency would also have
to designate the Regions containing power plants that are already on coal and
that contribute concentrations 1n excess of primary standards. This massive
Federal Intervention into relationships between control system manufacturers
and utilities 1s the least acceptable approach to achieving compliance since
1t would severely restrict the market for flue-gas desulfurization systems and
thus would destroy the manufacturer's Incentive to advance the technology.
A more acceptable but still undesirable approach would be to give priority
to plants on a case-by-case basis upon receipt by the Environmental Protection
Agency of a request from a utility for such a designation. Utilities would not
be eligible to apply for such priority designation before demonstrating good
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faith in attempting to procure appropriate control systems on their own. While
this approach would not be as restrictive as that of designating priority Air
Quality Control Regions in anticipation of control-system shortages, the Agency
still considers this to be an excessive measure that is to be used only after
all alternatives have failed.
It is important to recognize that any priority-setting system would be
extremely difficult to Implement for three reasons. The first is the diffi-
culty of developing a pi ant-by-plant priority list. Second, neither the
Environmental Protection Agency nor the State environmental agencies have any
direct control over the demand for flue-gas desulfurization systems. Under
the Clean Air Act, all polluting sources are allowed to choose the most cost-
effective way to comply with emission limitations. Although it can take
enforcement action, the Environmental Protection Agency cannot dictate the
method of compliance. It is difficult to see how an allocation authority,
which controls only the supply of flue-gas desulfurization equipment and not
the demand for such control equipment, would work. Finally, allocating
control equipment 1s quite different from allocating oil. Fuel oil is a
fairly homogeneous product, whereas flue-gas desulfurization systems can be
differentiated by types of process, cost, vendor sources, and reliability.
How would an allocation scheme that allowed utilities the choice of vendor
ensure equity among the dozen suppliers of flue-gas desulfurization systems?
For example, will one vendor who can supply flue-gas desulfurization equipment
in 1977 object when a utility 1s assigned a different vendor to install a
system in 1979? These are only Illustrative examples of the complexities
Involved in Invoking the priority-setting authority granted to the Environ-
mental Protection Agency under the Energy Supply and Environmental Coordina-
tion Act.
At the present time, therefore, the -Environmental Protection Agency does
not anticipate using the authority granted in Section 119(e) of the Clean Air
Act and has not developed regulations for its implementation. If it becomes
clear, as the provisions of the Energy Supply and Environmental Coordination
Act are carried out, that some form of a priority-setting procedure is required,
the Environmental Protection Agency will provide ample notification of its
intentions to use this authority well 1n advance of actually initiating such
procedures.
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TECHNICAL APPENDIX A:
STATUS OF LOW- AND INTERMEDIATE-Btu
RESIDUAL OIL AND COAL GASIFICATION SYSTEMS
The status of low- and Intermediate-Btu coal gasification systems as of
mid-1974 is given in this appendix. Eight types of pVocess are covered: (1)
moving bed/dry ash, (2) moving bed/slagging, (3) fluid bed/dry ash, (4) fluid-
ized bed/agglomerating ash, (5) entrained flow, (6) entrained flow/slagging,
(7) molten bath, and (8) underground gasification. Paragraph headings indi-
cate the developer of the system and, in parentheses, the current status of
the system.
MOVING BED/DRY ASH
Lurgi (Commercially Available)—Because the maximum size of the gasifier
is limited, several gasifier units must be operated in parallel. Older models
accepted only noncaking coals, but a modified version has been tested success-
fully with caking coals.
Wellman-Galusha (Commercially Avail able)--The standard gasifier accepts
only anthracite or coke, but an agitator model that also accepts bituminous
coal is available. ..-./,,
U.S. Bureau of Mines (Operational, Pilot)—A 1200-1 b/hr/.pi lot develop-
mentaT unit Ts in operation in Morgantown, W. Va. The Office of-Coal Research
and the Tennessee Valley Authority plan to install two qr more commercial-size
gasifiers designed on the basis of this unit. Tests indicate that it can
accept strongly caking coals.
Gegas/General Electric (Operational and Design, Pilot).—A 50-1 b/hr unit
has been in operation since 19/1, and a 1200-lb/hr pilot developmental unit
is in the design stage. General Electric hopes to develop a unique coal
extrusion process for feeding coal to the gasifier, and is also developing
membrane systems for gas clean-up. The process will be used to produce low-
Btu gas for power plants.
Kellogg (Under Construction, Pilot)—A 4-ton/hr pilot should be opera-
tional in mid-1975 in Houston, Texas.
MOVING BED/SLAGGING
Thyssen-Galocsy (Defunct, Pilot)—A 40-ton/day pilot plant was operated
in Germany in 1943-1944.Work was interrupted by World War II and not resumed.
FLUID BED/DRY ASH
Winkler (Commercially Available)—Atmospheric pressure processes in com-
mercial use for some time.System is being modified by Davy Powergas for
high-pressure operation.
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Synthane/U.S. Bureau of Mines (Under Construction. Pilot)—Construction
of this 3-ton/hr pilot unit in Bruceton, Pa., is expected to be completed in
January 1975. Studies with a 40-lb/hr gasifler indicate the process can
accept any U.S. coal.
COp Acceptor/Consolidated Coal (Operational. Pilot)—A 1.5-ton/hr pilot
unit Has been in operation since 1972 in Rapid City, S.D. It can only accept
lignite and subbituminous coal. Problems with refractory failure and plugging
of acceptor lines experienced during startup seem to be solved.
Exxon Oil Company (Under Construction, Pilot)—This 20-ton/hr pilot, under
construction In Baytown, Texas, will be used to produce intermediate-Btu gas
for upgrading to synthetic natural gas.
Hydrocarbons Research, Inc. (Commercially Available)--This 10-ton/day
unit was first operated in 1958 in Trenton, N.J., with anthracite. It was
modified in 1972 to accept bituminous coal.
COGAS/Cogas Development Company (Operational. Pilots)—A 4-ton/hr pilot
has been in operation since March 1974 in Leatherhead, England, and a 400-1b/hr
pilot has been in operation since May 1974 in Plainsboro, N.J. The process
will be used to produce intermediate-Btu gas for upgrading to synthetic natural
gas.
Bituminous Coal Research (Developmental, Bench Scale and Pilot)—A
$2,575,000, 50-month contract with the Office of Coal Research covers bench-
scale and pilot experimental development unit work that will provide the basis
for design of a pilot plant. The process will be used to produce low-Btu gas
for power plants.
FLUIDIZED BED/AGGLOMERATING ASH
U-Gas/IGT (Design, Pilot)—Funds are being sought for construction of the
10-ton/hr pilot plant that has been designed. Present studies are being made
with a 4-foot-diameter gasifier. The primary purpose of the process is to
provide low-Btu gas for power plants.
Westinghouse (Under Construction, Pilot)~-A 1200-1b/hr pilot developmen-
tal unit is mechanically complete in Waltz Mill, Pa. First hot tests were
expected in January 1975. If significant success is achieved with this unit,
a decision could be made to go directly to a full-size pilot Integrated with
a combined cycle plant (120 MW).
Battelle-Union Carbide (Under Construction. Pilot)—A 1200-1b/hr pilot
developmental unit was expected to be completed in the first quarter of 1975
in West Jefferson, Ohio.
ENTRAINED FLOW
Bigas/Bituminous Coal Research (Under Construction, Pilot)—This 5-ton/hr
pilot 1s expected to be completed in early 1975 in Homer City, Pa.
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Combustion Engineering (Design, Pilot)—A contract is presently being
negotiated for construction of a 5-ton/hr pilot. Very little information
1s available at this time. Process will be used to produce low-Btu fuel
for power plants. :
Fpster-Vlheeler (Design, Pilot)—Construction of this 50-ton/hr pilot
was scheduled to begin in the fourth quarter of 1974. In phase I, the pilot
will provide low-Btu gas for modified existing boilers. In phase II (early
1978), the gas will fuel a combined cycle plant.
Garret Flash Pyrolysis/Garret Research and Development Company (Proposed.
Pilot; Operational, Bench Scale)—Support is being sought for a 10-ton/hr
pilot plant.A bench-scale unit (50 Ib/hr) has been in operation since
January 1973.
ENTRAINED FLOW/SLAGGING
Koppers-Totzek (Commercially Available)—There are many commercial
1nstallations In Europe and Asia.
Texaco Oil Company (Defunct)—Texaco has had previous pilot plant ex-
peri enTe~^RWThTs~pTocesTriin^ra semi commercial unit was in operation for
a number of years.
Babcock andWilcox-DuPont (Defunct)—A 17-ton/hr commercial unit was
operated for about 1 year 1n the early fifties by DuPont at Belle, W.Va.
The unit has since been dismantled.
MOLTEN BATH
Applied Technology Corp. (Operational. Bench Scale)—Studies with a
molten iron tath have involved a 25-inch-inside-diameter induction furnace
to simulate the gasifier (4000-1b capacity).
M. VI. Kellogg Company (Operational, Bench Scale)—A pilot developmental
unit employing molten salt is planned and preliminary flow sheets and cost
estimates have been made.
Atomics International (Bench Scale)—This process, also employing molten
salt, will be used to produce low-Btu fuel for power plants.
UNDERGROUND GASIFICATION
Pilot-scale tests of this process are being conducted in Hanna, Wyo.
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TECHNICAL APPENDIX B:
OPERATING SUMMARY FOR FLUE-GAS
DESULFURIZATION SYSTEMS
This appendix presents a summary of the operational history of flue-gas
desulfurization (FGD) systems through October 1974. Paragraph headings
indicate utility and unit names and, in parentheses, unit capacity. Unless
otherwise specified, the units are coal-fired.
Arizona Public Service, Choi!a No. 1 (115 MW)—Since startup in October
1973, the FGD system availabitity has been consistently above 90 percent.
There have been a few mechanical problems, the most persistent being vibra-
tion 1n the reheater section.
Boston Edison, Mystic No. 6 (150-MW, oil)—For 1973, reported scrubber
availability ranged from 73 percent in August to 13 percent in December.
The decreasing availability was due to deterioration and subsequent overhaul
of the process equipment. Recent (1974) availability figures are: March, 87
percent; April, 81 percent; May, 57 percent; and June, 80 percent. This
system has been down, with no immediate plans for restarting, since the EPA
demonstration program was completed. Boston Edison is evaluating the data
collected during the demonstration period to determine the course of future
action.
Commonwealth Edison. Will County No. 1 (167 MW)--Avallability of
Module A has increased in the past several months. It was 72 percent in
April, 93 percent in May, 54 percent in June, 95 percent in July, 91 per-
cent 1n August, and 85 percent in September. Module B has been removed from
service until all necessary modifications are made to Module A to permit
reliable operation.
Duquesne Light, Phillips Section (410 MW)—At present, only flue gas
from Boilers 2, 3, and 4 (about 40 percent of the station capacity) is
treated because fly ash from the inefficient precipitators overloads the
clarifiers. Operating hours for Modules 1 through 4 between March 17 and
June 30, 1974 were 1756, 762, 815, and 1707, respectively. The plant tries
to run Modules 1 and 4 continuously. The outage hours for these units is
primarily for Inspections.
General Motors, Parma Plant (32 MW)—System availability has been
essentially TOfr percent since April 1974. However, the availability figure
has little meaning since only two of the four modules were operating at any
time because of low demand.
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Illinois Power, Vlood River (110 MW)—The unit operated only 700 hours
during the past 2 years.Primary reason for the downtime was the delay in
converting the reheaters from natural gas to fuel oil firing. The unit was
scheduled to restart in late November 1974.
Kansas City Power and Light, Hawthorn No. 3 (140 MM)—The FGD system has
undergone several major modifications.Availability has since increased from
30 percent in 1973 to as high as 70 percent recently. Plant operators were
on strike between July and October 1, 1974, and during that time the FGD
system was down. The system was restarted on October 1st.
Kansas City Power and Light, Hawthorn No. 4 (110 MW) — This unit was con-
verted from furnace injection to tail-end scrubbing.The plant has ex-
perienced more problems with this unit (both mechanical and chemical in
nature) than with Unit 3. The operation can be characterized as "fair."
Kansas City Power and Light, LaCygne (820 MW) —Initial problems included
fan deposits, demister and nozzle plugging, reheater failure, and screen
plugging. Many of the original problems were attributed to poor pH control.
Recently the unit has had about 80 percent availability and there are no out-
standing problems. However, it is necessary to remove each module from service
once a week to clean out accumulated sol Ids.
Kansas City Power and Light, Lawrence No. 4 (125 MW)—The system has under-
gone a number of process modifications.At present, the system is capable of
sustained operation, although sulfur dioxide removal efficiency is limited to
only 75 percent and the demisters must be washed daily (automatic washing).
Manual washing of the demisters is required every 2 weeks. The unit is badly
corroded and will be replaced by a new electrostatic precipitator and FGD
system in 1977.
Kansas City Power and Light, Lawrence No. 5 (400 MM)—This unit has en-
countered many of the same process problems as Unit, 4.In addition, there is
poor gas flow distribution between the eight modules and within each module;
measures are being taken to correct the distribution. The boiler burns
natural gas whenever it is available, so it is difficult to assess FGD system
availability.
Louisville Gas and Electric. Paddy's Run (65 MW)—FGD system availability
is near 100 percent.However, since the system is installed on a peaking
boiler there are many occasions when the boiler's run is too short to justify
startup of the FGD system.
Southern California Edison. Mohave No. 2 (160 MW)—This is an experi-
mental unit.It has operated quite successfully with an availability above
80 percent.
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Nevada Power, Reid Gardner No. 1 and No. 2 (125 MW each)—These two FGD
systems started up 1n March 197^ and have had an availability of over 90 per-
cent when there was sufficient trona (impure form of sodium carbonate). The
lack of trona has limited the operation of the units. Each system has
operated only 900 hours since April 1974.
Potomac Electric and Power, Dickerson No. 3 (100 MW)--There is no record
of the FGD system's availability for the period prior to August 1974 since
the unit was down frequently for process modification, equipment repairs,
etc. Availability since August is about 34 percent.
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