EPA-600/7-78-034
U.S. Environmental Protection Agency Industrial Environmental Research FPA-fiOO/7-"71
Office of Research and Development Laboratory
Research Triangle Park, North Carolina 27711 February 1978
PHYSICAL
COAL CLEANING
FOR UTILITY BOILER
SO2 EMISSION CONTROL
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental Protec-
tion Agency, have been grouped into seven series. These seven broad categories were
established to facilitate further development and application of environmental technology.
Elimination of traditional grouping was consciously planned to foster technology transfer
and a maximum interface in related fields. The seven series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the effort
funded under the 17-agency Federal Energy/Environment Research and Development
Program. These studies relate to EPA's mission to protect the public health and welfare
from adverse effects of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an environmentally-
compatible manner by providing the necessary environmental data and control technology.
Investigations include analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environmental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and
approved for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the Government, nor does
mention of trade names or commercial products constitute endorsement
or recommendation for use.
This document is available to the public through the National Technical Information Service,
Springfield, Virginia 22161.
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EPA-600/7-78-034
February 1978
PHYSICAL COAL CLEANING
FOR UTILITY BOILER
SO2 EMISSION CONTROL
by
E. H. Hall, L Hoffman, J. Hoffman,
and R. A. Schilling
Battelle Memorial Institute
Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Contract No. 68-02-2163, Task 851
Program Element No. EHE 623A
EPA Project Officer: James D. Kilgroe
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ABSTRACT
This study on the use of physical coal cleaning (PCC) for compliance
with SC>2 emission regulations was part of an evaluation of revised utility
boiler New Source Performance Standards (NSPS) performed for EPA's Office
of Air Quality Planning and Standards.
Estimates were made of the quantities of naturally occurring low-sulfur
coal and physically cleaned coal potentially available for compliance with
three emission standards: 1.2, 0.8, and 0.4 Ib S02/106 Btu (0.52, 0.34, and
0.17 kg S02/GJ). Estimates also were made of the amount of U.S. coal which
could be made available if flue gas desulfurization (FGD) or combinations
of FGD and PCC were used as the S02 emission control technique. The effects
of coal sulfur variability and required emission averaging time on the amount
of available compliance coals also were evaluated. An overview of the tech-
nology costs and environmental aspects of both physical and chemical coal
cleaning is included, and the applicability of fluidized bed combustion and
synthetic fuels for compliance with S02 emission standards are discussed
briefly.
The study results indicate that the use of coal cleaning as an emission
control technique will decrease if the emission limits are lowered. Under
thV~current NSPS^of 1.2 Ib S02/106 Btu (0.52 kg S02/GJ), an estimated total
j)f.Jx2.4 billion short tons of recoverable reserves could be burned without
cleaning^ or could be cleaned to compliance levels as compared with an esti-
mated portion of this amount of 36.4 billion tons of low-sulfur coal which
could be burned without cleaning. Under a limit of 0.8 Ib S02/106 Btu (0.34
kg S02/GJ), these quantities drop to 10.4 and 5.2 billion short tons, respec-
tively. No coal is available even with cleaning which could comply with a
limit of 0.4 Ib S02/106 Btu (0.17 kg S02/GJ). A short-term averaging require-
ment would reduce substantially the quantities available to meet either the
1.2 or 0.8 Ib S02/106 Btu (0.52 or 0.34 kg S02/GJ) limit. The combination
of coal cleaning plus FGD would be useful in meeting a 0.4 Ib 502/10^ Btu
(0.17 kg S02/GJ) emission standard. At this emission level coal cleaning
could nearly double the available reserve as compared with the use of FGD
alone. For other emission limits, the applicability of coal cleaning
combined with FGD will depend upon the cost effectiveness of this approach.
This report was submitted in partial fulfillment of Contract No.
68-02-2163, Task 851, by Battelle's Columbus Laboratories under the sponsor-
ship of the U.S. Environmental Protection Agency. Portions of the work were
performed by Hoffman-Muntner Corporation, Silver Spring, Maryland, under
subcontract to Battelle's Columbus Laboratories.
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TABLE OF CONTENTS
Page
ABSTRACT ±±
LIST OF CONVERSION FACTORS xi
ACKNOWLEDGEMENTS xii
INTRODUCTION i
CONCLUSIONS 2
VARIABILITY OF SULFUR IN COAL 5
RESULTS OF STUDY 8
General Discussion 8
Availability of Low-Sulfur Coal, Physically Cleaned Coal, and Flue
Gas Desulfurization to Meet Optional NSPS 9
FGD Considerations 25
Applicability of Combined Physical Coal Cleaning (PCC) and Flue Gas
Desulfurization (FGD) to Meet Optional NSPS 27
Applicability of Fluidized-Bed Combustion to Meet Optional NSPS . . 29
Applicability of Coal Conversion Processes to Meet Optional NSPS . 30
ELECTRIC POWER SUPPLY AND DEMAND 1977-1986 32
General Discussion , ^2
Peak Demand Forecasts ....',.., 34
Energy Forecasts ,..,...., 37
Generating Capability Projections ... 37
Annual Coal Demand for New Units, 1976-1985 37
Origin and Destination of Coal for New Units . . , 43
Transport of Coal to New Units ^
iii
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TABLE OF CONTENTS
(Continued)
Page
METHODOLOGY FOR DETERMINING COAL AVAILABILITY 50
General Discussion 50
Significance of Factors 51
Basic Calculations 56
TECHNOLOGY, COST, AND ENVIRONMENTAL OVERVIEWS OF COAL CLEANING .... 79
Physical Coal Cleaning 79
Chemical Cleaning 82
Meyers/TRW Process 84
Battelle Hydrothermal 86
Hazen Process 86
KVB 89
Ledgemont Oxygen Leaching t. . . . 91
BOM/ERDA 93
Dynatech 93
General Electric 93
Summary of Coal Cleaning Costs 95
REFERENCES 97
LIST OF DATA SOURCES £8
iv
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TABLES
Number Page
1 Definition of Coal Producing Regions 12
2 Peak Demand - As Projected April 1, 1977 by the Regional
Electric Reliability Councils Contiguous United States Megawatts 35
3 Projected Growth of Peak Demand — Contiguous United
States 1977-1986 36
4 Projected Annual Electric Energy Requirements for the Regional
Electric Reliability Councils Contiguous United States
Gigawatt-Hours I/ 38
5 Projected Electric Energy Growth as Reported by the Regional
Electric Reliability Councils April 1, 1977 in Response to FPC
Order 383-4 Contiguous United States 39
6 Annual Load Factors — in Percent as Projected April 1, 1977
by the Regional Reliability Councils Contiguous United
States 1977-1986 40
7 Projected Growth of Generating Capability — at Time of
Seasonal Peak Demand Periods Contiguous United States
1977-1986 Megawatts 41
8 State and Regional Coal Requirements for New Units Scheduled
for Operation Between 1976-1985 42
9 Comparison of Coal Reserve Data and Washability Data -
Appalachian Region ' 52
10 Western Region Reserves - Cumulative % of Total and Comparison
with Washability Data 53
11 The Significance of the Calculation Factors on the Determin-
ation of Coal Availability 55
12 Raw Coal Availability 59
13 Recoverable Reserves to Meet the NSPS, Raw and Prepared Coal
to Meet the 1985 Annual Demand From Electric Utilities
(Existing and New) - The Entire United States 60
v
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TABLES (Continued)
Number Page
14 Recoverable Reserves to Meet the NSPS, Flue Gas Desulfurization
(FGD) Combined with Prepared Coal to Meet the 1985 Annual
Demand from Electric Utilities- The Entire United States .... 61
15 Recoverable Reserves to Meet the NSPS, Raw and Prepared Coal
to Meet the 1985 Annual Demand From Electric Utilities
(Existing Plus New) - Eastern Region 62
16 Recoverable Reserves to Meet the NSPS, Flue Gas Desulfurization
(FGD) Combined with Prepared Coal to Meet the 1985 Annual Demand
From Electric Utilities (Existing Plus New) FGD-90% Removal
Efficiency, 100% of Gas Cleaned - Eastern Region 64
17 Recoverable Reserves to Meet the NSPS, Raw and Prepared Coal to
Meet the 1985 Annual Demand From Electric Utilities (Existing
Plus New) - Eastern - Midwest Region 66
18 Recoverable Reserves to Meet the NSPS, Flue Gas Desulfurization
(FGD) Combined with Prepared Coal to Meet the 1985 Annual Demand
From Electric Utilities (Existing Plus New) FGD - 90% Removal
Efficiency, 100% of Gas Cleaned - Eastern - Midwest Region ... 67
19 Recoverable Reserves to Meet the NSPS, Raw and Prepared Coal to
Meet the 1985 Annual Demand From Electric Utilities (Existing
Plus New)-Western - Midwest Region 73
20 Recoverable Reserves to Meet the NSPS, Flue Gas Desulfurization
(FGD) Combined with Prepared Coal to Meet the 1985 Annual
Demand From Electric Utilities (Existing Plus New) FGD-90%
Removal Efficiency, 100% of Gas Cleaned - Western-
Midwest Region . , , 74
21 Recoverable Reserves to Meet the NSPS, Raw and Prepared Coal to
Meet the 1985 Annual Demand From Electric Utilities (Existing
and New)-Western Region 75
22 Recoverable Reserves to Meet the NSPS, Flue Gas Desulfurization
(FGD) Combined with Prepared Coal to Meet the 1985 Annual Demand
From Electric Utilities (Existing Plus New) FGD-90% Removal
Efficiency, 100% of Gas Cleaned - Western Region ........ 76
VI
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TABLES (Continued)
Number Page
23 Physical Coal Cleaning Process Environmental Problems 83
24 Major Coal Cleaning Process Considerations 96
vii
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FIGURES
Number Page
1 Examples of Normal Distribution Curves ........... 6
2 Coal Availability Bar Chart ................. 11
3 Coal Availability Bar Chart (Including the Effects of the
Variability of the Sulfur Content of Coals: The Relative
Standard Deviation, RSD = 10%, Compliance = 99.87%) ..... 14
4 Coal Availability - The Entire United States ........ 15
5 Coal Availability (Including Sulfur Variability) - The
Entire United States .................... 16
6 Coal Availability - Eastern Region ............. 17
7 Coal Availability (Including Sulfur Variability) - Eastern
Region ........................... 18
8 Coal Availability - Eastern Midwest Region ......... 19
9 Coal Availability (Including Sulfur Variability) - Eastern-
Midwest Region ....................... 20
10 Coal Availability - Western Midwest Region
11 Coal Availability (Including Sulfur Variability) -Western-
Midwest Region ....................... 22
12 Coal Availability - Western Region ............. 23
13 Coal Availability (Including Sulfur Variability )-
Western Region ....................... 24
14 Projected Capacity Demand -Peak Power Demand and Required
FGD Capacity ........................ 26
15 Regional Electric Reliability Councils ........... 33
16 Flow of Coal to New Generating Units From the Western Regions
of the Northern Great Plains (in 1000 tons) 1980-1985 .... .45
viii
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FIGURES (Continued)
Number
17 Flow of Coal to New Generating Units From the Eastern Region
(Interior Province) and the Fort Union Region (in 1000
tons) 1980-1985 46
18 Flow of Coal to New Generating Units From the Appalachian
Region, From U.S, Bureau of Mines District 15, and From the
Mountain Region (in 1000 tons) 1980-1985 48
19 Percent of all U.S. Coal Samples Meeting the Current EPA
Standard of 1.2 Pounds S02/MM Btu with No Preparation .... 68
20 Percent of Alabama Region Coal Samples Meeting the Current
EPA Standard of 1.2 Pounds S02/MM Btu with No Preparation . . 69
21 Percent of Southern Appalachian Region Coal Samples Meeting
the Current EPA Standard of 1.2 Pounds S02/MM Btu with No
Preparation 70
22 Percent of Northern Appalachian Region Coal Samples Meeting the
Current EPA Standard of 1.2 Pounds S02/MM Btu with No
Preparation , , . . 71
23 Percent of Eastern Midwest Region Coal Samples Meeting the
Current EPA Standard of 1.2 Pounds S02/MM Btu with No
Preparation , . . , 72
24 Percent of Western Midwest Region Coal Samples Meeting the
Current EPA Standard of 1.2 Pounds S02/MM Btu with No
Prepration 77
i
25 Percent of Western Region Coal Samples Meeting the Current
EPA Standard of 1.2 Pounds S02/MM Btu with No Preparation . . 78
26 TRW Meyers Process Flow Diagram 85
27 Battelle Hydrothermal Process Flow Diagram 8?
28 Hazen Process Flow Diagram 88
ix
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FIGURES (Continued)
Number Page
29 KVB Process Flow Diagram , . . , 90
30 LOL Process Flow Diagram 92
31 BOM/ERDA Process Flow Diagram 94
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LIST OF CONVERSION FACTORS
Btu (at 60 F) x 1.055 x 103 = Joule (j)
feet x 0.3048 = meter (m)
degrees Fahrenheit (f) -32 x 0.555 = degrees Celsius (C)
pound mass (Ib) x 0.4536 = Kilogram (kg)
Btu/pound (Ib) x 2.326 x 10~3 = Mega Joule/kg (MJ/kg)
lb/106 Btu x 0.4299 = kg/GJ (kg/109J)
short ton (2000 Ib) x 0.906 = metric ton (1000 kg) = k kg
dollars/short ton x 1.1023 = dollars/metric ton
dollars/106 Btu x 0.9479 = dollars/GJ ($/109 J)
pound force per square inch (psi) x 6.89 x 10 =
Pascal (Pa) = Newton/m2) (N/m2)
gallon (U.S.) x 3.78 = liter
barrel (42 gallon) x 158.97 = liter
XI
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ACKNOWLEDGEMENTS
This study was conducted as a Task in Battelle Columbus Laboratories'
ongoing program, "Environmental Assessment of Coal Cleaning Processes'1,
which is supported by EPA. The contributions of the Program Manager, Mr.
G. Ray Smithson, Jr., and by the Deputy Program Manager, Mr. Alex W. Lemmon,
Jr., are gratefully acknowledged.
Significant contributions to this report were made by Mr. Lawrence
Hoffman and Mr. Jerome Hoffman, both of Hoffman-Muntner Corporation, Silver
Spring, Maryland, and as a result, these contributors are listed as co-authors
of this report.
The advice and counsel of the EPA project Officer Mr. James D. Kilgore,
and the liasion provided by Mr. Charles Sedman of the Office of Air Quality
Planning and Standards were invaluable in the performance of this work.
xii
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INTRODUCTION
This report has been prepared to provide information to EPA's Office
of Air Quality Planning and Standards (OAQPS) for a feasibility study
pertaining to possible revision of New Source Performance Standards (NSPS)
for power boilers. The report stresses physical coal cleaning as a control
J:echnique for SO^ emissions, and includes an analysis of the availability
of low-sulfur coal and of coal cleanable to compliance levels under various
alternative NSPS. The results of the availability analysis and brief dis-
cussions of the applicability of other control techniques to meet optional
NSPS are summarized in the study results section. Details of the projections
of coal demand for power boilers, and a description of the methodology for
estimating coal availability are presented in the subsequent sections. The
final section contains an overview of the technology, costs, and environ-
mental aspects of both physical and chemical coal cleaning processes.
During the course of the study questions have arisen regarding the
validity of the data base on coal reserves. Project staff consulted
directly with Bureau of Mines personnel associated with the development of
the reserve data and determined that revisions now in progress are not expected
to result in major changes in the data. In addition, coal cleanability data
are limited in scope and extrapolations based on the limited data cannot be
expected to be as accurate as they will be when broader cleanability data
become available. The results of the availability analysis are, of course,
i
subject to modifications as the Bureau of Mines reserve data are refined and
as additional cleanability studies are performed. However, the analysis is
based on the best data currently available and the results are believed to be
a reasonably good representation of the actual potential availability of low-
sulfur coal and cleanable coal.
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CONCLUSIONS
The potential role of physical coal cleaning (PCC) for control of S02
emissions from utility boilers was evaluated for three alternative New Source
Performance Standards (NSPS). The approach employed was based on a determin-
ation of the quantities of raw coal and of coal cleaned to various levels
which could be burned in compliance with S02 emission standards of 1.2, 0.8,
and 0.4 Ib S02/106 Btu (0.52, 0.34, and 0.17 kg S02/GJ). The impact of the
variability of sulfur in coal on the quantities of raw and cleaned coal which
could be burned in compliance with various emission limits also was evaluated.
The combined use of coal cleaning and flue gas desulfurization (FGD) was
examined, and the applicability of fluidized bed combustion and of coal
conversion processes to meet alternative NSPS was reviewed briefly.
The evaluations were made using U.S. Bureau of Mines coal reserves and
coal washability data bases.
The results of the study may be summarized by the following conclusions.
(1) It is estimated that a total of 62.4 billion short tons of
recoverable coal reserves could be burned without cleaning
or could be physically cleaned to comply with existing
NSPS for S02 emissions. This compares with 36.4 billion
short tons of recoverable reserves of low-sulfur coal
which could be burned without cleaning.
(2) If emission limits are lowered and short-term averaging
is required, PCC alone will be of limited value as an
emission control technique as illustrated by the following
tabulation.
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S00 Emission Limit, lb/106 Btu
1.2 0.8 0.4
Long- 30- Long- 30- Long- 30-
Emission Control Term Day Term Day Term Day
Technique Average Average Average Average Average Average
Recoverable U.S. Reserves,
billions of short tons
Low-Sulfur Coal 36.4 17.3 5.2 1.6 0.0 0.0
Low-Sulfur Coal
Plus Cleaned Coal* 62.4 32.3 10.4 7.1 0.0 0.0
* Cleaned at 1.5 inches top size with Btu recovery greater than 90 percent.
Tonnages do not reflect Btu or weight loss during cleaning.
(3) PCC can be combined with FGD to meet reduced emission limits.
The combination is particularly effective for a standard of 0.4
Ib S02/106 Btu (0.17 kg S02/GJ) because large quantities of
high-sulfur coals cannot be cleaned to this level with FGD
alone. The following tabulation summarizes the tonnages of
coal which would be potentially available using low-sulfur
coal with FGD or cleaned coal with FGD.
S02 Emission Limit, lb/106 Btu
172078674
Long- 30- Long- 30- Long- 30-
Emission Control Term Day Term Day Term Day
Technique Average Average Average Average Average Average
Recoverable U.S. Reserves,
billions of short tons
Low-Sulfur Coal
and FGD 254.6 229.4 215.6 184,5 111.7 85.9
Low-Sulfur Coal
Plus Cleaned Coal*
and FGD 257.2 253.8 254.6 229.4 171.5 141.1
* Cleaned at 1.5 inches top size with Btu recovery greater than 90 percent.
Tonnages do not reflect Btu or weight loss during cleaning.
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(4) Although a standard specifying a percentage reduction in
sulfur emissions was not addressed in this study, PCC may
be useful in combination with other controls in meeting
this type of standard. PCC would allow the scrubber or
other control system to operate at a lower efficiency since
credit would be given to precombustion sulfur removal.
(5) PCC has been used for many years to reduce ash and to
enhance the heating value. As such, PCC is an available
technology. Improvements designed to increase sulfur
removal are being developed and incorporated in the tech-
nology. PCC costs vary with the type of coal and the
treatment employed. An annualized cost of $0.18/10 Btu
of cleaned coal is typical.
(6) A number of chemical coal cleaning processes are in various
stages of development. These are designed to achieve
greater sulfur removajL than PCC. However, none of these
processes is commercially available at this time. The
projected costs range from $0.60 to $1.00/106 Btu of
cleaned coal.
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VARIABILITY OF SULFUR IN COAL
The fact that the composition and properties of coal can vary widely,
even within a given coal seam, is an important consideration with respect to
emission regulations. Because the sulfur content varies, the average value
for sulfur in coal can be used to determine compliance with a given standard
only if long-term averaging of the resultant S02 emission is permitted. If,
however, the emission limit includes a "never to be exceeded" statement, a
coal with average sulfur and heat content values which are equivalent to the
stated emission limit will be out of compliance approximately half of the time.
The net effect of an emission regulation which calls for anything other than
long-term averaging is to require the use of coal with a lower average sulfur
content so that when upward deviations fro* the average occur the unit will
still be in compliance. The problem is to determine how much lower the
average sulfur content must be.
In this analysis it was assumed that the variation in coal sulfur content
follows normal statistical relationships, and the standard deviation of the
sulfur values was used to determine the average sulfur content required to meet
a given emission limit. It should be noted that insufficient data on coal
sulfur variability exist to prove that the assumption of normal statistical
behavior is valid for all coals. In fact, the discrete nature of pyritic
sulfur in coal seems to preclude the expectation of normal distribution.
Nevertheless, the assumption that normal statistics are followed provides a
useful approach until more data on sulfur variability are obtained.
For a normal statistical distribution, the frequency of occurrence of
various sulfur values would follow a bell-shaped curve of the type shown in
Figure la and Ib. The highest point on the curve, i.e., the sulfur value
which occurs most frequently, represents the average or mean value, designated
by y. If the variability is small, the distribution curve would be tall and
narrow, as shown in Figure Ib. A short and broad curve, as shown in Figure
la, would be obtained if the variability is large. It is apparent that the
Shape of this sulfur distribution curve has great significance with respect
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Sulfur Emissions, Ib S02/IO°Btu
FIGURE 1. EXAMPLES OF NORMAL DISTRIBUTION CURVES
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to compliance with a stated SO^ emission limit. A much lower average sulfur
content is required for compliance, if the curve is similar to the one shown
in Figure la, than if it is like the one shown in Figure Ib. One factor which
influences the shape of the distribution curve is the size of the sample taken
for analysis, i.e., the smaller the sample size, the larger the variation in
the observed sulfur values, and, the more the curve will look like Figure la
rather than Figure Ib. The averaging time used for determining compliance with
a given standard similarly influences the shape of the distribution curve.
Since the quantity of coal burned during a given averaging time constitutes
the sample size, a short averaging time corresponds to a small sample size,
and large variations in sulfur content will be observed when compared to a
longer averaging time with a correspondingly larger sample size.
The impact of these considerations is shown in the following tabulation,
in which the averaging emission level required by different averaging times is
listed for various emission limits.
Average Emission Level Required, Ib 802/10^ Btu
Emission Standard,
Ib S02/1Q6 Btu
1.2
0.8
0.4
Long-Term
Averaging
1.2
0.8
0.4
30-Day
Averaging*
0.92
0.62
0.31
24-Hour
Averaging*
0.58
0.30
0.19
* Following recent EPA fhractice, the relative standard deviation (RSD),
defined as a/y where a is the standard deviation and y is the mean value,
was taken as the measure of sulfur variability. A 10 percent RSD was used
as representative of a 30-day averaging period and a 99.87 percent con-
fidence level was adopted. For a normal distribution, this level occurs
at y plus 30. This means that a coal with an average S02 emission of y
will exceed y + 3a only 0.13 percent of the time. A 36 percent RSD and
a 3a confidence level was used as representative of a 24-hour averaging
period.
It is apparent that short-term averaging requirements will greatly reduce
the quantities of raw coal and of cleaned coal which could be burned in com-
pliance with any given emission limit, because the average sulfur content
required for a 24-hour averaging period is less than one-half of the value
required for long-term averaging. The impact of averaging time with respect to
a percentage reduction regulation, although not addressed in this study, is
expected to be important also.
7
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RESULTS OF STUDY
General Discussion
The potential role of coal cleaning and other control technologies as SO-
emission control techniques for utility boilers was evaluated in terms of the
quantities of coal reserves which could be used in compliance with various
alternative NSPS. Such reserve quantities are referred to subsequently as
available coal. In this context, "available" means suitable for compliance with
a given emission standard, rather than ready for use. For each alternative
NSPS, the quantities of available coal were determined for different com-
binations of control technology application. These tonnages are compiled in
Tables 13-23 in a later section. In order to emphasize the impact of various
NSPS on the potential demand for coal cleaning and other control techniques,
the coal quantities in tons were converted to years of coal availability by
dividing by an assumed annual utility consumption of coal. In each case the
utility consumption of coal projected for 1985 was arbitrarily selected for
this conversion factor. The resulting quantities, years of coal availability,
are not intended to reflect the actual lifetimes of coal reserves, since other
coal uses, logistics of transportation, contractual arrangements, etc., have
not been considered. Rather, the years of coal availability are merely numbers
which reflect, on a regional basis, both the reserves and a significant fraction
of the total coal demand. It is this ratio of potential supply and potential
demand which more clearly reflects the impact of revised NSPS on the potential
for coal cleaning to serve as an S02 control measure for utility boilers.
The use of electricity is expected to increase during the period 1976-
1985, possiblv at a lower annual rate than observed in past decades. Demand and
energy requirements will be closely allied to the state of the economy and real
growth of the Gross National Product. Conservation, higher prices for electricity,
and a slight decrease in the rate of population growth will tend to reduce the
growth rate while the curtailment of gas and oil use will tend to increase it.
The Federal Power Commission has projected that the total national electric energy
requirement in 1985 will be within the approximate range of 3 to 3.5 million
gigawatt-hours (1 gigawatt is one million kilowatts). This compares with about
2.2 million gigawatt hours in 1977.
8
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The Energy Policy and Conservation Act of 1975 was enacted "to in-
crease domestic energy supplies and availability; to restrain energy demand;
to prepare for energy emergencies; and for other purposes." Many of the
provisions of this act will have significant impact on the availability of
fuels to the electric industry.
The bill provides for the extension of the Federal Energy Administra-
tion's (FEA) coal conversion authority enforceable through January 1, 1985.
With this authority the FEA can order a power plant which is burning oil
or gas to switch to coal, if the plant has coal burning capabilities. The
conversion must also be approved by the Environmental Protection Agency.
The FEA has estimated that if all units considered as potential candidates
for conversion are in fact converted to coal, utility annual coal demand
would be increased by 42.6 million kkg (47 million tons) by 1984.
The FPC estimates that electric power generation by coal-fired boilers
will increase from 45% in 1975 to 49% in 1985. This translates into an
annual utility demand for coal of 715 million kkg (788 million tons) in 1985.
The conversion-to-coal demand would therefore increase this amount by
approximately 6%.
A further potential influence on projected utility coal demand is the
National Energy Plan proposed by President Carter. Which portions of this
plan will be enacted is not clear at this time. However, various govern-
ment agency analysts have concluded that it is not likely to have a large
impact on utility coal use.
Availability of Low-Sulfur Coal, Physically
Cleaned Coal, and Flue Gas Desulfurization
to Meet Optional NSFS
Given the projected utility demand for coal, an analysis was conducted
of the availability of low-sulfur coal and physically cleaned coal to meet
this demand. The availability was determined for various alternative NSPS
and, for comparison, for the case of no emission standards. The availability
of coal which could meet the various NSPS with coal cleaning together with
flue gas desulfurization (FGD) also was determined.
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The bounded solution to this analysis was obtained by using:
1) The projected annual demand for coal, by all the coal-fired
electric utilities (existing and new) scheduled for 1985
operation
2) The annual coal demand by the potential utility candidates
for conversion from oil and gas to coal
3) The demonstrated recoverable coal reserve base
4) The potential cleanability of the reserve base
5) Assumptions regarding the effectiveness of FGD applied to
the combustion products from cleaned coal
6) Assumptions regarding the variability of sulfur in coal.
The analytical methodology and the detailed results are described in
a subsequent section. Summaries of the results of the analysis are dis-
played in the form of bar charts in Figure 2, in which sulfur variability is
not considered, and Figure 3, in which sulfur variability effects are included.
The bar chart is an effective means of conveying the effects of emission regu-
lations and techniques for compliance on the coal availability throughout the
United States. The definitions of the regions designated are given in Table 1.
The nature of the information presented in Figure 2 may be illustrated
by reference to the four bars for the entire United States. If there were
no emission standards, the demonstrated recoverable coal reserve base
could supply the utility demand for 330 years if consumed at the- projected
1985 rate. For a NSPS of 1.2 pounds S02 per 10 Btu, raw coal availability
drops to 46 years. Physical cleaning to the level noted increases the
availability to 79 years. If FGD and PCC were applied, the availability
becomes 326 years. This is almost the equivalent of the raw coal recover-
able reserve. This simply means that there is a small amount of coal which
could not meet a 1.2 pounds SO^ per 10 Btu on a long term averaging basis
even with PCC and FGD applied. If the NSPS were reduced to 0.8 pounds S09
f *-
per 10 Btu, raw coal and PCC coal availability both drop still further.,
Essentially no raw coal or coal which could be sufficiently cleaned is available
if the NSPS were reduced to 0.4 pounds S0~ per 10 Btu, and the availability
drops to 218 years if both PCC and FGD control techniques were applied. A
regional breakdown also is presented in Figure 2.
10
-------
0)
4J
rt
fA
S 500
o
01
''—>
o
1-t
PL.
0)
400
aq
4-1
ed
e
1
o 300
CJ
X
0)
c
o
>,
01
T3
•H
l-i
1)
0)
0)
o
•H
'••0
QJ
200
100
FIGURE 2
COAL AVAILABILITY BAR CHART
STATUS OF THE AVAILABILITY OF COAL TO MEET THE NSPS OPTIONS
FOR ALL COAL-FIRED UTILITIES OPERATING IN 1985 (EXISTING PLUS NEW)
RAW AND PREPARED COAL WITH AND WITHOUT FLUE GAS DESULFURIZATION (FGD)
WESTERN REGION
THE ENTIRE
UNITED STATES
il
^i
i§u
I
^
I
NO 12 O.S 0-4
EASTERN-MIDWEST
REGION
EASTERN REGION
NO 1.2 O.S
WESTERN-MIDWEST
REGION
NO 1.2 0-8 0.4
NO 1.2 0.8 0-4
EMISSION STANDARD (S02 Pounds Per Million Btu)
NO 1.2 b'."8 O4
Raw Coal
Prepared Coal (PCC)
>90% Btu Recovery, Crushed to 1-1/2" Top Size
FGD Combined uith //;•• Prepared Coal
90'" Removal Efficiency, 100*1, of i»Ji'
-------
TABLE 1
DEFINITION OF COAL PRODUCING REGIONS
REGION
APPALACHIA
DESIGNATION
EASTERN
STATES ENCOMPASSED
ALABAMA, EAST KENTUCKY,
MARYLAND, OHIO, PENNSYLVANIA,
TENNESSEE, VIRGINIA, WEST
VIRGINIA.
INTERIOR
BASIN
EASTERN
MIDWEST
ILLINOIS, INDIANA, WEST
KENTUCKY.
BUREAU OF
MINES
DISTRICT 15
WESTERN
MIDWEST
ARKANSAS, IOWA, KANSAS,
MISSOURI, OKLAHOMA, TEXAS
NORTHERN GREAT
PLAINS
THE ROCKIES,
AND
THE PACIFIC
WESTERN
ALASKA, ARIZONA, COLORADO,
IDAHO, MONTANA, NEW MEXICO,
NORTH DAKOTA, OREGON, SOUTH
DAKOTA, UTAH, WASHINGTON,
WYOMING
12
-------
For each region the available coal in the region is compared with the
projected 1985 utility demand for coal in the same region.
All of the information presented in Figure 2 is based on average
sulfur values. Consideration of the effect of sulfur variability was
incorporated in the analysis as summarized in Figure 3. The net effect
of requiring short-time averaging in determining compliance with a stated
emission limit is to reduce the availability of raw coal and of cleaned
coal, as can be seen by comparing Figure 3 with Figure 2.
The summary results of Figures 2 and 3 indicate the following con-
clusions.
1) PCC alone will be of limited value in meeting reduced NSPS
for utilities. PCC should have a role in combination with FGD.
2) FGD or other control techniques with comparable sulfur-
removal effectiveness will be required, if more stringent
SO « emission standards are imposed.
3) If the practicality of coal distribution from one region
to another region were ignored, and if it were assumed
that the coal reserves were available for use anywhere
in the United States, compliance with more stringent
regulations would still be impossible without FGD or
comparable control techniques.
4) Since the potential for conversion from oil and gas
to coal would increase the demand for coal by only
6 percent, this by itself would only cause a small ripple
effect in the coal availability results.
Somewhat more detailed summaries of the results of the availability
\
analysis are presented in Figures 4-13. These sets of curves cover the four
major coal-producing regions plus a composite graph for the entire United
States. In each case the first figure shows coal availabilities based on
average sulfur content, while the figure immediately following shows coal
availabilities obtained with consideration of the variability of sulfur in
coal. For example, Figure 6 shows results for the Eastern Region on the
basis of average sulfur content. If there were no NSPS, the "Maximum Years
13
-------
0)
« 500
00
OS
H
0)
.U
0
(1)
400
OJ
fi
J-J
4-J
03
O
o
w
hJ C
cq O
M 4J
H1 rl
O rH
tfl
< 00
W 0)
0)
•H
>
•H
P
03
CD
&
01
3
O
•H
00
T.T.T.TY BAR CHART
STATUS OF THE AVAILABILITY OF COAL TO MKKT THK MSPS OPTIONS
1'OR'ALL COAL-FIRED UTILITIES OPERATING IN 1935 (F.XISTIMG PLUS NEW)
RAW AND PREPARED COAL WITH AND WITHOUT FLUE GAS DKSULL'URIZATION (FGU)
'./!•;r/lCKN W-GIOM
INCLUDING THE EFFECTS OF THE.VARIABILITY OF THE SULFUR CONTENT OF COALS
THE RELATIVE STANDARD DEVIATION, RSD = 10%, COMPLIANCE = 99.87%
THE ENTIRE
UNITED STATES
EASTERN-MI DY/EST
REGION
EASTERN REGION
SSJ
WESTERH-HIOWEST
REGION
&:•
NO 1.2 0.8 0.4" NO 1.20-80.4 NO 1.20-80-4 NO 1.2
EMISSION STANDARD (S02 Pounds Per Million Btu)
Coat fPCC) f^^\ FCD Combined vlf-.1i f.J:.-> P>'
-------
FIGURE 4
CO
H
CO
1
s
H
to
a
§
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH
FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
THE ENTIRE UNITED STATES
STANDARD
2.0
WITHOUT FGD
BTU RECOVERY COAL PREPARATION
1. 1001
2. >90%
3. >50%
RAW
1-1/2" TOP SIZE
14 MESH TOP SIZE
pQ
S3 1.6
o
M
d
$5 1.2
CM
O
10
10
.8
.4
Present Standard
Alternative NSPS
Alternative NSPS
100
150
200
250
300
350
400 450
500
550
600
50
YEARS OF AVAILABLE COAL (at an Assumed Consumption of 788 x 10° Tons/Year)
^DECREASING YEARS OF OPERATING COAL SUPPLY
NOTE: FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATIONS
(This primarily affects curve 3. showing a higher coal availability than is actually the case).
-------
FIGURE 5
I
o
y*
M
Z
in
INCLUDING THE EFFECTS OF THE VARIABILITY OF THE SULFUR CONTENT OF COALS
THE RELATIVE STANDARD DEVIATION, RSD = 10%, COMPLIANCE = 99.87%
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
THE ENTIRE UNITED STATES
STANDARD
2.0
WITHOUT FGD
1 2 3
B
BTU RECOVERY COAL PREPARATION
RAW
1-1/2" TOP SIZE
MESH TOP SIZE
K 1.6
o
H
$3 1.2
o
w .8
g
o
Present Standard
Alternative NSPS
Alternative NSPS
100
150
200
250
300
350
400
450
500
550
600
YEARS OF AVAILABLE COAL (at an Assumed Consumption of 788 x 10 Tons/Year)
^ DECREASING YEARS OF OPERATING COAL SUPPLY
NOTE: FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATIONS
(.T_V-vjL_-c.._.. CT. »- X c>^ r- \ \ ^ r>.€.•go.e.fc «a *^v. .-^-.r-> 3. . *^ K rv._-/_i t^ o .->_ U i o 1_">..C_1" T-*** •A 1 O^f1^ Lv1'? ' 1 ' * X l Jinn i s .id t i;n 7 I y t ho cnsrO .
-------
FIGURE 6
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH
FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN REGION
CO
H
V)
H
Z
w
H
CO
§
STANDARD
2.0
§
55 1.6
o
M
d
S 1.2
.8
.4
CM
O
CO
CO
WIT-HOUT FGD
BTU RECOVERY COAL PREPARATION
003
2.
3-
RAW
1-1/2" TOP SIZE
1*1. MESH TOP SIZE
Present Standard
Alternative NSPS
Alternative NSPS
1 2 3
WITH FGD
50
100
150
200
250
300
350
400
450
500
550
600
NOTE:
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
^DECREASING YEARS OF OPERATING COAL SUPPLY
FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATION'
(This primarily affects curve 3, showing a higher coal availability than is actually the case).
-------
FIGURE 7
INCLUDING THE EFFECTS OF THE VARIABILITY OF THE SULFUR CONTENT OF COALS
THE RELATIVE STANDARD DEVIATION, RSD = 10%, COMPLIANCE = 99.87%
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S0? EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN REGION
STANDARD
co g
I
Vi
H'
I
t/5
s
H
to
I
2.0
1.6
1.2
.4
WITHOUT FGD
2 3
BTU RECOVERY COAL PREPARATION
1. 100%
2.
3.
RAW
1-1/2" TOP SIZE
\k MESH TOP SIZE
Present Standard
Alternative NSPS
N Alternative. NSPS
Tf ., .- .... _ „ .
JL
WITH FGD
j
i
j i
I
L
550 600
50 100 150 200 250 300 350 400 450 500
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
^DECREASING YEARS OF OPERATING COAL SUPPLY
UOTE: FOR PREPARED COAL THE REDUCTION III YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATION
•»_.
-------
FIGURE 8
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH
FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN - MIDWEST REGION
STANDARD
to
CO
H
%
O
53
CO
I
2.0
I"
a
v 1 7
S x » 6
.8
.4
WITHOUT FGD
BTU RECOVERY COAL PREPARATION
1. 100%
2. >90%
3. >50%
RAW
1-1/2" TOP SIZE
14 MESH TOP SIZE
Present Standard
Alternative NSPS
Alternative NSPS
WITH FGD
J I
50
100
150
200
250
300
350
400
450
500
550
600
NOTE:
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
^DECREASING YEARS OF OPERATING COAL SUPPLY~
FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATIONS
(This primarily affects curve J>, showing a higher coal availability than is actually the case).
-------
FIGURE 9
INCLUDING THE EFFECTS OF THE VARIABILITY OF THE SULFUR CONTENT OF COALS
THE RELATIVE STANDARD DEVIATION, RSD = 10%, COMPLIANCE = 99.87%
FOR DIFi
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FFERENT LEVELS OF COAL PREPARATION COMBINED WITH FLUE GAS DKSULFURIZAT
'URIZATION (FCD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN - KUDWEST REGION
N>
O
en
8
to
p
M
H
C-j
d
BTU RECOVERY COAL PREPARATION
.1. 100%
2. >90%
•3. >50%
RAW
1-1/2" TOP SIZE
14 MESH TOP SIZE
Present Standard
Alternative NSPS
Alternative NSPS
1
I
I
IIOTT:
50 100 150 200 250 300 350 400 450 500 550 600
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
^ _. . , , .._ . .
^DECREASING YEARS OF OPERATING COAL SUPPLY
FOR !V,.:?Af>EO COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THI{ CALCULATION
(fhi-i ^ r \ rv-> r \ 1 v a££e.dtR «-.urv/a 3. shov/ino a highiir coal n v.-a t 1 n b i 1 i f v tt~>.-in != -.,-»-..
-------
FIGURE 10
H
I
S5
M
PS
H
to
o
s
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S0? EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH
FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
WESTERN - MIDWEST REGION
STANDARD
WITHOUT FGD
2.0
pq
§ 1'6
M
•J
a 1.2
o
c/i .8
.4
BTU RECOVERY COAL PREPARATION
1. 100%
2. >90%
3. >50%
RAW
1-1/2"
U MESH
TOP
TOP
SIZE
SIZE
Present Standard
Alternative NSPS
Alternative NSPS
50
100
150
200
250
300
350
400
450
500
550
600
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
^DECREASING YEARS OF OPERATING COAL SUPPLY
NOTE: FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATIONS
(This primarily affects curve 3, showing a higher coal avilability than is actually the case).
-------
FIGURE 11
INCLUDING THE EFFECTS OF THE VARIABILITY OF THE SULFUR CONTENT OF COALS
THE RELATIVE STANDARD DEVIATION, RSD = 10%, COMPLIANCE = 99.87%
FOR DIFFERENT
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE SO, EMISSION,
FFERENT LEVELS OF COAL PREPARATION COMBINED WITH FLUE GAS DESULFUREZATTON (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
WESTERN -.MIDWEST REGION
CO
1
I
H
V.
e<
to
o
STANDARD
2.0
g 1-5
g
H i o
^4 JL • ^
O
CO
I
.'«
WITHOUT FGD
1 2 3
WITH FGD
-BJ3LJLE.CP_V§J^Y. COAL PREPARATION
1. 100%
2.
3.
RAW
1-1/2" TOP SIZE
1'* MESH TOP SIZE
Present Standard
Alternative NSPS
Alternative NSPS
50
100
150
200
250
300
350
400
A50
500
550
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
600
^ DECREASING YEARS OF OPERATING COAL SUP.PLY
NOTE: FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATIONS
-------
FIGURE 12
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH
FLUE GAS DESULFURIZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
WESTERN REGION
H
IO
H
B
S
K
1
STANDARD
2.0
55 1.6
o
M
d
S 1.2
CM
O
vi .8
o
BTU RECOVERY COAL PREPARATION
1.
2.
3.
100%
RAW
1-1/2" TOP SIZE
14 MESH TOP SIZE
I - WITH FGD
* 1 ,2,3 ALL
: ATTAIN THE MAXIMUM
I
WITHOUT FGD |5j
1 2 3 § Present Standard
JS
'§ Alternative NSPS
!i
S Alternative NSPS
ii
50
100
150
200
250
300
350
400
450
500
550
600
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
^DECREASING YEARS OF OPERATING COAL SUPPLY
NOTE: FOR PREPARED COAL THE REDUCTION IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATIONS
(This primarily affects curve 3, showing a higher coal availability than is actually the case).
-------
FIGURE 13
INCLUDING THE EFFECTS OF THE VARIABILITY OF THE SULFUR CONTENT OF COALS
THE RELATIVE STANDARD DEVIATION, RSD = 10%, COMPLIANCE = 99.87%
YEARS OF AVAILABLE COAL AS A FUNCTION OF ALLOWABLE S02 EMISSION,
FOR DIFFERENT LEVELS OF COAL PREPARATION COMBINED WITH FLUE GAS DESULFUREZATION (FGD)
FOR ALL UTILITIES SCHEDULED FOR 1985 OPERATION (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
WESTERN REGION
STANDARD ....... ... ....... - ---,
~i
H
H
O
if.
t-j
C
OTE:
2.0
B
g 1.6
M
3
O
CO
w .3
1 ,
f
0
FOR PREPARED
(TK\^ r. r ; rn.-. .- ;
BTU RECOVERY COAL PREPARATION ,-„„
i — Vu in rbU
1. 100* RAW J772^~ALL~
2. >902 1-1/2" TOP SIZE , ATTAIN THE MAXIMUM
3. >50S I'l MESH TOP SIZE '
WITHOUT F6D 19
•b
i 2 3 ' § Present Standard
^ ^ — § Alternative NSPS
•z^^^. "*" gj Alternative NSPS
, i i i i i i t i i! i i
50 100 150 200 250 300 350 AOO 450 500 550 600
YEARS OF AVAILABLE COAL (at the Projected 1985 Regional Utility Consumption Rate)
s-
- DECREASING YKARS OF OPERATING COAL SUPPLY
COAL THE REDUCT ON IN YIELD (ASSOCIATED WITH THE BTU RECOVERY) WAS NOT FACTORED INTO THE CALCULATI
\ ,, ^
-------
Available" of raw coal is approximately 220 years. However, at the present
1.2 NSPS, only 34 years of raw coal, and 56 years of cleaned coal (Curve 2
without FGD) are available. The curves in Figure 7 show that sulfur varia-
bility considerations reduce these values to 10 years and 20 years,
respectively.
It should be noted that these results are bounded by the assumptions
outlined in the section on methodology. These assumptions are such that
maximum availabilities (given the reserve base and washability data) are
obtained for each selected control technique and NSPS. Lesser quantities
may, in fact, be available as a result of logistical, economic, or con-
tractual factors which have not been considered in this analysis.
FGD Considerations
The Federal Power Commission has obtained preliminary data (currently being
updated) showing that the total FGD capacity in operation in the United States,
as of the beginning of the calendar year 1977, was 3,716 MW. From the
following section of this report, Table 3, we find that the peak demand in
the United States for 1977 is 396,359 MW. The portion of this demand supplied
by coal-fired utilities is 45%. Therefore, the FGD cpaacity is approximately
2 percent of the peak demand for coal-fired units.
The projected peak demand for the coal-fired electric utilties for
the 1977-1986 period is shown in Figure 14. Also shown is the required FGD
capacity to service a given percentage of the total capacity of the coal-
fired utilities in the United States.
A tabulation of projected utilization of FGD by new coal-fired units
which was attributed to PEDCO was received from OAQPS. This tabulation
shows a cumulative FGD capacity of 140,OQOJMW by the end of 1985 as shown
in Figure 14. ;!
w (r^'l '
.•1 fc'9 '
< e"0 p ^
25
-------
FIGURE 14
PROJECTED CAPACITY DEMAND-
PEAK POWER DEMAND AND REQUIRED FGD CAPACITY
350,000 -•
300,000 -'
250,000
Jz
53
H
H
CM
O
200,000
150,000
100,000 -•
50,000
FGD CAPACITY REQUIRED TO SERVICE ALL
COAL-FIRED UTILITIES PROJECTED FOR 1985
PEAK
DEMAND
1985 FGD CAPACITY
ONLY NEW COAL-FIR
SERV
UTILITIES
FGD CAPACITY TO SERVICE
UTILITIES CONVERTED TO
FGD
CAPACITY
100%
75%
50%
25%
10%
5%
1977 78
79
80
81
82
83
84
85
—H-
86
CALENDER YEAR
26
-------
Applicability of Combined Physical Coal
Cleaning (PCC) and Flue Gas Desulfurization
(FGD) to Meet Optional NSPS
The sulfur and ash contents of coal are reduced by physical coal cleaning
(PCC), with the attendant benefits of reduced transportation costs, reduced
ash-handling costs at the point of use, improved boiler operation and
efficiency, and reduced SOX and particulate emissions when the cleaned coal is
burned. However, the sulfur-reduction potential is limited since the organic
sulfur cannot be removed by this process. Therefore, not all coals can be
cleaned to compliance levels, and, as noted in the preceding section, if the
NSPS is reduced, the applicability of PCC as the sole control measure vanishes.
Another possible approach to SOX control could be the combined use of PCC and
flue gas desulfurization (FGD). This combination of control techniques was
considered in the availability analysis of the preceding section. If PCC, a
relatively low-cost process, can be used to reduce the sulfur content to near
the NSPS compliance level, then FGD, a relatively high-cost process, could be
used to treat just a portion of the flue gas stream in order to achieve NSPS
compliance. The size of the FGD unit required, and hence its cost, would be
reduced. A further benefit would accrue from using FGD on only a portion of
the flue gas if the recombined treated and untreated flue gas streams retain
sufficient bouyance that reheat would not be required to achieve plume rise.
The economics of combined PCC and FGD have been analyzed by Hoffman-
Muntner Corporation in a study for EPA through the Bureau of Mines*, and by
PEDCo-Environmental Incorporated in a study for EPA/RTP**. These studies showed
that a lower cost can be expected by using the combined technologies if the
sulfur content of the cleaned coal is near compliance levels. As the difference
between sulfur content and compliance level increases, FGD must be used on a
greater percentage of the flue gas, reducing the potential benefits which
accrue from scrubbing only a fraction of the flue gas stream. However,
because there are many variables involved, it is not^ possible __to__re_achi a
general conclusion regarding the cost effectiveness of using PCC combined with
FGD as a sulfur control measure, thus, the required analysis must be done in
a site-specific framework. For example, Eastern underground coal mined by
continuous mining techniques generally must be cleaned to remove high levels
* See Reference 1 on page 97.
** Miranda, C. F., et al., ''An Optimization Strategy for Control of SOX
From Coal-Fired Power Plants".
27
-------
of mineral matter as a prerequisite for satisfactory boiler operation. In
such a case, the incremental cleaning cost to achieve effective sulfur removal
may be more than offset by reduced scrubbing costs, even if much of the flue
gas stream must be scrubbed.
A standard specifying a percentage reduction in sulfur emissions was not
considered among the alternative NSPS during the course of this study. However,
a standard requiring 90 percent sulfur removal has been proposed by EPA since
the completion of this analysis. Although the proposed rule would allow credit
for precombustion sulfur removal, no PCC process can achieve 90 percent sulfur
removal. Thus, it would seem that, if such a standard were adopted, PCC might
not have a useful role. But, on the other hand, PCC could be used as a means
of reducing the efficiency requirements of the scrubber. As an example, if 50
percent of the sulfur were removed by coal cleaning, then the scrubber would
have to operate at only 80 percent removal to achieve the 90 percent removal
required by the proposed rule. In view of the current status of scrubber tech-
nology, the difference between 80 and 90 percent removal would be a significant
consideration in the design of a new system. Furthermore, if a scrubber system,
installed for the purpose of meeting 90 percent removal, failed to operate
consistently at that level, a switch to cleaned coal might provide the solution
to the problem. In light of such considerations, PCC could have a role in
meeting a percentage removal standard.
28
-------
Applicability of Fluidized-Bed
Combustion to Meet Optional NSPS
Fluidized-bed combustion (FBC) of coal is a technology under develop-
ment which has several attractive features. The fluidized-bed system pro-
vides high heat transfer rates, allowing smaller sized units for a given
capacity. The maximum combustion temperature is reduced, resulting in lower
NO production. Finally, if the fluidized bed is composed of a reactive
X
solid, S0~ can be removed in the combustion zone. Reactive bed materials
of calcined dolomite (MgO-CaO) or calcined limestone (CaO) have been studied
most extensively.
In practice, the amount of S02 removed by a CaO bed is not controlled by
thermodynamic equilibrium. The partial pressure of S02 in equilibrium with CaO,
CaS04, and 02 is 1.25 x KT7 atm at 1656 F, or about 0.125 ppm. This very low
value is not achieved in practice because equilibrium is not reached.
Relatively high S02 removal has been obtained in experimental units by
using greater than stoichiometric quantities of CaO. This need to have
Ca/S ratios of 2 or greater leads to large quantities of spent limestone.
This material must be disposed of in a once-through system design.
Research on methods of regenerating the spent bed material are in progress.
The excess CaO required for efficient S02 removal complicates the regener-
ation processes by increasing the quantity of material to be processed.
For these reasons considerable research is being devoted to keeping the
Ca/S ratio requirement at a minimum.
Reduction of NSPS for S02 would not, out of hand, preclude the further
development of FBC as a control technique, since, as indicated above, the
practical S0? removal efficiency is ,not controlled by thermodynamic equi-
librium. However, a reduced NSPS would require the use of increased Ca/S
ratios to obtain the higher S02 removal efficiencies needed for compliance.
Since it is desirable to minimize the Ca/S ratio, this would be expected to
delay the development of FBC to some extent.
In summary, theoretically FBC can be employed as a control technique
to meet reduced emission standards. Whether or not this can be achieved
practically and economically depends on the course of the research and
29
-------
development activities. Reduced emission standards would be expected
to make the development task more difficult.
Applicability of Coal Conversion
Processes to Meet Optional NSPS
One of the alternative approaches to the control of SO emissions
J\.
associated with the use of coal in stationary sources is the conversion of
coal to a clean fuel by gasification or liquefaction. Research efforts to
produce clean fuels from coal are proceeding along three major lines:
• High-Btu gas or synthetic natural gas (SNG)
• Low-Btu gas
• Synthetic liquids [the product of the solvent refined
coal (SRC) process is actually a solid at ambient
temperature].
None of these processes is sufficiently developed to serve as a near-term
SO control technique. SNG is not expected to be used as a boiler fuel.
A
The price will be too high, and the eventual need to replace natural gas
in the residential sector will preclude burning SNG under boilers.
Low-Btu gas has promise as a boiler fuel, particularly for plants
in which the gasification process is integrated with a combined-cycle power
plant. Such integrated designs offer promise of minimum heat rejection, and
hence, improved overall conversion efficiency. The sulfur problem remains
but is dealt with differently. In most gasification processes sulfur is
volatilized under reducing conditions to form I^S, scrubbed from the fuel
gas, stripped from the absorption liquor as a concentrated H-S stream, and
converted to sulfur using Claus plant technology. If strict emission regu-
lations are applied to such processes, a Claus plant tail gas treatment
process will be required. Direct oxidation systems, such as the Stretford
process, etc., may be used in lieu of the absorption/Glaus approach.
Liquefaction processes involve hydrogeneration of coal to produce
various liquids. Sulfur is released in the processing as H2S which is
scrubbed from the byproduct gas. The liquids produced are low in sulfur
content and can be burned without subsequent SO control.
30
-------
In summary, coal conversion processes to produce clean fuels are not
sufficiently developed to serve as near-term SO control techniques.
X
Reduced emission standards for stationary combustion sources will not
impact on these processes in the long term since the sulfur problem is
encountered in the conversion step. Regulations applicable to such pro-
cessing will have an impact on the final cost of the clean fuel.
31
-------
ELECTRIC POWER SUPPLY AND DEMAND 1977-1986
General Discussion
The information in this section concerns the bulk electric power supply
and demand in the contiguous United States as projected for the period 1977-
1986. It was obtained from the Federal Power Commission Bureau of Power Staff
Report. Data as to projected electrical demands, energy and generating capa-
bility have been summarized from the reports filed with the Commission on
April 1, 1977, by the Regional Electric Reliability Councils, in response to
FPC Order 383-4. Council acronyms and geographic boundaries are given in
Figure 15.
Formation of the councils was given impetus by the Commission re-
commendation that the utility industry establish "strong regional organiza-
tions" to coordinate planning, construction and operation of the national bulk
electric power supply. Through the standing and special committees of the
councils, planning and operating personnel of the electric utilities (Federal,
s-tate and municipally owned, privately owned and cooperatively owned) endeavor
to provide for rational economic development of electricity supply. The
Commission, in promulgating its series of orders (383-1, -2, -3, -4) related
to reliability and adequacy of bulk power supply, set up a frame of reference
for the compilation of certain planning data on a long-range regional basis.
The essential ingredients of satisfactory power supply are load forecasts made
with reasonable confidence, timely installation of new generating plants, a
properly coordinated transmission network and dependable supplies of fuel for
electric generation. Since 1970, the councils in responding to the series of
"383" orders have been furnishing data enabling the Commission to monitor
electric system planning in the large.
The electric utility power system in the U.S. is made up of three
component networks. The seven strongly interconnected council areas (ECAR,
MAAC, MAIN, MARCA, NPCC, SERC, AND SWPP) comprise essentially a single
32
-------
to
Go
Are*
Coordi-
emcnt
ca Intcr-
pool Network.
MAAC - MJd-Atlantic
Council
'.'CA - Mid-Cont!n?nt Area
RclIibUity Coordi-
nation Agjesmcnt
NTCC - Northc :t Pov.er
i CoorJinatini; Counctl
-Southi-;jt:ri> E!.cttic
Reli.-Mllty Council
-Soulliv. ,;t Fo,.\;
Pool
ERCOT -Electric RoU-bP'ty
Council of Texrj
WSCC - WetIcrn S> ktcmis Co-
-------
network covering all or part of 39 states. Interconnections among the systems
in the seven councils are sufficient for the interchange of significant
amounts of power in emergencies and for economic purposes. The 14 western
states (all or in part) are within the area of WSCC, which, while it has
numerous intraregional interconnections, has only minor interconnection
capability with the other regional council areas. ERGOT is the third network.
The ERGOT systems comprise an interconnected group that has no trans-
mission interconnections with any other council region, supplying power only
within a large part of the State of Texas.
Peak Demand Forecasts
"Peak Demand" in its customary electric power system sense means the
greatest one-hour use of electric energy during a specified period. Most
systems have two periods when use of electricity is high: summer and winter.
In many regions of the country, use of electric power is greater in summer
than in the winter, hence the "summer peak demand" is greater than the
"winter peak demand". The projected council summer and winter peak demands
for the period 1977-1986 are listed in Table 2. The contiguous United States
average annual summer and winter growth rates for the period are 5.7%
and 5.8%, respectively (Table 3). Note that the data reported were developed
and compiled in late 1976 and early 1977, and reflect economic expectations
then current.
The growth rate of demand reflects the combined workings of several
factors as viewed by the electric utilities: attempts at load management
and conservation; higher electricity prices and new pricing schedules; a lower
growth rate of the national economy. Substitution of electricity for fossil
fuels, where feasible, will tend to offset the foregoing. An additional
factor, which may have different weights in different areas, is increased use
of electricity caused by environmental pressures. Air pollution abatement
devices, for instance, may use electrostatic precipitators, thus directly
requiring greater use of electricity. Or, mechanical and chemical methods of
removing potential pollutants, by increasing the obstruction to flow of process
gases and the gases resulting from combustion, require greater fan capacity which
results in more use of electricity. In power plants, the use of scrubbers for
flue gas desulfurization, precipitators that remove extremely high percentages
34
-------
TABLE 2
PEAK DEMAND -
AS PROJECTED APRIL 1, 1977
BY THE REGIONAL ELECTRIC RELIABILITY COUNCILS
CONTIGUOUS UNITED STATES
MEGAWATTS
SUMMER PEAK DEMAND
YEAR
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
ECAR-/
59,838
63,461
67,156
71,150
75,111
79,323
83,655
88,318
93,186
98,293
NPCC -'
ERCOT
27,582
29,305
31,077
32,920
34,830
37,016
38,996
41,255
43,234
45,438
MAAC
32,650
34,200
35,780
37,400
39,050
40,730
42,450
44,230
46,030
47,810
MAIN
33,663
35,716
37,932
40,170
42,417
44,832
47,402
50,172
53,040
56,039
MARCA y
17,664
18,945
20,278
21,783
23,349
24,882
26,376
27,887
29,500
31,066
N.E.I/
13,905
14,648
15,455
16,315
17,209
18,152
19,125
20,166
21,255
22,384
N.Y.ft/
21,590
22,430
23,340
24,230
25,040
25,850
26,850
27,950
28,910
29,930
FLORIDA
15,681
16,692
17,796
18,902
20,041
21,214
22,347
23,422
24,453
25,490
SERC
SOUTHERN
19,946
22,095
23,977
25,816
27,814
29,769
31,848
33,930
36,081
38,561
TVA
20 , 150
21,650
23,350
25,050
26,250
27,400
28,650
29,950
31,250
32,650
VACAR
26,245
28,044
29,995
32,073
34,096
36,099
38,044
40,375
42,780
45,297
SWPP
37 , 132
39,895
42,586
45,832
48,806
52,278
56,053
60,019
64,214
68,660
WSCC ±.>
70,313
74,867
78,971
83,666
88.051
92,345
96,839
101,364
106,542
111,350
WINTER PEAK DEMAND
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
58,987
62,481
66,370
70,175
74,386
78,713
83,255
88,128
93,195
98,548
19,161
20,551
21,746
23,012
24,446
26.024
27,395
29,046
30,420
31,918
27,970
29,490
31,010
32,530
34,200
35,850
37,560
39,310
41,050
42,830
27,315
29,192
31,106
33,097
35,300
36,615
38,942
41,377
43,707
46,605
15,931
16,960
18,166
19,448
20,754
21,958
23,221
24,723
26,141
27,661
15,217
16,051
16,918
17,846
18,820
19,814
20,851
21,964
23,134
24,379
19,690
20,450
21,340
22,150
22,990
23,870
24,850
25,920
26,880
27,880
15,708
16,762
17,802
18,938
20,043
21,124
22,165
23,194
24,217
25,235
16,960
18,270
19,611
21,050
22,558
24,132
25,840
27,690
29,538
31,783
23,150
25,100
27,200
28,700
30,100
31,550
33,050
34,650
36,300
38,150
25,179
27,106
29,234
31,447
33,703
36,051
38,551
41 , 140
43,805
46,571
26,350
28,133
30,278
33,604
34,671
36,993
39,841
42,686
46,686
48,833
68,829
73,142
77,371
81,617
85,840
90,202
94,731
99,221
104,376
109,273
\J The demands listed include interruptible loads and exclude inter-regional purchases and sales.
y Includes only United States portion of Council.
3/ Total for the alx New England states.
4/ New York Power Pool.
5_/ Revised demand data for ECAR was obtained too late to be incorporated in this report.
However the greatest change for any uear would be less than one tenth of one percent.
SOURCE: April 1, 1977 responses to Appendix A-l of FPC Docket R-362 (Order 383-4), Item No. 1.
-------
TABLE 3
PROJECTED GROWTH OF PEAK DEMAND^'
CONTIGUOUS UNITED STATES '
1977-1986
SUMMER PEAK DEMAND PERIODS
Total U. S. Annual Increase
Year Peak Demand MJ 7»
1977 396,359
1978 421,948 25,589 6.5
1979 447,693 25,745 6.1
1980 475,307 27,614 6.2
1981 502,064 26,757 5.6
1982 529,890 27,826 5.5
1983 558,635 28,745 5.4
1984 589,038 30,403 5.4
1985 620,475 31,437 5.3
1986 652,968 32,493 5.2
Average Growth Rate =5.7
WINTER PEAK DEMAND PERIODS
1977-78 360,447
1978-79 383,688 23,241 6.4
1979-80 408,154 24,466 6.4
1980-81 433,614 25,460 6.2
1981-82 457,811 24,197 5.6
1982-83 482,896 25,085 5.5
1983-84 510,252 27,356 5.7
1984-85 539,049 28,797 5.6
1985-86 569,449 30,400 5.6
1986-87 599,666 30,217 5.3
Average Growth Rate = 5.8
Non-coincident total of demands projected by
the nine Regional Electric Reliability Councils
in their April 1, 1977 responses to PPC Order 383-4.
36
-------
of particulates from flue gases, and cooling towers add to the auxiliary
power requirements of fossil-fuel generating units. The additional auxiliary
power needed by generating units does not appear in the load forecasts,
because the forecasts include only customer requirements and transmission
and distribution losses. But the same type of additional power, when used
by customers of a utility, does appear as a load requirement. For the
Tennessee Valley Authority's (TVA) system, for instance, "it is expected that
7 percent of industrial electricity consumption will be utilized for pollution
control devices among the 50 large TVA-served industries which account for 20
percent of area load."
Energy Forecasts
Electric energy represents the total amount of electricity used, as
differentiated from the demand (rate of use of electricity). The total annual
electric energy requirement projected for each council area for the period
1977-1986 is listed in Table 4. Each council area of course has different
geographic, industrial and demographic characteristics that result in differ-
ing uses of electric power and different annual growth rates. The total U.S.
annual net energy requirements projected for 1977-1986 are shown in Table 5.
Council load and capacity factors based on projected net energy and peak loads
are given in Table 6.
Generating Capability Projections
The construction of generating units is subject to the negative pressures
of financing and environmental protection, as well as delays for various causes,
and therefore the actual installed capability will probably be less each year
than that projected. The total installed capability of the contiguous U.S.
as projected for the time of the summer and winter peak demands in the years
1977 through 1986 is listed in Table 7.
Annual Coal Demand for New Units, 1976-1985
The updated information on new coal-fired units and their future coal
requirements obtained through the FPC's regional offices is summarized, by
state and geographic region, in Table 8. It shows that, as of October 1976,
electric utilities intended to add 130 new coal-fired units with a total
37
-------
TABLE 4
PROJECTED ANNUAL ELECTRIC ENERGY REQUIREMENTS
FOR THE
REGIONAL ELECTRIC RELIABILITY COUNCILS
CONTIGUOUS UNITED STATES
GIGAWATT-HOURS I/
YEAR
1977
1978
1979
1980
1981
1982
1983
1984
OJ
00 1985
1986
ECAR^
352,500
372,500
334,400
418,300
441,800
466,800
492,500
520,500
549,400
579,900
ERCOT
137,510
147,980
156,690
165,911
176,089
186,966
196,292
207,739
217,107
227,445
MAAC
167,850
176,390
185,357
194,646
204,214
213,717
223,477
233,593
244,003
254,136
MAIN
163,905
173,489
184,525
195,610
207,130
219,327
232,361
246,003
260,697
275,970
MARCA2/
87,857
94,574
102,162
109,194
115,796
123,612
130,478
138,898
146,912
155,453
NPCC
N.E.I/
80,588
84,959
89,472
94,372
99,518
104,941
110,578
116,570
122,870
129,454
*' SERC
N.X.4/
117,552
120,654
125,022
129,096
133,325
138,756
144,784
150,624
156,654
162,305
FLORIDA
78,922
83,911
89,168
94,698
100,398
106,067
111,461
116,610
121,671
126,740
SOUTHERN
102,204
110,964
119,427
128,382
137,701
149,084
160,417
171,425
184,197
197,679
TVA
132,270
141,990
154,670
167,740
174,680
182,020
189,590
198,010
205,530
214,190
VACAR •
139,488
149,639
160,324
172,393
184,230
196,229
209,181
222,532
236,660
251,318
SWPP
180,133
192,118
204,807
219,706
232,914
247,859
263,346
279,753
297,970
316,471
WSCC 2/
411,082
437,770
461,874
489,303
513,692
540,443
566,901
594,891
625,699
654,770
i/ 1 gigawatt-hour » 1,000,000 kilowatt-hours.
2/ Includes only United States portion of Council.
3/ Total for the six New England states,
4/ New York Power Pool.
5/ Revised energy data for ECAR was obtained too late to be incorporated in this report.
~ However the greatest change for any year would be only two tenths of one percent.
SOURCE: April 1, 1977 responses to Appendix A-l of FPC Docket R-362, (Order 383-4) Item No. 1.
-------
TABLE 5
PROJECTED ELECTRIC ENERGY GROWTH
AS REPORTED BY THE REGIONAL ELECTRIC RELIABILITY COUNCILS
APRIL 1, 1977 IN RESPONSE TO FPC ORDER 383-4
CONTIGUOUS UNITED STATES
NET ENERGY REQUIREMENT If ANNUAL INCREASE
YEAR GWH 2.1 GWH %
1977 2,151,861
1978 2,286,997 141,090 6.3
1979 2,427,898 140,901 6.2
1980 2,579,351 151,453 6.2
1981 2,721,487 142,136 .5.5
1982 2,875,821 154,334 5.7
1983 3,031,366 155,545 5.4
1984 3,197,148 165,782 5.5
1985 3,369,370 172,222 5.4
1986 3,545,831 176,461 5.2
Average Growth Rate = 5.7
JL/ This is intended to be the sum of all actual loads and
system transmission and distribution losses. It is the
net "sendout" of all power plants.
2_/ 1 gigawatt-hour » 1,000,000 kilowatt-hours.
39
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TABLE 6
ANNUAL LOAD FACTORS i IN PERCENT
AS PROJECTED APRIL 1, 1977 BY THE
REGIONAL RELIABILITY COUNCILS
CONTIGUOUS UNITED STATES
1977-1986
NPCC
YEAR
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
ECAR
67.3
67.0
67.0
67.1
67.2
67.2
67.2
67.3
67.3
67.2
ERCOT
56.9
57.6
57.6
57.5
57.7
57.7
57.5
57.5
57.3
57.1
MAAC
58.7
58.9
59.1
59.4
59.7
59.9
60.1
60.3
60.5
60.7
MAIN
55.6
55.5
55.5
55.6
55.7
55.9
56.0
56.0
56.1
56.2
MARCA
56.8
57.0
57.5
57.2
56.6
56.7
56.5
56.9
56.9
57.1
N.E.
60.5
60.4
60.4
60.4
60.4
60.5
60.5
60.6
60.6
60.6
N.Y.
62.2
61.4
61.2
60.8
60.8
61.3
61.6
61.5
61.9
61.9
FLORIDA
57.4
57.2
57.2
57.1
57.2
57.1
56.9
56.8
56.8
56.8
SERC
SOUTHERN
58.5
57.3
56.9
56.8
56.5
57.2
57.5
57.7
58.3
58.5
TVA
65.2
64.6
64.9
66.7
66.3
65.9
65.5
65.2
64.6
64.1
VACAR
60.7
60.9
61.0
61.4
61.7
62.1
61.9
61.8
61.7
61.6
SWPP
55.4
55.0
54.9
54.7
54.5
54.1
53.6
53.1
53.1
52.6
wscc
66.7
66.8
66.8
66.8
66.6
66.8
66.8
67.0
67.0
67.1
i / T A T?O •-«,. t'i\ - Annual Energy Requirement In MWh 100
I/ Load Factor (/.) - o7fin v Annll^i Pfv:k nAm-nH in MU UU
8760 x Annual Peak Demand in MW
NOTE: According to the Edison Electric Institute's "59th Electric Power Survey" dated April 1976, p. 14,
the annual load factors of the total electric utility industry in the contiguous U.S. for 1973-1975
were: 1973 - 62.0
1974 - 61.2
1975 - 61.4
-------
TABLE 7
PROJECTED GROWTH OF GENERATING CAPABILITY
AT TIME OF SEASONAL PEAK DEMAND PERIODS
CONTIGUOUS UNITED STATES
1977-1986
MEGAWATTS
CAPABILITY AT TIME OF SUMMER PEAK
YEAR
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
TOTAL U.S.
CAPABILITY
512,158
541,592
566,688
591,656
620,586
654,274
689,447
729,335
760,141
792,909
Average
ANNUAL INCREASE
MW
--
29,434
25,096
24,968
28,930
33,688
35,173
39,888
30,806
32,768
Growth Rate
CAPABILITY AT TIME OF WINTER
1977-78
1978-79
1979-80
1980-81
1981-82
1982-83
1983-84
1984-85
1985-86
1986-87
529,431
556,635
581,351
610,120
641,306
672,788
705,259
743,862
773,898
811,992
Average
--
27,204
24,716
28,769
31,186
31,482
32,471
38,603
30,036
38,094
Growth Rate
Z
5.7
4.6
4.4
4.9
5.4
5.4
5.8
4.2
4.3
5.0
PEAK
-
5.1
4.4
4.9
5.1
4.9
4.8
5.5
4.0
4,9
4.8
I/ Total of installed capabilities projected by the nine
~~ Regional Electric Reliability Councils in their April 1,
1977 responses to FPC Order 383-4. Excludes purchases
and sales.
41
-------
TABLE 8
STATE AND REGIONAL COAL REQUIREMENTS FOR NEW UNITS
SCHEDULED FOR OPERATION BETWEEN 1976 - 1985
M * CCJAl UM Ts
SCMrOULI I) f OH |)?KP A
NO. Of
UNITS
CAPACITY
(MM)
INCREMENTAL
COAL DEMAND
IN 19HO
11000 TONSI
QUANTITY ASSURED
BY CQNTHATT
1 1000 t L'F
TONS1 DEMAND
TCTAL NEW COAI LNITS
SCHEDULED File OPFKACICN
PETMCE.V
NO. Of
UNITS
CAPACITY
(KM)
TOTAL
INCREMENTAL CUANTITY ASSURED
COAL DEMAND BY CONTRACT
IN 1965 I 1000 X OF
11000 TONS! TONS) DEMAND
LONN
Mt
MASS
vT
Nik ENGLAND
RtGIUNAL TOTAL
N Y
P A
'< J
Mlt ATLANTIC
REGIONAL TOTAL
I1L
I',D
M ICM
OH 1C
HSC
EAST NORTH CENTRAL
REGIONAL TOTAL
IA
KAN
••INN
M(.
NED
N 0
S 0
htST NORIM CENTRAL
REGIONAL TUTAL
UtLA
FLOX
CA
I'D
N C
i C
M VA
U C
V A
SOUTH ATLANTIC
REGIONAL TOTAL
ALA
KY
MISS
TENN
EAST SOUTH CENTRAL
REGIONAL TOTAL
ARK
LA
OK LA
IK
•«EST SOUTH CENTRAL
REGIONAL TOTAL
AMU
COLC
ID
MCNI
NEV
N M
UTAH
*YO
MOUNTAIN
REGIONAL TOTAL
ORE
CALF
NASH
PACIFIC
REGIONAL TOTAL
U.S. TOTAL
0
4.
&
4
5
7
5
4
i
2*.
4
4
)
4
6
5
U
26
1
2
1
0
1
I
2
0
C
a
«r
5
4
u
13
3
3
6
18
30
a
}
0
J
i
!
3
3
2*
1
b
0
1
130
0
3077
-
3077
1736
3696
1081
20->0
1*57
1C062
1497
2275
I860
1950
2097
2366
-
11997
4CO
904
696
0
720
280
1252
-
4452
1766
2COO
1396
-
5182
1928
1610
2960
9613
1611 1
2750
1710
0
1030
117
792
1215
1330
8944
500
-
_
500
60325
0
10300
-
10300
3145
10S40
2749
4250
3730
24214
5121
6093
5500
5150
4411
13750
-
40025
800
987
1551
0
1410
463
1500
-
6711
I960
4810
2286
-
9076
7260
3500
10046
36307
57113
8065
5415
0
2000
365
3220
2400
4600
26085
400
-
_
400
173924
0
7300
-
7JOO
2340
9990
0
2550
1230
16110
3340
5493
5500
5150
3897
13750
-
371 30
0
987
1551
0
1339
461
0
-
4340
1082
3046
1396
_
5524
7260
3500
10046
34307
95113
5885
5415
0
13)5
365
3220
2400
3100
21720
400
-
—
400
147637
c.o
70.9
-
7G.9
74.4
96.6
C.O
60.0
33.0
66.5
65.2
90.2
100.0
. 100. 0
88.3
ICu.O
-
92.6
0.0
10U.G
10C.O
G.O
95.0
IOC.O
0.0
-
64.7
54.6
63.3
61.1
—
60.9
IOC.O
100.0
100.0
94.5
96.5
72.8
100.0
C.O
66.7
100.0
IOC.O
100.0
67.4
83.3
100.0
—
_
100.0
84.9
3
5
0
B
a
11
10
9
6
44
7
7
5
5
6
10
0
40
1
4
5
1
3
3
2
0
C
14
6
11
4
0
21
5
5
a
38
56
9
6
2
3
6
4
5
5
40
-1
0
0
1
229
240C
3877
-
6277
3236
5143
2735
4 760
2737
19C11
2377
3065
346C
2550
2C97
4486
-
18857
400
1656
4196
800
2160
840
1252
-
11306
3152
4640
1396
-
9388
3326
2690
3660
20966
30644
3060
2210
1000
1730
2117
1A08
1715
2130
15590
500
-
_
SOD
111573
5900
12200
-
181CO
6835
154GO
8149
10150
6470
470G4
8021
116SO
9400
5750
6770
25699
-
67:130
600
3870
6751
15CO
4464
14G7
3000
-
23792
6398
13799
3052
-
23249
12960
9709
112C4
90334
124207
9085
7635
1600
7000
8746
64D5
5238
7100
52869
1200
-
-
12CO
357771
0
7300
-
7300
5975
6068
4000
4400
1230
• 23623
334C
102-.G
6600
4950
5937
25699
-
56776
0
1219
5551
0
1608
0
0
8378
3326
6574
2162
-
12062
12960
9709
9C01
63673
95343
5885
5905
1600
1335
7351
5450
5238
5600
38364
1200
-
_
1200
243046
0.0
59.8
-
40.3
66.7
52.4
49.1
43.3
19.0
50.3
41.6
67.7
70.2
86. :
87. 7
100.0
-
84.3
0.0
31.5
63.4
0.0
36.0
C.O
0.0
_
35.2
52.0
47.6
70.8
.
51.9
100.0
100.0
80.3
70.5
76.8
64.8
77.3
100.0
19.1
64.0
84.0
100.0
78.9
72.5
100.0
-
_
100.0
67.9
Source: Status of Coal Supply Contracts for New Electric Generating
Units 1976-1985, Federal Power Commission, January 1977.
42
-------
c~7 «/ o^tu w,h,<7 P( -h c,^ '* -^' (^
' ' '
capacity of 60,325 megawatts during the years 1976 through 1980. The national
j— —_ . ——•
average unit size planned for that 5-year period is 464 megawatts. By 1980
the projected annual coal requirement will be 2.88 tons per kilowatt of new
capacity, reflecting both a higher average capacity factor for the new units
and a lower average heat content of coal to be used by the new units.
During the period 1981-1985, utilities plan to construct an additional
99 units with a total capacity of JSl.^248 megawatts, i.e., the average unit
size will be 518 megawatts. The average annual coal requirement of units to
t .-
be completed during the second half of the decade is 3.26 kkg (3.59 tons) of
coal per kilowatt of new capacity, underscoring the significant shift to the
low-Btu subbituminous coal_from the_Northern Great Plains Province (Montana
and Wyoming)^and to lignite from the Fort Union Region (North and South Dakota)
and from Texas. The average size of all new units placed on stream during the
entire decade will be 487 megawatts and their average annual coal requirement
in 1985 will be^2*91_kkg_.(3.21 .tons) per kilowatt capacity.
The total 1980 and 1985 coal demand by new coal-fired units and the
portion of that demand which is already under contract, by state and geographic
region, also are shown in Table 6. Thus, in 1980, almost 85 percent, or 133.9
million kkg (147.6 million tons), of the total projected demand of 157.8 million
kkg (173.9 million tons) is already under long term contract. The portion of
the 1985 coal demand already under contract declines to 67.9 percent of the
total projected demand of 324.6 million kkg (357.8 million tons).
There are significant regional differences in the proportion of the
total cost demand which is under contract. Generally, utilities in the western
regions have a much higher proportion of their projected coal demand under
contract than utilities in the eastern regions.
Origin and Destination of Coal For New Units
Of the national total of 11,573 megawatts of new coal-fired capacity
scheduled for service in 1976-1985, 5_8^.8 percent will be located in states west
of thje_JlissjLasJ4iEl_^iver. Except for relatively small quantities of_cpal which
will be shipjged^westward_from the Eastern Coal_Region_ojf the Interior Province,
the new units in the west will depend amost entirely on bituminous and sub-
bituminous^coaT and lignite produced west of the Mississippi. The data supplied
by the utilities project that about 94 percentjDf the incremental coal produced
43
-------
in the west will be used by new units in the west. Because of the lower
average heat content of western coal, units in the west will use more than
their proportionate share of the new coal, i.e., 58.8 percent of the new coal-
fired capacity will require 68.7 percent of the total incremental tonnage.
The western region of the Northern Great Plains (NGP) will provide more
of the incremental steam coal production in the next 10 years than any other
region. Of the 324.6 million kkg (357.8 million tons) of coal demand projected
for new coal-fired units, 128 million kkg (141 million tons) or 39.4 percent
will be supplied from this region. As a result, in 1985 the NGP may account
for one-quarter of all the coal used by electric utilities. In 1975 this
region supplied 10 percent of the total. As can be seen from Figure 16, most
of the coal production from the western region of the Northern Great Plains
(NGP) will be going to adjacent areas of the country. The West South Central
Region will receive 57.0 million kkg (62.8 million tons) from the NGP while
38.9 million kkg (42.9 million tons) will go to the West North Central Region.
In 1975 the East North Central Region was the easternmost area to receive
coal from the Northern Great Plains, but by 1985 a small tonnage will be
shipped as far as the South Atlantic Region.
The four states comprising the Mountain Region—Colorado, Utah, Arizona,
and New Mexico—will supply 10.8 percent of the coal requirements for new coal-
tired units. In 1975, 5.3 percent of all electric utility steam coal came
from these states. Most of the coal from this four-state region going to new
units will remain within the area with many of the new units being mine-mouth
operations.
Bureau of Mines (BOM) District #15 which includes Kansas, Texas, Missouri
and part of Oklahoma will experience a rapid rate of growth in demand for its
coal production. With 15 percent of the coal demand for new units being for
BOM District #15 coal, this region will supply approximately 10 percent of all
electric utility coal in 1985, compared to 3.9 percent in 1975. As can be
seen from Figure 17 virtually all of this coal will stay within the region,
with 96 percent of the total coal output from BOM #15 being consumed in Texas.
The Appalachian Region has traditionally been the Nation's major source
of coal for electric power generation. Of the 430.5 million tons of coal
delivered to electric utilities in 1975, 44.8 percent was Appalachian coal.
Data for new coal-fired units coming on line from 1976 through 1985 show that
44
-------
4>
Ui
WNC - West North Central
WSC - West South Central
ENC - East North Central
SA - South Atlantic
FIGURE 16
FLOW OF COAL TO NEW GENERATINGi UNITS
FROM THE WESTERN REGIONS OF THE
NORTHERN GREAT PLAINS (IN 1000 TONS)
1980
1985
-------
WNC - West North Central
WSC - West South Central
SA - South Atlantic
FIGURE 17
FLOW OF COAL TO NEW GENERATING UNITS
FROM THE EASTERN REGION (INTERIOR PROVINCE)
AND THE FORT UNION REGION, (IN 1000 TONS)
1980
1985
-------
Appalachian will be the source for only 14.5 percent of the new units' coal
requirements. Appalachia will still remain the largest source for steam coal
in 1985, but its share of the total steam coal supply will drop to about 35
percent. As can be seen from Figure 6, 41.4 million tons of the total 52.2
million tons of Appalachian coal required by new units in 1985 will go to
destinations in the East.
The Eastern Region of the Interior Province (see Figure 18), which
supplied 29.4 percent of all the coal delivered to electric utilities in 1975,
will supply 10.2 percent of the coal required for new units in 1985. As a
result, by 1985 this region will supply only about 20 percent of the total
coal used by old and new units of all utilities. Of the 33.0 million kkg
(36.4 million tons) of coal from this region for new coal-fired units, 23.7
million kkg (26.1 million tons) will stay within the region, with relatively
small shipments going to the West North Central, West South Central, and South
Atlantic Regions.
Transport of Coal to New Units
Factors related to coal transport include the following:
a. Contractual agreements for transportation are not always con-
cluded simultaneously with supply contracts* as evidenced by the
proportions of total demand committed to supply and to transport
contracts.
b. Nearly two-thirds of the 1985 coal demand by new units will be
transported by rail. However, only a relatively small share of
the total projected rail shipments, particularly from Appalachia
to geographic regions in the eastern United States, is committed
to contract. The level of contracts is also low for rail ship-
ments from the Northern Great Plains, although not as low as
from Appalachia.
c. The bulk of the shipments by barge will be from Appalachia,
and to a lesser extent from the Interior Basin, to various
regions in the east.
d. Shipments by truck and belt, reflecting the extent of mine-
mouth plant developments, will take place almost entirely in
the west.
47
-------
-p-
00
SA - South Atlantic
FIGURE 18
FLOW OF COAL TO NEW GENERATING UNITS FROM THE
APPALACHIAN REGION, FROM U.S. BUREAU OF MINES DISTRICT 15,
AND FROM THE MOUNTAIN REGION (IN 1000 TONS)
1980
-------
e. Coal deliveries by collier across the Great Lakes to new units
in the East North Central Region will originate in the Northern
Great Plains and the first leg of the shipments will be by rail.
f. Pipeline deliveries are projected for proposed coal-slurry
shipments from the Rockies to plants in the Mountain Region.
49
-------
METHODOLOGY FOR DETERMINING COAL AVAILABILITY
General Discussion
The following input data were used:
1) A realistic projection of the demand for coal by the electric
utility industry... This was obtained from a FPC study,
"Status of Coal Supply Contracts for New Electric Generating
Units, 1976-1985", January 1977.
2) A reasonable assessment of the recoverable reserves... This
was obtained from the Bureau of Mines study, "The Reserves of
U.S. Coals by Sulfur Content", 1C 8693.
3) A method for determining the potential for preparing coal
reserves... This was obtained from the BOM study, "Sulfur
Reduction Potential of U.S. Coals"» RI 8118.
4) A projection of the electric power supply and demand... This
was obtained from the FPC report, "Electric Power Supply and
Demand, 1977-1986", May 1977, and summarized in the second
section of this report.
5) An estimate of the potential demand for coal, if all units
capable of conversion in the electric utility industry, did
convert... This was obtained from the FPC study, "Factors
Affecting - The Electric Power Supply, 1980-85", December 1976.
6) An accounting of the total FGD capacity in operation at the
present time... This was obtained from the FPC report, "Annual
Summary of Cost and Quality of Electric Utility Plant Fuels,
1976", May 1977.
The following factors entered into the use of the above input data;
1) The recoverability factor for underground coal is assumed
to be 50 percent and that for surface coal 85 percent.
50
-------
2) -The wash samples taken as part of the cleanability study are
assumed to accurately represent the recoverable reserve potential
and the coal preparation potential.
1,3) i The reduction in yield and Btu recovery were not factored
\
into the availability calculations.
4) Logistical, cost, contractual, and other relevant parameters
were not factored into the availability calculations.
5) It was assumed that all of the sulfur in the coal goes out of
the stack as SO .
6) A normal distribution of SCL emissions was assumed. A relative
standard deviation (RSD( of 10 percent and a 3a confidence level was
used to characterize the sulfur variability for a 30-day averag-
ing period. This is a simplistic assumption in view of the wide
variability of sulfur, but it is useful until better data are
available.
Significance of Factors
Factor (1) would have to be further examined for those regions of
the country where the results indicate the possibility of limited availability
of coal.
Factor (2) is important for the determination of the availability of
coal at the different cleanability levels. Comparisons of raw coal sulfur
contents between the reserve data and the wash samples are given in Tables 9
and 10.
The data contained in Table 9 indicate that the Northern Appalachian
washability samples related fairly well with coal reserve data. As indi-
cated, these are the coals with the greatest beneficiation attractiveness.
For the Southern Appalachian Region the washability data do not
correlate too well with the reserve base data, for a sulfur content less than
1 percent. This is due to the fact that the washability samples included in
the study were only from Kanawha and Logan counties in West Virginia. The
coals in this area are known to be of low sulfur content as mined.
The low sulfur comparison for the Western Region is given in Table 10.
The poor correlation is not critical for the results in the Western Region
since the availability of raw coal is adequate to meet the demand.
51
-------
TABLE 9
COMPARISON OF COAL RESERVE DATA
AND WASHABILITY DATA - APPALACHIAN
REGION
SULFUR CONTENT (WEIGHT PERCENT)
<3
N. Appalachian
Reserve Data 8.4 61.8
Washed Samples 8.5 56.5
S. Appalachian
(excluding Alabama)
Reserve Data 63.7 98.2
Washed Samples 80.0 98.5
52
-------
TABLE 10
WESTERN REGION RESERVES -
CUMULATIVE PERCENT OF TOTAL AND COMPARISONS WITH WASHABILITY DATA
MILLION SHORT TONS
CUMULATIVE TOTAL FOR SULFUR CONTENT ^1.0 PERCENT
STATE
Colorado
Montana
N. Dakota
N. Mexico
Utah
Woyming
TOTAL
CUMULATIVE TOTAL FOR
Colorado
Montana
N. Dakota
N. Mexico
Utah
Wyoming
TOTAL
CUMULATIVE PERCENT OF
DEEP
6,751
63,464
i
1,894
1,916
20,720
94,745
SULFUR CONTENT UP TO 3
7,438
65,860
2,109
3,320
26,531
105,258
TOTAL FOR < 1 PERCENT
STRIP
724
38,182
5,389
1,681
52
13,193
59,221
PERCENT
870
40,403
15,983
2,260
243
23,741
83,500
SULFUR CONTENT
TOTAL
7,475
101,646
5,389
3,575
1,968
33,913
153,966
8,308
106,263
15,983
4,369
3,563
50,272
188,758
- COMPARISON
RESERVE DATA 82
WASHED SAMPLES 50
53
-------
Factors (3) and (4) imply that the results for those regions of the
country that show little or no coal availability are bounded to reflect the
actual situation accurately. Those regions showing sufficient coal
availability would have to be further examined to determine the effect
of both these factors on the actual quantity of coal arriving at the
required destinations.
Factor (5) reflects the bituminous coal producing region accurately
(95-100 percent sulfur to SO- conversion). The subbituminous coal pro-
ducing regions (72 percent sulfur to S0? conversion) and the lignite coal
producing regions (60-90 percent sulfur to SO,, conversion) are affected as
follows: the results for the Western region, which contains a substantial
amount of subbituminous and lignite coals, are therefore bounded by Factor
(5) to reflect the actual situation accurately.
Factor (6) is important with respect to the results obtained with the
inclusion of the effects of sulfur variability. The assumptions stated are
probably reasonable, however, the actual RSD will vary for each type of coal
and it will not necessarily remain the same for continued deliveries of the
same coal. Deviations from the assumed value cannot be predicted on the basis
of regional considerations.
The manner in which these factors affect the calculations determining
the availability of coal from the different regions in the country is
summarized in Table 11. The No designation indicates that factors have no
significant effect and the Table 1 results can be used directly, without
further analysis, for that specific category. For example, the 0.172 kg/GJ
(0.4) standard cannot be met in any region. No further investigation is
required to firm up this result. However, the Further Investigation designa-
tion for the Western 0.34 kg/GJ (0.8) category (Factor 4) implies that although
it appears that coal is available, the problem of the coal getting from origin
to destination also should be studied.
Two additional points should be noted:
1) All the projected available coal reserves were assumed to be
available for use by the electric utility industry. At present,
the electric utilities consume approximately 70 percent of the total
coal production in the United States. If this ratio continued
54
-------
TABLE 11
THE SIGNIFICANCE OF THE CALCULATION FACTORS
ON THE DETERMINATION OF COAL AVAILABILITY *
SIGNIFICANCE
REGION
EASTERN
EASTERN -
MIDWEST
WESTERN -
MIDWEST
WESTERN
so2
1.2
0.8
0.4
1.2
0.8
0.4
1.2
0.8
0.4
1.2
0.8
0.4
COAL
RECOVERY
1
NO
FI
NO
FI
NO
NO
NO
\ NO
[
{ NO
j NO
NO
NO
F
WASH-
ABILITY
2
NO
FI
NO
FI
NO
NO
NO
NO
NO
NO
NO
NO
ACTORS
BTU
RECOVERY
(^ }
\ --
NO
FI
NO
FI
NO
NO
NO
NO
NO
NO
NO
NO
i
OTHER
ITEMS
4
NO
FI
NO
FI
NO
NO
NO
NO
NO
PI
FI
NO
r S -> SO.
^ !
5
NO
NO
NO
NO
i
NO
NO
j
NO
NO
NO
NO
NO
NO
* The significance of Factor 6, sulfur variability, cannot be established
regionally
FI - FURTHER INVESTIGATION DESIRABLE
NO - NO SIGNIFICANT EFFECT
/55
-------
into the 1985 period, then all the results of this study should
be reduced by 30 percent to reflect the use of coal in other sectors.
Of course, as stated previously, the years of coal availability
numbers are not intended to accurately reflect actual lifetimes of
reserves.
2) The input data of the regional coal demand projections included
heat content considerations. However, if one were tempted to
ignore regional demarcations and consider coal availability for the
entire United States as a whole unit, then variations in heat
content should be factored into the calculations. The lower Btu
content of the Western coals means that more coal is required to
satisfy the total Btu requirements. The results in this study
concerning "The Entire United States" do not take into account
the reduced heat content factor, and are therefore overly optimistic.
However, this again reinforces the need for FGD or a comparable
control technique as discussed previously.
Basic Calculations
The calculations were performed for the four (4) major coal producing
regions: Eastern, Eastern Midwest, Western Midwest, and Western. In addition,
a composite calculation was performed considering the Entire United States
as one whole region.
Three (3) levels of coal preparation were considered: raw coal, coal
crushed to 3.8 cm (1.5 in) top size with a Btu recovery greater than or equal
to 90 percent, and coal crushed to 0.117 (14 mesh) top size with a Btu recovery
greater than or equal to 50 percent.
In addition calculations were performed for cleaned coal combined with
FGD. The FGD was applied to 100 percent of the flue gas and had a 90 percent
removal efficiency.
Four (4) SO- emission standards were considered: 1.81, 0.52, 0.34, and
0.17 kg S02 per GJ (2.0, 1.2, 0.8, and 0.4 Ib S02 per million Btu).
56
-------
The following is the calculation procedure:
1. The coal reserve was obtained from Document 1C 8693.
2. The appropriate mining recovery factor was applied.
3. The percentage of this recoverable coal reserve, which can be
cleaned to each SC^ level, was read from one of the appropriate
graphs (Figures 19-25) which was obtained from Document RI 8118.
4. The appropriate percentage was applied to the recoverable coal
reserves. This yielded the total available coal tonnage for
compliance with a given emission standard.
5. The projected 1985 coal demand by region was obtained from the
FPC study, as tabulated in Table 4 of this report.
6. The total tonnage available was divided by the annual coal
demand. This yielded the number of years that coal is available.
To conclude consideration of the variability of the sulfur content in
coal, the following basic steps were employed in the calculation:
1) y + 3 o = e.s., where
y = mean value
a = standard deviation
3 a = 99.87% point
e.s. = emission standard.
For RSD = 10 percent, the following tabulation gives the means S02 emission
required to meet given emission standard.
e.s., Ib S02/106 Btu y, Ib SOjlO6 Btu
2.0 1-54
1.2 0.92
0.8 0.62
0.4 0.31
3) The curves obtained using average sulfur content (Figures 4,6,8,10,
and 12) were then used to obtain the new points. For example, for an emission
standard of 1.2, the 0.92 point was used to obtain the coal availability
information. The data obtained from these figures were then used to produce
the Bar Chart (Figure 3) and the curves in Figures 5,7,9,12, and 13.
57
-------
For example, for the Eastern Region, there are 220 years of coal
available (Table 12) if there were no S0~ emission regulations. The
^ r
imposition of a 0.17 kg SCL per GJ (0.4 Ib SO per 10 Btu) standard would
drop this availability to 0 years (Table 16, continued), even if PCC were
used. However, if FGD were used, this would make a minimum of 135 years of
coal available (Table 16, continued) and allow compliance with the 0.17 (0.4)
standard.
58
-------
TABLE 12. RAW COAL AVAILABILITY
(a)
1985 Utility
Recoverable Reserves Demand Maximum Years Available*
Region
106 Tons 106 Tons Years
Entire U.S. 259,798 788.3 330
Eastern 57,631 262.5 220
Eastern Midwest 50,687 162.8 312
Western Midwest 10,699 70.5 152
Western 140,781 274.5 512
* Based on 1985 Utility Demand Level
(a) Source: "Status of Coal Supply Contracts for New Electric Generating
Units, 1976-1985", Federal Power Commission, January 1977.
59
-------
TABLE 13
RECOVERABLE RESERVES TO MEET THE NSPS,
RAW AND PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING AND NEW)
THE ENTIRE UNITED STATES
Level of Coal
Preparation
STANDARD - LB S02/10 BTU
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
O ;
2.0
Recoverable Reserves
%
23
36
48
106 Tons
59,754
93,527
124,703
1985 DEMAND
1.
Recoverable
%
14
24
32
2
Reserves
106
36
62
83
FROM ALL UNITS
Tons
,372
,352
,135
(EXISTING
0.
Recoverable
%
2
4
7
AND NEW)
8
Reserves
106
5
10
18
Tons
,196
,392
,186
0.4
Recoverable
%
0
0
0
Reserves
106
0
0
0
Tons
788.3 x 106 TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
76 YRS
119 YRS
158 YRS
46 YRS
79 YRS
105 YRS
7 YRS
13 YRS
23 YRS
0 YRS
0 YRS
0 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 14
RECOVERABLE RESERVES TO MEET THE NSPS,
FLUE GAS DESULFURIZATION (FGD) COMBINED WITH PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
THE ENTIRE UNITED STATES
STANDARD - LB S02/106 BTU
Level Of Coal
Preparation
RAW COAL
1.5",790% Btu recovery*
14 Mesh,>50% Btu recovery*
1.
Recoverable
%
98
99
100
2
Reserves
106 Tons
254,602
257,200
259,798
1985 DEMAND
0.
Recoverable
%
83
98
99
8
Reserves
106 Tons
215,632
254,602
257,200
FROM ALL UNITS (EXISTING
0.4
Recoverable
%
43
66
87
PLUS NEW)
Reserves
106 Tons
111,713
171,467
226,024
788.3 x 106 TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
RAW COAL
1.5",^90% Btu recovery
14 Mesh, 5-50% Btu recovery
323 YRS
326 YRS
330 YRS
274 YRS
323 YRS
326 YRS
142 YRS
218 YRS
287 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
T\BLE 15
RECOVERABLE RESERVES TO MEET THE NSPS,
RAW AND PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
EASTERN REGION
Level Of Coal
Preparation
N. Appalachia
RAW COAL
1.5",- 90% Btu recovery*
14 Mesh,>50% Btu recovery*
STANDARD - LB SO0/10 BTU
S. Appalachia (Except Alabama)
RAW COAL
1.5", 90% Btu recovery*
14 Mesh,>50% Btu recovery* 100
Alabama
RAW COAL
1.5",>90% Btu recovery*
14" Mesh,>50% Btu recovery* 100
2.0
Recoverable Reserves
%
15
35
* 70
abama)
80
90
* 100
60
65
y* 100
106 Tons
5,472
12,768
25,536
16,095
18,107
20,119
620
671
1,032
1.
Recoverable
%
4
12
31
35
50
63
30
30
40
2
Reserves
106 Tons
1,459
4,378
11,309
7,042
10,060
12,675
310
310
413
0.8
Recoverable
% 10
1
2.5
2.5
3.5
3.5
3.5
8
8
8
Reserves
Tons
365
912
912
704
704
704
83
83
83
0.4
Recoverable
% 10
0
0
0
0
0
0
0
0
0
Reserves
Tons
0
0
0
0
0
0
0
0
-------
TABLE 15 (Continued)
RECOVERABLE RESERVES TO MEET THE NSPS,
RAW AND PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING AND NEW)
EASTERN REGION
STANDARD - LB S02/10 BTU
Level of Coal
Preparation
Entire Region
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
2.0
Recoverable Reserves
% 106 Tons
22,187
31,546
46,688
1.2 0.
Recoverable Reserves Recoverable
% 106 Tons %
8,811
14,748
24,397
8
Reserves
106 Tons
1,152
1,699
1,699
0.4
Recoverable Reserves
% 106 Tons
0
0
0
REGIONAL 1985 DEMAND FRON ALL UNITS (EXISTING AND NEW)
YEARS OF AVAILABLE SUPPLY
FROM RECOVERABLE RESERVES
**
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
85 YRS
120 YRS
179 YRS
34 YRS
56 YRS
93 YRS
4 YRS
7 YRS
7 YRS
0 YRS
0 YRS
0 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 16
RECOVERABLE RESERVES TO MEET THE NSPS,
FLUE GAS DESULFURIZATION (FGD) COMBINED WITH PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN REGION
STANDARD - LB S02/106 BTU
Level Of Coal
Preparation
N. Appalachia
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
S. Appalachia (Except Alabama)
RAW COAL
1.5",>90£ Btu recovery*
14 Mesh,>50% Btu recovery*
Alabama
RAW COAL
1.5">>90% Btu recovery*
14 Mesh,>50% Btu recovery*
1.
Recoverable
%
99
100
100
100
100
100
100
100
100
2
Reserves
106 Tons
36,115
36,480
36,480
20,119
20,119
20,119
1,032
1,032
1,032
0.
Recoverable
%
85
99
100
100
100
100
100
100
100
8
Reserves
106 Tons
31,008
36,115
36,480
20,119
20,119
20,119
1,032
1,032
1,032
0.4
Recoverable
1
43
77
91
94
100
100
78
82
100
Reserves
106 Tons
15,686
28,090
33,197
18,912
20,119
20,119
805
846
1,032
-------
TABLE 16 (Continued)
Ui
RECOVERABLE RESERVES TO MEET THE NSPS,
FLUE GAS DESULFURIZATION (FGD) COMBINED WITH PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN REGION
STANDARD - LB S02/1Q6 BTU
Level Of Coal
Preparation
1.2
0.8
0.4
Entire Region
Total
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
Recoverable Reserves
10 Tons
Recoverable Reserves
10 Tons
57,266
57,631
57,631
REGIONAL 1985 DEMAND
52,159
57,266
57,631
FROM ALL UNITS
(EXISTING AND NEW)
Recoverable Reserves
% 106 Tons
35,403
49,055
54,348
262.5 x 106 TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
219 YRS
220 YRS
220 YRS
199 YRS
218 YRS
220 YRS
135 YRS
187 YRS
207 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 17
RECOVERABLE RESERVES TO MEET THE NSPS,
RAW AND PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
EASTERN - MIDWEST REGION
STANDARD - LB S02/10 BTU
Level of Coal
Preparation
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
OS
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
2.0
1.2 0.8
Recoverable Reserves Recoverable Reserves Recoverable Reserves
% 106 Tons
2. 1,014
5.5 2,788
12. 6,082
REGIONAL 1985
6 YRS
17 YRS
37 YRS
% 106 Tons % 106 Tons
1. 507 0. 0
2. 1,014 1. 507
4. 2,028 2. 1,014
DEMAND FROM ALL UNITS (EXISTING AND NEW)
162.8 x 106 TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
3 YRS 0 YRS
6 YRS 3 YRS
12 YRS 6 YRS
0.4
Recoverable Reserves
% 106 Tons
0 0
0 0
0 0
0 YRS
0 YRS
0 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 18
RECOVERABLE RESERVES TO MEET THE NSPS,
FLUE GAS DESULFURIZATION (FGD) COMBINED WITH PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
EASTERN - MIDWEST REGION
STANDARD - LB S02/106 BTU
Level Of Coal
Preparation
1.2
0.8
0.4
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
Recoverable Reserves
10 Tons
Recoverable Reserves
10 Tons
Recoverable Reserves
10 Tons
98
100
100
49,
50,
50,
REGIONAL
673
687
687
1985
78
100
100
DEMAND
FROM ALL
39,
50,
50,
536
687
687
10
32
78
5
16
39
,069
,220
,536
UNITS (EXISTING AND NEW)
162.8 x IQt) TONS ANNUALLY
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
YEARS OF AVAILABLE SUPPLY**
FROM RECOVERABLE RESERVES
305 YRS
311 YRS
311 YRS
243 YRS
311 YRS
311 YRS
31 YRS
100 YRS
243 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
100
Product
a Row cool
b I'/2-inch
top size ,
90% Btu rec
T 14 -mesh
top size ,
50% Btu rec
Samples meeting
EPA stondord.%
14
24
32
I I J 1 I
0
10 12 14 16
LB S02/MM Btu
18
20
22
24
FIGURE 19
PERCENT OF ALL U.S. COAL SAMPLES MEETING THE CURRENT EPA STANDARD OF 1.2 POUNDS
S02/MM BTU WITH NO PREPARATION, CURVE a; COMPARED WITH THOSE CRUSHED TO 1-1/2-
INCH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL TO 90 PERCENT, CURVE b;
AND THOSE CRUSHED TO 14-MESH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL
TO 50 PERCENT, CURVE c, AND SEPARATED GRAVIMETRICALLY.
SOURCE: U.S. Bureau of Mines, RI8118
68
-------
c
o>
u
w
d>
Q.
CO
UJ
CO
LU
100
90
80
70
60
50
40
30
20
10
bo
Product
a
b
c
Row cool
I-L -inch
top size ,
90% Btu rec.
14 -mesh
top size ,
50% Btu rec.
Somples meeting
EPA stondord,%
30
30
40
EPA stondord 1.2
0
4 6 8 10
LB S02/MM Btu
12
FIGURE 20
PERCENT OF ALABAMA REGION COAL SAMPLES MEETING THE CURRENT EPA STANDARD OF 1.2
POUNDS SOo/MM BTU WITH NO PREPARATION, CURVE a; COMPARED WITH THOSE CRUSHED
TO l-l/2-INCH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL TO 90 PERCENT,
CURVE b; AND THOSE CRUSHED TO 14-MESH TOP SIZE AT A BTU RECOVERY OF GREATER THAN
OR EQUAL TO 50 PERCENT, CURVE c, AND SEPARATED GRAVIMETRICALLY.
SOURCE: U.S. Bureau of Mines, RI8118
69
-------
c
0)
CO
UJ
100
90
80
70
60
50
CO
y 40
30
20
10 —
0
Product
a Row coal
b \{ -'nch
top size ,
90% Btu rec.
c 14 -mesh
top size ,
50% Btu rec.
Samples meet
EPA standard
35
50
63
ing
-------
100
90
80
70
S 60
to
UJ
_
a.
UJ
z
50
40
30
20
10
Product
a Row coal
b lj -inch
top size ,
90% Btu rec.
c 14 -mesh
lop size ,
50% Btu rec.
Samples meeting
EPA standard, %
4
12
31
I I I I
\ I 1 I L
J L
10
12
14
16
16
20
LB SOj/MM Btu
FIGURE 22
PERCENT OF NORTHERN APPALACHIAN REGION COAL SAMPLES MEETING THE CURRENT EPA STANDARD
OF 1.2 POUNDS S02/MM BTU WITH NO PREPARATION, CURVE a; COMPARED WITH THOSE CRUSHED
TO 1-1/2-INCH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL TO 90 PERCENT,
CURVE b; AND THOSE CRUSHED TO 14-MESH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR
EQUAL TO 50 PERCENT, CURVE c, AND SEPARATED GRAVIMETRICALLY.
SOURCE: U.S. Bureau of Mines, RI8118
71
-------
c
o>
o
CO
UJ
<
C/J
100
90
80
70
60
50
40
30
20
10-
Somples meeting
EPA stondord.%
l^-inch
top size ,
90% Btu rec.
c 14 - mesh
top size,
50% Btu rec.
I I I I I I I
8 10 12
LB S02/MM Btu
14
16
18
20
FIGURE 23
PERCENT OF EASTERN MIDWEST REGION COAL SAMPLES MEETING THE CURRENT EPA STAND-
ARD OF 1.2 POUNDS S02/MM BTU WITH NO PREPARATION, CURVE a; COMPARED WITH
THOSE CRUSHED TO 1-1/2-INCH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL
TO 90 PERCENT, CURVE b; AND THOSE CRUSHED TO 14-MESH TOP SIZE AT A BTU RECOVERY OF
GREATER THAN OR EQUAL TO 50 PERCENT, CURVE c, AND SEPARATED GRAVIMETRICALLY.
SOURCE: U.S. Bureau of Mines, RI8118
72
-------
TABLE 19
RECOVERABLE RESERVES TO MEET THE NSPS,
RAW AND PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
WESTERN - MIDWEST REGION
STANDARD - LB SO-/10 BTU
Level of Coal
Preparation
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,x50% Btu recovery*
u>
2.0
1.2
Recoverable Reserves Recoverable Reserves
% 106
5
8
8
REGIONAL
Tons
535
856
856
1985
%
2.5
5.5
5.5
DEMAND FROM
106 Tons
267
588
588
ALL UNITS (EXISTING
0.
Recoverable
%
0
0
0
AND NEW)
8
Reserves
106 Tons
0
0
0
0.4
Recoverable Reserves
% 106 Tons
0 0
0 0
0 0
I
70.5 x 10b TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
8 YRS
12 YRS
12 YRS
4 YRS
8 YRS
8 YRS
0 YRS
0 YRS
0 YRS
0 YRS
0 YRS
0 YRS
* ^Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 20
RECOVERABLE RESERVES TO MEET THE NSPS,
FLUE GAS DESULFURIZATION (FGD) COMBINED WITH PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
WESTERN - MIDWEST REGION
STANDARD - LB S02/106 BTU
Level Of Coal
Preparation
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,>50% Btu recovery*
1.
Recoverable
%
82
93
100
2
Reserves
106 Tons
8,774
9,951
10,700
REGIONAL 1985 DEMAND
0.8
Recoverable Reserves
%
40
82
94
FROM ALL
106 Tons
4,280
8,774
10,058
UNITS (EXISTING
0.4
Recoverable
%
10
16
43
AND NEW)
Reserves
106 Tons
1,070
1,712
4,601
70.5 x 106 TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
RAW COAL
1.5",>-90% Btu recovery
14 Mesh,>50% Btu recovery
124 YRS
140 YRS
152 YRS
61 YRS
124 YRS
142 YRS
15 YRS
24 YRS
65 YRS
* Tonnages do not reflect-weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 21
RECOVERABLE RESERVES TO MEET THE NSPS,
RAW AND PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING AND NEW)
WESTERN REGION
STANDARD - LB S02/10 BTU
Level of Coal
Preparation
RAW COAL
1.5",>90% Btu recovery*
14 Mesh ,> 50% Btu recovery*
Ui
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
2.0
1.2 0.8
Recoverable Reserves Recoverable Reserves Recoverable Reserves
%
90
100
100
106 Tons
126,703
140,781
140,781
REGIONAL 1985
461 YRS
512 YRS
512 YRS
% 106 Tons % 106 Tons
70 98,547 25 35,195
94 132,334 37 52,089
98 137,965 57 80,245
DEMAND FROM ALL UNITS (EXISTING AND NEW)
274.5 x 106 TONS ANNUALLY
YEARS OF AVAILABLE SUPPLY **
FROM RECOVERABLE RESERVES
359 YRS 128 YRS
482 YRS 189 YRS
506 YRS 292 YRS
0.4
Recoverable Reserves
% 10 6 Tons
1 1,408
1 1,408
2 2,816
5 YRS
5 YRS
10 YRS
* Tonnages do not reflect weight or Btu.loss during cleaning.
** Based on 1985 demand level.
-------
TABLE 22
RECOVERABLE RESERVES TO MEET THE NSPS,
FLUE GAS DESULFURIZATION (FGD) COMBINED WITH PREPARED COAL TO MEET THE
1985 ANNUAL DEMAND FROM ELECTRIC UTILITIES (EXISTING PLUS NEW)
FGD-90% REMOVAL EFFICIENCY, 100% OF GAS CLEANED
WESTERN REGION
STANDARD - LB S02/1Q6 BTU
Level Of Coal
Preparation
RAW COAL
1.5",>90% Btu recovery*
14 Mesh,^50% Btu recovery*
1.
Recoverable
%
100
100
100
2
Reserves
106 Tons
140,781
140,781
140,781
REGIONAL 1985
0.8
0.
4
Recoverable Reserves Recoverable Reserves
% 106 Tons
100 140,781
100 140,781
100 140,781
DEMAND FROM ALL UNITS
7
fa
100
100
100
(EXISTING AND
106 Tons
140,781
140,781
140,781
NEW)
274.5 x 10b TONS ANNUALLY
RAW COAL
1.5",>90% Btu recovery
14 Mesh,>50% Btu recovery
512 YRS
512 YRS
512 YRS
YEARS OF AVAILABLE SUPPLY
FROM RECOVERABLE RESERVES
512 YRS
512 YRS
512 YRS
512 YRS
512 YRS
512 YRS
* Tonnages do not reflect weight or Btu loss during cleaning.
** Based on 1985 demand level.
-------
100 —
EPA stondord
: C I b
Samples meeting
EPA standard,
a Row cool
b l'/2 -inch
top size ,
90% Btu rec.
c 14-mesh
top size ,
50% Btu rec.
10 12 14 16 18 20 22
LB S02/MM Btu
24
FIGURE 24
PERCENT OF WESTERN MIDWEST REGION COAL SAMPLES MEETING THE CURRENT EPA STAND-
ARD OF 1.2 POUNDS S02/MM BTU WITH NO PREPARATION, CURVE a; COMPARED WITH
THOSE CRUSHED to 1-1/2-INCH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL
TO 90 PERCENT, CURVE b; AND THOSE CRUSHED TO 14-MESH TOP SIZE AT A BTU RECOVERY
OF GREATER THAN OR EQUAL TO 50 PERCENT, CURVE c, AND SEPARATED GRAVMETRICALLY.
SOURCE: U.S. Bureau of Mines, RI8118
77
-------
100
Product
o Row cool
b l-i -inch
1op size ,
90%Btu rec.
c 14 -mesh
top size ,
50% Btu rec.
Somples meeting
EPA standard , %
70
94
98
10 -
EPA standard 1.2
I I I
I I I
0 2 4 6 8 10 12
LB S02/MM Btu
FIGURE 25
PERCENT OF WESTERN REGION COAL SAMPLES MEETING THE CURRENT EPA STANDARD OF 1..2
POUNDS S02/MM BTU WITH NO PREPARATION, CURVE a; COMPARED WITH THOSE CRUSHED TO
1-1/2-INCH TOP SIZE AT A BTU RECOVERY OF GREATER THAN OR EQUAL TO 90 PERCENT,
CURVE b; AND THOSE CRUSHED TO 14-MESH TOP SIZE AT A BTU RECOVERY OF GREATER TflAN
OR EQUAL TO 50 PERCENT, CURVE c, AND SEPARATED GRAVIMETRICALLY.
SOURCE: U.S. Bureau of Mines, RI8118
78
-------
TECHNOLOGY, COST, AND ENVIRONMENT OVERVIEWS OF COAL CLEANING
Coal cleaning accomplishes the removal of slate, clay, carbon-
aceous shales, pyrite and rock aggregate. There are many processes for
cleaning coal, each having its own benefits and disadvantages. These
processes can be divided into two general categories, physical and
chemical coal cleaning.
Physical Coal Cleaning
Physical cleaning can be defined generally as the separation of
waste or unwanted "refuse" material from coal by techniques based on the
differences in the physical properties of coal and refuse. The most common
physical property used to clean coal is density. Specific gravity ranges
are generally as follows:
coal 1.2-1.7
carbonaceous shale 2.0-2.6
gypsum, kaolin, calcite 2.3-2.7
pyrite 5.0
Density separation is done using hydraulic jigs, concentrating tables, cyclones,
dense medium vessels, or air classifiers. In such equipment ground coal
is suspended in a fluid, and the refuse material falls to the bottom of
the separating unit, whereas the cleaned coal will float or move to the
top of the unit for removal. A related technique, froth flotation,
additionally utilizes the surface properties of coal particles to advantage
to enhance the separation. Physical cleaning will remove mineral sulfur,
e.g., pyrite, which has a high density, but not organic sulfur, which is
an integral part of the coal. The amount of mineral sulfur removed depends
on the crystal size of the mineral sulfur. The smaller the crystals are,
the smaller particle size the run of the mine (ROM) coal must be crushed
to achieve effective separation. If the particle sizes of the mineral sulfur
79
-------
and pulverized coal are not matched well, large amounts of coal will be lost
with the refuse if a large fraction of the mineral sulfur is to be removed.
As the coal is pulverized to smaller and smaller particle sizes, costs of
pulverization rise quickly. These costs vary widely depending on the type
of coal.
The Btu recovery rate of the cleaning process is usually based
on the input heating value. The heating value of the coal lost in the
refuse is counted as an energy loss. Physical cleaning generally has a
Btu recovery of 80 to 95 percent of the ROM coal, with the largest losses
associated with coal lost with the refuse, and, with the coal required to
operate the thermal drier. One can expect physical cleaning to remove 35
to 70 percent of the mineral sulfur in ROM coals, depending on the amount
of size reduction done and the many other physical characteristics of the
coal.
Hoffman^) nas studied the costs of physically cleaning easily-
cleaned northern Appalachian coals, presenting cost data for coals cleaned
at a top size of 0.95 cm (3/8 inch), and high yield factors (a range of 85
to 95 percent of input product yield, weight basis). Other Appalachian coals
(2)
generally have a 60 to 70 percent weight yield and the associated costs
would be higher on a cleaned-coal basis. Capital investment for a physical
cleaning plant larger than 454 kkg (500 tons) per hour capacity at the mine
mouth (a lower practical economic limit) can run between $9920 and $49,600
per kkg ($9,000 and $45,000 per short ton) per hour of capacity(2). (The
higher value, $49,600, includes rail spurs, and coal handling equipment
normally associated with mine facilities costs.) The mean cost range is
$16,500 to $19,800 per kkg ($15,000 to $18,000 per short ton) per hour
capacity. These mean costs are incremental to mine facility costs, e.g.,
rail spurs, conveyors, etc. If one assumes the following:
1) 15 year capital write off,
2) 13 productive hours per day, 260 days per year operation,
3) interest rate of 10 percent,
4) 90 percent product yield, and ,
5) $19,800 per ton per hour of capacity capital cost,
one can expect a capital charge of $0.845 per kkg ($0.767 per ton) of ROM
coal processed for a 454 kkg (500 short tons) per hour plant, and an operating
80
-------
and maintenance cost of $0.72 to $0.94 per kkg ($0.65 to $0.80 per short ton) I
of ROM coal processed, depending on the site and coal specifics of the
cleaning plant. The operating and maintenance cost includes an allowance
for disposal costs of the refuse. Because of the loss of rejects material
in cleaning, and because the heating value is an important factor in selling
the cleaned coal, costs are usually reported in dollars per million Btu.
If the coal is assumed to go from a ROM heating value of 25.58 MJ per kg
(11,000 Btu per pound) to a product heating value of 27.91 MJ per kg
(12,000 Btu per pound), with a ROM coal price of $19.80 per kkg ($18 per
ton), and a 90 percent weight yield, the cost of cleaning would be calculated
as follows:
Raw Coa! Cost - - *>.774/GJ
Cldaned Coal Cost = $19.80 ROM coal cost
. 84 capital charge
.94 O&M cost
$21.58 per kkg ROM coal
$21'58 . - = $23.98/kkg cleaned coal
0.9 yield y 5
$23.98/kkg
__
(27.91 MJ/kg)(1000 kg/kkg)
Cleaning cost = $0.859 - $0.774 = $0.085/GJ or $0.09/106 Btu
$19'57 . , , = $21.74/ ton cleaned coal
0.9 yield
Cleaning cost = $0.906 - $0.818 = $0.087/106 Btu
81
-------
This cost is for a plant using hydraulic jigs, washing tables, cyclones,
froth flotation units, filters, screens, and mechanical and thermal driers.
Using the cleaned coal as a basis, the cleaning cost is then $2.37 per kkg
(2.09 per ton). If the cleaning yield is assumed to be much lower, e.g. 60
weight percent, the ROM heating value of the coal say 18.61 MJ per kg
(8000 Btu per pound), and a ROM coal price of $11 per kkg ($10 per ton),
the capital charges and operating and maintenance costs used above lead
to a cleaned coal processing cost of $4.80 per product kkg ($4.27 per product
short ton), and $0.172 per GJ ($0.178 per million Btu's). These figures do
not include any profit for the operation.
It should be noted that other benefits accrue to the utility using
cleaned coal in addition to sulfur reduction, such as: increased heating
value and reduced ash content of the product, reduced transporation costs,
reduced pulverizing costs, increased boiler capacity and availability, and
savings in boiler maintenance costs. The value of these benefits should be
considered when the cost-benefit of coal cleaning is evaluated for a specific
utility application.
There are several other techniques that can be used in physical
cleaning, e.g., magnetic separation of iron pyrite (FeS2), oil agglomeration, and
electrophoretic and electrostatic separation. Either for economic or
processing reasons, these have not been developed sufficiently for detailed
discussion in this report.
Physical coal cleaning reduces sulfur and ash content. Both
enhance the environmental acceptability of burning the cleaned coal. However,
physical cleaning has its own set of environmental problems. The refuse
is usually gob piled. These piles can be a source of highly acid mine drain-
age, requiring a collection and lime treatment system for the drainage.
Gob piles also can be sources of fugitive dust. All of the physical cleaning
processes have various internal environmental problems. Table 23 gives
generalized environmental problems for the various process technologies.
Chemical Cleaning
There are currently 25 chemical cleaning processes under active
development and many more under conceptual development. Of these 25, only
eight have any economic information published or available.
82
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TABLE 23. PHYSICAL COAL CLEANING PROCESS ENVIRONMENTAL PROBLEMS
TECHNOLOGY
PROBLEM
CONTROL METHOD
oo
Jig, Launder,
Cyclone, Table
Dense medium vessel
and cyclone
Air classifier
Froth flotation
Electrostatic
Electrophoretic
Magnetic
Oil agglomeration
Contaminated process water
Contaminated process water, dense
media loss
Fugitive coal dust
Contaminated process water,
flotation reagents loss
Fugitive coal dust
Contaminated process water
Contaminated process water
Contaminated process water, fuel
oils, tar oil in contact with
water
Closed water cycle
Closed water cycle
Cyclone collector, bag house
electrostatic precipitator
(ESP)
Closed water cycle
Cyclone collector, bag house,
ESP
Closed water circuit
Closed water circuit
Closed water and oil circuit
-------
Meyers/TRW Process. The Meyers process is the most highly developed
chemical cleaning process. It has been studied by Dow Chemical, Bechtel,
and Dynatech. ' ' ' The process leaches -149 ym (-100 mesh) coal contain-
ing iron pyrite (FeS^) with ferric sulfate (Fe (SO )„), converting the pyrite
to sulfuric acid, ferrous sulfate, and elemental sulfur, at moderate
temperatures and pressures,70 C to 120 C (160 F to 250 F), and 100 kN/m2 to
2
550 kN/m , (15 to 80 psia), with long leaching times (5 to 10 hours). The
process has no proven organic sulfur removal and TRW does not claim any.
Elemental sulfur produced is solvent extracted or vaporized and recovered
by condensation. Figure 26 indicates the layout unit processes involved in
the Meyers process.
Dow Chemical(3) has done an extensive design and economics study
of this process for a 420 kkg (380 short tons) per hour plant. Their
total capital cost for this design was $145 million (mid-1975 dollars) plus
or minus about 20 percent. This includes limited physical cleaning facilities
for removal of rock aggregate and shales. Dow feels that based on this
design and 95 percent removal of pyritic sulfur, a cleaning cost of $11 to
$15.50 per kkg ($10 to $14 per ton) of cleaned coal would be appropriate
(4)
currently. Bechtel Corporation has studied the economics of a 300 kkg
(330 short ton) per hour plant suggesting a total capital cost of $131 million
and a cleaning cost of $0.78 per GJ ($0.82 per million Btu's), or $20.90
per cleaned kkg ($19 per cleaned short ton). Both companies' costs contain
no profit margins, and Dow's cost is based on cleaning a Pennsylvania Lower
Kittanning coal. Bechtel's design is based on using a Pittsburgh A bituminous
coal. Dow indicates that, based on their design, the process can achieve
a 90 percent Btu recovery, while Bechtel indicates 98 percent Btu recovery.
The Meyers process may be one of the more troublesome chemical
cleaning processes from an environmental standpoint. It uses organic solvents
in contact with process wastes to extract the elemental sulfur. A portion
of the solvent will be left in the cleaned coal. The waste products of
the process, ferrous sulfate, sulfuric acid, and physical cleaning refuse,
have to be disposed of properly with pH adjustment. This refuse is obviously
much more acidic than just physical cleaning refuse alone. Internally, the
process must use a closed water circuit with solvent recovery to avoid
further effluent problems.
84
-------
O2 FROM
OXYGEN PLANT
PULVERIZED COAL
MAKEUP
H2S04
REACTOR
RESIDENCE
TIME-10HRS
SULFUR
EXTRACTION
TANK
SLURRY
MIXING
TANK
RETURN LEACHANT
00
Ln
H2O
TO PROCESS
RECOVERED
SOLVENT
RECYCLE
COAL
SLURRY
IRON
SULFATE
REMOVAL
WATER
WASH
TANK
H2O
COAL DRYING
WITH SOLVENT
RECOVERY
SOLVENT
RECOVERY &
SULFUR
REMOVAL
FILTER
CLEAN
IRON
'SULFATE
COAL
ELEMENTAL
SULFUR
FIGURE 26. MEYERS/TRW PROCESS FLOW DIAGRAM
-------
The Meyers process probably could be commercial in 5 to 6 years. An
8 ton per day pilot plant has been constructed. Information from this
should help provide scale-up information.
Battelle Hydrothermal. The Battelle process leaches -149 urn + 74 urn
(-100 + 200 mesh) coal with sodium and calcium hydroxide solutions at elevated
2
temperatures and pressures, 98 C to 170 C (200 F to 340 F) and 1.55 MN/m to
2
17.25 MN/m (225 psia to 2500 psia). The process removes up to
99 percent of the mineral sulfur and has demonstrated 24 percent to 72 percent
organic sulfur removal, depending on the specific coal processed. Btu recovery
ranges from 75 to 90 percent, depending on process operation. Figure 27
indicates the process layout and unit operations. The capital cost of the
process suffers due to the elevated temperatures and pressures used in the
system, and the need for leachant regeneration equipment to close the process
water loop, preventing the loss of leachant.
Battelle currently feels that an operating cost of $19.80 to $27.50
per kkg ($18 to $25 per short ton) of cleaned coal or about $.95 per GJ
fQ\
($1.00 per million Btu) is a good estimate based on the regeneration of
leachant, 0.25 hour leaching time, and processing a Lower Kittanning coal
from 2.4 to 0.9 percent sulfur. Under these conditions a capital cost of
$134 million to $145 million has been estimated for a 360 kkg (400 short tons)
per hour plant, the cost depending on the coal to leachant ratio (2 to 1,
or 3 to 1). No profit margin is included in these figures.
With leachant regeneration, internal process water loops are closed,
so that the only water effluent is in the wet coal. Hydrogen sulfide
(H S) is produced in the process, and protection against H S leakage would
be necessary both from a processing and safety point of view. The process
is known to leach out many heavy metals in coal. Any effluents containing
high concentrations of these metals may require special disposal.
The Battelle hydrothermal process could be commercialized in 4 to 6
years.
(4)
Hazen Process. The Hazen process , shown in Figure 28 is a totally
dry process. The process reacts iron pyrite with gaseous iron pentacarbonyl:
3 FeS2 + Fe(CO)5 -*• 2 Fe^ + 5 C
86
-------
PULVERIZED
WASH H2O
FLUE GAS
oo
t COAL DRYER I COAL
COALTOCALCINER
ELEMENTAL
SULFUR
RECOVERY
ELEMENTAL
SULFUR
LIME MAKEUP
HEAT
EXCHANGER
I FEED PREHEATER
B x~\
Na2S
•f
CAUSTIC
REACTOR
RESIDENCE
TIME - 1/4 HR
SLURRY
MIXING
TANK
H2S
STRIPPER
AIR
WASH COOLER
MIXING
TANK
CALCINER
CLEAN COAL
MAKEUP H2O
NaOH & Ca (OH)2
CLEAN
LIME
MIXING
TANK
AND CAUSTIC
FIGURE 27. BATTELLE HYDROTHERMAL PROCESS FLOW DIAGRAM
-------
PULVERIZED
COAL
CYCLONE\y
M
00
00
A
40 PS!A
333° F
v \t v v v
HE ACTOR
RES;DEN&E
TIME - 1/2 HR
FLUE GAS TO COAL PREPARATION
MAGNETIC
SEPARATOR
CO BURNER
FIGURE 28. HAZEN PROCESS FLOW DIAGRAM
-------
The Fe2S3 is much more magnetically susceptible enabling it to be magnetically
separated from the coal. Thus this process can remove only mineral sulfur,
and requires very fine grinding of the coal in order to liberate the pyrite
particles. This may restrict application of the Hazen process. The process
is simpler than others, using fewer unit operations and process steps, at
mild temperatures and pressures. The process does have severe process
monitoring requirements due to the use of highly toxic iron pentacarbonyl.
Results reported to date have been limited to coal ground to 1.19 mm
(14 mesh) because there are no magnetic separators available to handle dry,
fine-pulverized materials. This will hinder development of the process.
(4)
Bechtel has estimated costs for a 300 kkg (330 short ton) per hour
plant for a Pittsburgh bituminous coal as a capital cost of $48 million,
and operating and maintenance costs of about $15.40 per kkg ($14 per short
ton) cleaned. They indicate a cleaning cost of $.57 per GJ ($.60 per million
Btu), with a Btu recovery of 76 percent. There are few aspects of Bechtel's
design that are specified. One specified is the Fe(CO) cost. Hazen
estimates its cost at $.10 per pound with a consumption of 32 pounds per ton
of coal (whether ROM or cleaned is not specified). Private vendor prices for
Fe(CO)5 go as high as $3.30 per kkg ($1.50 per pound). This higher price would
change the cleaning costs dramatically.
Along with monitoring Fe(CU) levels in the plant area, the disposal of the
refuse will be of environmental concern. Problems involved will be very much
the same as those for refuse from physical cleaning, except that Hazen refuse,
because of its small particle size, will create severe dusting problems.
Hazen is considering a 0.9 kkg (1 ton) per day plant, so commercialization
might be in 6 to 8 years.
(4 5)
KVB. The KVB process ' , shown in Figure 29, oxidizes sulfur
components of dry pulverized -1.19 mm + 0.595 mm (-14 + 28 mesh) coal with
followed by caustic leaching to solubilize and remove the sulfur compounds
formed in the oxidation step. The soluble sulfur compounds are mixed with
lime to regenerate caustic and precipitate gypsum (CaSO^), and iron oxides,
which would be landfilled. The advantages of the KVB process are its claim
to removal of both mineral and organic sulfur (up to 63 percent sulfur
removal with oxidation, 87 percent with additional caustic leaching), the
simplicity and low costs of dry oxidation, and the moderate temperatures,
89
-------
PULVERIZED
COAL
CYCLONE
VO
o
N2
MAKEUP GAS
\^
C-J
COMPRESSOR
102,N2,NO)
BLEED
(C02. H20, NOX)
SCRUBBING
1 HR AXMAKEUP GAS
xJCx PREHEATER
STM
EXTRACTOR
RECYCLE
CAUSTIC
FLUE GAS
1
COAL f
DRYER
GYPSUM
AIR
CLEAN
£3£jj383£CS^BI
COAL
COAL
COAL PREP.
N2 HEATER
FIGURE 29. KVB PROCESS FLOW DIAGRAM
-------
pressures, and vessel residence times. A problem in the system is the uptake
of nitrogen by the coal.
Bechtel has developed cost information on the KVB process, based on
the KVB patent and limited nonproprietary information (no literature is
available and little bench scale work has been done). Bechtel indicates a
capital cost of $68 million for a 300 kkg (330 short tons) per hour plant
with an operating and maintenance cost of $25 per kkg of cleaned coal ($23
per cleaned short ton). They indicate a cost of $.93 per GJ ($.98 per
million Btu), for a Pittsburgh bituminous coal, with 90 percent Btu recovery.
Environmentally, the KVB process has one major problem; it is a NO
X
producer. No information is available on expected effluent levels of NO .
The other waste product is gypsum for which established disposal tech-
nologies are available.
(4 5)
Ledgemont Oxygen Leaching. This process ' (LOL) (see Figure 30) is
based on the following reaction.
FeS. + HO + 3.500 -»• FeSO. + H0SO.
22 2 424
High temperatures and pressures must be used to speed the reaction rate for
a commercially viable process. Strong oxidizing conditions in the
reactor cause some coal loss and volatization in the reactor. This results
in loss of heating value. The process has no significant organic sulfur
removal capability. Sulfur is removed from the system by mixing the reaction
products with lime, producing gypsum and iron oxides which would be land-
filled. Kennecott Copper Company claims 95 percent pyritic sulfur removal
in the LOL process, with 93 percent Btu recovery.
(4 5)
Dynatech and Bechtel ' have studied the economics of the LOL process.
Dynatech's study gives an operating cost of $7.60 per kkg ($6.90 per short
ton) cleaned, but no capital costs. Bechtel's study gives a capital cost
of $155 million for a 300 kkg (330 short tons) per hour plant with an operat-
ing cost of $20.90 per kkg ($19 per cleaned short ton) or $0.77 per GJ
($0.81 per million Btu). Dynatech does not indicate what coals were used as
a design base, or what type of preparation facilities were included in the
cost case. Bechtel indicates a Pittsburgh A bituminous coal pulverized to
80 percent minus 74 ym (200 mesh).
91
-------
PULVERIZED COAL
RETURN TO O2 PLANT •*-
MAKEUP
H20
O2
OXYGEN
PLANT
VO
IS3
I
1
SLURRY
MIXING
TANK
HEAT OFFGAS
A
REACTOR
RESIDENCE TIME - 2 MRS
[315PSIA 266°F
FLASH GAS
QUENCH TOWER
i
FLUE GAS
i
FILTER
LIME
MIXING
TANK
RECYCLE H2O
THICKENER
FLASH
TANK
CLEAN
COAL
GYPSUM
FILTER
FIGURE 30. LOL PROCESS FLOW DIAGRAM
-------
BOM/ERDA. This process (see Figure 31) uses wet oxidation, employing
air instead of oxygen as used by LOL. The BOM/ERDA process operates at
higher temperatures and pressures than LOL, generating iron sulfates and
sulfuric acid. Because of the extreme operating conditions, both pyritic
and organic sulfur removal are claimed, and the process can be expected to
show coal loss similar to the LOL process. Lime is used to convert iron
sulfates to iron oxides and gypsum.
(4)
Bechtel has studied the economics of this process using a Pittsburgh
bituminous coal. With pulverization facilities, grinding to 80 percent
minus 74 ym (200 mesh), Bechtel estimates a capital cost of $130 million
and an operating and maintenance cost of $20.90 per kkg of cleaned coal ($19
per cleaned short ton), or $.80 per GJ ($.84 per million Btu) with a Btu
recovery of 94 percent. These costs are for a 300 kkg (330 short tons)
per hour plant.
Environmentally, the BOM/ERDA process will be very similar to the LOL
process. The process is under bench scale development, so commercialization
would be about 6 to 9 years off.
Dynatech. This process uses microbial action at 38 C (100 F) and
1 atmosphere pressure. There is little information, but Dynatech does
indicate using minus 74 urn (200 mesh) washed coal, complete pyritic and
some organic (amount unknown) removal, and gypsum, sulfuric acid, and elemental
sulfur products. Dynatech has released limited cost data for a 300 kkg
(330 ton) per hour plant with coal preparation facilities, indicating a cost
of $4.15 per kkg ($4.05 per ton) of cleaned coal. Other details are not
available.
General Electric. GE is developing a process that radiates coal with
microwaves, gasifying the sulfur. Information is limited, but GE claims 52
percent reduction in pyritic and organic sulfur, and the possibility of
reducing sulfur in most coals to 0.7 percent. Products of the process are
H S, COS, SO , H20, C02, and traces of CH^ C^, and HZ. GE's preliminary
cost data for a 440 kkg (400 ton) per hour plant claims a cost of $7.30
per kkg of cleaned coal ($6.60 per cleaned ton).
93
-------
PULVERIZED COAL
FLASH
TANK
REACTORS
RESIDENCE TIME - 1 HR
FIGURE 31. BOM/ERDA PROCESS FLOW DIAGRAM
-------
Summary of Coal Cleaning Costs. A summary of the costs of various coal
cleaning processes is given in Table 24, together with the ranges of sulfur
removal and Btu recovery claimed for each process.
95
-------
TABLE 24. MAJOR COAL CLEANING PROCESS CONSIDERATIONS
COSTS
PROCESS PLANT
short
(a\
Physical v '
TRW/Meyers
Battelle Hydro-
thermal
ON Hazen
KVB
LOL
BOM/ERDA
Dynatech
GE
SIZE BASIS
ton per hour
500
380
400
330
330
330
330
330
400
CAPITAL
9.0
145
134.. -145.
48.
68.
150.
130.
-
-
PROCESS ING (b)
$/ton $/106
4.27
10.- 14.
18. -25. 1.
14.
23.
19.
19.
4.05
6.60
Btu
18
82
00
60
98
81
84
-
-
SULFUR REMOVAL
PYRITIC ORGANIC
35-70
95
99 24-72
80
99 13
95
99 15
-
50 (Combined)
BTU RECOVERY
80-95
90
75-90
76
90
93
94
-
-
(a) See text for basis of costs and other data.
(b) Includes capital charge plus operating and maintenance costs, basis for costs are cleaned coal.
-------
REFERENCES
1. L. Hoffman, et al. (The Hoffman-Muntner Corporation)/'Engineering/
Economic Analysis of Coal Preparation With S0£ Cleanup Processes for
Keeping Higher Sulfur Coals in the Energy Market", U.S. Bureau of
Mines, Contract Number J0155171.
2. Personal communication with Lawrence Hoffman, the Hoffman-Muntner
Corporation, Silver Springs, Maryland.
3. W. F. Nekervis, E. F. Hensley (Dow Chemical U.S.A.), "Conceptual Design
of a Commercial Scale Plant for Chemical Desulfurization of Coal,"
Environmental Protection Technology Series, EPA-600/2-75-051.
4. R. R. Oder et al. (Bechtel Corporation), "Technical and Cost Comparisons
for Chemical Coal Cleaning Processes"> American Mining Congress Coal
Convention, Pittsburgh, Pennsylvania, May 1977.
5. Personal communication with Irwin Frankel, Versar Incorporated, Springfield,
Virginia.
6. Personal communication with W. F. Nekervis, Dow Chemical U.S.A., Midland,
Michigan.
7. S. Min, D. A. Tolle, et al. (Battelle Memorial Institute), "Technology
Overview of Coal Cleaning Processes and Environmental Controls", Draft
Report, U.S. Environmental Protection Agency, Contract number 68-02-2163,
January 1977.
8. Internal Battelle sources.
97
-------
LIST OF DATA SOURCES
"The Reserve Base of U.S. Coals by Sulfur Content", 1C 8680, and 1C 8693,
U.S. Breau of Mines, 1975.
"Sulfur Reduction Potential of U.S. Coals", RI 8118, U.S. Bureau of Mines,
April 1976.
"Status of Coal Supply Contracts for New Electric Generating Units, 1976-
1985", Federal Power Commission Staff Report, January 1977.
"Electric Power Supply and Demand, 1977-1986", Federal Power Commission, May
1977.
"Factors Affecting the Electric Power Supply, 1980-1985", Federal Power
Commission, December 1976.
"Annual Summary of Cost and Quality of Electric Utility Plant Fuels, 1976",
Federal Power Commission, May 1977.
98
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-034
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Physical Coal Cleaning for Utility Boiler SO2 Emission
Control
5. REPORT DATE
February 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
E. H. Hall, L.Hoffman* J. Hoffman* and R. A.Schilling
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Battelle Memorial Institute—Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2163, Task 851
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND.PERIOD COVERED
Task Final: 7-12/77
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES jERL-RTP project officer is James D. Kilgroe, Mail Drop 61,
919/541-2851. (*) Two authors are from the Hoffman-Munter Corp. , Silver Spring,
Maryland.
16. ABSTRACT
The report examines physical coal cleaning as a control technique for sul-
fur oxides emissions. It includes an analysis of the availability of low-sulfur coal and
of coal cleanable to compliance levels for alternate New Source Performance Stan-
dards (NSPS). Various alternatives to physical coal cleaning (such as chemical coal
cleaning, coal conversion, and fluidized-bed combustion) are also examined with
respect to alternate NSPS. Electric power supply and demand through 1985 are
reviewed, as well as the technology, cost, and environmental overviews of physical
and chemical coal cleaning techniques. Since the report deals with engineering
analyses of available data and several technologies in design stages, references are
somewhat limited. Descriptions of the methodologies used and the sources of infor-
mation are given in lieu of referenced published data in many cases.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
fa.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Coal
Cleaning
Utilities
Boilers
Sulfur Oxides
Fluidized-bed Pro-
cessing
Coal Gasification
Electric Power
Demand
Electric Power
Generation
Air Pollution Control
Stationary Sources
Low-sulfur Coal
Coal Conversion
13B
08G,21D 07A
13H
13A
07B
20C
10A
3. DISTRIBUTION! STATEMENT
19. SECURITY CLASS (TIlis Report!
Unclassified
21. NO. OF
111
Unlimited
20. SECURITY CLASS (TIlis page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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