STUDY OF COST OF SULPHUR OXIDE AND
PARTICULATE CONTROL USING SOLVENT REFINED COAL
Robert G. Shaver
General Technologies Corporation
A Subsidiary of Cities Service Company
1821 Michael Faraday Drive
Reston, Virginia 22070
April 1970
Department of Health, Education, and Welfare
National Air Pollution Control Administration
Rockville, Maryland
Contract No. CPA 22-69-82
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STUDY OF COST OF SULPHUR OXIDE AND
PARTICULATE CONTROL USING SOLVENT REFINED COAL
Robert G. Shaver
General Technologies Corporation
A Subsidiary of Cities Service Company
1821 Michael Faraday Drive
Reston, Virginia 22070
April 1970
Department of Health, Education, and Welfare
National Air Pollution Control Administration
Rockville, Maryland
Contract No. CPA 22-69-82
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ACKNOWLEDGEMENTS
The author wishes to acknowledge the advice and assistance of Mr. A. Gregbli
pf the Cities Service Research and Development Center in cost estimating, the assistance
of Mr. Edwin Abrams and Mr. Leon Ferguson of GTC in the collection of data, and the
assistance of Mr. William Powers of GTC in the market analysis as well as the guidance
and encouragement of Mr. Robert Jimeson and Mr. James Grout of NAPCA.
in
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TABLE OF CONTENTS
Page
I SUMMARY 1
II INTRODUCTION 2
III DISCUSSION OF SOLVENT REFINED COAL AND ITS MARKET 4
A. SOLVENT REFINED COAL TECHNOLOGY 5
IV BASIS OF EVALUATIONS 7
A. CAPITAL CHARGES 7
B. PLANT FACTOR 9
C. THERMAL EFFICIENCY 12
D. TRANSPORTATION OF FUEL 15
E. EXISTING OR NEW UNITS 18
F. UNIT SIZE 18
G. OPERATING LABOR 18
H. STEAM GENERATION RATE 20
I. EFFECT OF SOLVENT REFINED COAL ON PROCESS
AND EQUIPMENT 20
J. PRECIPITATOR CREDITS 22
K. FLY ASH DISPOSAL CREDITS 22
L. PRICE ADJUSTMENT TO CURRENT LEVELS 22
V RESULTS OF EVALUATIONS 27
A. CREDITS ACCRUING TO THE USE OF SRC 27
B. COST OF CONTROL USING SRC 28
C. THE LIMESTONE-WET SCRUBBING PROCESS 35
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TABLE OF CONTENTS (cont.)
Page
VI ESTIMATION OF MARKET 37
VII CONCLUSIONS AND RECOMMENDATIONS 43
REFERENCES 47
APPENDIX A DETAILED COST ESTIMATES A-l
APPENDIX B SUMMARY ALIGNMENT CHARTS B-l
VI
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LIST OF ILLUSTRATIONS
Figure Page
1 Solvent Refined Coal Process 6
2 U. S. Average Annual Plant Factor Experience for Fossil-Fueled
Steam-Electric Generating Plants 11
3 Typical Load Factor Over the Life of a Power Plant 11
4 Trends in Plant Thermal Efficiency by Decades 13
5 U.S. Steam-Electric Utility Thermal Efficency
Experience in Coal-Fired Plants 14
6 Relationship Between Heat Rate and Therrnal Efficiency 14
7 Transportation Cost Experience for Hauling Bituminous
Coal in U.S. 16
8 Cost Data on Hauling Bituminous Coal by Railroad 17
9 Trend in Combustion Unit Size in Steam-Electric Plants
Fossil Fueled 19
10 Relationship Between Steam Rate and Generating Rate
in Steam-Electric Plants 19
11 Effect of Unit Size on Compact Boiler Investment Credit 21
12 Installed Cost of Electrostatic Precipitators 23
13 Operating and Maintenance Expense for Electrostatic
Precipitators 24
14 Plant Fly Ash Disposal Investment 25
15 Plant Fly Ash Disposal Cost for 1967 25
16 Implicit Price Deflator for Non Residential Fixed Investment 26
17 Effect of Unit Size on Investment Credits 29
18 Effect of Unit Size on Total Annual Credits 30
VII
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LIST OF ILLUSTRATIONS (cont.)
Figure Page
19 Effect of SRC Processing Cost on the Cost of Control 31
20 Effect of Unit Size on Cost of Control by SRC 32
21 Effect of Fuel Transportation Costs to the Plant Site
on Cost of Control 33
22 Effect of Shipping Distance on Cost of Control by SRC 33
23 Transportation Cost for Solvent Refined Coal Based on Single Car
Loads 34
24 Effect of Plant Factor on Cost of Control with SRC 36
25 SRC Cost Market Situation for Daviess, Kentucky Location 39
26 SRC Cost Market Situation for Lewis, West Virginia Location 39
27 SRC Cost Market Situation for McKinley, New Mexico Location 40
28 SRC Cost Market Situation for Campbell, Wyoming Location 40
29 Comparison of Costs of Control by SRC and Limestone-Wet
Scrubbing in Electric Utilities 44
30 Estimated Potential Share of Existing Coal-Fired Combustion
Unit Market Available to SRC as Function of Processing Cost 46
APPENDIX B
B-l Cost of Control by Solvent Refined Coal B-3
Bt-2 Cost of Pollution Control by the Use of Limestone Injection
with Scrubbing B-5
VIII
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LIST OF TABLES
Table Page
I Comparative Analysis of Raw Coal ana1 Solvent Refined Product 5
II State-Wide Average Plant Factors for Coal-Burning Steam-Electric
Plants 10
III Potential Annual SRC Production 41
IV Power Plant Markets for Solvent Refined Coa\ 42
APPENDIX A
A-1 Annual Operating Cost Credits for Solvent Refined Coal Use -
50 MW Equivalent Size A-2
A-2 Annual Operating Cost Credits for Solvent Refined Coal Use -
200 MW Equivalent Size A-3
A-^3 Annual Operating Cost Credits for Solvent Refined Coal Use -
500 MW Equivalent Size A-4
A~4 Annual Operating Cost Credits for Solvent Refined Coal Use -
1000 MW Equivalent Size A-5
A-5 Annual Operating Costs for Limestone - Wet Scrubbing Power
Plant Stack Gas 200 MW Existing Unit, 2.9% Sulfur in Coal A-6
A-6 Annual Operating Costs for Limestone - Wet Scrubbing Power
Plant Stack Gas - 200 MW New Unit, 2. 9% Sulfur in Coal A-7
A-7 Calculation of Potential Power Plant Market A-8
IX
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SECTION I
SUMMARY
The products of coal combustion are large contributors to air pollution, especially
sulfur dioxide and fly ash. Satisfactory apparatus to control fly ash emission now exists
in the forms of mechanical collectors and electrostatic precipitators, but the sulfur dioxide
escapes since it is a gaseous emission. In the long run, removing sulfur oxides from the stack
gas is not a solution because of costs and because not all the sulfqr can be removed. The
solution is pretreatment of coal to remove the organic and pyritic sulfur as well as the ash.
One process that can achieve this is solvent refined coal (SRC). This fuel is water-free,
low in sulfur, very low in ash, has a melting point low enough to allow it to be transported
as a fluid, and, regardless of the grade of coal used, the product has a heat content of
16,000 Btu/lb.
The potential market for solvent refined coal is difficult to predict largely because
its use requires a long-term commitment on the part of producers to process it and on the
part of the users, primarily the electric power utilities, to consume it. A level of pro-
duction necessary for economy requires this. However, the potential benefits to the use
of solvent refined coal rather than a combustion gas treatment process are great, and the
special characterisitc that allows a minimized combustion plant investment ensures that
the SRC combustion units as they age and are changed from base load toward intermittent
Iqad use will be op a much sounder financial basis than those that have combustion gas
treatment equipment added on.
A processing cost pf no more than 10<|;/MMBtu to convert bituminous coal to SRC
should allow price-competitive access to over 60% of the current bituminous coal->fired
combustion unit market.
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SECTION II
INTRODUCTION
The sulfur in coal is present both as pyrite and as complex organic substances. Both
forms are amenable to reduction through solvent-refining, the pyrites being removed by
filtration and the organic sulfur through hydrogenation to r^S. Where coal desulfuriza-
tion is practical at reasonable cost it offers the most obvious and direct method to reduce
SO2 pollution by combustion.
This report details the cost analysis study of the use of solvent refined coal (SRC)
in combustion units as a means of pollution control for stack emissions. The processing
involved in producing solvent refined coal results in low sulfur and ash contents and this
places its use in direct competition with such other means of sulfur dioxide and particulate
pollution control for coal-fired combustors involving the removal of sulfur from the stack
gas after combustion.
Many ways of removing pollutants after combustion are being actively developed at
this time. All involve some means of bringing the combustion gas in contact with some sub-
stance which picks up the SO2, leaving the gas to the stack relatively free of this pollu-
tant. There are some 25 such processes under development in this country by industry and
by the National Air Pollution Control Administration, while many others are being de-
veloped overseas in Europe and Japan('). Examples of some of these alternative control
measures are: dry limestone injection, limestone-scrubbing, catalytic oxidation, and
sodium sulfite scrubbing processes, among others. All processes do not function equally
well for the purpose of reducing particulate emissions in addition to SO2 control, but
within their technical capabilities these, and others, can be considereaalternatives in
the design of pollution control coal combustion systems. The primary purpose of this study
is to display the cost analysis data in such a way that it is readily adaptable to a large
variety of real or hypothetical situations of heat or power generation so that direct com-
parisons can be made of the pollution control cost in specific situations by the use of sol-
vent refined coal to that of any other projected system for which control cost information
is available.
Although the chief benefit to be obtained from the use of solvent refined coal is the
reduction of SO2 and particulate pollution, certain other benefits directly or indirectly
accrue because of its properties. For example, the heat content is considerably higher
than the coal from which it is made and hence shipping costs are lower on an equivalent
thermal basis. This is approximately 16,000 Btu/lb, which exceeds high quality anthra-
cite or bituminous coal. Combustion chamber corrosion and slagging problems are directly
reduced by its use. Since solvent refined coal can be liquified by heating and/or in-
creasing its residual solvent oil content, there exists the option of firing as solid coal or
as fuel oil. Lastly it is essentially a "fail-safe" pollution control process so far as the
combustion unit is concerned, since no unusual SOo pollution can be emitted due to
breakdown or bypassing of equipment, as could occur with processes that cleanse combus-
tion products.
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The technology for the production of solvent refined coal has been extensively defined
by work sponsored by the Office of Coal Research at Spencer Chemical Co. and Pittsburgh
and Midway Coal Mining Co., subsidiaries of Gulf Oil Corp. This technology and pro-
jected use and market of the material has been discussed in a number of publications during
the last five years^"^). To achieve the potential benefits from this process, two simul-
taneous long-term commitments must be made: the investment in plants to produce solvent
refined coal must be made and the design or conversion of combustion plants to its use
must be made. To the degree that pulverized solid solvent refined coal can be directly
substituted for pulverized coal in existing coal-fired units, the extent of the latter commit-
ment need is minimized. However, without a substantial and strategically placed series
of solvent refined coal plants producing at an economical level, the economic basis for
its gse cannot be realized.
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SECTION III
DISCUSSION OF SOLVENT REFINED COAL
AND ITS MARKET
Statistics of the National Coal Association(6) show that by far the largest consumer
of bituminous coal in the United States is the electric utility industry. In 1967, of the
480 million tons of bituminous coal consumed in the U.S., 57% was burned by the electric
utilities, 19% was used to make coke, 18% was for other industrial uses such as plant heat,
power and process steam, 3% for cement mills, steel mills and roll ing mills, and 3% for
retail delivery to homes, apartments and commercial buildings. Therefore at least 75% of
the bituminous coal combustion is carried in combustors under conditions similar to those
in steam-electric power generating stations.
The current rate of increase of demand for electric power is a doubling every
decade(6) and since the consumption of coal by the electric utilities grows every year,
the prospects are that for the foreseeable future the significance of coal combustion in
electric utilities will grow. Even if nuclear reactor development is stressed, coal com-
bustion is predicted to account for almost half the power produced at the end of this
centuryw.
At the other end of the spectrum, retail coal deliveries have been steadily de-
creasing in relative importance for 20 years, so that the 1968 retail market volume was
essentially the same as in 1967(6). This source of pollution by bituminous coal combus-
tion is at one and the same time an area of declining relative importance and also one
whose pollution abatement can be brought about directly by substitution of solid solvent
refined coal for the present sulfur-containing coal without elaborate economic justifica-
tions. Most such combustion units are very small and the alternative of investment in a
stack gas purification units is unattractive at this level in the face of an available supply
of pollution-free fuel at moderately higher cost.
The industrial users of fuel are expected to grow slowly in use of coal, probably
thereby occupying a declining share of the total use, also. In most of this market, the
size and practice conforms closely to that of the electric utility industry at the appropriate
size and hence the cost analyses for the one are pertinent directly for the other.
As brought out by the National Coal Association(6), the growth in the use of bitum-
inous coal by its largest category of user, the electric power utilities, has been largely
due to the development of mine-mouth generating stations. Several of these plants that
serve the populated areas of the East are located in the Appalachian coal fields. Others
are being developed in the West. In these instances the importance of location of solvent
refined coal plants is very evident. Having the mine, solvent refining plant and power
generating station in one location minimizes the costs up through the generation of the
power.
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A. SOLVENT REFINED COAL TECHNOLOGY
The solvent refined coal process as developed by Pittsburgh and Midway Coal Mining
Company is depicted in Figure 1. This consists of mixing pulverized coal with a coal-
derived solvent oil having a 500° to 800° F boiling range, passing the mixture with hydro-
gen through a preheater and a reactor, separating excess hydrogen plus the hydrogen sulfide
and light hydrocarbons formed, filtering the solution, flash evaporating the solvent and
recovering the solidified coal product(5). Any coal except possibly anthracite can be dis-
solved and moisture in the coal does not interfere with the process, since it is removed as
it separates from the oil solution. During the reaction phase, the hydrogen reacts with
organic sulfur compounds forming the hydrogen sulfide. The hydrogen also stabilizes the
solubilized coal products. Further reduction of the organic sulfur content by utilizing
greater quantities of hydrogen than in the present design is believed possible(4). The
pyritic sulfur leaves the process in the filtration step, as does the ash components (mineral
matter).
The process generates an excess of solvent oil, thus requiring no make-up solvent.
This is released from the coal itself. It is this characteristic which affords the opportunity
to provide conveniently a liquid or semi-solid form of the solvent refined coal, if desired.
Economical disposal of the mineral residue can be carried out by its use as an asphal-
tic construction material or as a cement kiln feed stock. The specific cost of solvent
refined coal would depend, of course, on the degree toward which the economic value of
the solvent oil and mineral residue by-products are recovered. Comparative character-
istics of a raw coal and a solvent refined product from it are given in Table I. The
sulfur reduction was due primarily to removal of pyritic sulfur. The hydrogen content
used was that necessary to stabilize the polymerization. This hydrogen treatment has
partially reduced the organic sulfur. Presumably further hydrogen treatment could have
further reduced the organic sulfur content of this coal to very low levels. The solid sol-
vent refined coa| is stated to be brittle and readily grindable to a powder, and hence it
is suitable for pulverized coal boiler operation.
Table I. Comparative Analysis of Raw Coal and Solvent Refined Product*
Kentucky No. 11 Coal Refined Coal
Percentage Constituent:
Ash 6.91 0.14
Carbon 71.31 89.18
Hydrogen 5.29 5.03
Nitrogen 0.94 1.30
Sulfur 3.27 0.95
Oxygen (by difference) 12.28 4.40
Volatile Matter 44 51
Heat Content, Btu/lb 13,978 15,956
Melting Point, °C 128
*From Ref. 4
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Solvent-
Feed Pump L
Preheater
Dissolver
Light Oil
Filter
Distillation
Solvent
. Refined
Coal
Ash Residue
Ash Processing
Figure 1. Solvent Refined Coal Process
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SECTION IV
BASIS OF EVALUATIONS
The purpose of this study is to determine the cost of control of pollution emission by
the use of solvent refined coal in producing a unit of heat in the significant existing bi-
tuminous coal-fired combustion units and also in those newly designed and constructed for
the specific use of the refined coal. Since in these new combustion units equipment credits
can be accrued due to the special properties of SRC, the cost of control is defined in this
work as:
Cost of Control = (Price of SRC @ Unit) - (Credits) - (Price of Standard Coal @ Unit)
All costs in the definition are in terms of the unit of output heat, millions of Btu (MMBtu).
In this method of cost of control analysis the cost elements specific to equipment
and operation of the combustion unit itself are completely within the "Credits" factor.
The two prices of fuel factors contain the cost elements external to the combustion unit,
namely the minehead price of coal, the processing costs to produce SRC and the cost of
hauling to the site of the combustion unit. These costs are essentially not within the control
of the combustion unit designer and hence are represented in this report only by typical
ranges for past and current experience and by the estimates of othersH) for the production
cost of SRC. The detail of equipment and operating costs herein analyzed apply to the
combustion unit. In using the results of this study, the known or estimated delivered costs
of fuel must be given and the credits computed herein applied to them.
A. CAPITAL CHARGES
Capital charges to product cost are an annual percentage charge of plant investment
which is used to estimate the return a company should receive to maintain its credit, pay a
return to the owners, and ensure attraction of money for future needs, plus the depreciation,
insurance, taxes and replacements of short I ife equipment. Guidelines and a formula for
this computation is given in a Federal Power Commission publication(S). In a recent de-
sign and cost study of power plant stack gas treatment by the TVA(9), this formula applied
to existing and new units yielded capital charge rates of 14-1/2% and 13%, respectively.
The difference between the two rates being primarily due to a 20-year depreciation for
existing units and 35 years for new units. In a similar recent study by the GCA Corporation
for the American Petroleum InstituteOO/11), a somewhat different approach to capital
charges was taken. For the dolomite injection-wet scrubbing installation a capital charge
rate of 21% was used for the stated reasons of reflecting the higher cost of money and
increased depreciation (11 year life) which was recommended by the Internal Revenue
Service(12) for Chemical and Allied Products. Using the FPC method with 35 year depre-
ciation, a 14% capital charge rate was calculated in this API study, but not used. The
recent higher cost of money has had an impact on the electric utilities as documented in
recent FPC publications(24,25).
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A more recent publication by TVA authors(13) based on the 1969 design and cost
study(9) of the limestone-wet scrubbing process uses a 15% capital charge figure. This
includes a 20 year remaining plant life, which corresponds to an existing plant situation.
An earlier (1968) TVA design and cost study of the dry limestone process for power
plant stack gas(14) used an apparent capital charge rate of 13%, covering interest, de-
preciation, taxes and insurance. This also included a 20-year depreciation pertinent to
existing units, although the capital charge rate is the same as that calculated for new
units in the later TVA study(9) that used a 35-year depreciation.
In a presentation to the Air Pollution Control Association on cost determination
procedures, Edmisten and Bunyard of NAPCAO^) recommend the IRS guidelines(12) for
depreciating the capital investment on emission control equipment. They consider a
depreciation period of 15 years typical for control equipment installations and 28 years
otherwise for steam-electric generating industry. Further the cost of capital (interest,
taxes and insurance) was stated to range from 6 to 12 percent per year depending on local
taxes, industry, financial position, and the existing money market. A value of 7 percent
was selected for consistency in their recommendation.
The capital charge parameter is one of considerable significance in the cost com-
parison among various means of pollution control since it is the specific parameter that
discriminates with regard to complexity of additional installed facilities. The importance
of consistent capital charge values is self-evident.
It seems most consistent for the purposes of this study to use the guidelines of the
FPC for capital charges, with certain updatings to conform to the altered money market.
With respect to the use of solvent refined coal, any differences in plant investment between
using it or using regular coal will be due to changes only in size or complexity of con-
ventional combustion plant equipment and hence the calculations clearly fall under the
FPC guidelines.
The specific breakdown of the components of capital charge that is used in this study
is given below:
Annual Percent of Investment
Existing Units New Units
Power Control Power Control Industrial and
Component Plant Equipment Plant Equipment Commercial
Depreciation, straight line 5.0 6.7 3.6 6.7 9.1
Interim Replacements - - 0..7 0.7 0.7
Insurance 0.3 0.3 0.3 0.3 0.3
Taxes 5.0 5.0 5.0 5.0 5.0
Cost of Capital 4.3 4..3 5.1 _5J 4.9
Total of Capital Charges 14.6 l"673" ll~7 17.8 20.0
Capital Charge Rate Used 15 16 15 18 20
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The cost of capital includes 50% debt and 50% equity for utilities, and 25% debt and 75%
equity for industry. Debt on existing utilities is at 6% and on new utilities at 9% of de-
preciated value. Equity is at 11% of depreciated value. Debt on industrial is at 6%.
Thus for the calculations on the use of solvent refined coal, credits to its use will
accrue due to the elimination or modification of conventional power plant equipment
and consequently a capital charge rate on changes in investment for this study will be 15%
for new and existing public utility units and 20% for industrial and commercial combustion
units. The 16% rate for control equipment on existing units and 18% on new units will
apply in this study only on the limestone-scrubbing process example.
B. PLANT FACTOR
Power must be generated at the moment of use because there is no practical way of
storing it in appreciable amounts as mechanical or electrical energy, steam, heat or com-
pressed air. Many factors are variously employed to define the character of the plant
load. Among them are:
average load for period
load factor = 1iT-? r:
peak load for period
_ output for period
capacity factor - ratea capacity X hours in period
The latter factor, capacity, is the one defined in this study as the "plant factor". This
factor is the more meaningful for costing estimates based on plant ratings, which are fixed
and directly related to invested capital.
Intermittent and partial load operation of combustion units is an important variable
in the economy of combustion plants. This has a direct effect principally on the main-
tanence type of operations, which are relatively minor costs, but the indirect effect on
capital charges is a major one. Since the investment charges are related to capacity
and are charged out on a yearly basis, operation at lower than capacity increases these
charges per unit of output in a direct and major way.
Recent experience in coal-fired electric utility plant factors on a state-by-state
basis is shown in Table II. Even the average values range widely, from a low of 24 per-
cent to a high of 71 percent. Optimization of costs call for as nearly full capacity opera-
tion as possible, but experience clearly shows that this cannot be achieved even approximately
in real practice on a large scale. Recent experience nation-wide as shown in Figure 2
is annual averages between 55 and 61%.
During the life of a power plant the plant status changes from base load to peak
load and finally to occasional load operation. This results in the decrease in average
annual load factor shown in Figure 3. The average factor over the life is a 57% load
factor or 53% capacity factor. This shows that in estimating the economics for a specific
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Table II. State-Wide Average Plant Factors for
Coal-Burning Steam-Electric Plants*
State Weighted Average Plant Factor, percent
Alabama 65
Arizona 43
Arkansas 27
Colorado 59
Connecticut 70
Delaware 68
D.C. 56
Florida 47
Georgia 51
Illinois 57
Indiana 53
Iowa 60
Kansas 48
Kentucky 50
Maryland 55
Massachusetts 63
Michigan 60
Minnesota 61
Missouri 58
Nebraska 61
Nevada 85
New Hampshire 69
New Jersey 62
New York 64
North Carolina 56
North Dakota 60
Ohio 62
Pennsylvania 64
Rhode Island 49
South Carolina 52
South Dakota 69
Tennessee (TVA) 59
Utah 58
Vermont 24
Virginia 58
West Virginia 71
Wisconsin 56
Wyoming 52
*From data of FPC (Ref. 16)
States not cited have no coal-burning steam-electric utilities
10
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1938
1957
1967
Figure 2. U.S. Average Annual Plant Factor Experience for Fossil-Fueleo
Steam-Electric Generating Plants (from data of FPC, Ref. 16)
100
80
c
01
5 60
t3
-o
§
]40
0)
OJ
8
o
20 ~
10 20
Years
30
Figure 3. Typical Load Factor Over the Life of A Power Plant (Adapted from Reft 17)
11
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application, the current operating history, if available, should be examined in detail.
Pollution control systems that minimize combustion plant capital investment will be
the more suitable ones economically for low plant factor operation. The widespread occurrence
of rather low plant factors indicates that this is a major consideration in practical combus-
tion plant pollution control.
C. THERMAL EFFICIENCY
Thermal efficiency is the ratio of the electric energy produced to the thermal energy
of the fuel burned. As thermal efficiency increases the amount of coal burned to produce
the given output is reduced. The thermal efficiencies of plants in use vary, but the trend
is upward with time, as seen in Figure 4. The general upward trend has been interrupted
by two plateau regions in the efficiency curve. The one during the years of the Great
Depression and World War II was due to the lack of interest in investment in fundamental
improvement of cycle efficiency. Subsequently new growth in energy requirements brought
about improvement in efficiency. In recent years a second plateau in efficiency was
brought about by our increasing reliance on the use of cheap subsidized fuel as an alter-
native to thermodynamic optimization''"). Because of the current high cost of money, the
plants now being built are at a minimum current investment design rather than optimized
thermal efficiency.
The specific trend in thermal efficiencies in the U.S. adapted from data of the
Federal Power CommissionO^) js shown in Figure 5, both as thermal efficiency and as
the so-called "heat rate" of Btu's required to produce a kilowatt-hour of electricity. Both
an increase and a leveling off of the increase of efficiency are evident. The heat rate
and thermal efficiency are inversely related by the factor of the mechanical equivalent
of heat (3413 Btu/KWH), that is:
heat rate (Btu/KWH) = , Jff r^:
thermal efficiency f 100
This relationship is shown graphically in Figure 6.
In the long run, further increases in the thermal efficiency of coal combustion-
steam turbine cycle plants will be small because of the inherent limitations of the second
low of thermodynamics coupled with high temperation problems due to materials of con-
struction and slagging of combustor surfaces. The thermal efficiency is basically limited
by the spread between the upper temperature to which the steam can be brougSt by the
combustion-heat transfer process and the lower temperature at which the waste heat is
rejected to the surroundings. With a steam initial temperature of 1100°F, the reversible
cycle efficiency is about 60%. Actual inefficiencies in boiler heat transfer, combustion,
powering of auxiliaries and the like reduce the overall thermal efficiency markedly.
Based on this reasoning and the data of the FPCO^), a range of efficiencies up to 40 per-
cent is judged to cover all pertinent coal combustion applications for a practical future
period. Existing units on the average would have thermal efficiency of 33-34%, whereas
new well-designed facilities would be upwards of 36%. Individual existing units have
shown annual heat rates as low as 8,660 Btu/KWH, which is an efficiency of 39.4%(16).
12
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80
75
70
65
60
55
^ 50
^ 45
u
.1 40
u
LLJ 35
1 30
£ 25
20
15
10
Trends in Plant Thermal Efficiency
Compound Cycles
Fuel Cell
Highest Plant Average For
the Year
Highest
Estimo*
Most
Probable
Projected Probable
Average for the Year
Includes all Plants
I
I
I
I
I
I
I
1890 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990
Years
2000
Figure 4. Trends in Plant Thermal Efficiency by Decades (Adapted from Ref. 14)
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45
«. 40
u
.1 35
u
30
25
1957
Meat Rate
Efficiency
i
1959
1961
1963
I
1965
Year
1967
12
X
11 I
a
3
CD
TJ
c
10 Si
40
I
* 30
u
a.
£
05
I20
o
-
10 -
10
FigureS. U.S. Steam-Electric Utility Thermal Efficiency
Experience in Coal-Fired Plants
'T-
IS
T
T
20 25 30
Thermal Efficiency (percent)
35
40
Figure 6. Relationship Between Heat Rate and Thermal Efficiency
14
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The best annual company heat rate in the same year (1967) was 9,487 Btu/KWH or 36%
efficiency.
D. TRANSPORTATION OF FUEL
Coal transportation is highly competitive, but the largest share in the U. S. by far
is carried on the railroads. Trucking, barging and coal slurry pipeline are contending
modes of transport. Since coal is a bulk commodity, its transportation costs add considerr-
ably to the users total costs. The average railway freight in 1965 added 70% to the cost
of the coal at the mine. However, the transportation rates have been lowered in the
past few years under the competitive pressure within the energy market. That this is evi-
dent can be seen in Figure 7. From peak rates in the years 1957-1958, the cost has de-
creased consistently, and rather more rapidly since 1962.
The competition to reduce the delivered coal cost has involved the railroads pri-
marily, which haul over 70% of the bituminous coal in the U.S. This is a major source
of rail revenue, and for some railroads is the principal source of revenue. The slurry coal
pipeline challenge of 1957 caused the railroads to develop rate schedules which reflect
the economies of large volume sales to a single customer, as is evident in Figure 7. The
use of unit trains that run directly between the mine and the user without intermediate
yarding is a significant step in cost economizing. This allows the complete shipping
cycle to be reduced in time drastically. The total train capacity is about 10,000 tons
and larger units are expected. The extension of this unit train concept to integral trains
is, being planned. These trains will consist of permanently coupled cars carrying 35,000
to 40,000 tons of coal with rapid unloading capability.
Apparently because of the intense competition and the relatively fluid state of
railroad rates, obtaining generalized rate data directly is difficult, and its value some-
what doubtful. Data for specific situations is more readily available. The most generalized
data available is depicted in Figure 8. The significant effects shown are those due to
length of haul and size of shipping contract. That the actual cost to haul the coal by
railroad in terms of dollars per ton is not go greatly affected, on the average, as might
be inferred from Figure 8, can be seen clearly in Figure 7.
We suspect that the significant difference in actual transportation costs for most
large users of bituminous coal will arise by virtue of location, that is whether the com-
bustion plant is near the mine head or whether public rail transport has to be used. Be-
cause of the uncertainties in the costs of the major source of coal transportation with
respect to the future, the cost analyses were carried out on a basis of fuel price delivered
at the combustion plant as the imput parameter. This value is very likely to be known
reliably to those contemplating a major installation at a specific location.
15
-------
320 -,
-5*310
o>
D
O
'o 300
-C
0>
V
I
V
O)
2
% 290
280 _
1.00 -,
3.50 -
o
o- 3.00 H
e
_o
"o
o
2.50 -
2.00
JW
I
o
0)
Q_
V
O
Average
Length of
Haul
1947
1952
1957
Year
1962
Figure 7. Transportation Cost Experience for Hauling
Bituminous Coal in U.S. (Source, Ref. 6)
1967
-------
1.8
1.6
1.4
1.2
Single Carloads, 50 Ton Minimum, Ref. 9
a>
a.
L
Ref. 19
0.6
\
Unif train, TVA, Ref. 9
0.4
0.2 .
100 200 300 400
Length of Haul (miles)
500 600
Figure 8. Cost Data on Hauling Bituminous Coal By Railroad
17
-------
E. EXISTING OR NEW UNITS
The status of the unit for power generation, that is whether it is in existence or
whether it is being planned, has been.found to be an important factor in the stack gas
pollution control process studies(3, 9,17). This ;s primarily because these processes require
alterations in plant design and allowance for additional equipment. These accommoda-
tions can be more economically met during the design of a new plant than by add-on to
an existing one. The effect of status of the plant on the economics of the use of solvent
refined coal is similar in the sense that certain installations are not required with SRC.
Most conspicuous is the precipitator equipment, which is a very substantial investment
and is not necessary for a plant that burns refined coal exclusively. Thus we would expect
economies due to integrated design for the use of this fuel.
F. UNIT SIZE
The economics of scale are well-known in the power generation field and the trend
for years has been toward construction of larger combustion units as seen in Figure 9.
TVA(14,17) projects that over 95% of the capacity installed after 1970 will be in units
of 600 MW or larger and 80% in units of 1000 MW or larger. Therefore it is evident that
the focus in pollution control will inevitably move in the direction of large, new units.
In the recent FPC data('°), the largest coal-fired steam-electric plants are up to
the vicinity of 1,900 MW consisting of 6 to 10 units each generally. Among the thirty-
six coal-fired units with the best annual heat rates (thermal efficiencies) in 1967, the
unit size ranged from 185 to 704 MW, with the best ten averaging 356 MW and the best
thirty-six averaging 317 MW. Thus it is evident that the economies of size not only occur
in design and planning, but also in actual operation. One of the important variables
included in this study is unit size, which will be projected to the 1,500 MW size and its
equivalent in combustor size.
G. OPERATING LABOR
Using statistics of the Department of Labor for the electric utilities(20)/ an esti-
mated current weighted average rate for operating personnel for the coal-fired combus-
tion plants covered in this study has been derived. The wage data, straight-time hourly
earnings excluding pay for overtime and the like, has been employee number-averaged
for those occupations clearly engaged in the combustion power plant, e.g. boiler opera-
tions, control room operators, maintenance mechanics, turbine operators, pipefitters, etc.
This wage value for 1967 is $3.57 per hour. As a basis for updating to current, the wage
trend data of the category "skilled maintenance (men), all industries" from a 1969 Depart-
ment of Labor Study(21) was used. This value was an increase from 1967 to 1969 of 7.8%.
To raise to the 1970 level a further 4% increase was assumed. Thus the average hourly
operating labor wage rate for this study is calculated to be:
18
-------
1500
400
300
J- 200 -
a
In
-------
1967 rate (derived from Ref. 20)
7.8% increase 1969 (from Ref. 21)
Estimated 1969 rate
4% increase to 1970, estimated
Estimated 1970 rate
14% allowance for supervision
Total Labor and Supervision Rate
H. STEAM GENERATION RATE
In relating the steam-electric utility plants and non-power-generating steam plants,
such as those used for heat and process steam, a steaming rate of 10 Ibs of steam per
13,500 Btu of coal-fired energy is used based on the recommendations of Chemical En-
gineering Costs Quarterly(22). This corresponds to a boiler efficiency of about 80%. On
this basis the steaming rate capacity and the power generating capacity are directly re-
lated by the plant thermal efficiency (heat rate), a variable discussed earlier and readily
obtained from prior experience or design criteria, for existing or new units, respectively.
The relationship between steam rate and power generating rate is shown in Figure 10.
I. EFFECT OF SOLVENT REFINED COAL ON PROCESS AND EQUIPMENT
All large coal-burning electric power plants in the U.S. use the pulverized fuel
technique whereby powdered coal is blown into furnaces of very large volumes(T). Since
the solvent refined coal can be optionally handled either as a solid or as a fuel oil liquid,
it is most likely that those combustors now using coal would use solvent refined coal in
the powdered solid form. This would entail minimum conversion. New plants could be
designed either way, the decision presumably resting on economic merits.
In the design of a boiler firing solvent refined coal there are some factors that must
be considered regarding its tendency to agglomerate, to pack in transport systems and to
adhere to surfaces when in molten form. There are still developmental and demonstration
efforts along these lines required to establish the guidelines for design of a boiler. Despite
these uncertainties, we herein make the assumption that SRC is equivalent to Bunker C
oil as to burning characteristics in the combustion chamber. Under this assumption a more
compact and less expensive boiler would be used than one for firing a good bituminous coal
at the same heat release rate. Therefore the estimation of the cost credits accruing to the
compact boiler design consisted of the addition of the cost of pulverizer equipment to the
cost of a Bunker C-type boiler and subtracting this total from the cost of the bituminous
coal-fired boiler at the various sizes. The data with respect to the oil-fired versus coal-
fired units came from two sources, published data of Durham(22) and private communication
with the Foster Wheeler Corporation. This information is summarized in Figure 11.
20
-------
5x10'
10'
_o
"o
c
v
E
i/>
OJ
>
10*
I I UNI
Ml
i I I I I I I I
300 500 1000 5000
Boiler Size (thousands Ibs/hr of steam)
10,000
Figure 11. Effect of Unit Size on Compact Boiler Investment
Credit
21
-------
J. PRECIPITATOR CREDITS
Precipitator credits accrue due to reduction in labor, overhead and maintenance in
both existing and newly designed unit. Credits due to elimination of the investment in
precipitator equipment accrue only for new units, since they are assumed to exist in present
units and the investment in them cannot be recovered. The basis for these figures has
been obtained from the recent literature on the limestone-wet scrubbing process(9,10).
Installed cost figures from these studies are plotted in Figure 12 together with the regression
analysis line from a recent NAPCA survey of power plant installations(23). There is good
correspondence between the survey data line and the estimate correlating line of the API
study at the lower size range, but substantial deviation above 500MW. Since there is
no reason to believe that the cost should be linear with size, the 0.8 power relationship of
the API studyOO) was used in this work.
As regards the annual operating and maintenance expense, estimates from the TVA
study(9) and the survey data points of NAPCA(23) are shown in Figure 13. Because of the
enormous scatter in the survey data, due in part probably to differences in accounting
procedures at the various facilities, the more consistent values of the TVA study are used
herein.
K. FLY ASH DISPOSAL CREDITS
Fly ash disposal credit data was derived from the NAPCA survey of steam-electric
facilities(23). These data and our selected correlating I ines are given in Figures 14 and
15 for the system investment and operating costs, respectively. Although the survey data
are quite scattered, the trends with size of unit are evident and the correlations are
believed to be sufficient for these estimation purposes.
L. PRICE ADJUSTMENT TO CURRENT LEVELS
The data of the Department of Commerce of the relative price index levels for
non-residential fixed investment given in reference 23 has been extrapolated to the 1970
level. This is shown in Figure 16. These values have been used to adjust prices in the
various literature sources to a consistent basis.
22
-------
2400
2200
2000
1800
= 1600
T3
s
-81400
c
§
Jl200
ulOOO
0)
in
C
800
600
400
200
\ I I I I I
Regression Line
_ From Ref. 23"~
Ref. 10
Ref. 9
I
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Boiler-Associated Installed Generating Capacity (megawatts)
Figure 12. Installed Cost of Electrostatic Precipitators
23
-------
0.09
0.08
c
9)
x-0.07
-------
2000
1800.
-51600
~o
-§1400
§
Jl200
flOOO
Z 800
a 600
1
2*400
SI200
I
0
I
i 200 400 600 800 1000 1200 1400 1600 1800 2000
Installed Generating Capacity (megawatts)
Figure 14. Plant Fly Ash Disposal Investment
(adapted from Ref. 23)
0.30
|j 0.20
u
"s
§
5
-S
t 0.10
c
_p
a.
0.00
200 400 600 800 1000 1200 1400 1600 1800 2000
Plant Installed Generating Capacity (meaawott^
Figure 15. Plant Fly Ash Disposal Cost for 1967 (adapted from Ref. 23)
25
-------
no
100
I 90
c
80
70
1955
1960 1965
Years
I J 1 I I I I II I I I I 1
1970
Figure 16. Implicit Price Deflator for NonResi-
dential Fixed Investment
26
-------
SECTION V
RESULTS OF EVALUATIONS
The basis of these evaluations was the examination of the combustion-heat generation
process for those units consuming bituminous coal in significant quantities. The principal
type of combustion unit of this sort is the steam-generating unit consisting of boiler auxil-
iaries, firing equipment fuel and ash-handling equipment, boiler feed pumps, water treat-
ing plant, and the steam and water piping. This is the sort of unit that powers the gene-
rators in steam-electric power plants, the single largest type of user of bituminous coal,
and that furnishes in-plant power, heat, and process steam for large industrial uses, such
as chemical and food processing industries. The heating of large commercial and public
building complexes uses similar combustion units, in those instances where bituminous
coal is the fuel.
In all such applications the solid solvent refined coal can be directly substituted for
the bituminous coal by employing the suitable particle size. Conventional feed equipment
should handle the SRC without significant change.
These ranges of parameters whose effects on overall process economics were con-
sidered:
Unit Size: 350 to 704 thousand Ibs/hr of steam generating capacity
Power Plant Size: 50 MW to 1000 MW
Plant Factor: 20% to 100%
Power Plant Heat Rate: nominal 9500 Btu/KWH, range 8000-15,000
The types of units considered in these calculations were:
existing units in industrial, commercial and utility operation.
new units in these uses, designed for the specific use of SRC fuel.
The preceding section details that basic information and assumptions upon which these
calculations were made.
The operating costs include appropriate capital charges, and the investments
include engineering costs, contractor fees, and contigency charges. In this way, the
evaluations were designed to be as comparable as possible to those of recent studies by
TVA (9/ 13, 14) anc| fne APl(10,11) for other processes of sulfur oxide pollution control.
The single significant difference between the basis of this study and these earlier ones
is the updating of fixed charge rates, costs and labor rates to reflect current financial data.
A. CREDITS ACCRUING TO THE USE OF SRC
The basic calculations involved the calculation of fixed charge and operating cost
credits, whether positive or negative, accruing to the use of solvent refined coal in place
of bituminous. These calculations are independent of the exterior fuel costs (price and
delivery charges), which vary for many reasons including location. The calculations of
27
-------
credits are summarized in Appendix A, Tables A-l to A-4. Figure 17 summarizes the in-
vestment credits computed for the various size combustion units. These credits are all
positive credits since they consist of equipment not required when SRC is used as fuel.
Figure 18 summarizes the total annual operating credits for the various sizes and types of
units under the specific conditions of 8000 hours per year operation at the rated output,
the base line case used in this study.
B. COST OF CONTROL USING SRC
In the basic definition of cost of control for solvent refined coal, the credits are
subtracted from the difference in delivered fuel costs between SRC and bituminous coal, on
a comparable basis. The price of coal at the mine-head varies rather widely from location
to location around the U.S. and so does the cost of transporting it to the user. To establish
reasonable cases that could be analysed for the specific costs of control, the range of pro-
cessing costs to form SRC from bituminous coal of 10 - 18 cents per million Btu given in an
earlier analysis by Jimeson and Groutv^) was assumed. It was further assumed that the
SRC was derived from the specific bituminous coal in use at the combustion plant and that
the processing was carried out nearby to the mine. Thus the transportation costs in terms
of dollars per ton to the combustion plant would be the same for either coal or SRC. Further
the price of the SRC would then be the mine-head cost of the coal plus the assumed proc-
essing cost range.
Proceeding on this basis several series of representative control cost cases were cal-
culated to delineate the effect of several major variables and these results are shown in
Figures 19 to 23. In Figure 19, the SRC processing cost variable itself is examined and
it is found to be a major element in determining the cost of control, as would be expected.
The range of costs represented by the several types of combustion units is for less than the
range of uncertainty in the SRC processing cost itself.
In Figure 20 the effect of combustion unit size on the cost of control is depicted.
This is found to be a relatively unimportant factor under the restraints of no variation in
SRC cost, transportation cost, or load factor due to size. To examine the fuel transpor-
tation rate effect in detail the calculations in Figure 21 were made. In this a constant
hauling distance between fuel source and combustion plant of 297 miles was used, which
happens to be the average haul for bituminous coal on railroads in the U. S. in 1967(").
Hauling rate is a major factor affecting cost of control since there is a substantial increase
in heat content in forming SRC from bituminous coal. Thus the cost of control responds
negatively to increases in the railroad hauling rates. Since fuel hauling rate may in fact
be related to unit size or more probably plant size by virtue of changes in shipping rate
schedule because of large hauling contracts, the overall effect of size is difficult to
quantify but probably is significant.
Similarly, the effect of distance of haul of the fuel on the cost of control can be
seen in Figure 22. This was calculated at the single car load rate schedule shown in
Figure 23.
28
-------
I/I
o
=5 6
4
U
c
0)
I 2
V
>
; 1 2 34 56 78
Steam Generating Capacity (millions of Ibs/hr)
Figure 17. Effect of Unit Size on Investment Credits
29
-------
2X106 r-
10C
5x 105
o
-o
I
s
V
Q.
o
2x10"
I I I I I [
8000 hrs/xr operation
80% boiler efficiency
9500 Btu/KWH
_L
I.I I I I I 'I.
50 100 200 300 400 500 100Q
Power Unit Size (megawatts)
I I I I I I I I . f . 1 . I I I I I
400
1000 2000 500
Btu Rate (millions Btu/hr)
10,000
.1.1 I I
300 500 1600 2000
Steam Rate (thousands Ibs/hr)
Figure 18, Effect of Unit Size on Total Annual Credits
5000 7000
30
-------
14
13
12
I
c
10
9
o
U
V)
O
T
T
Steam Generating Capacity = 1,410,000 Ibs/hr
200 MW Size
Transportation Cost $2.90/ton
Equal Shipping Distance for Coal or SF
Coal = ll,OOOBtu/lb
I
I
10
12 14 16
Processing Cost of SRC (
-------
14
13 |-
12
11
10 -
CO
7
i I I
New Utilities
91% Plant Factor
_SRC Processing Cost = 18C/MMBtu
14$/MMBtu
10^/MMBtu
Transportation Cost $2.90/ton
Coal = ll,OOOBtu/lb
I
I
I
I
I
I
I
01 234567
Steam Generating Capacity (millions Ibs/hr)
Figure 20. Effect of Unit Size on Cost of Control by SRC
32
-------
16
14 -
12
10
I
3°
I«
1 1 1 T
200 MW Size
91% Load Factor
297 Mile Distance Both Coal
and SRC
0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8
Fuel Transportation Rate ($/ton-mile)
Figure 21. Effect of Fuel Transportation Costs to the
Plant Site on Cost of Control
16
14
12
3
CO
**
-o 8
c
o
w. 6
o
o
U
200MW-S1ze
Single Car Load Ton-Mile Rates:
Equal Distances Coal and SRC
New Utilities
91% Plant Factor
Coal ll,OOOBru/lb
I
I
I
100 200 300
Fuel Shipping Distance (miles)
400
500
Figure 22. Effect of Shipping Distance on Cost of Control bv SRC
33
-------
10
9
8
3
CO
O-
t; 5
o
u
§ 4
o
O-
in
O
0
0
100
200 300
Distance (miles)
400
500
Figure 23. Transportation Cost for Solvent Refined Coal Based on Single
Car Loads
34
-------
As one would expect from the previously seen effect of rate changes, the effect of
increasing distance of haul is to decrease the cost of control. Clearly the use of SRC is
favored in plants relatively remote from the mines.
The effect on cost of control of the plant factor experienced by the combustion unit
is shown in Figure 24. Variations in control cost due to this factor arise from the amount
of output that the fixed charges are spread across. Since there are no investment credits
taken for existing units using SRC, the load factor has no effect on the cost of control.
However, the new units, that is those designed and constructed specifically for SRC use,
have a strong relationship between cost of control and plant factor. Since the investment
credits are positive, the lower load factor operation has significantly lower cost of control,
The interesting feature of this correlation is that although new units initially start out at
high plant factors under base load conditions, the service changes over a 20-year perjod
through peak use to intermittent use at 20% or lower plant factor. The national average
recently is 55%0^) and thus in the up-coming decades, if SRC-fueled combustion units
have become common in service, the cost of control advantage for SRC will be quite
substantial.
As an aid to the use of the estimates generated in this study, the calculations have
been consolidated in the form of the alignment chart in Appendix B, Figure B-l. This
nomograph was constructed to yield cost of cost of control values accurate to within
l/2$/MMBtu in the range of the variables calculated and to allow extrapolation for a
reasonable range beyond. To use this chart the following factors must be known: the
capacity of the combustion unit or the electric power unit rating and thermal efficiency,
the unit load factor, the unit status, and the delivered prices of the alternative fuels,
SRC and the standard bituminous coal, for the location.
A sample case consistent with the representative trend examples shown earlier in
Figures 19 to 24 is given on the nomograph.
C. THE LIMESTONE-WET SCRUBBING PROCESS
To provide cross-comparison information with a well developed combustion gas treat-
ment process for pollution control, the data and calculations of TVA in their 1969 report(9)
and of the API in their studyOO) of the limestone-wet scrubbing process were recalculated
to be consistent with the capital charge rates, labor rates and price levels used in this
SRC study. Examples of these calculations are given in Appendix A, Tables A-5 and A-<6.
An alignment chart summarizing these calculations over essentially the same range of
variables as the SRC study plus a coal sulfur content range of 1/2 to 4-1/2 percent is
also given in Appendix B, Figure B-2. By means of the two alignment charts in Appendix
B, a consistent set of control costs of these two pollution control systems can be estimated
for a given real or hypothetical combustion unit situation.
35
-------
7
6
5
4
2
c
o 3
U J
'o
ti'-l
o
U
-2
-3
-4 ._
-5
0
20
Existing Units
Unit Size: 1,410,000 Ibs/hr Steam Rate
(200 MW)
Coal Cost: $6.62/ton del ivered
Coal Heat Content: 13,880 Btu/lb
SRC Cost: 30(J/MMBtu delivered
40 60
Plant Factor (percent)
80
100
Figure 24. Effect of Plant Factor on Cost of Control with SRC
36
-------
SECTION VI
ESTIMATION OF MARKET
As discussed earlier, the market for solvent refined coal is difficult to estimate be-
cause the attainment of a significant volume of use is dependent on the ready availability
of low-cost refined coal, a situation that involves a circularity. In short the virtual
simultaneous construction of solvent refining plants and decision to substitute SRC for
bituminous coal in large scale combustion uses must take place, as has been brought out
by Jimeson andGrout(4).
In estimating the market volume potential for solvent refined coal several aspects
must be considered. First the SRC must be looked upon as a new produce being introduced
into an existing market that has been solely dominated by bituminous coal for many years.
SRC is an innovation that offers several previously stated technological advantages over
the commonly used bituminous coal. Most important of these advantages, of course, is
the significant reduction in sulfur content. It is not realistic to suggest that deep market
penetration can be achieved on the strength of any one or all of the technological ad-
vantages offered by SRC but as requirements for limitation of sulfur content in coal become
more stringent it is reasonable to assume that the low sulfur and ash characteristic would
have more market impact.
It now becomes evident that the primary factor that will directly bear on the market
penetration of SRC is cost. Simple cost comparison between SRC and bituminous coal is
meaningless as explained previously. Overall economics must be evaluated on the basis
of cost per MMBtu for each competitive product at the consumers plant.
Since 57% of the bituminous coal consumed in this country is burned by the electric
utilities(6) and since, to a significant degree, theyare already under governmental control,
this is the primary market that should be approached. Although these computations show
that there is substantial benefit to be obtained by the use of SRC in industrial steam, heat
and power generation in units designed for it, the numbers of individual actions required
to establish SRC in this market does not make it favorable for the short term. Once SRC
production in volume at an economical level has been established and assuming significant
pressure on industry from the governmental units and from the public for pollution control,
this can then be a very fruitful market for SRC.
The initial penetration of the power plant market simply on the economic virtues will
probably occur in those plants having high transportation costs and those having low load
factors due to service use. In these operations, the use of SRC to combat pollution
can minimize the penalty on output KWH's over other pollution control systems. The
approach to pollution control by the use of SRC is essentially one of centralized removal
of pollutants in large effective process units, rather than in a fragmented series of much
smaller units at the combustion site.
37
-------
In establishing a potential market size for solvent refined coal, a specific tactic for
selection must be considered. This tactic is based on the probable transportation cost
differential due to the lighter weight per unit heat with solvent refined coal. Since it
must be presumed that the raw material for the SRC process is at the same minehead price
as that of the coal shipped directly to the users in the area, the add-on cost for the SRC
less the transportation cost credit (differential per unit heat due to lower weight) and less
the operating cost credits in existing combustion units must be zero or negative for the
SRC to capture the specific market location from the bituminous coal. This market estimate
tactic, of course, does not make any allowance for the value to be attached to pollution
abatement, per se. Stringent enforcement of sulfur oxide emission standards would change
the basis of comparison from the simple use of bituminous coal as it is now done to the
alternative pollution control systems based on combustion gas treatment.
Four central locations were chosen to provide a basis for cost computations. These
locations, although not optimum, are suggested (4) as being favorable relative to sources
of cheap coal, and central to large potential markets for the SRC. The four hypothetical
SRC processing plant locations are as follows:
(1) Lewis, West Virginia
(2) Daviess, Kentucky
(3) McKinley, New Mexico
(4) Campbell, Wyoming
Computation of the comparative costs between SRC and bituminous becomes quite in-
volved but it can be carried out with reasonable confidence in the results achieved. The
many involved factors and calculated results are shown in Table A-7. Computations were
conducted on a state-by-state basis, with each state related to one of the four hypothetical
SRC production plant locations. After credit allowance for the SRC operating cost econom-
ies were subtracted from the total of transportation cost, raw coal cost and SRC processing
cost, the SRC was compared to bituminous coal on a net cost per MMBtu basis FOB consumer
power plant. On an individual state basis the SRC either captured the entire power plant
bituminous coal market if it had a lower net cost, or the bituminous coal retained the entire
state market of it had the lower net cost. These data on potential SRC markets were then
grouped by cost ranges and plotted on Figures 25 through 28. These data show, for each
SRC plant location, the available power plant SRC market volume versus the various levels
of SRC processing cost.
Jimeson and Grout' v provide estimates of SRC production versus output costs at two
production levels for each of the previously stated locations as is shown in Table III.
The data in Table III represent the production volumes for given plant locations that
would result in processing costs of either 10$/MMBtu or 18$/MMBtu. These output costs
data have also been plotted for each respective location on Figures 25 through 28.
38
-------
I
8
u
O)
c
U
40 60
Millions of Tons of SRC
80
100
Figure 25. SRC Cost-Market Situation for Daviess, Kentucky Location
I
8
u
CD
C
's
a
U
50 100 150
Millions of Tons of SRC
200
Figure 26. SRC Cost-Market Situation for
Lewis, West Virginia,Location
-------
I I
Output Costs
8
o
O)
_c
v»
-------
Table III. Potential Annual SRC Production
. SRC Production (Thousands of Tons)
Location @18<: Processing Cost @10$ Processing Cost
West Virginia 4,742 11,464
Kentucky 4,646 7,076
New Mexico 3,910 3,966
Wyoming 5,059 6,001
Conclusions can now be drawn by comparison of the output cost curve and the avail-
able market curve for each of the four SRC plant locations. On Figure 25, for the Daviess,
Kentucky location, it is seen from the output cost curve that SRC can be processed at the
7 million ton per year level (Point A), at a cost of 10$/MMBtu, with ready markets avail-
able for the entire output. At a price of 10^/MMBtu the existing market for SRC is that
shown at Point B, or approximately 55 million tons. At a price of 18
-------
Table IV. Power Plant Markets for Solvent Refined Coal
Potential Market (Millions of Tons)
Location @18(J Processing Cost @10$ Processing Cost
Kentucky 0 55
West Virginia 15 93
Wyoming 0 0
New Mexico 0 0
Total 15 148
42
-------
SECTION VII
CONCLUSIONS AND RECOMMENDATIONS
The principal advantages to the use of solvent refined coal for combustion purposes
arise from the fact that this fuel carries a very small amount of the polluting ash into the
combustion process and markedly reduces the sulfur content depending on the degree of
processing. Because of this no investment in stack gas treatment equipment for the pur-
pose of controlling such emissions need be necessary at the site of the combustion unit.
Since the solvent refined coal is available in the normal coal form, namely a brittle solid,
it can be directly substituted for bituminous coal in the feed system to the combustion unit
at no anticipated additional investment at that point, either. Indeed this more compact,
higher heat form of solid fuel is believed to allow a lessened investment in the combustion
chamber itself over that for bituminous coal. The greatly reduced ash content of this fuel
eliminates the need for electrostatic precipitators to treat the stack gas. Hence, for newlyr
designed units expressly constructed to take advantage of the properties of SRC, there
would be a reduced investment over that required fora bituminous coal fired unit.
Chiefly because of this reduced investment feature of plants using SRC, there are
some singular advantages to its use as a pollution control measure, some characteristics
that are shared by no other currently envisioned pollution abatement process for coal.
That this is so can be seen in Figure 29 which gives a control cost comparison for SRC use
and limestone-scrubbing. Here are plotted the control costs as functions of load factor on
hypothetical 200 MW steam-electric units located in the East Central states. The signif-
icance is that although the new power plant combustion units are designed with the ex-
pectation of high load factor use (over 90%) which generally occurs during its first few
years of productive life, during the second decade of life, on the average, the load factors
decrease from the 80% to the 20% level as the use goes from base load to through peak
load to occasional load service. The use of stack treatment pollution abatement processes,
such as the limestone injection processes, severely penalizes this mode of operation and
the cost of electricity produced can escalate many mills/KWH during this period. The
SRC process however does not penalize the shift to lower load factors that occur with age.
In fact, with the units designed and built specifically for SRC, the control cost can actually
decrease by virtue of the smaller financial encumbrance due to the smaller combustion unit
investment than in current power plant construction.
Since the average load factor currently experienced in power plants in the U.S. is
about 55%, the direct substitution of SRC for bituminous coal in existing units, rather than
installation of further stack gas treatmentswould have probable economic advantage,
again see Figure 29. Thus the line of reasoning based on estimates using base load con-
ditions is not strictly applicable to the nation-wide situation and can lead to misleading
conclusions of one abatement process versus another.
For the advantages of solvent refined coal to be obtainable, a large-scale industry
to produce it must be established. The economic advantages depend of course on a steady
43
-------
10
9
8
7
6
oo
i 4
§ 3
u
o
U
0
-1
-2
0
SRC-existing units
200 MW Unit Size
SRC Cost: 30<:/MMBtu delivered
Coal Cost: $6.62/ton delivered
Coal Heat Content : 13,880 Btu/lb
4.1% Sulfur in Coal
Limestone Cost: $2. 30/ron del ivered
20
40 60 80
Plant Factor (percent)
Figure 29. Comparison of Costs of Control by SRC and
Limestone-Wet Scrubbing in Electric Utilities
100
44
-------
supply of the fuel at its high volume output price. No single combustion unit or plant can
establish this kind of market and so the economic results implied by this study require wide-
spread use of SRC for it to be economically employed at any one location. This is analogous
to the petroleum refining situation in general, in the sense that the widespread use of re-
fined petroleum products in all applications allows the low price in any single use.
Other effects of significance found in this study are that the costs of control by the
use of SRC respond beneficially to increases in either railroad hauling rate or distance.
Thus, combustion plants unfavored due to location or size of hauling contract can be
benefitted strongly by the use of SRC. Also, apart from benefits on hauling rates indirectly
due to plant size, the cost of control is only slightly affected by plant size. Therefore the
economic benefits of the use of SRC are spread quite uniformly across the combustion units
and are not deleteriously affected in a significant way by the trend toward larger combustion
units in, for example, the power generating utilities.
Among types of combustion units those most strongly benefitted by the construction of
units specifically designed for SRC use are those having the highest fixed charge rate.
This tends to be the industrial users with their generally higher expected rate of return on
capital. To the extent that the trend in cost of money in recent years is definitely upward
the future should hold even more favorable cost of control situations for SRC by virtue of
the reduced investment feature.
The estimated potential market for SRC consists of that fraction of the presently con-
stituted bituminous coal-burning combustion units that can be sold on a price-competitive
basis. Figure 30 shows how large this fraction of the bituminous market is for various costs
of processing the coal to the SRC form. It is quite evident that economical operation of the
SRC processing plants is a key to obtaining large-scale markets. SRC plants centrally
located relative to cheap sources of coal and the large electric power utilities market,
with production capabilities in the order of 12 million tons per year and processing costs
of approximately 10
-------
100 r-
90 -
0)
J3
o
80
jj 70
L.
D
60
8 50
u
D 40
O)
c
5 30
o
t 20
(D
U
0)
Q_
10
0
0
I
I
6 8 10 12 14
SRC Processing Cost (<;/MMBtu)
16
18 20
Figure 30. Estimated Potential Share of Existing Coal-Fired Combustion Unit
Market Available to SRC as Function of Processing Cost
46
-------
REFERENCES
1. Sherwood, Thomas K., "Must We Breathe Sulfur Oxides?", Technology Review, Vol. 72,
No. 3, Jan. 1970, pp. 24-31.
2. Jimeson, R. M., "The Possibilities of Solvent Refined Coal", Thesis, George Washington
University, Feb. 22, 1965.
3. Jimeson, R. M., "Utilizing Solvent Refined Coal in Power Plants", CEP, Vol. 62,
No. 10, Oct. 1966, pp. 53-60.
4. Jimeson, R. M. and Grout, J. M., "Solvent Refined Coal: Its Merits and Market
Potential", Presented at Annual Meeting of American Institute of Mining, Metallurgi->
cal and Petroleum Engineers, Washington, D. C., Feb. 16-20, 1969.
5. Brant, V. L. and Schmid, B. K., "Pilot Plant for De-Ashed Coal Production", CEP,
Vol. 65, No. 12, Dec. 1969, pp. 55-60.
6, "Bituminous Coal Facts", National Coal Association, 1968 Edition.
7. Holcomb, Robert W., "Power Generation: The Next 30 Yeqrs", Science, Vol. 167,
No. 3915, Jan. 9, 1970, pp. 159-160.
8. "Instructions for Estimating Electric Power Costs and Values", Federal Power Com-
mission, Tech. Memo No. 1, Washington, D. C., I960.
9. "Sulfur Oxide Removal From Power Plant Stack Gas-Use of Limestone in Wet-
Scrubbing Process", TVA 1969, Contract No. TV-29233A.
10. Dennis, R. and Bernstein, R. H., "Engineering S tudy of Removal of Sulfur Oxides
from.Stack Gases", Am. Petrol. Inst. Report, August 1968.
11. Cortelypu, C.G., "Commercial Processes for SO2 Removal", CEP, Vol. 65, No. 9,
Sept. 1969, pp. 69-77.
12. "Depreciation Guidelines and Rules", U.S. Treasury Department, Internal Revenue
Service, Publication No. 456, July 1962, revised August 1964.
13. Falkenberry, H, L. and Slack, A. V., "SO2 Removal by limestone Injection", CEP,
Vol. 65, No. 12, Dec. 1969, pp. 61-66.
14. "Sulfur Oxide Removal from Power Plant Stack Gas-Sorption by Limestone or Lime,
Dry Process", TVA 1968, Contract No. TV-29233A.
47
-------
15. Edmisten, Norman G. and Bunyard, Francis L, "A Systematic Procedure for Assess-
ing the Cost of Controlling Particulate Emissions from Industrial Sources", Paper
No. 69-103.
16. "Steam-Electric Plant Construction Cost and Annual Production Expenses", 20th
Annual Supplement 1967, Federal Power Commission, Washington, Nov. 1968.
17. Slack, A. V., "Economic Factors in SC>2 Recovery of Sulfur Oxides from Power
Plant Stack Gas", Paper No. 69-142, 62nd Annual Meeting of the Air Pollution
Control Assoc., N.Y.C., June 22-26, 1969.
18. Jaske, R. T., etal., "A National Estimate of Public and Industrial Heat Rejection
Requirements by Decades Through the Year 2000 A.D.", 67th Nat. Meeting of
AlChE, Atlanta, Feb. 17, 1970, Paper No. 37A.
19. Zimmerman, O. T. and Lavine, Irvin, "Energy and Energy Conversion", Cost
Engineering, Oct. 1962, pp. 8-19.
20. "Industry Wage Survey, Electric and Gas Utilities, Oct-Nov. 1967", Bulletin No.
1614, U.S. Dept. of Labor, May 1969.
21. "Area Wage Survey", Bulletin No. 1625-60, U.S. Dept. of Labor, Bureau of Labor
Statistics, March 1969.
22. Durham, Edwin, "Steam Generation", Chem. Engineering Costs Quarterly, Vol. 4,
April 1954, pp. 41-63.
23. O'Connor, John R. and Citarella, Joseph F., "An Air Pollution Control Cost Study
of the Steam-Electric Power Generating Industry", Paper No. 69-102, Air Pollution
Control Assoc. Annual Meeting, N.Y.C., June 22-26, 1969.
24. "Hydroelectric Power Evaluation", Federal Power Commission, FPCP-35, March 1968.
25. "Hydroelectric Power Evaluation, Supplement No. 1", Federal Power Commission,
FPCP-38, November 1969.
26. Steam-Electric Plant Factors, National Coal Association, 1968 Edition.
48
-------
APPENDIX A
DETAILED COST ESTIMATES
A-l
-------
Table A-l. Annual Operating Cost Credits for Solvent
Refined Coal Use - 50 MW Equivalent Size*
Operating Cost Credits
Unit Status
Capital
Precipitator Operating
Fly Ash Disposal Cost
Maintenance from Redu
Investment Credits
Electrostatic Precipitator
Fly Ash Disposal System
Reduced Boiler Size
Total
Existing
Cost 4,500
6,200
iced Corrosion 16,500
Investment
($)
143,000
7,500
71,000
221,500
Annual Cost
($)
New,Utility
39,600
7,800
6,200
16,500
New, Industrial
52,800
7,800
6,200
16,500
Total
27,200
70,100
83,300
* Equivalent to 350,000 Ibs/hr of steam
Basis:
99% effective electrostatic precipitator on new units
9500 Btu/KWH
8000 hrs/yr operation at rated
80% boiler efficiency
A-2
-------
Table A-2. Annual Operating Cost Credits for Solvent
Refined Coal Use - 200 MW Equivalent Size*
Investment Credits
Electrostatic Precipitator
Fly Ash Disposal System
Reduced Boiler Size
Total
Investment
($)
440,000
200,000
500,000
1,140,000
Operating Cost Credits
Unit Status
Capital Charges
Precipitator Operating Cost
Fly Ash Disposal Cost
Maintenance from Reduced Corrosion
Total
Existing
17,900
24,000
66,000
107,900
Annual Cost
($)
New, Utility
171,000
31,000
24,000
66,000
292,000
New, Industrial
228,000
31,000
24,000
66,000
349,000
* Equivalent to 1,410,000 Ibs/hr of steam
Basis:
(see preceding table)
A-3
-------
Table A-3. Annual Operating Cost Credits for Solvent
Refined Coal Use - 500 MW Equivalent Size*
Investment Credits
Electrostatic Precipitator
Fly Ash Disposal System
Reduced Boiler Size
Total
Investment
($)
950,000
500,000
1,870,000
3,320,000
Operating Cost Credits
Unit Status
Capital Charges
Precipitator Operating Cost
Fly Ash Disposal Cost
Maintenance from Reduced Corrosion
Total
Existing
43,500
49,500
154,500
247,500
Annual Cost
($)
New, Utility
497,700
75,400
49,500
154,500
777,100
New, Industrial
664,000
75,400
49,500
154,500
943,400
* Equivalent to 3,520,000 Ibs/hr of steam
Basis:
(see first table)
A-4
-------
Table A-4. Annual Operating Cost Credits for Solvent
Refined Coal Use - 1000 MW Equivalent Size*
Investment Credits
Electrostatic Precipitator
Fly Ash Disposal System
Reduced Boiler Size
Total
Investment
($)
1,620,000
1,000,000
5,000,000
7,620,000
Operating Cost Credits
Unit Status
Capital Charges
Precipitator 'Operating Cost
Fly Ash Disposal Cost
Mqintenance from Reduced Corrosion
Existing
66,000
69,000
288,000
Annual Cost
($)
New, Utility
1,143,000
114,600
69,000
288,000
New, Industrial
1,524,000
114,600
69,000
288,000
Total
423,000
1,614,600
1,995,600
* Equivalent to 7,040,000 Ibs/hr of steam
Basis:
(see first table)
A-5
-------
Table A-5. Annual Operating Costs for Limestone - Wet
Scrubbing Power Plant Stack Gas 200 MW
Existing Unit, 2.9% Sulfur in Coal
Total Project Investment
$2,420,000
Direct Costs
Delivered Limestone
Operating Labor and Supervision
Utilities
Water
Electricity
Maintenance (3% of investment)
Analyses
Subtotal Direct Costs
Indirect Costs
Annual Quantity
63, 200 tons
14, 000 man-hours
210,000 M gal
9,280,OOQKWH
2,190 hr
Annual Cost
$/Unit ($)
Capital Charges, 16% of investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of Operating Labqr
Subtotal Indirect Costs
Operating Credits
Precipitator Operating Credit
Thermal Effect of Raw Limestone Injection on
Operating Cost of Power Generation
Maintenance for Corrosion Reduction in Boiler
Subtotal Credits
Total Chargeable Annual Operating Cost
2.10/ton
4.56/hr
0.
7.5,0/hr
gal
132,760
63,800
21,000
35,800
72,600
16,400
342,360
387,200
31,440
6,380
425,020
-17,900
+16,000
-18,000
-19,900
747,480
Basis: 600,000 tons/yr coal
Performance parameters as in Process A, Ref. 9, Table C-7
A-6
-------
Table A-6. Annual Operating Costs for Limestone - Wet
Scrubbing Power Plqnt Stack Gas ^ 200
New Unit, 2.9% Sulfur in Coal
Total Project Investment
$2,340,000
Direct Costs
Delivered Limestone
Operating Labor and Supervision
Utilities
Water
Electricity
Maintenance (3% of investment)
Analyses
Subtotal Direct Costs
Indirect Costs
Annual Quantity
63,200 tons
14,000 man-hours
210,000 M gal
9,280,OOOKWH
2,190hr
Capital Chqrges, 18% of investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of Operating Labor
Subtptal Indirect Costs
Operating Credits
Precipitator Operating Credit
Precipitator Investment Credit (18%)
Thermal Effect of Raw Limestone Injection on
Operating Cost of Power Generation
Maintenance Credit for Reduced Corrosion in Boiler
Total Credits
Total Chargeable Annual Operating Cost
$/Unit
2.10/ton
4.56/hr
0.10/M gal
0.004/KWH
7,50/hr
Annual Cost
($)
132,700
63,800
21,000
35,800
70,200
16,400
339,900
421,200
31,080
6,380
458,660
-31,000
-79,200
*16,000
-18,000
-112,200
686,360
Basis; Performance parameters as in Process A, Ref. 9, Table C-12
A-7
-------
Table A-7. Calculation of Potential Power Plant Market
SRC
Plant
Campbell, Wy.
McKinley,N.M,
Daviess,Ky.
User
State
Montana
Wyoming
Utah
Colorado
N.Dakota
S.Dakota
Nebraska
Minnesota
Nevada
Arizona
N.Mexico
Iowa
Kansas
Missouri
Illinois
Indiana
Kentucky
Tennessee
Alabama
Wisconsin
Michigan
Thousands
of Tons
of Coal
326
2,276
408
2,970
2,411
235
503
4,244
324
343
2,458
2,950
408
6,463
28, 245
19,120
12,990
11,893
14,158
7,899
18,343
Coal
Cost/Ton
FOB
Plant
2.69
3.40
5.42
4.58
2.02
5.29
7.27
6.82
7.62
4.92
2.50
5.80
6.08
4.61
4.92
4.76
3,77
4.47
5.28
7.09
7.46
Btu/lb
6,560
7.824
12,454
10,572
6,861
8,678
12,121
11,216
12,703
10,427
8,873
10,785
12,079
10,756
10,697
11,134
1 1 , 282
11,734
11,893
11,851
12,568
FOB Plant
Coal Cost
(<:/MMBtu)
20.5
21.7
21.7
21.7
14.8
30.5
30.0
30.4
31.7
23.6
14.1
26.9
25.2
21.4
23.0
21.4
16.7
19.1
22.2
30.0
29.7
Average
Miles
300
150
500
400
350
300
400
650
520
250
200
430
640
300
250
200
200
200
400
500
450
Trans-
portation
Cost
(C/MMBtu
7.2
5.4
9.0
8.1
7.6
7.2
8.1
10.0
9.1
6.7
6.2
8.4
9.9
7.2
6.7
6.2
6.2
6.2
8.1
9.0
8.5
Net Cost
of SRC*
) (C/MMBtu)
22.4-32.4
20.6-28.6
24.2-32.2
23.2-31.2
22.8-30.8
22.4-32.4
23.2-31.2
25.2-33.2
26.8-34.8
24.4-32.4
23.9-31.9
22.7-30.7
24.2-32.2
21.5-29.5
21.0-29.0
20.5-28.5
20.5-28.5
20.5-28.5
22.4-30.4
23.3-31.3
22.8-30.8
Capture
Market at
Low 'Cost
Limit?
No
Yes
No
No
No
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
Yes
Yes
No
No
No
Yes
Yes
Capture
Market at
High Cost
Limit?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
* overage existing unit operating credit = 7.2<;/MMBtu,
produced cost of SRC, <;/MMBtu = 22.4-30.4 (Campbell, Wy.)
24.9-32.9 (McKinley, N. M.)
21.5-29.5(Daviess, Ky.)
23.4-31.4 (Lewis, W.Va.)
-------
Toble A-7. Calculation of Potential Power Plant Market (conf.)
SRC User
Plant State
Lewis, W. Va. Vermont
N.Hampshire
N.York
Massachusetts
Rhode Island
Connecticut
Pennsylvania
Ohio
Maryland
Delaware
W. Virginia
Virginia
N.Carol ina
S.. Carolina
Georgia
Florida
N.Jersey
Wash.,D,C.
Thousands
of Tons
of Coal
34
326
13,617
3,156
229
3,457
24,675
28,390
7,137
1,238
11,199
8,146
12,856
3,543
5,776
4,174
5,743
526
Coal
Cost/Ton
FOB
Plant
10.01
9.22
8.49
8.93
9.57
8.13
5.70
5.13
7.66
7,88
4.37
6.92
7.62
7.59
6.91
6.01
8.28
8.92
Btu/lb \
13,772
13,859
13,109
12,725
13,622
12,764
12,266
11,668
13,012
13,217
11,764
12,960
12,614
12,198
11,520
13,150
13,187
12,362
FOB Plant
Cool Cos!
;<;/MMBtu)
36.4
33.3
32.4
35.2
35.1
31.8
23.3
22.1
29.4
29.9
18.6
26.7
30.2
31.1
30.0
22.9
31.4
36.1
Average
Miles
600
600
430
500
500
430
200
150
220
270
100
220
300
400
500
750
320
200
Trans-
portation
Cost
(
-------
APPENDIX B
SUMMARY ALIGNMENT CHARTS
B-l
-------
USE OF NOMOGRAPH FOR SRC
la. For power generating plants:
Enter plant size in column A and thermal efficiency or heat rate in B.
Draw connecting line to C.
Ib. For other combustion units:
Enter plant size in column C.
2. Select combustion plant type and status and the combustion unit capacity
factor. Note that existing units do not require capacity factor entry.
Enter on appropriate D scale.
3. Connect C intercept and D point. Intercept of this line on E is "credits".
4. Enter "credits" E on column F.
5. Enter cost of SRC at plant site in column G and cost of standard coal
at plant site in column H. Draw connecting line to I.
6. Connect I intercept and credit value on column F. The intercept on
column J is the cost of pollution control due to use of SRC in £/MMBtu.
B-2
-------
Power
Unit
Siz
(M\
50-
60-
~7O-
80-
90-
loo-
2OO
300-
400-
5bo-
600-
700-
6Oo-
900-^
looo
1500-
e
V)
F
C Credits T
Combustion
Unit Size
(C/M/i
x- thousands N/TnilhonsN Tp
klbs steam/hrA Btu/hr ) ^
i I^OOO Credits
- B
Powe
Unit
10,000
J
-
700O
ffwt
tfMXJ~~
Thermal 5000
Eff.
(7o) 1
U) -
\
\ao-
30-
AG
*»W
4600-
-25,000 -
-^IkOOQ
3000-
-is,oca
-IO/MO
rweo
b?000-
r\
B \
Heat Rate V
(Btu/KWH)
looo
9oo
600-
700-
600-
.
500-
(C/MMBtu) J)
U New,
~ /2 -n
- II -
/0,ooo 10
-,000 s_:
8000 r_I
TOCO (,
10 j
feooo 5- -i
^
-SDOO 4-i
_^
^
-4000 3 ":
:
-3ooo *-~
-- ;
^- - _j
_^ '
^060 ~~ D .J
Existing
Units
^- » 0
"
0.5-
New' Industrial
Utility .
ipy
T
20-j
f
1 C51
4-40 ^
I *
40-f I
7, "-
J"60 S
T -5
W.o°-
*J-'ao
^
\
\
\
X. :
^\
\.
>v.
-1000
-9OO
-8«0
- 700
ABtu) J
rll
J
-IO Cost of
Control
(
.
20-
Figure B-l . Cost of Pollution Control by the Use of Solvent Refined Coal
f?
-------
USE OF NOMOGRAPH FOR LIMESTONE
INJECTION WITH SCRUBBING
la. For power generating plants:
Enter plant size in column A and thermal efficiency or heat heat in B. Draw
connecting line to C.
Ib. For other combustion units:
Enter plant size in column C.
2. Enter coal sulfur content in column D and extend C intercept through
column E to D value.
Enter plant factor and new or existing status in column F and draw
line from E intercept through it to column G.
3. Enter delivered limestone price in column H and coal sulfur content in
column I.
Connect and extend line to column J.
4. Add together the values of "Costs and Credits" (column G) and "Delivered
Limestone Cost" (column J).
Enter this sum in column K.
5. Enter heat content of coal in column L and connect with point on K;
extend to column M. Read value of cost of control in <£/MMBtu.
B-4
-------
O.S-
G
M
/ Costs and ^ Cost of
f/.O Credits Cosfo Control
_ / .. /. , Control ^/MMRt,.\ J
F
r
Steam- °
Electric Combustion
Unit Size Unit Size
(MW) (MMBtu/hr)
50-|
loo-
200-
300-
Heat \
Rate \
- /Bfu > 200^v
UWH/
B
) OOO-
/
/
/
- / W>°n> ($/M -
I 6T
T* e-
1
r
T3
1
L
I r
/^S- 20-,
/ Co0/t 1-30 .
/C../r 1 -»rt J / 2 .
/io/for' 3°|f-4o
x Vsfc ;
' n aVAo
ij «oj.r«o
x^>~ -, ,
Plant Plant Og.
' Factor Factor fle.
New Unit Existing fl 7
/ (%) (%) ' :
/ 0.6-
F F
; /
0.4-
/
/ 03-
' /
O.ZJ
1-
z-
1
i
0-9-
i- 0.7-
- o^--
OA-
0.3-
/
/ 0.2-
2 -
L
Heat
^\ Content
. of Coal
X(Btu/lb) ? -
/«;o0el(41008
- llfloo-.^tfloc "
11,000- N.
- " /Q OOO
9,000 - - \
--e/ooo^ -
. T-,000-1- ^
6 -
^
r-
e-
9-
10-
|C_
1 o
/
2.0-
Delivered
Limestone
Cost
($/ton
0.4-
0-3 ~
_ 0.2-
a/r-
'
-^sj'«. ;
o.i-
ao»-
0.05-
O.04-
coal)
-\
. j
- ^ Coal
Sulfur
Content H
- (%) Delivered
5\r- Limestone
4-r Cost
-^ ($/ron)
- 3'A 'i
- 2~\ ':
'- ,:: 'V:
0.9 -- \:
o-d~ V
. «-T- - 2 J
0.6 -- :
ar-L :
2.5-
- 3 -
4-
Figure B-2. Cost of Pollution Control by the Use of Limestone-Wet Scrubbing
B-5
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