EPA
TVA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-79-177
August 1979
Tennesee Valley
Authority
Office of Power
Emission Control
Development Projects
Muscle Shoals AL35660
ECDP B-4
Definitive SOX Control
Process Evaluations:
Limestone, Double Alkali,
and Citrate FGD Processes
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine 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
8. "Special" Reports
9. Miscellaneous Reports
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 sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses 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 environ-
mental issues.
EPA 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 Informa-
tion Service, Springfield, Virginia 22161.
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EPA Number
ECDP B-4
DEFINITIVE SO CONTROL PROCESS EVALUATIONS
LIMESTONE, DOUBLE-ALKALI, AND CITRATE FGD PROCESSES
by
S. V. Tomlinson, F. M. Kennedy,
F. A. Sudhoff, and R. L. Torstrick
Tennessee Valley Authority
Office of Power
Emission Control Development Projects
Muscle Shoals, Alabama 35660
Interagency Agreement EPA D9-E721-BI (TV-41967A)
Program Element No. INE-624A
EPA Project Officer: C. J. Chatlynne
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, DC 20460
August 1979
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DISCLAIMER
This report was prepared by the Tennessee Valley Authority and has been
reviewed by the Office of Energy, Minerals, and Industry, U.S. Environmental
Protection Agency, and approved for publication. Approval does not signify
that the contents necessarily reflect the views and policies of the Tennessee
Valley Authority or the U.S. Environmental Protection Agency, nor does mention
of trade names or commercial products constitute endorsement or recommendation
for use.
ii
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ABSTRACT
A detailed comparative technical and economic evaluation of limestone
slurry, generic double alkali, and citrate flue gas desulfurization (FGD)
processes was made assuming proven technology and using representative power
plant, process design, and economic premises. For each process, economic
projections were made for a base case (500 MW, 3.5% sulfur in coal, new unit)
and case variations in power unit size, fuel type, sulfur in fuel, new and
existing power units, waste slurry ponding and filter cake trucking, and sul-
fur dioxide (SC^) removal (1.2 Ib S02 allowable emission per million Btu heat
input vs 90%). Capital investment, annual revenue requirements (7000 hr/yr),
and lifetime revenue requirements over a 30-year declining operating profile
were estimated for the base case and each variation. Investment costs were
projected to mid-1979; annual revenue requirements were calculated in projected
mid-1980 dollars. Effects of variations in raw material costs, energy costs,
maintenance costs, cost of capital, and net sales revenue and operating labor
cost escalation were studied.
Depending on unit size and status, fuel type and sulfur content, solids
disposal method, and overall project scope, the ranges in estimated capital
costs in 1979 dollars are $71 to $127/kW for limestone slurry, $80 to $130/kW
for generic double alkali, and $105 to $194/kW for citrate (recovery process).
The results can be scaled or altered to reflect other site-specific conditions.
iii
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CONTENTS
Abstract .................... . ..........
Figures ............................... vii
Tables ......... ... .................... ix
Abbreviations and Conversion Factors ......... . .......
Acknowledgements ...........................
Economic Evaluation and Comparison
Capital Investment
Results
Discussion of Results
Executive Summary .......................... xvii
Introduction ............................. 1
Process Background and Description .................. 3
Limestone Slurry Process ...................... 3
Generic Double-Alkali Process ................ ... 8
Citrate Process .......................... 12
Design and Economic Premises ..................... 15
Design Premises .......................... 15
Power Plant ........................... 15
FGD System ............................ 21
Economic Premises ......................... 25
Capital Investment ........................ 25
Revenue Requirements ....................... 30
Systems Estimated .......................... 37
Limestone Slurry Process ....... . .............. 37
Major Process Areas ....................... 42
Storage Capacity ......................... 42
Solids Disposal ......................... 43
Generic Double-Alkali Process ................... 52
Major Process Areas ....................... 55
Storage Capacity ......................... 55
Solids Disposal ......................... 55
Citrate Process .......................... gg
Major Process Areas ....................... 35
Storage Capacity ......................... g^
Chloride Purge .......................... g7
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Revenue Requirements 100
Results 100
Discussion of Results 112
Conclusions 129
Capital Investment Conclusions 129
Revenue Requirement Conclusions 130
Process Conclusions 131
References 133
Appendix
A. Total Capital Investment, Average Annual Revenue Requirement,
and Lifetime Revenue Requirement Tables - All Processes and
Case Variations 139
Vi
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FIGURES
Number Page
1 Limestone slurry process. Base case flow diagram 38
2 Limestone slurry process. Mobile-bed scrubber system base
case plan and elevation 39
3 Limestone slurry process. Base case materials handling and
feed preparation system layout 40
4 Limestone slurry process. Base case overall plot plan ... 41
5 Pond construction diagram 51
6 Generic double-alkali process. Base case flow diagram ... 53
7 Generic double-alkali process. Perforated-tray scrubber
system base case plan and elevation 54
8 Generic double-alkali process. Base case materials handling
and feed preparation system layout 57
9 Generic double-alkali process. Base case overall plot plan . 58
10 Citrate process. Base case flow diagram 59
11 Citrate process. Packed-tower scrubber system base case
plan and elevation 70
12 Citrate process. Base case sulfur processing area layout . . 71
13 Citrate process. Base case overall plot plan 72
14 All processes. Effect of power unit size on total capital
investment for new coal-fired units 96
15 All processes. Effect of power unit size on total capital
investment for existing coal-fired units 95
16 All processes. Effect of sulfur content of coal on total
capital investment for new 500-MW units 97
17 All processes. Effect of power unit size on unit invest-
ment cost for new coal-fired units 97
18 All processes. Effect of power unit size on unit invest-
ment cost for existing coal-fired units 98
19 All processes. Effect of sulfur content of coal on unit
investment cost for new 500-MW units 98
20 All processes. Effect of power unit size on annual revenue
requirements for new coal-fired units 113
21 All processes. Effect of power unit size on annual revenue
requirements for existing coal-fired units 113
22 All processes. Effect of sulfur content of coal on annual
revenue requirements for new 500-MW units 114
23 Limestone slurry process. Effect of power unit size and
variations in limestone price on annual revenue requirements
for new coal-fired units 114
vii
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FIGURES (continued)
Number Page
24 Limestone slurry process. Effect of sulfur in coal and
variations in limestone price on annual revenue require-
ments for new 500-MW units 115
25 Generic double-alkali process. Effect of power unit size
and variations in total raw materials cost on annual revenue
requirements for new coal-fired units 115
26 Citrate process. Effect of power unit size and variations
in total raw materials cost on annual revenue requirements
for new coal-fired units 116
27 Generic double-alkali process. Effect of sulfur in coal and
variations in operating labor cost on annual revenue require-
ments for new 500-MW units 116
28 Citrate process. Effect of power unit size and variations
in operating labor cost on annual revenue requirements for
new coal-fired units 117
29 Citrate process. Effect of power unit size and variations
in energy cost on annual revenue requirements for new coal-
fired units 117
30 Citrate process. Effect of sulfur in coal and variations in
energy cost on annual revenue requirements for new 500-MW
units 118
31 Limestone slurry process. Effect of power unit size and
variations in maintenance cost on annual revenue require-
ments for new coal-fired units 118
32 Limestone slurry process. Effect of sulfur in coal and
variations in maintenance cost on annual revenue require-
ments for new 500-MW units 119
33 Generic double-alkali process. Effect of power unit size
and variations in capital charges on annual revenue
requirements for new coal-fired units 119
34 Generic double-alkali process. Effect of sulfur in coal
and variations in capital charges on annual revenue
requirements for new 500-MW units 120
35 Citrate process. Effect of power unit size and variations
in sulfur price on total annual income from byproduct sales
for new coal-fired units 120
36 Citrate process. Effect of power unit size and variations
in sulfur price on annual revenue requirements for new coal-
fired units 121
37 All processes. Effect of power unit size on levelized unit
revenue requirements for new coal-fired units 121
38 All processes. Effect of power unit size on levelized unit
revenue requirements for existing coal-fired units 128
39 All processes. Effect of sulfur in coal on levelized unit
revenue requirements for new 500-MW units 128
viii
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TABLES
Number Page
S-l Summary of Total Capital Investment Requirements xx
S-2 Summary of Average Annual Revenue Requirements (Including
Byproduct Credit) xxi
S-3 Summary of Levelized Operating Cost of FGD Over Power Unit
Lifetime (Including Byproduct Credit) xxii
S-4 Limestone Slurry Process - Additional Investment Required
for Modified Project Scope xxiii
1 Commercial, Operational Limestone FGD Systems at U.S.
Electric Power Stations (December 1977) 6
2 Commercial, Double-Alkali FGD Systems Under Construction
at U.S. Electric Power Stations 10
3 Coal Compositions and Flow Rates at Varying Sulfur Levels . 16
4 Fuel Alternative Case Oil Composition and Flow Rate .... 16
5 Assumed Power Plant Capacity Schedule 18
6 Power Unit Input Heat Requirements 18
7 Estimated Flue Gas Compositions for Power Units Without
Emission Control Facilities 19
8 Power Plant Flue Gas and S02 Rates 20
9 Current EPA Emission Standards for New Steam Generating
Facilities 21
10 Required Removal Efficiencies 21
11 Assumed Operating Conditions for Scrubbing Systems Applied
to New Coal-Fired Power Units 23
12 Cost Indexes and Projections 27
13 Project Expenditure Schedule 29
14 Relative Quantities of Gas and Sulfur To Be Processed in
Comparison With the Base Case Quantities 31
15 Projected 1980 Unit Costs for Raw Materials, Labor, and
Utilities 32
16 Estimated Overall Annual Maintenance Costs 33
17 Annual Capital Charges for Power Industry Financing .... 34
18 Limestone Slurry Process - Material Balance - Base Case . . 44
19 Limestone Slurry Process - Base Case Equipment List
Description and Cost 46
20 Limestone Slurry Process - Acreage Required for Waste
Solids Disposal 52
21 Generic Double-Alkali Process - Material Balance - Base
Case 59
22 Generic Double-Alkali Process - Base Case Equipment LJst
Description and Cost 61
ix
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TABLES (continued)
Number
23 Generic Double-Alkali Process Acreage Required for Waste
Solids Disposal 67
24 Citrate Process - Material Balance - Base Case 73
25 Citrate Process - Base Case Equipment List Description
and Cost 76
26 Limestone Slurry Process - Total Capital Investment Summary . 89
27 Generic Double-Alkali Process - Total Capital Investment
Summary 90
28 Citrate Process - Total Capital Investment Summary 91
29 Limestone Slurry Process Base Case - Direct Investment -
Process Equipment and Installation Costs 92
30 Generic Double-Alkali Process Base Case - Direct Investment -
Process Equipment and Installation Costs 93
31 Citrate Process Base Case - Direct Investment - Process
Equipment and Installation Costs 94
32 Comparison of Investment Requirements for Solids Disposal
Alternatives 95
33 Comparison of Investment Requirements for Different S02
Removal Levels 99
34 Limestone Slurry Process - Additional Investment Required
for Modified Project Scope 101
35 Limestone Slurry Process - Annual Revenue Requirements
Summary 102
36 Generic Double-Alkali Process - Annual Revenue Requirements
Summary 103
37 Citrate Process - Annual Revenue Requirements Summary .... 104
38 Limestone Slurry Process Base Case - Annual Revenue Require-
ments Direct Costs 105
39 Generic Double-Alkali Process Base Case - Annual Revenue
Requirements Direct Costs 106
40 Citrate Process Base Case - Annual Revenue Requirements
Direct Costs 107
41 Limestone Slurry Process - Actual and Discounted Cumulative
Total and Unit Increase (Decrease) in Cost of Power Over the
Life of the Power Unit 109
42 Generic Double-Alkali Process - Actual and Discounted Cumu-
lative Total and Unit Increase (Decrease) in Cost of Power
Over the Life of the Power Unit 110
43 Citrate Process - Actual and Discounted Cumulative Total and
Unit Increase (Decrease) in Cost of Power Over the Life of
the Power Unit Ill
44 Sensitivity Variations Studied in the Economic Cost Projec-
tions 122
45 Comparison of Average Annual Revenue Requirements for Solids
Disposal Alternatives 123
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TABLES (continued)
Number
46 Comparison of Average Annual Revenue Requirements for
Different S02 Removal Levels 123
47 Major Operating Cost Components Included in the Base Case
Annual Revenue Requirements 124
48 Citrate Process - Lifetime Sulfur Production and Credit . . . 126
49 Comparison of Cumulative Lifetime Discounted Process Cost
for Solids Disposal Alternatives 127
50 Comparison of Cumulative Lifetime Discounted Process Costs
for Different SC>2 Removal Levels 127
XI
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ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
ac
acre kWh
aft-Vmin actual cubic feet per Ib
minute L/G
bbl barrel
Btu British thermal unit
°F degrees Fahrenheit
dia diameter M
FGD flue gas desulfurization mi
ft feet mo
square feet MW
cubic feet ppm
gal gallon psig
gpm gallons per minute rpm
gr grain sec
hp horsepower sft-Vtnin
hr hour
in. inch SS
k thousand yr
kW kilowatt
kilowatt-hour
pound
liquid-to-gas ratio in gallons
per thousand actual cubic
feet of gas at outlet condi-
tions
million
mile
month
megawatt
parts per million
pounds per square inch (gauge)
revolutions per minute
second
standard cubic feet per
minute (60°F)
stainless steel
year
xii
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CONVERSION FACTORS
EPA policy is to express all measurements in Agency documents in metric units. Values in this
report are given in British units for the convenience of engineers and other scientists accustomed
to using the British systems. The following conversion factors may be used to provide metric equiva-
lents.
British
Metric
ac acre 0.405
bbl barrels of oila 158.97
Btu British thermal unit 0.252
°F degrees Fahrenheit minus 32 0.5556
ft feet 30.48
ft2 square feet 0.0929
ft3 cubic feet 0.02832
ft/min feet per minute 0.508
ft3/min cubic feet per minute 0.000472
gal gallons (U.S.) 3.785
gpm gallons per minute 0.06308
gr grains 0.0648
gr/ft3 grains per cubic foot 2.288
hp horsepower 0.746
in. inches 2.54
Ib pounds 0.4536
lb/ft3 pounds per cubic foot 16.02
Ib/hr pounds per hour 0.126
psi pounds per square inch 6895
mi miles 1609
rpm revolutions per minute 0.1047
sft3/min standard cubic feet per 1.6077
minute (60°F)
ton tons (short)b 0.9072
ton, long tons (long)^ 1.016
ton/hr tons per hour 0.252
hectare ha
liters £
kilocalories kcal
degrees Celsius °C
centimeters cm
square meters m^
cubic meters m3
centimeters per second cm/sec
cubic meters per second m3/sec
liters £
liters per second £/sec
grams g
grams per cubic meter g/m3
kilowatts kW
centimeters cm
kilograms kg
kilograms per cubic meter kg/m3
grams per second g/sec
Pascals (Newton per square meter) pa (N/m2)
meters m
radians per second rad/sec
normal cubic meters per Nm3/hr
hour (0°C)
metric tons tonne
metric tons tonne
kilograms per second kg/sec
a. Forty-two U.S. gallons per barrel of oil.
b. All tons, including tons of sulfur, are expressed in short tons in this report.
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ACKNOWLEDGEMENTS
Project supervision, process investigation, design, cost estimating,
economics, and report preparation were performed by Emission Control Develop-
ment Projects personnel of TVA Office of Power, Muscle Shoals, Alabama.
Background information on power plant design, operation, and economics, and
air and water pollution considerations were provided by several TVA organi-
zations involved in related activities. Key aspects of the report were
coordinated with TVA Energy Research staff in Chattanooga, Tennessee.
In addition to referenced material, several organizations have supplied
technical and economic information for use in the study. The data furnished
by these companies are gratefully acknowledged.
C and I/Girdler, Inc.
P.O. Box 174
1721 South Seventh Street
Louisville, Kentucky 40201
Chapman and Associates, Inc.
3505 Brainerd Road
Chattanooga, Tennessee 37411
Combustion Equipment Associates
555 Madison Avenue
New York, New York 10022
Koppers Company, Inc.
Engineering and Construction Division
1120 Koppers Building
Pittsburgh, Pennsylvania 15219
Garden City Fan and Blower Company
Langley Systems
Birmingham, Alabama 35216
Morrison-Knudsen Company, Inc.
Energy Systems and Services Division
P.O. Box 7808
Boise, Idaho 83729
xiv
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Norton Company
Chemical Process Products Division
Department TR-2
P.O. Box 350
Akron, Ohio 44309
Pfizer, Inc.
Chemicals Division
235 East 42nd Street
New York, New York 10017
Sherritt Gordon Mines, Ltd.
Fort Saskatchewan, Alberta, Canada
Home Oil Company, Ltd.
Calgary, Alberta, Canada T2P OR4
U.S. Bureau of Mines
Salt Lake City Metallurgy Research Center
1600 East First South Street
Salt Lake City, Utah 84112
Universal Oil Products
Air Correction Division
Darien, Connecticut 06820
Zurn Industries, Inc.
Air Systems Division
275 1st Street North
Birmingham, Alabama 35201
xv
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DEFINITIVE SOX CONTROL PROCESS EVALUATIONS - PHASE I
EXECUTIVE SUMMARY
Under the provisions of the Clean Air Act of 1967 and its subsequent
amendments, the U.S. Environmental Protection Agency (EPA) has funded research
and development on sulfur dioxide (S02) removal processes, including the pub-
lication of several conceptual design and cost studies. This report is one
of a series of flue gas desulfurization (FGD) studies sponsored by EPA to
determine comparative costs of some of the more prominent S02 removal systems
now being offered by vendors. Three processes are evaluated in this report—
limestone slurry, generic double alkali, and citrate scrubbing. Process
evaluations in subsequent studies will include lime scrubbing, magnesia
scrubbing, the Wellman-Lord sodium sulfite process, and the Rockwell Inter-
national aqueous carbonate process.
PROCESS DEFINITION
A brief description of the three processes in this study and the data
sources used as the basis are given below. The process data represent the
state of technology in late 1977.
Representative flow diagrams, material balances, plant layouts, and
equipment arrangements are included in the report for the base case (new
500-MW coal-fired unit, 3.5% sulfur in fuel, 1.2 Ib S02 emission per million
Btu heat input) of each process. These and detailed equipment descriptions
define the systems estimated.
Limestone Slurry Process
Stack gas is scrubbed with a recirculating slurry of limestone and
reacted calcium salts in water (pH about 5.8) using a presaturator unit
for cooling and humidification and a mobile-bed scrubber for S02 removal.
Limestone feed is wet-ground prior to addition to the scrubber effluent
hold tank. Calcium sulfite and sulfate salts are withdrawn to a disposal
pond where they settle to a 40% solids sludge. Cleaned stack gas is reheated
to 175°F. Design is based on data taken from the TVA-EPA-Bechtel Shawnee
test program and TVA Widows Creek unit 8.
xvii
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Generic Double-Alkali Process
Stack gas is cooled and humidified in a presaturator using recycled
scrubber effluent and scrubbed in a perforated-plate scrubber with regenerated
sodium sulfite(pH about 6.0). A bleedstream of scrubber effluent is reacted
with lime to regenerate sodium sulfite and produce calcium sulfite and sul-
fate salts. After filtering and washing to recover the sodium sulfite solu-
tion, the calcium sulfite-sulfate cake is reslurried and pumped to the dis-
posal pond where the salts settle to 40% solids. Makeup soda ash is added
at the thickener overflow tank. Cleaned stack gas is reheated to 175°F.
The double-alkali design is generalized from several processes currently
offered in the United States.
Citrate Process
Stack gas is cooled and humidified in a presaturator using recycled
liquor and scrubbed in a packed-tower scrubber with regenerated citrate
solution (pH about 4.5). A bleedstream of presaturator recycle liquor is
neutralized with lime and discarded to control chlorides in the system.
Scrubber effluent is reacted with hydrogen sulfide (H2S) to produce elemental
sulfur and regenerate the citrate scrubbing solution. Sulfur is separated
by air flotation, melted, and stored in liquid form to be sold. Part of the
sulfur is combined with natural gas and steam to form l^S for use in the
reduction process. Makeup soda ash and citric acid are added to replace
losses due to handling and oxidation of sulfite to sulfate. Sodium sulfate
crystals are purged from the system and discarded. Cleaned stack gas is
reheated to 175°F. Conceptual design for the generalized citrate process
is based primarily on the U.S. Bureau of Mines system. Design differences
in the Bureau of Mines demonstration unit have been noted.
MAJOR DESIGN AND COST FACTORS
The base case for evaluating the three processes is a new, 500-MW,
coal-fired power unit located in the Midwest (Illinois, Indiana, Kentucky
area). The project schedule begins in mid-1977 with a 3-year construction
period ending mid-1980. The midpoint of construction costs is mid-1979;
revenue requirements are estimated in mid-1980 dollars.
Other important design and cost assumptions used in the evaluations are;
• The coal has a heating value of 10,500 Btu/lb and contains 16% ash.
• S02 removal reduces emissions to 1.2 Ib S02 per million Btu heat input.
• Stack gas is reheated to 175°F.
• Both ponding and trucking disposal at a site 1 mile from the FGD
facilities are evaluated for the limestone and double-alkali processes.
Thirty-day storage and a base^value of $40 per short ton for sulfur
have been used for the citrate process.
xviii
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The use of a fully developed design is assumed. No redundancy is
included; only spare pumps are included. A second pond transport
line is included in disposal cases. An orderly and well-managed
design and construction program is assumed.
Revenue requirements are estimated on 7,000-hour annual operation.
RESULTS
Summaries of capital investment, annual revenue requirements, and life-
time operating costs for all cases estimated are displayed in Tables S-l,
S-2, and S-3, respectively.
Capital Investment
In order of increasing investment, the base case process ranking is
(1) limestone slurry, (2) generic double alkali, and (3) citrate.
Except for the waste-disposal-by-trucking cases, limestone has the
lowest capital investment and citrate has the highest for each variation.
The limestone trucking alternative capital investment is 2.4% higher than
the double-alkali case because limestone FGD produces more waste solids and
requires a larger investment in the feed preparation area.
Capital investment for the existing power unit variation is greater
than the new power unit variation at each plant size with the exception of
the limestone 200-MW cases. For the existing limestone 200-MW unit the
decrease in cost due to decrease in pond size based on a remaining life of
20 years slightly outweighs the increase in labor charges required for
retrofit.
SC>2 removal of 90% compared with S02 removal equal to 1.2 Ib S02
emission per million Btu heat input increases base case capital investment
by 3.5% to 4.2%.
Base case projections described here represent a proven FGD system
designed with no redundancy and operating at minimum required removal capac-
ity on flue gas from 3.5% sulfur coal. As an indication of how the project
scope and corresponding investment could vary, the effects of changes in
process design and indirect charges on the limestone base case estimate are
shown in Table S-4. Changes such as 50% redundancy, 90% SC>2 removal, 6%
sulfur in coal, increased stoichiometry, greater entrainment in the cleaned
gas, and a larger contingency charge can double the investment requirement
for the limestone slurry process. Similar effects on investment needs can
be expected in the double-alkali and citrate processes with changes in
project scope.
xix
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TABLE S-l. SUMMARY OF TOTAL CAPITAL INVESTMENT REQUIREMENTS
a,b
Limestone process
Case
Years
remaining
life
Total capital
investment ,
$
$/kW
Generic double-
alkali process
Total capital
investment,
$ $/kW
Citrate process
Total capital
investment ,
$
$/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E
200 MW N
3.5% sulfur
3.5% sulfur
500 MW E 3.5% sulfur
500 MW N 2.0% sulfur
500 MW N 3.5% sulfur
500 MW N 5.0% sulfur
1,000 MW E 3.5% sulfur
1,000 MW N 3.5% sulfur
Solids disposal by trucking
500 MW N 3.5% sulfur
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur
20
30
25
30
30
30
25
30
30
30
25,057,000
25,461,000
50,120,000
39,641,000
125.3
127.3
100.2
79.3
26,006,000
25,477,000
53,675,000
42,110,000
130.0
127.4
107.4
84.2
38,788,000
38,075,000
72,605,000
58,098,000
193.9
190.9
145.2
116.2
48,728,000
54,621,000
74,830,000
71,423,000
42,307,000
97.5
109.2
74.8
71.4
50,551,000 101.1 71,639,000 143.3
57,579,000
85,487,000
79,016,000
84.6 41,335,000
115.2
85.5
79.0
82.7
82,572,000
109,024,000
106,589,000
165.1
109.0
106.6
50,437,000 100.9 52,404,000 104.8 74,624,000 149.2
Oil-Fired Power Unit
0.8 Ib SC>2/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur
25
38,480,000
77.0 40,260,000
80.5 52,442,000 104.9
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979. Minimum in-process storage; only pumps are spared. Disposal area located
1 mile from power plant. Investment requirements for fly ash removal and disposal excluded. Con-
struction labor shortages with accompanying overtime pay incentive not considered.
These investment costs are characterized by the defined premises and assumptions. Modifying the
project scope of the limestone process as shown in Table S-4 can increase system costs by $96/kW
or more depending on the assumptions made.
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X
X
H-
TABLE S-2. SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS
(INCLUDING BYPRODUCT CREDIT)
Years
remaining
Case life
Limestone process
Average annual
revenue
requirements ,
$ Mills/kWh
Generic double-
alkali process
Average annual
revenue
requirements ,
S Mills/kWh
Citrate process
Average annual
revenue
requirements ,
$ Mills/kWh
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20
200 MW N 3.5% sulfur 30
500 MW E 3.5% sulfur 25
500 MW N 2.0% sulfur 30
500 MW N 3.5% sulfur 30
500 MW N 5.0% sulfur 30
1,000 MW E 3.5% sulfur 25
1,000 MW N 3.5% sulfur 30
Solids disposal by trucking
500 MW N 3.5% sulfur 30
90% SC>2 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30
7,479,400
7,153,200
14,789,400
11,624,900
14,101,900
16,032,200
23,241,200
21,874,300
15,172,400
14,651,300
5.34
5. 11
4.23
3.32
4.03
4.58
3.32
3.12
4.33
4. 19
7,553,000
7,169,100
15,441,700
11,335,300
14,676,000
17,741,900
25,750,900
24,147,700
14,293,900
15,438,800
5.40
5.12
4.41
3.24
4.19
5.07
3.68
3.45
4.08
4.41
12,289,200
11,670,800
23,174,000
17,091,700
22,538,000
27,513,400
36,933,500
35,602,400
23,812,400
8.78
8.34
6.62
4.88
6.44
86
28
5.09
6.80
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur
25
11,446,600
3.27
11,128,400
3.18
16,091,700
4.60
Power unit on-stream time, 7,000 hr/yr. Midwest plant location, 1980 revenue requirements. Investment and revenue
requirement for removal and disposal of fly ash excluded.
These revenue requirements are based on the defined premises and assumptions and the capital investments shown in
Table S-l. They would vary as project scope changed; for example, with additions to the scope outlined in Table S-4,
annual revenue requirements for limestone could increase to 9.37 mills/kWh for a new, 500-MW unit burning 3.5% sulfur.
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TABLE S-3. SUMMARY OF LEVELIZED OPERATING COST OF FGD
OVER POWER UNIT LIFETIME (INCLUDING BYPRODUCT CREDIT)3
H-
H-
Years
remaining
Case life
Limestone process
Cumulative present Levelized increase
worth net increase (decrease) in unit
(decrease) in cost operating cost,
of power. b $ mills/kWhc
Generic double-alkali process
Cumulative present Levelized increase
worth net increase (decrease) in unit
(decrease) in cost operating cost,
of power ,b $ mills/kWhc
Citrate process
Cumulative present Levelized increase
worth net increase (decrease) in unit
(decrease) in cost operating cost,
of power, b $ mills/kWhc
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat Input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.57. sulfur 20
200 MW N 3.57. sulfur 30
500 MW E 3.57. sulfur 25
500 MW N 2.07. sulfur 30
500 MW N 3.5% sulfur 30
500 MW N 5.07. sulfur 30
1,000 MW E 3.57. sulfur 25
1,000 MW N 3.57. sulfur 30
Solids disposal by trucking
500 MW N 3.57. sulfur 30
907. SC>2 removal; onsite
solids disposal (ponding)
500 MW N 3.57. sulfur 30
52,811,700
65,253,700
122,034,600
104,931,000
127,709,200
144,837,500
188,891,100
195,672,000
132,750,600
132,602,400
9.28
6.56
5.82
4.22
5.14
5.83
4.51
3.94
5.34
5.34
53,388,600
65,224,800
127,562,500
103,925,200
132,472,900
158,278,400
209,774,100
215,525,300
125,275,900
138,947,500
9.39
6.56
6.09
4.18
5.33
6.37
5.00
4.34
5.04
5.59
84,862,500
104,508,300
187,099,800
153,984,800
200,363,000
241,941,500
293,113,800
312,517,300
211,103,800
14.92
10.51
8.93
6.20
9.74
6.99
6.29
8.50
Oil-Flred Power Unit
0.8 Ib SC>2/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.57. sulfur
25
94,271,900
4.50
93,023,600
4.44
131,410,200
6.27
a. Basis
Power unit operating profile for 30-year life = 7,000 hours - 10 years, 5,000 hours - 5 years, 3,500 hours - 5 years, 1,500 hours - 10 years.
Midwest plant location, 1980 operating costs.
Investment and revenue requirements for removal and disposal of fly ash excluded.
Constant labor cost assumed over life of project.
b. Discounted at 10% to initial year.
c. Equivalent to discounted process revenue requirement over life of power unit.
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TABLE S-4. LIMESTONE SLURRY PROCESS
ADDITIONAL INVESTMENT REQUIRED FOR MODIFIED PROJECT SCOPE
Investment
required, $/kW
Base case - limestone slurry process: 500-MW new unit
burning coal containing 3.5% sulfur, 16% ash, 10,500 Btu/lb
heat value; 1.2 Ib S02 allowable emission per MBtu heat
input; 0.1% liquid entrainment in cleaned stack gas;
30-yr life, 127,500-hr operation; no redundancy; 20%
contingency; onsite solids disposal; mid-1979 cost basis 97.5
Additional
investment
required, $/kW
Modified case: 500-MW new unit burning coal containing
6% sulfur, 16% ash, 10,500 Btu/lb heat value; 90% S02
removal; 0.3% liquid entrainment in cleaned stack gas;
30-yr life, 127,500-hr operation; 50% redundancy; on-
site solids disposal, mid-1979 cost basis
Investment increases due to:
Increased raw material handling 18.3
Larger waste disposal area and pond 46.9
50% redundancy of ball mills, scrubbers, and other
equipment 30.8
Total increase in capital investment 96.0
xxiii
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Annual Revenue Requirements
For base case conditions the ranking of average annual revenue require-
ments for the processes is the same as the investment ranking: (1) limestone
slurry, (2) generic double alkali, and (3) citrate.
Capital charges are the largest component of revenue requirements for
all processes. Electrical demand is significantly greater for the limestone
and citrate processes than for the double-alkali process. Raw materials
cost is 19% and 22% of the total revenue requirements for base case citrate
and double alkali, respectively, while raw material cost for limestone is
only 8% of the total. For all case variations estimated in this study,
projected 1980 FGD revenue requirements range from 3.25 to 8.78 mills/kWh.
Lifetime Revenue Requirements
The relative rankings in levelized lifetime revenue requirements are
similar to those projected for annual requirements. Lifetime levelized
revenue requirements are slightly higher than corresponding average annual
revenue requirements because of the declining operating profile of the
power unit. The average on-stream time over the life of the plant is
4,250 hr/yr, compared to the higher on-stream time of 7,000 hr/yr used for
the annual revenue requirement estimates.
CONCLUSIONS
Because ponding costs for the limestone process offset the additional
equipment needs of the double-alkali process, capital investment require-
ments are quite similar for the two processes. The capital investment for
the citrate process is considerably higher; however, it should be recognized
that citrate is a recovery process and should also be compared with other
recovery processes.
The limestone or lime slurry process is the best known and most
completely developed FGD system in the United States today. The evaluation
of limestone FGD in this study, reflecting the broad experience of vendors
and utilities in constructing and operating this system, is based on consid-
erable available data. Limestone is still the simplest and cheapest FGD
process available today for most applications, but it continues to require
intensive maintenance effort, and it produces a waste sludge of questionable
stability and environmental effect.
Although construction and operating experience is not as extensive
for the double-alkali process as for limestone, unit areas in the double-
alkali process can be compared either with limestone or with other chemical
operations for an understanding of design and operation. Double-alkali
FGD is a competitive alternative to limestone, especially when trucking
is used to dispose of the waste filter cake. Even though double alkali
is a waste-producing process, the system produces less waste solids than
xx iv
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limestone, requiring a smaller area for disposal, and it regenerates the
process scrubbing liquor. Because of system design, it is expected to
require less maintenance than limestone.
As a recovery system, the citrate process is inherently more expensive
and should not be compared only with the waste-producing processes evaluated
here but also with other recovery processes. For this study the citrate
process is assumed proven, but less is known about the unit areas of the
process as an integrated operating system than is known about the limestone
or double-alkali processes, and the operation of many of these areas is
more complex. Although the citrate process offers the advantage of producing
a salable byproduct, the use of natural gas in the reduction step could limit
its application. It is important that the citrate process be proven in the
field in order to more fully answer the questions of real cost and opera-
bility.
xxv
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INTRODUCTION
Coal-fired power plants are a major source of the sulfur dioxide (862)
emitted to the atmosphere in the United States. By the end of 1976, 54% of
the electricity generated in the United States was being produced from coal-
fired power plants according to Electrical World (1977c). The Federal Energy
Administration (FEA) predicts that by 1985 this figure will increase to 70%
of the total electrical energy produced (Electrical World, 1977b). Critical
attention is focused on the electrical power utility industry as it searches
for reliable emission control methods that will meet the air quality regula-
tions.
Possible S02 control alternatives to flue gas desulfurization (FGD) do
exist. However, recent court decisions have denied the use of tall stacks
and reduced production during periods of weather stagnation as control
methods. Projected shortages of natural gas and fuel oils force a growing
dependence on coal, but low-sulfur coal is not found in sufficient quantity
in regions of greatest electrical demand. While the concept of coal desul-
furization prior to combustion is under study, its development has not yet
reached the commercial status of FGD.
Although scattered attempts at power plant S02 control were pursued in
Europe as early as the 1930's clean air legislation in the United States
made S02 control a necessity in this country in the 1960's. At this time
government-sponsored research and development (R&D) began to focus attention
on FGD and it became increasingly important to be able to evaluate the
systems technically and economically from a standard basis of comparison.
In 1967 the National Center for Air Pollution Control (now part of the U.S.
Environmental Protection Agency—EPA) contracted with the Tennessee Valley*
Authority (TVA) for a series of conceptual design and economic studies to be
carried out by TVA on FGD processes. The first studies evaluated four proces
• Dry process limestone injection (TVA, 1968)
• Limestone wet scrubbing (TVA, 1969)
• Ammonia scrubbing (TVA, 1970)
• Magnesia scrubbing (McGlamery, et al., 1973)
The earliest S02 removal systems were limestone or lime processes and
much of the R&D through the late 1960's and early 1970's focused on limestone
and lime as absorbents. A previous TVA-EPA publication (McGlamery, et al.,
1975) included evaluations of limestone slurry and lime slurry scrubbing.
Most FGD systems operating today at power unit sites are limestone or lime,
representing over 90% of the 13,000 MW of removal capacity (commercial and
demonstration) currently employed at U.S. power plants by 1978 (Laseke, et
al., 1978).
-------
Although limestone and lime processes are considered the least expensive
methods of FGD at this time, the processes have several disadvantages:
(1) they require intensive maintenance, (2) they are once-through processes,
i.e., the scrubbing slurry is not regenerated for reuse, and (3) the SC>2 is
removed in the form of a waste sludge. Continuing R&D has developed processes
that minimize or eliminate one or more of these problems.
Two of the three processes selected for evaluation in this study offer
possible solutions to the disadvantages mentioned. The generic double-alkali
process, representing several of the double-alkali processes now available
in the United States, reduces maintenance requirements by introducing lime
as a second alkali outside the scrubbing loop, thereby reducing the potential
for calcium scaling. Although the system produces a waste sludge that is
principally calcium sulfite, it does regenerate the sodium scrubbing liquor
for recycle. The citrate process, based on the U.S. Bureau of Mines FGD
system, also regenerates and recycles its scrubbing liquor. In addition,
the process reduces the removed S(>2 to elemental sulfur, an important chemi-
cal feedstock.
TVA-EPA studies now in preparation will evaluate processes producing
salable sulfur compounds on a comparative basis.
-------
PROCESS BACKGROUND AND DESCRIPTION
Full-scale scrubbing of power plant flue gas was first undertaken at
the Battersea power station in London, England, in the early 1930's. This
and the scrubbing systems at English power stations that followed in the
decade of the 1930's posed many chemical and design questions. Investigators
such as G. W. Hewson, et al. (1933), J. L. Pearson, et al. (1935), and
R. L. Rees (1953) in England and H. F. Johnstone, et al. (1938) in the United
States studied these and other factors pertaining to S02; much of their
research is still applicable today and forms the basis for current R&D. The
most concentrated R&D effort in the United States toward improved FGD has
occurred in the past 15 years, especially since the passage of the clean air-
legislation in 1967 and 1970. A useful summary of regulations proposed
through mid-1976 has been prepared by Chaput (1976).
For a better understanding of the specific processes evaluated in this
study, the development of each is given including present status, process
characteristics, and chemistry.
LIMESTONE SLURRY PROCESS
Limestone and lime absorption systems are the most widely used tech-
nology in the United States today for S02 removal from fossil-fueled power
plant flue gas. About 90% of the equivalent megawatts for which removal
systems are in use, under construction, or planned is limestone or lime
absorption (Kennedy and Tomlinson, 1978).
The chemistry of limestone slurry scrubbing can be described by the
following series of reactions from McGlamery, et al. (1975). Equations 1,
2, and 3 are reactions of S02 absorption in an aqueous scrubbing liquor.
S02(g) t S02(aq) (1)
S02(aq) + H2° *• H2S03 + HS03~ + H+ (2)
HS03~ t H+ + S03~ (3)
Simultaneously, limestone dissolves into the scrubbing liquor as shown
in equations 4 and 5.
CaC03(s) J CaC03(aq) (4)
CaC03(aq) ^ Ca""" + C03= (5)
-------
Sulfite ion combines with calcium to yield the very insoluble calcium
sulfite hemihydrate.
Ca*"1" + S03= + 1/2H20 J CaS03-l/2H2C4 (6)
Carbon dioxide, either in the flue gas or from calcium carbonate inter-
acts with water as shown in equations 7 and 8.
C02(g) + H2° *• H2C03(aq) *" H+ + HC03~ (7)
HC03~ ^ H+ + C03= (8)
In addition, sulfite ion may be ultimately converted to gypsum by the
following reactions.
S03= + 1/202 -»• S04= (9)
Ca*"1" + S04= + 2H20 + CaS04-2H204- (10)
Because detailed discussions of process development may be found in
many publications by TVA (TVA, 1970; McGlamery, et al., 1975; Kennedy and
Tomlinson, 1978), only a brief historical description of the limestone
slurry process and some codevelopment of lime slurry will be included here.
The scrubbing process developed by the London Power Company for its
Battersea and Bankside power stations (Hewson, et al. , 1933; Rees, 1953)
used alkaline water from the Thames River to remove dust and S02 from boiler
exhaust gases. The once- through system returned acidic effluent to the Thames
and required very large quantities of water which cooled the gas to low tem-
peratures creating plume problems. To overcome these difficulties, Howden
and Company and Imperial Chemical Industries (Howden - ICI) developed a lime-
scrubbing process which was a first attempt at closed-water-loop operation.
A process pilot plant was constructed in Billingham in 1933 and the process
was used commercially at the Tir John (Swansea) and Fulham (London) power
stations. The Tir John scrubbing system was soon shut down because of opera-
tional difficulties from the high ash content of the coal. Fulham operated
until World War II. The two Battersea scrubbers were closed permanently in
1969 and 1974 because of plume problems and Bankside is now England's only
operational FGD system.
Although Canada and the USSR began S02 removal development in the 1930' s
and 1940 ?s using sorbents other than limestone or lime, very little more was
done with limestone and lime scrubbing during this time. In 1953 TVA began
a brief series of pilot-plant studies of several FGD processes including a
packed-tower scrubber using a 10% slurry of pulverized limestone (Slack, 1971),
Reliance on atmospheric monitoring and tall stack dispersion during this
period reduced TVA's interest in the expansion of these studies.
-------
FGD development intensified in the 1960's. Wisconsin Electric Power and
Universal Oil Products conducted a 1-MW joint program in 1965 (Pollack, et
al., 1967) on a coal-fired 120-MW boiler. Combustion Engineering and Detroit
Edison (Plumley, et al., 1967) collaborated on a 1966-1967 program to study
limestone injection into a boiler. Other U.S. companies—Babcock and Wilcox
Company, Chemical Construction Corporation (Chemico), Research-Cottrell, Inc.,
Zurn Industries, and Peabody Coal Company—also developed limestone scrubbing
data during this decade.
A joint TVA-EPA-Bechtel program began in 1967 at TVA's Shawnee Steam
Plant, Paducah, Kentucky (Bechtel Corporation, 1973). The EPA-funded test
demonstration facility includes three 10-MW scrubbers of different types;
the test program is directed by Bechtel and the facility is operated by TVA.
All phases of limestone and lime scrubbing are being studied, from operating
optimization to equipment reliability. At present two of the scrubbers, a
venturi followed by a spray tower and a Turbulent Contact Absorber (TM) (TCA),
are being operated in an advanced test program which began in June 1974 and
is scheduled to run through December 1979 (Head, 1977; Head, et al., 1978).
The program objectives include demonstrating process and equipment reliability
under varying flue gas conditions, determining the effect of additives on SOo
removal, determining the effectiveness of forced oxidation to produce an
improved waste sludge product, characterizing stack gas emissions, and evalu-
ating methods of automatic control. In August 1978 a program sponsored by
the Electric Power Research Institute (EPRI) was begun to study cocurrent
limestone scrubbing on the third scrubber.
In conjunction with the EPA-sponsored Shawnee test program, Bechtel and
TVA have jointly developed a computer program capable of projecting compara-
tive investment and revenue requirements for limestone and lime scrubbing
(Torstrick, et al., 1978). The computer program has been developed to permit
the estimation of relative economics of limestone and lime scrubbing systems
for variations in process design alternatives or variations in the values of
independent design variables. Although the program is not intended to com-
pute the economics of an individual system to a high degree of accuracy, it
is based on sufficient detail to allow the rapid projection of preliminary
conceptual design and costs for various limestone and lime case variations
on a common design and cost basis.
Currently, 11 commercial-sized limestone units are in operation in the
United States (Table 1). Kansas Power and Light Company's Lawrence installa-
tion was the initial system cited by EPA as evidence of demonstrated tech-
nology. The limestone injection - wet scrubber system has been replaced on
unit 4 with limestone scrubbing in a spray tower. The new system went on-
stream in January 1977. The same type scrubber changes were made on unit 5
and this operation began in mid-1978. The boilers began burning Wyoming
low-sulfur coal (0.5%) in the fall of 1974.
-------
TABLE 1. COMMERCIAL, OPERATIONAL LIMESTONE FGD
SYSTEMS AT U.S. ELECTRIC POWER STATIONS (DECEMBER 1977)
Power plant
Utility
Kansas Power
and Light
Kansas Power
and Light
Kansas City
Power and Light
Arizona Public
Service
Northern States
Power
Northern States
Power
Springfield City
Utilities
Tennessee Valley
Authority
South Carolina
Public Service
Texas Utilities
Company
Indianapolis
Power and Light
Company
Station
Lawrence
Lawrence
La Cygne
Cholla
Sherburne
Sherburne
Southwest
Widows Creek
Winyah
Martin Lake
Petersburg
Unit
No.
4
5
1
1
1
2
1
8
2
1
3
FGD
MW
125
400
820
115
710
680
200
550
140
793
530
startup
12/68
1/77
11/71
6/78
2/73
10/73
3/76
kill
4/77
5/77
7/77
8/77
12/77
FGD installation
New/
retrofit
R
N
N
R
N
N
N
R
N
N
N
Vendor
Combustion Engineering
Combustion Engineering
Babcock and Wilcox
Research-Co ttrell
Combustion Engineering
Combustion Engineering
Universal Oil Products
Tennessee Valley Authority
Babcock and Wilcox
Research-Co ttrell
Universal Oil Products
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La Cygne unit 1 (Kansas City Power and Light) has eight identical
venturi-sieve tray modules for fly ash and S02 removal. The unit burns high-
ash (15% to 25%), high-sulfur (5.3% to 6%) coal which is mined locally. An
intensive development program has been conducted at the site; however, opera-
ting and maintenance problems remain.
Flooded disc scrubbers and packed-tower absorbers were retrofitted to
the 115-MW boiler of Arizona Public Service's Cholla unit 1. The unit burns
0.5% sulfur coal. High on-stream time has been achieved, but extensive
maintenance and operation efforts are required.
Sherburne station boilers Nos. 1 and 2 burn low-sulfur (0.8%) coal.
Each unit has 12 scrubbing modules. Each module operates with a ventri-rod
scrubber followed by a marble-bed absorber. Erosion and spray nozzle pluggin
have caused problems in these units. Northern States Power Company is plan-
ning two additional power units of 860 MW each at Sherburne with limestone
slurry FGD included for each unit.
During startup, the FGD system at Southwest No. 1 (Springfield City
Utilities) experienced mist eliminator scaling and some control problems.
It is anticipated that scrubber system modifications will be made during a
scheduled outage. The unit burns 3.5% sulfur coal.
Coal with 3.7% sulfur content is burned in TVA's Widows Creek Unit 8.
The TVA-designed scrubbing system has four trains, each of which includes
a variable-throat venturi followed by a grid-type absorber. Commercial
scrubber operation began in late 1977.
The scrubbing unit on Winyah No. 2, a part of the South Carolina Public
Service system, began initial operation in July 1977. Fuel for the unit is
a 1% sulfur Virginia coal. Plans are underway to increase the size of the
scrubber which now cleans 50% of the flue gas from unit 2.
Texas lignite with 1% sulfur and 8% ash content is burned in the new
Martin Lake Unit 1 boiler of Texas Utilities Company. Six packed/spray
tower absorbers scrub 75% of the total flue gas with the remainder bypassed
for reheat. Compliance testing began in late 1977.
Indianapolis Power and Light Company has installed TCA limestone
scrubbers at their new Petersburg No. 3 unit. The unit burns 3.5% sulfur
with ash content of 10%. Operation of the four modules began in December
1977.
In addition to the 11 operating limestone units listed, another 17,500
equivalent megawatts of limestone FGD units are under construction or
planned (Laseke, et al., 1978; Kennedy and Tomlinson, 1978).
The process design data and operating conditions used in this study for
the limestone slurry process are based primarily on the latest design and
operating conditions at the TVA Shawnee test facilities and Widows Creek
Unit 8.
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GENERIC DOUBLE-ALKALI PROCESS
As in the limestone slurry system, double-alkali processes dispose of
removed S02 as throwaway calcium sludge. Unlike limestone, however, absorp-
tion of S02 and production of disposable waste are separated—the addition
of limestone or lime occurring outside the scrubber loop. The scrubbing
step utilizes an aqueous solution of soluble alkali. The absorption reaction
depends on gas/liquid chemical equilibrium and mass transfer rates of sulfur
oxides (SOX) from flue gas to scrubbing liquid instead of limestone dissolu-
tion, the limiting factor in limestone scrubbing. Therefore, SOX absorption
efficiency in a double-alkali system is potentially higher than in a lime-
stone system with the same physical dimensions and liquid-to-gas (L/G) flow
rates (Kaplan, 1974). Scaling and plugging in the absorption area are reduced
because calcium slurry is confined to the regeneration and disposal loop and
soluble calcium is minimized in the scrubber liquor. The process has been
described by Kaplan (1976) and LaMantia, et al. (1976, 1977).
Technically, the use of any combination of alkaline compounds, organic
or inorganic, for S02 removal and disposal can be classified as a double-
alkali process. The process chosen for evaluation in this report is a
sodium sulfite absorbent - lime reactant system.
Sodium sulfite in solution absorbs S02 in the scrubbing step represented
by equation 11.
S03= + S02 + H20 -»• HS03~ (11)
Sodium hydroxide formed in the regeneration step and sodium carbonate
added as sodium makeup react with S02 as shown below. The absorption reac-
tions actually involve reaction of 862 with an aqueous base such as sulfite,
hydroxide, or carbonate rather than sodium ion which is present only to
maintain electrical neutrality.
20H~ + S02 -»• S03= + H20 (12)
CO = + S02 ->• S03= + C02 (13)
The use of lime for regeneration allows the system to be operated over
a wider pH range which in turn includes the complete range of active alkali-
hydroxide/sulfite/bisulfite. Limestone regeneration operates only in the
sulfite/bisulfite range.
Ca(OH)2 + 2HS03~ ->• S03= + CaS03'l/2H20 + 3/2H20 (14)
Ca(OH)2 + S03= + 1/2H20 -> 20H~ + CaS03'l/2H20 (15)
Ca(OH)2 + S04= ^ 20H~ + CaS04 (16)
Ca(OH)2 + S04= + 2H20 + 20H~ + CaS04'2H20 (17)
-------
Total oxidizable sulfur (TOS) is the total concentration of sulfite
and bisulfite in solution. Oxidation of TOS to sulfate may occur in any
part of the system and is affected by composition of the scrubbing liquor,
oxygen content of the flue gas, impurities in the lime, and design of the
equipment.
S03= + 1/202 -> S04= (18)
HS03~ + 1/202 -»• S0,= + H+ (19)
The sum of the concentrations of NaOH, Na2C03, NaHCOo, Na2S03, and
NaHS03 in the scrubbing solution is termed active alkali. The active alkali
concentration in a system can be dilute or concentrated; a concentrated mode
(active sodium concentration greater than 0.15 M) was chosen for this study.
In this mode high sulfite levels prevent the precipitation of calcium sulfate
(CaSO^) as gypsum (CaSO^' 21^0) , equation 17. However, CaSO^ is precipitated
along with calcium sulfite (CaSO-j' 1/2H20) as shown in equations 14-16. In
this way the system can keep up with sulfite oxidation at the rate of 25%
to 30% of the S02 absorbed without becoming saturated with CaSO,. Usually
soluble calcium levels are less than 100 ppm in the regenerated liquor of a
concentrated mode double-alkali process.
Several U.S. and Japanese companies have developed double-alkali FGD
processes. Unlike the Japanese processes which generally result in the pro-
duction of gypsum, U.S. processes are of the waste-producing type, producing
a calcium sludge that is primarily CaS03' 1/2H20.
The first U.S. patent for a double-alkali system was awarded to FMC
Corporation in October 1975. FGD investigation was started at FMC in 1956
with limestone and lime scrubbing (FMC, 1976; Legatski, 1976), but by the
1960 's FMC was testing a sodium-based scrubbing process on a pilot-plant scai<
The process produce sodium sulfite (Na2S03) and sodium sulfate
(Na2SO^) and when efforts to sell these products failed, FMC began a search
to find a method of recovering the sodium values from the system while pro-
ducing an acceptable solid waste for disposal. The resulting concentrated
double-alkali process was demonstrated as an equivalent 30-MW prototype
installed on a reduction kiln at FMC's Modesto (California) Chemical Plant
in 1971. Since 1971 several installations have been constructed or are
planned for industrial boilers of up to 150 MW equivalent size. Removal of
S02 and unit availability have been 90% or greater. An FMC system, scrubbine
flue gas from coal of 3.75% sulfur, is planned for the 250-MW A. B. Brown
Unit No. 1, Southern Indiana Gas and Electric Company (Table 2).
-------
TABLE 2. COMMERCIAL, DOUBLE-ALKALI FGD
SYSTEMS UNDER CONSTRUCTION AT U.S.
ELECTRIC POWER STATIONS
Power plant
Utility
Louisville Gas
and Electric
Southern Indiana
Gas and Electric
Central Illinois
Public Service
Station
Cane Run
A. B. Brown
Newton
Unit
No.
6
1
1
FGD
MW
277
250
575
FGD
startup
2/79
4/79
11/79
FGD installation
New/
retrofit
R
N
N
Vendor
Combustion Equipment
Associates/Arthur D. Little
FMC Corporation
Buell/Envirotech
-------
Envirotech Corporation developed its Buell double-alkali S02 control
process for both dilute and concentrated mode operation (Bloss, et al., 1976).
A joint R&D effort with Utah Power and Light Company was undertaken at Gadsby
station in Salt Lake City. The 1-MW pilot plant began testing in January
1972. Envirotech research has also focused on high-chloride coals and the
acceptable disposal of chlorides in a throwaway system. At present Envirotech
is constructing a 575-MW FGD system at Newton station unit 1, Central Illinois
Public Service (Table 2). Unit 1 will burn coal containing 4% sulfur and 0.2%
chloride.
In 1972 Arthur D. Little, Inc., (ADL) was awarded a $1.1M EPA contract
to develop double-alkali technology. In the ADL laboratory program, tests
were conducted to develop process chemistry, to study regeneration of sodium
scrubbing solutions, and to characterize double-alkali waste products
(LaMantla, et al., 1976, 1977). ADL, in conjunction with Combustion Equip-
ment Associates, Inc., (CEA), conducted pilot-plant work involving both con-
centrated and dilute modes of operation. A 20-MW prototype double-alkali
system using lime in a concentrated mode was designed and developed by CEA
and ADL for installation at Gulf Power Company's Scholz Steam Plant at Sneads
Florida. The test program, a part of the EPA contract, ran from May 1975 to
July 1976. CEA and ADL have been awarded an EPA contract for a full-scale
double-alkali demonstration unit now under construction at Cane Run
Unit 6, Louisville Gas and Electric Company (Van Ness, 1978). Coal sulfur
content at Unit 6 is 3.5% to 4%. Although the entire cost of the installation
$16.3M, is being borne by Louisville Gas and Electric, EPA will provide addi-
tional funding of $4.5M to cover performance testing and a 1-year operational
study. SC>2 removal efficiencies greater than 95% have been guaranteed (Table 21
Other U.S. companies have developed double-alkali processes or have
conducted experimental programs to study process feasibility. A dilute mode
limestone regeneration double-alkali system, developed by General Motors
Corporation and installed at its Parma, Ohio, steam plant, was put into
operation March 1974 (Interess, 1977). Under contract to EPA, ADL conducted
a 2-year test program at the Parma site to study operating characteristics
and waste byproduct properties of the system. The Zurn double-alkali process
(Zurn Industries, Inc.) is in use at the Caterpillar Tractor Company plant
in Joliet, Illinois (Lewis, 1976). The process is dilute mode, lime regenera-
tion, and scrubs gas from two industrial boilers burning 4% sulfur coal. The
CALSOX system, a Monsanto Enviro-Chem Systems, Inc., development (Barnard, et
al., 1974), absorbs S02 in an aqueous solution of ethanolamine and regenerates
scrubbing liquor with lime. Chemico and Bechtel have also conducted pilot-
plant tests of double-alkali systems.
Double-alkali process chemistry was studied in the laboratories of EPA
at Research Triangle Park, North Carolina (Draemel, 1972), in the early 1970 »s
as a part of an EPA program which included work contracted to Radian Corpora-
tion and ADL. Radian designed a mathematical model of the double-alkali
system which included certain chemical species not already considered in the
laboratory. A bench-scale study was undertaken by ADL to find optimum equip-
ment arrangement, to develop mass transfer coefficients, and to use process
knowledge to develop economic information about the system.
11
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Also in the early 1970's laboratory- and bench-scale studies of sodium
and ammonia sorbents were conducted by TVA (TVA, 1973, 1974) using limestone
or lime as regenerants. A pilot-plant study at TVA's Colbert Steam Plant
was developed under EPA contract using an ammonia system; the study concluded
in 1976 (Williamson and Puschaver, 1977).
The design of the generic double-alkali process evaluated in this study
follows the development of U.S. double-alkali throwaway systems, using a con-
centrated mode with sodium sulfite absorbent and lime regenerant.
CITRATE PROCESS
The U.S. Bureau of Mines Metallurgy Research Center at Salt Lake City
began FGD research in 1968 to find ways to control S02 emissions from the
nonferrous smelting industry. After a year of testing many possible organic
and inorganic sorbing combinations, an aqueous solution of sodium citrate
and citric acid was chosen for its chemical stability, low vapor pressure,
high S02 absorption, completeness of regeneration, and purity of the resulting
sulfur (Rosenbaum, et al., 1971; McKinney, et al., 1974a). The chemistry of
the citrate process was investigated in laboratory studies by the Bureau of
Mines and by Pfizer, Inc. (Korosy, 1974). In the absorption stage S02 dis-
solves in water, but the absorption is self limiting.
S02 + H20 £ HS03~ + H+ (20)
Hydrogen ions are removed and solubility increases by the buffering
action of the various citrate species.
Cit~ + H+ £ HCit= (21)
HCit= + H+ £ H2Cit~ (22)
H2Cit~ + H+ t H3Cit (23)
Some thiosulfate, formed in the regeneration step, will recycle with
the absorbing solution and can form a complex with S02.
H+ + HS03~ + S203= £ S02'S203= + H20 (24)
Reaction between bisulfite and thiosulfate can result in the formation
of trithionate.
4HS03~ + S203= + 2H+ -»• 2S306= + 3H20 (25)
Although the complexing of absorbed S02 (equation 24) inhibits oxidation
to sulfate, some oxidation will occur during absorption.
HS03~ + 1/202 -> HS04~ ^ H+ + S04= (26)
12
-------
The reaction of hydrogen sulfite (H2S) and SC>2 in aqueous solution
during regeneration is complex and thiosulfate and other intermediates are
formed. Reduction of these and the intermediates of equations 24 and 25
result in the following general equations.
S03= + 2H2S + 2H+ ->• 3S + 3H20 (27)
S203= + 2H2S + 2H+ ->• 4S + 3H20 (28)
Some decomposition of thiosulfate occurs during the sulfur-melting step
at temperatures above 257°F (125°C). The overall reaction is
3S203= + 2H+ -> 2S04= + 4S + H20 (29)
Sulfate formed by equations 26 and 29 is purged from the system by the
addition of alkali to neutralize the hydrogen ions which have also formed.
H+ + S04= + Na2C03 -»• 2Na+ + S04= + H20 + C02 (30)
Natural gas and steam are reacted with a portion of the product sulfur
to produce H2S for the regeneration step (equations 26 and 27).
CH4 + 4S + 2H20 -> 4H2S + C02 (31)
The initial Bureau of Mines process was designed to include the
following steps: (1) gas cooling and cleaning, (2) S02 absorption in citrate
solution, (3) reaction of absorbed S02 with H2S, (4) washing of precipitated
sulfur, and (5) formation of H2S. Laboratory-scale tests in 1970 processed
up to 15 ft3/min of gas containing 0.3% to 2.0% S02. In these tests the
precipitated sulfur was not washed but was filtered and melted to separate
the occluded citrate. H2S preparation was not a part of these tests.
o
In November 1970, a pilot plant treating a maximum 400 ftj/min of
reverberatory furnace gas was placed into operation jointly by the Bureau of
Mines and Magma Copper Company, a subsidiary of Newmont Mining Corporation,
at the San Manuel smelter in Arizona (McKinney, et al., 1974b; Rosenbaum, et
al. , 1973). Liquid H2S was purchased for the S02 reduction process step.
The operation of the pilot plant was frequently interrupted by mechanical
failures; however, the Bureau of Mines concluded that (1) the process could
remove 90% to 99% of the S02 from the smelter gas, (2) regeneration of the
scrubbing liquor was easily managed, and (3) high-quality sulfur could be
recovered by a combination of thickening, centrifuging , and melting.
In 1971 Pfizer, Inc., a chemical plant operator and manufacturer of
citric acid, working with the Bureau of Mines built and operated laboratory
units to study citrate process chemistry. Arthur G. McKee and Company and
Peabody Engineered Systems joined Pfizer in 1972 in plans to demonstrate the
commercial feasibility of the citrate process (Korosy, 1974). A 2,000 sft3/min
pilot plant was constructed at Pfizer 's Vigo plant site in Terre Haute, Indiana
The gas stream, from a coal-fired industrial boiler, averaged 1,000 ppm S02
at the inlet to the FGD system. Two major design changes incorporated in
13
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this pilot plant were the impingement plate tower which replaced the packed
tower of the Bureau of Mines system and sulfur separation which was accomplished
by air rather than hydrocarbon flotation. Peabody at one time offered this
system under the trade name Citrex process.
Further investigation by the Bureau of Mines continued in February 1974
at the Bunker Hill Company lead smelter, Kellogg, Idaho. A pilot plant, using
a packed tower with polypropylene Intalox saddles and sized to treat 1,000
sft-Vmin of 0.5% S02 gas, was designed to be operated in three phases
(McKinney, et al., 1974). In Phase I, a smeltering furnace gas containing
4% to 5% S02 was diluted with air to 0.5% SC>2. Purchased liquid I^S was used
for reducing the 862 to sulfur. Phase II operation was similar to Phase I
with the exception that a 76% to 78% H2S gas produced onsite from product
sulfur, natural gas, and steam was used as the reducing gas. In Phase III
tail gas from the lead smelter sinter plant, containing 0.3% to 0.9% S02, was
used as feed. A gas cooling and cleaning plant was designed to recover the
dust in the tail gas in a baghouse, cool the gas in a packed wet scrubber,
and remove sulfuric acid (H2S04) mist and trace particles in a wet electro-
static precipitator (ESP). The Bunker Hill citrate pilot plant operated
through November 1975 for a total of 4,500 hours and produced about 50 net
tons of high-quality sulfur.
With EPA, the Bureau of Mines initiated plans for a full-scale citrate
process demonstration plant and in mid-1976 entered into a cost-sharing co-
operative agreement with the St. Joe Minerals Corporation to provide the
host site (Madenburg and Kurey, 1978). A citrate process demonstration plant
has been constructed at St. Joe's 60-MW coal-burning G. F. Weaton electric
generating station at Monaca, Pennsylvania. Morrison-Knudsen Company of Boise,
Idaho, has built the plant under a turnkey design/build/operate contract.
The retrofitted system will treat 156,000 sft-Vmin of flue gas and is scheduled
to begin operation in the summer of 1979. At that time Radian will begin a
1-year emission testing and performance evaluation of the demonstration system.
The citrate process design data and operating criteria used in this
study are based primarily on the Bureau of Mines process. Design differences
in the citrate process demonstration plant at Weaton Station are cited in the
Systems Estimated, Citrate Process section below.
14
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DESIGN AND ECONOMIC PREMISES
To make the comparison of process evaluations as equitable as possible
it is essential to carefully define the design and economic premises used as
a basis for the study calculations. TVA has been involved in establishing
study criteria and preparing technical and economic evaluations of alternate
FGD processes for EPA and others since 1967. A report published by TVA and
EPA (McGlamery, et al., 1975) outlined in detail a set of premises developed
by TVA for use in its evaluation studies. Recently these premises have been
modified through discussions with EPA and others to reflect prevailing fuel
characteristics, current design practice, and projected economic conditions.
DESIGN PREMISES
The updated values used in this study are considered to be representa-
tive of modern boiler units less than 10 years old for which FGD wo"ld be
considered. The base case is a new 500-MW power unit with a heat rate of
9,000 Btu/kWh, burning 3.5% sulfur coal (dry basis). Criteria that establish
efficiencies, production rates, and other process design characteristics
that are common to FGD systems are also included.
Power Plant
Both coal- and oil-fired power units are considered in the power plant
design premises; because of decreasing emphasis on oil as a fuel source of
electricity, however, only one oil-fired case—an existing 500-MW unit—is
evaluated. A midwestern location (Illinois, Indiana, Kentucky area) is
assumed for the power units because of the concentration of power stations
in that area and their proximity to major coal fields.
Fuels—
Although coals of low sulfur and ash contents and high heating values
are the most desirable, availability, location, and price often result in
the use of coals of lesser quality. To represent the wide range of coals
currently being burned, sulfur contents of 2.0%, 3.5%, and 5.0% (dry basis)
were chosen. The coal composition was altered from previous studies to
reflect a lower heating value (HHV) of 10,500 Btu/lb (as fired) and a
higher ash content of 16%. The as-fired coal composition and flow rate for
the three sulfur levels are given in Table 3.
A No. 6 fuel oil with 2.5% sulfur and an ash content of 0.1% is assumed
for the oil case variation (Table 4). A heating value of 144,000 Btu/gal
is assumed.
15
-------
TABLE 3. COAL COMPOSITIONS AND FLOW RATES AT VARYING SULFUR LEVELS
(500-MW new unit, 9,000 Btu/kWh heat rate,
10,500 Btu/lb higher heating value of coal)
Coal
components
Base case
3.5% S (dry basis)
Wt %, Lb/hr,
as fired as fired
2.0% S (dry basis) 5.0% S (dry basis)
Wt %,
as fired
Lb/hr,
as fired
Wt %,
as fired
Lb/hr,
as fired
C
H
N
0
S
Cl
Ash
H20
57.56
4.14
1.29
7.00
3.12
0.15
16.00
10.74
246,800
17,700
5,500
30,000
13,400
600
68,600
46.000
58.03
4.17
1.30
81
1.80
0.15
16.00
10.74
248,700
17,900
5,600
33,500
7,700
600
68,600
46,000
56.89
4.
1,
.09
.27
6.40
4.46
0.15
16.00
10.74
244,000
17,500
5,400
27,400
19,100
600
68,600
46,000
Total 100.00 428,600 100.00 428,600 100.00 428,600
TABLE 4. FUEL ALTERNATIVE CASE
OIL COMPOSITION AND FLOW RATE
(500-MW existing unit, 9,200 Btu/kWh heat rate, 2.5% S)
Oil components Wt %, as fired Lb/hr
C
H
N
0
S
Ash
Sediment
83.66
11.46
0.63
1.25
2.50
0.10
0.40
204,100
28,000
1,500
3,000
6,100
200
1,000
Total
100.00
243,900
16
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Design'—-
The size of operating fossil-fueled power plants in the United States
today ranges to 1300 MW. Of the new units scheduled for commercial service
in 1977 through 1980, sizes for coal-fired boilers range from 80-1300 MW
(Electrical World, 1977a). Although a considerable portion of the future
generating capacity will be from power units 500 MW or larger, many older
and smaller units, 200 MW or less, will continue operation in the years to
come. Therefore, to determine the effect of power unit size on the economics
of SC>2 removal, three unit sizes—200, 500, and 1,000 MW—are chosen for study.
Balanced-draft boiler design is assumed for a horizontal, pulverized
coal, frontal-fired unit. A tangential-fired boiler is assumed for the oil-
fired unit. ESP units designed to remove 99.5% of the particulate matter are
assumed to be located ahead of the FGD system for coal-burning units. Fly
ash emission from oil-fired units does not exceed the EPA particulate emission
standard; therefore, these power plants do not require fly ash collection
facilities.
A balanced-draft power unit without an S02 removal unit normally requires
one induced-draft (ID) fan per duct, capable of overcoming a pressure drop
of approximately 15 inches downstream of the boiler. In the design of new
power plants with S02 removal facilities, it is assumed that the balanced-
draft system includes the same capacity ID fan which will feed flue gas into
a common plenum. Downstream from the plenum one forced-draft (FD) fan
(relative to the SC>2 absorber) is provided per scrubbing train to overcome
the additional pressure drop attributed to S02 removal. Since existing
power units are already equipped with a 15-inch ID fan, retrofitted SC^
removal facilities will follow the same design by adding one FD fan per
scrubbing train downstream of the plenum.
In this evaluation 200-MW power units are assumed to have two economizers
air heaters, and exhaust ducts, while 500- and 1,000-MW units are assumed to
be equipped with four of each.
Operation—
Based on power plant evaluation guidelines suggested by the Federal
Energy Regulatory Commission (FERC) (formerly the Federal Power Commission)
(FERC, 1968) , the expected operating life of a new fossil-fueled power unit
is about 30 years. Reflecting past TVA experience (Slack, et al., 1971),
Table 5 shows the power plant operating schedule assumed for this study.
This schedule represents a total on-stream time of 127,500 hours over the
life of the plant. Existing 200-MW units are assumed to be 10 years old
with a remaining life of 20 years or 57,500 operating hours; existing 500-
and 1,000-MW units are assumed to be 5 years old with a remaining life of
25 years or 92,500 operating hours.
17
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TABLE 5. ASSUMED POWER PLANT CAPACITY SCHEDULE
Operating year
1-10
11-15
16-20
21-30
Average for 30-yr life
Capacity
factor, %
80
57
40
17
48.5
Annual
operating
time, hr
7,000
5,000
3,500
1,500
4,250
Power plant efficiencies vary with size and status. FERC data (1973)
list heat rates for approximate 500-MW power units up to 5 years old, ranging
from 8,800 to 12,800 Btu/kWh. Representative heat rates chosen for use in
this study are given in Table 6.
TABLE 6. POWER UNIT INPUT HEAT REQUIREMENTS
Size, MW Status Heat rate, Btu/kWh
1,000
1,000
500
500
200
200
New
Existing
New
Existing
New
Existing
8,700
9,000
9,000
9,200
9,200
9,500
Flue gas compositions vary with power unit design, fuel, and a variety
of operating conditions. The following combustion and emission parameters
for determining gas composition are based on FERC (1976) and EPA (1973) data
for balanced-draft boiler design and average values for the sulfur content
of coal. Not taken into consideration are variations in coal—sulfur in
actual coal deliveries—which can result in levels as much as 22% greater
than average values.
Coal-fired units—Flue gas compositions are based on combustion of
pulverized coal and a total air rate to the air preheater equivalent to 133%
of stoichiometric requirement. This includes 20% excess air to the boiler
and 13% air inleakage at the air preheater. These values reflect operating
experience with typical horizontal, frontal-fired, coal-burning units. It
is assumed that 80% of the ash present in coal is emitted as fly ash and 95%
of the sulfur in coal is emitted as SOX. One percent of the SOX emitted is
assumed to be sulfur trioxide (863), the remainder is S02- Nitrogen oxides
(NOV) emission is reported as nitric oxide (NO).
X
18
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Oil-fired unit—A tangential-fired boiler is considered for the oil-
fired units with flue gas composition estimated assuming a total air rate
to the air preheater equivalent to 115% of the stoichiometric requirement.
This includes 5% excess air to the boiler with an estimated 10% air inleakage
at the preheater. It is also assumed that all of the ash and sulfur in the
fuel oil is emitted as fly ash and
assumed to be 803.
SOX. One percent of the SOX emitted is
The flue gas compositions and flow rates calculated from these parameter!
are shown in Table 7. Calculated flue gas and equivalent S02 emission rates
are listed in Table 8.
TABLE 7. ESTIMATED FLUE GAS COMPOSITIONS
FOR POWER UNITS WITHOUT EMISSION CONTROL FACILITIES
Fuel and boiler type
Flue gas components
(% by vol)
Coal-fired boiler
(horizontal
frontal fired)
Oil-fired boiler
(tangential fired)
Sulfur content of fuel, % by wt (dry basis)
2.0 3.5 5.0 2.5
N2
02
C02
S02
803
NOX (as NO)
HC1
H20
73.68
4.83
12.44
0.14
0.0014
0.06
0.01
8.84
73.76
4.83
12.31
0.24
0.0024
0.06
0.01
8.79
73.80
4.84
12.20
0.34
0.0034
0.06
0.01
8.75
73.60
2.54
11.96
0.13
0.0013
0.02
-
11.75
Fly Ash Loading
gr/sft3 (dry)
gr/sft3 (wet)
6.67
6.08
6.65
6.06
6.66
6.08
0.036
0.032
19
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TABLE 8. POWER PLANT FLUE GAS AND S02 RATES
ro
o
Power plant
size, MW
Coal-fired units
200
200
500
500
Type
plant
Existing
New
Existing
New
Sulfur content
of fuel, %
(dry basis)
3.5
3.5
3.5
2.0
Gas flow
to FGD systems,
aft3/min (300°F)
652,000
631,000
1,577,000
1,539,000
Equivalent SC>2 emission
rate to FGD systems,
Ib S02/hr
10,610
10,270
25,690
14,500
500 (base case) New
500
1,000
1,000
Oil-fired unit
500
New
Existing
New
Existing
3.5
5.0
3.5
3.5
2.5
1,543,000
1,539,000
3,085,000
2,982,000
1,313,000
25,130
35,920
50,250
48,580
12,060
-------
FGD System
Scrubber SC>2 removal requirements, design and redundancy, bypass,
reheat, and other FGD design considerations are as follows:
Emission Standards—
Current EPA Federal Standards of Performance for New Stationary Sources
(often called new source performance standards—NSPS) which define the maxi-
mum emission levels for new power plants in the United States are shown in
Table 9 (Federal Register, 1971). The design assumed for this report
is based on meeting the standard for particulate matter and S02 emission
rather than designing for a higher degree of removal. NSPS revisions, pro-
posed in the Federal Register (1978), include a requirement of 85% SC>2 removal
(24-hour average) with maximum emissions of 1.2 Ib S02/MBtu.
TABLE 9. CURRENT EPA EMISSION STANDARDS FOR
NEW STEAM GENERATING FACILITIES
Allowable emission, Ib/MBtu
heat input
Coal-fired unit Oil-fired unit
Particulate matter 0.1 0.1
S02 1.2 0.8
Degree of Removal—
Because required S02 removal efficiencies vary depending on fuel type
and sulfur content, case variations will show a range of 63% to 85% removal
required to meet existing NSPS. The required removal efficiencies for fly
ash and S02 are given in Table 10 for the fuels and sulfur levels considered.
For all fuels evaluated, designs provide for limiting S02 emission to 1.2 u,
S02/MBtu input (current NSPS). An additional case based on a 500-MW new
coal-fired unit with 3.5% sulfur level has been prepared to show the effect
of designing for 90% 862 removal.
TABLE 10. REQUIRED REMOVAL EFFICIENCIES
Sulfur content Degree of Degree
of fuel, % particle removal, wt % S02 removal. %_
Coal-fired units
2.0 99.5 62.7
3.5 99.5 78.5
5.0 99.5 85.0
Oil-fired units
2.5 - 69.8
21
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S02 Scrubber—
Scrubbing system design assumes that technology used in each process is
proven, has been demonstrated, and is not first-of-a-kind. No special
redundancy provisions are assumed necessary for utility boiler - SC>2 scrubber
system reliability.
Several methods are available to provide turndown capabilities of the
control systems resulting from changes in power supply requirements including:
1. Multiple-scrubbing trains
2. Variable-flow control to individual scrubbers
3. Compartmentalized scrubbers
4. Individual scrubber bypasses
5. Connecting plenum ducts between trains
For this study, ESP ducts are assumed to exhaust to a common plenum
connecting the scrubbing trains. Separate ducts from the plenum to each
scrubbing train are equipped with dampers for individual scrubber shutoff
for maintenance or power plant turndown. Because of the reliability implied
in the assumption that these processes are based on proven technology, other
special design provisions for individual scrubber shutdown are not provided.
Bypass ducts for maintaining full power generation capacity during shutdown
of one or more scrubbing trains are not provided.
The scrubber type for each process is:
Process Scrubber type
Limestone Mobile bed
Double alkali Perforated plate tower
Citrate Packed tower
Each scrubber system is designed with a presaturator for cooling and humidi-
fying the flue gas. Absorption of flue gas components in the presaturator
is assumed as follows:
Component % removal
S02 5
S03 50
HC1 100
NOX 0
In the limestone and double-alkali processes these compounds are disposed of
in the waste stream along with the additional SC^ removed in the absorption
tower. In the citrate process the excess liquor from the presaturator drains
into the bottom of the S02 absorber and is recycled to the presaturator for
humidification and cooling of the flue gas. A liquor purge stream is pumped
to a neutralization tank to which lime is added to control chloride contami-
nation of the system. An SC>2 stripper is placed upstream from the neutralization
22
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tank to remove SC>2 from the purge stream and return it to the flue gas
stream to allow as much sulfur as possible to be reclaimed from the system.
Each SC>2 scrubber is equipped with a chevron-type entrainment separator
at the scrubber outlet. The use of an entrainment separator or mist elimi-
nator in the scrubber is desirable for the following purposes.
1. To reduce the heat load on the stack gas reheater.
2. To decrease the deposition of liquid and entrained solids in ducts
and equipment located downstream from the scrubber.
3. To reduce the amount of entrained solids emitted to the atmosphere.
The exit gas from the SC>2 absorber is assumed to contain water entrainment
equivalent to 0.1% by weight of the wet gas mass rate.
Specific design conditions for SC>2 removal will vary from installation
to installation corresponding to expected fluctuations in the fuel analysis
and to differences in operating requirements. The operating conditions
chosen for each base case scrubbing system in this study are presented in
Table 11.
TABLE 11. ASSUMED OPERATING CONDITIONS FOR SCRUBBING
SYSTEMS APPLIED TO NEW COAL-FIRED POWER UNITS
[500-MW units, 3.5% S in coal (dry basis),
1.2 Ib S02/MBtu heat input allowable emission]
Operating conditions
Stoichiometry
Design gas velocity, ft/sec
S02 scrubber
L/G, gal/kft3
Presaturator
S02 scrubber, recycle liquor
S02 scrubber, regenerated liquor
Design pressure drop, inches H20
Oxidation of removed S02 to S0^=, %
Limestone
1.32
12.5
4
50
-
8
20
Process
Generic
double alkali
1.0
7.0
4
4
3
3
10
Citrate
_
10.0
4
-
5
15
2
23
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Reheat—
The need for stack gas reheat for corrosion reduction and plume buoyancy
after aqueous scrubbing is recognized in the contemporary designs. Indirect
steam reheat of the cleaned gas to 175°F is provided for all case variations
except the oil-fired case. For the existing oil-fired power unit, direct
stack gas reheat to 175°F is provided by mixing the combustion byproducts
of an oil-fired reheater directly with the scrubbed gas.
Raw Materials—
Listed below are the raw materials that are used in the three desulfur-
ization processes, with typical characteristics given for each.
1. Limestone
Purchase size -Ox 1/2 inch
Analysis - 90% CaC03, 0.15% MgO, 4.85% inerts, 5% H20
Limestone ground as 60% solids slurry
Ground size - 70% minus 200 mesh
Bulk density - 95 lb/ft3
2. Lime
Analysis - 95% CaO, 1% Si02, 2% MgO, 2% H20
Size - 3/4 to 1-1/4 inch
Bulk density - 55 lb/ft3
3. Sodium carbonate
Analysis - 99.8% Na2C03 (58.36% Na20), 0.15% NaCl,
0.02% inerts, 0.03% H20
Bulk density - 35.5 lb/ft3
4. Citric acid
Analysis - 99.5% to 100% purity
Bulk density - 55 lb/ft3
Solids Disposal—
One important design consideration for the limestone and double-alkali
processes is the method for waste solids disposal. Two alternatives are
investigated in this study.
1. Onsite pond disposal—The base case for the disposal of untreated
limestone sludge is direct ponding of spent slurry from the scrubber
in a clay-lined pond. The slurry is pumped to the pond at a solid
concentration of 15%. In the double-alkali base case, a filter cake
of calcium waste solids is reslurried to 15% solids and pumped to a
clay-lined pond. The following assumptions are made for the pond.
a. The pond is one mile from the scrubber system site and is located
on flat land.
b. The pond life is the same as power plant remaining life defined
earlier in the power plant design premises.
24
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c. The pond is sized and costed for the disposal of calcium wastes
only. Fly ash disposal is not considered. Pond is designed to
minimize total pond construction cost including cost of land
by optimizing pond depth and excavation.
d. Pond is lined with 12 inches of impervious clay.
e. Settled sludge contains 40% by wt solids and 60% free water.
f. Closed-loop water cycle is maintained by returning excess
pond water to the scrubber system.
g. Pond evaporation and seepage equals rainfall.
2. Trucking alternative—A special case is evaluated for the limestone
and double-alkali processes in which the calcium solids are trucked
to the disposal site. Each process is designed with a slurry de-
watering system to produce a disposal cake containing 55% solids.
Charges for land preparation by scraping are included. No stabili-
zation is assumed; disposal cake is piled to a height of 30 feet.
Further discussion of this alternative appears in the Systems Esti-
mated section.
The disposal methods are those currently used. More stringent regula-
tions for control of runoff pollution from solid wastes may be effected in
the future and could affect some aspects of disposal area design and site
maintenance. Although beyond the time frame projected in this report, such
regulations could be an economic factor in waste disposal considerations.
ECONOMIC PREMISES
Economic evaluations of the three processes are divided into capital
investment and revenue requirements. Criteria are assumed that define
cost indexes; land, raw material, and utilities costs; capital charges;
and other factors required for comparative estimates.
Capital Investment
Capital investment estimates represent projects beginning mid-1977 and
ending mid-1980, with an average cost basis for scaling of mid-1979. Other
project estimates may be scaled from mid-1979 to the midpoint of project
expenditures. System design is assumed to require 6 to 12 months and con-
struction 24 months. The overall project is assumed to be completed over a
30- to 36-month project schedule.
25
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Estimates are based on cost information obtained from engineering-
contracting, processing, and equipment companies; TVA equipment purchases
and construction data; and authoritative publications on estimating and
costs, such as Bauman (1964), Guthrie (1969), Peters and Timmerhaus (1968),
Popper (1970), The Chemical Engineer's Handbook (Perry and Chilton, 1973),
and The Richardson Rapid System (1978). Costs are projected (Table 12) for
1979 from historical annual Chemical Engineering (1974, 1975, 1976) cost
indexes and published projections (Thorsen, 1972).
The battery limits of the SC^ removal facility estimates began with the
common plenum downstream of the ESP and include the stack gas reheaters
downstream of the absorbers. The stack plenum is considered necessary to a
power unit without SC>2 removal and is not included in the FGD cost. Costs
for booster fans and ductwork required to circulate flue gas through the
FGD system are included. Fly ash removal by ESP and fly ash disposal are
considered power plant functions and are not included in investment or
revenue requirement estimates. The ID fans located between the ESP and the
first plenum are considered a part of the boiler unit and their cost is not
included in the FGD evaluation. Neutralization of the chlorides purged from
the flue gas in the citrate system presaturator is included in the FGD cost.
Other special provisions and assumptions used in the preparation of
investment estimates are:
1. Spare pumps are provided to prevent operational shutdowns due to
pump failure. For the limestone slurry and generic double-alkali
processes, a spare pipeline is included for transport of sludge
to the disposal area. No other spare equipment is included.
2. Process water utilization is based on closed-loop operation.
3. Indirect steam reheat of stack gases is assumed in all cases except
for the existing oil-fired unit which utilizes direct oil-fired reheat.
4. Costs for the supplemental generation facilities for electricity used
by the FGD system are not included in the capital investment. Com-
pensation for derating of the boiler caused by FGD system electrical
usage is added to the cost of electricity in the revenue requirement
estimates.
5. Equipment, material, and construction-labor shortages with accompanying
overtime pay incentive are not considered.
Direct Investment—
A detailed equipment list is prepared for the base case estimate which
itemizes cost for materials and installation labor for each equipment item.
In addition the cost of piping, insulation, ductwork, concrete foundations,
excavation, structures, electrical, instrumentation, painting, and buildings
required for each unit area are itemized.
26
-------
TABLE 12. COST INDEXES AND PROJECTIONS
Year
Plant ,
Material
Laborc
1972
137.2
135.4
152.2
1973
144.1
141.9
157.9
1974
165.4
171.2
163.3
1975
182.4
194.7
168.6
1976a
197.9
210.3
183.8
1977a
214.7
227.1
200.3
1978a
232.9
245.3
218.3
1979a
251.5
264.9
237.9
1980a
271.6
286.1
259.3
1981a
293.3
309.0
282.6
a. Projections. Although actual cost indexes are available for 1976-1978, TVA continues
to use its projections for these years so that consistency with past estimates is main-
tained .
b. Same as index in Chemical Engineering for "equipment, machinery, supports."
^j c. Same as index in Chemical Engineering for "construction labor."
-------
Services, utilities, and miscellaneous costs are calculated as 6% of
direct investment minus pond construction costs. This is assumed to include
such items as maintenance shops, stores, communications, security, and offices,
Also included are costs for parking lots, walkways, landscaping, fencing,
vehicles, and 1 mile of paved roads. Necessary electrical, fuel oil, steam,
process water, fire and service water, and compressed air distribution facil-
ities and instrument air generation facilities are also a part of this cost.
Indirect Investment—
In addition to direct costs which include equipment, installation, ser-
vices and utilities, and pond construction, the indirect costs covering engi-
neering design and supervision, architect and engineering contractor expenses,
construction expense, contractor fees, and contingency are estimated for each
project. The engineering design and supervision and contingency factors are
based on proven design, not first-of-a-kind installation.
Engineering design and supervision (ED&S)—A technique that correlates
the number of major equipment items with drafting room man-hour and engi-
neering design costs is used to estimate this indirect investment factor.
Battery-limit areas are included as a varying percentage of area cost. The
percentage used is determined by commercial status and design reliability of
the purchased unit. The formula used is:
Engineering design and supervision = (8900) (1.294) (number of major
equipment pieces) + (5-25%) (battery-limit investment)
A separate procedure, based on pond construction expense, was developed
to determine ED&S cost for the pond area.
Pond engineering design and supervision = (0.076) (a) '
where (a) = direct pond investment in M$
The sum of these costs appears in the indirect investment display as
ED&S for each process case variation.
Architect and engineering contractor expenses (A&E)—This factor is
derived from the costs of engineering design and supervision. Twenty-five
percent of the portion of ED&S associated with major equipment and battery-
limit units is assumed for A&E. For cases involving disposal ponds, 10% of
the ED&S associated with pond construction is estimated as additional A&E
expense.
Construction expense—Construction expense is estimated based on direct
investment by the following equation:
A QO n Q O
Construction expense = 0.25 (b) + 0.13 (c)
where b = direct investment in M$ excluding pond investment costs
c = direct pond cost in M$
28
-------
Contractor fees—A correlation between contractor fees and direct invest-
ment is used to estimate the cost of contractor fees.
Contractor fees = 0.096 (d)
Contingency—Contingency is assumed to be 20% of the sum of direct
itment, engineering design and supervision costs, architect and engineer!
•actor expenses, construction expense, and contractor fpp
-------
raw material puschases, (4) accounts payable, and (5) taxes payable. For
these premises, working capital is defined as the equivalent of 3 weeks of
raw material costs, 7 weeks of direct costs, and 7 weeks of overhead costs.
Case Variations-
Each area of the base case direct investment is analyzed and adjusted
as necessary to reflect required modifications in process design for the
case variations. For example, indirect steam reheat investment costs are
replaced with direct oil-fired reheat investment costs for the existing oil-
fired unit. In the citrate process, the chloride purge is eliminated for the
existing oil-fired case. Modifications are made in the amount of ductwork
provided for all existing units.
The adjusted area investment subtotal is scaled exponentially according
to the relative throughput, using a weighted average scaling exponent cal-
culated from the base case investment breakdown. Flue gas processing areas
are scaled on the basis of relative gas throughput; byproduct processing
areas are scaled on the basis of relative sulfur throughput. Table 14 shows
the relative quantities of gas and sulfur which must be processed for each
of the case variations in comparison with the base case quantities. The
direct, indirect, fixed, and total capital investments are then determined
by the same procedure described for the base case investment.
-Revenue Requirements
Annual Revenue Requirements—
Average annual revenue requirements for each case variation are cal-
culated under regulated economics assuming 7,000 hours of operation per year.
Process operation schedules are assumed to be the same as the power plant
operating profiles and remaining life assumptions given in the power plant
design premises. Operating costs for removal and disposal of fly ash are
not included.
Direct Costs—
Raw materials, operating labor and supervision, utilities, maintenance
costs, and analyses have been projected to 1980 dollars to reflect a mid-1980
scrubbing unit startup. The projected unit costs for raw materials, labor,
and utilities are shown in Table 15. All tonnages are expressed in short
tons. Raw material costs are the delivered costs to a Chicago power plant
location; labor costs are rates for the midwestern area (Illinois, Indiana,
Kentucky). Unit costs for steam and electricity generated by the power plant
are based on acutal production cost including labor, fuel, depreciation, rate
base return on investment, and taxes.
30
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TABLE 14. RELATIVE QUANTITIES OF GAS AND SULFUR TO BE
PROCESSED IN COMPARISON WITH THE BASE CASE QUANTITIES
Relative throughput ratet %
Gas Sulfur removed
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.5% sulfur 42.22 42.22
200 MW N 3.5% sulfur 40.89 40.'89
500 MW E 3.5% sulfur 102.22 102.22
500 MW N 2.0% sulfur 100.00 46.01
500 MW N 3.5% sulfur 100.00 100.00
500 MW N 5.0% sulfur 100.00 153.81
1,000 MW E 3.5% sulfur 200.00 200.00
1,000 MW N 3.5% sulfur 193.33 193.33
Solids disposal by trucking
500 MW N 3.5% sulfur 100.00 100.00
90% S02 removal
500 MW N 3.5% sulfur 100.00 113.92
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW E 2.5% sulfur 84.70 44.08
31
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TABLE 15. PROJECTED 1980 UNIT COSTS
FOR RAW MATERIALS, LABOR, AND UTILITIES
Raw Materials
Limestone
Lime
Soda ash
Citric acid
Natural gas
Catalyst
$/unit
7.00/ton
42.00/ton
90.00/ton
1,340.00/ton
3.50/kft3
_a
Labor
Operating labor
Analyses
Trucking landfill
12.50/man-hr
17.00/man-hr
17.00/man-hr
Utilities
Fuel oil (No. 6)
Steam (500 psig) ]
Process water (citrate)
Process water"
0.40/gal
2.00/MBtu
0.06/kgal
0.12/kgal
200 MW
500 MW
Electricity
1,000 MW
0.031/kWh 0.029/kWh 0.028/kWh
a. Unit costs supplied by C&I Girdler.
b. Varies according to water volume requirements which are process
dependent.
Quantities of raw materials and utilities required by each process,
except for electricity, are derived from the base case material balance.
Electricity requirements are compiled from motor horsepower and equivalent
kilowatt usage as defined in the base case equipment description. The amount
of equipment in each process area and the difficulty of operation are con-
sidered in estimating the hours of operating labor and supervision for each
process. Labor estimates for laboratory analysis are based on the quantities
of materials which must be analyzed to maintain quality control.
32
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Maintenance costs are estimated on the basis of direct investment and
are varied for each process as a function of unit size to reflect economy of
scale. Maintenance percentages are also varied for each process according
to projected relative process complexity and historical experience, when
available. Table 16 shows the estimated overall annual maintenance factors
which are applied to the total direct investment, minus pond construction
costs, for each process, corresponding to an annual operating schedule of
7,000 hours. Pond maintenance for the limestone and double-alkali processes
is estimated as 3% of the pond construction cost.
TABLE 16. ESTIMATED OVERALL ANNUAL MAINTENANCE COSTS
% of direct investment
excluding pond construction3
Process
Limestone
Double alkali
Citrate
200 MW
9
5
7
500 MW
8
4
6
1,000 MW
7
3
5
a. Pond maintenance is estimated as 3% of pond con-
struction cost.
Indirect Costs—
In estimating revenue requirements for FGD systems, the method chosen
for financing the system—regulated power industry practice, nonregulated
chemical industry practice, or a combination of the two—has a major effect
on capital charge items such as depreciation and taxes. This study is based
on regulated utility economics. The capital charges included in the indirect
revenue requirement costs are applied as average charges which include dep!-e_
ciation, interim replacements, insurance, cost of capital, and taxes. These
charges vary with remaining life of the power plant. A breakdown of the
capital charges is given in Table 17. The depreciation rate is straight
line, based on the remaining life of the power plant after the FGD system ts
installed.
In estimating the regulated capital charges associated with stack gas
scrubbing, the conventional method of considering the overall life of the
power plant is used. FERC (1968, 1969) recognized the conclusion of the
National Power Survey that a 30-year service life is reasonable for steam-
electric plants. Because some equipment items have life spans less than 3Q
years, however, an allowance factor, designated interim replacements, is
included. Use of this allowance, following FERC recommended practice, pro-
vides for financing the cost of replacing short-lived units. Although an
average allowance of about 0.35% of the total investment is normally provided
a somewhat larger allowance factor is used for new units in this study to
account for the unknown life span of FGD facilities. An insurance allowance
is also included in the capital charges. Property taxes, the fourth item Of
the capital charge rate applied to the original investment, are estimated at
1.5% of the total depreciable capital investment.
33
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TABLE 17. ANNUAL CAPITAL CHARGES FOR POWER INDUSTRY FINANCING
Percentage of total depreciable
capital investment
Years remaining life 30 25 20
Depreciation (straight line, based on
years remaining life of power unit) 3.3 4.0 5.0
Interim replacements (equipment having
less than 30-year life) 0.7 0.4
Insurance 0.5 0.5 0.5
Property taxes 1.5 1.5 1.5
Total rate applied to original
investment 6.0 6.4 7.0
Percentage of unrecovered
capital investment3
Cost of capital (capital structure assumed
to be 60% debt and 40% equity)
Bonds at 10% interest 6.0
Equity^ at 14% return to stockholder 5.6
Income taxes (Federal and State)c 5.6
Total rate applied to depreciation base 17.2"
a. Original investment yet to be recovered or "written off."
b. Contains retained earnings and dividends.
c. Federal and State income taxes are assumed to have the same Impact
on capital cost as return on equity.
d. Applied on an average basis, the total annual percentage of original
fixed investment for new (30-yr) plants would be 6.0% + 1/2(17.2%) = 14.6%.
Debt to equity ratio is another component of capital charges for which
variations of ratios may be expected. FERC data (1972, 1974) indicate that
the long-term debt for privately owned electric utilities varied only
slightly from 51.5% to 54.8% of total capitalization during the period 1965-
1973. Recent economic trends have affected the incremental debt to equity
ratio, however, as utilities are forced to depend more and more on bonds and
bank loans for project funding. The capital structure for this study is
assumed to be 60% debt and 40% equity, with the interest rate for bonds
assumed to be 10% and the return to stockholders 14%. Federal and State
income taxes are assumed to have the same effect on capital cost as return
on equity (5.6%).
34
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The procedure for calculating plant, administrative, and marketing over-
heads can vary from company to company. Based on several cost estimating
sources used in this study, the following methods are used to estimate over-
heads.
1. Plant overhead is estimated as 50% of the total conversion costs less
utilities. This method has been selected to avoid overcharging proc-
esses which are energy intensive.
2. Administrative overhead is estimated as 10% of the operating labor and
supervision cost.
3. Marketing of FGD byproducts is defined as sales to a distributor,
shipping costs excluded, and marketing overheads are estimated on the
basis of the relative difficulty in marketing the various products o£
the processes studied. For the citrate process, marketing overhead
is estimated as 10% of the revenue collected from the sale of sulfur
The citrate process is the only system evaluated in this study that pro-
duces a salable byproduct. In the calculation of citrate annual and lifetime
economics, credit from the sale of sulfur ($40 per short ton) is deducted
from the yearly projection of revenue requirement to give the net effect of
the FGD process on the cost of power.
Case Variations—
Raw materials and utilities for the case variations are scaled from the
requirements indicated on the detailed base case revenue requirement summar
Utilities such as reheat energy and fan electricity are scaled proportionate!
to the relative gas rate for each case variation; raw materials and utility.
such as absorbent and electricity for the sulfur processing areas are seal d
proportionately to the relative sulfur rate for the various cases. Annual
costs for raw materials and utilities are then calculated by applying the
unit costs to the scaled annual usage rates.
Lifetime Revenue Requirements—
Because of the typical declining load of most power units over their
life, lifetime revenue requirements are better measures of the overall pro
costs than are annual revenue requirements. Since annual revenue requirem
vary each year as the rate base declines because of depreciation writeoff _»
with any changes in on-stream time of the power unit, it is desirable to
have a year-to-year tabulation of annual and cumulative lifetime revenue
requirements for any given case. For a comparison that recognizes the tim
value of money, the declining annual revenue requirements for each process
over the life of the plant should be discounted at the cost of money
(11.6% for this study) to the initial year of operation. The total of these
costs can be compared directly or can be converted to equivalent unit costs
for comparison with the premium expected for low-sulfur fuels.
35
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For each of the case variations of the three processes, lifetime costs
are projected corresponding to the declining operating profile established
(Table 5). Year-by-year revenue requirements included in the lifetime pro-
jections are calculated by computer in the same manner as annual revenue
requirements, with the exception that capital charges are based on the
declining undepreciated investment. Since the regulated return on investment
profitability is included in the year-by-year projections of revenue require-
ments, any revenue received from sale of byproducts can be applied toward
reducing these yearly costs.
36
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SYSTEMS ESTIMATED
Process description, material balance, flow diagram, layout drawings
and equipment requirements have been prepared for each of the three processe
evaluated. Each process is divided into major functional areas to facilitat
comparisons of investment and revenue requirements for similar processing
steps. Equipment lists follow the area-by-area pattern with material costs
presented in 1979 dollars for each item. The additional items of cost in
each area are piping and transport lines, ductwork, concrete foundations
excavation and site preparation, structure, electrical wiring, instrumenta-
tion, buildings, and pond construction.
LIMESTONE SLURRY PROCESS
The limestone slurry process for desulfurization of flue gas (Figure 11
assumes fly ash removal by ESP. A common plenum is placed downstream from
the ESP and the power plant ID fans to distribute the gas to the absorbers
Booster fans are placed between the plenum and the absorber to overcome
the pressure drop created by the FGD system (Figure 2).
Incoming 0 x 1-1/2 inches limestone is received either by truck or rail
and conveyed to a 30-day storage pile located about 150 feet from the grinn-
ing facilities (Figure 3). The limestone is reduced to about 0 x 3/4 inches
using gyratory crushers, wet-ground to 70% minus 200 mesh in two parallel
ball mills, and stored as a 60% solids slurry in a feed tank with 8-hour
storage capacity. The slurry feed tank is located near the absorber syst
(Figure 4) about 1500 ft from the limestone preparation area.
Makeup limestone slurry is combined with scrubber effluent slurry and
recycle pond water in the absorber hold tank to control the concentration
of the recirculating slurry at approximately 15% solids. Flue gas is cooled
in a presaturator with recycle slurry and fed to the mobile-bed absorbers
Limestone slurry circulates through the absorbers where it reacts with th"
S02 in the cooled flue gas. The absorbers are equipped with chevron-type
entrainment separators with provisions for upstream and downstream wash
with fresh makeup water to control entrainment carryover in the gas stream
Scrubber outlet gas is reheated to 175°F by indirect steam heat before
entering the stack.
37
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U)
00
PULVERIZED L
COAL
HOPPERS, FEEDERS 8 CONVEYORS
Figure 1. Limestone slurry process. Base case flow diagram.
-------
ELECTROSTATIC
PRECIPITATOHS
POWER PLANT
I D. FANS
ABSORBER SYSTEM
FD FANS
SLURRY RECIRCULATION
PUMPS
PLAN
ELEVATION
Figure 2. Limestone slurry process. Mobile-bed scrubber system base case
plan and elevation.
39
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r
570' (APPROX.)
LIMESTONE
PILE
INCLINE CONVEYOR
x
o
ae
a.
o
o>
RECLAIM—' RECLAIM—^
HOPPER PIT
UNLOADING PIT
— INCLINE
CONVEYOR
-UNLOADING
HOPPER
BUCKET
ELEVATOR
FEED
BIN
CRUSHER
WET BALL
MILL
MILL PRODUCT
TANK
Figure 3. Limestone slurry process.
preparation system layout.
Base case materials handling and feed
40
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LIMESTONE PILE
COAL
STORAGE
V_
Ifi
ROAD
SERVICE
BLDG
500MW UNIT
TURBINE
ROOM
BOILER
ROOM
n
FUTURE
LL_...
FUTURE
O
D
LIMESTONE
PREPARATION
AREA
i
ROAD
ROAD
O
o
o
Figure 4. Limestone slurry process. Base case overall plot plan.
41
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A bleedstream from the recirculation tank is fed to the pond feed tank
and the spent slurry is pumped to the onsite pond where the solids in the
slurry settle to form a sludge containing approximately 40% solids. Pond
supernate is recycled to the wet ball mills and the absorber effluent hold
tank to maintain closed-loop operation. A special case is evaluated in which
the spent slurry is pumped to a slurry dewatering system to produce a dis-
posal cake containing 60% solids; the cake is trucked to a disposal site
located 1 mile from the scrubbing facilities. Slurry dewatering includes
thickener and rotary drum filters. Overflow from the thickener is recycled
to the wet ball mills and to the absorber recirculation tanks.
A material balance for the base case limestone slurry scrubbing process
is shown in Table 18 and a detailed equipment list by area for the system is
presented in Table 19.
Major Process Areas
The limestone slurry process is divided into the following operating
areas.
1. Materials handling. Facilities for receiving raw limestone, a storage
stockpile, and in-process limestone storage are included in this area.
2. Feed preparation. This area includes the equipment for converting
raw limestone to a 70% minus 200 mesh, 60% solids slurry for feed to
the scrubbers.
3. Gas handling. Included in this area is one inlet flue gas plenum
interconnecting each of the four flue gas ducts which feed the absorb-
ers and four FD fans which overcome the pressure drop in the FGD
systems.
4. S02 absorption. Four mobile-bed absorbers with presaturators, recir-
culation tanks, and pumps are included.
5. Stack gas reheat. Equipment in this area includes indirect steam
reheaters and soot blowers for the coal variations. The oil-fired
unit is designed with one direct oil-fired reheater per duct which
discharges hot combustion gases directly into the duct.
6. Solids disposal. Equipment in this area consists of one pond feed
tank with agitator and pond feed and pond return pumps.
Storage Capacity
Storage requirements for raw materials and allowances for in-process
streams are listed below.
42
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Raw materials:
Limestone storage - 30 days stockpile
In-process storage:
Crusher feed bin - 8 hours
Mills product tank - 20 minutes
Slurry feed tank - 8 hours
Pond feed tank - 15 minutes
Recirculation tanks - 10 minutes each (includes sufficient surge
capacity for shutdown of scrubbers)
Solids Disposal
In the case variations which dispose of FGD waste solids by ponding,
spent slurry containing 15% solids is pumped from an agitated pond feed tank
to a disposal pond located 1 mile from the scrubbing facilities where the
calcium salts settle to a sludge containing 40% solids. For the base case
(500-MW, new, 3.5% sulfur, coal-fired unit), the field line transporting
slurry to the pond is a 12-inch rubber-lined, carbon steel pipe. A spare
field line to the pond is included and both lines are trenched. The recycle
pond waterline for the base case is 10 inches, unlined, carbon steel pipe;
no spare is included.
Pond Construction—
Optimum pond dimensions and costs for each case are calculated by com-
puter based on a square configuration with a diverter dike three-fourths the
length of a side. A pond construction diagram is shown in Figure 5. Assumin
level land for the pond site, total pond depth for base case is 19.6 feet
with an excavation depth of 3.0 feet. The pond is lined with 12 inches of
impervious clay assumed to be excavated at the site. Pond areas for each
case variation are listed in Table 20.
Trucking Alternative—
A case variation has been prepared on base case conditions which pro-
duces a filter cake disposed of by piling. A thickener and rotary drum fil^
ters which dewater the slurry to a 55% solids cake are added to the system
after the pond feed tank (now the thickener feed tank). The cake is moved
by conveyor to an in-process waste pile where wheeled loaders transfer the
solids to dump trucks for transport to a disposal area 1 mile from' the
scrubbing facilities. Assuming level land, the disposal site is scraped
to clay base and a ditch 10 feet wide and 10 feet long is dug around the
perimeter of the site runoff to the ash pond. Waste solids are piled 30
feet high using a grader, a dozer^ and a towed roller.
A detailed description of the economics of lime-limestone waste dis-
posal has been published (Barrier, et al., 1978).
43
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TABLE 18. LIMESTONE SLURRY PROCESS
MATERIAL BALANCE - BASE CASE
Stream No.
Description
J
2
)
4
^
6
/
8
9
1°
Total stream, Ib/hr
sftj/min (60°F)
Temperature, °F
Pressure, psix
epm
Specific gravity
M
Undlssolved solids, %
1
Coal to boiler
428,600
2
Combustion air
to air heater
4,546,200
1,005,000
80
3
Combustion
air to boiler
4,101,800
906,700
535
4
Gas to
economizer
4,516,100
958,000
890
5
Gas to air
heater
4,516,100
958,000
705
Stream No.
Description
1
2
1
i,
5
f>
7
8
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psiR
Rpm
Specific gravity
oH
Undissolved solids, %
6
Gas to
electrostatic
precipitator
4,960,400
1,056,000
300
7
Gas to
presaturator
4,905,800
1,056,000
300
8
Gas to reheater
5,108,100
1,127,200
127
9
Gas to stack
5,108,100
1,129,000
175
10
Steam to
reheater
93,070
470
500
Stream No.
Description
1
2
1
4
5
d
/
H
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
PH
Undissolved solids, X
11
Recycle slurry
for saturation
2,803,900
5,094
1 . 1
5.3
15
12
Makeup water
to absorber
292,100
5S4
13
Recycle slurry
to absorber
35,023,500
63, 458
1.1
5.3
15
14
Overflow to
pond feed tank
360,000
654
1.1
15
15
Slurry to pond
360,000
654
1.1
15
Stream No.
Description
1
2
1
k
i
fi
/
H
9
10
Total streanij Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psis
Kpm
Specific gravity
PH
Undissolved solids , %
16
Settled sludge
135 ,000
205
1.32
40
17
Pond water to
wet ball mill
26,400
53
18
Pond water to
recirculation
tank
198.600
397
19
Limestone to
weigh feeder
45.200
20
Slurry to mills
product tank
71.600
89
1.61
60
(continued)
44
-------
TABLE 18 (continued)
Stream No.
Description
2
1
tt
r}
h
7
K
<»
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psie
gpm
Specific gravity
PH
Undissolved solids, %
21
Limestone
slurry to
recirculation
tank
71,600
89
1.61
60
7
8
9
iO
K
9_
10
9
To"
45
-------
TABLE 19. LIMESTONE SLURRY PROCESS
BASE CASE EQUIPMENT LIST DESCRIPTION AND COST
Area
1.
2.
3.
1 — Materials
Car
Car
Item
shaker
puller
Hand ling
No.
1
1
Hopper, limestone 1
Description
Top
25
12
mounting
hp
ft
with 5
with
crane
hp return
x 20 ft x 2
ft bottom,
Total
cost
9
50
9
material
, 1979 $
,000
,000
,300
unloading
4. Feeder, limestone 1
unloading
5. Conveyor, 1
limestone
unloading
6. Conveyor, 1
limestone
stocking (incline)
7. Conveyor, 1
limestone stocking
8. Tripper 1
9. Mobile equipment 1
10. Hopper, reclaim 2
11. Feeder, live 2
limestone storage
12. Pump, tunnel sump 1
13. Conveyor, live
limestone feed
14. Conveyor, live
limestone feed
(incline)
20 ft deep, 4,800 ft3, carbon
steel
Vibrating pan 42 in. wide x 4,800
60 in. long, 3 hp, 250 tons/hr
Belt 36 in. wide x 10 ft long, 2,200
5 hp, 250 tons/hr, 130 ft/min
Belt 36 in. wide x 320 ft long, 48,000
30 hp, 15° slope, 250 tons/hr,
130 ft/min
Belt 36 in. wide x 200 ft long, 30,000
7-1/2 hp, 250 tons/hr, 130 ft/min
5 hp, 30 ft/min 14,800
Scraper tractor, 22 to 24 yd3 181,000
capacity
7 ft x 7 ft, 4 ft deep, 60° 11,200
slope, carbon steel
Vibrating pan 24 in. wide x 7,000
40 in. long, 1 hp, 12 tons/hr
Vertical, 60 gpm, 70 ft head, 3,400
5 hp, carbon steel, neoprene
lined
Belt 30 in. wide x 100 ft long, 14,400
2 hp, 100 tons/hr, 60 ft/min
Belt 30 in. wide x 190 ft long, 26,600
5 hp, 35 ft lift, 100 tons/hr,
60 ft/min
(continued)
46
-------
TABLE 19 (continued)
Item
No.
Description
Total material
cost, 1979 *
15. Elevator, live
limestone feed
16. Bin, crusher feed 1
17. Dust collecting
system
18. Dust collecting
system
19. Dust collecting
system
Subtotal
Continuous, bucket, 12 in. x 30,8OO
8 in. x 11-3/4 in., 20 hp,
75 ft lift, 100 tons/hr, 160
ft/min
17 ft dia x 17 ft high, w/cover, 13,800
3/8 in. carbon steel
Cyclone, 2,100 aft3/min, motor 5,90Q
driven fan
Cyclone, 6,200 aft^/min, motor 14,20Q
driven fan
Bag filter, polypropylene bag,
14,400 aftVmin, automatic shaker
system (1/2 cost in feed prepara-
tion area)
Area 2—Feed Preparation
Item No.
Description
Total material
cost, 197Q
1. Feeder, limestone 2
bin discharge
2. Feeder, crusher 2
3. Crusher
4. Ball mill
Ball charge
5. Hoist
6. Tank, mills
product
Lining
Vibrating, 12 tons/hr, w/cover,
carbon steel
Weigh belt, 18 in. wide x 14 ft
long, 1-1/2 hp, 12 tons/hr
Gyratory, 0 x 1-1/2 to 3/4 in.,
50 hp, 12 tons/hr
Wet, open system, 8 ft dia x 13
ft long, 350 hp, 300 tons/day
Electric, 5 ton
9 ft dia x 5 ft high, 2,350 gal,
open top, four 9 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining
(continued)
47
393,100
31,100
8,300
1,300
1,100
-------
TABLE 19 (continued)
Item
No.
Description
Total material
cost, 19/9 $
7. Agitator, mills
product tank
8. Pump, mills pro-
duct tank
9. Tank, slurry feed 1
Lining
10. Agitator, slurry
feed tank
11. Pump, slurry feed
tank
12. Dust collecting
system
13. Dust collecting
system
Subtotal
36 in. dia, 10 hp, neoprene 12,000
coated
Centrifugal, 89 gpm, 60 ft head, 5,400
7-1/2 hp, carbon steel, neoprene
lined
18 ft dia x 22 ft high, 42,800 gal, 10,500
open top, four 18 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining 9,800
3 turbines, 72 in. dia, 75 hp, 58,000
neoprene coated
Centrifugal, 89 gpm, 60 ft head, 5,400
7-1/2 hp, carbon steel, neoprene
lined
Cyclone, 8,200 aft3/min, motor- 16,300
driven fan
Bag filter, polypropylene bag, 10.000
14,400 aftVmin, automatic shaker
system (1/2 cost in materials
handling area)
634,000
Area 3—Gas Handling
Item
No.
Description
Total material
cost, 1979 $
1. Fans
Subtotal
Forced draft, 13 in. static head, 812,000
890 rpm, 1,250 hp, fluid drive,
double width, double inlet
812,000
(continued)
48
-------
TABLE 19 (continued)
Area 4—SO? Absorption
Item
No.
Description
Total material
cost. 197Q $
1. SC>2 absorber
2. Tank, recir-
culation
Lining
Mobile-bed scrubber, 31 ft long 2,813,7oo
x 14 ft wide x 40 ft high, 1/4 in.
carbon steel, neoprene lining; 316
SS grids, nitrile foam spheres,
FRP spray headers, 316SS chevron
vane entrainment separator
34 ft dia x 26 ft high, 173,500 gal, 85,6QO
open top, four 34 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lined 79 gOft
3.
4.
5.
6.
7.
Area
1.
2.
Agitator, recir-
culation tank
Pump, presatu-
rator
Pump , makeup
water
Pump, slurry
recirculation
Soot blowers
Subtotal
5 — Reheat
Item
Reheater
Soot blowers
Subtotal
4 100 in. dia, 50 hp, neoprene
coated
6 Centrifugal, 1,274 gpm, 105 ft head
75 hp, carbon steel, neoprene lined
2 Centrifugal, 1,168 gpm, 150 ft head
75 hp, carbon steel
10 Centrifugal, 7,954 gpm, 105 ft head
500 hp, carbon steel, neoprene
lined
40 Air, retractable
No. Description
4 Steam, tube type, 3,600 ft2, one-
half tubes made of Inconel 625
and one-half made of Cor-Ten
20 Air, retractable
(continued)
49
185,600
58,000
15,3QO
294,000
-160,000
3,792 O0o
Total material
cost, 197o *
z— = 2__2,
856,000
J^OOQ
986,Q<>0
-------
TABLE 19 (continued)
Area 6—Solids Disposal
Item
No.
Description
Total material
cost. 1979 $
1. Tank, pond feed
Lining
2. Agitator, pond 1
feed tank
3. Pumps, pond feed 2
4. Pumps, pond
return
Subtotal
12 ft dia x 15 ft high, 12,700 gal,
open top, four 12 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining
2 turbines, 66 in. dia, 15 hp,
neoprene coated
Centrifugal, 654 gpm, 100 ft head,
50 hp, carbon steel, neoprene lined
Centrifugal, 450 gpm, 100 ft head,
30 hp, carbon steel
4,100
3,700
19,500
12,800
6,900
47,000
50
-------
OUTER BOUNDARY
OF PONO AREA
GROUND LEVEL I
10% FREE BOARD
PONO PERIMETER DIKE
TOP9OL EXC/W4T1ON
(I FT)
Z
*• ei
DEPTH OF SLUDGE
_1_ TOTAL
EXCAVATION DEPTH
T
SUBSOIL EXCAVATION
TOPSC*. EXCAVATION
(i FT. )
ORGINAL GROUND LEVEL
SUBSOIL EXCAVATION
POND DIVERTER DIKE
10% FREE BOARD
(TYP OTHER SIDE)
DEPTH OF SLUDGE
i. TOTAL
EXCAVATION DEPTH
Figure 5. Pond construction diagram.
-------
TABLE 20. LIMESTONE SLURRY PROCESS
ACREAGE REQUIRED FOR WASTE SOLIDS DISPOSAL
Years
remaining
Case life Acres
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 79
200 MW N 3.5% sulfur 30 142
500 MW E 3.5% sulfur 25 227
500 MW N 2.0% sulfur 30 155
500 MW N 3.5% sulfur 30 287
500 MW N 5.0% sulfur 30 424
1,000 MW E 3.5% sulfur 25 383
1,000 MW N 3.5% sulfur 30 480
Solids disposal by trucking
500 MW N 3.5% sulfur 30 96
90% S02 removal; onsite solids
disposal (ponding)
500 MW N 3.5% sulfur 30 329
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 110
GENERIC DOUBLE-ALKALI PROCESS
The double-alkali process included in this study (Figure 6) has been
generalized from the several processes currently available in the United
States. In this design, an ESP is used for removal of fly ash and a common
plenum and booster fans are included downstream from the ESP and the power
plant ID fans for distribution of the gas (Figure 7).
Flue gas is cooled and saturated in a presaturator with a recycle stream
of scrubber effluent. In the absorber tower S02 is removed using a mixture
of a regenerated sodium sulfite solution and recycle scrubber effluent
(pH about 6.0). The outlet gas from the scrubber passes through a chevron-
type entrainment separator with provisions for upstream wash with fresh
makeup water. The cleaned flue gas is reheated to 175°F by indirect steam
heat before entering the stack.
-------
Ln
UJ
Flfcur* 6.
-------
PRESATURATOR
PUMPS
BLEED STREAM
PUMPS
"D
n
STACK
PLENUM
DAMPER (TYP
WHERE SHOWN )
ELECTROSTATIC
PRECIPITATORS
POWER PLANT
ID FANS
ABSORBER SYSTEM
FD FANS
LIQUOR RECIRCULATION
PUMPS
PLAN
EXPANSION
JOINT I TYP
WHERE SHOWN I
INDIRECT STEAM
REHEATER
-AIR
PREHEATER
POWERHOUSE
ELECTROSTATIC
PRECIPITATOR
STACK
PLENUM
POWER PLANT
I D FAN
ABSORBER SYSTEM PUMP RECIRCULATION
FD FAN TANK
ELEVATION
Figure 7. Generic double-alkali process. Perforated-tray scrubber system
base case plan and elevation.
54
-------
Incoming pebble lime, from an across-the-fence limestone calcination
plant, is received in a silo with a 10-day capacity and conveyed to two 4-houi
feed bins that supply the slakers (Figures 8 and 9). The lime is processed
in two parallel slakers to a slurry concentration of 15% solids. A slurrv
feed tank with a residence time of 8 hours is provided for in-process sto
Lime slurry is reacted with a bleedstream of absorber effluent in
tated tanks. The reaction product, predominately calcium sulfite, is
to a thickener where the slurry is concentrated to 25% solids. This
is further dewatered using drum filters to produce a cake of about 55%
The filter is designed with two wash sections to minimize sodium loss. TH
filter cake is reslurried to 15% solids with supernate from the pond and ^
makeup water for pumping to disposal. The solids settle to a concentratl
of approximately 40% in the pond. A special case is evaluated in which *
spent slurry, after thickening and filtering, is trucked to a disposal
located 1 mile from the scrubbing facilities.
Makeup soda ash is pneumatically conveyed from a rail hopper car"" to K
storage silo and fed to an agitated tank where it is slurried in fresh
thick-
The slurry is added to the regenerated scrubber liquor at the " ^^
ener overflow storage tank.
The material balance for the base case double-alkali system is shown
in Table 21 and a detailed equipment list by area for the system is pre«
in Table 22. aent«*
Major Process Areas
The generic double-alkali process has been divided into the follow!
operating areas. 8
1. Materials handling. This area includes facilities for receiving
pebble lime from an across-the-fence limestone calcination plant
lime storage silo, and in-process storage for supply to the slake
Soda ash storage is also provided. *"*<•
2. Feed preparation. Included in this area are two parallel slakin
systems and the facilities for dissolving makeup soda ash in wate
before feeding to the absorption system. *
3. Gas handling. Fan location and duct configuration is the same as
the limestone slurry process.
4. S02 absorption. Four tray tower absorbers with presaturators,
culation tanks, and pumps are included. '
5. Stack gas reheat. Equipment in this area includes indirect steam
reheaters and soot blowers for the coal variations. The oil-fir
unit is designed with one direct oil-fired reheater per duct whi w
discharges hot combustion gases directly into the duct.
55
-------
6. Reaction. Reaction tanks with agitators and pumps are provided in
this area.
7. Solids separation. Separation of calcium salts is accomplished by
thickener and filters.
8. Solids disposal. Filter cake is reslurried in this area and purged
to the disposal pond. A pond return pump is included.
Storage Capacity
Storage requirements for raw materials and allowances for in-process
streams are listed below.
Raw materials:
Lime storage silo - 10 days (from across-the-fence calcination plant)
Soda ash storage silo - 4 months (purchased in bulk quantity by rail)
In-process storage:
Lime feed bins - 4 hours each
Slaker product tank - 5 minutes
Slurry feed tank - 8 hours
Soda ash solution tank - 8 hours
Recirculation tanks - 10 minutes each (includes sufficient surge
capacity for shutdown of scrubbers)
Thickener - 4 hours
Thickener overflow storage tank - 20 minutes
Filter cake reslurry tank - 5 minutes
Solids Disposal
Waste solids in the generic double-alkali process are handled in the
same manner as the limestone slurry process.
Pond Construction—
Pond designs are similar to the design for the limestone slurry process.
Total pond depth for the base case is 18.9 feet and excavation depth is 3.1
feet. Pond areas for each case variation are listed in Table 23.
Trucking Alternative--
Transport of waste solids by truck to a disposal area is similar to the
method used for the limestone process.
56
-------
SLAKERS
Ol
ENCLOSED
CONVEYOR
ENCLOSED
CONVEYOR
LIME FEED
BINS
ENCLOSED
CONVEYOR
ELEVATOR
-ENCLOSED
CONVEYOR
LIME STORAGE
SILO
SLAKER PRODUCT
TANK
SLURRY FEED
TANK
-------
COAL
STORAGE
cc
UJ
ROAD
Figure 9. Generic double-alkali process. Base case overall plot plan.
cc.
58
-------
TABLE 21. GENERIC DOUBLE-ALKALI PROCESS
MATERIAL BALANCE - BASE CASE
1
2
i
h
/
~
-------
TABLE 21 (continued)
Stream No.
Description
|
2
1
lt
5
h
1
X
9
10
Tnt-al ^t-rp
-------
TABLE 22. GENERIC DOUBLE-ALKALI PROCESS
BASE CASE EQUIPMENT LIST DESCRIPTION AND COST
Area 1—Materials Handling
Item
No.
Description
Total material
cost* 197Q $
1. Conveyor, lime
storage
(enclosed)
2. Elevator, lime
storage
3. Silo, lime
storage
4. Feeder, reclaim
5. Conveyor, live
lime feed
6. Elevator, live
lime feed
7. Bin, lime
feed
8. Conveyor, soda
ash storage
9. Silo, soda ash
storage
1 Belt, 24 in. wide x 1,500 ft 169,9QQ
long, 30 hp, 100 tons/hr,
150 ft/min
1 Continuous, bucket 16 in. x 8 102,900
in. x 11-3/4 in., 75 hp, 120 ft
lift, 100 tons/hr, 160 ft/min
1 46 ft dia x 69 ft high, 109,000 75,9QO
ft3, cone bottom, 3/8 in. carbon
steel
1 Vibrating pan, 3-1/2 hp, 40 tons/hr 12,2OQ
1 Belt, 18 in. wide x 100 ft long, 9,30Q
2 hp, 40 tons/hr, 100 ft/min
1 Continuous, bucket 11 in. x 6 in. 56,OOO
x 8-3/4 in., 50 hp, 50 ft lift,
40 tons/hr, 160 ft/min, with
diverter gate
2 10 ft dia x 15 ft high, 1,180 ft3, 5,40O
w/cover, carbon steel
1 Pneumatic, vacuum, 40 hp 65,OOO
15 ft dia x 30 ft high, 5,850 ft3, 9,200
cone bottom, carbon steel
10.
Vibrators
Dust collecting
system
Subtotal
4
1 Bag filter, polypropylene bag,
8,800 aft3/min, automatic shaker
system
6,100
21,400
533,300
(continued)
61
-------
TABLE 22 (continued)
Area
1.
2.
3.
4.
5.
2 — Feed Preparation
Item No.
Feeder, lime 2
bin discharge
Feeder, slaker 2
S laker 2
Tank, slaker 2
product
Lining
Agitator, slaker 2
Description
Vibrating, 3-1/2 hp, carbon steel
Screw, 12 in. dia x 12 ft long,
1 hp, 5 tons/hr
6 ft wide x 28 ft long, 10 hp
slaker, 2 hp classifier, 5 tons/hr
7 ft dia x 6 ft high, 1,730 gal,
open top, four 7 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining
30 in. dia, 5 hp, neoprene coated
Total material
cost, 1979 $
9,200
12,000
108,000
2,100
1,700
17,500
product tank
6. Pump, slaker
product tank
7. Tank, slurry
feed
Lining
8. Agitator, slurry 1
feed tank
9. Pump, slurry 2
feed tank
10. Feeder, soda 1
ash silo discharge
11. Feeder, soda ash 1
solution tank
12. Tank, soda ash 1
solution
Lining
Centrifugal, 140 gpm, 100 ft head, 8,700
7-1/2 hp, carbon steel, neoprene
lined
24 ft dia x 36 ft high, 122,000 gal, 18,500
open top, four 24 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining 17,500
2 turbines, 96 in. dia, 50 hp, neo- 46,600
prene coated
Centrifugal, 279 gpm, 100 ft head, 6,700
15 hp, carbon steel, neoprene lined
Rotary air lock, carbon steel 2,500
Weigh 5,400
12 ft dia x 14 ft high, 11,850 gal, 3,900
open top, four 12 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining 3,500
(continued)
62
-------
TABLE 22 (continued)
Item
No.
Description
Total material
_costii979 $
13. Agitator, soda
ash solution tank
14. Pump, soda ash
solution tank
Subtotal
48 in. dia, 15 hp, neoprene
coated
20 gpm, 60 ft head, 1 hp, carbon
steel, neoprene lined
^,500
Area 3—Gas Handling
Item
No.
Description
Total
material
1. Fans
Forced draft, 8 in. static head,
700 rpm, 850 hp, fluid drive,
double width, double inlet
Subtotal
Area 4—SO^Absorption
Item
No.
Description
1. SC>2 absorber
2. Tank, recircu-
lation
Lining
3. Agitator, recir-
culation tank
4. Pump, presat-
urator
5. Pump, liquor
recirculation
Tray tower, 31 ft dia x 40 ft high,
3/8 in. carbon steel, flake-
lined; 1-316 SS sieve tray, 316
SS nozzles, polypropylene chevron
vane entrainment separator
28 ft dia x 30 ft high, 137,350
gal, open top, four 28 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining
108 in. dia, 25 hp, neoprene
coated
Centrifugal, 1,274 gpm, 105 ft head,
75 hp, carbon steel, neoprene lined
Centrifugal, 1,274 gpm, 105 ft head,
75 hp, carbon steel, neoprene lined
(continued)
63
76.0OO
71.200
58
ooo
58,OOt>
-------
TABLE 22 (continued)
6.
7.
8.
Area
1.
2.
Area
1.
2.
3.
_ i
Item No.
Pump, bleed to 6
reaction
Pump , makeup 2
water
Soot blowers 40
Subtotal
5~Reheat
Item No.
Reh eater 4
Soot blowers 20
Subtotal
6~Reaction Tanks
Item No.
Tank, reaction 2
Lining
Agitator, reaction 2
tank
Pump, reaction 2
tank
Subtotal
Description
Centrifugal, 887 gpm, 100 ft head,
60 hp, carbon steel, neoprene lined
Centrifugal, 1,000 gpm, 150 ft
head, 60 hp, carbon steel
Air, retractable
Description
Steam, tube type, 3,600 ft2,
one-half tubes made of Inconel
625, and one-half made of Cor-Ten
Air, retractable
Description
26 ft dia x 15 ft high, 59,570
gal, open top, four 26 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining
100 in. dia, 25 hp, neoprene
coated
Centrifugal, 3,726 gpm, 50 ft head,
100 hp, carbon steel, neoprene
lined
(continued)
64
Total material
cost, 1979 $
40,200
12,000
260,000
4,006,000
Total material
cost, 1979 $
856,000
130,000
986,000
Total material
cost, 1979 $
20,600
18,800
56,600
31,200
127,200
-------
TABLE 22 (continued)
Area 7—Solids Separation
Item
No.
Description
Total material
COStT 1070 $
1. Thickener
Rake motor and
mechanism
2. Pump, underflow
slurry
3. Tank, thickener 1
overflow storage
Lining
Agitator, thick-
ener overflow
storage tank
Pump, scrubbing
liquor return
6. Filter
7. Pump, filter
wash water
8. Conveyor,
filter cake
Subtotal
Stainless steel tank, 140 ft dia
x 8 ft high; concrete basin, 4 ft
high
7-1/2 hp
Centrifugal, 271 gpm, 100 ft head,
20 hp, carbon steel, neoprene
lined
33 ft dia x 15 ft high, 96,000 gal,
open top, four 33 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining
132 in. dia, 25 hp, neoprene coated
Centrifugal, 955 gpm, 125 ft head,
60 hp, carbon steel, neoprene
lined
Rotary vacuum, 12 ft dia x 14 ft
face, 20 total hp
240 gpm, 80 ft head, 15 hp, carbon
steel
Belt, 18 in. wide x 100 ft long,
5 hp, 40 tons/hr, 100 ft/min
H2.900
422,000
9,300
28,500
6QO
251,300
(continued)
65
-------
TABLE 22 (continued)
Area 8—Solids Disposal
Item
No.
Description
Total material
cost, 1979 $
1. Tank, filter
cake reslurry
2.
Lining
Agitator, filter 1
cake reslurry tank
3. Pump, pond feed
4.
Pump, pond
return
Subtotal
7 ft dia x 10 ft high, 2,700 gal,
open top, four 7 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining
30 in. dia, 7-1/2 hp, neoprene
coated
Centrifugal, 508 gpm, 110 ft head,
50 hp, carbon steel, neoprene lined
Centrifugal, 349 gpm, 110 ft head,
25 hp, carbon steel, neoprene lining
1,600
1,400
11,700
12,400
9,900
37,000
66
-------
TABLE 23. GENERIC DOUBLE-ALKALI PROCESS
ACREAGE REQUIRED FOR WASTE SOLIDS DISPOSAL
Years
remaining
Case life Acres
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 64
200 MW N 3.5% sulfur 30 116
500 MW E 3.5% sulfur 25 187
500 MW N 2.0% sulfur 30 127
500 MW N 3.5% sulfur 30 233
500 MW N 5.0% sulfur 30 329
1,000 MW E 3.5% sulfur 25 315
1,000 MW N 3.5% sulfur 30 393
Solids disposal by trucking
500 MW N 3.5% sulfur 30 87
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 260
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 97
67
-------
CITRATE PROCESS
The citrate process design developed for this study (Figure 10) is
adapted from a U.S. Bureau of Mines process and represents the state of tech-
nology in 1977. The demonstration program for the Bureau of Mines citrate
process has been in active development during the time for preparation of
this report. Certain features of the demonstration design which are signif-
icantly different from the process design represented here have been identi-
fied under Major Process Areas.
The scheme evaluated assumes fly ash removal by ESP, Power plant ID
fans feeding a common plenum and booster FD fans are included in the design
(Figure 11). Flue gas is cooled and saturated in a presaturator with recycle
liquor from the bottom of the scrubber. S02 is removed from the flue gas by
countercurrent scrubbing in a packed tower using a regenerated solution con-
taining sodium citrate as a buffer. A purge stream to control chlorides is
pumped from the bottom of the absorber through an SC>2 stripper to a neutrali-
zation tank where it is reacted with lime before being pumped to the ash dis-
posal pond. Stripped SC>2 is returned to the absorption tower at the presat-
urator. Cleaned flue gas is passed through a chevron-type entrainment
separator with provisions for upstream wash with fresh makeup water and
reheated to 175°F by indirect steam heat before entering the stack.
Elemental sulfur is precipitated from the S02~laden sorbent in reduction
tanks by countercurrent contact with I^S gas containing 80% to 97% t^S. The
sulfur is separated by air flotation, then melted and settled from the slurry
liquor in a decanter operating at a pressure of about 35 psig (Figure 12).
Storage is provided for the molten sulfur before marketing.
Hydrogen from natural gas or other sources and a portion of the molten
product sulfur from the decanter are feedstocks for l^S generation. The
system guards against l^S escape in the reduction step by returning unreacted
H- S to the boiler for incineration and by neutralizing dissolved I^S down-
stream from the reducing tanks with a small stream of S02~rich liquor from
the absorber (5% of the absorber effluent).
About 2% of the absorbed S02 is oxidized in the system to sodium sulfate.
This sulfate, along with the sulfate formed from absorption of 803 in the
flue gas and thiosulfate decomposition during the sulfur melting step, is
removed from the recirculated sorbent by crystallization as Glauber's salt
(NaoSC-A' 10H20), which is disposed of in the fly ash pond. Liquor from the
flotation tank is filtered to remove remaining sulfur particles before
cooling and crystallizing. The sulfate crystals are separated by centrifuge
and the liquor is returned to the system. Sodium and citrate losses are
replaced by adding a mixture of sodium hydroxide or sodium carbonate and
citric acid to the recycling sorbent.
The general layout (plot plan) for the citrate system is shown in
Figure 13. A material balance for the base case citrate scrubbing process
is shown in Table 24 and a detailed equipment list by area for the system
is presented in Table 25.
68
-------
JL
Figure 10. Citrate process. Base case flow diagram.
-------
AIR
COMPRESSOR
ELECTROSTATIC
PRECIPITATORS
POWER PLANT
ID FANS
• ABSORBER SYSTEM
FD FANS
PLAN
YJ.i^
/ ^ - - ^
V N
/
i i
1 1
1 '!
1 1
WHERE
STACK
PLENUM
ELEVATION
Figure
11. Citrate process.
elevation.
Packed-tower scrubber system base case plan and
70
-------
/-FLASH
1 DRUM
Figure 12. Citrate procew. Base CM« fulfur proc«a»lng area layout,
-------
COAL
STORAGE
c
ROAD
SERVICE
BLDG.
500MW UNIT
TURBINE
ROOM
BOILER
ROOM
FUTURE
FUTURE
ROAD
9[>§0
ROAD
or
Ul
Figure 13. Citrate process. Base case overall plot plan.
72
-------
TABLE 24. CITRATE PROCESS
MATERIAL BALANCE - BASE CASE
Stream No.
Description
1
2
1
S
h
8
<)
|fl
Total stream, Ib/hr
Temperature, °F
Pressure, psig
Kpm
Specific gravity
pH
Undissolved solids, %
1
Coal to boiler
428, 606
2
Combustion air
to air heater
4, 546,200
80
3
Combustion air
to boiler
4,101,800
535
4
Vented H2S gas
to boiler
660
128
!> ~j
Coal flue g-%
to atr he«t«r
Ji.Sl^.ftQQ •-•
~~ '
tfby.tfpq "—
il
1 — —
Stream No.
Description
I Total stream, Ib/hr
sft-S/min (60°F)
Temperature. °F
H2S flue gas
to air heater
300
Gas to
electrostatic
precipitator
4.961,100
1,056,300
Gas to
presaturator
1,056,300
300
Specific gravity
pH
Undissolved solids, %
Stre
Description
Total stream, Ib/hr
sftJ/min (60°F)
Recycle gas to
presaturator
4.770
1.060
-12-
Recycle liquor
to presaturator
2.614.100
Liquor from
presaturator
2,640,500
Makeup water
to presaturator
Liquor to
stripper
Pressure, psig
Undissolved solids,
Stream No.
16
Description
Liquor to
neutralization
Lime to
neutralization
Slurry to pond
Flue gas to
absorber
J_ Total stream. Ib/hr
5,091,501)
Scrubbing
liquor to
absorber
Specific gravity
Undissolved solids.
49
(continued)
73
-------
TABLE 24 (continued)
Stream No.
Description
2
1
4
5
h
7
ii
9
i°_
Total stream. Ib/hr
sftJ/min (60°F)
Temoerature. °F
Pressure. Dsi(^
eom
Scecific gravity
pH
Undlssolved solids, X
21
Absorber
effluent to
hold tank
3.545.000
6.440
22
Gas to
reheat er
5.097.200
1,126,500
127
23
Steam to
reheater
92,870
470
500
24
Gas to stack
5,097.200
1,128,300
175
25
Bypass liquor
177.300
322
Stream No.
Description
1
2
)
-4
5
(/
7
R
9
HL
Total stream, Ib/hr
sft'Vmin (60°F)
Temperature, UF
Pressure, psig
Spm
Specific gravity
j>H
Undissolved solids, X
26
Liquor to S02
reduction
3,368.800
6,120
27
HjS gas to
SC>2 reduction
22,115
3,990
130
28
Slurry from
S02 reduction
3,390,300
6,159
0 9
29
Return from
sulfur settler
41,760
30
Slurry to
flotation tank
3,609,300
6,558
Stream No.
Description
1
2
i
4
$
h
7
H
9
10
Total stream, Ib/hr
«ftJ/min (60°F)
Temoerature. F
pressure. nsiE
pom
{Specific eravitv
J>H
Undissolved solids, /.
31
Slurry to
melter
72,200
32
Sulfur from
melter
30,440
307
35
1.78
33
Sulfur to
storage
6,090
34
Sulfur to H2S
generators
24,355
35
Sulfur from
H2S generators
3,650
Stream No.
Description
1
" 2
1
4
•i
h
7
8
9
Total stream, Ib/hr
«ft3/min (60°F>
Tenroerature. °F
Pressure. DsiK
RP™
Soecific eravitv
oH
^dissolved solids, I
36
Sulfur to
shipment
9,735
37
Hydrogen to
H2S generator
1,350
4,150
38
Liquor to
cooler
35,450
65
39
Centrifuge
wash water
600
1
40
Glauber salts
to disposal
2,990
80
(continued)
74
-------
TABLE 24 (continued)
Stream No.
!
i
)
6
8
9
12.
Description
Pressure, psig
Specific gravity
PH
Undissolved solids, %
41-
Liquor recycle
to hold tank
60
Refrigerant to
crystallizer
38
4~14
1.07
43
Cooling H20 to
refrigeration
44
Citric acid to
makeup
solution tank
75
45 '"
Soda ash to
makeup
solution tank
8ff
8
9
1U.
Description
sft3/min (60°F)
Pressure, psig
_gpm
PH
Undissolved solids. %
Water to makeup
solution tank
To
Water to filter
*
Water to
absorber
Too
75
-------
TABLE 25. CITRATE PROCESS
BASE CASE EQUIPMENT LIST DESCRIPTION AND COST
Area 1—Materials Handling
Item
1. Conveyor, lime
unloading
2. Silo, lime
storage
3. Feeder, lime
storage silo
discharge
Description
Total material
cost, 1979 $
Belt, 12 in. wide x 200 ft 28,300
long, 3 hp, 10 tons/hr, 100 ft/min
20 ft dia x 35 ft high, 10,750 ft-\ 16,500
cone bottom, carbon steel
1 Rotary stargate, 1 hp, 5 tons/hr
4. Conveyor/elevator, 1
live lime feed
5. Bin, lime feed 1
Redler Z type, 100 ft long, 3 hp,
5 tons/hr
10 ft dia x 10 ft high, 785 ft3,
cone bottom, carbon steel
1,800
13,300
3,000
6.
7.
8.
Vibrators
Conveyor , soda
ash and citric
acid
Bin, soda ash
storage
Vibrators
Bin, citric
acid storage
Vibrators
Subtotal
2 3,000
1 Pneumatic, vacuum, 50 hp, 20 102,500
tons/hr
2 20 ft dia x 24 ft high, 7,540 ft3, 25,700
cone bottom, carbon steel
2 3,000
1 9 ft dia x 8 ft high, 510 ft3, 2,200
cone bottom, carbon steel
2 3,000
202,300
(continued)
76
-------
TABLE 25 (continued)
Area 2—Feed Preparation
Item
No.
Description
Total material
cost. 197Q $
1. Feeder, soda 2
ash bin discharge
2. Feeder, soda
ash makeup con-
veyor
3. Feeder, citric
acid bin discharge
4. Feeder, citric
acid makeup con-
veyor
Rotary stargate, 1/2 hp, 855 Ib/hr 1,600
Weigh belt, 14 in. wide x 5 ft 7,200
long, 1/2 hp, 855 Ib/hr, variable
speed
1 Rotary stargate, 1/2 hp, 75 Ib/hr
§00
Weigh belt, 14 in. wide x 5 ft 3
long, 1/2 hp, 75 Ib/hr, variable
speed
5.
6.
7.
8.
Area
1.
Conveyor, makeup
solution tank
Tank, makeup
solution
Lining
Agitator, makeup
solution tank
Pump, makeup
solution tank
Subtotal
3— Gas Handling
Item
Fans
1 Belt, 12 in. wide x 40 ft long,
1/2 hp, 1,000 Ib/hr, 100 ft/min
1 7 ft dia x 8 ft high, 2,300 gal,
open top, four 7 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining
1 30 in. dia, 7-1/2 hp, neoprene
coated
2 Centrifugal, 10 gpm, 50 ft head,
1 hp, carbon steel, neoprene lined
No. Description
4 Forced draft, 20 in. static head,
o "7 c i r\f\f\ i _ci • i i _ _*
4
1
1
11
__2
33
cost^
888
~
,200
,200
,200
,700
±300
i!QO_
material
-1979 J^
^000
double width, double inlet
Subtotal
(continued)
77
-------
TABLE 25 (continued)
Area 4—SOg Absorption
Item
No.
Description
Total material
cost, 1979 $
1. S02 absorber
2. Pump, absorber 2
makeup water
3. Pump, presatu- 6
rator liquor
4. Pump, presatu- 6
rator makeup
water
5. Stripper, chloride 4
purge
Packed tower, 25 ft dia x 45 ft
high, 5/8 in. carbon steel, FRP
lining, 316 SS distributor plate,
Inconel 625 spray header, 316 SS
chevron vane entrainment separator;
polypropylene cascade mini-ring
packing
Centrifugal, 100 gpm, 150 ft head,
10 hp, carbon steel
Centrifugal, 1,262 gpm, 75 ft head,
50 hp, carbon steel, neoprene lined
Centrifugal, 91 gpm, 150 ft head,
10 hp, carbon steel
Packed column, 4 ft dia x 30 ft
high, carbon steel
6,048,400
6. Compressor,
stripper air
7. Tank, effluent
hold
Lining
8. Agitator, effluent 4
hold tank
9. Pump, effluent 6
hold tank
Subtotal
1 1,000 ft3/min, 10 psig, 300 hp
Centrifugal, 1,610 gpm, 120 ft
head, 100 hp, carbon steel, neoprene
lined
4,000
38,400
12,000
64,800
71,400
14-1/2 ft dia x 14 ft high, 19,750 18,100
gal, open top, four 15 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining 17,500
58 in. dia, 15 hp, neoprene coated 76,200
59,700
6,410.500
(continued)
78
-------
TABLE 25 (continued)
Area 5—Reheat
Item
No.
Description
Total material
cost. 197Q $
1. Reheater
2. Soot blowers
Subtotal
4 Steam, tube type, 3,600 ft2, one-
half tubes made of Inconel 625
and one-half made of Cor-Ten
20 Air, retractable
856,000
986,000
Area 6—Chloride Purge
Item
No.
Description
Total material
cost. 197 Q $
1. Feeder, lime 1
feed bin discharge
2. Feeder, neutral!- 1
zation tank
3. Tank, neutraliza- 1
tion
Lining
4. Agitator, neutral-
ization tank
5. Pump, neutrali-
zation tank
Subtotal
Rotary stargate, 1/2 hp, 655 Ib/hr
Weigh belt, 14 in. wide x 5 ft
long, 1/2 hp, 655 Ib/hr, variable
speed
6 ft dia x 7-1/2 ft high, 1,530
gal, open top, four 6 in. baffles,
agitator supports, carbon steel
1/4 in. neoprene lining
24 in. dia, 7-1/2 hp, neoprene
coated
Centrifugal, 48 gpm, 150 ft head,
7-1/2 hp, carbon steel, neoprene
lined
800
7,100
1,000
900
6,300
(continued)
79
-------
TABLE 25 (continued)
Area 7—S°o Reduction
Item
1. Tank,
reduction (first)
Lining
2. Agitator, S02
reduction tank
3. Sparger, S02
reduction tank
4. Pump, transfer
5. Tank, S02
reduction
(second)
6.
7.
8.
Lining
Agitator, S02
reduction tank
SO,
Sparger,
reduction
Pump, sulfur
slurry
No.
Description
Total material
cost, 1979 $
9. Trap, reduction 1
tank offgas
10. Tank, aging 1
16 ft dia x 24 ft high, 36,100 12,400
gal, convex dish head top and
bottom, four 16 in. baffles,
agitator supports, carbon steel,
30 psig operating pressure
1/4 in. neoprene lining 10,000
2 turbines, 66 in. dia, 50 hp, 48,000
neoprene coated
5 ft dia ring of 10 in. schedule 5,900
40, 316 stainless steel
Centrifugal, 6,120 gpm, 60 ft head, 46,200
200 hp, carbon steel, neoprene
lined
16 ft dia x 24 ft high, 36,100 gal, 12,400
convex dish head top and bottom,
four 16 in. baffles, agitator
supports, carbon steel, 30 psig
operating pressure
1/4 in. neoprene lining 10,000
2 turbines, 66 in. dia, 50 hp, 48,000
neoprene coated
5 ft dia ring of 12 in. schedule 7,300
40, 316 stainless steel
Centrifugal, 6,540 gpm, 75 ft 52,200
head, 250 hp, carbon steel, neo-
prene lined
4 ft dia x 10 ft high, carbon steel, 1,500
neoprene lined
23 ft dia x 24 ft high, 74,600 gal, 17,300
convex dish head top and bottom,
four 23 in. baffles, agitator
supports, carbon steel, 30 psig
operating pressure
(continued)
80
-------
TABLE 25 (continued)
Item
No.
Description
Total material
cost. 197Q $
10. (continued)
Lining
11. Agitator, aging
tank
1/4 in. neoprene lining
1 92 in. dia, 30 hp, neoprene
coated
16,300
Subtotal
3^8^800
Area 8—Sulfur Separation and Removal
Item
No.
Description
1. Tank, flotation
2.
3.
Compressor,
flotation tank
air
5 5 ft wide x 20 ft long x 5 ft
deep, carbon steel, neoprene
lined; skimmer with 2 hp motor
1 1,000 ft3/min, 10 psig, 300 hp
Filter, flotation 10
tank underflow
4. Pump, filtrate
5. Tank, liquor
hold
Lining
6. Agitator, liquor
hold tank
7. Pump, scrubbing
liquor return
8. Pump, cooler
feed
Rotary vacuum, 12 ft dia x 14 ft
face, 20 total hp
Centrifugal, 1,500 gpm, 40 ft
head, 50 hp, carbon steel,
neoprene lined
20 ft dia x 30 ft high, 70,500
gal, closed top, four 20 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
2 turbines, 84 in. dia, 40 hp,
neoprene coated
Centrifugal, 1,590 gpm, 100 ft
head, 75 hp, carbon steel, neo-
prene lined
Centrifugal, 60 gpm, 50 ft head,
2 hp, carbon steel, neoprene lined
(continued)
81
71,400
6OO
38,400
!3,60Q
41,500
58,000
4,100
-------
TABLE 25 (continued)
Item
9. Tank, sulfur
slurry
Lining
10. Pump, sulfur
melter feed
11. Melter, sulfur
12. Tank, sulfur
settler
Insulation
Heater
13. Flash drum,
sulfur settler
14. Fan, vent line
exhaust
Subtotal
Area 9—Sulfur Storage
Item
1. Pit, sulfur
receiving
Insulation
Heater
Total material
No. Description cost, 1979 $
1 10 ft dia x 10 ft high, 5,900
gal, closed top, cone bottom,
carbon steel
1/4 in. neoprene lining
2 Screw type, 100 gpm, 160 ft head,
10 hp, 316 stainless steel
1 Shell and tube, 1,140 ft2, 316
stainless steel, insulated
1 9 ft dia x 13-1/2 ft long, convex
dish head top and bottom, 316
stainless steel
Fiberglass
1 Steam, 100 ft2, 316 stainless
steel
1 4 ft dia x 5-1/2 ft long, 316
stainless steel
1 1,000 ft3/min, 5 hp
and Shipping
No. Description
1 10 ft wide x 10 ft long x 10 ft
deep, w/cover, 304 stainless steel
Fiberglass
1 Steam, 100 ft2, 400 ft of 1 in.
2,900
2,600
7,900
59,900
10,900
2,100
2,600
1,700
700
1,644,600
Total mater
cost, 1979
10,400
2,500
2,500
iai
$
2. Pump, sulfur
transfer
schedule 40, 304 stainless steel
Submerged, high temperature,
15 gpm, 100 ft head, 1-1/2 hp,
316 stainless steel, steam
traced, insulated
(continued)
82
5,500
-------
TABLE 25 (continued)
Item
No.
Description
Total material
cost. 197Q $
3. Tank, sulfur
storage
Insulation
4. Heater
5. Pump, sulfur
shipping
Subtotal
43 ft dia x 41 ft high, 467,100
gal, closed top, 304 stainless
steel
Fiberglass
Steam, 300 ft2, 1,200 ft of 1 in.
schedule 40, 304 stainless steel
Submerged, high temperature, 60
gpm, 100 ft head, 5 hp, 316 stain-
less steel, steam traced, insulated
147,000
29,500
6.4OO
Area 10—Sulfate Purge
Item
No.
Description
1. Cooler, sulfate
purge stream
2. Pump, liquor
return
3. Crystallizer,
sulfate
Insulation
4. Agitator,
sulfate crystal-
lizer
5. Pump, centrifuge
feed
6. Centrifuge, sul- 1
fate purge
700 ft2, 316 stainless steel
Centrifugal, 60 gpm, 60 ft head,
2 hp, carbon steel, neoprene
lined
3 ft dia x 12 ft high, 4,500 gal,
closed top, four 8 in. baffles,
agitator supports, 200 ft2
cooling coil
Polyurethane foam
32 in. dia, 10 hp, neoprene coated
Centrifugal, 60 gpm, 60 ft head,
2 hp, carbon steel, neoprene
lined
Solid bowl, 36 in. dia x 84 in.
long, 200 hp, insulated
(continued)
83
35,800
11,200
1,400
12,000
4,100
-------
TABLE 25 (continued)
Item
7 . Conveyor , sul-
fate removal
8. Tank, centrate
surge
Lining
q Pump, centrate
No. Description
1 Belt, 12 in. wide x 20 ft long,
1 hp, 2,990 Ib/hr
1 7 ft dia x 7 ft high, 2,000 gal,
closed top, carbon steel
Neoprene lining
2 Centrifugal, 60 gpm, 60 ft head,
Total material
cost, 1979 $
3,900
1,200
800
4,100
return
10. Tank, refrigerant
surge
Insulation
11. Pump, cooling
water
12. Refrigeration
system
Sub total
2 hp, carbon steel, neoprene lined
8 ft dia x 6 ft high, 2,250 gal,
closed top, carbon steel
Polyurethane foam
Centrifugal, 247 gpm, 150 ft head,
20 hp, carbon steel
1 200 tons
1,300
800
5,800
47,000
309.600
ArpaM--HoS Generation
Item
No.
Description
Total material
cost, 1979 $
1. H2S generator
Subtotal
300 tons/day, battery limit,
installed cost
5,850,000
5,850,000
Area
12 — H? Generation
Item
No.
Description
Total material
cost, 1979 $
1. H2 generator
20 tons /day, battery limit,
installed cost
4,680,000
Subtotal
4,680,000
84
-------
Major Process Areas
The citrate process has been divided into the following operating areas'
1. Materials handling. Facilities for receiving and storing lime, soda
ash, and citric acid are included in this area. The solids handling
and storage equipment for crystalline citric acid is eliminated at
the demonstration plant by purchasing citric acid as a 50 weight ner-
cent liquid. Makeup citric acid solution is added in truckload batch*
directly to a liquor hold tank.
2. Feed preparation. This area includes facilities for producing a s 1 -
tion of makeup soda ash and citric acid.
3. Gas handling. Fan location and duct configuration are the same as
the limestone slurry process.
4. SQ2 absorption. Four packed- tower absorbers with presaturators
effluent hold tanks and pumps are provided. Also included are SO
strippers and air compressor. For this study a carbon steel absorh
with an FRP liner has been specified. Field applied flakeglass li ?«$
of the absorber is specified at the demonstration plant.
5. Stack gas reheat. Equipment in this area includes indirect steam
reheaters and soot blowers for the coal-fired cases. The
unit is designed with one direct oil-fired reheater per duct whi h
discharges hot combustion gases directly into the duct.
6. Chloride purge. This area includes facilities for neutralizing w*
lime a purge stream of presaturator liquor for the control of chl lit
buildup in the system.
7. S02 reduction. In this area, l^S gas contacts the SC>2-rich sorbe
in reduction (reactor) tanks to produce elemental sulfur. Both
transfer pump for circulating citrate solution between reactors
the sulfur slurry pump to feed solution containing sulfur cryst
to the flotation tank have been eliminated in the demonstration-
design by using gravity flow in a cascading elevation sequence
8. Sulfur separation and removal. Facilities are provided to separat-
sulfur particles from the slurry liquor and heat the sulfur to th *
molten state. Based on pilot plant operation data, filtration of
regenerated solution has been discontinued. Filtration of the r
erated solution was used in development work on the process but ^en"
not considered necessary in scaleup to demonstration plant maen1t- S
The absorber packing is considered sufficiently washed by soluti
so that sulfur and ash particles will not foul the system. The **
erated solution underflow from the flotation tank flows by
directly to the liquor hold tank.
85
-------
A flash system for letdown of pressure on the citrate solution leaving
the sulfur settler tank has not performed reliably in pilot plant
operation. When the citrate solution flashes to a reduced pressure,
sufficient water is vaporized to cause citrate sulfate crystals to
form in the flash system and cause plugging. The vapors leaving the
flash drum are corrosive and must be condensed in order to return to
the liquor hold tank. The Bureau of Mines system quenches the hot
solution before pressure letdown.
9, Sulfur storage and shipping. A receiving pit and sulfur storage tank
are provided in this area. A below-ground concrete pit or an insulated
carbon steel tank can be used for molten sulfur storage.
10. Sulfate purge. A purge stream of scrubbing liquor is routed to the
purge treatment area for removal of sodium sulfate from the system.
Equipment for the crystallization, separation, and removal of sodium
sulfate is included in this area. The Bureau of Mines demonstration
unit does not include filtration of the slipstream to the sulfate
purge area.
The unit uses an evaporative-cooled crystallizer system to chill the
purge stream to about 39°F which produces sodium sulfate decahydrate
crystals. The sulfate crystals are screened from the citrate solu-
tion. The residual solution removed with the crystals provides an
additional purge from the system of accumulated chlorides and entrained
solids.
11 H s generation. This area includes one complete l^S generation unit
with a capacity of 300 tons H2S per day. The Bureau of Mines system
uses an i^S generator developed and licensed by the Home Oil Company,
Ltd., of Canada. The generator design was adapted for use with the
Bureau of Mines citrate system in the pilot stage of process develop-
ment. The generator consumes natural gas, steam and molten sulfur to
produce a product gas containing about 78% l^S on a dry basis. Reduc-
tant gas feedstocks other than natural gas can be used. Propane, car-
bon monoxide, hydrogen, and methanol have been demonstrated. The
molten sulfur source is provided by inventory from the citrate process.
The generator is provided as a package plant.
12. Hogeneration. A 20-ton-per-day H2 generation unit using natural gas
as feedstock produces the required reducing gas for t^S production.
This area is combined with area 11 at the Bureau of Mines demonstra-
tion site.
Storage requirements for raw materials and allowances for in-process
streams are listed below.
86
-------
Raw materials:
Lime storage silo - 30 days
Soda ash storage bin - 10 days
Citric acid storage bin - 15 days
In-process storage:
Makeup solution tank - 4 hours
Effluent hold tank - 5 minutes
Neutralization tank - 30 minutes
S02 reduction tanks - 5 minutes each
Aging tank - 10 minutes
Liquor hold tank - 10 minutes
Product storage:
Sulfur storage tank - 30 days
Chloride Purge
Unlike the waste-producing processes which trap enough chloride in *-v
interstitial water of the settled sludge to maintain a steady-state chloride
concentration in the recycle liquor, chlorides in a recovery process can
build up over a period of time and thereby cause problems of product quaUt
and equipment corrosion. A purge is added to the citrate process to con.t ol
chloride buildup in the system. For this study it is assumed that the l-i
neutralized purge stream for chloride control is pumped to the fly ash T» *w4
for disposal. However, this method may be environmentally unacceptable -tf
seepage of calcium chloride from the ash pond contaminates underground o
nearby water sources. Although several methods of control such as speci
pond liners and reverse osmosis are available, the scope of this study
not include the evaluation of water treatment systems.
87
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ECONOMIC EVALUATION AND COMPARISON
Based on the design and economic conditions described in Design and
Economic Premises section and the material balance and equipment requirements
of each process detailed in Systems Estimated, capital investment and annual
and lifetime revenue requirements have been projected for the economic evalu-
ation and comparison of the three processes. All the possible design and
economic configurations, variations, and combinations encountered in site-
specific applications of these processes cannot be covered in this study.
However, it is expected that the procedures used in preparing this evaluation
are sufficiently discussed to allow adjustment of results to fit the many
possible applications.
CAPITAL INVESTMENT
Results
The projected capital investment estimates are calculated in 1979 dollars.
Three methods are used for displaying the results.
1. Total capital investment requirements - tabular investment results
for all case variations. For each of the three processes, a summary
table is presented listing the projected total capital investment
requirements for the case variations, expressed as total dollars and
dollars per kW (Tables 26-28).
2. Summary of estimated capital investment - summarized area costs for
all case variations studies. A summary of estimated capital invest-
ment is presented in the appendix for each of the projected case
variations.
3. Total capital investment requirements - base case process equipment
and installation analysis. Tables 29-31 show summarized area-by-area
equipment costs along with installation expense. For all three proc-
ess displays, these costs are itemized separately and displayed
according to the material and labor component of each. The area
analysis tables show the distribution of total investment as a percent
of direct investment.
88
-------
TABLE 26. LIMESTONE SLURRY PROCESS
TOTAL CAPITAL INVESTMENT SUMMARY3
Years
remaining Total capital
Case life investment. $ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 25,057,000 125.3
200 MW N 3.5% sulfur 30 25,461,000 127.3
500 MW E 3.5% sulfur 25 50,120,000 100.2
500 MW N 2.0% sulfur 30 39,641,000 79.3
500 MW N 3.5% sulfur 30 48,728,000 97.5
500 MW N 5.0% sulfur 30 54,621,000 109.2
1,000 MW E 3.5% sulfur 25 74,830,000 74.8
1,000 MW N 3.5% sulfur 30 71,423,000 71.4
Solids disposal by trucking
500 MW N 3.5% sulfur 30 42,307,000 84.6
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 50,437,000 100.9
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 38,400,000 77.0
a. Basis
Midwest plant location represents project beginning mid-
1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 175°F.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirements for fly ash removal and disposal
excluded; FGD process investment estimate begins with
common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime
pay incentive not considered.
89
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TABLE 27. GENERIC DOUBLE-ALKALI PROCESS
TOTAL CAPITAL INVESTMENT SUMMARY3
Years
remaining Total capital
Case life investment, $ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 26,006,000 130.0
200 MW N 3.5% sulfur 30 25,477,000 127.A
500 MW E 3.5% sulfur 25 53,675,000 107.4
500 MW N 2.0% sulfur 30 42,110,000 84.2
500 MW N 3.5% sulfur 30 50,551,000 101.1
500 MW N 5.0% sulfur 30 57,579,000 115.2
1,000 MW E 3.5% sulfur 25 85,487,000 85.5
1,000 MW N 3.5% sulfur 30 79,016,000 79.0
Solids disposal by trucking
500 MW N 3.5% sulfur 30 41,335,000 82.7
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 52,404,000 104.8
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 40,260,000 80.5
Basis
Midwest plant location represents project beginning mid-
1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 175°F.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirements for fly ash removal and disposal
excluded; FGD process investment estimate begins with
common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime
pay incentive not considered.
90
-------
TABLE 28. CITRATE PROCESS
TOTAL CAPITAL INVESTMENT SUMMARY3
Case
Years
remaining
life
Total capital
investment. $ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.5% sulfur
200 MW N 3.5% sulfur
500 MW E 3.5% sulfur
500 MW N 2.0% sulfur
500 MW N 3.5% sulfur
500 MW N 5.0% sulfur
1,000 MW E 3.5% sulfur
1,000 MW N 3.5% sulfur
90% S02 removal
500 MW N 3.5% sulfur
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW E 2.5% sulfur
20
30
25
30
30
30
25
30
30
38,788,000
38,075,000
72,605,000
58,098,000
71,639,000
82,572,000
109,024,000
106,589,000
74,624,000
193.9
190.9
145.2
116.2
143.3
165.1
109.0
106.6
149.2
25
52,442,000
104.9
a. Basis
Midwest plant location represents project beginning mid-
1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 175°F.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal
excluded; FGD process investment estimate begins with
common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime
pay incentive not considered.
91
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TABLE 29. LIMESTONE SLURRY PROCESS BASE CASE - DIRECT INVESTMENT -
PROCESS EQUIPMENT AND INSTALLATION COSTS (k$)
Direct Investment
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation
Railroads, roads, and pond
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Subtotal
Services, utilities, and miscellaneous
Total excluding pond construction
Pond construction
Total direct investment
Percent of total direct investment
Materials
handling
486
106
13
3
-
-
112
452
-
254
91
62
158
11
3
1
7
.
-
1,759
_
1,759
_
1,759
6.8
Feed Gas
preparation handling
634
104
181
88
-
-
55
212
-
-
-
92
176
66
16
1
8
39
68
1,740
_
1,740
_
1,740
6.7
812
78
-
-
1,562
1,187
12
51
-
-
19
195
347
46
8
.
1
-
.
4,318
_
4,318
_
4,318
16.6
S02 Stack gas Solids " direct
absorption reheat disposal Total investment
3,792 986
773 122
1,905 57
599 38
-
-
74
207
-
164
399
148 1
251 2
490 63
91 12
4
21 1
.
_
8,918 1,282
_
8,918 1,282
_
8,918 1,282
34.3 4.9
47
17
885
367
-
-
12
35
8
1
12
62
183
6
2
3
18
-
-
1,658
_
1,658
_
1,658
6.4
6,757
1,200
3,041
1,095
1,562
1,187
265
957
8
419
521
560
1,117
682
132
9
56
39
68
19,675
1, 180
20,855
5.145
26,000
26.0
4.6
11.7
4.2
6.0
4.6
1.0
3.7
-
1.6
2.0
2.2
4.3
2.6
0.5
-
0.2
0.2
0.3
75.7
4.5
80.2
19.8
100.0
7. of total
capital
investment
13.9
2.5
6.2
2.2
3.2
2.4
0.5
2.0
-
0.9
1.1
1.2
2.3
1.4
0.3
-
0.1
0.1
0.1
40.4
2.4
42.8
10.6
53.4
-------
vO
TABLE 30. GENERIC DOUBLE-ALKALI PROCESS BASE CASE - DIRECT INVESTMENT -
PROCESS EQUIPMENT AND INSTALLATION COSTS (k$)
Direct Investment
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation
Railroads, roads, and pond
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Subtotal
Services, utilities, and mi see 1 1 aneous
Total excluding pond construction
Pond construction
Total direct investment
Percent of total direct investment
handling
533
378
-
-
-
-
36
94
-
129
46
183
208
58
28
2
15
-
-
1,710
-
1,710
.
1,710
6.4
Feed
preparation
288
94
23
24
-
-
9
25
-
-
-
69
80
142
70
1
8
-
-
833
_
833
.
833
3.1
handling
752
68
-
-
1,562
1,187
12
51
-
-
19
195
347
46
8
-
1
-
-
4,248
_
4,248
.
4,248
15.9
absorption reheat
4,006 986
1,473 122
1,298 57
620 38
-
-
62
172
-
160
388
206 1
232 2
462 63
86 12
5
36 1
-
-
9,206 1,282
_
9,206 1,282
_
9,206 1,282
34.4 4.8
Reaction
127
75
22
19
-
-
8
22
-
14
6
13
38
7
3
2
1
-
-
357
_
357
_
357
1.3
Solids
separation
907
530
206
179
-
-
19
51
27
10
4
95
152
101
46
4
17
4
-
2,352
.
2,352
_
2,352
8.8
Solids
disposal
37
16
481
367
-
-
12
33
8
2
6
62
191
7
4
3
18
-
-
1,247
.
1,247
_
1,247
4.7
Total
7,636
2,756
2,087
1,247
1,562
1,187
158
448
35
315
469
824
1,250
886
257
17
97
4
.
21,235
1.274
22,509
4,241
26,750
7. of
investment
28.4
10.3
7.8
4.7
5.8
4.4
0.6
1.7
0.1
1.2
1.8
3.1
4.7
3.3
1.0
0.1
0.4
-
-
79.4
4.8
84.2
15,8
100.0
% of
investment
15.1
5.5
4.1
2.5
3.1
2.3
0.3
0.9
0.1
0.6
0.9
1.6
2.5
1.8
0.5
.
0.2
.
.
42.0
2.5
44.5
8.4
52.9
-------
TABLE 31. CITRATE PROCESS BASE CASE - DIRECT INVESTMENT -
PROCESS EQUIPMENT AND INSTALLATION COSTS (k$)
Direct Investment
Equipment
Material
Labor
Piping and Insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation
Railroads, roads, and pond
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Battery limits
Subtotal
Services, utilities, and miscellaneous
Percent of total direct Investment
202
116
-
-
-
-
24
64
-
52
32
61
114
57
31
4
13
_
_
770
_
2.1
34
9
3
7
-
-
2
4
-
2
1
11
19
19
11
1
5
3
I
132
_
0.1
BBS
92
-
-
1,406
1,068
6
15
-
12
7
276
268
37
17
_
1
.
_
4,093
_
11.1
6,410
2,105
1,040
960
-
-
78
212
-
380
170
91
259
369
181
5
25
.
_
12,285
_
33.2
986 22
122 4
57 9
38 3
-
-
1
3
1
1
1
1 13
2 19
63 10
12 5
1
1 4
-
_
1,282 97
_
3.5 0.3
S02
319
183
24
56
200
150
14
36
-
13
7
45
30
13
7
1
2
-
-
1,100
_
3.0
Sulfur
1,645
266
88
82
86
64
12
31
-
2
2
162
176
40
20
1
4
20
5
2,706
_
7.3
Sulfur
and shipping
211
280
42
78
-
-
10
26
17
-
-
31
44
20
10
1
2
-
-
772
_
2.1
purse
310
83
97
73
-
-
4
11
-
_
1
91
259
40
20
1
4
-
_
994
_
2.7
H2S H2
11,027
3,260
1,360
1,297
1,692
1,282
151
402
- 18
462
221
782
1,190
668
314
15
61
23
6
5.850 4.680 10.530
5,850 4,680 34,761
2.086
15.9 12.7
*oftota,
29.9
8.8
3.7
3.5
4.6
3.5
0.4
1.1
-
1.3
0.6
2.1
3.2
1.8
0.9
.
0.2
0.1
-
28.6
94.3
5.7
15.4
4.6
1.9
1.8
2.4
1.8
0.2
0.6
-
0.6
0.3
1.1
1.7
0.9
0.4
_
0.1
_
.
14.7
48.5
2.9
-------
Discussion of Results
The capital investment costs for limestone and double alkali are quit
close; the relative simplicity of limestone scrubbing offset by smaller
requirements in double alkali. The projected total investments for the
limestone slurry process range from $25,057,000 ($125.3/kW) for an existing
200-MW 3.5% sulfur coal-fired unit to $74,830,000 ($74.8/kW) for an existl
1,000-MW 3.5% sulfur coal-fired unit. Investments for the generic double^**
alkali process range from $25,477,000 ($127.4/kW) for a new 200-MW 3.5%
sulfur coal-fired unit to $85,487,000 ($85.5/kW) for an existing 1,000-MW
3.5% sulfur coal-fired unit.
Understandably, the product-producing citrate process has greater
investment requirements than the waste-producing processes. The projected
capital investments for citrate range from $38,075,000 ($190.9/kW) for a n
200-MW 3.5% sulfur coal-fired unit to $109,024,000 ($109.0/kW) for an exi JT
1,000-MW 3.5% sulfur coal-fired unit. 8tu»
The summarized capital investment results for the three processes ar
shown in Figures 14-16 which indicate the effect of power unit size and a
fur content of coal on the total fixed investment for units of different
status (new or existing). The effects of similar variations on capital
investment in dollars per kW are given in Figures 17-19.
A variation of the base case was prepared for the waste-producing pr
esses in which the waste solids are disposed of by trucking to the dig ^C**
area. This is the single case variation comparison between limestone
double alkali in which double alkali has a lower investment requirement
($41,353,000 for double alkali and $42,307,000 for limestone). While the
double-alkali process includes thickening and filtration as a normal proc
step, it must be added to the limestone system to produce a truckable flit-
cake. In addition, limestone FGD produces more waste solids because of a *
higher stoichiometric ratio of calcium to S02 removed and it includes a
expensive feed preparation area. These factors combine to produce a
stone investment that is 2.4% higher than the double-alkali case. When
double-alkali disposal-by-trucking case is compared with the limestone bt
case (slurry disposal by ponding) the limestone capital investment requti
is 18% higher. Table 32 is a comparison of capital investment costs for
disposal alternatives.
TABLE 32. COMPARISON OF INVESTMENT
REQUIREMENTS FOR SOLIDS DISPOSAL ALTERNATIVES3
Process
Limestone
Double alkali
Slurry ponding, $
(base case)
48,728,000
50,551,000
Filter cake
trucking, $
42,307,000
41,335,000
Investment decrease
in trucking alternatli.^
$ % ^
6,421,000 13.2
9,216,000 18.2
Base case conditions: Pond and cake disposal are both 1 mile from
scrubbing facilities.
-------
r
X Citrate process
O Generic double-alkali process
_ A Limestone slurry process
3.5% sulfur in coal
1.2 Ib 502/MBtu
400
POWER UNIT SIZE, MU
Figure 14. All processes. Effect of power unit size on total
capital investment for new coal-fired units.
I
I
T
Citrate process
Generic double-alkali process
Limestone slurry process
3.5Z sulfur in coal
1.2 Ib S02/MBtu
400 600 800
POWER UNIT SIZE, MW
Figure 15. All processes. Effect of power unit size on total
capital investment for existing coal-fired units.
96
-------
80
60
T
T
T
X
o
A
Citrate process
Generic double-alkali process
Limestone slurry process
1.2 Ib S02/MBtu
SULFUR IN COAL, Z
Figure 16. All processes. Effect of sulfur content of coal
on total capital investment for new 500-MW units.
150
100
50
Figure 17,
3.5% sulfur in coal
1.2 Ib S02/MBtu
X Citrate process
~~ 0 Generic double-alkali process
A Limestone slurry process
I
400 600 800
POWER UNIT SIZE, MW
All processes. Effect of power unit size on unit
investment cost for new coal-fired units.
97
-------
200
150
100
50
X Citrate process
-O Generic double-alkali process
A Limestone slurry process
3.5% sulfur in coal
X—
400
600
800
1000
Figure 18.
POWER UNIT SIZE, MW
All processes. Effect of power unit size on unit
investment cost for existing coal-fired units.
200
150
100
50
X
O
A
Citrate process
Generic double-alkali process
Limestone slurry process
1.2 Ib S02/MBtu
SULFUR IN COAL, $
Figure 19. All processes. Effect of sulfur content of coal
on unit investment cost for new 500-MW units.
98
-------
The difference in investment requirements for S02 removal at base case
conditions (1.2 Ib S02/MBtu heat Input allowable emissions) versus 90% SO9
removal for each process is displayed in Table 33. Capital investment
increases range from 3.5% to 4.2% or from an increase of $1,709,000 addi-
tional capital required for limestone to $2,985,000 additional capital
required for citrate.
TABLE 33. COMPARISON OF INVESTMENT
REQUIREMENTS FOR DIFFERENT S02 REMOVAL LEVELS
Projected total capital Investment
investment requirements, $ increase resulting
500-MW new 3.5% sulfur coal-fired units from increased SO
1.2 Ib S02/MBtu heat 90% removal to 902
Process
Limestone
Double alkali
Citrate
input allowable emission
48,728,000
50,551,000
71,639,000
SO? removal
50,437,000
52,404,000
74,624,000
$
1,709,000
1,853,000
2,985,000
___%__
3.5
3.7
4.2
Differences in capital investment requirements between processes,
new and existing units, or between sulfur content of fuels can best be ana-
lyzed by studying the specific unit areas within the processes. Base case
summarized area equipment-and-installation breakdowns which give component
costs for the three processes are shown in Tables 29-31. In each process
the greatest fraction of the investment cost is attributed to the SOo abso-ro-
tion area, approximately 33% to 34% of the direct investment for base case
conditions. Gas handling (contributing from 11% to 17% for the base case)
and pond construction (contributing from 16% in double alkali to 20% in tne
limestone base case) also are significant portions of the direct investment
In the citrate process, the H2 and H2S generation plants represent approxi-"
mately 29% of the direct investment. Special purging of chlorides in
systems producing salable abatement products such as the citrate process
accounts for only 0.3% of the direct investment in the citrate base case,
In a comprehensive area-by-area comparison of capital investment require'
ments for all case variations (see tables in appendix) the S02 absorption
area cost ranges from 29% to 43% of the direct investment. The effect of
plant age on investment costs becomes important in waste-producing procesac
where pond size and construction costs depend on remaining plant life. po
example, the cost of pond construction for the double-alkali 200-MW new
coal-fired unit (30-year remaining life) is $2,141,000 while the pond con-
struction cost for a 200-MW existing coal-fired unit (20-year remaining
life) is $1,197,000. The H2 and H2S generation plants represent 22% to 33*
of the citrate direct investment. Chloride purge facilities account for l
than 1% of citrate direct investment for all case variations.
99
-------
Capital investment and revenue requirements are now available for a num-
ber of limestone FGD units. A citrate system and several double-alkali units
are under construction. As costs for these become available, comparisons
with the results of this study are to be expected. Care must be taken in
these comparisons to understand the scope of the work and to determine the
areas that may not be directly comparable. The base case (500-MW 3.5% sul-
fur new coal-fired unit) capital investment for limestone slurry scrubbing
derived in this study is $97.5/kW. As an example of how changes in scope
affect the capital investment, Table 34 defines area-cost increases which
total $96/kW or a new capital investment for limestone of $193.5/kW. Con-
tractor bid competition, construction experience, and changes and refinements
in process design will affect the actual costs of installing and operating a
large-scale system. Ultimately, demonstrated performance of any FGD system
will produce the necessary data for full understanding of process costs.
REVENUE REQUIREMENTS
Results
Annual and lifetime revenue requirements for the three processes are cal-
culated on a regulated economics basis. The projected annual revenue require-
ments are calculated in 1980 dollars.
Annual Revenue Requirements—
Three methods for displaying results are presented.
1. Summary of average annual revenue requirements - tabular revenue
requirement results for all case variations. For each of the three
processes, a summary table is presented listing the projected total
average annual revenue requirements for the case variations, expressed
as total dollars and equivalent unit costs (Tables 35-37).
2. Projected average annual revenue requirements - all case variations
for three processes. Summary tables showing changes in process costs
and the corresponding equivalent unit revenue requirements are pre-
sented in the appendix for the case variations studied for each
process. The distribution of revenue requirement components is
expressed as a percent of the total average annual revenue require-
ments .
3. Average annual revenue requirements - base case operating breakdown
analysis. Summarized by operating area, revenue requirements are
projected according to direct cost components (Tables 38-40).
Lifetime Revenue Requirements—
Results of the lifetime economic projections are presented.
1. Tables 41-43 summarizing the lifetime economics results for each
case variation.
2. Computer printouts of the detailed year-by-year cash flow analyses,
displayed in the appendix, for each case variation of each process.
100
-------
TABLE 34. LIMESTONE SLURRY PROCESS
ADDITIONAL INVESTMENT REQUIRED FOR MODIFIED PROJECT SCOPE
Investment
required
Base case - limestone slurry process: 500-MW new unit 97.5
burning coal containing 3.5% sulfur, 16% ash, 10,500 Btu/lb
heat value; 1.2 Ib S02 allowable emission per MBtu heat
input; 0.1% liquid entrainment in cleaned stack gas; 30-year
life, 127,500-hr operation; no redundancy; 20% contingency;
onsite solids disposal; mid-1979 cost basis
Additional
investment
required
Modified case: 500-MW new unit burning coal containing
6% sulfur, 16% ash, 10,500 Btu/lb heat value; 90% S02
removal; 0.3% liquid entrainment in cleaned stack gas;
30-year life, 127,500-hr operation; 50% redundancy;
onsite solids disposal; mid-1979 cost basis
Investment increases due to:
Increased raw material handling 18.3
Larger waste disposal area and pond 46.9
50% redundancy of ball mills, scrubbers, and
other equipment
Total increase in capital investment
101
-------
TABLE 35. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS SUMMARY^
o
M
Case
Coal-Fired
Years Total annual
remaining revenue
life requirements Mills/kWh
$/ton (bbl)
of coal (oil)
burned
$/MBtu
heat input
$/ton
sulfur removed
Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E
200 MW N
500 MW E
500 MW N
500 MW N
500 MW N
1,000 MW
1,000 MW
3.5%
3.5%
3.5%
2.0%
3.5%
5.0%
E 3.
N 3.
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
5% sulfur
5% sulfur
20
30
25
30
30
30
25
30
7,
7,
14,
11,
14,
16,
23,
21,
479,400
153,200
789,400
624,900
101,900
032,200
241,200
874,300
5.34
5.11
4.23
3.32
4.03
4.58
3.32
3.12
11
11
9
7
9
10
7
7
.81
.67
.65
.75
.40
.69
.75
.54
0
0
0
0
0
0
0
0
.56
.56
.46
.37
.45
.51
.37
.36
506.05
499.87
413.34
717.59
402.91
295.91
332.02
323.25
Solids disposal by trucking
500 MW N 3.5% sulfur 30 15,172,400 4.33
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 14,651,300 4.19
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 11,446,600 3.27
10.11
9.77
0.48
0.47
433.50
358.22
2.15
0.35
770.81
a. Basis
Midwest plant location, 1980 revenue requirements.
Power unit on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Investment and revenue requirement for removal and disposal of fly ash excluded.
-------
TABLE 36. GENERIC DOUBLE-ALKALI PROCESS
ANNUAL REVENUE REQUIREMENTS SUMMARY3
Case
Years
remaining
life
Total annual
revenue
requirements
Mills/kWh
$/ton (bbl)
of coal (oil)
burned
$/MBtu
heat input
$/ton
sulfur removed
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 7,553,000 5.40
200 MW N 3.5% sulfur 30 7,169,100 5.12
500 MW E 3.5% sulfur 25 15,441,700 4.41
500 MW N 2.0% sulfur 30 11,335,300 3.24
500 MW N 3.5% sulfur 30 14,676,000 4.19
500 MW N 5.0% sulfur 30 17,741,900 5.07
1,000 MW E 3.5% sulfur 25 25,750,900 3.68
1,000 MW N 3.5% sulfur 30 24,147,700 3.45
Solids disposal by trucking
500 MW N 3.5% sulfur 30 14,293,900 4.08.
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 15,438,800 4.41
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 11,128,400 3.18
11.92
11.69
10.07
7.56
9.78
11.83
8.58
8.33
9.53
10.29
0.57
0.56
0.48
0.36
0.47
0.56
0.41
0.40
0.45
0.49
511.03
500.99
431.57
699.71
419.31
327.46
367.87
356.84
408.40
387.90
2.09
0.34
749.39
Basis
Midwest plant location, 1980 revenue requirements,
fyvtr wit ottrttrum tiae, 7,000 hr/yr,
*•*
.
«4»1*«
f*»
M« «l*»«Ml o« fly Mtt excluded.
-------
TABLE 37. CITRATE PROCESS
o
-P-
ANNUAL REVENUE REQUIREMENTS SUMMARY*
Case
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.5% sulfur
200 MW N 3.5% sulfur
500 MW E 3.5% sulfur
500 MW N 2.0% sulfur
500 MW N 3.5% sulfur
500 MW N 5.0% sulfur
1,000 MW E 3.5% sulfur
1,000 MW N 3.5% sulfur
Years Total annual
remaining revenue
life requirements
20
30
25
30
30
30
25
30
12,289,200
11,670,800
23,174,000
17,091,700
22,538,000
27,513,400
36,933,500
35,602,400
Mills/kWh
8.78
8.34
6.62
4.88
6.44
7.86
5.28
5.09
$/ton (bbl)
of coal (oil)
burned
19,40
19.03
15.11
11.39
15.02
18.34
12.31
12.28
$/MBtu
heat input
0.92
0.91
0.72
0.54
0.72
0.87
0.59
0.58
$/ton
sulfur removed
831.47
815.56
647.68
1,055.04
643.94
507.81
527.62
526.12
$/ton
sulfur recovered
859.99
843.26
669.96
1,097.73
654.98
528.60
545.71
544.21
90% S02 removal
500 MW N 3.5% sulfur 30 23,812,400 6,80
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW E 2.5% sulfur 25 16,091,700 4.60
15.87
0.76
598.30
3.02
0.50
1,042.88
617.70
1,060.76
Basis
Midwest plant location, 1980 revenue requirements.
Power unit on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Investment and revenue requirement for removal and disposal of fly ash excluded.
-------
TABLE 38. LIMESTONE SLURRY PROCESS BASE CASE
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Total hand Una preparation
Total direct investa-ent, $ 26,000,000 1,759,000 1,740,000
Total depreciable investment, $ 46,677,000
Unit Raw
Direct Costs cost, $ material
Delivered raw Materials
Line stone 7.00/ton
Annual quantity, tons 158,300
Annual cost, $ 1.108.100
Operating labor and supervision 12.50/Ban-hr
Annual quantity, sun-hr 4.20O 6,600
Annual cost, $ 52,500 82,500
Utilities
St«>.. 2.00/HBtu
Annual uantity, MBtu
Annual ost, $ -
Process v t*r 0.12/kgal
Annual uantity, kgal
Annual ost, $ - -
Electrici y 0.029/kUh
Annual quantity, kUh 770,000 4,458,000
Annual cost. $ 22,300 129,300
Maintenance (labor and .utertal)
Annual cost, $ 140.700 139,200
Analyses 17.00/s.an-hr
Annual quantity, .un-hr 1,500
Annual cost. $ 25.500
Subtotal conversion costs 25,500 215,500 351,000
Total direct costs 1.133,600 215,500 351.000
costs 18.96 3.61 5.88
Services, Total Total t of average
handlinc absorption reheat disposal miscellaneous construction quantities dollars requirements
4,318,000 8,918,000 1,282,000 1,658,000 1,180,000 5,145,000 26,000,000
158,300
1.108.100 7.86
1,690 8,500 1,500 3,500 - - 25,990
21,100 106,200 18,800 43,800 - - 324,900 2.30
489,800 - - - 489,800
979,600 - - 979,600 6.95
247,400 ... - 247,400
29,700 - - 29,700 0.21
26,179,000 24,171,000 - 637,000 455,000 - 56,670.000
759,200 700,900 - 18,500 13,200 - 1,643,400 11.65
345.50O 713,400 102,600 132,600 94,400 154,400 1,822,800 12.93
1,880 - 380 - - 3,760
32.000 - 6,400 - - 63,900 0.45
1,125,800 1,582,200 1.101,000 201,300 107,600 154,400 4,864,300 34.49
1,125,800 1,582,200 1,101,000 201,300 107,600 154,400 5.972.400 42.35
18.85 26.49 18.43 3.37 1.80 2.59
-------
TABLE 39. GENERIC DOUBLE-ALKALI PROCESS BASE CASE
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Total direct inveatsKnt, $
Total depreciable InveatsKot, $
Total capital investawnt, $
Direct Coits
Delivered raw Baterlal*
Lie*
Annual quantity, tons
Annual cost, $
Soda aah
Annual quantity, tana
Annual cost, $
Subtotal raw Materials cost
Conversion costs •
t— • Operating labor and supervision
£} Annual quantity, man-hr
fj^ Annual cost, $
w Utilities
Steaei
Annual quantity, MBtu
Annual cost, $
Process water
Annual quantity, kgal
Annual cost, 3
Electricity
Annual quantity, kUi
Annual cost. $
Maintenance (labor and material)
Annual cost, $
Analyses
Annual quantity', hr
Annual cost, $
—
Total direct costs
costs
Material* Feed Gas $0? Stack gas
Total handling preparation handling absorption reheat teaction
26,750,000 1,710,000 833,000 4,24»,OOO 9.206.000 1.282.000 357,000
48,530.000
50,551.000
Unit lav
coat. $ material
42.00/ton
63.600
2,671.200
90.00/ton
6.060
545.400
3,216.600
12.50/man-hr
4,200 6,600 1,700 7.000 1,500 1,750
52,500 82,500 21,200 87,500 18,800 21,900
2.00/MBtu
489,800
979,600
0.12/kgal
121,800 - - 46.620
14,600 - - 5.600
0.029/kUh
1,078,000 903,000 17,872.000 S,369,OOO - 819,000
31,300 26,200 518,300 155,700 - 23,700
68,400 33,300 169,900 368,200 51,300 14,300
17.00/Ban-hr
1.500 - - 1,700 - 700
.25,500 - - - 28.900 - 11.900
3,242,100 166,800 142,000 709,400 645,900 1,049,700 71,800
49.08 2.52 2.15 10.74 9.78 15,89 1.09
Services, Total
Solids Solids utilities, and Pond annual
2,352,000 1.247.0OO 1,374,000 4,241.000
63,600
6,060
8,250 3,500 - - 34.500
103,100 43,800
489,800
.
44,100 28,980 - - 241,500
5,300 3,SOO
2,100,000 504,000 455,000 - 29,100,000
60,900 14,600 13,200
94,100 49,900 51,000 127,200
Z80 380 - - *,560
4.700 6.500
268,100 118,300 64,200 127,200
4.06 1.79 0.97 1.93
Total X of average
annual annual revenue
26,750.000
.2,671,200 18.20
545.400 3.72
3,216,600 21.92
431,300 2.94
979.600 6.67
29,000 0.20
843, 900 3.75
1,027,600 7.00
77.500 0.53
3,388,900 23.09
6,605,500 45.01
-------
TABLE 40. CITRATE PROCESS BASE CASE
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Total direct investment, $
Total depreciable investment,
Total capital investment, $
Total
Sulfur Sulfur
Materials Feed Gas S02 Stack gas Chloride S02 separation storage
handling preparation handling absorption reheat purge reduction and removal and shipping
36,847,000
69,520,000
71,639,000
770,000
132,000
4,093,000 12,285,000 1,282,000 97,000 1,100,000 2,706,000
772,000
Direct Costs Unit cost. $
Raw
material
Delivered raw materials
Line 42.00/ton
Annual quantity, tons
Annual cost, $
Soda ash 90.00/ton
Annual quantity, tons
Annual cost, $
Citrate 1,340.00/ton
Annual quantity, tons
Annual cost, $ 3
Natural gas 3.50/kft
Annual quantity, kft
Annual cost, $
Catalyst
Annual quantity, tons
Annual cost, $
Subtotal raw materials cost
Conversion costs
Operating labor and supervision 12,50/man-hr
Annual quantity, man-hr
Annual cost, $
Utilities
Steam 2.00/MBtu
Annual quantity, MBtu
Annual cost, $
Process water 0.06/kgal
Annual quantity, kgal
Annual cost, $
Electricity 0.029/kWh
Annual quantity, kWh
Annual cost, $
Maintenance (labor and material)
Annual cost, $
Analyses 17.00/man-hr
Annual quantity, man-hr
Annual cost, $
Subtotal conversion cost*
Total direct cost*
ftrcmt of tottl dirwt
2,870
120,500
2,630
236,700
230
308,200
1,050,000
3,675,000
400
6.800
6,800
4,368,200
37.21
2,000
25,000
367,600
10,700
46,200
81,900
81,900
0,10
1,750
21,900
127,400
3,700
7,900
400
6.800
40.300
40.300
*,*
1,700
21,200
41,846,000
1,213,600
245,600
7,000
87,500
197,400
11,900
5,553,100
161,000
737,100
1,500 1,750
18,700 21,900
489,800
979,600
118,500
3,400
76,900
5,800
1,480,400 1,027,200 1,075,200 39,600
1,480,400 1,027,200 1,075,200 39,600
9,240
115,500
12,61
I.7S
9. It
0,34
3,063,700
88,900
66,000
317,200
317,200
2.70
9,240
115,500
180,700
361,400
400
5,641,800
163,600
162,400
826,700
826,700
7.04
3,500
43,800
68,600
137,200
139,400
4.000
46,300
2,03
-------
TABLE 40 (continued)
o
oo
Sulfate
Total direct investment, $ 994,000
Total depreciable investment, $
Total capital investment, $
Direct Costs
Delivered raw materials
Lime
Annual quantity, tons
Annual cost , $
Soda ash
Annual quantity, tons
Annual cost, $
Citrate
Annual quantity, tons
Annual cost, $
Natural gas
Annual quantity, kft
Annual cost, $
Catalyst
Annual quantity, tons
Annual cost, $
bt 1
Conversion costs
Operating labor and supervision
Annual quantity, man-hr 9,240
Annual cost, $ 115,500
Utilities
Steam
Annual quantity, MBtu
Annual cost, $
Process water
Annual quantity, kgal 107,200
Annual cost, $ 6,400
Electricity
Annual quantity, kWh 6,090,500
Annual cost, $ 176,600
Maintenance (labor and material)
Annual cost, $ 59,600
Analyses
Annual quantity, raan-hr 500
Annual cost, $ 8.500
Subtotal conversion costs 366,600
Percent of total direct
costs 3.12
Services , Total Total
H2S H2 utilities, and Byproduct annual annual
generation generation miscellaneous sales revenue quantities dollars
5,850,000 4,680,000 2,086,000 36,847.000
2,870
120,500
2,630
236,700
230
308,200
1,050,000
3,675,000
_
21,000
4 36 1 400
14,000 7,000 - - 67,920
175,000 87,500 - - 849,000
121,000 175,800 - - 1,035,900
242,000 351,600 - - 2,071,800
507,500 1,680,000 - - 2,492,500
30,500 100,800 - - 149,600
1,535,000 1,085,000 532,000 - 66,100,000
44,500 31,500 15,40O - 1,916,900
351,000 280,800 125,200 - 2,210,800
2,000 500 - 10,600
34,000 8.500 - - 180.200
877,000 860,700 140,600 7,378,300
877,000 860,700 140,600 11,739,700
7.47 7.33 1.20
Z of
average annual
reveni r requirements
0.53
1.05
1.37
16.31
0.09
3.77
9.19
0.66
8.51
9.81
0.80
32.74
52.09
-------
TABLE 41. LIMESTONE SLURRY PROCESS
ACTUAL AND DISCOUNTED CUMULATIVE TOTAL AND UNIT INCREASE (DECREASE)
IN COST OF POWER OVER THE LIFE OF THE POWER UNIT3
Lifetime average increase (decrease)
in unit revenue requirement
Cumulative actual
$/ton
Levelized increase (decrease) in
unit revenue requirement*1
Cumulative present $/ton
Years net increase (bbl) of
Case
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (pondingt
200 MW E 3.5% S
200 MW N 3.57. S
500 MW E 3.5% S
500 MW N 2.0% S
500 MW N 3.5% S
500 MW N 5.0% S
l.OOO MW E 3.5% S
1,000 MW N 3.5% S
Solids disposal by trucking
500 MW V 3.5% S
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% S
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% S
a. Basis
Midwest plant location
life of power, $ burned Mills/kWh
20
30
25
30
30
30
25
30
30
30
25
115,734,600
183,304,700
300,128,600
293,271,500
357,374,000
405,112,800
462,118,100
544,862,300
372,822,400
371,004,000
231,792,200
22.25
16.41
14.81
10.73
13.08
14.83
11.66
10.32
13.65
13.58
3.29
10.06
7.19
6.49
4.60
5.61
6.35
5.00
4.27
5.85
5.82
5.01
$/MBtu
heat input
105.94
78.13
70.54
51.11
62.29
70.61
55.51
49.12
64.98
64.66
54.48
worth net increase (bbl) of
of S removed of power. $ burned
948.64
702.32
633.85
992.46
560.59
410.45
499.59
441.72
591.78
497.66
1,182.61
52,811,700 20.52
65,253,700 14.99
122,034,600 13.29
104,931,000 9.85
127,709,200 11.99
144,837,500 13.60
188,891,100 10.52
195,672,000 9.50
132,750,600 12.47
132,602,400 12.45
94,271,900 2.96
$/MBtu $/ton
Mills/kUh heat input of S removed
9.28 0.98 875.82
6.56 0.71 642.26
5.82 0.63 569.19
4.22 0.47 911.65
5.14 0.57 513.92
5.83 0.65 376.40
4.51 0.50 450.71
3.94 0.45 407.06
5.34 0.59 540.52
5.34 0.59 456.62
4.50 0.49 1,062.82
, 1980 revenue requirements.
Over previously defined unit operating
profile. 30-yr life
; 7,000
hr - 10 yr, 5
,000 hr - 5 yr,
3,500 hr - 5 yr,
1,500 hr - 10 yr.
Stack gas reheat to 175°F.
Investment and revenue
requirement for
removal and disposal
of fly
ash excluded.
b. Discounted at 10% to initial year.
c. Equivalent to discounted process cost over life of power units.
-------
TABLE 42. GENERIC DOUBLE-ALKALI PROCESS
ACTUAL AND DISCOUNTED CUMULATIVE TOTAL AND UNIT INCREASE (DECREASE)
IN COST OF POWER OVER THE LIFE OF THE POWER UNIT3
Lifetime average lu^icaoc ^ue^LEaa^j
in unit revenue requirement
Case
Coal-Fired Power Unit
1.2 Ib S02/M8tu heat input
allowable emission; onaite
solids disposal (ponding)
200 MB E 3.51 S
200 HU N 3.51 S
500 HH E 3.5S S
500 MW N 2.01 S
500 MM N 3.51 S
500 HW N 5.O1 S
1,000 HU E 3.51 S
1,000 MW H 3.51 S
Years
remain ing
life
20
30
25
30
30
30
25
30
Cumulative actual
net increase
(decrease) in cost
of power. $
116,680,000
182,336,300
312,313,600
290,205,200
368,601,500
439,183,100
511,039,500
596,859,100
5/ton
(bbl) of
coal (oil)
burned
22.43
16.32
15.41
10.62
13.49
16.07
12.89
11.30
Mllls/kUh
10.15
7.15
6.75
4.55
5.78
6.89
5.52
4.68
6 /Wllf.,
9/ruiiu
heat input
106.30
77.72
73.40
50.58
64.24
76.55
61.39
53.81
c /*• mi
97 con
of S removed
956.39
698.61
659.59
982.08
578.20
444.97
552.48
484.27
Cumulative present
worth net Increase
(decrease) in cost
of cower. b $
53,388,600
65,224,800
127,562,500
103,925,200
132,472,900
158,278,400
209,774,100
215,525,300
LfeveLi.£cu LIIVLCHBC v MC i,*. case ,; 1.11
unit revenue requirement0
$/ton
(bbl) of
coal (oil)
burned
20.75
14,98
13.89
9.76
12.44
14,86
11.68
10.47
MllU/kUh
9.39
6.56
6.09
4.18
5.33
6.37
5.00
4.34
S/MBtu
heat input
0.99
0.71
C.66
0.46
0.59
0.71
0.56
0.5O
$/ ton
of S removed
835.38
641.98
594.97
902.91
533.09
411.33
500.53
448.54
Solids disposal by trucking
500 MB N 3.51 S
90% SO2 removal; onsite
solids disposal (ponding)
500 HW N 3.51 S
Oil-Fired Power Unit
0.8 Ib S02/HBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 (W E 2.5* S
30
30
348,993,900
386,333,300
223,580,000
12.77
14.14
5.47
6.06
60.83
67.33
53.72
547.44
533.24
1,166.22
125,275,900
138,947,500
93,023,600
11.76
13.05
2.92
5.04
5.59
4.44
0.56
0.62
0.48
504.13
491.85
1,048.74
a. Basis
Midwest plant location, 1980 revenue requirements.
Over previously defined unit operating profile. 30-yr life; 7,OOO hr - 10 yr, 5,000 hr - 5 yr, 3,500 hr - 5 yr, 1,500 hr - 10 yr.
Stack gas reheat to 175°F.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Constant labor cost assumed over life of project.
b. Discounted at 107. to initial year.
c. Equivalent to discounted process cost over life of power units.
-------
TABLE 43. CITRATE PROCESS
ACTUAL AND DISCOUNTED CUMULATIVE TOTAL AND UNIT INCREASE (DECREASE)
IN COST OF POWER OVER THE LIFE OF THE POWER UNIT
a
Lifetime average increase (decrease)
in unit revenue requirement
Cumulative actual
Case
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.51 S
200 MW N 3.51 S
500 MM E 3.51 S
500 MU N 2.01 S
500 MU N 3.5% S
500 MU N 5.01 S
1,000 MU E 3.51 S
1,000 MH N 3.5t S
901 SO2 removal
500 MU S 3.57. S
Otl-Flred Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MU E 2.5Z S
a. Basis
Midwest plant location,
Over previously defined
Years
life
20
30
25
30
30
30
25
30
30
25
$/ton
Levelized increase (decrease)
unit revenue requirement0
in
Cumulative present $/ton
net Increase (bbl) of
of power. $ burned Mills/kUh
185,604,300
292,291,500
457,099,200
429,700,300
557,059,800
670,722,600
711,393,300
863,634,100
586,326,400
322,358,300
35.68
26.17
22.56
15.73
20.39
24.55
17.94
16.35
21.46
4.58
16.14
11.46
9.88
6.74
8.74
10.52
7.69
6.77
9.20
6.97
heat input
169.89
124.59
107.43
74.89
97.09
116.90
85.45
77.86
102.19
75.76
worth net Increase (bbl) of
of S removed
1,521.35
1,119.89
965.36
1,454.15
873.82
679.56
769.07
700.72
808.73
1,584,07
of power
84,862
104,508
187,099
153,984
200,363
241,941
293,113
312,517
211,103
131,410
,b $ burned
,500 32.98
,300 24.00
,800 20.38
,800 14.46
,000 18.81
,500 22.72
,800 16.32
,300 15.18
,800 19.82
,200 4.12
Mills/kUh heat input
14.
10.
8.
6.
8.
9.
6.
6.
8.
6.
92 1.57
51 1.14
93 0.97
20 0.69
06 0.90
74 1.08
99 0.78
29 0.72
50 0.94
27 0.68
of S removed
1,407.34
1,028.63
872.67
1,337.83
806.29
628.75
699.39
650.40
747.01
1,425.27
1980 revenue requirements.
unit operating
profile. 30-yr life
; 7,000
hr - 10 yr, 5,
,000 hr - 5 yr,
3,500 hr - 5 yr,
1,500 hr
- 10 yr.
Stack gas reheat to 175°F.
Investment and revenue
Revenue $40/short ton S
requirement for
removal and disposal
of fly
ash excluded.
Discounted at 10* to initial year.
Equivalent to discounted process cost over life of power units.
-------
Discussion of Results
Annual Revenue Requirements—
Summaries of the case variations for each process are shown in the
appendix and tabulated totals are presented in Tables 35-37. In comparing
results, it should be remembered that limestone and double alkali are waste-
producing processes and citrate is a recovery process; however, credit for
the sale of sulfur is included in the annual revenue requirements projected
for citrate.
Generally, the ranking of annual revenue requirements for the processes
is the same as the capital investment rankings. Projected revenue require-
ments for the limestone slurry process range from $7,153,200 (5.11 mills/kWh)
for a new 200-MW 3.5% sulfur coal-fired unit to $23,241,200 (3.32 mills/kWh)
for an existing 1,000-MW 3.5% sulfur coal-fired unit. Annual revenue require-
ments for the generic double-alkali process range from $7,169,100 (5.12 mills/
kWh) for a new 200-MW 3.5% sulfur coal-fired unit to $25,750,900 (3.68 mills/
kWh) for an existing 1,000-MW 3.5% sulfur coal-fired unit.
The sulfur-producing citrate process has greater annual revenue require-
ments than the waste-producing processes. The projected annual revenue
requirements for citrate range from $11,670,800 (8.34 mills/kWh) for a new
200-MW 3.5% sulfur coal-fired unit to $36,933,500 (5.28 mills/kWh) for an
existing 1,000-MW 3.5% sulfur coal-fired unit.
The sensitivity of revenue requirements to variations in the more impor-
tant economic parameters has been evaluated and the effects of these varia-
tions on the projected annual revenue requirements are presented in Figures
20-36. Table 44 identifies the parameters that are varied and the range of
values that is studied. Each range has been selected to correspond to
differences in design or costs which might be encountered in more site-specific
operation. As an illustration, limestone price variations represent the
effect of plant location and the corresponding effect on overall process
costs. Operating labor price fluctuations might also be the result of plant
location.
Figures 20-22 show the effects of power unit size and status (new and
existing) and sulfur content of coal on annual revenue requirements. As the
orolections show, sulfur in coal has a greater effect on the citrate process,
while the differences in status of power units have a small effect on the
annual revenue requirements of a specific unit size.
Special case variations are shown for the alternate disposal of waste
solids by trucking and 90% S02 removal. Tables 45 and 46 display the results
of these projections.
112
-------
30
20
T
T
I
Citrate process
Generic double-alkali process
Limestone slurry process
3.5% sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
XX
1000
POWER UNIT SIZE, MW
Figure 20, All processes. Effect of power unit size on annual
revenue requirements for new coal-fired units.
Citrate process
Generic double-alkali process
Limestone slurry process
3.5% sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
POWER UNIT SIZE, MW
Figure 21. All processes. Effect of power unit size on annual
revenue requirements for existing coal-fired units
113
-------
20
15
10
X Citrate process
O Generic double-alkali process
A Limestone slurry process
1.2 Ib S02/MBtu
7000 bour annual operation
SULFUR IN COAL, %
Figure 22. All processes. Effect of sulfur content of coal on
annual revenue requirements for new 500-MW units.
15
10
Figure 23.
3.5% sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
800
1000
POWER UNIT SIZE, MW
Limestone slurry process. Effect of power unit
size and variations in limestone price on annual
revenue requirements for new coal-fired units.
114
-------
w 20
15
10
1.2 Ib S02/MBtu
7000 hour annual operation
SULFUR IN COAL, Z
Figure 24. Limestone slurry process. Effect of sulfur in
coal and variations in limestone price on annual
revenue requirements for new 500-MW units.
I
25
20
10
Figure 25.
3.5X sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
200
400 600 SOO
POWER UNIT SIZE, MW
Generic double-alkali process. Effect of power unl
size and variations in total raw materials cost on *
annual revenue requirements for new coal-fired unit-
-------
30
3.5% sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
Figure 26.
200
400
600
800
1000
POWER UNIT SIZE, HW
Citrate process. Effect of power unit size and
variations in total raw materials cost on annual
revenue requirements for new coal-fired units.
2
« 18
* 16
s
J
I
14
12
10
Figure 27.
1.2 lb SO2/MBtu
7000 hour annual operation
I
1
I
SllUVR IN COAL. I
Generic double-alkali process. Effect of sulfur in
coal and variations in operating labor cost on annual
revenue requirements for new 500-MW units.
116
-------
30
20
10
Figure 28.
3.5* sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
200
400
600
POWER UNIT SIZE, MW
Citrate process. Effect of power unit size and
variations in operating labor cost on annual
revenue requirements for new coal-fired units.
40
30
20
I "
3.5X sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
I
I
POWER UNIT SIZE, MW
Figure 29. Citrate process. Effect of power unit size and
variations in energy cost on annual revenue require-
ments for new coal-fired units.
117
-------
in" 40
20
1.2 Ib S02/MBtu
7000 hour annual operation
01 2345
SULFUR IN COM., Z
Figure 30. Citrate process. Effect of sulfur in coal and
variations in energy cost on annual revenue
requirements for new 500-MW units.
25
S
(ft
H
1 20
a
1 15
w
§ 10
3.5% sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
I
I
I
I
I
200
400
600
800
1000
Figure 31,
POWER UNIT SIZE, MW
Limestone slurry process. Effect of power unit
size and variations in maintenance cost on annual
revenue requirements for new coal-fired units.
118
-------
1.2 Ib S02/MBtu
7000 hour annual operation
I
I
SULFUR IN COAL, Z
Figure 32. Limestone slurry process. Effect of sulfur in
coal and variations in maintenance cost on annual
revenue requirements for new 500-MW units.
1
25
10
T
T
T
T
3.5X sulfur in coal
1.2 Ib S02/HBtu
7000 hour annual operation
600
POWER UNIT SIZE. MW
800
Figure 33. Generic double-alkali process. Effect of power unit
size and variations in capital charges on annual
revenue requirements for new coal-fired units.
119
-------
S 20
a 15
1.2 Ib S02/MBtu
7000 hour annual operation
I
SULFUR IN COAL, Z
Figure 34. Generic double-alkali process. Effect of sulfur in
coal and variations in capital charges on annual
revenue requirements for new 500-MW units.
T
T
T
T
3.5% sulfur In coal
1.2 Ib S02/MBtu
7000 hour annual operation
800
$80/ton
$60/ton
540/ton
$20/ton
[base case)
1000
POWER UNIT SIZE, MW
Figure 35. Citrate process. Effect of power unit size and
variations in sulfur price on total annual income
from byproduct sales for new coal-fired units.
120
-------
1
I
a
o
40
30
20
10
Figure 36.
3.5% sulfur in coal
1.2 Ib S02/MBtu
7000 hour annual operation
200
400
600
800
$80/ton
560/ton
$40/ton
$20/ton
(base case)
1000
POWER UNIT SIZE, MW
Citrate process. Effect of power unit size and
variations in sulfur price on annual revenue
requirements for new coal-fired units.
B
at
1600
1200
800
400
X Citrate process
O Generic double-alkali process
A Limestone slurry process
3.52 sulfur in coal
1.2 Ib S02/MBtu
Figure 37.
•X—
_L
_L
200
1000
37.2
27.9
18.6
9.3
400 600 800
'POWER UNIT SIZE, MW
All processes. Effect of power unit size on
levelized unit revenue requirements for new coal-
fired units.
121
-------
TABLE 44. SENSITIVITY VARIATIONS STUDIED IN THE ECONOMIC COST PROJECTIONS
Item
Process
Power unit
descriptiona
Annual revenue requirements
Base value
Range ofvar iations
NJ
Raw material price Limestone 1 and 2
Double alkali 1
Citrate 1
Operating labor Double alkali 2
Citrate 1
Energy cost Citrate process 1
Maintenance
Limestone
1 and 2
Capital charges Double alkali 1 and 2
Product revenue Citrate
Limestone, $7/ton
Lime, $42/ton
Soda ash, $90/ton
Lime, $42/ton
Soda ash, $90/ton
Citric acid, $0.67/ton
Natural gas, $3.50/kft3
Labor, $12.50/man-hr
Labor, $12.50/man-hr
Steam, $2.00/MBtu
Electricity, $0.029/kWh
8% of direct investment excluding
pond construction plus 3% of
pond construction
Average capital charges, 6.0%
of total depreciable investment
plus 8.6% of total capital
investment
Sulfur, $40/ton
$4-$10/ton
75-150% of total raw
material cost
75-150% of total raw
material cost
$12.50-$25.00/man-hr
$12.50-$25.00/man-hr
50-150%
$20-$80/ton
a. Power unit description
1. New power units: 200, 500, and 1,000 MW; 3.5% sulfur in coal.
2. New power unit, 500 MW: 2.0%, 3.5%, and 5.0% sulfur in coal.
-------
TABLE 45. COMPARISON OF AVERAGE ANNUAL REVENUE
REQUIREMENTS FOR SOLIDS DISPOSAL ALTERNATIVES3
Process
Limestone
Double alkali
Slurry ponding
(base case) , $
14,101,900
14,676,000
Filter cake
trucking, $
15,172,400
14,293,900
Revenue requirement
increase (decrease) in
trucking alternative
$ %
1,070,500 7.6
(382,100) (2.6)
a. Base case conditions: Pond and cake disposal areas each 1 mile
from scrubbing facilities.
TABLE 46. COMPARISON OF AVERAGE ANNUAL REVENUE
REQUIREMENTS FOR DIFFERENT S02 REMOVAL LEVELS
Process
Projected total
annual (7,000 hr)
revenue requirements,
(500-MW new 3.5% sulfur coal-fired units)
1.2 Ib S02/MBtu heat
input allowable emission
90% S02 removal
Limestone
Double alkali
Citrate
14,101,900
14,676,000
22,538,000
14,651,300
15,438,800
23,812,400
Annual revenue
requirement
increase resulting
from increased
S00 removal
549,400 3.9
762,800 5.2
1,274,400 5.7
123
-------
The trucking alternative for limestone increases annual revenue require-
ments by 7.6% over the limestone base case, a result of additional operating
labor, analyses, electricity, and fuel. While operating labor for trucking
and fuel charges are added to the cost of double alkali, the original operating
labor and electricity needs are decreased because the filter cake is not
reslurried and pumped to disposal. In addition, the indirect cost decreases
by $957,000, resulting in an overall decrease in revenue requirements. The
double-alkali trucking alternative revenue requirements are 6% less than
limestone trucking but are still higher than the limestone slurry ponding
case by approximately 1.4%.
Removal of 90% of the S02 compared with removal to meet emission stan-
dards results in revenue requirement increases of 4% to 6% for new 500-MW
units. The credit for additional sulfur recovered and sold in the citrate
process does not equal the increases in raw materials and utilities necessary
for the additional removal.
From the detailed area-by-area base case annual revenue requirement
breakdown analyses (shown in Tables 38-40) it can be seen that total capital
charges are the largest components of revenue requirement for each process.
Base case capital charges range from 46% of total annual revenue requirements
tn the citrate process to 50% in limestone and double-alkali processes. As
ould be expected because of the complexity of the process, citrate has the
highest process operating labor cost. When disposal equipment operation is
included (trucking alternative cases), however, labor costs for limestone
re the highest. Excluding the trucking case variations, operating labor
anees from 2% to 6% of the total revenue requirements for all processes.
Fnergv costs are significant for all processes. Steam for reheat is approx-
ately the same for all processes, but citrate re/quires additional steam
t f product sulfur. Table 47 shows the four major operating cost components
f each process and the corresponding percentage distribution of annual
venue requirements attributed to each component for the base case installa-
tion.
TABLE 47. MAJOR OPERATING COST COMPONENTS INCLUDED
IN THE BASE CASE ANNUAL REVENUE REQUIREMENTS
Major operating cost components
(percent of annual revenue requirements)
Process
Limestone
Double alkali
Citrate
1
Capital charges
(49.58)
Capital charges
(49.47)
Capital charges
(45.84)
2
Maintenance
(12.93)
Raw materials
(21.92)
Raw materials
(19.35)
3
Electricity
(11.65)
Maintenance
(7.00)
Maintenance
(9.81)
4
Limestone
(7.86)
Steam
(6.67)
Steam
(9.19)
124
-------
The sensitivity of the annual revenue requirements to variations in raw
material price for the limestone process is shown in Figures 23-26. Figures
27 and 28 show the sensitivity of annual revenue requirements to variations
in operating labor costs for the generic double-alkali process. Although
similar variations in operating labor projections for limestone result in
different ranges of costs, the general effect is similar.
The effect of energy cost variations for the citrate process is shown
in Figures 29 and 30 for variations in power unit sizes and sulfur levels in
coal. The effect of varying energy is similar for the other processes.
Maintenance is one of the major operating cost components of annual
revenue requirements for all three processes. Figures 31 and 32 project the
effect of varying maintenance requirements for the limestone slurry process
Table 47 shows that capital charges have the greatest effect on annual
revenue requirements. For the double-alkali process the effect of capital
charge variations as a function of power unit size and sulfur level is shown
in Figures 33 and 34.
Annual income from the sale of sulfur for the citrate process will vary
according to Figure 35 as a function of power unit size and selling prices
The effect of variations in selling price on annual revenue requirements i«
presented in Figure 36.
Lifetime Revenue Requirements—
Along with the investment and annual revenue requirement summary tables
given in the appendix, computer projections of the detailed year-to-year
operating cost and sales revenue analyses for all case variations for each
of the three processes are presented. These projections are prepared on a
regulated economics basis as discussed in the procedure and correspond to
the 30-year declining operating profile of the unit established in the power
plant premises. Annual capital charges are based on the undepreciated invest-
ment. The overall net increase or decrease in cost of power is shown for
each year, considering the declining annual operating cost and the net sale
revenue resulting from sale of sulfur. Lifetime costs, both total and dis-
counted (at the regulated cost of money - 11.6% for this study), are dis-
played and equivalent unit revenue requirements are shown. Summarized
results of the lifetime revenue requirement projections for the three proc-
esses are presented in Tables 41-43. Table 48 shows the cumulative lifetime
credits, both actual and discounted, for the citrate process which are
included in the lifetime cost projections. Cumulative lifetime costs for
the solids disposal alternatives and for different SC>2 removal levels are
compared in Tables 49 and 50.
Graphic representations of the effect of power unit size on levelized
unit revenue requirement in dollars per ton of sulfur removed for new and
existing coal-fired power units are shown in Figures 37 and 38. These unit
cost results show trends similar to the annual revenue requirement estimat
however, the magnitude of the costs is greater. The higher costs are the *
result of the declining operating profile of the power plant.
125
-------
TABLE 48. CITRATE PROCESS
LIFETIME SULFUR PRODUCTION AND CREDIT
Case
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.5% sulfur
200 MW N 3.5% sulfur
500 MW E 3.5% sulfur
500 MW N 2.0% sulfur
500 MW N 3.5% sulfur
500 MW N 5,0% sulfur
1,000 MW E 3.5% sulfur
1,000 MW N 3.5% sulfur
Years
remaining Lifetime production
life sulfur, short tons
20
30
25
30
30
30
25
30
117,500
252,000
457,000
283,500
627,000
949,000
89,4,000
1,191,000
Net revenue,
$/short ton sulfur
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
Cumulative revenue
Actual, $
4,700,000
10,080,000
18,280,000
11,340,000
25,080,000
37,960,000
35,760,000
47,640,000
Discounted, $
2,320,500
3,922,200
8,285,300
4,427,100
9,771,300
14,794,700
16,207,400
18,571,800
90% S02 removal
500 MW N 3.5% sulfur 30
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW E 2.5% sulfur 25
702,000
40.00
28,080,000 10,936,300
201,000
40.00
8,040,000
3,637,700
-------
TABLE 49. COMPARISON OF CUMULATIVE LIFETIME DISCOUNTED PROCESS COST
FOR SOLIDS DISPOSAL ALTERNATIVES3
Cumulative discounted
process cost
Process
Limestone
Double alkali
Slurry ponding
(base case) , $
127,709,200
132,472,900
Filter cake
trucking , $
132,750,600
125,275,900
Cumulative discounted
lifetime increase
(decrease) resulting
from trucking alternative
$ %
5,041,400 3.9
(7,197,000) (5.4)
a. Base case conditions: Pond and cake disposal areas each 1 mile from
scrubbing facilities.
TABLE 50. COMPARISON OF CUMULATIVE LIFETIME DISCOUNTED PROCESS COSTS
FOR DIFFERENT SO2 REMOVAL LEVELS
Cumulative lifetime discounted
process cost, $ (500-MW, new, 3.5%
sulfur coal-fired units)
1.2 lb S02/MBtu
heat input
Cumulative lifetime
discounted cost
increase resulting
from increased
Process
Limestone
Double alkali
Citrate
allowable emission
127,709,200
132,472,900
200,363,000
90% S02 removal
132,602,400
138,947,500
211,103,800
$
4,893,200
6,474,600
10,740,800
%
3.8
4.9
5.4
• •
Figure 39 shows the effect of sulfur content of coal on levelized life-
time unit revenue requirements ($/ton of sulfur removed) for a new 500-MW
unit. In comparison with the annual revenue requirements given earlier, the
relative ranking remains the same.
127
-------
T
T
I
1600
1200
800
400
200
X Citrate process
O Generic double-alkali process
& Limestone slurry process
3*5% sulfur In coal
1.2 Ib S02/MBtu
I
I
I
400
600
800
37.2
27.9
18.6
9.3
§
s
a,
H
H
Figure
38.
POWER UNIT SIZE, MW
All processes. Effect of power unit size on levelized
unit revenue requirements for existing coal-fired units.
1600
1200
800
400
\
\
\
X Citrate process
O Generic double-alkali process
& Limestone slurry process
3.5% sulfur in coal
1.2 Ib S02/MBtu
\
\
I
SULFUR IN COAL, Z
Figure 39. All processes. Effect of sulfur iu coal on levelized
unit revenue requirements for new 500-MW units.
128
-------
CONCLUSIONS
The conclusions of this study have been summarized for capital invest-
ment requirements, revenue requirements, and processes. These are listed
below.
CAPITAL INVESTMENT CONCLUSIONS
1. For base case conditions, the limestone process has the lowest invest-
ment requirements, followed by the double-alkali process, with the
citrate process the highest. This ranking remains the same for each
case variation except for the disposal-by-trucking alternative in
which the limestone case variation investment is 2.4% higher than the
double-alkali case. Limestone FGD requires more waste solids handling
and a more expensive feed preparation area resulting in slightly
higher capital investment needs. When the double-alkali disposal-hv-
trucking case is compared with the limestone base case (slurry disnosal
by ponding) limestone capital investment is 18% higher. It should be
recognized that citrate is a recovery process and should also be com-
pared with other recovery processes.
2. With one exception, the existing power unit case variations are
greater than the new power unit case variations at each power plant
size (200, 500, or 1,000 MW) in each process. In the limestone 200-
MW cases, the decrease in costs because of the decrease in pond size
based on a remaining life of 20 years is greater than the increase
in labor charges required for retrofit situations so that the capital
investment for the 200-MW existing unit is lower than the 200-MW new
unit investment. Plant age is an important factor in the limestone
and double-alkali waste-producing processes where pond size depends
on remaining plant life.
3. Capital investment requirements are greater for systems that are
designed for higher sulfur content. The existing oil-fired variation
(2.5% sulfur in oil), however, requires less capital investment than
the existing 500-MW unit burning 2.0% sulfur coal.
4. Removal of 90% of the S02 (instead of the removal to meet emission
standards) increases investment by 3.5% to 4%.
129
-------
5. Special purging of chlorides is unnecessary in waste-producing
processes where enough neutralized chloride is trapped in the inter-
stitial water in the settled sludge to maintain chloride control.
Processes producing salable products, such as the citrate process,
must control chloride buildup in the system. However, the addition
of a chloride purge accounts for less than 1% of the direct investment.
6. In each process the S02 absorption area has greatest effect on the
investment cost, from 29% to 43% of the direct investment. Gas han-
dling and pond construction also contribute significantly to the
direct investment. In the citrate process the H2 and l^S generation
plants represent 22% to 33% of the direct investment.
REVENUE REQUIREMENT CONCLUSIONS
1. For base case conditions, the limestone process has the lowest annual
revenue requirements, followed by the double-alkali process, with the
citrate process the highest. This ranking remains the same for each
case variation except for three instances: (1) 500-MW, 2% sulfur in
coal, (2) 500-MW, 3.5% sulfur in coal with disposal-by-trucking, and
(3) 500-MW, 2.5% sulfur in oil. For these variations, double-alkali
annual revenue requirements are lower than limestone. In the lime-
stone 500-MW, 2.0% sulfur in coal variation, electricity and mainte-
nance costs are great enough to increase annual revenue requirements
3% over the comparable double-alkali requirements. (Base case lime-
stone annual revenue requirements are 4% less than comparable double-
alkali annual revenue requirements and 40% less than comparable citrate
annual revenue requirements.) In the trucking and oil variations,
electricity and maintenance charges increase limestone annual revenue
requirements 6% and 3%, respectively, over those of double alkali.
Also contributing to the increase in limestone annual revenue require-
ments over those of double alkali in the trucking variation are addi-
tional vehicle fuel costs and a plant overhead charge that is $500,000
greater in limestone. Lifetime revenue requirements follow a similar
pattern.
2. Annual revenue requirements for the existing power unit variations are
greater than the new power unit costs at each power plant size in each
process. The increases in annual revenue requirements range from 3%
at the 500-MW size for citrate to 7% at the 1,000-MW size for double
alkali.
3. Annual revenue requirements are greater for systems which are designed
for higher sulfur content. As with capital investment requirements,
the oil variation (existing 500-MW unit, 2.5% sulfur) requires less
revenue than the existing 500-MW unit burning 2.0% sulfur coal, but
there is no direct comparison between the two.
130
-------
4, Removal of 90% of the SC^ (instead of removal to meet 1.2 Ib/MBtu
emission standards) increases revenue requirement by 4% to 6%. The
credit for additional sulfur removed and sold in the citrate process
does not equal the increases in raw material and utility costs required
for the additional removal.
5. Raw material costs are highest for the citrate process and lowest for
the limestone process. Natural gas is the largest raw material cost
in the citrate process, representing approximately 85% of the total
raw material cost. The lime required for chloride neutralization in
the citrate process adds from $49,100 to $240,700 to the raw material
costs in the case variations evaluated.
6. As would be expected because of the complexity of the process, citrate
has the highest total process operating labor cost. When disposal
equipment operation is included (trucking alternative cases), however
labor costs for limestone are the highest. Excluding the trucking '
case variations, operating labor ranges from 2% to 6% of the annual
revenue requirements for all processes.
7. Energy costs are significant for all processes. Double alkali has the
lowest electricity requirement; citrate requires additional steam f
product sulfur. Steam for reheat is essentially the same for all
processes.
8. Maintenance ranges from 5% of the annual revenue requirements
double-alkali 1,000-MW existing unit to 15% for the limestone
existing unit.
9. Capital charges are the largest component of revenue requirement f
each process. Base case capital charges.range from 50% of annual
revenue requirements in limestone and double-alkali processes to 461
in the citrate process.
10. Revenue from the sale of sulfur produced in the citrate process
amounts to 4% to 8% of the adjusted revenue requirement.
PROCESS CONCLUSIONS
The limestone-lime slurry process is the best known and most completel
developed FGD system in the United States today. The evaluation of limest e
FGD in this study reflects the broad experience of vendors and utilities in"
constructing and operating this system. Limestone is still the simplest and
cheapest FGD process available today for most applications, but it contin
to require intensive maintenance effort, it is a once-through process anrf6*
it produces a throwaway sludge of questionable stability and environment
effects.
131
-------
While construction and operating experience is not as extensive for
double alkali as for limestone, double-alkali FGD is a competitive alterna-
tive to limestone, especially when trucking is used to dispose of the waste.
While double alkali is a waste-producing process, it requires less area for
disposal and it regenerates the process scrubbing liquor. Because of system
design* it should require less maintenance than limestone. As more experience
±s gained in constructing and operating the system, capital investment and
revenue requirements could decrease because of changes in process design, but
no significant changes are anticipated.
As a recovery system, the citrate process is inherently more expensive
and cannot be compared directly with the throwaway processes evaluated here.
For this study the citrate process is assumed proven. However, less is known
about the integrated technology for this system than is known about limestone
or double alkali, and the operation of many of the process areas is more
omplex. The citrate process is a more environmentally acceptable process
rhan either the limestone or double-alkali processes because the disadvantage
£ producing waste solids is eliminated by the production of sulfur and
odium sulfate. Maintenance may also be relatively simple. More extensive
eineering an(j operating experience could decrease costs in the areas of
eduction and sulfur separation. However, the use of natural gas in the
eduction step presents possible future problems of supply. The citrate
cess must be proven in the field in order to answer questions of real
cost and operability.
132
-------
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138
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APPENDIX A
TOTAL CAPITAL INVESTMENT, AVERAGE ANNUAL REVENUE REQUIREMENT,
AND LIFETIME REVENUE REQUIREMENT TABLES - ALL PROCESSES AND CASE VARIATIONS
139
-------
TABLE A-l. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(200-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO- absorption (two TCA scrubbers including presaturators
and entrainment separators, recirculation tanks, agitators,
and pumps)
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total Indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , S
1,070,000
1,208,000
2,203,000
4,310,000
584,000
1,392,000
10,767,000
646,000
11,413,000
1,444,000
12,857,000
869,000
203,000
2,062,000
669,000
3,803,000
3,332,000
19,992,000
1,855,000
2,399,000
24,246,000
295,000
516,000
25,057,000
% of
total direct
investment
8.3
9.4
17.2
33.6
4.5
10.8
83.8
5.0
88.8
11.2
1UO.O
6.8
1.6
16.0
5.2
29.6
25.9
155.5
14.4
18.7
188.6
2.3
4.0
194.9
Baals
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
140
-------
TABLE A-2. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(200-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib SOa/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
67,700 tons 7.00/ton
16,440 man-hr 12.50/man-hr
206,800 MBtu 2.00/MBtu
107,100 kgal 0.12/kgal
23,927,000 kWh 0.031/kWh
1,980 man-hr 17.00/man-hr
Total % of average
annual annual revenue
cost. $ requirement-..
473,900
473,900
205,500
413,600
12,900
741,700
1,070,500
33,700
2,477,900
2,951,800
6.34
6.34
2.75
5.53
0.17
9.92
14.31
0.45
33.13
39.47
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 7.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 5.34
1,697,200
2,154,900
654,900
20,600
4,527,600
7,479,400
$/ton coal $/MBtu heat $/short
22.69
28.81
8.76
0.27
60.53
100.00
ton
burned input S removed
11.81 0.56 506.
05
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 20 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 633,500 tons/yr, 9,500 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 14,780 short tons/yr; solids disposal 77,790 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $12,857,000; total depreciable investment, $24,246,000; and total
capital investment, $25,057,000.
141
-------
TABLE A.-3
L1HF.STONE SLUfi«Y PHOCESS 200 M* EXISTING COAL-FIHEO PO«E* UNIT 3.5% S IN COAL» REGULATED CO. ECONOMICS
FIXED INVESTMENT: i 25057000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
3
4
5
6
7
8
9
in
11 5000
12 5000
13 5000
14 500P
_15 5222-
16 1500
17 3500
18 3500
19 3500
-2C 3522.
21 1500
22 1500
23 1500
2* 150C
25 152iJ
26 1500
27 1500
2ft 1500
29 1500
3ft 1522
TOT *7500
LIFETIME
PROCESS COST
LEVELIZED
TOTAL
SULFUR BY-PHOUUCT OP. COST
REMOVED RATE, INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED TOTAL
HEAT FUEL POLLUT10M TONS/YEAR S/TON ROI FOR NET
REQUIREMENT. CONSUMPTION. CONTROL POWER SALES
MILLION HTU TONS COAL PROCESS. DRY DRY COMPANY, REVENUE,
/YtAB /YEAR TONS/YEow SOLIDS SOLIDS S/YEAQ S/YEAR
9500000 *52*00 10600
9500000 *52*00 10600
9500000 452400 10600
9500000 452400 . 10600
95.02220-- -452*22. -12&22 -_ .
6650000 316700 7*00
6650000 316700 7400
6650000 316700 7*00
6650000 316700 7*00
— 6,652020 - 316222 2422
2850000 135700 3200
2850000 135700 3200
2850000 135700 3200
2850000 135700 3200
2S52"22 135222- 3222_
2850000 135700 3200
2850000 135700 3200
2850000 135700 3200
2850000 135700 3200
28522n2 13522SL 3222_
56600 0.0
55600 0.0
55600 0.0
55600 0.0
55622 _-2»2
38900 0.0
38900 0.0
38900 0.0
38900 0.0
3ti22Q fl*0
16700 0.0
16700 0.0
16700 0.0
16700 0.0
16700 0.0
16700 0.0
16700 0.0
16700 0.0
16700 0.0
109250000 5202500 122000 639500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL HURNEO
MILLS PER KILOWATT-HOUR
CENTS PFR MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVF.D
niSCOUNTEO AT 11.6* TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION HTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
8773700
8565200
8356700
81*8200
7052200
68*3700
6635200
6*26700
501S«00
4807300
459H800
4390300
3973300
3764800
3556200
3347700
31122flfl_
115734600
22.25
10.06
105.94
9*H.6*
52811700
PROCESS COST OVER
20.52
9.?8
97.73
875.82
0
0
0
0
2_.
0
0
0
0
2 .
0
0
0
0
tt_.
0
0
0
0
ft_.
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
f
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
s
8773700 8773700
8565200 17338900
8356700 25695600
81*8200 33843800
2232622 4.118.34.20
7052200 48835600
68*3700 55679300
6635200 62314500
6426700 68741200
6216222 -14242410
5015800
4807300
4598800
4390300
_41fllfl22_
3973300
3764800
3556200
3347700
115734600
22.25
10.06
105.94
9*8.6*
52811700
POWER UNIT
20.52
9.28
97.73
875.82
79975200
8*782500
89381300
93771600
^ 21253410
101926700
105691500
109247700
112595400
-------
TABLE A-4. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(200-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, curshers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO. absorption (two TCA scrubbers including presaturators
and entrainment separators, recirculation tanks, agitators,
and pumps )
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
960,000
1,188,000
1,850,000
4,034,000
569,000
1,250,000
9,851,000
591,000
10,442,000
2,598,000
13,040,000
916,000
207,000
2,039,000
676,000
3,838,000
3,376,000
20,254,000
1,766,000
2,430,000
24,450,000
514,000
497,000
25,461,000
% of
total direct
investment
7.4
9.1
14.2
30.8
4.4
9.6
75.5
4.6
80.1
19.9
100.0
7.0
1.6
15.6
5.2
29.4
25.9
155.3
13.5
18.7
187.5
3.9
3.8
195.2
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay Incentive not considered.
143
-------
TABLE A-5. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(200-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
65,600 tons
7.00/ton
16,440 man-hr 12.50/man-hr
200,300 MBtu
103,700 kgal
23,173,000 kWh
2.00/MBtu
0.12/kgal
0.031/kWh
1,980 man-hr 17.00/man-hr
459.200
459,200
205,500
400,600
12,400
718,400
1,017,700
33,700
2,388,300
2,847,500
6.42
6.42
2.87
5.60
0.17
10.04
14.24
0.47
33.39
39.81
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,467,000
2,189,600
628,500
20,600
4,305,700
7,153,200
20.51
30.61
8.78
0.29
60.19
100.00
$/ton coal $/MBtu heat $/short ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 5.11
11.67
0.56
499.87
Baals
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 613,200 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 14,310 short tons/yr; solids disposal 75,310 tons/yr Ca solids including only
hydrate water. «
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $13,040,000; total depreciable investment, $24,450,000; and total
capital Investment, $25,461,000.
144
-------
TABLE A-6
LIMFSTONE SLURRY PflOCFSS ?0fl Mw NF.W COAL-FIHED POWER UNIT 3.5% S IN COAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT:
25461000
SULFUH BY-PRODUCT
PtMOVtO HATE,
YEARS ANNUAL POrfE-* UMT POKER UNIT BY EOUIVALENT NET REVENUE.
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR I/TON
POWFR TION, REOUIRFMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION RTU TONS COAL PROCESS. DHY DRY
START KM /YEAH /YEAH TONS/YEAR SOLIOS SOLIDS
1 7000 12180000 613300 14300 7b300 0.0
2 7000 l?880nOO 613300 1*300 75300 0.0
3 7000 12B80000 613300 14JOO 75300 0.0
4 7000 12880000 613300 14300 75300 0.0
5 jaaa isasaaac &i33aa_ liiua i&aaa a*a.
6 7000 12880000 613300 1*300 75300 0.0
7 7000 128BOOOO 613300 1*300 75300 0.0
8 7000 12880000 613300 1*300 75300 0.0
9 7000 12880000 613300 14300 75300 0.0
ia _iaaa isascQQfi &i32aa_ liiaa Z53aa a*a
11 5000 9200000 438100 10200 53800 0.0
12 5000 9200000 438100 10200 53800* 0.0
13 5000 9200000 438100 10200 53800 0.0
14 5000 9200000 438100 10200 53800 0.0
is _saaa 92.aao.aa _43aica iaz.ua 53aaa tua
16 3500 6*40000 306700 7200 37700 0.0
17 3500 6*40000 306700 7200 37700 0.0
18 3500 6440000 306700 7200 37700 0.0
19 3500 64*0000 306700 7200 37700 0.0
_za jsaa iiscnaa aa&zae zzaa azz&a a*a
21 1500 2760000 131400 3100 16100 0.0
22 1500 2760000 131400 3100 16100 0.0
23 1500 2760000 131400 3100 16100 0.
24 1500 2760000 131400 3100 16100 0.
es _isaa 2ifiaaao. _i3i4flfi ante ..ifeiaa „ (Ui
26 1500 2760000 131400 3100 16100 0.
27 1500 2760000 131400 3100 16100 0.
28 1500 2760000 131400 3100 16100 0.
29 1500 2760000 131400 3100 16100 0.
_3a isaa 2Z$aaaa miaa 3iaa ifeioa tua
TOT 127500 23*600000 11171000 261000 1371500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAH. DOLLARS
TOTAL
OP. COST
INCLUDING NET ANNUAL
REGULATED TOTAL INCREASE
ROI FOR NET (DECREASE)
POWER SALES IN COST OF
COMPANY, REVENUE, POWER.
S/YEAR t/YEAR $
9343100 0 9343100
9202900 0 9202900
9062700 0 9062700
8922600 0 8922600
azagiaa a aiagiftii
8642200~ ~ 0 8642200
8502000 0 8502000
8361800 0 8361800
8221700 0 8221700
aatti&aa a aaaisaa —
7111000 ~ 0 7111000
6970800 0 6970800
6830600 0 6830600
6690500 .0 6690500
65itt3fla B &S5tt3fltt—
5755300 0 5755300
5615100 0 5615100
5474900 0 5474900
5334800 0 5334800
smwia a aii^ua—
4046200 0 4096200
395*000 0 3956000
3«15«00 0 3815800
3675700 0 3675700
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
93*3100
185*6000
27608700
36531300
isataiao
53955900
62*57900
70819700
790*1*00
_&112220,0
94233900
101204700
108035300
114725800
L2i.2Z6LftO
127031400
132646500
138121400
143456200
Liwiaatto
1 527*7000
156703000
160518800
16419*500
aiisano a asaasflfl lAizaaaao
339*300 o 3395300
3255100 0 3255100
3114900 0 3114900
2974800 0 2974800
2JH16J2A a gfliififtfl—
183304700 0 183304700
16.41 0.0 16.41
7.19 0.0 7.19
78.13 0.0 78.13
702.32 0.0 702.32
65253700 0 65253700
17112S300
174380*00 .
177495300
180*70100
lass a*.ia°
LEVELIZEO INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF POKER UNIT
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PEH TON OF SULFUR REMOVED
14.99 0.0 !*.»»
6.56 0.0 6.56
71.36 0.0 71.36
6*2.26 0.0 6*2.26
-------
TABLE A-7. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
% of
total direct
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO- absorption (four TCA scrubbers including presaturators
and entrainment separators, recirculation tanks, agitators,
and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
1,940,000
1,870,000
5,111,000
9,424,000
1,312,000
1,826,000
21,483,000
1,289,000
22,772,000
4,084,000
26,856,000
1,174,000
265,000
3,764,000
1,170,000
6,373,000
6,646,000
39,875,000
3,579,000
4,785,000
48,239,000
820,000
1,061,000
50,120,000
investment
7.2
7.0
19.0
35.1
4.9
6.8
80.0
4.8
84.8
15.2
100.0
4.4
1.0
13.9
4.4
23.7
24.8
148.5
13.3
17.8
179.6
3.1
3.9
186.6
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
146
-------
TABLE A-8. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
•
(500-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
163,900 tons 7.00/ton
25,990 man-hr 12.50/man-hr
500,700 MBtu 2.00/MBtu
257,900 kgal 0.12/kgal
57,930,000 kWh 0.029/kWh
3,760 man-hr 17.00/man-hr
Total % of average
annual annual revenue
cost, $ reauiremencc
1,147,300
1.147,300
324,900
1,001,400
30,900
1,680,000
1,944,300
63,900
5,045,400
6,192,700
7.76
7.76
2.20
6.77
0.21
H.36
13.14
0.43
34.11
41.87
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital Investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 4.23 9.65
3,087,300
4,310,300
1,166,600
32,500
8,596,700
14,789,400
$/MBtu heat $/short
20.88
29.14
7.89
0.22
58.13
100.00
ton
input S removed
0.46 413.
34
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,533,350 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 35,780 short tons/yr; solids disposal 188,300 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $26,856,000; total depreciable investment, $48,239 000- and tot i
capital investment, $50,120,000. ' ai
147
-------
TABLE A-9
oo
SV.WWY PROCESS 500 Km EXISTING COM.-FIKEO POwE« UNIT 3.S* S IN COAU» REbULATEO CO. ECONOMICS
FIXED INVESTMENT: 5 50120000
YEARS ANNUAL
AFTER OPERA-
POWFR TION,
UNIT KW-HR/
START KW
1
2
3
4
5
6 7000
7 7000
8 7000
9 7000
_12 2222..
11 5000
12 5000
13 5000
14 5000
15 5222
16 3500
17 3500
18 3500
19 3500
22 3522
POWER UNIT POWER UNIT
HEAT FUFL
REQUIREMENT, CONSUMPTION,
MILLION *TU TONS COAL
/YEAR /YEAH
32200000
32200000
32200^)00
3?2flOOOO
32222222
23000000
23000000
23000000
23000000
23222222
16100000
16100000
16100000
16100000
1611)0000
21 1500 6900000
22 1500 6900000
23 1500 6900000
24 1500 6900000
.25 1522 6222222
2
-------
TABLE A-10. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit,
2.0% S in coal; 1.2 lb S02/MBtu
heat input allowable emission; onsite solids disposal)
— ,.
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators
and entrainment separators, reclrculatlon tanks, agitators,
and pumps)
Stack gas reheat (four Indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilites, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed Investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
974,000
1,179,000
4,120,000
8,282,000
1,222,000
1,290,000
17,067,000
1,024,000
18,091,000
2,800,000
20,891,000
1,130,000
260,000
3,071,000
967,000
5,428,000
5,264,000
31, 583, 000
2,878,000
3,790,000
38,251,000
563,000
827,000
39,641,000
% of
total direct
investment
4.7
5.6
19.7
39.6
5.9
6.2
81.7
4.9
86.6
13.4
100.0
5.4
1.2
14.8
4.6
26.0
25.2
151.2
13.8
18.1
183.1
2.7
3.9
189.7
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling^ mid-1979.
Stack gas reheat to 175 F by Indirect steam reheat.
Minimum In-process storage; only pumps are spared.
Disposal pond located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP. ,
Construction labor shortages with accompanying overtime pay incentive not considered.
149
-------
TABLE A-11. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGUEATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
2.0% S in coal; 1.2 Ib S02/MBtu
hefat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total 7. of average
Unit annual annual revenue
cost, $ cost, $ requirements
73,600 tons
7.00/ton
23,280 man-hr 12.50/man-hr
515,200
515,200
291,000
489,800 MBtu
215,000 kgal
53,505,000 kWh
3,370 man-hr
2.00/MBtu
0.1 2 /kgal
0.029/kWh
17.00/man-hr
979,600
25,800
1,551,600
1,531,300
57,300
4,436,600
4,951,800
4.44
4.44
2.50
8.43
0.22
13.35
13.17
0.49
38.16
42.60
Tndlrect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.32
2,295,100
3,409,100
939,800
29,100
6,673,100
11,624,900
$/ton coal $/MBtu heat $/short
19.74
29.33
8.08
0.25
57.40
100.00
ton
burned input S removed
7.75 0.37 717.
59
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 gons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 16,200 short tons/yr; solids disposal 85,260 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $20,891,000; total depreciable investment, $38,251,000; and total
capital investment, $39,641,000.
150
-------
TABLE A-12
LIMESTONE SLURRY PrtOCESS SOO MW NE* COAL-FIRED POWER UNIT 2.0* S IN COAL REGULATED CO. ECONOMICS
FIXFD INVESTMENT:
39641000
TOTAL
SULFUR KY-PRODUCT OP. COST
rfEMOVtl) HATE. INCLUDING
YEARS ANNUAL POWER UNIT POWER UNIT HY EQUIVALENT MET REVENUE, REGULATED TOTAL
AFTFR OPERA- HEAT FUEL POLLUTION TONS/YEAR J/TON ROI FOR NET
POWFR TION, REQUIREMENT, CONSUMPTION. CONTROL POWER SALES
UNIT KW-HR/ MILLION STU TONS COAL PrtOCPSS. DHY DRY COMPANY, REVENUE,
START KW /YEAR /YEAR TONS/YtA* SOLIDS SOLIDS J/YEAR S/YEAR
1 7000
2 7000
3 7000
4 7000
6 7000
7 7000
8 7000
9 7000
ia zaaft
11 5000
12 5000
13 5000
14 5000
15 -5flO.fi
16 3500
17 3500
18 3500
19 3500
_2a 3saa
21 1500
22 1500
23 1500
24 1500
25 iSflfl
26 1500
27 1500
28 1500
29 1500
_aa isaa
31500000
31500000
31500000
31500000
3.15flBQ.aJ!_
31500000
31500000
31500000
31500000
3i5aaaaa
1500000
1500000
1500000
1SOOOOO
i5aaaaa_
1500000
1500000
1500000
1500000
1500000
22500000 1071400
22500000 1071400
22500000 1071400
22500000 1071400
225flaflaa__ __iazi*aa _.
15750000 750000
15750000 750000
15750000 750000
15750000 750000
iszsaaaa 750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
321400
321400
321400
321400
32i4aa_
321400
321400
321400
321400
16200
lt>200
16200
16200
_i&2aa
16^00
16200
16
-------
TABLE A-13. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
X of
total direct
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO- absorption (four TCA scrubbers including presaturators
and entrainment separators, recirculatlon tanks, agitators,
and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities Including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect Investment
Corvt inttency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable Investment
Land
Working capital
Total capital investment
Investment, $
1,759,000
1,740,000
4,318,000
8,918,000
1,282,000
1,658,000
19,675,000
1,180,000
20,855,000
5,145,000
26,000,000
1,207,000
268,000
3,617,000
1,142,000
6,234,000
6,447,000
38,681,000
3,354,000
4,642,000
46,677,000
1,030,000
1.021,000
48,728,000
investment
6.8
6.7
16.6
34.3
4.9
6.4
75.7
4.5
80.2
19.8
100.0
4.6
1.0
13.9
4.4
23.9
24.8
148.7
12.9
17.9
179.5
4.0
3.9
187.4
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979. '
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
152
-------
TABLE A-14. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
158,300 tons
7.00/ton
25,990 man-hr 12.50/man-hr
_1, 108, 100
1,108,100
324,900
489,800 MBtu
247,400 kgal
56,670,000 kWh
3,760 man-hr
2. 00 /MBtu
0.12/kgal
0.029/kWh
17. 00 /man-hr
979,600
29,700
1,643,400
1,822,800
63,900
4,864,300
5,972,400
7.86
7.86
2.30
6.95
0.21
11.65
12.93
0.45
34.49
42.35
Indirect Costs
Capital charges
Depreciation, interim replacements, and
Insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills /kWh
Equivalent unit revenue requirements 4.03
2,800,600
4,190,600
1,105,800
32,500
8,129,500
14,101,900
$/ton coal $/MBtu heat $/short
19.86
29.72
7.84
0.23
57.65
100.00
ton
burned input S removed
9.40 0.45 402.
91
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 35,000 short tons/yr; solids disposal 184,200 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $26,000,000; total depreciable Investment, $46,677,000; and total
capital investment, $48,728,000.
153
-------
TABLE k-15
LIMESTONE SLURRY PROCESS 500 MX NEW COAL-FIRED POWER UNIT 3.5% S IN COAL* REGULATED CO. ECONOMICS
FIXED INVESTMENT:
48728000
YEARS ANNUAL
AFTFR OPERA-
POWER TION.
UNIT KW-HR/
START KW
1
2
3
4
5.
f.
7
e
9
-12
11
12
13
14
-15-
16
17
18
19
~21~
22
23
24
_25_
26
27
28
29
.31-
7000
7000
7000
7000
ZOOO
POWER UNIT
HEAT
REQUIREMENT.
MILLION BTU
/YEAR
31500000
31500000
31500000
31500000
31500000
7000 31500000
7000 31500000
7000 31500000
7000 31500000
_- ZQQfl— 315QQOQO
5000
5000
5000
5000
_5aaa
22500000
22500000
22500000
22500000
22500000
3500 15750000
3500 15750000
3500 15750000
3500 15750000
3500 15750000
1500
1500
1500
1500
1500~~
1500
1500
1500
._ 1500—
6750000
6750000
6750000
6750000
6Z5220U
6750000
6750000
6750000
6750000
SULFUR
REMOVEU
POWER UNIT BY
FUEL POLLUTION
CONSUMPTION. CONTROL
TONS COAL PROCESS.
/YEAR TONS/YEAR
1500000 35000
1500000 35000
1500000 35000
1500000 35000
1500002 250JIQ_ _
1500000
1500000
1500000
1500000
1071400
1071400
1071400
10714QO
750000
750000
750000
750000
Z50000
321400
321400
321400
321400
321*J10_ _
321400
321400
321400
321400
35000
35000
35000
35000
25000
25000
25000
25000
25000_
17500
17500
17500
17500
lliflU
7500
7500
7500
7500
Z500
7500
7500
7bOO
7500
Z500_._
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED TOTAL
S/TON ROI FOR NET
POWER SALES
DRY COMPANY. REVENUE.
SOLIDS S/YEAR S/YEAR
1B4200 0.0 18292200
184200 0.0 18024600
184200 0.0 17757000
184200 0.0 17489400
184205 0-0 17221800
184200
184200
184200
184200
181200
131600
131600
131600
131600
121600
92100
92100
92100
92100
22100
39500
39500
39500
39500
32500
39500
39500
39500
39500
_ __ 22500
0.0
0.0
0.0
0.0
0..0 -
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0*0
0.0
0.0
0.0
0.0
0*0
0.0
0.0
0.0
0.0
_ 0*0
16954100
16686500
16418900
16151300
15883700
13871300
13603700
13336000
13068400
11169400
10901AOO
10634200
10366500
-1002S2AO
7868600
7601000
7333400
7065800
6Z28.2Q9
6530500
6262900
5995300
5727700
5440100- _
0
0
0
0
0
0
0
0
0
~0
0
0
0
0
0
0
0
0
ft
0
0
0
0
ft
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
S
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
S
18292200 18292200
18024600 36316800
17757000 54073800
17489400 71563200
_lZ22lfloo aaiaaojio
16954100
16686500
16418900
16151300
ISfl&alOfl
13671300
13603700
13336000
13068400
12flOOflOA
11169400
10901800
10634200
10366500
100.96900
7868600
7601000
7333400
7065800
___619820fl
0 6530500
0 6262900
0 5995300
0 5727700
. ft.,. . .54.6.0100..
105739100
122425600
138844500
154995800
. LL08Z25JIO
184750800
198354500
211690500
224758900
211552140
248729100
259630900
270265100
280631600
__24ftZ3Jl500
298599100
306200100
313533500
320599300
321321540
333928000
340190900
346186200
351913900
351314000
TOT 127500 573750000 27321000 637500 3355500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PF« TON OF COAL BURNED
MILLS PFR KILOWATT-HOUR
CFNTS PFW MILLION HTU HFAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6% TO INITIAL YEAH. DOLLARS
357374000
13.08
5.61
62.29
560.59
127709200
357374000
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TON OF COAL BURNtD 11.99
"ILLS PER KILOWATT-HOUR 5.14
CENTS PFR MILLION BTU HEAT INPUT 57.10
OOLLARS PER TON OF SULFUR REMOVED 513.92
0.0
0.0
0.0
0.0
0
FE OF
0.0
0.0
0.0
0.0
13.08
5.61
62.29
560.59
127709200
POWER UNIT
11.99
5.14
57.10
513.92
-------
TABLE A-16. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit,
5.0% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
S0_ absorption (four TCA scrubbers including presaturators
and entrainment separators, recirculation tanks, agitators,
and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities Including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed Investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
1,931,000
2,028,000
4,327,000
8,948,000
1,283,000
1,957,000
20,474,000
1,228,000
21,702,000
7,553,000
29,255,000
1,274,000
275,000
3,911,000
1,249,000
6,709,000
7,193,000
43,157,000
3,560,000
5,179,000
51,896,000
1,511,000
1,214,000
54,621,000
% of
total direct
investment
6.6
6.9
14.8
30.6
4.4
6.7
70.0
4.2
74.2
25.8
100.0
4.4
0.9
13.3
4.3
22.9
24.6
147.5
12.2
17.7
177.4
5.2
4.1
186.7
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling^ mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESF.
Construction labor shortages with accompanying overtime pay incentive not considered.
155
-------
TABLE A-17. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
5.0% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
266,500 tons
7.00/ton
27,910 man-hr 12.50/man-hr
1.865.500
1,865,500
348,900
489,800 MBtu
295.300 kgal
59,828,000 kWh
4,040 man-hr
2.00/MBtu
0.12/kgsl
0.029/kWh
17. 00 /man-hr
979,600
35,400
1,735,000
1,962,800
68,700
5,130,400
6,995,900
11.64
11.64
2.18
6.11
0.22
10.82
12.24
0.43
32.00
43.64
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital Investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 4.58 10.69
3,
A.
1.
9,
16,
113
697
190
34
036
032
$/MBtu heat
input
0.51
,800
,400
,200
,900
,300
,200
$/ short
19
29
7
0
56
100
ton
.42
.30
.42
.22
.36
.00
S removed
295.
91
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 54,180 short tons/yr; solids disposal 285,140 tons/yr Ca solids Including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $29,255,000; total depreciable investment, $51,896,000; and total
capital Investment, $54,621,000.
156
-------
TABLE A-18
LIMESTONE SLURRY PROCESS 500 Mh NEW COAL-FIRSO PJWER UNIT S* S IN COAL* REGULATED CO. ECONOMICS
YEARS ANNUAL
AFTFR OPERA-
POWER TION,
UNIT KW-HR/
STAOT KW
POWER UN'IT PO«ER UNIT
HEAT FUEL
REQUIREMENT. CONSUMPTION.
MILLION RTU TONS COAL
/YEAR
/YEAH
SULFUR
REMOVtll
MY
POLLUTION
rONTKOL
POOCfSS.
TONS/YFAR
INVESTMENT:
RY-HROOUCT
R.ATt,
EQUIVALENT
TONS/YEAR
ORY
SOLIDS
S4621000
NET REVENUE.
i/TON
DRY
SOLIDS
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
P01ER
COMPANY,
S/YEAR
TOTAL
NET
SALES
REVENUE.
J/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
4
1 7000
2 7000
3 7000
* 7000
.5 2222—.
6 7000
7 7000
B 7000
9 7000
.12 2222—.
11 5000
12 5000
13 5000
1* 5000
.15 5.222...
16 3500
17 3500
18 3500
19 3500
22 3522__.
21 1500
22 1500
23 1500
24 1500
_25 15.22—.
26 1500
27 1500
28 1500
29 1500
.32 15.22—
31500000
31500000
31500000
31500000
...31S2Q220.-
31500000
31500000
?1500000
31500000
...315.22222.
22500000
22500000
22500000
22500000
...225.22C22.
15750000
15750000
15750000
15750000
—15252222-
6750000
6750000
6750000
6750000
6.75.2200..
6750000
6750000
6750000
6750000
6.252222.
1500000
1500000
1500000
1500000
1S22220-.
1500000
1SOOOOO
1500000
1500000
15.22222-..
1071400
1071400
1071400
1071400
1211422-.
750000
750000
750000
750000
Z5,2222_.
321400
321400
321400
321400
321422-.
321400
321400
321400
321400
54^00
54200
54200
5_4_i2!l __
54^(10
54200
54200
54200
3«700
3S700
T8700
22122—
27100
27100
27100
27100
2110.0.-.
11600
11600
11600
iiooo
116J12-.
11600
11600
11600
11600
11622—
28S100
24)5100
2H5100
2HblOO
2S5122.
2H5100
285100
285100
2M5100
2S5.10.2.
203700
203700
203700
203700
222222.
142600
142600
142600
142600
142622,
61100
61100
61100
61100
611P.2-
61100
61100
61100
61100
6.1122.
0.0
0.0
0.0
0.0
.2*2
0.0
0.0
0.0
0.0
.2*2
0.0
0.0
0.0
0.0
.2*2
0.0
0.0
0.0
0.0
20730200
20432700
20135100
19837600
195.4^0.22-
19242500
18945000
18647400
18349900
15715600
1541HOOO
15120500
14823000
1263*000
123*1400
12043900
11746300
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
«579200
8281700
7984100
IfelfcMfl-
7309000
70-M500
674*000
6496400
0
0
0
0
_2_
0
0
0
0
.2.
0
0
0
0
"o"
0
0
0
"o"
0
0
0
"o"
0
0
0
20730200
20432700
20135100
19837600
.125.42222-
19242500
18945000
18647400
18349900
-18.25.2322-
15715600
15418000
15120500
14823000
-145.25.422-
12639000
12341400
12043900
11746300
-11440*122-
8876800
8579200
8281700
7984100
20730200
41162900
61298000
81135600
1(12615.620
119918100
138863100
157510500
175860400
_193212120
209628300
225046300
240166800
254989800
269.5.15.220
282154200
294495600
306539500
318285800
7389000
7091500
6794000
6496400
338611400
347190600
355472300
363456400
21114320.0-
378532000
385623500
392417500
398913900
_425112fiao
TOT 127500 573750000 27321000 9b7000 51V3500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL RURNtO
MILLS PER KILOWATT-MOUH
CENTS PER MILLION RTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEA*. DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EOOIVALENT
DOLLARS PER TON OF COAL HUWNEO
MILLS PER KILOWATT-rtOUR
CENTS PEH MILLION HTU HEAT INPUT
DOLLARS PER TON OF SULFUR HE MOVED
405112*100
405112800
TO
DISCOUNTED
14.83
6.35
70.61
410.45
144837500
PROCESS COST OVER
13.60
5. A3
64.76
376.40
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
14.83
6.35
70.61
410.45
144837500
POWER UNIT
13.60
5.03
64.76
376.40
-------
TABLE A-19. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(1000-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators.
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO- absorption (four TCA scrubbers including presaturators
and entrainment separators, recirculatlon tanks, agitators,
and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities Including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
T
-------
TABLE A-20. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS
(1000-MW existing coal-
3.5% S in coal; 1.
heat input allowable emission;
fired power unit,
2 Ib S02/MBtu
onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost. $
Total
annual
cost, $
320,600 tons
7.00/ton
36,750 man-hr 12.50/man-hr
2,244.200
2,244,200
459,400
979,700 MBtu
503,400 kgal
113,344,000 kWh
6,100 man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
17. 00 /man-hr
1,959,400
60,400
3,173,600
2,593,400
103,700
8,349,900
10,594,100
% of average
annual revenue
requirements
1.98
8.43
0.26
13.65
Indirect Coats
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.32
4,587,500
6,435,400
1,578,300
45,900
12,647,100
23,241,200
S/ton coal $/MBtu heat $/short
19.74
27.69
6.79
0.20
54.42
100.00
ton
burned Input S removed
7.75 0.37 332.
02
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 2,999,850 gons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 70,000 short tons/yr; solids disposal 368,400 tons/yr Ca solids Including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $40,966,000; total depreciable investment, $71,680,000; and total
capital investment, $74,830,000.
159
-------
TABLE A-21
LIMFSTONE SLURRY PHoCF.SS 1000 »•* fXISTlNG COftL-FHtn HO»F.« UNIT
5 IN COAL« WEGULATED CO. ECONOMICS
FlxFfl INVESTMENT:
YEARS ANNUAL
AFTFR OPEHA-
POWFR TION,
UNIT PO*KR UNIT
HEAT FUFL
rfFOUI*F"ENT. CONSUMPTION.
UNIT KH-HR/ MILLION
START KW
TONS COAL
/YEAH
SULFU-*
POLLUTION
CONTROL
"WOCFSS.
TONS/YF«,v
'•"Y-PPUUUCT
EQUIVALENT
OHY
SOLIDS
7*830000
NET KEVtNUE.
*/TON
OHY
SOLIDS
TOTAL
OP. COST
INCLUDING
MEGULATEO
HOI FOR
POMF.Q
TOTAL
NET
SALES
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
COMPANY! REVENUE. POxER.
*/YFAW
S/YEAR
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
PO«ER»
*
1
2
3
4
s
6
7
8
9
|0
11
12
13
14
15
7000
7000
7000
7000
5000
5000
5000
5000
5000
16 3500
17 3500
18 3500
19 3500
.22 3522
21 1500
22 1500
23 1500
24 1500
25 1522
26 1500
27 1500
28 1500
29 1500
32 1522
63000000 3000000
63000000 3000000
63000000 3000000
63000000 3000000
63.2o.2D2" 3_U2Qojip_
45000000 2142900
45000000 214P900
45000000 214?9l)0
45000POO 214POQO
31500000 1500000
31300000 1500000
31500000 1SOOOOO
31600000 1500000
13500000 642900
13500000 642900
1350000D 642-^00
13500000 642900
13500000 64291)0
13500000 642*00
13500000 642aOO
13500000 642900
7ci(jOO
70000
70000
StiOOO
S 0 0 0 0
soooo
S 0 0 0 0
350 TO
350 no
35000
1SOOO
15000
15000
1SOOO
15000
1^000
1SOOO
15000
368400
36H400
36rt400
263100
263100
263100
263100
1^4200
184200
184200
184200
7MVOO
78900
78900
7H900
78900
78900
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0
0
0
ft
0
0
0
0
.0
.0
.0
.11
Aft
.0
.0
.0
.0
29676700 0
29183500 0
28197200 0
2112*222 2 -
2*11*800
23621600
23128500
22635300
22112123
19251?00
18758000
18264900
17771700
U21£5JJO.
12896000
12402900
11909700
10923*00
10430200
9937100
9443900
1 0
I 0
I 0
i 0
! 2
1 0
I 0
i 0
i 0
a
0
0
0
0
_ a__
29676700 29676700
29183500 58B60200
28690300 87550500
28197200 115747700
.21121220. _U3*.illttO
24114800 167566500
23621600 191188100
23128500 214316600
22635300 236951900
22112102 25_9_Q.ilMO
19251200
18758000
18264900
17771700
.112145 flft
13389200
12896000
12402900
11909700
114.16600
278345200
297103200
315368100
333139800
.352110.12.0
363807500
376703500
389106*00
401016100
0 10923400 423356100
0 10430200 4337B6300
0 9937100 443723*00
0 9443900 453167300
2 8252S22 IMllfilAO
TOT 92500 832SOOOOO 39643500 9?SOOO 4867500
LIFETIME AVERAGE INCPEASE (OECwFASE) IN UNIT yPF&ATlNfi COST
DOLLARS PFe TON OF COAL rJUwNdi)
MILLS PFfc KlLO^ATT-hOU*
CENTS PER MILLION HTU HFAT INPUT
DOLLARS PER TON OF SULF'JW HEMOVFO
PROCESS COST DISCOUNTED AT ll.h* TO INITIAL Y£AK. HOLLARS
462118100
11.66
5.00
55.51
499.59
188891100
0.0
0.0
0.0
0.0
462118100
11.66
5.00
55.51
499.59
188891100
LEVELIZEO INCREASE (DEC*FASE> IM UN'T OMKHATINI-. COST EUUIVALENT TO DISCOUNTED PROCESS COST OVEH LIFE OF PO»EK UNIT
DOLLARS PER TON OF COAL nu-»Mtu 10.52 o.o 10.52
MILLS PFfi KILOWATT-HOUW 4.SI 0.0 4.51
CFNTS PFP MILLION BTU Hf AT J.M^UT 50.07 0.0 50.07
DOLLARS PEP TON OF SULFI;* kEMOVfO 450.71 0.0 450.71
-------
TABLE A-22. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(1000-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
% of
total direct
Investment. $ Investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO- absorption (four TCA scrubbers including presaturators
and entralnment separators, recirculation tanks, agitators,
2,199,000 5.7
2,229,000 5.7
7,135,000
18.3
and pumps)
Stack gas reheat (four Indirect steam reheaters)
Solids disposal (onsite disposal facilities Including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps )
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total Indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable Investment
Land
Working capital
Total capital investment
13,087,000
1,875,000
2,104,000
28,629,000
1,718,000
30,347,000
8,547,000
38,894,000
1,299,000
277,000
5,019,000
1,551,000
8,146,000
9,408,000
56,448,000
A, 790, 000
6,774,000
68,012,000
1,717,000
1,694,000
71,423,000
33.7
4.8
5.4
73.6
4.4
78.0
22.0
100.0
3.3
0.7
12.9
4.0
20.9
24.2
145.1
12.3
17.5
174.9
4.4
_4.3
183.6
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling^ mid-1979.
Stack gas reheat to 175 F by Indirect steam reheat.
Minimum In-process storage; only pumps are spared.
Disposal pond located .1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
161
-------
TABLE A-23. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(1000-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost. $ requirements
309,900 tons
7.00/ton
36,750 man-hr 12.50/man-hr
2,169^300
2,169,300
459,400
947,000 MBtu
487,200 kgal
109,566,000 kWh
6,100 man-hr
2.00/MBtu
0.1 2 /kgal
0.028/kWh
1 7 . 00/man-hr
1,894,000
58,500
3,067,800
2,380,700
103,700
7,964,100
10,133,400
9.92
9.92
2.10
8.66
0.27
14.03
10.88
0.47
36.41
46.33
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
4,080,700
6,142,400
1,471,900
45,900
11,740,900
21,874,300
18.65
28.08
6.73
0.21
53.67
100.00
Mllls/kWh
S/ton coal
burned
Equivalent unit revenue requirements
3.12
7.54
$/MBtu heat
input
0.36
$/short ton
S removed
323.25
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 2,900,100 gons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 67,670 short tons/yr; solids disposal 356,140 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $38,894,000; total depreciable investment, $68,012,000; and total
capital investment, $71,423,000.
162
-------
TABLE A-24
LIMESTONE SLURRY PROCESS 1000 Mw NE» COAL-F I^FO i^OWFh UNIT 3.S% S IN COAL« REGULATED CO. ECONOMICS
YEARS
AFTER
POWER
UNIT
START
ANNUAL
OPERA-
TION,
KW-HR/
KM
POWER UNIT
HEAT
REQUIREMENT,
MILLION HTU
/YEAR
POWER UNIT
FUEL
CONSUMPTION,
TONS COAL
/YEAR
FIXFO INVESTMENT: * 71423000
SULFUrt
"EMOVtU
RY
POLLUTION
CONTwoL
PROCESS.
HY-^RODUCT
EQUIVALENT
TONS/YEAH
SOLIDS
NET REVENUE.
*/TON
DRY
SOLIDS
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
TOTAL
NET
SALES
REVENUE,
I/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
%
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER*
S
UJ
1
2
3
4
-.5.
6
7
fl
9
.10.
11
12
13
14
~16~
17
18
22
23
24
~26~
27
28
29
.32-
7000
7000
7000
7000
—2202.
7000
7000
7000
7000
—2202-
5000
5000
5000
5000
5222.
3500
3500
3500
3500
—3522-
1500
1500
1500
1500
1522-
1500
1500
1500
1500
1522.
60900000
60400000
60900000
60900000
—623.0.2222.
60900000
60900000
60900000
f.0900000
—6.2522222-
43500000
43500000
43500000
43500000
— 4.3.522222-
30450000
30450000
30450000
30450000
—32452222.
13050000
130SOOOO
13050000
130SOOOO
—1325.2222-
13050000
13050000
13050000
13050000
2900100
2900000
2900000
2900000
22Q2229_.
3900000
2900000
2900000
2900000
67700
h7700
677CO
356100
356100
35MOO
35MOO
2071400
2071400
2071400
2071400
2211422..
1450000
1450000
1450000
1450000
>>7700
67700
67700
h7/00
61Z22_.
356100
356100
356100
356100
0.0
0.0
0.0
0.0
.0*2-
0.0
0.0
0.0
0.0
28016100
27626100
27236200
26H46200
4H400
254400
254400
254400
254400
33*00
33900
33900
621400
621400
621400
621400
621*2P_.
(S21400
621400
621400
621400
621«20__
I4b00
I4b00
14^00
14^0(1
Isa22_.
178100
17B100
178100
178100
Ilttl0.2_
76300
76300
7h300
76300
0.0
0.0
0.0
0.0
-!Uft-
0.0
0.0
0.0
0.0
26066400
25676400
25266500
24696500
245.06.620..
21155300
20765400
20375500
199H5SOO
12515622.
16914400
16524500
16134600
15744600
14bOP
U52JL.
76300
76300
7fJOO
76300
0.0
0.0
0.0
0.0
-2*2.
o.u
0.0
0.0
0.0
.0*2.
11724600
11334700
10944700
10554*00
0 28016100
0 27626100
0 27236200
0 26646200
0 264563.22.
0 26066400
0 25676400
0 25286500
0 24896500
2 24526622-
0 21155300
0 20765400
0 20375500
0 19985500
2 12525602-
0 16914400
16524500
16134600
15744600
.15354100.
11724600
28016100
55642200
82878400
109724600
11334700
10944700
10554800
9774900
93H5000
8995000
8605100
8215222
544862300
0
0
0
a
o
0
0
0
a iai642oo.
0 9774900
0 9385000
0 8995000
0 8605100
0 82.15200.
0 544862300
162247300
187923700
213210200
238106700
2626133,00
283768600
304534000
324909500
344895000
264420600
381405000
397929500
414064100
429808700
4451634OO
456888000
468222700
479167400
489722200
422flaiIOO
509662000
519047000
528042000
536647100
544862200
TOT 127500 1109250000 S2H21000 1233500 6466500
LIFETIME AVERAGE INCREASE (DECREASE) I'M UNIT OPERATING COST
DOLLARS PER TON OF COAL
MILLS PFR KILOKATT-hOUw
CFNTS PER MILLION PTU MFAT
HOLLARS PER TON OF <-ULFUK REMOVED
PROCESS COST DISCOUNTED AT 11.6* To INITIAL YEAK, HOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF POWER UNIT
DOLLARS PER TON OF COAL HUtfNEO 9.50 0.0 9.50
MILLS PFR KILOdATT-nOUK 3.9* 0.0 3.94
CENTS PER MILLION HTU KF»T INHUT 45.26 o.o 45.26
HOLLARS PER TON OF SULFUR WEMOVFO 407,06 0.0 407.06
10.32
4.?7
49.12
441.72
195672000
0.0
0.0
0.0
0.0
0
10.32
4.27
49.12
441.72
195672000
-------
TABLE A-25. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; trucking alternative)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO, absorption (four TCA scrubbers including presaturators
and entralnment separators, reclrculation tanks, agitators,
and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (thickener, drum filters, tanks, agitators,
pimps, and conveyors)
Subtotal
Services, utilities, and miscellaneous
Total direct Investment
jndlrect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable Investment
Land
Working capital
Trucking charge (Including Indirect charges)
Total capital Investment
Investment , $
1,759,000
1,740,000
A, 318, 000
8,918,000
1,282,000
2,400.000
20,417,000
1,225,000
21,642,000
1,255.000
314,000
3,208,000
993,000
5,770,000
5.482,000
32,894,000
3,289,000
3.947.000
40,130,000
361,000
1,282,000
534,000
42,307.000
Z of
total direct
Investment
8.1
8.0
20.0
41.2
5.9
ll.j
94.3
5.7
100.0
5.8
1.5
14.8
4.6
26.7
25.3
152.0
15.2
18.2
185.4
1.7
5.9
2.5
195.5
BMlt
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
coit belli for scaling, mid-1979.
Stack (as reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal area located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered,
164
-------
TABLE A-26. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; trucking alternative)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Limestone 158,300 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 43,500 man-hr
Operating labor disposal equipment 42,000 man-hr
Utilities
Steam 489,800 MBtu
Process water 247,400 kgal
Electricity 58,119,000 kWh
Fuel 245,930 gal
Maintenance
Labor and material
Analyses
Disposal land preparation
Total conversion costs
Total direct costs
3,980 man-hr
5.3 acres
7.00/ton
12.50/man-hr
17.00/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
0.60/gal
17.00/man-hr
1600/acre
1,108.100
1,108,100
543,800
714,000
979,600
29,700
1,685,500
147,600
2,100,400
67,700
8.500
6,276,800
7,384,900
3.58
4.71
6.46
0.20
11.11
0.97
Indirect Costs
Capital charges
Depreciation, interim replacements, and
Insurance at 6.0% of total depreciable
Investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10Z of operating labor
Trucking labor
Total indirect costs
Total average annual revenue requirements
2,487,200
3,633,400
1,171,500
54,400
441.000
7,787,500
15,172,400
S/ton coal $/MBtu heat $/short ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements
4.33
10.11
0.48
433.50
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 35,000 short tons/yr; solids disposal 184,200 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $21,642,000; total depreciable investment, $40,130,000; and total
capital investment, $42,307,000.
165
-------
TABLE A-27
UMESinNt SLURRY FROCtSi 500
NtV CCAL-HRID POUER UNIT 3.5XS 1H COM., TkUCKlNt, REGULATED CO. ECONOMICS
FIXED INVESTMENT: & 42307000
SULFUR BV-PRLDUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POkFR UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TICN. REQUIREMENT, CONSUMPTION, CONTROL
UNIT Kk-KR/ MLL1GN Pit TCftS CCAL PRCCESS. DRY
START KW /YEAR /YEAR TONS/YEAR SOLIDS
1 7000 31500JOU 1500000 34600 lf><-200
2 70CO 31500000 1500COO 34600 11'4200
3 7000 31500000 1503C30 34630 184200
4 7000 3150000C 1500COO 346CO 184200
-S 710.1 ^1^3n">nn I^QIQQQ l4.kOQ l«4?oa
6 TOGO 31500000 lr<00000 34600 184200
7 7000 31500000 1500P30 34630 lt>4200
* 7000 3150000C 1500COO 34600 184200
9 7003 31530300 1503000 34630 104200
_1Q IDUfl •< is none P lifllJiDXl iiiflO 1&42.QO,
11 5000 22500000 10714PO 24700 131600
1? 5000 22500000 1071400 24700 131600
13 5000 2250U300 1071430 24700 131600
14 5000 22500GOC 1P71400 24700 131600
LS fflOO 7?"i:lQGO7 1500 6750900 321400 7400 39533
28 15CO 675000C 32140C 7400 3«500
29 1500 6750000 321400 7400 39500
_3JJ_ 1300 £J!tQQQQ 22,1.40.0. _24DQ 31500.
TOT 127500 573750000 27321000 630000 3355533
LIFETIME AVERAGE INCREASE UECKEASLI IN UNIT OPERATING COST
DOLLARS PE* TDK CF CCAL BORNEO
KILLS PER KltrVATT-HGUR
CENTS PEB MIL ION KTL< HEAT INPUT
DOLLARS PER TDK OF SULFUk REMOVED
PROCESS CCST OISCCLMEC AT 11.6% TO INITIAL YEAR, DOLLARS
LEVELIZEO INCREASE (DECREASE) Ifc UNIT OPERATING COST ECUIVALENT TO
OriLLAKS PER TON OF COAL 6UKNED
MILLS PFR KHDKATT-HPUR
CENTS PER Mil ION BTU HEAT INPUT
PLLLARS FES UK CF SILFUK fEMOVFD
TOTAL
OP. COST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE, REGULATED TOTAL INCREASE hET INCREASE
>/TON R01 FOR NET (DECREASEI (DECREASE 1
POWER SALES IN COST OF IN COST OF
CRY COMPANY, REVENUE, POWER, POWER.
SOLIDS I/YEAR I/YEAR t $
0.0
G.O
C.O
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
ttJO.—
0.0
OJ>
0.0
0.0
c.o~
0.0
0.0
0.0
U>Q
0.0
0.0
0.0
0.0
DISCfUNlED
IBBltO))
1R5B5900
18355R}]
16125800
17665600
1 743553 J
17205400
16975300
0
0
0
0
_Q-
0
0
0
0
0
14414433 0
14184300 0
13954233 0
13724100 0
13A94QDJ1 0-
11598900 0
1136C930 0
11138800 0
10908700 0
7990500
7760400
7530300
7300300
7O7O700
6840100
6610090
6379900
6149800
372*22400
13.65
5.85
64.98
591 .71
132750600
PROCESS COST OVER
12.47
5.34
59.36
540 .52
0
0
0
0
o_
30000
0
0.0
0.0
0.0
3.0
0
LIFE OF
0.0
0.0
0.0
0.0
18816000
18585900
18355800
18125800
Lzas&zao.
17665600
17435500
17205400
16975300
1AJ&320Q
14414400
14184300
13954200
13724100
i^4»4nnn
11598900
11368900
11138800
10908700
7990500
7760400
7530300
7300300
7
-------
TABLE A-28. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; onsite solids disposal)
% of
total direct
Investment, $ investment
Direct Investment
bins, shaker, puller)
Feed preparation (feeders, curshers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
S0_ absorption (four TCA scrubbers Including presaturators
and entrainment separators, reclrculation tanks, agitators,
and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable Investment
Land
Working capital
Total capital investment
1,788,000
1,804,000
4,323,000
8,930,000
1,283,000
1,752,000
19,880,000
1,193,000
21,073,000
5,867,000
26,940,000
1,228,000
270,000
3,703,000
1,173,000
6,374,000
6,663,000
39,977,000
3,411,000
4,797,000
48,185,000
1,175,000
1,077,000
50,437,000
6.6
6.7
16.0
33.2
4.8
6.5
73.8
4.4
78.2
21.8
100.0
4.6
1.0
13.7
4.4
23.7
_24.7^
148.4
12.7
17.8
178.9
4.4
3.9
187.2
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scalingj mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
167
-------
TABLE A-29. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
192,000 tons
7.00/ton
25,990 man-hr 12.50/man-hr
1.344.000
1,344,000
324,900
9.17
9.17
2.22
489,800 MBtu
264,200 kgal
57,197,000 kWh
3,760 man-hr
2.00/MBtu
0.1 2 /kgal
0.029/kWh
17.00/raan-hr
979,600
31,700
1,658,700
1,861,900
63,900
4,920,700
6,264,700
6.68
0.22
11.32
12.71
0.44
33.59
42.76
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
Investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
2,891,100
4,337,600
1,125,400
32.500
8,386,600
14,651,300
19.73
29.61
7.68
0.22
57.24
100.00
Mills/kWh
Equivalent unit revenue requirements
4.19
S/ton coal $/MBtu heat $/short ton
burned input S removed
9.77
0.47
358.22
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 40,900 short tons/yr; solids disposal 215,250 tons/yr Ca solids Including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $26,940,000; total depreciable investment, $48,185,000; and total
capital investment, $50,437,000.
168
-------
TABLE A-30
LIMFSTONE SLURRY PROCESS 500 MVK NE* COAL-FIPED POxER UNIT 1.5* S 90% REMOVAL REGULATED CO. ECONOMICS
FIXED INVESTMENT:
50437000
SULFUR flY-PRODUCT
REMOVED HATE.
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTFR OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWFR TION, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION HTU TONS COAL PROCESS, DHY
START KW /YEAR /YEAR TONS/YEAR SOLIDS
1 7000 31500000 1500000 *0900
2 7000 31500000 1500000 40900
3 7000 31500000 1500000 40900
4 7000 31500000 1500000 40900
5 2222 31522222 1522222- 42*2tt
6 7000 31500000 1500000 4090ft
7 7000 31500000 1500000 40900
8 7000 3150000P 1500000 40900
9 7000 31500000 1500000 40900
IQ 7222 31522222 _ 1522222- 40.9.21
215300
215300
215300
215300
215322
215300
215300
215300
215300
215300
11 5000 22500000 1071*00 29200 153800
12 5000 22500000 1071*00 29
-------
TABLE A-31. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT0
(500-MW existing oil-fired power unit,
2.5% S in oil; 0.8 Ib S02/MBtu heat input
allowable emission; onsite solids disposal)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist,
tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
SO- absorption (four TCA scrubbers including presaturators
and entrainment separators, recirculatlon tanks, agitators,
and pumps)
Stack gas reheat (four direct oil reheaters)
Solids disposal (onsite disposal facilities including feed
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, S
1,077,000
1,196,000
4,447,000
8,377,000
726,000
1,399,000
17,222,000
1,033,000
18,255,000
2,020^00
20,275,000
1,101,000
257,000
3,018,000
945,000
5,321,000
5,119,000
30,715,000
2,870,000
3,686,000
37,271,000
409,000
800,000
38,480,000
% of
total direct
investment
5.3
5.9
21.9
41.3
3.6
6.9
84.9
5.1
90.0
10.0
100.0
5.4
1.3
14.8
4.7
26.2
25.3
151.5
14.2
18.1
183.8
2.0
4.0
189.8
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175 F by direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
170
-------
TABLE A-32. LIMESTONE SLURRY PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW existing oil-fired power unit,
2.5% S in oil; 0.8 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
62,410 tons
7.00/ton
24,860 man-hr 12.50/man-hr
436,900
436,900
310.800
2,676,600 gal
174,700 kgal
45,618,000 kWh
3,590 man-hr
0.40/gal
0.12/kgal
0.029/kWh
17.00/man-hr
1,070,600
21,000
1,322,900
1,541,200
61,000
4,327,500
4,764,400
2.72
9.35
0.18
11.56
13.46
0.53
37.80
41.62
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital Investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 107. of operating labor
Total Indirect costs
Total average annual revenue requirements
$/bbl oil
Mllls/kWh burned
Equivalent unit revenue requirements 3.27 2.15
2,
3,
6,
11,
385,
309,
956,
31,
682,
446.
$/MBtu heat
input
0.35
300
300
500
100
200
600
$/short
20.
28.
8.
0.
58.
100.
ton
84
91
36
27
38
00
S removed
770.
81
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Oil burned, 5,350,000 bbl/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 F.
S removed, 14,850 short tons/yr; solids disposal 63,030 tons/yr Ca solids Including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $20,275,000; total depreciable investment, $37,271,000; and total
capital investment, $38,480,000.
171
-------
TABLE A-33
LIMESTONE SLURRY PROCESS 500 M* EXISTING OIL-FIRtU POWER UNIT 2-5Z S IN OIL, HE5ULATEO CO. ECONOMICS
FIKF.O INVESTMENT: S 38*80000
ro
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KM
POWER UNIT
HEAT
REQUIREMENT,
MILLION BTU
/YEAR
POWER UNIT
FUFL
CONSUMPTION,
BARRELS OIL
/YEAR
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAH
HY-PROOUCT
RATE,
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
NET REVENUE
S/TON
DRY
SOLIDS
TOTAL
OP. COST
INCLUDING
, REGULATED
HOI FOR
POWER
COMPANY,
S/YEAR
TOTAL
NET
SALES
REVENUE,
*/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
X
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
2
3
4
5
6 7000 32200000
7 7000 32200000
8 7000 32200000
9 7000 32200000
_12 Z222 32222222
11 5000 23000000
12 5000 23000000
13 5000 23000000
14 5000 23000000
_15 - 5222. 23222222
16 3500 16100000
17 3500 16100000
18 3500 16100000
19 3500 16100000
.22 3522 16122222
21 1500 6900000
22 1500 6900000
23 1500 6900000
24 1500 6900000
25— 1522. 690QQQH
26 1500
27 1500
28 1500
29 1500
.32 1522. .
5324100
5324100
5324100
5324100
5324122
3802900
3802900
3MOP900
3802900
_3822222_ .
2662000
2662000
2662000
2662000
—2662222
1140900
1140900
1140900
1140900
1140900
6900000 1140900
6900000 1140900
6400000 1140900
6900000 1140900
690QOOO 11*Q9BQ
14800
14BUO
14«00
14800
10600
lObOO
IflbOO
lObOO
_ 12&22
7400
7400
7400
7400
3200
3200
3200
3200
3222
3200
3200
3200
3200
3222
63000
63000
63000
63000
63222
45000
45000
45000
45000
4.50.22
31500
31500
31500
31500
31522
13500
13500
13500
13500
1352"
13500
13500
13500
13500
13522_.
0.0
0.0
0.0
0.0
2*2 _
0.0
0.0
0.0
0.0
-2*2
14755500
14499000
14242600
1 39H6POO
131£9QQQ
0 14755500
0 14499000
0 14242600
0 13986200
0 13729800
12077300 0 12077300
11820900 0 11820900
115b4400 0 11564400
1130HOOO 0 11308000
1IOS1AOA 0 11051600
0.0 9701000
0.0 9444600
0.0 9188100
0.0 8931700
2*2 fl6l53flfl_
0.0 6835500
0.0 6579100
0.0 6322700
0.0 6066200
0.0 5553400~
0.0 5297000
0.0 5040600
0.0 4784200
__2«.2 4527700
0
0
0
0
0
0
0
0
g
0
0
0
0
2 .
9701000
944<»600
9188100
8931700
8615322—
6835500
6579100
6322700
6066200
5fl22fl22_
5553400
5297000
5040600
4784200
4521Z22
14755500
29254500
43497100
57483300
11213120
83290400
95111300
106675700
117983700
122235220
138736300
148180900
157369000
166300700
114216220
181811500
188390600
194713300
200779500
__2265H2320
212142700
217439700
222480300
227264500
__2211i2220
TOT 92500 425500000 70354000 196000 832500 231792200 0 231792200
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED 3.29 o.o 3.29
MILLS PER KILOWATT-HOUR ^.01 o.o 5.01
CENTS PER MILLION BTU HEAT INPUT 54.48 o.o 54.48
DOLLARS PER TON OF SULFUR REMOVED 1182.61 0.0 1182.61
PROCESS COST DISCOUNTED AT 11.6% TO INITIAL YEArt, DOLLARS 94271900 0 94271900
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PKOCESS COST OVER LIFE OF POWER UNIT
DOLLARS PER BARREL OF OIL BURNED 2.96 0.0 2.96
MILLS PER KILOWATT-HOUR 4.50 0.0 4.50
CENTS PER MILLION BTU HEAT INPUT 48.89 o.o 48.89
DOLLARS PER TON OF bULFUR REMOVED 1062.S2 O.C 1062.82
-------
TABLE A-34. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(200-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Materials handling (conveyors , elevators , bins , and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
dampers from absorber to reheater and stack)
S02 absorption (two tray towers including presaturators and
entrainraent separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (two indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks , agitators,
pumps, and conveyors)
Solids disposal (onsite disposal facilities including
res lurry tank, agitator, slurry disposal pumps , and pond
water return pumps)
Subtotal
Services, utilities, and miscellaneous
Pond cons t rue t ion
Total direct invest men t
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , S
961,000
550,000
2,141,000
4,354,000
584,000
238,000
1,555,000
891,000
11,274,000
676,000
Uqcfl nnn
, 7 3U , UUU
1,197,000
13,147,000
1,099,000
262,000
2,111,000
680,000
4,152,000
3,460,000
20,759,000
1,956,000
2,491,000
25,206,000
243,000
557,000
26,006,000
% of
total direct
investment
7.3
4.2
16.3
33.1
4.4
1.8
11.8
6.8
85.7
5.2
90.9
9.1
100.0
8.4
2.0
16.1
5.1
31.6
26.J
157.9
14.9
18.9
191.7
1.8
4.3
197.8
a. Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream.
Construction labor shortages with accompanying overtime pay incentive not considered.
173
-------
TABLE A-35. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(200-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
p-frect Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
26,850 tons 42.00/ton
2,560 tons 90.00/ton
22,490 man-hr 12.50/man-hr
206,800 MBtu 2.00/MBtu
102,100 kgal 0.12/kgal
12,270,000 kWh 0.031/kWh
2,630 man-hr 17. 00 /man-hr
Total % of average
annual annual revenue
cost, $ reauirements
1,127,700
230,400
1,358,100
281,100
413,600
12,300
380,400
580,600
44,700
1,712,700
3,070,800
14.83
3.05
17.98
3.72
5.48
0.16
5.04
7.69
0.59
22.68
.40.66
Costs
Capita1 charges
pepreciation, interim replacements, and
insurance at 7.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
overheads
plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,764,400
2,236,500
453,200
28,100
4,482,200
7,553,000
23.36
29.61
6.00
0.37
59.34
100.00
Mills/kWh
Eauivalent
unit revenue requirements
5.40
$/ton coal $/MBtu heat $/short ton
burned input S removed
11.92
0.57
511.03
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 20 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 633,500 tons/yr, 9,500 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 14,780 short tons/yr; solids disposal 60,280 tons/yr Ca solids including only hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $13,147,000; total depreciable investment, $25,206,000; and total capital
investment, $26,006,000.
174
-------
TABLE A-36
Ol
GENERIC DOUBLE ALKALI PROCESS 200 MW EXISTING COAL-FIRED POWER UNIT 3.5% S IN COALt REGULATED CO ECONOMICS
FIXED INVESTMENT:
26006000
YEARS ANNUAL
AFTER OPERA-
POWER UNIT
HEAT
POWER UNIT
FUEL
SULFUR
REMOVED
BY
POLLUTION
BY-PRODUCT
HATE.
EQUIVALENT
TONS/YEAR
NET REVENUE,
S/TON
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
TOTAL
NET
NET ANNUAL
INCREASE
(DECREASE)
CUMULATIVE
NET INCREASE
(DECREASE)
POWER TION. REQUIREMENT, CONSUMPTION.
UNIT KW-HR/ MILLION BTU
START
KW
/YEAR
TONS COAL
/YEAR
CONTROL
PROCESS.
TONS/YEAR
POWER
SALES IN COST OF IN COST OF
DRY
SOLIDS
DRY
SOLIDS
COMPANY, REVENUE. POWER,
POKER.
S/YEAR
S/YEAR
1
2
3
4
5
6
7
8
9
11 5000
12 5000
13 5000
14 5000
15 _5flflO.
16 3500
IT 3500
8 3500
19 3500
_2ft 35flft
21 1500
22 1500
23 1500
24 1500
25 ISflft
9500000
9500000
9500000
9500000
6650000
6650000
6650000
6650000
2850000
2850000
2850000
2850000
295QQOO
26 1500 2850000
27 1500 2850000
28 1500 2850000
29 1500 2850000
-30. l5P.fi 235P.O.OJZ
452400
452400
452400
452400
_452ififi
316700
316700
316700
316700
_ai6ifla
135700
135700
135700
135700
_135Iflfl
135700
135700
135700
135700
10600
10600
10600
10600
7400
7400
7400
7400
7400
3200
3200
3200
3200
3200
3200
3200
3200
3100
320.0
43100
43100
43100
43100
30100
30100
30100
30100
12900
12900
12900
12900
12900
12900
12900
12900
1220.P.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
SUfl.
0.0
0.0
0.0
0.0
8903100 0 8903100 8903100
8686400 0 8686400 17589500
8469600 0 8469600 26059100
8252800 0 8252800 34311900
aP.16.9JlP. Q__ 8036000 48347900
7128500 0
6911700 0
6694900 0
6478200 0
6261400 Q
5061200 0
4844400 0
4627700 0
4410900 0
*1?HQO 0
3977400 0
3760600 0
3543800 0
3327000 0
aiuaaa a
7128500 49476400
6911700 56388100
6694900 63083000
6478200 69561200
6.26.1422 18&22MO
5061200 80883800
4844400 85728200
4627700 90355900
4410900 94766800
3977400 102938300
3760600 106698900
3543800 110242700
3327000 113569700
3110JO.O. Ub&aP. 0.0.0
TOT 57500 109250000 5202500 12?000 495000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAH, DOLLARS
116680000
22.43
10.15
106.80
956.39
53388600
0.0
0.0
0.0
0.0
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TON OF COAL BUPNEO 20.75 0.0
MILLS PEP KILOWATT-HOUH 9.39 0.0
CENTS PER MILLION BTU HEAT INPUT 98.80 0.0
DOLLARS PER TON OF SULFUR REMOVED 885.38 0.0
116680000
22.43
10.15
106.80
956.39
53388600
POWER UNIT
20.75
9.39
98.80
885.38
-------
TABLE A-37. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENTa
(200-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
% of
total direct
Investment, $ investment
Direct Investment
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts, and
dampers from absorber to reheater and stack)
S02 absorption (two tray towers including presaturators and
entrainraent separators, recirculatlon tanks, agitators, and
pumps)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps , and conveyor)
Solids disposal (onsite disposal facilities including
reslurry tank, agitator, slurry disposal pumps, and pond
water return pumps)
Subtotal
Services, utilities, and miscellaneous
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
846 ,000
489,000
1,853,000
3,926,000
569 ,000
209,000
1,375,000
776,000
10,043,000
603,000
10,646 ,000
2,141,000
12,787,000
1,140,000
266.000
2,025,000
666.000
4,097,000
3,377,000
20,261.000
1,812,000
2,431,000
24,504,000
425,000
548,000
25,477,000
6.6
3.8
14.5
30.7
4. 5
1.6
10.8
6.1
78.6
4.7
83.3
16.7
100.0
8.9
2.1
15.8
5.2
32.0
26.4
158.4
14.2
19.0
191.6
3.3
4.3
199.2
a. Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream.
Construction labor shortages with accompanying overtime pay incentive not considered.
176
-------
TABLE A-38. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(200-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
26,010 tons
2,480 tons
22,490 man-hr
200,300 MBtu
98,700 kgal
11,880,000 kWh
2,630 man-hr
Unit
cost, $
42.00/ton
90.00/ton
12.50/man-hr
2. 00 /MBtu
0.12/kgal
0.031/kWh
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,092,400
223,200
1,315,600
281,100
400,600
11,800
368,300
596,500
44,700
1,703,000
3,018,600
15.24
3.12
18.36
3.92
5.59
0.16
5.14
8.32
0.62
23.75
42.11
Indirect Costs
Capital charges
Depreciation, interim replacements and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.67.
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements , ,- 11 to
1,470,200
2,191,000
461,200
28,100
4,150,500
7,169,100
$/MBtu heat $/short ton
input S removed
0.56 500.99
20.
30.
6.
0.
57.
100.
51
56
43
39
89
00
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 613,000 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 14,310 short tons/yr; solids disposal 58,360 tons/yr Ca solids including only hydrate
water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $12,787,000; total depreciable investment, $24,504,000; and total capital
investment, $25,477,000.
177
-------
A-J9
DOUfcU *UUU PHOCtiS 200 Ml HIM COM.-f\UO POWER UH11 3.iX S 1H CUM, MGUUUD CO ECONOMICS
FIXED INVESTMENT: I 254V7QOO
oo
YEARS ANNUAL
AFTER OPERA-
POWER T10N,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
s 7nnn
SULFUR BY-PRDDUCT
REMOVED RATE,
POWER UNIT POkER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS, DRY
/YEAR /YEAR TONS/YEAR SOLIDS
12880000 613300 14300
12880000 613300 14300
12880000 613300 14300
12880000 613300 14300
i7««nnno «.i*3on it inn
6 7000 12880000 613300 14300
7 7000 12880000 613300 14300
8 7000 12880000 613300 14300
9 7000 12880000 613300 14300
-10. 7J1Q.O. i»RAr>nnn *,mnn 14300
11 5000
12 5000
13 5000
14 5000
i s
-------
TABLE A-40. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Z of
total direct
Investment, $ investment
Materials handling (conveyors, elevators, bins , and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts, and
dampers from absorber to reheater and stack)
SOa absorption (four tray towers including presaturatora and
entrainment separators, reclruclation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks , agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1
5
10
1
2
1
23
1
25
3
28
1
4
1
6
7
42
3
5
51
1
53
.927
932
,058
,126
,312
404
,643
,424
.826
,430
,256
,377
.633
,416
328
,004
,229
.977
,122
.732
,936
,128
,796
678
,201
,675
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
6
3
17
35
4
1
9
5
83
5
88
U
100
5
1
14
4
24
24
149
13
17
180
2
4
187
.7
.3
.6
.4
.6
.4
.2
.0
.2
.0
.2
JL
.0
.0
.1
.0
.3
.4
.8
.2
.8
.9
.9
.4
.2
.5
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
179
-------
TABLE A-41. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS
(500-MW existing coal-fired power unit,
3.5% S in coal; 1.2 lb S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Lime
Soda ash
Utilities
Steam
Proce:
Elect
Mainten,
Labor
Analyses
Annual Unit
quantity cost, $
IStS
•ials
65,010 tons 42.00/ton
ih 6,190 tons 90.00/ton
il raw materials cost
>n costs
.ng labor and supervision 34,500 man-hr 12.50/man-hr
, 500,700 MBtu 2.00/MBtu
>ss water 247,000 kgal 0.12/gal
:ricity 29,700,000 kWh 0.029/kWh
lance
• and material
:s 4,560 man-hr 17. 00 /man-hr
il conversion costs
il direct costs
Total % of average
annual annual revenue
cost, $ requirements
2,730,400
557,100
3,287,500
431,300
1,001,400
29,600
861,300
1,016,400
77,500
3,417,500
6,705,000
17.68
3.61
21.29
2.79
6.49
0.19
5.58
6.58
0.50
22.13
43.42
Costs
Capita1 charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 107. of operating labor
Total indirect costs
Total average annual revenue requirements
enulvalent unit revenue requirements
4.41
3,314,900
4,616,100
762,600
43,100
8,736,700
15,441,700
21.47
29.89
4.94
0.28
56.58
100.00
$/ton coal $/MBtu heat $/short ton
Mills/kWh burned input S removed
10.07
0.48
431.57
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,533,350 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 35,780 short tons/yr; solids disposal 145,931 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $28,633,000; total depreciable investment, $51,796,000; and total
capital investment, $53,675,000.
180
-------
TABLE A-42
GENERIC DOUBLE ALKALI PROCESS 500 Mw EXISTING COAL-FIRED POWER UNIT 3.5% S IN COALt REGULATED CO. ECONOMICS
00
FIXED INVESTMENT:
53675000
YEARS ANNUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START KW
1
2
3
4
.5 _
6 7000
7 7000
8 7000
9 7000
10. _2222
11 5000
12 5000
13 5000
14 5000
15 5222-
16 3500
17 3500
18 3500
19 3500
22 3.50.0.
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT. CONSUMPTION.
MILLION BTU TONS COAL
/YEAR /YEAR
32200000 1533300
32200000 1533300
32200000 1533300
32200000 1533300
322flQ.Qfl.fl 1533300
23000000
23000000
23000000
23000000
232220.22—
16100000
16100000
16100000
16100000
1610QOQQ
21 1500 6900000
22 1500 6900000
23 1500 6900000
24 1500 6900000
_25._ 1522-_ 62HQQQO
26 1500
27 1500
28 1500
29 1500
.38. -1522 _.
6900000
6900000
6900000
6900000
6222222— .
1095200
1095200
1095200
1095200
1225220
766700
766700
766700
766700
266102
32H600
328600
328600
328600
322622
328600
328600
328600
328600
328620
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS.
TONS/YEAR
35800
35800
35800
35800
25600
25600
25600
25600
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
145900
145900
145900
145900
145222
104200
104200
104200
104200
10.4200
NET REVENUE
S/TON
DRY
SOLIDS
0.0
0.0
0.0
0.0
TOTAL
OP. COST
INCLUDING
, REGULATED TOTAL
ROI FOR NET
POWER SALES
COMPANY, REVENUE
S/YEAR S/YEAR
20056100
19701800
19345400
18989100
18632700
0.0 16333300
0.0 15976900
0.0 15620600
0.0 15264200
0.0 14907900
17900 73000 0.0
17400 73000 0.0
17900 73000 0.0
17900 73000 0.0
Hi22. 132.22 . _2*.2
7700 31300 0.0
7700 31300 0.0
7700 31300 0.0
7700 31300 0.0
_ZZ2.2_ _313Q.Q_ 0.0
7700 31300 0.0
7700 31300 0.0
7700 31300 0.0
7700 31300 0.0
7ZOO 31320 (UP. _
13056000
12699700
12343300
11987000
11632622
9180300
8823900
8467600
8111200
Z25*.2flfl
7398500
7042200
6685800
6329500
5973100 .,.
0
0
0
0
2
0
0
0
0
2
0
0
0
0
2
0
0
0
0
2
0
0
0
0
2.
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
, POWER,
S
20058100
19701800
19345400
18989100
,18632700
16333300
15976900
15620600
15264200
14907?00
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
*
20058100
39759900
59105300
78094400
113060400
129037300
144657900
159922100
11*8.30000
13056000 187886000
12699700 200585700
12343300 212929000
11987000 224916000
Ilfe306fl.fl 2.3*5.44620
9180300 245726900
8823900 254550800
8467600 263018400
8111200 271129600
7398500 ~286283000
7042200 293325200
6685800 300011000
6329500 306340500
., ..5213180.... 3U31362.0
TOT 92500 425500000 20262000 473500 1928500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNEQ
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR. DOLLARS
312313600
15.41
6.75
73.40
659.59
127562500
0.0
0.0
0.0
0.0
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TON OF COAL BURNED 13.89 0.0
MILLS PER KILOWATT-HOUR 6.09 0.0
CENTS PER MILLION BTU HEAT INPUT 66.16 0.0
DOLLARS PER TON OF SULFUR REMOVED 594.97 0.0
312313600
15.41
6.7S
73.40
659.59
127562500
POWER UNIT
13.89
6.09
66.16
594.97
-------
TABLE A-43. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit,
2.0% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
S0a absorption (four tray towers including presaturators and
entrainment separators, recirculat ion tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total Indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , S
929,000
524,000
4,248 ,000
9,206,000
1,222,000
224,000
1,476,000
826,000
18,655,000
1,119,000
19,774,000
2,339,000
22,113,000
1,378,000
324,000
3,239,000
1,010,000
5,951,000
5,613,000
33,677,000
3,134,000
4,041,000
40,852,000
464,000
794,000
42,110,000
% of
total direct
investment
4.2
2.4
19. 2
41.6
5.5
1.0
6.7
3.7
84.3
5.1
89.4
10.6
100.0
6.2
1.5
14.6
4.6
26.9
25.4
152.3
14.2
18.2
184.7
2.1
3.6
190.4
a. Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process
investment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
is:
-------
TABLE A-44. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
2.0% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total % of average
annual annual revenue
cost, $ requirements
29,260 tons
2,790 tons
42.00/ton
90.00/ton
31,070 man-hr 12.50/man-hr
489,800 MBtu 2.00/MBtu
226,000 kgal 0.12/kgal
26,130,000 kWh 0.029/kWh
4,125,man-hr 17.00/man-hr
1,228,900
251.100
1,480,000
388,400
10.84
2.23.
13.05
3.43
979
27
757
861
70
3,084
4,564
,600
,100
,800
,100
,100
,100
,100
8.64
0.24
6.68
7.60
0.62
27.21
40.26
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
2,451,100
3,621,500
659,800
38,800
6,771,200
11,335,300
21.63
31.95
5.82
0.3A
59.74
100.00
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements
3.24
7.56
$/MBtu heat $/short ton
input S removed
0.36
699.71
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 16,200 short tons/yr; solids disposal 66,070 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $22,113,000; total depreciable investment, $40,852,000; and total
capital investment, $42,110,000.
133
-------
TABLE A-45
GENERIC DOUBLE M.KM.1 PROCESS BOO MM NEW COAL-FIRED PO«R UNIT Z.0% S IN COM.. REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 42110000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TTON. REQUIREMENT, CONSUMPTION, CONTROL
UNIT KH-HR/ MILLION dTU TONS COAL PROCESS.
START KW /YEAR /YEAR TONS/YEAR
1 7000 31500000 1500000 16200
2 7000 31500000 1500000 16200
3 7000 31500000 1500000 16200
4 7000 31500000 1500000 16200
5 -Iflflfl 315U O.O.O.P. _ 15flflQflO_ _ _ 162flp_ ._
6 7000 31500000 1500000 16200
7 7000 31500000 1500000 16200
B 7000 31500000 1500000 16200
9 7000 31500000 1500000 16200
10 7.0.0.0. 315flftO.O_Q. iSttflflflO- _ _l&2flfl_
11 5000 22500000 1071400 11600
12 5000 22500000 1071400 11600
13 5000 22500000 1071400 11600
14 5000 22500000 1071400 11600
H- lz §0.0.0. 22520.0.0.0. ICZliflQ- llfeflO-
00 16 3500 15750000 750000 6100
** 17 3500 15750000 750000 8100
IB 3500 15750000 750000 8100
19 3600 15750000 750000 8100
gft 35P.O. 1515QP.PJ1 Z5P.g.o.p_ _ &LSHL.
21 1500 6750000 321400 3500
22 1500 6750000 321400 3500
23 1500 6750000 321400 3500
24 1500 6750000 321400 3500
_85 150.Q 625flflaa__ 3214HQ _ _3Sflfl
?6 1500 6750000 321400 3500
27 1500 6750000 321400 3500
28 1500 6750000 321400 3500
29 1500 6750000 321400 3500
39. 150.Q. 6Z50.fl.ttfl 32145 P_ 35flp_
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
NET REVENUE
S/TON
DRY
SOLIDS
66100 0.0
66100 0.0
66100 0.0
66100 0.0
ftfelOfl JUtt
66100 0.0
66100 0.0
66100 0.0
66100 0.0
-, , T.661PO, 0.0
47200
47200
47200
47200
4I2ftfi
33000
33000
33000
33000
33P.OJI
14200
14200
14200
14200
Li20.fl
14200
14200
14200
14200
14200
TOT 127500 573750000 27321000 295500 1204000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 8TU HfAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR. DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
0.0
0.0
0.0
0.0
(Up. _
0.0
0.0
0.0
0.0
(UP. _
0.0
0.0
0.0
0.0
(Up. ..
0.0
0.0
0.0
0.0
p.* B
TOTAL
OP. COST
INCLUDING
. REGULATED TOTAL
ROI FOR NET
POWER SALES
COMPANY. REVENUE.
S/YEAR J/YEAR
14956600
14722400
14488200
14254000
14919000
13785600
13551300
13317100
13082900
. 1264fl700n__, ...
11285300
11051100
10816900
10582700
1034.8*00 ^
9085000
8850800
8616600
8302400
41M20P
64S5100
6220900
5986600
5752400
SSLflZOO
5284000
5049000
4615600
4581400
4347200
290205200
10.62 0.
4.55 0.
50.58 0.
982.08 0.
103925200
DISCOUNTED PROCESS COST OVER LIFE
9.76 0.
4.18 0.
46.47 0.
902.91 0.
0
0
0
0
0
0
0
0
0
p_
0
0
0
0
p.
0
0
0
0
o
0
0
0
0
0
0
0
0
0
o
0
0
0
0
0
0
OF
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
*
14956600
14722400
14488200
14254000
14019000
13785600
13551300
13317100
13082900
J284870.0
11205300
11051100
10816900
10582700
10348400
9085000
88S0800
0616600
8302400
8148900
6455100
6220900
5906600
5752400
5518200
5284000
5049800
4015600
4501400
4347200
290205200
10.62
4.55
50.50
902.08
103925200
POWER UNIT
9.76
4.18
46.47
902.91
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
%
14956600
29679000
44167200
58421200
mtlBQO
06226600
99777900
113095000
126177900
l3.9QZ66.aO
150311900
161363000
172179900
102762600
19.91UQOJ)
202196000
211046000
219663400
220045800
?3*1 94000
242649100
248870000
254056600
260609000
_.26612I2AO
271411200
276461000
201276600
285850000
^91205200
-------
TABLE A-46. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENTa
(500-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
S02 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks , agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Pond construction
Total direct investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , S
1,710,000
833,000
9,206,000
1,282,000
357,000
2,352,000
1,247,000
21,235,000
1,274,000
4,241,000
26,750,000
1,444,000
331,000
3,746,000
1,167,000
6,688,000
6,688,000
40,126,000
3,589,000
4,815,000
48,530,000
837,000
1,184,000
50,551,000
7. of
total direct
investment
6.4
3.1
34.4
4.8
1.3
8.8
4.7
79.4
4.8
15.8
100.0
5.4
1.2
14.0
4.4
25.0
25.0
150.0
13.4
18.0
181.4
3.1
4.4
188.9
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
135
-------
TABLE A-47. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
63,600 tons
6,060 tons
34,500 man-hr
489,800 MBtu
241,500 kgal
29,100,000 kWh
4,560 man-hr
Unit
cost, $
42.00/ton
90.00/ton
12.50/man-hr
2. 00 /MBtu
0.12 /kgal
0.029/kUh
17. 00 /man-hr
Total % of average
annual annual revenue
cost, $ requirements
2,671,200
545,400
3,216,600
431,300
979,600
29,000
843,900
1,027,600
77,500
3,388,900
6,605,500
18.20
3.72
21.92
2.94
6.67
0.20
5.75
7.00
0.53
23.09
45.01
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 4.19
2,911,800 19.
4,347,400 29.
768,200 5.
43,100 0.
8,070,500 54.
14,676,000 100.
$/ton coal S/MBtu heat $/short ton
burned input S removed
9.78 0.47 419.31
84
63
23
29
99
00
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 35,000 short tons/yr; solids disposal 142,750 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $26,750,000; total depreciable investment, $48,530,000; and total
capital investment, $50,551,000.
186
-------
TABLE A-48
GENERIC DOUBLE-ALKALI PROCESS 500 Mw ME* COAL-FIRED POWER UNIT 3.5* S IN COAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
50551000
SULFUR BY-PRODUCT
REMOVED RATE.
YEARS ANNUAL POWE« UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION, REQUIREMENT, CONSUMPTION. CONTROL
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS. DRY
START KW /YEAR /YEAR TONS/YEAR SOLIDS
1 7000 31500000 1500000 35000 142700
2 7000 31500000 1500000 35000 142700
3 7000 31500000 1500000 35000 142700
4 7000 31500000 1500000 35000 142700
5 70DQ 3150QOQO ^ iSOOQQO ^™ 35QOO ^142700
6 7000 31500000 1500000 35000 142700
7 7000 31500000 1500000 35000 142700
8 7000 31500000 1500000 35000 142700
9 7000 31500000 1500000 35000 142700
1C 2220__ -JISOOQOO-- 1502202 35002 -142202
NET REVENUE
S/TON
DRY
SOLIDS
0.0
0.0
0.0
0.0
OiO
0.0
0.0
0.0
0.0
0.0
TOTAL
OP. COST
INCLUDING
. REGULATED
ROI FOR
POWER
COMPANY.
S/YEAR
19023600
18745300
18467100
18188800
-12210622
17632400
17354100
17075900
16797600
_i651940Q
11 5000 22500000 1071400 25000 102000 0.0 14326600
12 5000 22500000 1071400 25000 102000 0.0 14048400
13 5000 22500000 1071400 25000 102000 0.0 13770100
14 5000 22500000 1071400 25000 102000 0.0 13491900
-15 5020 22522222 1221402 25000 102000 0x2 132L3ZOO
16 3500 15750000 750000 17600 71400 0.0 11461300
17 3500 15750000 750000 17500 71400 0.0 11183100
18 3500 15750000 750000 17500 71400 0.0 10904800
19 3500 15750000 750000 17500 71400 0.0 10626600
22 _3520 15252202 Z52000_ 12500- -21AOO 0.0 10348300
21 1500 6750000 321400 7500 30600
22 1500 6750000 321400 7bOO 30600
23 1500 6750000 321400 7500 30600
24 1500 6750000 321400 7500 30600
25 1500 67500QP 321400 7502 30600
26 1500 6750000 321400 7500 30600
27 1500 6750000 321400 7500 30600
28 1500 6750000 321400 7500 30600
29 1500 6750000 321400 7500 30600
30 _1500 6252222 3.21*20- _2MO_ -3.0612
TOT 127500 573750000 27321000 637500 2600000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR» DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KJLOWATT-HOUR
CENTS PER MILLION BTU HFAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Oifl
8003300
7725000
7446SOO
7168600
M20320 —
6612100
6333800
6055600
5777300
5499100
368601500
13.49
5.78
64.24
578.20
132472900
DISCOUNTED PROCESS COST OVER
12.44
5.33
59.23
533.09
NET ANNUAL
TOTAL INCREASE
NET (DECREASE)
SALES IN COST OF
REVENUE. POWER.
S/YEAR t
0 19023600
0 18745300
0 18467100
0 18188800
0—12212600-
0 17632400
0 17354100
0 17075900
0 16797600
0 165194.02
0 14326600
0 14048400
0 13770100
0 13491900
0 J32137QP.
0 11461300
0 11183100
0 10904800
0 10626600
0 10348300
0 8003300
0 7725000
0 7446800
0 7168600
0 68.94300
0 6612100
0 6333800
0 6055600
0 5777300
0 5499190
0 368601500
0.0 13.49
0.0 5.78
0.0 64.24
0.0 STB. 20
0 132472900
LIFE OF POWER UNIT
0.0 12.44
0.0 5.33
0.0 59.23
0.0 533.09
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER*
19023600
37768900
56236000
74424800
9233540.0
109967800
127321900
144397800
161195400
, 177714800
192041400
206089800
219859900
233351800
246.5655QO
258026800
269209900
280114700
290741300
309092900
316817900
324264700
331433300
3383236.00
344935700
351269500
357325100
363102400
3A1621500
-------
TABLE A-49. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit,
5.0% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber , exhaust gas ducts and
dampers from absorber to reheater and stack)
S0a absorption (four tray towers including presaturators and
entrainment separators , recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps , and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agi tator, slurry disposal pumps , and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , S
2,399,000
1,077,000
4,248,000
9,206,000
1,283,000
462,000
3,045,000
1,567,000
23,287,000
1,397,000
24 684 000
5,905,000
30,589,000
1,494,000
336,000
4,146,000
1,292,000
7,268,000
7,571,000
45,428,000
3,952,000
5,451,000
54,831,000
1,184,000
1,564,000
57,579,000
7, of
total direct
investment
7.8
3.5
13.9
30.1
4.2
1.5
10.0
5.1
76.1
4.6
ftft 7
OU. /
19.3
100.0
4.9
1.1
13.6
4.2
23.8
24.7
148.5
12.9
17.9
179.3
3.9
5.1
188.3
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
188
-------
TABLE A-50. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit,
5.0% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Annual
quantity
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
97,
9,
37,
489,
257,
31,960,
4,
820 tons
320 tons
150 man-hr
800 MBtu
000 kgal
000 kWh
940 man-hr
Unit
cost, $
42.00/ton
90.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
4,108
838
4,947
464
979
30
926
1,164
84
3,650
8,597
,400
,800
,200
,400
,600
,800
,800
,500
,000
,100
,300
23.
4.
27.
2.
5.
0.
5.
6.
0.
20.
48.
16
73
89
62
52
17
22
57
47
57
46
Indirect Costs
Capital charges
Depreciation, interim replacements and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect ocsts
Total average annual revenue requirements
3,289,900
4,951,800
856,500
46,400
9,144,600
17,741,900
18.54
27.91
4.83
0.26
51.54
100.00
$/ton coal $/MBtu heat $/short ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements
5.07
11.83
0.56
327.46
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,000 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 54,180 short tons/yr; solids disposal 221,000 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $30,589,000; total depreciable investment, $54,831,000; and total
capital investment, $57,579,000.
139
-------
TABLE A-51
GENERIC DOUBLE ALKALI PROCESS 500 MX NEW COAL-FlHEO POWER UNIT 5.0* S IN CO»L» REGULATED CO. ECONOMICS
FIXED INVESTMENT:
YEARS ANNUAL
AFTFR OPERA-
UNIT
HEAT
POKER UNIT
FUEL
POWER TION, REQUIREMENT, CONSUMPTION.
UNIT KW-HR/ MILLION BTU TONS COAL
START KM
/YEAR
/YEAR
SULFUH
KEMOVEO
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAO
HY-PROOUCT
KATE,
EQUIVALENT
TONS/YEA*
OKY
SOLIDS
57579000
NET REVENUE,
S/TON
OHY
SOLIDS
TOTAL
OP. COST
INCLUDING
RE6ULATED
ROI FOR
POKER
TOTAL
NET
NET ANNUAL
INCREASE
(DECREASE)
SALES IN COST OF
COMPANY, REVENUE,
POWER,
S/YEAH
J/YEAR
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
*
1
2
3
4
_.5_
6
7
8
9
-12.
11
12
13
14
15
16
17
18
19
-2Q-
21
22
23
24
-85.
26
27
28
29
_30.
7000 31500000 1500000 54200 221000
7000 31500000 1500000 54200 221000
7000 31500000 1500000 54200 221000
7000 31500000 1500000 54200 221000
-7Q.0.2 3.15C2222 1522222 _ 5*222 221202—
7000 31500000 1500000 54200 221000
7000 31500000 1500000 542DO 221000
7000 31500000 1500000 54200 221000
7000 31500000 1500000 54200 221000
-J22Q 3150QQOO 1500QQ!L 5.4220. 2210QQ
5000
5000
5000
5000
_5Q02
3500
3500
3500
3500
3520
1500
1500
1500
1500
1502
1500
1500
1500
1500
1500
2'2500000
22500000
22500000
22500000
22522222
15750000
15750000
15750000
15750000
15Z52222 __
6750000
6750000
6750000
6750000
6.252202
6750000
6750000
6750000
6750000
.___6Z50022
1071400
1071400
1071400
1071400
12Z1420
750000
750000
750000
750000
Z50222-
321400
321400
321400
321400
321420-
321400
321400
321400
321400
321420
38700
36700
38700
38700
3«Z22
27100
27100
27100
27100
2Z102
11600
11600
11600
11600
11&20- _
11600
11000
11600
11600
llfcflQ
157900
157900
157900
157900
15Z202
110500
110500
110500
110500
112522
47400
47400
47400
47400
_4.l4ae
47400
47400
47400
47400
414H8
0.0
0.0
0.0
0.0
.0*2
0.0
0.0
0.0
0.0
.0*0
0.0
0.0
0.0
0.0
.0*0
0.0
0.0
0.0
0.0
.0*0
0.0
0.0
0.0
0.0
0*JU.
0.0
0.0
0.0
0.0
ft*ft
22693200 0
22378800 0
22064500 0
21750100 0
Z1435Z2Q 0— .
21121400 0
20807000 0
20492600 0
20178300 0
1266-3220 2
17064300 0
16750000 0
16435600 0
16121300 0
-15806942 _ 0
13585700
13271400
12957000
12642600
. 12323122-
9358100
9043700
8729400
8415000
B1026JJ2
7786300
7471900
7157500
6843200
6528800. __
0
0
0
0
a
0
0
0
0
0 —
0
0
0
0
-0
22693200 22693200
22378800 45072000
22064500 67136500
21750100 88806600
— 21435Z20 110322300
21121400 131443700
20807000 152250700
20492600 172743300
20178300 192921600
126.6.3222 2i£7.fl55.0.0
17064300
16750000
16435600
16121300
-_15fi2fe222
13585700
13271400
12957000
12642600
12320322-
9358100
9043700
8729400
8415000
.8.1206.00-
7786300
7471900
7157500
6843200
652B_fl20_
229849800
246599800
263035400
279156700
224263620
308549300
321820700
334777700
347420300
3MZ4fl6.no
369106700
378150400
386879800
395294800
—403325400
411181700
418653600
425811100
432654300
4321&2100
TOT 127500 573750000 27321000 987000 4026000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION RTU HFAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* To INITIAL YEAH,
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF COAL
MILLS PFR KILOWATT-hOUM
CENTS PER MILLION «TU HFAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
439183100
439183100
IT
'ED
HOLLARS
COST EQUIVALENT
IT
ED
16.07
6.89
76.55
444.97
158278400
TO DISCOUNTED PROCESS COST OVER
14. A6
6.37
70.77
411.33
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
16.07
6.89
76.55
444.97
158278400
POWER UNIT
14.86
6.37
70.77
411.33
-------
TABLE A-52. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(1000-MW existing coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
: of
total direct
Investment, $ investment
Direct Investment
Feed preparation (feeders* slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater.and stack)
SO a absorption (four tray towers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheatera)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators.
pumps, and conveyor)
Solids disposal (onsite disposal facilities Including res lurry
pumps)
Subtotal
Services , utilities , and miscellaneous
Pond construction
Total direct investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect Investment
Contingency
Total fixed investment '
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital Investment
3 , 269 ,000
1.390,000
8,447,000
17,207,000
2,026,000
603,000
3,954,000
2,032,000
38,928,000
2,336,000
Al ")fiL {\f\C\
**1 , £O*4 , UUU
5,636,000
46,900,000
1,486,000
335,000
6,027,000
1,788,000
9,636,000
11,307,000
67,843,000
6,221,000
8,141,000
82,205,000
1,142,000
2,140,000
85,487,000
7 . 0
3.0
18.0
36.7
4.3
1.3
8.4
4.3
83.0
5.0
88 0
12.0
100.0
3.2
0.7
12.8
3.8
20.5
24.1
144.6
13.3
17.4
175.3
2.4
4.6
182.3
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175 F by indirect steam reheat.
Minimum In-process storage; only pumps are spared.
Disposal pond located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP. '
Construction labor shortages with accompanying overtime pay Incentive not considered.
191
-------
TABLE A-53. GENERIC DOUBLE-ALKALI PROCESS
SU1-C1ARY OF AVERAGE ANNUAL REVENUE REQUIRElffiNTS -
REGULATED UTILITY ECONOMICS*
(1000-I1W existing coal-fired ^power unit,
3.5% S in coal; 1.2 lb SOa/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam j
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
127,200 tons
12,120 tons
48,150 man-hr
979,700 MBtu
483,000 kgal
58,100.000 kWh
7,080 man-hr
Unit
cost, $
42.00/ton
90.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
17.00/man-hr
Total % of averaRe
annual annual revenue
cost, $ requirements
5, 34 2., 400
1,090,800
6,433,200
601,900
1,959,400
58,000
1,626,800
1,277,900
120,400
5,644,400
12,077,600
20.75
4.24
24.98
2.34
7.61
0.23
6.31
4.96
0.47
21.92
46.90
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.43! of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
. Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
5,261,100
7,351,900
1,000,100
60,200
13,673,300
25,750,900
20.43
28.56
3.88
0.23
53.10
100.00
MlUs/kWh
S/ton coal $/KBtu heat
burned input
Equivalent unit revenue requirements
3.68
8.58
0.41
S/short ton
S removed
367.87
Basis -
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 2,999,850 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 70,000 short tons/yr; solids disposal 285,500 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct Investment, 546,900,000; "total depreciable investment, $82,205,000; and total
capital investment, $85,487,000.
192
-------
TABLE A-54
GENERIC DOUBLE ALKALI PROCESS 1000 M* EXISTING COAL-FIRED POKER UNIT 3.5% S IN COAL. REGULATED CO. ECONOHICS
FIXED INVESTMENT:
85487000
VD
OJ
SULFUR HY-PRODUCT
REMOVED RATE.
YEARS ANNUAL POKE* UNIT POWER UNIT BY EQUIVALENT NET
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION. REQUIREMENT. CONSUMPTION. CONTROL
UNIT KW-HR/ MILLION 3TU TONS COAL PROCESS. DRY
START KW /YEAR /YEAR TONS/YEAR SOLIDS
1
3
4
5 . . ._
6 7000 63000000 3000000 70000 285500
7 7000 63000000 3000000 70000 285500
8 7000 63000000 3000000 70000 285500
9 7000 63000000 3000000 70000 285500
\o 7QOO 630000QO 3002QOQ 70000 28.55QO
11 5000 45000000 2142900 50000 203900
12 5000 45000000 2142900 50000 203900
13 5000 45000000 2142900 50000 203900
14 5000 45000000 2142900 50000 203900
15 5SJQ2 45022220 2142200- 50002 .203202
16 3500 31500000 1500000 35000 142700
17 3500 31500000 1500000 35000 142700
18 3500 31500000 1500000 35000 142700
19 3500 31500000 1500000 35000 142700
22 _3522 31522222 1522202 35002 .142102
21 1500 13500000 642900 15000 61200
22 1500 13500000 642900 15000 61200
23 1500 13500000 642900 15000 61200
24 1500 13500000 642900 15000 61200
25 1502 13520220 642200- 15002 61202
26 1500 13500000 642900 15000 61200
27 1500 13500000 642900 15000 61200
28 1500 13500000 642900 15000 61200
29 1500 13500000 642900 15000 61200
REVENUE.
S/TON
DRY
SOLIDS
0.0
0.0
0.0
0.0
Old
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Q«fl ^
0.0
0.
0.
0.
fit
0.
0.
0.
0.
_32 1502 13522220 642202 15002 61202 0*0
TOT 92500 832500000 39643500 925000 3772500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU MEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11. 6» TO INITIAL YEAR. DOLLARS
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY.
S/YEAR
33104800
32539200
31973600
31408100
30ft42500
26778600
26213000
25647500
25081900
24.51630Q
21279700
20714100
20148500
19582900
1201Z400.
14764200
14198600
13633100
13067500
11936400
11370800
10S05200
10239600
2614100
511039500
12.89
5.52
61.39
552.48
209774100
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
11.68
5.00
55.61
500.53
NET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE)
SALES IN COST OF IN COST OF
REVENUE. POWER. POWER*
S/YEAR % *
0 33104800 33104800
0 32539200 65644QOO
0 31973600 97617600
0 31408100 129025700
0 3QB425Q.P. J59B66?Ofl
0 26778600 186646800
0 26213000 212859800
0 25647500 238507300
0 25081900 263589200
_ 0 24516300 2&8.I05500
0 21279700 309385200
0 20714100 330099300
0 20148500 350247800
0 19582900 369830700
2 19217400 3.8.184811)0
0 14764200 403612300
0 14198600 417810900
0 13633100 431444000
0 13067500 444511500
0 12521902 457013400
0 11936400 468949800
0 11370800 480320600
0 10805200 491125800
0 10239600 501365400
0 2614100 511032540
0 511039500
0.0 12.89
0.0 5.52
0.0 61.39
0.0 552.48
0 209774100
LIFE OF POWER UNIT
0.0 11.66
0.0 S.OO
0.0 55.61
0.0 500.53
-------
TABLE A-55. GENERIC DOUBLE-ALKALI PROCESS
SU1C1ARY OF ESTIMATED CAPITAL INVESTilENTa
(1000-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
S02-absorption (four tray towers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators.
pumps, and ccnveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
2,873,000
1,234,000
6,651,000
15,497,000
1,875,000
530,000
3,493,000
1,769,000
33,922,000
2,035,000
35,957,000
7,025.000
42,982,000
1,525,000
339,000
5,545,000
1,673,000
9,082,000
10,413,000
62,477,000
5,545,000
7,497,000
75,519,000
1,412,000
2,085,000
79,016,000
7. of
total direct
investment
6.7
2.8
15.5
36.2
4.4
1.2
8.1
4.1
79.0
4.7
83.7
16.3
100.0
3.5
0.8
12.9
3.9
21.1
24.3
145.4
12.9
17.4
175.7
3.3
4.8
183.8
a. Basie
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
194
-------
TABLE A-56. GENERIC DOUBLE-ALKALI PROCESS
SUID1ARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS*1
(1000-MW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/IlBtu
heat input allowable emission; onsite solids disposal)
Total 31 of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
123,000 tons 42.00/ton 5,166,000
11,720 tons 90.00/ton 1,054,800
6,220,800
48,150 man-hr 12.50/man-hr 601,900
947,000 MBtu 2.00/MBtu 1,894,000
467,000 kgal 0.12/kgal 56,000
56,160,000 kWh 0.028/kWh 1,572,500
1,289,500
7,080 man-hr 17. 00/man-hr 120,400
5,534,300
11,755,100
21.39
4.37
25.76
2.49
7.85
0.23
6.51
5.34
0.50
22.92
48.68
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
4,531,100
6,795,400
1,005,900
60,200
12,392,600
24,147,700
18.76
28.14
4.17
0.25
51.32
100.00
$/ton coal S/MBtu heat S/short ton
Mllls/kWh burned input S removed
Equivalent unit revenue requirements
3.45
8.33
0.40
356.84
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 2,900,100 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 67,670 short tons/yr; solids disposal 276,000 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $42,982,000; total depreciable investment, 575,519,000; and total
capital investment, $79,016,000.
195
-------
TABLE A-57
GENERIC DOUBLE ALKALI PROCESS 1000 Mh NEW COAL-FIRED POWER UNIT 3.5% S IN COAL« REGULATED CO. ECONOMICS
FIXED INVESTMENT:
79016000
VO
SULFUR
REMOVED
YEARS ANNUAL POWErt UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWFR TION. REQUIREMENT. CONSUMPTION. CONTROL
UNIT KW-HR/ MILLION 3TU TONS COAL PROCESS.
ST4RT KW /YEAR /YEAR TONS/YEAR
1 7000 60900000 2900000 67700
2 7000 60900000 2900000 67700
3 7000 60900000 2900000 67700
4 7000 60900000 2900000 67700
5 7000 6.Q9.QOQQO 29000(10 $7100
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
ORY
SOLIDS
276000
276000
276000
276000
276000
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED TOTAL
S/TON ROI FOR NET
POWER SALES
DRY COMPANY. REVENUE.
SOLIDS S/YEAR S/YEAR
0.0 30943600
0.0 30510600
0.0 30077600
0.0 29644600
0.0 29211600
6 7000 60900000 2900000 67700 276000 0.0 28778700
7 7000 60900000 2900000 67700 276000 0.0 28345700
8 7000 60900000 2900000 67700 276000 0.0 27912700
9 7000 60900000 2900000 67700 276000 0.0 27479700
.10 ZflflO 6.020QQQO__ __220flOOQ &11QQ _2ZfeftOQ __ 0*0 jeiflifiaOQ. _ .
11 5000 43500000 2071400 48300 197200 0.0 23208400
12 5000 43500000 2071400 48300 197200 0.0 22775400 '
13 5000 43500000 2071400 48300 197200 0.0 22342400
14 5000 43500000 2071400 48300 197200 0.0 21909500
15 SOQO 43500000 20I140B 4fi3QQ 121200 (Ml _21AI45fiO
16 3500 30450000 1450000 33800
17 3500 30450000 1450000 33BOO
18 3500 30450000 1450000 33800
19 3500 30450000 1450000 33HOO
20 3500 30450000 1450000 33aOfl_
21 1500 13050000 621400 14500
22 1500 13050000 621400 14500
23 1500 13050000 621400 14500
24 1500 13050000 621400 14500
25 1500 J305QPO.P 621400- 14520
138000
138000
138000
138000
138.000
59100
59100
59100
59100
59100
26 1500 13050000 621400 14500 59100
27 1500 13050000 621400 14500 59100
28 1500 13050000 621400 14500 59100
29 1500 13050000 621400 14500 59100
.30 1500 13fl5QO.GB 6214BB 14.548, ..521HO _
TOT 127500 1109250000 52821000 1232500 5027000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR. DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER M'ILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
0.0 18441500
0.0 18008500
0.0 17575600
0.0 17142600
OtB -i*7.(W6,p.p.
0. 12680100
0. 12247200
0. 11814?00
0. 11381200
ft* 10948.2QQ
0.0 10515300
0.0 10082300
0.0 9649300
0.0 9216300
fun azmtoo
596859100
11.30 0.
4.68 0.
53.81 0.
484.27 0.
215525300
DISCOUNTED PROCESS COST OVER LIFE
10.47 0.
4.34 0.
49. «5 0.
448.54 0.
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
t
0 30943600
0 30510600
0 30077600
0 29644600
Q 29211600
0
0
0
0
B
0
0
0
0
|)
0
0
0
0
0_
0
0
0
0
ft_
0
0
0
0
o
0
0
0
0
0
0
OF
0
0
0
0
28778700
28345700
27912700
27479700
220iifiOO.
23208400
22775400
22342400
21909500
21476500
18441500
18008500
17575600
17142600
16/09600
12680100
12247200
11814200
11381200
—imagpju
10515300
10082300
9649300
9216300
8783400—
596859100
11.30
4.68
53.81
484.27
215525300
POWER UNIT
10.47
4.34
49.85
448.54
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
%
30943600
61454200
91531800
121176400
1.54368000
179166700
207512400
235425100
262904800
2^1951600
313160000
335935400
358277800
380187300
40 I 663«00
420105300
438113800
455689400
47g832000
489541600
502221700
514468900
526283100
537664300
5416.12500
559127800
569210100
578859400
588075700
_526ft52ifl.o
-------
TABLE A-53. GENERIC DOUBLE-ALKALI PROCESS
SUIMARY OF ESTIMATED FIXED INVESTMENT3
(500-11W new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/MBtu
heat input allowable emission; trucking alternative)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts, and
dampers from absorber to reheater and stack)
SO- absorption (four tray towers including presaturators and
entralnment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids disposal (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor's fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Trucking charge (including indirect charges)
Total capital investment
1,710,000
833,000
4,248,000
9,206,000
1,282,000
357,000
2,352,000
19,988,000
1,199,000
21,187,000
1,175,000
294,000
3,152,000
977,000
5,598,000
5,357,000
32,142,000
3,214.000
3,857,000
39,213,000
326,000
1,305,000
491,000
41,335,000
8.1
3.9
20.0
43.4
6.1
1.7
11.1
94.3
5.7
100.0
5.5
1.4
14.9
4.6
26.4
25.3
151.7
15.2
18.2
185.1
1.5
6.3
2.3
195.2
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal area located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream.
Construction labor shortages with accompanying overtime pay incentive not considered.
197
-------
TABLE A-59. GENERIC DOUBLE-ALKALI PROCESS
TOTAL AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-IfW new coal-fired power unit,
3.5% S in coal; 1.2 Ib S02/HBtu
heat input allowable emission; trucking alternative)
Direct Costs
Raw materials
Lime
Soda ash
Total raw material cost
Conversion costs
Operating labor and supervision
Operating labor disposal equipment
Utilities
Steam
Process water
Electricity
Fuel
Maintenance
Labor and material
Analyses
Disposal land preparation
Total conversion costs
Total direct costs
Annual
quantity
63,600 tons
6,060 tons
31 ,000 man-hr
42,000 man-hr
489,800 MBtu
217,600 kgal
27,000,000 kWh
196,000 gal
5 acres
4,180 man-hr
Unit
cost, $
42.00/ton
90.00/ton
1 2. 50/ man-hr
17.00/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
0.60/gal
1600/acre
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
2,671,200
545,400
3,216,600
387,500
714,000
979,600
26,100
783,000
117,600
876,900
8,000
71,100
3,963,800
7,180,400
18.69
3.81
22.50
2.73
5.00
6.85
6.85
0.18
0.82
5.48
6.13
0.06
0.50
27.73
50.23
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 107. of operating labor
Trucking labor
Total indirect costs
Total annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 4.08 9.53
2,425,800
3,554,800
653,100
38,800
441,000
7,113,500
14,293,900
$/MBtu heat $/short
16.97
24.87
4.57
0.27
3.09
49.77
100.00
ton
input S removed
0.45 408.40
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 35,000 short ton/yr; solids disposal 142,750 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $21,187,000; total depreciable investment, $39,213,000, and total
capital investment, $41,335,000.
198
-------
TABLE A-60
&ENEKIC IUUBLE ALKALI PROCESS 500 *W NEW COAL-FIRED POWER UNIT 3.5* S IN COAL, TRUCKING ALTERNATIVE, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
41335000
vo
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL PCLLUTICIN
POWER T1LN, RETIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION BTU ICiKS CCAl PROCESS,
START KW /YtAR /YEAR TONS/YEA*
1
3
4
— 5_
6
7
8
9
ll"
12
13
_Li.
16
17
18
1 9
_20_
22
25
26
27
28
29
aa_
7000
7003
7000
7000
. -JflCO.
7000
7000
7000
7000
7(1QD
315000CC 1500COC
31530300 1533000
315000CC I500COC
31500000 1500000
_ 2i50.QO.Qa isaaoaa
31500000 1500000
315000CC 15COOOO
31500000 1500000
31500000 1500030
nsnnnnn isnnrnn
5000 22500000 1071400
5000 22500000 1071400
5000 22500300 1071400
5000 225000CC 107140C
jiOJQ.0. 225naono in7K.no
3500
35CD
3500
3500
_Ji£D.
1500
1500
1500
1500
LSUQ.
1500
1500
15CO
1500
LiQO
TOT 127500
LIFETIME
PROCESS COST
LEVEL12EC
157500CC 750COO
15750000 753000
157500CC 750COC
15750000 750000
J5J5£X1££ .12X1CQQ
6750300 321400
67500GO 32140C
6750UOO 321400
6750CCC 321400
fc750OOn 321400
675COCC 321«OC
6750000 321400
£750000 321400
6750000 321400
6.7'iUnQ.O. 12L4I10,
35000
35000
35000
35000
3.50. 00
35000
35000
35000
35000
350.00
25000
25000
25000
25000
250,0.0.
17500
17500
17500
17500
12SQQ
7500
7500
7500
7500
7500
7500
7500
7500
7500
TSfttt
BY-PRODUCT
RATE,
EQUIVALENT
IONS/YEAR
DRY
SOL IDS
142700
142703
142700
142730
142100
142700
142700
142700
142700
1*2700
102000
102000
102000
102000
71400
71400
71400
71430
7.1*00
30600
30600
30690
30600
30600
30633
30600
30600
in*, a a
573750000 27321000 637500 2600000
AVERAGE INCREASE (INCREASE) IN UNIT OPERATING COST
COLLARS PEC TDK CF CL'Al BURNED
MILS PER MLOfcAlT-HGUR
CLNTS PER MLLION *TU HEAT INPUT
DULLAKS Pit ION OF SULFUR REM3VEO
DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
INCREASE (CECREASf) l» INIT ITERATING COST ECUIVALENT TO
DULLAKS PER TON OF COAL BURNED
MILLS PFR KILOWATT-HOUR
CENTS PER PILLION BTU HFAT INPUT
HOLLARS PER TDK CF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
t/TDN R01 FOR NET
POWER SALES
DRY COMPANY, REVENUE,
SOLIDS I/YEAR S/YEAR
0.0
0 J)
0.0
0.0
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
c.o
JB.J1
0.0
0 J)
0.0
0.0
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
a.o_
DISCCUMED
17849000
17623630
17398200
17172900
16722100
16496700
16271300
16045933
15H7PSQO
13524139
13298700
130734J3
12848000
L2&226.HQ.
10789500
10564100
10338700
10113300
QHRignn
7372830
7141500
6922130
6696700
6245900
6020500
5795100
5569700
348993900
12.77
5.47
60.83
547.44
12527590}
PROCESS COST OVER
11.76
5.04
56.0?
504 .13
0
0
0
0
o
0
0
0
0
n
0
0
D
0
0
0
0
0
0
n
0
0
0
0
n
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE! (DECREASE)
IN COST OF IN COST OF
POWER. POWER.
* $
17849000
17623600
17398200
17172900
1 A 94 7500
16722100
16496700
16271300
16045900
13524100
13298700
13073400
12848000
10789500
10564100
10338700
10113300
7372800
7147500
6922100
6696700
0 6245900
0 6020500
0 5795100
0 5569700
a 5.i44aao_ .
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
348993900
12.77
5.47
60.83
547.44
125275900
POWER UNIT
11.76
5.04
56.02
504.13
17849000
35472600
52870800
70043700
103713300
120210000
136481300
152527200
JjLfl 243100
181871800
195170500
208243900
221091900
244504000
255068100
265406800
275520100
292780800
299928300
306850400
313547100
326264300
332284800
338079900
343649600
.148913800
-------
TABLE A-61. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; onsite solids disposal)
1. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorber to reheater and stack)
S02 absorption (four tray towers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1,889,000
897,000
4,248,000
9,206,000
1,283,000
385,000
2,536,000
1,333,000
21,777,000
1,307,000
23,084,000
4,679,000
27,763,000
1,458,000
332,000
3,852,000
1,200,000
6,842,000
6,921,000
41,526,000
3,685,000
4,983,000
50,194,000
932,000
1,278,000
52,404,000
6.8
3.2
15.3
33.2
4.6
1.4
9.1
4.8
78.4
4.7
83.1
16.9
100.0
5.3
1.2
13.9
4.3
24.7
24.9
149.6
13.3
17.9
180.8
3.4
4.6
188.8
a. Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°P by indirect steam reheat.
Minimum In-process storage; only pumps are spared.
Disposal pond located 1 ml from power plant.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
200
-------
TABLE A-62. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
72,450 tons
6,900 tons
34,500 man-hr
489,800 MBtu
245,300 kgal
29,161,000 kWh
4,560 man-hr
Unit
cost, $
42.00/ton
90.00/ton
12. 50 /man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
3,042,900
621,000
3,663,900
431,300
979,600
29,400
845,700
1,063,700
77,500
3,427,200
7,091,100
19.71
4.02
23.73
2.79
6.34
0.19
5.48
6.90
_0.50
22.20
45.93
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
3,011,600
4,506,700
786,300
43.100
8,347,700
15,438,800
19.51
29.19
5.09
0.28
54.07
100.00
$/ton coal $/MBtu heat $/short ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements
4.41
10.29
0.49
377.48
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 40,900 short tons/yr; solids disposal 166,810 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $27,763,000; total depreciable investment, $50,194,000; and total
capital investment, $52,404,000.
201
-------
TABLE A-63
GENERIC DOUBLE ALKALI PROCESS 500 MW NEW COAL-FIRED POWER UNIT 3.5% S IN COAL. 90* REMOVAL REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 52*0*000
SULFUK
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TION, REQUIREMENT, CONSUMPTION. CONTROL
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS.
START KW /YEAR /YEAR TONS/YEAR
1 7000 31500000 1500000 39800
2 7000 31500000 1500000 39800
3 7000 31500000 1500000 39800
* 7000 31500000 1500000 39800
5 -20.0.0. 31500.0.0J! 150.0.0.0.0 32a0.S
6 7000 31500000 1500000 39800
7 7000 31500000 1500000 39800
8 7000 31500000 1500000 39800
9 7000 31500000 1500000 39800
10. -20.0.0. 3150.0.0.0.0 15Q0.fl0.0_ 32tt0.8._
11 5000 22500000 1071*00 28*00
12 5000 22500000 1071*00 26*00
13 5000 22500000 1071*00 28*00
1* 5000 22500000 1071*00 28*00
15 -50.0.0. 2250.0.0.0JZ -10.11*0.0- _ 2£i0.o_
16 3500 15750000 750000 19900
17 3500 15750000 750000 19900
18 3500 15750000 750000 19900
19 3500 15750000 750000 19900
84- -350.0.- 15250.0.0JI _15fl0.ftO_ 1220.0_
21 1500 6750000 321*00 8500
22 1500 6750000 321*00 8500
23 1500 6750000 321*00 8500
2* 1500 6750000 321*00 8500
85 150,0. _ 615000Jtt _32140.0_ _fi50-0_
26 1500 6750000 321*00 8500
27 1500 6750000 321*00 8500
28 1500 6750000 321*00 8500
29 1500 6750000 321*00 8500
30 1500 675gooo t 321*00 flSQtt
TOT 127500 573750000 27321000 72*500
RY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
166800
166800
166800
166800
1$68.Q0
166800
166800
166800
166800
16.680.0.
119200
119200
119200
119200
NET REVENUE,
S/TON
DRY
SOLIDS
0.0
0.0
0.0
0.0
1U0.
0.0
0.0
0.0
0.0
!U2
0.0
0.0
0.0
0.0
1122JIO. o-o
83*00
83*00
83*00
83*00
0.0
0.0
0.0
0.0
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
199*5500
19657700
19369900
19082200
_ _ia22*.40.0.
18506600
18218800
17931100
176*3300
11355500.
15014400
1*726600
1*438800
1*151000
-13&&330.0.
11996300
11708500
11*20700
11133000
TOTAL
NET
SALES
REVENUE,
S/YEAR
0
0
0
0
0
0
0
0
p__
0
0
0
0
0
0
0
0
0
_sa*.aa o-o 108*5200 a .
35700
35700
35700
35700
35700
35700
35700
35700
3038000
0.0
0.0
0.0
0.0
QiQ
0.0
0.0
0.0
0.0
0_»a
83*8000
8060300
7772500
7*8*700
li2fiSflp_
6909200
6621*00
6333600
60*5000
S15£Utft-
386333300
0
0
0
0
0_
0
0
0
0
0_.
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
%
199*5500
19657700
19369900
19082200
18224400—
18506600
18218800
17931100
176*3300
, ,17355509
15014*00
1*726600
14*38800
1*151000
J3.8&3.300
11996300
11708500
11*20700
11133000
10.8*5.200
83*8000
8060300
7772500
7*8*700
7196900
6909200
6621*00
6333600
60*5800
.... 525810ft-
386333300
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
199*5500
39603200
58973100
78055300
2684210.0
115356300
133575100
151506200
1691*9500
__ ifi.450_50_io
201519*00
2162*6000
23068*800
2**835800
2586991110
270695*00
282*03900
29382*600
30*957600
31&80^a0-0
32*150800
332211100
339983600
3*7*68300
__35.*6.fc5.2JlO
36157*400
368195800
37*529*00
380575200
..38*33330.0
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR. DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
14.14
6.06
67.33
533.2*
1389*7500
DISCOUNTED PROCESS COST OVER
13.05
5.59
62.13
491.85
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
14.1*
6.06
67.33
533.2*
1389*7500
POWER UNIT
13.05
5.59
62.13
*91.85
-------
TABLE A-64. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW existing oil-fired power unit,
2.5% S in oil; 0.8 lb S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Investment
Materials handling (conveyors, elevators, bins, and feeders)
Feed preparation (feeders , slakers , tanks , agitators , and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
S02 absorption (four tray towers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four direct oil reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services , utilities, and miscellaneous
d
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , $
995,000
564,000
8,728,000
726,000
243,000
1,596,000
931,000
18.181,000
1,091.000
1,794,000
21,066,000
1,356,000
322,000
3,125,000
973.000
5,776,000
5,368.000
32,210,000
3,042,000
3,865,000
39,117,000
366,000
777,000
40,260,000
7. of
total direct
Investment
4,
2.
41
3
1
7.
4.
86.
5,
8.
100.
6,
1.
14.
4.
27.
25.
152.
14.
18.
185.
1.
3.
191.
.7
,7
.9
.4
.4
.2
.6
.4
.3
,2
.5
.5
.0
,5
.5
,8
.6
4
.5
9
4
4
7
7
7
1
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 175°F by direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for flyash removal and disposal excluded FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
203
-------
TABLE A-65. GENERIC DOUBLE-ALKALI PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW existing oil-fired power unit,
2.5% S in oil; 0.3 Ib S02/MBtu
heat input allowable emission; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
Total % of average
annual annual revenue
cost, $ requirements
28,030 tons
2,670 tons
32,800 man-hr
2,676,600 gal
169,300 kgal
22,410,000 kWh
4,350 man-hr
42.00/ton
90.00/ton
12.50/man-hr
0.40/gal
0.12/kgal
0.029/kWh
17.00/man-hr
1,177,300
240,300
1,417,600
410,000
1,070,600
20,300
649,900
824,700
74,000
3,049,500
4,467,100
10.58
2.16
12.74
3.68
9.62
0.18
5.84
7.41
0.67
27.40
40.14
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.18
2,503,500
3,462,400
654,400
41,000
6,661,300
11,128,400
$/bbl oil $/MBtu heat $/short ton
burned input S removed
2.09 0.34 749.39
22.5
31.11
5.88
0.37
59.86
100.00
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-streara time, 7,000 hr/yr.
Oil burned, 5,324,100 bbl/yr, 9,200 Btu/kUh.
Stack gas reheat to 175°F.
S removed, 14,850 short tons/yr; ^ol'ds disposal 63,030 tons/yr Ca solids including only
hydrate water.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $21,066,000; total depreciable investment, $39,117,000; and total
capital investment, $40,260,000.
204
-------
TABLE A-66
GENERIC DOUBLE ALKALI PROCESS SOO MW EXISTING OIL-FIRED POWER UNIT
KIXEO INVESTMENT: j
S IN OIL REGULATED CO. ECONOMICS
40260000
YEARS ANNUAL
AFTER OPERA-
POWFR TTON.
UNIT KW-HR/
START KW
POWER UNIT
HEAT
REQUIREMENT.
MILLION HTU
/YEAR
SULFUrt
REMOVED
POWER UNIT «Y
FUEL POLLUTION
CONSUMPTION, CONTROL
BARRELS OIL PROCESS,
/YEAR TONJS/YEAR
RY-PROUUCT
RATE.
EQUIVALENT
TONS/YEAH
OWY
SOLIDS
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
I/TON ROI FOR
POWER
DRY COMPANY,
SOLIDS I/YEAR
NET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE)
SALES IN COST OF IN COST OF
REVENUE. POWER. POWER,
I/YEAR $ $
1
2
3
4
6
7
8
9
-10.— .
11
12
13
to 1*
o .15....
<-" 16
17
IB
19
.2Q___.
21
22
23
24
.25—.
26
27
28
29
3Q-. .
7000
7000
7000
7000
J222.
5000
5000
5000
5000
.5222..
3500
3500
3500
3500
.3522.
1500
1500
1500
1500
1522
32200000 5324100 14800 63000
32200000 5324100 14HOO 63000
32200000 5324100 14HOO 63000
32200000 5324100 14HOO 63000
32222222- 5324122 14ttfiO 63000
23000000 3H02900
23000000 3R02900
23000000 3*02900
23000000 3802900
22222222 2822222
161000QO 2662000
16100000 266POOO
16100000 2662000
16100000 2662000
16122222 2662000
6900000
6900000
6900000
6900000
6900000
1500 6900000
1500 6900000
1500 6900000
1500 6900000
.1522 690.2222
1140900
1140900
1140900
1140900
1140900
11409QO
1140900
1140900
__ 1142222
0.0
0.0
0.0
0.0
OiO
10600 45000 0.0
10600 45000 0.0
10600 45000 0.0
10600 45000 0.0
12622 45222 2*2
7400 31500 0.0
7400 31500 0.0
7400 31500 0.0
7400 31500 0.0
Z422 31500 (Mi
3200
3200
3200
3200
2220-
3200
3200
3200
3200
2222
13500
13500
13500
13500
125ft2
13500
13500
13500
13500
._ —125P.2
0.0
0.0
0.0
0.0
„ (UP.
0.0
0.0
0.0
0.0
_ft*fl_
14590600
14321500
14052400
137B3200
12514122
11943500
11674300
11405200
11136100
9589800
9320700
9051600
8782500
6814500
6S49400
6276200
6007100
— 513600.2
5468900
5199700
4930600
4661SOO
0
0
0
0
2
14590600
14321500
14052400
13783200
13514100
0 11943500
0 11674300
0 11405200
0 11136100
0 9589800
0 9320700
0 9051600
0 8782500
tt _ 8513300
0
0
0
0
2
0
0
0
0
tt—
6814500
6545400
6276200
6007100
5468900
5199700
4930600
4661500
_43223P.ft—
14590600
28912100
42964500
56747700
IO.26J.ft20
82205300
93879600
105284800
116420900
__1212kZ2ttO
136877700
146198400
155250000
164032500
__ii2545aao
179360300
185905700
192181900
1981B9000
"209395900
214595600
219526200
224187700
.22.85(12220
TOT 92500 425500000 70354000 196000 832500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BUHNED
MILLS PER KILO«ATT-rtOUR
CENTS PFR MILLION 8TU HFAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAK, DOLLARS
228580000
3.25
4.94
53.72
1166.22
93023600
0.0
0.0
0.0
0.0
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATlMt. COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER BARREL OF OIL HUHNED 2.92 0.0
MILLS PER KILOWATT-HOUR 4.44 0.0
CENTS PER MILLION BTU HEAT INPUT 48.25 o.o
DOLLARS PER TON OF SULFUR REMOVED 1048.74 0.0
228580000
3.25
4.94
53.72
1166.22
93023600
POWER UNIT
2.92
4.4*
48.25
1040.74
-------
TABLE A-67. CITRATE PROCESS
SULGIAUY OF ESTIMATED CAPITAL INVESTMENT3
(200-I1W existing coal-fired power unit, 3.5% S in coal;
1.2 lb S02/'lBtu heat input allowable emission)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tanks, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO™ absorption (two packed tower absorbers including
presaturators and entrainment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
S02 reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (5 receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H_S generation (battery limit plant)
H. generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
4i7,UOO 2.2
77,000 0.4
1.824,000
5,512,000
584,000
60,000
661,000
1,599,000
445,000
544,000
3,641,000
2,537.000
17,901,000
1.074.000
18,975,000
9.6
29.0
3.1
0.3
3.5
8.4
2.3
2.9
19.2
13.4
94.3
5.7
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed Investment
6,790,000
5.153,000
30,918,000
12.7
3.2
15.2
4.7
35.8
27.1
162.9
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,092,000
3.710,000
37,720,000
35,000
1,033,000
38,788,000
16.3
19.6
198.8
0.2
5.4
204.4
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP,
Construction labor shortages with accompanying overtime pay incentive not considered.
206
-------
TABLE A-63. CITRATE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOIIICS3
(200-MW existing coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
Annual Unit
quantity cost, $
Direct Costs
Raw materials
Lime 1,210 tons 42.00/ton
Soda ash 1,110 tons 90.00/ton
Citric acid 96 tons 1,340.00/ton
Natural gas 443,000 kft' 3.50/kft'
Catalyst
Conversion costs
Operating labor and supervision 52,700 man-hr 12.50/man-hr
Utilities
Steam 436,550 MBtu 2.00/MBtu
Process water 1,052,000 kgal 0.06/kgal
Electricity 27,908,000 kWh 0.031/kWh
Maintenance
Labor and material
Analyses 5,600 man-hr 17.00/man-hr
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 7.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 102 of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 14,290 short tons 40.00/short ton
Subtotal byproduct sales revenue
Total average annual revenue requirements
S/ton coal S/MBtu heat
Mills/kWh burned Input
Equivalent unit revenue requirements 8.78 19.40 0.92
Total
annual
cost, $
50,800
99,900
128,600
1,550,500
8,900
1 838 700
658,800
873,100
63,100
865,100
1,327,000
95,200
3 882 300
5,721,000
2,640,400
3,335,800
1,040,500
65,900
57.200
7,139,800
12,860,800
(571.600)
(571,600)
12,289,200
$/short ton
S removed
831.47
% of average
annual revenue
requirements
0.41
0.81
1.05
12.62
0.07
14.96
5.36
7.10
0.51
7.04
10.81
0.77
31.59
46.55
21.48
27.14
8.47
O.S4
_0.47
58.10
104.65
14^651
(4.65)
100.00
$/short ton
S recovered
859.99
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 20 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 633,500 tons/yr, 9,500 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 14,780 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct Investment, $18,975,000; total depreciable investment, $37,720,000; and total capital
Investment, $38,788,000.
207
-------
TABLE A-69
CITRATE PROCESS 200 MW EXISTING COAL-FIHEO POWER UNIT 3.5* S IN COAL REGULATED CO. ECONOMICS
FIXED INVESTMENT:
38788000
to
o
00
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS,
START KW /YEAR /YEAR TONS/YEAH SULFUR
1
2
3
4
5.
6
7
a
9
la
11 5000
12 5000
13 5000
14 5000
_15 Safltt-
16 3500
17 3500
18 3500
19 3500
22 35Bfl-
21 1500
22 1500
23 1500
24 1500
26 1500
27 1500
28 1500
29 1500
_3a 1544-
TOT 57500
LIFETIME
PROCESS COST
LEVEL IZED
9500000 452400 10600
9500000 452400 10600
9500000 452400 10600
9500000 452400 10600
6650000 316700 7400
6650000 316700 7400
6650000 316700 7400
6650000 316700 7400
6650Q80 316700. 74QQ
2850000 135700 3200
2850000 135700 3200
2850000 135700 3200
2850000 135700 3200
2fl540fl4_ 135140 _324fl
2850000 135700 3200
2850000 135700 3200
2850000 13S700 3200
2850000 135700 3200
28500QQ 135705 3SQQ
10200
10200
10200
10200
102P.fi
7100
7100
7100
7100
naa
3100
3100
3100
3100
3iflfl
3100
3100
3100
3100
3100
NET REVENUE,
S/TON
SULFUR
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40. 00 ,
40.00
40.00
40.00
40.00
40iOO
40.00
40.00
40.00
40.00
40.00
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POKER
COMPANY,
S/YEAR
14523800
14199400
13875100
13550700
11593100
11268700
10944300
10619900
8080500
7756100
7431700
7107300
6458600
6134200
5809800
S485400
5161000
109250000 5202500 122000 117500 190304300
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED 36.58
MILLS PER KILOWATT-HOUR 16.55
CENTS PER MILLION BTU HEAT INPUT 174.19
DOLLARS PER TON OF SULFUR REMOVED 1559.87
DISCOUNTED AT 11.6% TO INITIAL YEAR, DOLLARS 87183000
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER
DOLLARS PER TON OF COAL BURNED 33.88
MILLS PER KILOWATT-HOUR 15.33
CENTS PER MILLION BTU HFAT INPUT 161.34
DOLLARS PER TON OF SULFUR REMOVED 1445. B2
TOTAL
NET
SALES
REVENUE,
S/YEAR
408000
408000
408000
408000
-448.444
284000
284000
284000
284000
-284444..
124000
124000
124000
124000
12400Q
124000
124000
124000
124000
4700000
0.90
0.41
4.30
38.52
2320500
LIFE OF
0.90
0.41
4.29
38.48
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
f
14115800
13791400
13467100
13142700
UB193QO
11309100
10984700
10660300
10335900
1001150Q
7956500
7632100
7307700
6983300
6658900.
6334600
6010200
5685800
5361400
5431444
185604300
35.68
16.14
169.89
1521.35
84862500
POWER UNIT
32.98
14.92
157.05
1407.34
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
f
14115800
27907200
41374300
54517000
78644400
89629100
100289400
110625300
128593300
136225400
143533100
150516400
151115340
163509900
169520100
175205900
180567300
. 146604340
-------
TABLE A-70. CITRATE PROCESS
SUIC1ARY OF ESTIMATED CAPITAL INVESTMENT3
(200-MW new coal-fired power unit, 3.5% S in coal;
1.2 lb S02/MBtu heat input allowable emission)
Dir
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tanks, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducCS and dampers from absorber to reheater and stack)
S09 absorption (two packed tower absorburs int-luding
presaturators and entrainment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
S09 reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
' filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H.S generation (battery limit plant)
H7 generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
7. of
total direct
Investment, $ investment
408,000
75,000
1,785,000
5,400,000
569,000
59,000
649,000
1,568.000
436,000
531,000
3,577,000
2,480.000
17,537,000
1,05.;,OOP
18,589,000
2.2
0.4
9.6
29.1
3.1
0.3
3.5
8.4
2.3
2.8
19.3
13.3
94.3
5.7
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
6,/06,000
5,059,000
30,354,000
12.9
3.2
15.2
4.8
36.1
27.2
163.3
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,035,000
3,643.000
37,032,000
35,000
1,008.000
38,075,000
16.3
19.6
199.2
0.2
5.4
204.8
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by Indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered,
209
-------
TABLE A-71. CITRATE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(200-I1W new coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
Direct Costs
Raw materials
Lime
Soda ash
Citric acid
Natural gas
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost. $
Total
annual
cost, $
1,170 tons
1,070 tons
93 tons
429,000 kft3
42.00/ton
90.00/ton
1,340. 00/ton
3.50/kft'
49,100
96,300
124,600
1,501,500
8,600
52,700 man-hr
423,600 MBtu
1,019,200 kgal
26,947,000 kWh
5,600 man-hr
12.50/man-hr
2.00/MBtu
0.06/kgal
0.031/kWh
17.00/man-hr
1,780,100
658,800
3,799,000
5,579,100
70 of average
annual revenue
requirements
0.42
0.83
1.07
12.86
0.07
15. 2}
5.64
7.26
0.52
7.16
11.15
0.82
32.55
47.80
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
2,221,900
3,274,500
19.04
28.07
8.80
0.56
0.47
56.94
104.74
Byproduct Sales Revenue
Sulfur
Subtotal byproduct sales revenue
Total average annual revenue requirements
Mill!
Equivalent unit revenue requirements 8.
13,840 short tons
}
$/ton coal
i/kWh burned
34 19.03
40.uO/short ton
$/MBtu heat
input
0.91
(553,600)
(553,600)
11,670,800
$/short ton
S removed
815.57
04.74)
(4.74)
100.00
$/short ton
S recovered
843.27
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 613,200 tons/yr, 9,200 Btu/kWh,
Stack gas reheat to 175°F.
S removed, 14,310 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $18,589,000; total depreciable investment, $37,032,000; and total capital
investment, $38,075,000.
210
-------
TABLE A-72
CITRATE PROCESS 200 MM NEW COAL-FIRED POKER UNIT 3.5X S IN COAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT: i 38075000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KM-HR/
START KM
1 7000
2 7000
3 7000
4 7000
5 7001)
6 7000
7 7000
8 7000
9 7000
LQ moo
1 1 5000
12 SOOO
13 5000
14 SOOO
i *, «nnn
16 3500
17 3500
18 3500
19 3500
?o iinn
21 1500
22 1500
23 1500
24 1500
-2,5 15.0.0.-
26 1500
27 1500
28 1500
29 1500
in ispn
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR
REMOVED
POKER UNIT POtiER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS.
/YEAR /YEAR TONS/YEAR
12880000 613300 14300
12860000 613300 14300
12860000 613300 14300
12880000 613300 14300
]?«nnnnn «.ninn i&ioo
12880000 613300 14300
12880000 613300 14300
12680000 613300 14300
12680000 61330C 14300
17880000 fcl^lOO 1410.0
9200000 43B10C 10200
9200000 438100 10200
9200000 436100 10200
9200000 438100 10200
opnnnnr vision 10?in
6440000 306700 7200
6440000 306700 7200
6440000 306700 7200
6440000 306700 7200
(,440000 30&7OO 7?nn
2760000 13140C 3100
2760000 131400 3100
2760000 131400 3100
2760000 131400 3100
BY-PRODUCT
RATE.
EGUIVALFNT
TONS/YEAR
SULFUR
13800
13800
13800
13800
J 13BGQ .
13*00
13800
13800
13800
138.00
9900
9900
9900
aonrj
6900
6900
6900
6900
f,inn
3000
3090
3000
3000
NET REVENUE,
*/TUN
SULFUR
40.00
40.00
40.00
4Q.CO
4h.no
40.00
40.00
4C.OO
40.00
fcfl -in
40.00
40.00
40.00
40.00
40 -nn
40.00
40.00
40.00
40.00
4C..QO
40.00
40.00
4Q.OO
40.00
TOTAL
OP. COST
INCLUDIMG
REGULATED
ROI FOR
POWER
COMPANY,
J/YEAR
1549B800
15206500
15074200
1466185D
L&6495.9.Q
14437253
142249DD
140126)3
13800300
115.829-10
11744700
11532430
11320100
11107890
TOTAL
NET
SALES
REVENUE.
S/YtAR
552000
552000
552000
552000
5^2 OOQ
552000
552000
552000
552000
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
i
14946KOO
14734500
14522200
14309800
i 4n47snn
13885200
13672900
13460600
13248300
(DECREASE I
IN COST OF
POWER,
»
14946600
29661300
44203500
58513300
72A1 OBD.O
86496000
100168900
113629500
126877800
S.52QQQ unison H4Qii7nn
396000
396000
396000
396000
1134H700
11136400
10924100
10711800
151262400
162398800
173322900
184034700
inB9«aQ i<»*>nnn intoa^nn t<>t<;i&?nn
9406490
9194100
6981890
8769500
8551200
6498300
6285990
6073600
5861390
216.0QQQ 13.14. OQ 3.10.0. JO 00 tO«fiQ SAkSOia.
2760000 131400 3100
2760000 131400 3100
2760000 131400 3100
2760000 131400 3100
77fifinpo 111 itfif\ 1 1 nn
234600000 11171000 261000
3000
3000
3000
3000
1000
252000
40.00
40.00
40.00
40.00
40.00
5436700
52244)3
5012090
4799790
£5 A *}6QQ
302371500
276000
276000
276000
276000
>7*vQnn
120000
120000
1200CO
120000
_-_L2.aoao_
120000
170000
120000
120000
_l 2gonQ
10080000
9130400
6918100
8705800
8493500
B.7H 1 PflO
6378300
6165900
5953600
5741300
203664600
212582700
221288500
229782000
? ^ftfifc 32QQ
244441500
250607400
256561000
262302300
5.5.29.DQQ 262£113.DO
5316700
5104400
4892000
4679700
6&&76 HO
292291500
273148000
278252400
283144400
2F7824100
2 9229 1 SCO
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER K1LOKATT-HUUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON CF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING C05T
DOLLARS PER TOD OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
27.07
11.86
128.8)
1158.51
108430500
0.90
0.40
4.30
38.62
3922200
DISCOUNTED PROCESS COST OVER LIFE OF
24.90
10.91
118.57
1067.29
0.90
0.40
4.28
38.61
26.17
11.46
124.59
1)19.89
104508300
POWER UNIT
24.00
10.51
114.29
1028.63
-------
TABLE A-73. CITRATE PROCESS
SU:tIARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW existing coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/I'"Btu heat input allowable emission)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor , tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
S0_ absorption (four packed tower absorbers including
presaturators and entraintnent separators, strippers,
Stack gas reheat (four indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
S02 reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H2S generation (battery limit plant)
H2 generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
782,000
134,000
4,154,000
\ 9 A^O fiflfl
i £ ,*O7 , UUU
1,312,000
98,000
1,114,000
2,743,000
783,000
1,009,000
5,921,000
4,753,000
35,262,000
2,116,000
37,378,000
3,352,000
838,000
5,049,000
1,505,000
10,744,000
9,624,000
57,746,000
5,775,000
6,930,000
70,451,000
39,000
2,115,000
72,605,000
2.1
0.4
11.1
•1 •> -J
JJ. J
3.5
0.3
3.0
7.3
2.1
2.7
15.8
12.7
94.3
5.7
100.0
9.0
2.2
13.5
4.0
28.7
25.8
154.5
15.5
18.5
188.5
0.1
5.7
194.3
Baals
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
212
-------
TABLE A-74. CITRATE PROCESS
SUIC1ARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW existing coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/HBtu heat input allowable emission)
Direct Costs
Raw materials
Lime
Soda ash
Citric acid
Natural gas
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, S
Total
annual
cost, $
2,930 tons
2,680 tons
233 tons
1,070,000 kft'
67,920 man-hr
1,059,000 MBtu
2,547,800 kgal
67,568,000 kWh
10,600 man-hr
42.00/ton
90.00/ton
1,340. 00/ton
3.50/kft5
12.50/man-hr
2.0U/MBtu
0.06/kgal
0.029/kWh
17 .00/man-hr
4,443,100
849,000
7,502,300
11,945,400
% of average
annual revenue
requirements
0.53
1.04
1.35
16.16
0.09
19.17
3.66
9.14
0.66
8.46
9.68
0.78
32.38
51.55
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 34,590 short tons
Subtotal byproduct sales revenue
Total average annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 6.62 15.11
4,508,900
6,244,000
1,636,000
84,900
138,400
12,612,200
24,557,600
40.00/short ton (1,383,600)
(1,383,600)
23,174,000
$/MBtu heat S/short ton
input S removed
0.72 647.68
19.46
26.93
7.06
0.37
0.60
54.42
105.97
(5.97)
(5.97)
100.00
$/short ton
S recovered
669.96
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,533,350 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 35,780 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $37,378,000; total depreciable investment, $70,451,000; and total capital
investment, $72,605,000.
213
-------
TABLE A-75
CITRATE PROCESS 500 NW EXISTING COAL-FIRED POWER UNIT 3.5X S IN COAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
72605000
SULFUR
REMOVED
YEARS ANNUAL POKER UNIT POkER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POkER TICK. RECLIREMEM, CCKIUMPTICN, COMTRCL
UNIT KW-HR/ MILLION BTU TOUS COAL PROCESS,
START KU /YEAR /YEAR TONS/YEAR
1
2
3
4
5
6 1CCC 2220COCC 153330C 3S10C
7 7000 32200000 1533300 35800
8 70CO 22200000 1533300 35800
9 7000 32200000 1533300 35800
_io 2000 322aaaao is.3i3.aa isaaa
11 5000 23000000 1095200 25600
12 5000 23000000 1095200 25600
13 5000 2300000C 1095200 2560C
14 5000 23000000 1095200 25600
is spaa . ?3COCCCC . |0«SJ°t - _. 2,*fPr
16 3500 16100000 766700 17900
17 3500 1610000C 76670C 1790C
18 3500 16100000 766700 17900
19 3500 1610COCC 166100 17900
20 3SOQ 1 61QOOOP 7frfr ^0" nQflfl
21 1SCO tfOCOCC 328COC HOC
22 1500 6900000 328600 7700
23 1500 6900000 328600 7700
24 1500 6900000 328600 7700
.2.5 isao. 6saaaaa 128.600 2200 „.
26 1500 6900000 328600 7700
27 1500 6900000 328600 7700
28 1500 6900000 328600 7700
29 1500 6900000 328600 7700
30 1500 tsoenec -. 3^«*uc _, Jjoc
TOT 92500 425500000 20262000 473500
LIFETIME AVERACE INCREASE KECREAiE) IN UNIT GPERATII
DOLLARS PER TON OF COAL BURNED
HILLS PER KILONATT-MDUR
CENTS PER MILLION BTU HEAT INPUT
COLLARS PER TO* CF SULFUR REMOVED
PROCESS COST DISCOUNTEC AT 11.6* 10 INITIAL YEAR, OCLLl
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
HILLS PER KILOWATT-HOUR
CEkTS PER MLLIOK BTl HEAT IRPLT
DOLLARS PER TON OF SULFUR REMOVED
EY-PROCUCT
RATE.
EQUIVALENT
TONS/YEAR
SULFUR
34600
34600
34600
34600
34600
24700
24700
24700
24700
17300
17300
17300
11300
7400
7400
1400
7400
3400
7400
1400
7400
7400
3600
457000
IIC COST
IRS
EOUIVALENT TO
TOTAL
OP. COST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE. REGULATED TOTAL INCREASE NET INCREASE
$/TON ROI FOR NET (DECREASE) (DECREASE)
POkER SALES IN COST CF IN COST GF
COMPANY. REVENUE, PC HER, POKER,
StLFUR I/YEAR S/YEAR 1 $
40.00 30801800 13840CO 2S417CCG
40.00 30311100 1384000 28933100
4C.OO 29832400 1384000 26446400
40.00 29341700 13840CO 27963700
40.00 24867900 988000 23879900
40.00 24383200 988000 23395200
40.00 23898500 9880CO 229105CO
40.00 23413800 988000 22425POO
4C.QO 2?92$IOQ CB80CD, }]<)ilirn
40.00 19730200 692000 19038200
40.00 1924SSOO 6920CO 18553500
40.00 18760800 692000 18068800
40.00 18276100 6920CO 115841CO
4fl-nO 17791*00 69.2000... 17Q99400
2S411CCO
58350900
86799300
114763000
~166121900
189517100
212421600
234853400
25£334iCO
275832700
294386200
312455000
33003*100
40.00 13413200 2960CO 131112CC 36C315100
40.00 12988500 296000 12692500 373008200
4C.OO 12503800 2960CO 12207(00 385216000
40.00 12019100 296000 11723100 396939100
40.00 1L&3440JO. 2,9.6.040 1123U4QG 4QB1Z25QO
40.00 11049700 296000 10753700 418931200
4G.OO 10565000 296000 10269000 429200200
40.00 10080300 296000 9784300 438984500
40.00 9595700 296000 9299100 448284200
4H.jia siiiaaa istQLa j«xs££D 453015200
475379200 18280000 451099200
23.46 0.90 22.56
10.28 0.40 9.88
111.72 4.29 107.43
1003.97 38. tl 965. 3«
145385100 82853CO 181099CCO
DISCOUNTED PROCESS COST OVER LIFE OF POWER UNIT
21.28 0.90 20.38
9.32 0.39 8.93
101.34 4.30 97. C4
911.31 38.64 872.61
-------
TABLE A-76. CITRATE PROCESS
SUI1MARY OF ESTIMATED CAPITAL INVESTMENT3
(500-11W new coal-fired power unit, 2.0% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO. absorption (four packed tower absorbers including
presaturators and entrainment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
SO. reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks.
pumps, and refrigeration)
H.S generation (battery limit plant)
H,, generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
444,000
81,000
4,093,000
12,285,000
1,222,000
97,000
696,000
1,685,000
,
470,000
577,000
3,817,000
2,697,000
28,164,000
1,690,000
29,854,000
2,728,000
682,000
4,190,000
1,268.000
8,868,000
7,744,000
46,466,000
4,647,000
5,576,000
56,689,000
39,000
1,370,000
58,098,000
1.5
0.3
13.7
41.2
4.1
0.3
2.3
5.6
1.6
1.9
12.8
9.0
94.3
5.7
100.0
9.1
2.3
14.0
4.2
29.6
26.0
155.6
15.6
18.7
189.9
0.1
4.6
194.6
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
215
-------
TABLE A-77. CITRATE PROCESS
SUl-ClAPvY OF AVERAGE ANNUAL PvEVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 2.0% S in coal;
1.2 lb S02/MBtu heat input allowable emission)
Annual Unit
quantity cost, 5
Direct Costs
Raw materials
Lime 1,320 tons 42.00/ton
Soda ash 1,210 tons 90.00/ton
Citric acid 105 tons 1,340.00/ton
Natural gas 483,000 kft3 3.50/kft'
Catalyst
Operating labor and supervision 56,380 man-hr 12.50/man-hr
Utilities
Steam 741,500 MBtu 2.00/MBtu
Process water 1,253,400 kgal 0.06/kgal
Electricity 56,355,000 kWh 0.029/kWh
Maintenance
Labor and material
Analyses 9,500 man-hr 17.00/man-hr
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 15,570 short tons 40.00/short ton
Subtotal byproduct sales revenue
Total average annual revenue requirements
S/ton coal S/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements 4.88 11.39 0.54
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 16,200 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded
Total
annual
cost, $
55,400
108,900
140,700
1,690,500
9.700
2 ,005 ,200
704,800
1,483,000
75,200
1,634,300
1,791,200
161,500
5,850,000
7,855,200
3,401,300
4,996,400
1,328,800
70,500
62,300
9,859,300
17,714,500
(622,800)
(622,800)
17,091,700
$/short ton
S removed
1,055.04
% of average
annual revenue
requirements
0.32
0.64
0.82
9.89
0.06
11.73
4.12
8.68
0.44
9.56
10.49
0.94
34.23
45.96
19.90
29.24
7.77
0.41
0.36
57.68
103.64
(3.64)
(3.64)
100.00
S/short ton
S recovered
1,097.73
Total direct investment, $29,854,000; total depreciable investment, $56,689,000; and total capital
investment, $58,098,000.
215
-------
TABLE A-78
CITRATE PROCESS 500 HW NEW COAL-FIRED POWER UNIT 2.0* S IN COAL, REGULATtD Cti. ECONOMICS
FIXED INVESTMENT: *
st-o^eooo
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
1 ^
16
17
18
19
_2,a
21
22
23
24
•> c
26
27
28
29
_3.D
ANNUAL
OPERA-
TION.
KW-HR/
KW
7000
7000
7000
7000
7.00.0.
7000
7000
7000
7000
7onn
5000
5000
5000
5000
5000
3500
3500
3500
3500
POWER UNIT
HEAT
REQUIREMENT,
MILLION BTU
/YEAR
31500000
31500000
31500000
31500000
ninnnnn
31500000
31500000
31500000
31500000
305000.0.0
22500000
22500000
22500000
22500000
??*i 000 00
15750000
15750000
15750000
15750000
POWER UNIT
FUEL
CONSUMPTION,
TOKS CCAL
/YEAR
1500000
1500000
1500000
150000C
i ifififinfi
1500000
1500000
150000C
1500000
150.040.0
1071400
1071400
1071400
1071400
JQ71 AfjQ
750000
750COO
750000
750000
.3.5.00, 1S7SOODO 7snnno
1500
1500
1500
1500
unn
1500
1500
1500
1500
6750000
6750000
6750000
6750000
675.00,00,
6750000
6750000
6750000
6750000
321400
321400
321400
321400
-12140.Q
321400
321400
321400
321400
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS.
TONS/YEA*
16200
16200
16200
16200
.16200
16200
16200
16200
16200
16200
11600
11600
11600
11600
11600.
8100
8100
8100
8100
_B.1QD
3500
3500
3500
3500
1500
3500
3500
3500
3500
BY-PRODUCT
RATF,
EQUIVALENT
TPNS/tEAR
SULFUR
15600
15600
15600
15600
i "ifcfiri
15600
15600
15600
15603
i 5*, on
11103
11100
11100
11100
111QQ
7600
7fOO
7600
7800
NET REVENUE,
I/TON
SULFUR
40.00
40.00
4C.OO
40.00
^fi n n
40.00
40 .00
40.00
40 .CO
4r nQ
40.03
40.00
40.00
4G.OO
tn.nn
40.00
40.00
40.00
40.00
TOTAL
OP. COST
INCLUDING
REGULATED
RDI FOR
POWER
CDHPANY,
1/YEAH
22711033
22385930
22060933
21735900
2.141QS3.Q.
21085900
20760930
20435900
201109DO
197859.00 ,
17150400
16*25400
16500400
16175433
ico 5.04*10.
13726933
13401930
13376933
12751900
TOTAL
NET
SALFS
RFVENUE,
*/YEAR
674000
624000
674000
624000
h? boon
624000
624000
624000
624000
_£24UOO
444000
444000
444000
444000
_4i.40-Cfl
312000
312000
312000
312000
NET ANNUAL
INCREASE
(DECREASE)
IN COST E.F
POWER,
1
22DK7000
21761900
21436900
21 1 ll^OO
?O7i!«.9nn
20461900
20136900
19811900
19486900
16706400
16381400
16056400
15731400
_L54fl&4£lCL
13414900
13089900
12764900
12439900
CUMULATIVE
NET INCREASE
(DECREASE 1
IN COST HF
POWER,
$
22087000
43848900
65285800
86397700
i n it ft &finn
121646500
147783400
167595300
187082200
?Ofc2A4 1 00
222950500
239331900
255388300
271119700
, . 286526100
299941000
313030900
325795800
338235700
. ^laao,^ kO-nn iPtJAHfin -*i:>nnn i;ii4«nn ^n^snsnn
3300
330D
3300
3300
3300
3300
3300
3300
3300
40.00
40 .00
40.00
40.00
40 DO
40.00
40.00
40.00
40.00
9529500
9204530
8879500
8554500
.B22S.50.Q .
7904500
7579500
7254500
6929433
1320CO
132000
132000
132000
i -a ^ QQQ
132000
132000
13200P
132000
9397500
9072500
8747500
8422500
7772500
7447500
7122500
6797400
359748000
36*820500
377568000
385990500
3u&Q R 8,0,0.0
401860500
409338000
416430500
423227900
isoo «>7snnnn tyitnn 4400 ^0.0. tn.nn 6.&046QQ 132000 &47?4on tpqinmnn
TOT 127500 573750000 27321GOO 295500 283500
LIFETIME AVERAGE INCREASE (DECREASE I IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
HIILS PE* KILOWATT-HOUR
CENTS PER PILLION BTU HEAT INPLT
DOLLARS PER TO* CF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
441040333 1I340000 429700300
16.14
6.92
76.87
1492.52
158411900
0.41
0.18
1.98
38.37
4427100
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
COLLARS PER TON OF COAL BURNED 14.B6 0.42
HILLS PER KILOWATT-HOUR 6.37 0.17
CENTS PER MILLION BTU HEAT INPUT 70.83 1.98
DOLLARS PER TON OF SULFUR REMOVED 1376.30 38.47
15.73
6.74
74.89
1454.15
153984800
POWER UNIT
14.46
6.20
68.85
1337.83
-------
TABLE A-79. CITRATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
S00 absorption (four packed tower absorbers Including
presaturators and entrainment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
SO reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H?S generation (battery limit plant)
H~ generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
770,000
132,000
4,093,000
12,285,000
1,282,000
97,000
1,100,000
2,706,000
772,000
994,000
5,850,000
4,680,000
34,761,000
2,086.000
36,847,000
2.1
0.4
11.1
33.2
3.5
0.3
3.0
7.3
2.1
2.7
15.9
12.7
94.3
5.7
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
3,330,000
833,000
4,989,000
1,488.000
10,640,000
9,497.000
56,984,000
9.0
2.3
13.5
4.0
28.8
25.6
154.6
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
5,698,000
6,838,000
69,520,000
39,000
2.080.000
71,639,000
15.5
18.6
188.7
0.1
5.6
194.4
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
213
-------
TABLE A-80. CITRATE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 3.5% S in coal;
1.2 lb S02/MBtu heat input allowable emission)
Direct Costs
Raw materials
Lime
Soda ash
Citric acid
Natural gas
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
2,870 tons
2,630 tons
230 tons
1,050,000 kft3
67,920 man-hr
1,035,900 MBtu
2,492,500 kgal
66,100,000 kWh
10,600 man-hr
42.00/ton
90.00/ton
1,340.00/ton
3.50/kft3
12.50/man-hr
2.00/MBtu
0.06/kgal
0.029/kWh
17.00/man-hr
120,500
236,700
308,200
3,675,000
21,000
4,361,400
849,000
2,071,800
149,600
1,916,900
7,378,300
11,739,700
% of average
annual revenue
requirements
0.53
1.05
1.37
16.31
0.09
19.35
3.77
9.19
0.66
8.51
9.81
0.80
32.74
52.09
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 34,410 short tons
Subtotal byproduct sales revenue
Total average annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 6.44 15.02
4,171,200
6,161,000
1,620,000
84,900
13;, 600
12,174,700
23,914,400
40.00/short ton (1.376.400)
(1,376,400)
22,538,000
S/MBtu heat S/short ton
input S removed
0.72 643.94
18.51
27.33
7.19
0.38
0.61
54.02
106.11
(6.11)
(6.11)
100.00
$/short ton
S recovered
654.98
a. Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 35,000 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $36,847,000; total depreciable investment, $69,520,000; and total capital
investment, $71,639,000.
219
-------
TABLE A-81
CITRATF PROCESS 500 MW NEW COAL-FIRED POWER UNIT 3.5* S IN COAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT: » 71639000
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
_lfl —
11
12
13
14
16
17
18
19
-2.0 —
21
22
23
24
26
27
28
29
10
ANNUAL
OPERA-
TION,
KW-HR/
KW
SULFUR BY-PRODUCT
REMOVED RATE.
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
RETIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS,
/YEAR /YEAR TONS/YEAR SULFUR
7000 31500000
7000 31500000
7000 31500000
7000 31500000
— IOQO. 315.000.0.0.
7000 31500000
7000 31500000
7000 31500000
7000 31500000
"*(1flO ' t *iflftflflG
5000
5000
5000
5000
snnn
3500
3500
3500
3500
35Qfl
1500
1500
1500
1500
1500
1500
1500
1500
22500000
22500000
22500000
22500000
15750000
15750000
15750000
15750000
6750000
6750000
6750000
6750000
«.7sonoo
6750000
6750000
6750000
6750000
*,7snnon
1500COC 35000 34400
1500000 35000 34400
1500000 35000 34400
1500000 35000 34400
l^nnnnn 15.QOJ1 3.4&QQ__
1500000 35000 34400
1500000 35000 34400
1500000 35000 34400
1500000 35000 34400
1071400
1071400
1071400
1071400
75000C
750000
750000
750000
1SOX1Q.Q
321400
321400
321400
321400
321400
321400
321400
321400
25000
25000
25000
25000
17500
17500
17500
17500
_ -115.00.
7500
7500
7500
7500
7500
7500
7500
7500
1SQD
24600
24600
24600
24600
17200
17200
11200
17200
11204-
7400
1400
7400
1400
3*00 , .
7400
7400
7400
1400
1400
NET REVENUE,
t/TDN
SULFUR
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FO*
POWER
COMPANY,
*/YEA*
NET AhNUAl
TOTAL INCREASE
NET (DECREASE)
SALES IN COST OF
REVENUE. PCWER.
*/VEAR *
CUMULATIVE
NET INCREASE
(DECREASE )
IN CDS! Of
POWER,
*
40.CO 30075300 1376000 26699300 2B699300
40.00 29676700 1376000 2X300700 57000000
40.00 29278200 1376000 27902200 84902200
40.00 28879630 1376000 27503600 117405800
&G~QO J,Bi.a 10.11 13.16.OaO 21105000 13-2ilOaaO
40.00 28082430 1376000 26706400 166217200
40.00 276839)0 1376000 26307900 192525100
40.00 27285330 1376000 25909300 21B434400
40.00 26886730 1376000 25510700 243945100
L.n .fin ?A4«»jnn n7fcnnn piii.?inn )bnn
40.00
40.00
40.00
40.00
40. fQ
40.00
40.00
40.00
40.00
fcO.,.0.0
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
4.0.00 .
22639300 984000
22240700 984000
21842130 984000
21443500 984000
210443110. 9a40OQ .
17978400
17579800
17181200
16782630
..LCOBAULl--.
12214200
118156)3
11417030
11016500
1022)300
9822700
9424200
9025600
A<>2 7(100
21655300
21256100
20858100
20459500
POO&Q90Q
68BOOC 17290400
688000 16891800
688000 16493200
688000 16094600
jfc.t8.aQD 15fc.S6.lQQ—
296000 1)918200
296000 11519600
296000 11121000
296000 10722500
. 296DDO inip-icnn
296000
296000
296000
296000
_2&6.aao .
9925300
9526700
9126200
8729600
A3.3J.oaa .
290712500
311969200
332827300
353286800
SJaatiiao
390638100
407529900
424023100
440117700
4.5.5.8.13,aOO
467132000
479251600
490372600
50)095100
— — 5JJ.41SOOO
521344300
53C871000
539999200
540728800
TOT 127500 573750000 21321COC 637500 627000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CbAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER PILLION BTU HEAT INPLT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
582139800 2508000P 557059800
21.31
9.1)
101.46
913.16
210134300
0.92
0.39
4.37
39.34
9771300
LEVELIZEO INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT Ttl DISCOUNTED PROCESS COST OVER LIFE UF
DOLLARS PER TON CF CI1AL BURNED 19.73 0.92
HILLS PER KILOWATT-HPUR 8.46 0.40
CENTS PER MILLION BTU HEAT INPUT 93.96 4.37
DOLLARS PER TON OF SULFUR REMOVED 845.61 39.32
20.39
8.74
97. C9
873.82
200363000
POWER UNIT
18.81
8.06
89.59
806.29
-------
TABLE A-32. CITRATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 5.0% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO absorption (four packed tower absorbers including
presaturators and entrainment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
SO- reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H2S generation (battery limit plant)
H~ generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , $
1,045,000
173,000
4,093,000
12,285,000
1,283,000
97,000
1,418,000
3,519,000
1,017,000
1,344,000
7,413,000
6,354,000
40,041,000
2,402,000
42,443,000
3,816,000
954,000
5,611,000
1,657,000
12,038,000
10,896,000
65,377,000
6,538,000
7,846,000
79,761,000
39,000
2,772,000
82,572,000
% of
total direct
investment
2.5
0.4
9.6
28.9
3.0
0.2
3.3
8.3
2.4
3.2
17.5
15.0
94.3
5.7
100.0
9.0
2.2
13.2
3.9
28.3
25.7
154.0
15.4
18.5
187.9
0.1
6.5
194.5
a. Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
221
-------
TABLE A-33. CITRATE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(500-MW nev; coal-fired power unit, 5.0% S in coal;
1.2 lb SOa/MBtu heat input allowable emission)
Annual Unit
quantity cost, $
Direct Costs
Raw materials
Lime 4,410 tons 42.00/ton
Soda ash 4,040 tons 90.00/ton
Citric acid 350 tons 1,340.00/ton
Natural gas 1,620,000 kft' 3.50/kft1
Catalyst
Conversion costs
Operating labor and supervision 79,450 man-hr 12 .50/man-hr
Utilities
Steam 1,329,800 MBtu 2.00/MBtu
Electricity 75,814,000 kWh 0.029/kWh
Maintenance
Labor and material
Analyses 11,350 man-hr 17.00/man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 52,050 short tons 40.00/short ton
Subtotal byproduct sales revenue
Total average annual revenue requirements
S/ton coal S/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements 7.86 18.34 0.87
Total
annual
cost , $
185,200
363,600
469,000
5,670,000
32,300
6,720,100
993,100
2,659,600
223,600
2,198,600
2,546,600
193,000
8,814,500
15,5J4,600
4,785,700
7,101,200
1,866,400
99,300
208,200
14,060,800
29,595,400
(2.082,000)
(2,082,000)
27,513,400
$/short ton
S removed
507.81
% of average
annual revenue
requirements
0.67
1.32
1.70
20.61
0.12
24.42
3.61
9.67
0.81
7.99
9.26
0.70
32.04
56.46
17.39
25.82
6.78
0.36
0.76
51.11
107.57
(7.57)
(7.57)
100.00
$/short ton
S recovered
528.60
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 54,180 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, 542,443,000; total depreciable investment, $79,761,000; and total capital
investment, $82,572,000.
222
-------
TABLE A-84
CITRATE PROCESS 500 MM NEW COAL-FIRED POWER UNIT 5.0* S IN COAL, REGULATED CO. ECCWOMCS
FIXED INVESTMENT:
82572000
ISJ
SULFUR BY-PRO CUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION. REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION BTU TOKS COAL PROCESS.
START KM /YEAR /YEAR TONS/YEAR SULFUR
1 7000
2 7000
3 7000
4 7000
6 7000
7 7000
8 7000
9 7000
10 7OOO
1 1 5000
12 5000
1 3 5000
14 5000
16 3500*
17 3500
1 8 3500
1 9 3500
21 1 500
22 1500
23 1500
24 1500
PS ison
26 1500
27 1500
28 1500
29 1500
-3-0. ISQ.Q-
TOT 127500
LIFETIME
PROCESS COST
IEVEII2ED
31500000 1500000 54200
31500000 1500000 54200
31500000 1500000 54200
31500000 1500000 54200
31500000 1500000 54200
31500000 1500000 54200
31500000 1500000 54200
31500000 1500000 54200
4i*nnnnn isonnnn <;&?an
22500000 1071400 38700
22500000 1071400 38700
22500000 1071400 38700
22500000 1071400 38700
77^00000 1011400 ?A*ipo
15750000 75000C 27100
15750000 750000 27100
15750000 750000 27100
15750000 750000 27100
6750000 321400 11600
6750000 321400 11600
6750000 321400 11600
6750000 321400 11600
6750000 321400 11600
6750000 321400 11600
6750000 321400 11600
6750000 321400 11600
*.7snnnn 3.71400 II&QO
573750000 21321COO 987000
AVERAGE INCREASE {DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF COAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL VEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EC
DOLLARS PER T0» CF COAL BURNED
NILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON (IF SULFUR REMOVED
52100
52100
52100
52100
52100
52100
52100
52100
.-521QQ-.
TOTAL
OP. CCIST
INCLUDING
NET REVENUE, REGULATED
»/TPN ROI FOR
POWER
COMPANY,
SULFUR t/YEAft
40.00
40 .00
40.00
40.00
4(1 _nn
40.00
40.00
40.00
40.00
4fl^£lD_
31200 40.00
37200 40.00
37200 40.00
37200 40.00
3 77 Q o frfl rnn
26000 40.00
26000 40 .00
26000 40.00
26000 40.00
. . . 2£OQO . in .on
11200
11200
11200
11200
11700
11200
11200
11200
11200
Lizda
949000
COST
UIVALENT TO
40.00
40.00
40.00
40.00
36696900
36239630
35782300
35325030
34410400
33953100
33495BDO
33038933
3,2Sai?aa
27561433
27104100
26646833
26189500
21760300
21303000
20845700
20388430
ISMl'QQ
14540800
14083500
13626200
131689)3
1771K.QO
40.00 12254333
40.00 11797030
40.00 11)39733
40.00 10882400
kO,»0-Q— 10425100
708682600
25.9*
11.12
123.52
718.02
256736200
DISCOUNTED PROCESS COST OVI
24.11
10.33
114.80
667.19
TOTAL
NET
SALES
REVENUE,
»/YtAK
20641 00
2064000
20R4000
20P4000
2084000
20B4000
2064000
ZClEiQUD
146fcOOO
148BOOO
1488000
1486000
1040000
1040000
1040000
104QOOO
jntfirnn
448000
448000
448000
448000
-Ai-BQflQ .
448000
448000
448000
448000
37960000
1.39
0.60
6.62
38.46
14794700
ER LIFE OF
1.39
0.59
6.62
38.44
NET ANNUAL
INCREASE
(DECREASE t
IN COST OF
POWER.
34612900
34155600
33698300
33241000
3.77C.3.7QQ
32326400
31869100
31411BOO
30954500
Z 60 73 400
25616100
25158800
24701500
•?42*.420n_
20720300
20263000
19805700
19348400
I afiQi 7nn
14012800
13635500
13178200
12720900
. , 12263*00
11806300
11349000
10891/00
10434400
9977HJO
670722600
24.55
10.52
116.90
679.56
241941500
POWER UNIT
22.72
9.74
108.18
628.75
CUMULATIVE
NET INCREASE
(DECREASE!
IN CDST LIF
POKER,
34612900
68768500
102466800
135707800
200817900
232687000
264098800
29505 3300
375550500
351623900
377240000
402396800
427100300
472064800
492327800
512133500
5314H1900
564465900
578131400
591279600
604000500
616.266100
628070400
639419400
650311100
660745500
-------
TABLE A-85. CITRATE PROCESS
SUICIARY OF ESTIMATED CAPITAL INVESTMENT*
(1000-MW existing coal-fired power unit, 3.5% S in coal;
1.2 lb S02/*lBtu heat input allowable emission)
7, of
total direct
Investment, $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO- absorption (four packed tower absorbers including
presaturators and entralnment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
SO- reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump.
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H2S generation (battery limit plant)
H~ generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1,260,000
204,000
6,557,000
19,144,000
2,026,000
143,000
1,656,000
4,130,000
1,203,000
1,615,000
8,565,000
7,656,000
54,159,000
3,250,000
57,409,000
4,184,000
1,046,000
7,209,000
2,085,000
14,524,000
14,386,000
86,319,000
8,632,000
10,358,000
105,309,000
45,000
3,670,000
109,024,000
2.2
0.4
11.4
33.4
3.5
0.2
2.9
7.2
2.1
2.8
14.9
13.3
94.3
5.7
100.0
7.3
1.8
12.6
3.6
25.3
25.1
150.4
15.0
18.0
183.4
0.1
6.4
189.9
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
224
-------
TABLE A-86. CITRATE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(1000-MW existing coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
Annual Unit
quantity cost, S
Direct Costs
Raw materials ^^ ^ A2.0o/ton
Soda ash 5-250 cons 90.00/ton
Citric acid 455 cons 1,340.00/ton
Natural gas 2,100,000 kft' 3.50/kft'
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision 83,100 man-hr 12.50/man-hr
"'steam6" 2,062,800 MBtu 2.00/MBtu
Process water 4,984,900 kgal 0.06/kgal
Electricity 132,201,000 kWh 0.028/kWh
Maintenance
Labor and material
Analyges 17,450 man-hr 17.00/man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 507. of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10^ of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 67,680 short tons 40. 00/short ton
Subtotal byproduct sales revenue
Total average annual revenue requirements
S/ton coal $/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements 5.28 12.31 0.59
Total
annual
cost, S
240,700
472,500
609,700
7,350,000
42,000
8,714,900
1,038,800
4,125,600
299,100
3,701,600
2,870,500
296,700
12,332,300
21,047,200
6,739,800
9,376,100
2,103,000
103,900
2,'D,700
18,593,500
39,640,700
(2,707,200)
(2,707,200;
36,933,500
$/short ton
S removed
527.62
% of average
annual revenue
requirements
0.65
1.28
1.65
19.91
0.11
23.60
2.81
11.17
0.81
10.03
7.77
0.80
33.39
56.99
18.25
25.39
5.69
0.28
0.73
50.34
107.33
(7.33)
(7.33)
100.00
S/short ton
S recovered
545.71
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plane, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 2,999,850 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 70,000 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, 557,409,000; total depreciable investment, $105,309,000; and total capital
investment, $109,024,000.
225
-------
TABLE A-87
CITRATE PROCESS 1000 MW EXISTING COAL-FIRED POWEK UNIT 3.5% S IN COAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 10902*000
YEARS
AFTER
POWFR
UNIT
START
ANNUAL POWER UNIT
OPERA- HEAT
TION, REQUIREMENT,
KW-HR/ MILLION BTU
KW /YEAR
SULFUR
UEMOVED
POWER UNIT BY
FUEL POLLUTION
CONSUMPTION. CONTROL
TONS COAL PROCESS.
/YEAR TONS/YEAH
RY-PROOUCT
RATE,
EQUIVALENT
TONS/YEAR
SULFUR
NET REVENUE.
S/TON
SULFUR
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
NET ANNUAL
TOTAL INCREASE
NET (DECREASE)
SALES IN COST OF
REVENUE, POWER.
S/YEAR t
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
S
1
2
3
*
5
6
7
8
9
11
12
N> 13
K 1*
c^ 15
16
17
IB
19
_22__.
21
22
23
2*
_25—
26
27
28
29
-30—
7000
7000
7000
7000
2202
5000
5000
5000
5000
5022
3500
3500
3500
3500
_3522
1500
1500
1500
1500
1522
1500
1500
1500
1500
63000000
63000000
63000000
63000000
63000010
3000000
3000000
3000000
3000000
300QQQQ_
*5000000 21*2900
*5000000 21*2900
45000000 2142900
45000000 2142900
45222222 21429flO_
31500000
31500000
31500000
31500000
31522222
13500000
13500000
13500000
13500000
13522222
13500000
13500000
13500000
13500000
1352020.2— _
1500000
1500000
1500000
1500000
1522222- _
642900
642900
642900
642900
6429flO_
642900
642900
642900
642900
70000
70000
70000
70000
12222 _
50000
50000
50000
50000
_ 52020.
35000
35000
35000
35000
35222 -_
15000
15000
15000
15000
15222
15000
15000
15000
15000
67700
67700
67700
67700
61122
48300
48300
48300
48300
44320
33800
33800
33BOO
33800
14500
14500
14500
14500
14520
14500
14500
14500
1*500
14522
40.00 49016900
40.00 48292400
40.00 47567900
40.00 46843300
42«.22 4611fia22__
40.00 39200600
40.00 38476000
40.00 37751500
40.00 37027000
40*02 36302420—
40.00 30833900
40.00 30109*00
40.00 29384800
40.00 28660300
_40«.20_ 27935800
40.00
40.00
40.00
40.00
40*00_
40.00
40.00
40.00
40.00
4Q.QO
20623600
19899100
19174600
18450000
-11125500
17001000
16276400
15551900
14827400
._14122a20__
2708000
2708000
2708000
2708000
-2126222
1932000
1932000
1932000
1932000
-1232000—
1352000
1352000
1352000
1352000
-1352020--.
5BOOOO
580000
580000
580000
592222
580000
580000
580000
580000
530000 -.
46308900
45584400
**859900
4*135300
43410500
37268600
3654*000
35819500
35095000
--34310400-
29*81900
28757*00
28032800
27308300
26583500-
200*3600
19319100
1859*600
17870000
12145500
46308900
91893300
136753200
180888500
_. -22*222300
261S67900
298111900
333931400
369026400
40a326«00
432878700
461636100
489668900
516977200
56360*600
582923700
601518300
619388300
636533800
16*21000 65295*800
15696*00 668651200
1*971900 683623100
1*2*7*00 697870500
.-13522620 __ 11U23300
TOT 92500 632500000 39643500 925000 894000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION STU HFAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6% TO INITIAL YEAR. DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
747153300 35760000 711393300
18.85 0.91 17.94
8.08 0.39 7.69
89.75 4.30 85.45
807.73 38.66 769.07
309321200 16207400 293113800
PROCESS COST OVER LIFE OF POWER UNIT
17.22 0.90 16.32
7.38 0.39 6.99
82. oo 4.30 77.70
738.06 38.67 699.39
-------
TABLE A-38. CITRATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(1000-MW new coal-fired power unit, 3.5% S in coal;
1.2 Ib S02/MBtu heat input allowable emission)
a of
total direct
Investment , $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO_ absorption (four packed tower absorbers including
presaturators and entrainment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (feeder, tank, agitator, and pumps)
S0_ reduction (reactor tanks, aging tank, agitators, and
.centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H.S generation (battery limit plant)
H- generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
1,230,000
200,000
6,408,000
18,733,000
1,875,000
140,000
1,623,000
4,045,000
1,177,000
1,577,000
8,406,000
7.473.000
52,887.000
3,173.000
56,060,000
2.2
0.4
11.4
33.5
3.3
0.2
2.9
7.2
2.1
2.8
15.0
13.3
94.3
5.7
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed Investment
4,132,000
1,033,000
7,068,000
2,048.000
14,281,000
14.068.000
84,409,000
7.4
1.8
12.6
3.7
25.5
25. j
150.6
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital Investment
8,441,000
10.129.000
102,979,000
45,000
3.565.000
106,589,000
15.1
18.0
183.7
0.1
6.4
190.2
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by Indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FCD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
227
-------
TABLE A-39. CITRATE PROCESS
SUIC1ARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS3
(1000-MW new coal-fired power unit, 3.5% S in coal;
1.2 lb S02/MBtu heat input allowable emission)
Annual
quantity
Direct Costs
Raw materials
Lime
Soda ash
Citric acid
Natural gas
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
5
5
2,030
83
2,002
4,818
127,919
17
,540
,070
440
,000
,100
,700
,600
,000
,450
tons
tons
tons
kft'
man-hr
MBtu
kgal
kWh
man-hr
Unit
cost, S
42
90
1,340
3
12
2
0
0.
17
.00/ton
.00/ton
.00/ton
.50/kfts
.50/man-hr
.00 /MBtu
.06/kgal
028/kWh
.00/man-hr
Total
annual
cost , $
7,
8,
1,
4,
3,
2,
12,
232,
456,
569,
105,
40,
424,
038,
005,
289,
581,
803,
296,
700
300
600
000
600
200
800
400
100
700
000
700
014,700
20,438,900
% of average
annual revenue
requirements
0,
1
1
19
0
23
2
11
0
10
7
0
33
57
,65
.28
.66
.96
.11
.66
.92
.26
.81
.06
.87
.83
.75
.41
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
6,178,700
9,166,700
2,069,300
103,900
261,700
17,780,300
38,219,200
17.35
25.75
5.81
0.29
0.74
49.94
107.35
Byproduct Sales Revenue
Sulfur 65,420 short tons 40.00/short ton (2.616.800)
Subtotal byproduct sales revenue (2,616,800)
Total average annual revenue requirements 35,602,400
$/ton coal $/MBtu heat $/short ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 5.09 12.28 0.58 526.12
$/short ton
S recovered
544.21
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 2,900,100 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 67,670 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $56,060,000; total depreciable Investment, $102,979,000; and total capital
investment, $106,589,000.
223
-------
TABLE A-90
CITRATE PROCESS 1000 MW NEW COAL-FIRED POWER UNIT 3.5* S Ik, COAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: * 106589000
YEARS ANNUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START KW
1
2
3
4
6
7
8
9
10
11
12
13
14
M J5
7000
7000
7000
7000
zaaa_.
7000
7000
7000
7000
innn
5000
5000
5000
5000
snnn
NJ 16 3500
"° 17 3500
18 3500
19 3500
_za _iio.a_
21 1500
22 1500
23 1500
24 1500
? 5 15DO
26
27
28
29
3D
1500
1500
1500
1500
1500
POWER UNIT
HEAT
REOUIREMENT.
MILLION BTU
/YEAR
6090000C
60900000
60900000
60900000
602aaaaa
60900000
60900000
60900000
60900000
Anonnnnn
43500000
43500000
43500000
43500000
30450000
30450000
30450000
30450000
13050000
13050000
13050000
13050000
13050000
13050000
13050000
13050000
nn*nnnn
SULFUR
REMOVED
POWER UNIT BY
FUEL POLLUTION
CON5UMPTICN. CONfRCL
TOKS COAL PROCESS,
/YEAR TONS/YEAR
2900COC 6770C
2900000 67700
2900000 67700
2900000 67700
_2.saaaaa_ uT.b.a
2900000
2900000
2900000
2900000
jqnnnnr
2071400
2071400
2071400
2071400
145000C
1450000
1450000
1450000
621400
621400
621400
621400
621400
621400
621400
621400
671400
67700
67700
67700
67700
6J7.OD
48300
48300
48300
48300
33800
33800
33800
33800
naaa
14500
14500
14500
14500
1&SQD
14500
14500
14500
14500
i&sna
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
SULFUR
65400
65400
65400
65400
65400
65400
65400
65400
6S400
467CO
46700
46700
46700
"•700
32700
32700
32700
32700
3,2200.-
14000
14000
14000
14000
1*0.0,0-
14000
14000
14000
14000
14DOO
TGT 127500 1109250000 5282100C 1232500 1191000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER PILLION BTl HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
lEVEHZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON CF CCAL BURNED
MILLS PER MLOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
NET REVENUE
t/TCJN
SULFUR
TOTAL
DP. COST
INCLUDING
, REGULATED
RDI FOR
POWER
COMPANY,
I/YEAR
40.00 47385600
40.00 46795200
40.00 46204800
40.00 45614400
40,00 <.<;n?&nin
40.00
40.00
40.00
40 .00
40.00
40.00
40.00
40.00
40.00
4n.no
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40 .00
40.00
40.00
40.00
40.00
44433600
438432)3
43252830
42662430
&20.31SD-0—
35466300
34875900
34285500
33695100
TOTAL
NET
SALES
REVENUE,
*/YEAR
2616000
2616000
2616000
2616000
_2jUL6.aaa_.
2616000
2616000
2616000
2616000
1X68000
1868000
1868000
1868000
ntftunnn
27905700 1308000
27315300 1308000
26724900 1308000
26134500 1308000
2.U4.4L13. ivmnnn
18550300
179599)3
17369400
16779039
15598200
15007800
14417430
13827000
i-*??i,i>aa
560000
560000
5600CO
560000
560000
560000
560000
560000
JfcOODO_
911214100 47640000
17.25 0.90
7.1$ 0.38
62.15 4.29
739.37 38.65
331089100 18571800
DISCOUNTED PROCESS COST OVER LIFE OF
16.08 0.90
6.66 0.37
76.57 4.29
689.05 38.65
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
44769600
44179200
43588800
42998400
41817600
41227200
4063680C
40046400
CUMULATIVE
NET INCREASE
(DECREASE )
IN COST OF
POWER,
*
4476 S600
88948800
132537600
175536000
259761600
300988800
341625600
381672000
4.2ii?7qnn
33598300 454726200
33007900 487734100
32417500 520151600
31827100 551978700
31216.1(10 5A3215AaO
26597700 609813100
26007300 635820400
25416900 661237300
24826500 68606 ?800
_2.42,36_1QQ_ 710?9
-------
TABLE A-91. CITRATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-1'iW new coal-fired power unit, 3.5% S in coal;
90% S02 removal)
7. of
total direct
Investment , $ investment
Direct Investment
Materials handling (unloading conveyor, elevator conveyor,
pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
S0? absorption (four packed tower absorbers including
presaturators and entralnment separators, strippers,
compressor, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheacers)
Chloride purge (feeder, tank, agitator, and pumps)
SO. reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
Sulfate purge (coolers, agitators, centrifuge, tanks,
pumps, and refrigeration)
H9S generation (battery limit plant)
H? generation (battery limit plant)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
845,000
143,000
4,093,000
12,285,000
1,283,000
97,000
1,188,000
2,930,000
839,000
36,210,000
2,173.000
38,383,000
2.2
0.4
10.7
31.9
3.3
0.3
3.1
7.6
2.2
2.8
16.4
13.4
94.3
5.7
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
3,463,000
866,000
5,161,000
1.535.000
11,025,000
9.881.000
59,289,000
9.0
2.3
13.4
4.0
28.7'
25.7
154.4
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable Investment
Land
Working capital
Total capital investment
5,929,000
7.115.000
72,333,000
39,000
2.252.000
74,624,000
15.4
18.6
188.4
0.1
5.9
194.4
Baeis
leis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Aver
basis for scaling, mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
• estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
age cost
230
-------
TABLE A- 92. CITRATE PROCESS
OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
REGULATED UTILITY ECONOMICS*
(500-11W new coal-fired power unit, 3.5% S in coal;
90% S02 removal)
Annual
quantity
Unit
cost, $
Total
annual
cost. $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Lime
Soda ash
Citric acid
Natural gas
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
3,260 tons
2,990 tons
259 tons
1,200,000 kft'
67,920 man-hr
42.00/ton
90.00/ton
1,340.00/con
3.50/kft5
12.50/man-hr
136,900
269,JOO
347,100
4,200,000
23.900
4,977,000
849,000
1,111,900 MBtu
2,812,000 kgal
68,613,000 kWh
10,600 man-hr
2.00/MBtu
0.06/kgal
0.029/kWh
1 7. OO/ man-hr
2,223,800
168,700
1,989,800
2,303,000
180,200
7,714,500
12,691,500
0.57
1.13
1.46
17.64
0.10
20.90
3.57
9.33
0.71
8.36
9.67
0.76
32.40
53.30
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 38,550 short tons
Subtotal byproduct sales revenue
Total average annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 6.80 15.87
4,340,000
6,417,700
1,666,100
84,900
154,200
12,662,900
25,354,400
40.00/short ton (1,542,000)
(1,542,000)
23,812,400
$/MBtu heat S/short ton
input S removed
0.76 598.30
18.23
26.94
7.00
0.36
0.65
53.18
106.48
(6.48)
(6.48)
100.00
S/short ton
S recovered
617.70
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 39,800 short tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $38,383,000; total depreciable investment, $72,333,000; and total capital
investment, $74,624,000.
231
-------
TABLE A-93
CITRATE PROCESS 500 NU NEW COAl-FIREO POWER UNIT 3.5% S IN CCAL 904 REHliVAL KEGULATED CD. ECONOMICS
FIXED INVESTMENT:
74624000
YEARS
AFTER
POWER
UNIT
START
I
2
3
4
6
7
8
9
11
12
13
_15
16
17
18
19
21
22
23
26
27
28
29
ANNUAL
OPERA-
TION,
KW-hR/
KU
7000
7000
7000
7000
7000
7000
7000
7000
7DOO
5000
5000
5000
5000
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
J5flO
POWER UNIT
HEAT
REQUIREMENT.
MILLION BTU
/YEAR
31500000
91500000
31500000
31500000
31500000
31500000
31500000
31500000
22500000
22500000
22500000
22500000
-225.0,0000-
15750000
15750000
15750000
15750000
6750000
6750000
6750000
6750000
6JS.aO.QQ
6750000
6750000
6750000
6750000
*>7^nr)00
SULFUR
REMOVED
POWER UNIT BY
FUEL POILUTIDK
CONSUMPTION, CONTROL
TONS COAL PROCESS,
/YEAR TONS/YEAR
1500COO
1500000
150000C
1500000
J;QQODO
1500000
1500000
1500000
1500COO
1500000
39800
39800
39800
39800
.39800
39800
39800
39800
39800
iQsnn
1071400 28500
1071400 28500
1071400 28500
1071400 28500
1Q21AQ.Q 24 5. 00
750000 19900
750COO 19900
750000 19900
750000 19900
75QI.O.O 19900
321400
321400
321400
321400
321400
321400
321400
321400
8500
8500
8500
8500
8500
8500
8500
8500
_fl5QD
BY-PROIUCT
RATF,
EQUIVALENT
Tf'NS/HFAR
SULFUR
3H500
3*500
3B500
3*500
38500
38500
3»500
38500
27500
27500
27500
27500
2J50U
19300
19300
19300
19300
i«on
8300
8330
8300
8300
B300
(300
8300
C300
TC'TAL
DP. COST-
INCIUDIVG
NET REVENUE, REGULATED
«-/Tl'N ROI FOR
POWER
COMPANY,
SULFUR t/YEAR
40.00
40 .30
4C.OO
40.00
&C.DQ.
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
40.00
ifl.JlO
40.00
40.00
40.00
40.00
31772300
31357630
30942900
305282DO
29698830
29284100
28869430
28454700
2fiO_3.3SQQ_
23896000
23481300
23066600
22651900
1«942900~
18528200
18113530
176988}]
12810600
12395950
11981200
11566500
LLLSLB11
40.30 10737130
40.00 10322400
40.00 9907700
40.00 94930}]
<.n.nn omn^jq
TOIAL
NET
SALES
REVENUE ,
S/YEAR
1540000
1540000
1540000
1540000
1540000
1540000
1540000
1540000
1100000
1100000
1100000
1100000
772000
772000
772000
772000
222000-
332000
332000
332000
332000
33 2 00. Q
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST DF IN COST OF
POWER, POWER,
1 I
30232300
29B17600
29402900
28988200
? 8573 5.00
20)58600
27744100
27329400
26914700
26499900
22796000
223H1300
21966600
21551900
2LL1Z20.0.
18170900
17756200
17341500
16926800
1.65.12100
12478600
12063900
11649200
11234500
i rtBiQfinn
30232300
60049900
89452800
11B441000
175173300
202917400
230246800
257161500
3064574(10
328838700
350835300
372357200
411665300
429421500
446763000
463689800
492680500
504744400
516393600
527628100
S3H647900
332000 10405100 54E853000
332000 9990400 558843400
332000 9575700 568419100
332000 9161000 577580100
132000. 8.246.300 5.66.326AOO
TOT 127500 573750000 21321COO 725000 702000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON DF COAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER PILLION BTU HEAT INPLT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
(14A06400 28080000 586326400
22.49
9.6*
107.09
847.46
222040100
1.03
0.44
4.90
36.73
10936300
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE DF
DOLLARS PER TO* CF COAL BURNED 20.85 1.03
MILLS PER KILOWATT-HLUR 8-94 0.44
CENTS PER MILLION BTU HEAT INPUT 99.26 4.89
DULLARS PER TON OF SULFUR REMOVED 785.70 38.69
21.46
9.20
102.19
808.73
211103frOO
POWER UNIT
19.82
8.50
94.39
747.01
-------
TABLE A-94. CITRATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW existing oil-fired power unit, 2.5% S in oil;
0.8 Ib S02/MBtu heat input allowable emission)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (pneumatic conveyor, feed storage bins)
Feed preparation (feeders, conveyor, tank, agitator, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO. absorption (four packed tower absorbers including
presaturators and entrainment separators, tanks, agitators.
and pumps)
Stack gas reheat (four direct oil reheaters)
SO reduction (reactor tanks, aging tank, agitators, and
centrifugal pumps)
S separation and removal (flotation tanks, rotary drum
filters, pumps, slurry tank, heat exchanger, settling
tank, heaters, flash drum, and compressor)
S storage and shipping (S receiving pit, heaters, S pump,
and storage tank)
pumps, and refrigeration)
H S generation (battery limit plant)
H- generation (battery limit plant)
2
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
230,000
76,000
3,656,000
10,865,000
726,000
678,000
1,642,000
456,000
561,000
3,728,000
2,616,000
25,234,000
1,514,000
26,748,000
2,529,000
632,000
3,825,000
1,167,000
8,153,000
6,980,000
41,881,000
4,188,000
5,026,000
51,095,000
39,000
1,308,000
52,442,000
0.9
0.3
13.7
40.6
2.7
2.5
6.1
1.7
2.1
13.9
9.8
94.3
5.7
100.0
9.5
2.4
14.3
4.4
30.6
26.0
156.6
15.6
18.8
191.0
0.1
5.8
196.9
a. Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost
basis for scaling, mid-1979.
Stack gas reheat to 175°F by direct oil reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for flyash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
233
-------
TABLE A-95. CITPvATE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS -
ft
REGULATED UTILITY ECONOMICS
(500-I1W existing oil-fired power unit, 2.5% S in oil;
0.8 Ib S02/MBtu heat input allowable emission)
Direct Costs
Raw materials
Soda ash
Citric acid
Natural gas
Total raw materials cost
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Electricity
Maintenance
Labor and material
Annual
quantity
1,160 tons
100 tons
462,800 kft3
64, 525 man-hr
2,676,600 gal
240,710 MBtu
1,178,900 kgal
48,688,000 kWh
Unit
cost f $
90.00/ton
1,340.00/ton
3.50/kft3
12.50/man-hr
0.40/gal
2.00/MBtu
0.06/kgal
0.029/kWh
Total
annual
cost , 5
104,400
134,000
1,619,800
9,300
l,867,iOO
806,600
1,070,600
481,400
70,700
1,412,000
1,604,900
171,700
5,617,900
7,485,400
% of average
annual revenue
requirements
0.65
0.83
10.07
0.06
11.61
5.01
6.65
2.99
34.92
46.52
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
,, , f _ 15,170 short tons
Sulfur
Subtotal byproduct sales revenue
Total average annual revenue requirements
S/bbl oil
Mills/kWh burned
Equivalent unit revenue requirements 4.60 3.02
3,270,100
4,510,000
1,291,600
80,700
60,700
9,213,100
16,698,500
40.00/short ton (606,800)
16,091,700
$/MBtu heat S/short ton
input S removed
0.50 1,042.88
20.32
28.02
8.03
0.50
0.38
57.25
103.77
(3.77)
100.00
$/short ton
S recoveied
1,060.76
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 25 yr.
Power unit on-stream time, 7,000 hr/yr.
Oil burned, 5,324,100 bbl/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
S removed, 15,430 shore tons/yr.
Investment and revenue requirement for removal and disposal of flyash excluded.
Total direct investment, $26,748,000; total depreciable investment, $51,095,000; and total capital
investment, $52,442,000.
234
-------
TABLE A-96
CITRATE PROCESS 500 MW EXISTING OIL-FIRED POWER UNIT 2.5« S IN OIL REGULATED CO. ECONOMICS
FIXED INVESTMENT: % 52*43000
U)
l-n
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED
HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
REQUIREMENT, CONSUMPTION. CONTROL POWER
MILLION 8TU BARRELS OIL PROCESS. COMPANY.
/YEAR /YEAR TONS/YEAR SULFUR SULFUR S/YEAR
TOTAL
NET
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
1
2
3
4
6 7000
7 7000
8 7000
9 7000
10 7QOD
32200000 5324100 15400
32200000 5324100 15400
32200.000 5324100 15*00
32200000 5324100 15400
32200000 5324100 15400
11 5000 23000000 3802900 11000
12 5000 23000000 3802900 11000
13 5000 23000000 3802900 11000
14 5000 23000000 3802900 11000
.15 50.0.0 23flflftflM 2fi022IiQ LLOOfl
16 3500 16100000 2662000 7700
17 3500 16100000 2662000 7700
18 3500 16100000 2662000 7700
19 3500 16100000 2662000 7700
29 _25fla 16100000 2662000 7700
21 1500
22 1500
23 1500
24 1500
25 15PO
26 1500
27 1500
28 1500
29 1500
3ft _15DP.
TOT 92500
LIFETIME
PROCESS COST
LEVELIZED
6900000 1140900 3300
6900000 1140900 3300
6900000 1140900 3300
6900000 1140900 3300
6200DQO 114B9QQ. 33PO
6900000 1140900 3300
6900000 1140900 3300
6900000 1140900 3300
6900000 1140900 3300
69POPQO 11*0900 33PO
425500000 70354000 203500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11. 6« TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EO
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
15200
15200
15200
15200
10800
10800
10800
10800
7600
7600
7600
7600
I6M
3300
3300
3300
3300
3300
3300
3300
3300
aaaa
201000
COST
UIVALENT TO D
40.00 21207900
40.00 20856*00
40.00 20504900
40.00 20153300
*fl.QQ 198(11800
*0.00
40.00
40.00
40.00
40*0.0.
40.00
40.00
40.00
40.00
*fl«0ft
40.00
40.00
40.00
40.00
4QfOQ
40.00
40.00
40.00
40.00
-40*00.
ISCOUNTED
17248700
16897100
165*5600
J61-M100
13775600
13424100
13072500
12721000
1236.95.00
9560200
9208700
8857200
8505600
608000
608000
608000
608000
_6.aaooo_.
432000
432000
432000
432000
.41200.0.
304000
304000
304000
304000
_204QJUL,.
132000
132000
132000
132000
132000
7802600 132000
7451000 132000
7099500 132000
67*8000 132000
639.6.40P. 132000
330398300
*.70
7.1*
77.65
1623.58
1350*7900
PROCESS COST OVER
*.2*
6.44
70.0*
1464.73
8040000
0.12
0.17
1.69
39.51
3637700
LIFE OF
0.12
0.17
1.88
39.46
20599900
20248*00
19896900
195*5300
-_12123flOO_
16816700
16*65100
16113600
15762100
15*.i05QP.
13*71600
13120100
12768500
12*17000
12Q65.500
9*28200
9076700
8725200
8373600
8022100
7670600
7319000
6967500
6616000
6264*00
322358300
4.58
6.97
75.76
1584.07
131410200
POWER UNIT
4.12
6.27
68.16
1425.27
20599900
408*8300
607*5200
80290500
224&43.00
U6301000
132766100
148879700
164641800
Lftamaao
193523900
206644000
219412500
231829500
2.43895000
253323200
262399900
271125100
279498700
287520800
295191400
302510400
309*77900
316093900
3223583PO
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-79-177
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Definitive SOx Control Process Evaluations:
Limestone, Double Alkali, and Citrate FGD
Processes
5. REPORT DATE
August 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
S.V.Tomlinson, F.M.Kennedy, F.A.Sudhoff, and
_R. L.Torstrick
8. PERFORMING ORGANIZATION REPORT NO.
ECDP B 4
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TVA, Office of Power
Emission Control Development Projects
Muscle Shoals, Alabama 35660
10 PROGRAM ELEMENT NO.
INE-624A
11. COM "ACT/GRANT NO.
EPA-IAG-D9-E721-BI and
TV-41967A
2. 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
Phase I; 1/78 - 3/79
14. SPONSORING AGENCY CODE
EPA/600/13
. SUPPLEMENTARY NOTES IERL-RTP project officer is Charles J. Chatlynne, Mail Drop 61,
919/541-2915.
16 ABSTRACT The report gives results of a detailed comparative technical and economic
evaluation of limestone slurry, generic double alkali, and citrate flue gas desulfuri-
zation (FGD) processes, assuming proven technology and using representative power
plant, process design, and economic premises. For each process, economic projec-
tions were made for abase case (500 MW, 3. 5% sulfur coal, new unit) and case var-
iations in power unit size, fuel type, sulfur in fuel, new and existing power units,
waste slurry ponding and filter cake trucking, and SO2 removal (1.2 Ib SO2 allowable
emission per million Btu heat input vs 90%). Depending on unit size and status, fuel
type and sulfur content, solids disposal method, and overall project scope, ranges
in estimated capital costs in 1979 dollars are $71 to $127/kW for limestone slurry,
^80 to $130/kW for generic double alkali, and $105 to $194 AW for citrate (recovery
process). Results can be scaled or altered to reflect other site-specific conditions.
Capital investment, annual revenue requirements (7000 hr/yr), and lifetime revenue
requirements over a 30-year declining operating profile were estimated for the base
case and each variation. Investment costs were projected to mid-1979; annual reve-
nue requirements were calculated in projected mid-1980 dollars. Effects of variations
in various cost parameters were studied.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Pollution
Evaluation
Coal
Combustion
Flue Gases
Desulfurization
Sulfur Oxides
Limestone
Slurries
Citrates
Waste Disposal
Ponds
Pollution Control
Stationary Sources
Double Alkali Process
Trucking
13 B
14B
21D
21B
07B
08G
11G
07C
07A,07D 08H
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
236
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