EPA
TVA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-80-OO1
January 1980
Tennessee Valley
Authority
Office of Power
Emission Control
Development Projects
Muscle Shoals AL 35660
ECDP B-7
Definitive SOx Control
Process Evaluations:
Limestone, Lime, and
Magnesia 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-600/7-80-001
TVA ECDP B-7
January 1980
Definitive SOx Control
Process Evaluations:
Limestone, Lime,
and Magnesia FGD Processes
by
K.D. Anderson, J.W. Barrier,
W.E. O'Brien, and S.V. Tomlinson
TVA, Office of Power
Emission Control Development Projects
Muscle Shoals, Alabama 35660
EPA-IAG-D9-E721-BI and TV-41967A
Program Element No. INE624A
EPA Project Officer: C.J. Chatlynne
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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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. Environ-
mental 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 endorse-
ment or recommendation for use.
ii
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ABSTRACT
Updated economic evaluations and ground-to-ground energy evalua-
tions of the limestone slurry, lime slurry, and magnesia (producing
sulfuric acid) flue gas desulfurization (FGD) processes were made. The
lime slurry process was evaluated using purchased lime and lime calcined
onsite. The lime slurry process remains lower in capital investment
(90 $/kW for the base-case 500-MW power plant burning 3.5% sulfur coal)
than the limestone slurry process (98 $/kW). The limestone slurry
process remains lower in annual revenue requirements (4.02 mills/kWh)
than the lime slurry process (4.25 mills/kWh). The magnesia process is
about one-third higher in capital investment (132 $/kW) and one-fourth
higher in annual revenue requirements (5.05 mills/kWh including credit
for acid sales) compared to the limestone slurry process, because of the
complexity of the absorbent-recovery and acid-producing areas. The lime
slurry process using purchased lime is more economical than the limestone
slurry process at low absorbent consumption rates (below about 200 MW or
about 2% sulfur coal). Onsite lime calcination becomes economical
compared to purchased lime for larger power plants and higher coal
sulfur levels (about 1,000 MW with 3.5% sulfur coal, 750 MW with 5%
sulfur coal). The limestone slurry process has the lowest overall (raw
material, FGD, and disposal) energy requirements, 15,000 Btu/lb sulfur
removed, compared to 20,000 for the lime slurry process, and 21,000 for
the magnesia process. The overall energy requirements for the magnesia
process are only 45% higher than the limestone process (compared to 90%
for FGD energy alone) because of the low raw material consumption and a
credit for replacement of commercial acid with FGD acid.
iii
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CONTENTS
Abstract 11:L
Figures vii
Tables x
Abbreviations and Conversion Factors xiii
Executive Summary xv
Introduction 1
Process Background .... 3
Limestone-Lime Slurry Processes 3
Magnesia Scrubbing - Regeneration 7
Design, Economic, and Energy Premises 9
Design Premises 9
Emission Standards 9
Fuels 10
Power Plant Design 10
Power Plant Operation 12
Flue Gas Composition 13
Scrubber Design 14
Reheat 17
Raw Materials 17
Waste Disposal 17
Case Variations 17
Economic Premises 18
Capital Costs 19
Contingency 21
Other Capital Charges 21
Land 21
Working Capital 21
Annual Revenue Requirements 22
Energy Premises 25
Transportation Energy 25
Limestone 26
Lime Calcination 26
Magnesia From Magnesite 26
Magnesia From Seawater 27
Byproduct Sulfuric Acid Energy Credit 27
Systems Estimated 28
Limestone Slurry Process 28
Major Process Areas 33
Storage Capacity 33
Solids Disposal 34
Pond Construction 34
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Limestone Production 34
Lime Slurry Process 34
Major Process Areas 49
Storage Capacities 49
Solids Disposal 56
Lime Production 56
Storage Capacities 60
Magnesia Process 60
Major Process Areas 80
Storage Capacity 89
Magnesia Production 89
Magnesia From Magnesite 90
Major Process Areas 90
Magnesia From Seawater 94
Major Process Areas 94
Economic and Energy Evaluation and Comparison 99
Capital Investment 99
Base Case 104
Case Variations 109
Annual Revenue Requirements 113
Case Variations 123
Variations in Economic Factors 127
Lifetime Revenue Requirements 132
Alternate Particulate Removal and Waste Disposal Comparison . . 149
Energy Evaluation and Comparison 150
Mining, Separation, and Sizing 152
Absorbent Processing 152
Transportation 152
Cumulative Energy Requirements for Delivered Absorbents .... 155
FGD Process Battery Limits 157
Byproduct Disposal 157
Byproduct Sulfuric Acid Energy Credit 160
Total Ground-to-Ground Energy Requirements 160
Conclusions 163
Capital Investment 163
Annual Revenue Requirements 164
Energy Requirements 165
Process Development 166
References 167
Appendix
A. Total Capital Investment, Average Annual Revenue Requirement,
and Lifetime Revenue Requirement Tables - All Processes and
Case Variations 171
VI
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FIGURES
Number Page
S-l Total energy requirement per pound of sulfur removed.
Base case xxvi
1 Limestone slurry process. Base-case flow diagram .... 29
2 Limestone slurry process. Base-case overall plot plan . 30
3 Limestone slurry process. Mobile-bed scrubber system
base-case plan and elevation 31
4 Limestone slurry process. Base-case control diagram . . 32
5 Pond construction diagram 42
6 Limestone mining and processing flow diagram 44
7 Lime slurry process. Base-case flow diagram 45
8 Lime slurry process. Base-case overall plot plan .... 46
9 Lime slurry process. Mobile-bed scrubber system
base-case plan and elevation 47
10 Lime slurry process. Base-case control diagram 48
11 Lime from limestone. Base-case flow diagram 58
12 Lime from limestone. Base-case control diagram 59
13 Lime from limestone. Base-case plan and elevation ... 61
14 Magnesia process. Base-case flow diagram 68
15 Magnesia process. Base-case control diagram 69
16 Magnesia process. Base-case overall plot plan 70
17 Spray grid tower absorber system. Base-case plan and
elevation 71
18 Magnesia process. Base-case plot plan - regeneration
and acid production area 73
19 Magnesia process. Regeneration area elevation 74
20 Magnesia process. Base-case acid plant plan 75
21 Magnesia process. Base-case acid plant elevation .... 76
22 Magnesia from magnesite. Flow diagram 91
23 Magnesia from seawater. Flow diagram 95
24 All processes. Effect of power unit size on capital
investment: new coal-fired units 110
25 All processes. Effect of power unit size on unit invest-
ment cost, $/kW: new coal-fired units Ill
26 All processes. Effect of sulfur content of coal on unit
investment cost, $/kW: new 500-MW coal-fired units . . . 112
27 All processes. Effect of power unit size on annual
revenue requirements: new coal-fired units 124
28 All processes. Effect of sulfur content of coal on
annual revenue requirements: new 500-MW coal-fired
units 125
29 All processes. Effect of power unit size on average unit
operating cost, $/ton of coal burned: new 500-MW coal-
fired units 126
30 Limestone slurry process. Effect of power unit size
and variations in operating labor cost on annual revenue
requirements: new coal-fired units 129
vii
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FIGURES (continued)
Number Page
31 Lime slurry process. Effect of power unit size and
variations in operating labor cost on annual revenue
requirements: new coal-fired units 130
32 Magnesia and limestone processes. Effect of sulfur in
coal and variations in operating labor cost on annual
revenue requirements: new 500-MW units 131
33 Lime slurry process with onsite calcination. Effect of
power unit size and variations in maintenance cost on
annual revenue requirements: new coal-fired units .... 133
34 Magnesia process. Effect of sulfur in coal and variations
in maintenance cost on annual revenue requirements: new
500-MW units 134
35 Magnesia process. Effect of power unit size and variations
in capital charges on annual revenue requirements: new
coal-fired units 135
36 Magnesia process. Effect of sulfur in coal and variations
in capital charges on annual revenue requirements: new
500-MW units 136
37 Magnesia process. Effect of power unit size and variations
in sulfuric acid price on total annual income from byprod-
uct sales: new coal-fired units 137
38 Magnesia process compared with limestone. Effect of power
unit size and variations in sulfuric acid sale price on
annual revenue requirements: new coal-fired units .... 138
39 Magnesia process. Effect of sulfur in coal and variations
in sulfuric acid price on total annual income from byprod-
uct sales: new 500-MW units 139
40 Magnesia process compared with limestone. Effect of
sulfur in coal and variations in sulfuric acid price on
annual revenue requirements: new 500-MW units 140
41 Limestone slurry prqcess. Effect of power unit size and
variations in limestone price on annual revenue require-
ments: new coal-fired units 141
42 Lime slurry process with onsite calcination and limestone
slurry process. Effect of sulfur in coal and variations
in limestone price on annual revenue requirements: new
500-MW units 142
43 Lime slurry process with onsite calcination. Effect of
power unit size and variations in limestone price on
annual revenue requirements: new coal-fired units .... 143
44 Lime slurry process. Effect of power unit size and varia-
tions in lime price on annual revenue requirements: new
coal-fired units 144
45 All processes. Effect of power unit size on levelized
unit revenue requirements: new coal-fired units 147
46 All processes. Effect of sulfur in coal on levelized unit
revenue requirements: new 500-MW units 148
viii
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FIGURES (continued)
Number
47 Total energy requirement per pound of sulfur removed.
Base case 151
48 Mining, separation, and sizing energy requirements per
ton of absorbent 153
49 Mining, separation, and sizing energy requirements per
pound sulfur removed. Base case 153
50 Absorbent processing energy requirements per ton of
absorbent production 154
51 Transportation energy requirements per ton of absorbent . 154
52 Total energy requirements per ton of absorbent 156
53 Absorbent processing energy requirements per pound sulfur
removed. Base case 158
54 Transportation energy requirements per pound sulfur
removed. Base case 158
55 FGD energy requirements per pound of sulfur removed.
Base case 159
ix
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TABLES
Number
S-l Summary of Total Capital Investment Requirements .... xx
S-2 Summary of Average Annual Revenue Requirements
(Including Byproduct Credit) xxi
S-3 Absorbent Preparation Energy Requirements xxiv
S-4 Energy Required for Production of Sulfuric Acid From
Sulfur xxiv
S-5 Ground-To-Ground Energy Requirements Assessment - Btu/lb
Sulfur Removed xxv
1 Status of FGD Systems in the U.S. in September 1979 ... 5
2 Lime and Limestone Systems in Operation in the U.S. -
September 1979 6
3 Required Removal Efficiencies 10
4 Coal Compositions and Flow Rates at Varying Sulfur
Levels 11
5 Oil Composition and Flow Rate 11
6 Assumed Power Plant Capacity Schedule 12
7 Power Unit Input Heat Requirements 12
8 Calculated Base-Case Flue Gas Composition and Flow Rate . 13
9 Flue Gas Compositions for Power Units Without Emission
Control Facilities 14
10 Power Plant Flue Gas and SO Rates 15
11 Scrubber Operating Conditions 16
12 Relative Quantities of Gas and Sulfur To Be Processed
in Comparison With the Base-Case Quantities 19
13 Cost Indexes and Projections 20
14 Projected 1980 Unit Costs for Raw Materials, Labor, and
Utilities 22
15 Estimated Overall Annual Maintenance Costs 23
16 Annual Capital Charges for Power Industry Financing ... 24
17 Limestone Slurry Process - Material Balance 35
18 Limestone Slurry Process - Base-Case Equipment List
Description and Cost 37
19 Limestone Slurry Process - Acreage Required for Waste
Solids Disposal 43
20 Lime Slurry Process - Material Balance 50
21 Lime Slurry Process - Base-Case Equipment List Descrip-
tion and Cost 52
22 Lime Slurry Process - Acreage Required for Waste Solids
Disposal 57
23 Lime From Limestone - Material Balance 62
24 Lime From Limestone - Base-Case Equipment List Descrip-
tion and Cost 63
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TABLES (continued)
Number Page
25 Magnesia Slurry - Regeneration Process - Material
Balance 77
26 Magnesia Slurry - Regeneration Process - Base-Case Equip-
ment List Description and Cost 81
27 Magnesia From Magnesite - Major Equipment List and Horse-
power 92
28 Magnesia From Magnesite - Material Balance 93
29 Magnesia From Seawater - Material Balance 96
30 Magnesia Production From Seawater - Major Equipment List
and Horsepower 98
31 Limestone Slurry Process - Total Capital Investment
Summary 100
32 Lime Slurry Process - Total Capital Investment Summary 101
33 Lime Slurry Process With Onsite Calcination - Total Capital
Investment Summary 102
34 Magnesia Process - Total Capital Investment Summary 103
35 Limestone Slurry Process Base Case - Area Process Equipment
and Installation Costs (k$) 105
36 Lime Slurry Process Base Case - Area Process Equipment and
Installation Costs (k$) 106
37 Lime Slurry Process With Onsite Calcination Base Case - Area
Process Equipment and Installation Costs (k$) 107
38 Magnesia Process Base Case - Area Equipment and Installation
Costs (k$) . 108
39 Limestone Slurry Process - Total Annual Revenue Requirements
Summary 114
40 Lime Slurry Process - Total Annual Revenue Requirements
Summary 115
41 Lime Slurry Process With Onsite Calcination - Total Annual
Revenue Requirements Summary 116
42 Magnesia Process - Total Net Annual Revenue Requirements
Summary 117
43 Limestone Slurry Process Base Case - Annual Revenue Require-
ments Direct Costs 118
44 Lime Slurry Process Base Case - Annual Revenue Requirements
Direct Costs 119
45 Lime Slurry Process With Onsite Calcination - Annual Revenue
Requirements Direct Costs 120
46 Magnesia Process Base Case - Annual Revenue Requirements
Direct Costs 121
47 Sensitivity Variations Studied in the Economic Cost Projec-
tions 128
48 Comparison of Cumulative Lifetime Discounted Process Costs
for Different S02 Removal Levels 145
49 Magnesia Process - Lifetime Sulfuric Acid Production and
Credit 146
xi
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TABLES (continued)
Number
50 Case Variations for Magnesia Process Wet Particulate
Scrubbing and Limestone Process Waste Fixation and Landfill
Disposal 149
51 Absorbent Energy Requirements 155
52 FGD Energy Allotment 157
53 Energy Required for Production of Sulfuric Acid From Sulfur . . . 161
54 Ground-To-Ground Energy Requirements Assessment - Btu/lb
Sulfur Removed 161
xii
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ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
ac
aft /min
bbl
Btu
°F
dia
FGD
gal
gpm
gr
hp
hr
in.
k
kW
acre kWh
actual cubic feet per Ib
minute L/G
barrel
British thermal unit
degrees Fahrenheit
diameter M
flue gas desulfurization mi
feet mo
square feet MW
cubic feet ppm
gallon psig
gallons per minute rpm
grain sec
horsepower sft^/min
hour
inch SS
thousand yr
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
xiii
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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/ft grains per cubic foot 2.288
hp horsepower 0.746
in. inches 2.54
Ib pounds 0.4536
Ib/ft 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
sft /min standard cubic feet per 1.6077
minute (60°F)
ton tons (short)b 0.9072
ton, long tons (long)b 1.016
ton/hr tons per hour 0.252
hectare ha
liters I
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 fc/sec
grams g
grams per cubic meter g/m
kilowatts kW
centimeters cm
kilograms kg
kilograms per cubic meter kg/m
grams per second g/sec „
Pascals (Newton per square meter) pa (N/m )
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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EXECUTIVE SUMMARY
As a part of the flue gas desulfurization (FGD) studies sponsored
by the U.S. Environmental Protection Agency, the Tennessee Valley
Authority has conducted a series of economic evaluations based on
conceptual designs of FGD processes. These studies are based on prem-
ises which permit equitable economic comparisons between processes. The
studies of some processes are refined and updated as the technologies of
the processes develop. This study updates the limestone, lime, and
magnesia scrubbing processes previously evaluated in 1973 and 1975. It
is the second part of a three-part study of current FGD technology. The
first part has been published and the third part is being prepared.
Since the earlier studies many full-scale applications of the limestone
and lime processes have been placed in operation. The magnesia process
has been further refined and has been evaluated to some extent in full-
scale application. The processes represent the state of technology in
mid-1979. For the lime process the economics of onsite calcination are
also compared with the economics of a process using purchased lime.
A ground-to-ground energy requirement assessment is also included.
The assessment consists of a determination of raw material mining,
processing, and transportation energy requirements in addition to FGD
energy requirements. For the magnesia process an energy credit for the
byproduct sulfuric acid produced is also included. Also, the difference
in energy requirements between the magnesia process and the lime and
limestone slurry processes (the energy penalty for making acid) is com-
pared with the energy required to make acid in a conventional acid plant.
PROCESS BACKGROUND
The limestone and lime slurry processes are similar in design and
function. The flue gas is scrubbed with a recirculating slurry of
finely ground limestone or lime to produce a mixture of calcium sulfite
and calcium sulfate salts. In the simplest form of the process a purge
stream of slurry is pumped to a disposal pond where it settles to a
semisolid sludge. The lime slurry process has a more reactive and
efficient scrubbing slurry at the expense of a more costly absorbent.
Most U.S. FGD processes are variations of limestone or lime processes
because of their simplicity and relatively advanced technical develop-
ment. A major disadvantage is the large volume of intractable waste
produced.
xv
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The magnesia process scrubbing system is similar to the limestone
and lime systems. Magnesium oxide (MgO) is used as the absorbent. The
highly reactive MgO provides an efficient scrubbing medium and is expected
to reduce scaling and plugging problems. The high cost of the MgO
necessitates its recovery, however. The scrubber purge of magnesium
sulfite and sulfate is centrifuged, dried, and calcined to produce MgO,
which is reused, and sulfur dioxide (S0?), which is processed to sulfuric
acid. The magnesia process thus produces a salable product and eliminates
major waste disposal problems, but requires a costly and complicated
regeneration and acid manufacturing system. Control of impurities in
the closed-cycle MgO regeneration loop also requires additional pre-
scrubbing equipment. The magnesia process has been evaluated in three
full-scale U.S. applications and other systems are planned.
PREMISES
The premises used in this study were developed by TVA and EPA to
provide an equitable basis for economic comparisons of FGD processes.
Conditions for the base case are representative of typical power-industry
conditions. Case variations are used to determine the sensitivity of
costs to variations in conditions. All FGD costs, including waste
disposal or acid manufacture, are included. A sales credit for byprod-
uct acid is also included.
Design Premises
For the base-case conditions a new, 500-MW Midwestern power plant
with an operating lifetime of 30 years and a declining operating schedule
totaling 127,500 hours is used. The heat rate is 9,000 Btu/kWh. The
base-case fuel is a typical Eastern U.S. coal with 3.5% sulfur and 16%
ash and a heating value of 10,500 Btu/lb, as fired. It is assumed that
80% of the ash and 95% of the sulfur is emitted with the flue gas. Fly
ash and SCL control systems are assumed to remove fly ash and S(X, to
meet the new-source performance standards (NSPS) that were in ef5fct
when this study was begun (0.1 and 1.2 Ib/MBtu, respectively). The FGD
system is assumed to begin downstream from the boiler electrostatic
precipitators and induced-draft fans, which are not included in the FGD
costs. The flue gas is fed to parallel scrubber trains from a common
plenum. Two trains are used for the 200-MW power plant and four^trains
for the 500- and 1000-MW power plants. Each train is equipped with a
forced-draft (relative to the FGD units) fan and provisions for reheat
to 175°F. Indirect steam reheat is used for coal-fuel cases and direct
oil-fired reheat is used for the oil-fuel case. No bypass or redundancy
provisions are provided.
Scrubber design is based on TVA experience, power-industry operating
experience, and process vendor information. The designs are generic,
representing most-proven technology rather than a particular installa-
tion, and they are sized and costed as fully developed and proven units.
xvi
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Case variations consist of 200- and 1000-MW power plant sizes,
existing power plants, coal with 2% and 5% sulfur, and oil with 2.5%
sulfur.
Economic Premises
The economic premises are divided into capital investment costs and
first-year annual revenue requirements. Cost information is based on
engineering firm and vendor information, TV A data, and published sources.
Cost projections are based on Chemical Engineering cost indices. The
premises are based on regulated-utility economics with a 60% debt - 40%
equity capital structure.
Capital investment costs are divided into direct costs, indirect
costs, land, and working capital. The costs are projected to mid-1979,
representing a mid-1977 to mid-1980 construction period with 50% expendi-
ture by mid-1979. Direct capital costs cover process equipment, piping
and insulation, transport lines, foundations and structural, excavation
and site preparation, roads and railroads, electrical equipment, instru-
mentation, buildings, and trucks and earthmoving equipment. These
estimates are based on costs obtained from vendors and on related litera-
ture information.
Indirect capital costs consist of engineering design and super-
vision, architect and engineering contractor expenses, construction
expenses, contractor fees, contingency, allowance for startup and modi-
fications, and interest during construction. Working capital and land
costs are included as separate entries. These estimates are based on
current industry practice and authoritative literature sources.
Annual revenue requirements are based on a first-year operating
schedule of 7,000 hours. The costs are projected to mid-1980. In
addition, lifetime revenue requirements are included for the three power
plant sizes with both declining and constant operating schedules.
Revenue requirements are divided among direct costs for raw materials,
labor, utilities, equipment fuel and maintenance, and analyses and
indirect costs for capital charges and overheads.
Energy Premises
The reference datum for the ground-to-ground energy assessment is a
hypothetical total-available-energy reservoir. All energy withdrawn
from this reservoir to meet FGD requirements, including raw material
production, is included in the assessment. In addition, an energy
credit for byproduct sulfuric acid is assigned to the magnesia process.
The byproduct acid replaces acid that would have otherwise been produced
by conventional methods, for which energy would have been withdrawn from
the hypothetical reservoir. The energy consumptions are based on data
obtained on typical commercial operations for quarrying, mining, and
processing of the raw materials used. All energy requirements for
xvii
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explosives, diesel fuel, and drying and calcining fuel are converted to
Btu per pound of raw material and Btu per pound of sulfur removed. The
energy credit is based on sulfuric acid produced from Frasch sulfur.
PROCESS DESCRIPTIONS
The limestone slurry process uses a mobile-bed absorber with a pre-
saturator using absorber slurry and a chevron mist eliminator on the
absorber outlet. The flue gas is cooled to about 130°F in the presatu-
rator. The absorbent consists of a 15% solids slurry of 70% minus 200
mesh limestone prepared onsite by crushing and ball-milling limestone.
The stoichiometry is 1.3 mols of calcium carbonate (CaCO,) per mol of
sulfur removed and the liquid to gas (L/G) ratio is 50 gallons per 1,000
cubic feet. The absorber waste, consisting of a bleedstream from the
absorber recirculation loop, is pumped to an earthen-diked, clay-lined
pond one mile from the FGD facilities. The waste settles to a 40%
solids sludge and the supernatant is returned to the FGD system.
The limestone used is assumed to be obtained locally in a quarrying
operation involving stripping, blasting, and quarry-site sizing and
grading. The material delivered to the power plant is 95% CaCO,, 0 x
1-1/2 inch crushed limestone.
The lime process uses identical scrubbing and waste disposal systems.
The equipment and pond are sized for the more reactive chemistry of lime
and a stoichiometry of 1.05 mols of calcium oxide (CaO) per mol of
sulfur removed. The L/G ratio is 45 gallons per 1,000 cubic feet. The
absorbent is a 15% solids slurry of slaked lime prepared onsite from
pebble lime.
For the onsite calcination process a coal-fired (oil-fired for the
oil-fuel case variation) calciner sized for the FGD requirements is
located adjacent to the FGD unit. The calciner supplies pebble lime to
the FGD system, which is otherwise identical to the process using pur-
chased lime.
The magnesia process uses a spray grid column for the absorber and
a venturi scrubber for chloride control in place of the presaturator.
Chevron mist eliminators are used on both the scrubber and absorber.
The chloride scrubber uses absorber liquid and freshwater. The chloride
scrubber waste stream is neutralized with limestone and pumped to the
ash pond. The spray grid column uses a 15% solids slurry of MgO as the
absorbent at a stoichiometry of 1.05 mols of MgO per mol of sulfur
removed and an L/G ratio of 10 gallons per 1,000 cubic feet.
The spent slurry from the absorber, containing magnesium sulfite
(MgSO ) as the major component, is centrifuged to 85% solids, dried in
an oil-fired dryer, and calcined in a fluid-bed reactor. The MgO is
returned to storage and the S02 is processed to sulfuric acid.
xviii
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The magnesia used in the process can be produced by calcination of
magnesite (MgCO.), which is mined at a single U.S. location, or by
treatment of dolomite [MgCa(CCL) ~] with seawater followed by calcination.
For the ground-to-ground energy evaluation, both processes are included.
RESULTS
Summaries of capital investment and annual revenue requirements for
all cases estimated are given in Tables S-l and S-2, respectively.
Capital Investment
In order of increasing investment, the base-case ranking by increasing
cost is (1) lime, (2) limestone, (3) lime with onsite calcination, and
(4) magnesia. The magnesia process capital investment requirements are
45% greater than those for lime. The lime process has a lower capital
investment than the limestone process because it requires less feed
preparation, has smaller slurry handling equipment, and a smaller waste
disposal pond. The capital investment advantages for the lime slurry
process are more than offset by the additional materials handling and
calcining equipment required with onsite calcination.
The higher capital requirements for the magnesia process are a
direct result of the relative complexity of the system. Regeneration of
the spent magnesia, including processing, drying, and calcination requires
a capital investment of almost $9 million. The recovery system also
requires chloride removal prior to the SO- absorber, necessitating
another $5 million for chloride scrubbing. Sulfuric acid production,
storage, and shipping increases costs another $7 million. These capital
requirements of approximately $21 million exceed by over $14 million the
savings resulting from the elimination of sludge ponding. (Limestone
slurry pond construction and waste disposal direct costs are under $7
million and those for lime slurry are slightly over $6 million.)
The capital investments for the waste-producing processes increase
with power plant size less rapidly than the capital investment of the
magnesia process. The more equipment-intensive magnesia process has
less economy of scale.
There-is a slightly greater rate of increase in capital investment
for the magnesia process with higher sulfur coal than for the waste-
producing processes. This is also due to the extensive equipment
requirements for the magnesia process.
As also has been shown in previous studies, the effect of 90% SCL
removal on capital investment, compared with the base-case 79% removal,
is slight (3% to 4%) for all processes studied.
xix
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TABLE S-l. SUI-C1ARY OF TOTAL CAPITAL INVESTMENT REQUIREMENTS
x
X
Lime process with
Limestone process Lime process onsite calcination
Years
remaining
Case life
Coal-Fired Power Unit
Total capital
investment,
$
Total capital
investment ,
$/kW $
Total capital
investment,
$/kW $ $/kW
Magnesia process
Total capital
investment ,
$
$/kW
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 25,121,000 126 22,758,000 114 28,292,000
200 MW N 3.5% sulfur 30 25,529,000 128 22,798,000 114 28,371,000
500 MW E 3.5% sulfur 25 50,406,000 101 46,446,000 93 55,039,000
500 MW N 2.0% sulfur 30 39,848,000 80 36,947,000 74 43,407,000
500 MW N 3.5% sulfur 30 48,943,000 98 45,319,000 90 53,860,000
500 MW N 5.0% sulfur 30 54,797,000 110 50,293,000 101 61,187,000
1,000 MW E 3.5% sulfur 25 75,075,000 75 71,098,000 71 82,812,000
1,000 MW N 3.5% sulfur 30 71,730,000 71 67,654,000 68 79,667,000
142 35,119,000
142 34,439,000
110 66,837,000
87 53,703,000
108
122
83
80
65,911,000
75,805,000
103,641,000
101,353,000
175
172
134
108
132
152
104
101
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur
30
50,649,000
101
46,909,000
94
55,910,000
112 68,620,000
137
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur
25
38,636,000
77
35,811,000
72
42,391,000
85 42,635,000
85
Basis
Midwest plant location represents project beginning mid-1977, ending raid-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.
-------
X
X
TABLE S-2. SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS
(INCLUDING BYPRODUCT CREDIT)
Lime process with
Case
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.57; sulfur
200 MW N 3.52 sulfur
500 MW E 3.57. sulfur
500 MW K 2.02 sulfur
500 MW N 3.5% sulfur
500 MW N 5.07. sulfur
1,000 MW E 3.5X sulfur
1,000 MW N 3.57. sulfur
Years
remain ing
life
20
30
25
30
30
30
25
30
Limestone
Average annual
revenue
requirements ,
s
7,469,000
7,147,200
14,771,500
11,637,200
14,082,600
15,898,600
23,122,300
21,761,300
process
Lime
process
Average annual
Mills/kWh
5.34
5.11
4.22
3.32
4.02
4.54
3.30
3.11
revenue
tequirements
$
7,591,000
7,213.200
15,518,400
11,710,600
14,887,700
17,372,400
25,387,500
23,916,100
,
Mills/kWh
5.42
5.15
4.43
3.35
4.25
4.96
3.63
3.42
onsite calcination
Average annual
revenue
requirements ,
$
8,429,400
8,022,800
16,194,900
12,601,100
15,558,500
17,836,300
25,456,200
24,125,800
Mills/kWh
6.02
5.73
4.63
3.60
4.45
5.10
3.64
3.45
Magnesia
Average annual
revenue
requ irements ,
S
9,808,300
9,273,500
18, 312, ROD
14,663,200
17,787,900
20,407,500
28,812,300
27, 738,500
process
Mills/kWh
7.01
6.62
5.23
4.19
5.08
5.83
4.12
3.96
90% SC>2 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur
30
14,557,400
4.15
15,593,800
4.46
16,161,800
1.62
18,473,700
5.2
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
Allowable emission; onsite
solids disposal (ponding)
500 MW E 2.Yf, sulfur
11,557,700
3.30
11,576,000
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.
Byproduct credit, S25/ton H^SO/,
3.31
12,793,100
3.66
12,177,600
-------
Annual Revenue Requirements
For base-case conditions the ranking of annual revenue requirements
in order of increasing cost is: (1) limestone, (2) lime, (3) lime with
onsite calcination, and (4) magnesia. The magnesia process revenue
requirements include a credit of $25 per ton for the sale of byproduct
sulfuric acid. The limestone revenue requirements are lower than those
of the lime process despite its higher capital investment, primarily
because of the lower raw material cost (0.32 mill/kWh for limestone and
0.82 mill/kWh for lime).
Fuel oil cost for calcination is the largest element of utility
costs (0.72 mill/kWh of the total 1.52 mills/kWh) of the magnesia process,
The magnesia process annual revenue requirements are somewhat less
sensitive to economy of scale in the power plant size range of 200 to
1000 MW. This is due to the equipment-intensive nature of the magnesia
process and its higher variable costs, such as utilities.
The annual revenue requirements advantage of the limestone process
over the lime process increases with both power plant size and fuel
sulfur content. This is caused principally by the lower raw material
cost of the limestone process.
The difference in revenue requirements for lime and lime with onsite
calcination processes is reduced with increased plant size or coal sulfur
content. Extrapolation of the data for 3.5% sulfur coal shows a break-
even for onsite calcination at 1150 MW. For a 5.0% sulfur coal the
break-even power plant size for economically feasible onsite calcination
is 750 MW.
The requirement for 90% SCL removal, compared with the base-case
79% removal, has little effect on annual revenue requirements for each
of the four processes. Limestone scrubbing annual revenue requirements
are increased by 3% from the base case while lime scrubbing, with its
higher raw material cost requirements, is increased by 5%.
Other Process Comparisons
Other, possibly more site-specific, variations of the limestone
slurry and magnesia process may also be compared. For example, if
ponding is not practical a fixation and landfill disposal process might
be used for waste disposal. For the magnesia process the chloride
scrubber could be modified to perform particulate removal to meet the
0.1 Ib/MBtu NSPS, eliminating the ESP units. For these process varia-
tions the capital investment of both processes is reduced, as shown
below. The annual revenue requirements, however, are increased for the
limestone slurry process and decreased for the magnesia process.
xxii
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Limestone base case
Limestone, fixation-landfill
Magnesia base case
Magnesia, particulate scrubbing
Capital
investment,
$/kW
98
80
132
116
Annual
net revenue
requirements,
mills /kWh
4.02
4.62
5.08
4.97
a. Including byproduct sulfuric acid credit at $25/ton.
Energy Evaluation and Comparison
The respective process absorbents, limestone, lime, and magnesia
(either from magnesite or seawater) have different energy requirements.
The elements of these energy requirements are: (1) mining, separation,
and sizing, (2) processing, including calcining, and (3) transportation.
The upper portion of Table S-3 shows the energy requirements per
ton of each absorbent delivered to the FGD system. Limestone with low
mining and transportation energy requirements and no processing require-
ment is by far the lowest at 0.268 MBtu per ton, followed by lime at
6.777 MBtu per ton, magnesia from magnesite at 10.376 MBtu per ton, and
magnesia from seawater at 25.696 MBtu per ton. Processing energy
requirements dominate the total energy requirements of the absorbents on
a delivered ton basis. Since the overall energy requirements for the
lime onsite calcination and purchased lime cases are almost identical
the latter case is not included in Table S-3.
The consumption rate of the absorbents varies considerably from
magnesia at 0.04 pound per pound of sulfur removed to lime at 1.98
pounds per pound of sulfur removed and limestone at 4.58 pounds per
pound of sulfur removed. As seen in the lower part of Table S-3,
expression of the energy requirements on the basis of process require-
ments results in a very high energy requirement for lime (6,697 Btu per
pound of sulfur removed) as compared with the other absorbents (limestone
at 614, magnesia from seawater at 542, and magnesia from magnesite at
219 Btu per pound of sulfur removed).
The magnesia process produces sulfuric acid as a byproduct. Much
of the commercial sulfuric acid is produced from elemental sulfur mined
by the Frasch method, an energy-intensive operation. Replacement of
acid produced from sulfur with FGD byproduct acid will conserve the
energy used in mining, transportation, and conversion of sulfur to
sulfuric acid. Partially offsetting these energy savings, the heat
produced in the combustion of sulfur is not obtained for use and must be
deducted from the byproduct energy credit. Table S-4 shows a net energy
requirement of 5,491 Btu per pound of sulfur.
xxiii
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TABLE S-3. ABSORBENT PREPARATION ENERGY REQUIREMENTS
Mining, separation,
and sizing
Absorbent
processing
Transport
Total energy
requirement,
delivered to
power plant
Limestone
0.191
0.077
0.268
Lime onsite Magnesia
calcination from magnesite
Magnesia
from seawater
MBtu/ton of absorbent
0.360
6.272
0.145
6.777
1.20
7.613
1.563
10.376
0.882
24.008
0.806
25.696
Absorbent energy
consumed in base
case, 500-MW plant
Lb absorbent
consumed per Ib of
sulfur removed
Btu per Ib sulfur
removed
4.58
614
1.98
6,697
0.04
219
0.04
542
TABLE S-4. ENERGY REQUIRED FOR PRODUCTION OF
SULFURIC ACID FROM SULFUR
Energy expenditure
Energy required,
Btu/lb of sulfur
Sulfur mining (natural gas)
Sulfur transport (diesel oil)
Sulfuric acid production
(electricity)
Useful heat recovery in sulfuric
acid production (steam)
Net energy required
7,940
343
937
-3,729
5,491
xxiv
-------
FGD itself requires by far the largest portion of the ground-to-
ground energy requirements. The total ground-to-ground energy require-
ments for each of the absorbents is shown in Table S-5 and Figure S-l.
TABLE S-5. GROUND-TO-GROUND ENERGY REQUIREMENTS ASSESSMENT
Btu/LB SULFUR REMOVED
Lime with onsite
Limestone calcination
Mining
Absorbent processing
Transportation
FGD
Sludge disposal
Total
Byproduct credit
Net total
Btu/kWh
% difference from
limestone
% of total power unit
energy output
438
-
176
14,042
22
14,678
_
14,678
291
0
3.24
356
6,198
143
13,165
15
19,877
_
19,877
395
35
4.39
Magnesia
-magnesite
25
161
33
26,387
-
26,658
(5,491)
21,115
420
44
4.67
Magnesia
-seawater
18
507
17
26,387
-
26,929
(5,491)
21,438
426
46
4.73
Previous energy assessments have been restricted to FGD process
energy requirements. The magnesia process has been shown to have energy
requirements about twice those of limestone and lime. The ground-to-
ground comparison shows a substantially reduced difference in magnesia
and limestone energy requirements and it shows almost no difference
between magnesia and lime. Principally because of the inclusion of
calcining energy for lime and the application of the byproduct sulfuric
acid energy credit, the lime process energy requirements on the ground-
to-ground basis are about 94% of those for the magnesia process. The
result of the change from FGD-only energy to the ground-to-ground energy
comparison is shown below.
Energy requirements as %
above lowest process
FGD-only Ground-to-ground
Limestone 7% 0%
Lime 0% 35%
Magnesia (from magnesite) 100% 44%
Magnesia (from seawater) 100% 46%
xxv
-------
25
II Transportation
FGD
Absorbent processing
Mining
Total net energy consumption
20
15
C/3
s
•U
s
10
-5
Sulfuric acid
byproduct credit
1 Steam
2 Electricity
3 Coal
4 Fuel oil
I
Limestone Lime with onsite Magnesia from Magnesia from
calcination roagnesite seawater
Figure S-l. Total energy requirement per pound
of sulfur removed. Base case.
xxvi
-------
In FGD-only energy, the lime process is lowest and the magnesia process
requires twice as much energy. In the ground-to-ground energy, however,
the limestone process is lowest, the lime process requires almost as
much as the magnesia process, and the magnesia process requires only
half again as much as the limestone process. There is still an energy
penalty ranging from 1,200 to 6,800 Btu/lb of sulfur removed for produc-
tion of sulfuric acid as compared with waste-producing processes. It
is, however, substantially reduced in ground-to-ground energy require-
ments as compared with FGD-only energy requirements. Although the
limestone slurry process consumes the largest quantity of raw material,
the low energy requirements for producing it result in a relatively low
ground-to-ground energy requirement. The lime slurry process exchanges
relatively modest FGD energy savings for relatively high raw material
energy requirements and suffers equivalently in energy-requirement
(though not in economic) comparison. Essentially, the lime slurry
process, proceeding from the same raw material as the limestone slurry
process, exchanges additional energy use and cost for FGD operational
and economic benefits.
The magnesia process proceeds further in this direction but com-
pensates for the high raw-material energy requirements by recovering the
raw material. On a sulfur-removed basis, therefore, the magnesia process
has the lowest raw material energy requirements, which partially compen-
sates for the high FGD energy requirements.
Energy requirements are not proportionally related to FGD costs.
(The cost per Btu for fuel oil and coal differ, for example, though
either fuel could perform the same function.) In addition, energy
consumptions for raw materials are seen only indirectly, as costs, by
the power plant operator. Depending on conditions such as location and
the combination of mining, processing, and transportation costs, magnesia
from seawater could be equal in cost to magnesia from magnesite, although
the latter requires only two-fifths the energy to produce. Similarly,
the byproduct acid energy credit is seen only as a compensating economic
factor on a national energy balance basis. The energy consumptions and
credits are thus not directly measurable in terms of FGD economics and
are comparable only on the ground-to-ground datum of energy-available -
energy-consumed.
The energy penalty for producing sulfuric acid instead of using a
waste-producing process can also be compared. Excluding the byproduct
energy credit, the energy differences between the limestone and lime
slurry processes and the magnesia process are about 12,000 and 7,000
Btu/lb of sulfur removed, respectively, compared to the approximately
5,000 Btu/lb of sulfur removed energy requirement for manufacture of
sulfuric acid. In terms of energy requirements, therefore, more than
twice as much energy is required to produce byproduct acid by the magnesia
process as compared with conventional acid production if the magnesia
process is used instead of the limestone slurry process. Only about
two-fifths more energy is required if the magnesia process is used
instead of the lime slurry process.
xxvii
-------
CONCLUSIONS
1. The capital investments and annual revenue requirements for all
three processes are substantially increased over the results
reported in 1975 although the ranking of the three processes has
not changed. The magnesia process capital investment has increased
at a greater rate than those for the other processes, largely
because of modifications and additions in the now more developed
magnesia process (such as materials handling changes and chloride
purge addition). The range of annual revenue requirements is
significantly narrower than the range of capital investments.
The base-case revenue requirements difference between the lime-
stone slurry and magnesia processes is under 26% whereas the
base-case capital investment for the magnesia process is over 45%
greater than that for the lime slurry process.
2. The capital investment costs related to spent-slurry processing
in the magnesia process are about three times greater than capital
investment disposal costs in the waste-producing processes.
Elimination of pond costs does not compensate for the additional
equipment requirements of the magnesia process.
3. Lime is the highest cost absorbent in terms of dollars per ton of
sulfur removed. The lime slurry process is also the least capital-
intensive and therefore benefits less than the others in scale-up
economies resulting from increased power plant size or sulfur
content of the fuel.
4. The lime slurry process with onsite calcination annual revenue
requirements increase less with scale-up than those of the lime
slurry process using purchased lime largely because of the improved
economics of onsite calcination at the higher rates required for
larger power plants or higher sulfur fuel. The minimum power
plant size for onsite calcination is approximately 1150 MW using
3.5% sulfur coal. With a coal sulfur content of 5.0%, the
minimum power plant size for economical onsite calcination is
approximately 750 MW.
5. There are conditions under which the lime slurry process is more
economical to operate than the limestone slurry process. The
lime slurry process has lower revenue requirements at low raw
material consumption levels (small plant size, low-sulfur coal,
and low heat rate) and the limestone slurry process has lower
revenue requirements at high raw material consumption levels.
6. Power plant size and coal sulfur content have large effects on
total costs although unit costs (in terms of sulfur removed)
decrease significantly as power plant size increases. Power
plant remaining life affects the waste-producing processes
(because pond requirements decrease with age) but do not materi-
ally affect the magnesia process costs. Increased removal effi-
ciency from 79% to 90% for 3.5% sulfur coal has little effect on
costs.
xxviii
-------
7. In the oil-fired case the magnesia process is nearly economically
competitive with the lime slurry process with onsite calcination
because the chloride purge is not required. A similar situation
would pertain for overall flue gas cleaning in coal-fired cases,
particularly at high coal sulfur levels, if chloride purging
could be combined with wet-scrubbing fly ash removal at a cost
equivalent to ESP costs.
8. The energy consumed per ton of absorbent delivered to the power
plant (including mining, processing, and transportation energy)
varies almost one hundredfold from limestone (0.27 MBtu per ton)
to magnesia from seawater (25.7 MBtu per ton). Because of the
differing amounts of absorbents used, however, the ground-to-
ground energy requirements of the processes per unit of sulfur
removed differ by less than 50%.
9. The byproduct credit for reduced energy consumption caused by the
replacement of conventional sulfuric acid production from sulfur
with FGD byproduct acid is a significant element of the base-case
magnesia process. The application of this energy credit reduces
the total ground-to-ground energy requirements of the magnesia
process by one-fifth.
10. The lime and limestone scrubbing technologies are the most highly
developed and most utilized systems in the United States. The
magnesia process, however, is relatively immature and requires
additional development and demonstration to determine the long-
term effects of contaminant buildup in recycled magnesia, the
need for and type of chloride purge, and calcining operation
reliability as well as other information which can be developed
only with experience in long-term operation of the completely
integrated system.
11. If ponding of waste slurry is not practical, the alternative
of waste fixation and landfill would require appreciably higher
annual revenue requirements and would result in a more attractive
comparison for magnesia scrubbing.
xxix
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DEFINITIVE SOX CONTROL PROCESS EVALUATIONS:
LIMESTONE, LIME, AND MAGNESIA FGD PROCESSES
INTRODUCTION
Regulations rising from the Clean Air Act of 1967 and its sub-
sequent amendments in 1970 and 1977 have had a fundamental effect on
industries using fossil fuels. When making design and economic deci-
sions managers have increasingly turned to consideration of factors
affecting the emission of atmospheric pollutants from these fuels. A
wide range of technological studies have been initiated to investigate
methods of controlling emission of pollutants.
Sulfur oxides (SO ), predominately sulfur dioxide (SO-), is one of
the main gaseous pollutants created by combustion of fossil fuels and
poses a substantial potential threat to health and the environment. The
major sources of manmade atmospheric SO in the United States are sta-
tionary, coal-burning installations, of which the electrical power
industry composes the major portion. Over half of the total SO
emissions in the United States between 1970 and 1975 was emitted by
electrical utilities (Electrical World, 1977b). Without controls the
condition can easily be exacerbated in the future by increasing reliance
on coal for electrical generation (Electrical World, 1977a). Consequently,
processes and technologies to control SO emissions have received long
and intensive study in the power industry.
There are several possible approaches to the control of SO
emissions from coal-burning plants. One, the use of naturally occurring,
low-sulfur coal, is limited by present and future availability. Further-
more, the revised new source performance standards (NSPS) (Federal
Register, 1979) which required a minimum of 70% SO removal for new
power plants, effective September 19, 1978, will preclude the use of
low-sulfur coal as the sole SO emission control method for future coal-
fired boilers. Others such as special combustion techniques, coal
processing to remove sulfur, and coal conversion are potentially practical
methods but they are not likely to provide general solutions in the near
future. Intermittent controls and more efficient dispersal have not met
with U.S. Environmental Protection Agency (EPA) approval. The most
fully developed and widely used method of SO emission control is flue
gas desulfurization (FGD) in which the SO is removed from the flue gas,
usually by a scrubbing process, and converted to a solid waste or sulfur
byproduct. There is now a broad spectrum of research, development, and
plant demonstration projects in progress that apply FGD technology to
SO emission control (Kennedy and Tomlinson, 1978).
X
-------
As a part of this effort, the Tennessee Valley Authority (TVA) has
conducted a series of economic and conceptual design studies, many of
them in conjunction with EPA, on FGD systems. These evaluations are
based on a set of design and economic premises established to permit
equitable comparisons between different systems. Both the evaluation
processes and the premises are updated and refined as needed to meet
increasingly complex requirements as the technology of FGD process
develops.
Several of these studies have investigated the limestone, lime, and
magnesia scrubbing processes (McGlamery and others, 1973; McGlamery and
others, 1975). Since these earlier studies, technical and operating
information on these systems has greatly increased. Many full-scale
applications of the limestone and lime systems are now in operation and
the magnesia process has also been evaluated to a lesser extent in full-
scale operation. This study is a continuation of the earlier design and
economic evaluations of these processes that incorporates the more
developed technologies. An updated evaluation using the same premise
basis and incorporating the limestone, double-alkali, and citrate proc-
esses has been published (Tomlinson and others, 1979). A third evaluation
in this series evaluating recently developed FGD processes is being
prepared.
In addition, a special energy requirement assessment of the three
systems is included. Energy costs are expected to increase more rapidly
than other costs associated with FGD processes. Increases in energy
costs relative to other FGD costs could radically change the comparative
economics of processes which have different energy requirements. The
energy assessment is a ground-to-ground study that includes all energy
requirements for raw material mining, preparation, and transportation,
as well as direct process energy use. An energy credit for the magnesia
process byproduct acid is also included. This represents the energy
saved by not producing an equivalent amount of producer acid.
The process data represent the state of technology in mid-1979.
All cost estimates are based on the latest available equipment develop-
ment, design, and economic information. Several visits were made to
facilities involved in the production of raw materials in order to
assess the energy needs for the materials being produced. Visits were
also made to engineering contractor firms, vendors, and power plants to
obtain as much firsthand information as possible concerning the systems
being studied.
A base-case system is used that permits comparison with previous
studies of FGD systems. Several variations from the base case have been
prepared to analyze sensitivity of process economics to power plant size
and remaining life, sulfur content of coal, and SO removal efficiency.
X
-------
PROCESS BACKGROUND
Interest in FGD first developed to a significant degree during the
1930's especially in England where several full-scale applications of
wet-scrubbing limestone systems were made. During the same period a
process using magnesia (MgO) was developed by United States and Canadian
paper manufacturers to recover waste sulfites, and wet-scrubbing of
power plant flue gas with MgO was used in the USSR. Various studies
were continued after World War II but it was not until the 1960's, under
the impetus of increasing air pollution problems and pending legislation,
that intensive studies of FGD technology began. Most early work was
concerned with wet-scrubbing using limestone or lime to produce a waste
sludge of calcium-sulfur salts. Problems of waste disposal and a more
developed technology have led in recent years to other wet-scrubbing
processes which regenerate the scrubbing medium and produce a useful
sulfur byproduct such as gypsum, sulfuric acid, or sulfur. Many such
processes have been developed to various stages, particularly in the
United States, and in Japan, which was earliest faced with acute pollu-
tion and waste disposal problems. Previous studies of FGD processes
treat these developments in greater detail (McGlamery and others, 1973;
McGlamery and others, 1975; Tomlinson and others, 1979).
LIMESTONE-LIME SLURRY PROCESSES
The limestone and lime scrubbing processes are similar in design
and function. A slurry of finely ground limestone or slaked lime
absorbent is circulated through a gas-liquid contact scrubber in the
flue gas exhaust system. The SOX in the flue gas is absorbed and reacts
with the absorbent to form insoluble calcium sulfur salts. A purge
stream is withdrawn and fresh slurry is added to maintain the desired
conditions in the scrubber system. The slurry concentration is gener-
ally maintained between 5% and 15% solids and the liquid to gas ratio
between 40 and 100 gal/1000 aft-*. Commercial systems are commonly
designed for an 80% to 90% removal efficiency. The flue gas is usually
treated to remove fly ash and is cooled and humidified before it enters
the scrubber system. The scrubbed flue gas can be passed through a mist
eliminator and reheated for plume buoyancy before entering the stack.
The purge stream of scrubber liquid is often pumped to a waste sludge
pond where it settles to a semi-solid sludge of about 40% solids and the
excess water is returned to the scrubber system. Processes for treating
the effluent to form gypsum or dewatering and treatment to produce a
landfill material exist (Rossoff and others, 1978; Duvel and others,
1978). Several scrubber designs and configurations are used, including
fixed and variable venturi, mobile bed, spray, and packed types in
single and parallel arrays.
3
-------
The various scrubber designs reflect different approaches to improve-
ments in diffusion-absorption kinetics and to control of scale formation
in the system. The scale, consisting of hard buildup of sulfate-sulfite
salts, has been a persistent problem in limestone and lime scrubbing
processes. Its formation, still not fully understood, is controlled by
scrubber design and adjustment of operating conditions such as pH and
stoichiometry.
The absorption-reaction process can be simplified by division into
steps that illustrate the kinetics of the process.
1. Diffusion of SO- to the gas-liquid interface.
2. Absorption of S02 by the liquid.
3. Hydrolysis and dissociation of the SC>2 to form sulfite (SO ~)
and bisulfite (HS03 ) ions.
4. Diffusion of the sulfites in the liquid.
5. Hydrolysis and dissociation of limestone or lime to form calcium
ions.
6. Reaction of the calcium and sulfite ions to form hydrated calcium
sulfite, predominantly the insoluble hemihydrate (CaSO3-l/2H.O).
Depending on the conditions, different steps may control rates,
although steps 1, 4, and if limestone is used, 5 are usually controlling.
Scrubber design and operating conditions such as gas-liquid ratio and
velocities, hold times, and pH are important factors, as are flue gas
composition and impurities. Limestone dissociation is improved by fine
grinding (at least 70% to pass U.S. Mesh No. 200). Limestone dissociation
is also affected by its MgCO content and crystal structure. The slow
dissociation rate of limestone is compensated for by using higher
limestone to S02 stoichiometric ratios (1.2 to 1.5:1.0 is usual, com-
pared to about 1.0 to 1.1:1.0 for the more reactive lime).
The actual number of chemical reactions and the range of kinetics
are much greater than the steps listed above suggest and are not fully
defined in all aspects. In addition to the S02 and calcium compounds
there are also appreciable quantities of carbon dioxide and free oxygen
present as well as other potentially reactive dissolved or suspended
impurities. It is believed that the reactive calcium species for both
the limestone and lime processes may be calcium bicarbonate—Ca(HCO-j)2—
formed by dissolved carbon dioxide as well as the limestone carbonate.
The oxygen present oxidizes an appreciable percentage of the sulfites to
sulfates, which increases scale formation.
The pH, which controls the equilibrium conditions of the several
carbonate and sulfite species present, has important effects on the
process chemistry. Absorption of both sulfur dioxide and carbon dioxide,
solubilities of the absorbent, and the types and quantities of materials
-------
precipitated are all pH sensitive at the scrubbing conditions used. Lime
processes tend to operate at higher pH than the limestone processes.
Limestone and lime scrubbing processes generally operate in the 5 to 7
pH range, with the lower part of the range favoring increased absorbent
utilization and decreased scale formation.
The scrubbing liquid is thus a complex medium of calcium (and
possibly magnesium) sulfur compounds, carbonates, and hydroxides both in
solution, some at a high degree of supersaturation, and as variously
hydrated solids. The liquid is constantly changed in composition as
fresh absorbent is added, flue gas components absorbed, and effluent
withdrawn. The many factors of design and operating conditions which
control these conditions are a large portion of current technological
investigation.
Limestone and lime scrubbing systems represent 80% to 90% of the
full-scale FGD systems operating, or under construction in the United
States through 1978. Table 1 shows a summary of FGD system status
through September 1979. Table 2 shows the name, size, utility identity
and vendor for the 46 limestone and lime scrubbing operations in September
1979.
TABLE 1. STATUS OF FGD SYSTEMS IN THE U.S. IN SEPTEMBER 1979
Under
Q
Operational construction Contracted Planned
Limestone or lime 46 35 16 11
Other J_0 _6 _3 3£
Total 56 42 19 44
Percent limestone 68 83 84 25
or lime
Source: Melia, 1979.
a. Considering limestone, lime, and other FGD systems.
-------
TABLE 2. LIME AND LIMESTONE SYSTEMS IN OPERATION IN THE U.S. - SEPTEMBER 1979
Unit
Tombigbee 2 & 3
Pleasants 1
Apache 2 & 3
Cholla 1 & 2
Duck Creek 1
Conesville 5 & 6
Coal Creek 1
Elrama 1-4
Phillips 1-6
Petersburg 3
Hawthorn 3 & 4
La Cygne 1
Jeffrey 1
Lawrence 4 & 5
Green River 1-3
Cane Run 4 & 5
Mill Creek 3
Paddy's Run 6
Milton R. Young 2
Colstrip 1 & 2
Sherburne 1 & 2
Bruce Mansfield 142
Winyah 2
R. D. Morrow 1 & 2
Marion 4
Southwest 1
Shawnee 10A & 10B
Widows Creek 8
Martin Lake 1, 2, & 3
Monticello 3
Hunter 1
Hunt ington
FCD system
Size (MW)
Utility
Scrubber vendor
Line
or limestone
179 each
519
195 each
119 & 35
378
411 each
327
510
410
532
90 each
874
540
125 i. 420
64
188 & 190
442
72
405
360 each
740 each
917 each
140
124 each
184
194
10 each
550
595 each
800
360
366
Alabama Electric Cooperative
Allegheny Power System
Arizona Electric Power Cooperative
Arizona Public Service
Central Illinois Light
Columbus and Southern Ohio Electric
Cooperative Power Association
Duquesne Light
Duquesne Light
Indianapolis Power and Light
Kansas City Power and Light
Kansas City Power and Light
Kansas Power and Light
Kansas Power and Light
Kentucky Utilities
Louisville Gas and Electric
Louisville Gas and Electric
Louisville Gas and Electric
Minnkota Power Cooperative
Montana Power
Northern States Power
Pennsylvania Power
South Carolina Public Service
South Mississippi Electric Service
Southern Illinois Power Cooperative
Springfield City Utilities
Tennessee Valley Authority
Tennessee Valley Authority
Texas Utilities
Texas Utilities
Utah Power and Light
Utah Power and Light
Feabody Process Systems
Babcock and Wilcox
Research-Cottre11
Research-Cottrell
Riley Stoker/Environeering
Universal Oil Products
Combustion Engineering
Chemico
Chemico
Universal Oil Products
Combustion Engineering
Babcock and Wilcox
Combustion Engineering
Combustion Engineering
American Air Filter
American Air Filter
American Air Filter
Combustion Engineering
ADL/Combustion Equipment Associates
ADL/Combustion Equipment Associates
Combustion Engineering
Chemico
Babcock and Wilcox
Riley Stoker/Environeering
Babcock and Wilcox
Universal Oil Products
Universal Oil Products & Chemico
Tennessee Valley Authority
Research-Cottrell
Chemico
CiiCTnico
CheTT.ico
Limestone
Lime
Limestone
Limestone
Limestone
Lime
Lime/Alkaline flyash
Lime
Lime
Limestone
Lime
Limestone
Limestone
Limestone
Lime
Lime
Lime
Lime
Lime/Alkaline fly ash
Lime/Alkaline fly ash
Limestone/Alkaline fly ash
Lime
Limestone
Limestone
Limestone
Limestone
Lime/Limestone
Limestone
Limestone
Limestone
Lime
Source: Smith, 1979.
-------
MAGNESIA SCRUBBING - REGENERATION
The economics of the magnesia process have been evaluated in two
earlier TVA-EPA studies. The results are presented in conceptual design
reports published in 1973 (McGlamery and others) and 1975 (McGlamery and
others). The results of the latter study indicated that the magnesia
process was not then economically competitive with the limestone and
lime slurry processes. Interest in the process has since been renewed
because site-specific limestone and lime systems are often more costly
than generalized systems. They also leave the utility with the diffi-
cult problem of sludge disposal and disposal-site reclamation.
The background and chemistry of the various magnesia processes have
been extensively discussed in the earlier reports. Basically, the
magnesia process used in this study consists of a wet-scrubbing system
similar to the limestone and lime processes. A slurry of commercial-
grade MgO is contacted with the flue gas to form magnesium-sulfur salts.
A purge stream is removed and fresh magnesia slurry added to maintain
the desired concentrations. Because of the high cost of the MgO,
however, it must be regenerated to make the process economically prac-
tical. The regeneration process consists of removing and drying the
effluent solids and calcining them to produce MgO and SO . The SO,, can
be further processed to sulfuric acid.
The use of MgO and a regeneration system provides some technical
advantages and some restrictions. The MgO is more reactive than lime-
stone or lime and has a low scaling potential, thus providing a wider
scope for scrubber design and operating conditions. As a closed system,
however, provision has to be made to reduce the buildup of impurities
such as fly ash and chlorides.
The same simplified steps applied to the limestone and lime processes
can be applied to the magnesia scrubbing process. The MgO, hydrolized
to magnesium hydroxide [MgCOH^l during slurrying, reacts with sulfite
and bisulfite in solution to form insoluble sulfites. Both magnesium
sulfite hexahydrate [Mg'SO^'6H20] and magnesium sulfite trihydrate
[MgSO-j-Sl^O] are formed in quantities dependent upon the operating
characteristics of the specific facility (Lowell and others, 1977).
Representative overall reactions are:
Mg(OH)2 + 5H20 + S02 + MgS03'6H20 (ppt)
Mg(OH) -6H 0 + S00 ->- Mg(HSO ) + 5H.O
2. 2. 2 j 2. 2.
Mg(HSO_)0 + MgO + 11H00 -»- 2MgSO_'6H00 (ppt)
J2 2. j 2
Mg(HSO-). + MgO + 5H_0 -»• 2MgSO.'3H00 (ppt)
J 2 2 J 2
Some oxidation of the MgSO. occurs through reaction with absorbed oxygen:
2MgS03 + 02 H
-------
Solids in the effluent, consisting of hydrated MgSO^ and MgSO^ are
separated from the liquid, dried to remove both free water and water of
hydration, and calcined under controlled conditions to produce MgO and
SCL . The MgO is recycled to the scrubber system and the SCL is converted
to sulfuric acid in a separate plant.
The magnesia scrubbing process has not been developed to the same
extent as the lime and limestone processes. There are no commercial-
scale units in full-time operation. Three demonstration-scale plants
have been operated over the past 6 years, however, and have provided a
considerable amount of information needed to define process equipment
and operating condition requirements.
The Boston Edison Company operated a 150-MW magnesia scrubbing
facility from April 1972 through June 1974 at their 2.5% sulfur oil-
fired Mystic 6 station. The research prototype was not operated on a
routine basis. It experienced severe maintenance problems in the first
year. The system also experienced problems with MgO losses although it
was promising in the areas of S0~ removal and in the absence of scale
buildup and plugging.
Operation of the 95-MW magnesia scrubbing system at the 2.0% sulfur
coal-fired Dickerson station of Potomac Electric Power Company on an
intermittent basis between September 1973 and August 1975 was also
impeded by problems. MgO slaking and handling was difficult because of
differences between the regenerated and virgin MgO which were alternately
fed to the system. Scaling problems were not encountered, but erosion
and corrosion of carbon steel pumps and piping were severe. S0~ removal
was adequate.
The magnesia facility at the 2.3% sulfur coal-fired Eddystone
Station of Philadelphia Electric was put onstream in late 1975. Problems
similar to those experienced at the other two demonstration plants have
occurred. The unit has operated intermittently since startup. A second
magnesia system is planned for the Eddystone station.
A full-scale 600-MW magnesia scrubbing facility complete with a
regeneration system for sulfuric acid production is being planned by TVA
for the Johnsonville Steam Plant. The latest available technology will
be incorporated into the design of the facility. The conceptual design
presented in this report also represents current technology but does
not exactly parallel the TVA design because of the site-specific nature
of the Johnsonville project.
-------
DESIGN, ECONOMIC, AND ENERGY PREMISES
This study compares the economics of the three FGD systems using
conditions that are representative of projected industry conditions.
The premises used in this study have been developed by TVA, EPA, and
others during similar economic evaluations made since 1967.
The premises are designed to establish base-case efficiencies,
process flow rates, and other operating and design conditions. Case
variations are used to determine the sensitivity of costs to changes in
plant size, new versus existing plants, sulfur in coal, and SOX removal
efficiency. Because of the decreased emphasis on oil as a utility
fuel, only one oil-fired variation is included. The economic premises
are designed to include the many factors affecting FGD costs. Energy
premises are designed to compare the overall energy requirements of the
alternate FGD systems. They include not only the energy expended in the
FGD processes but also the energy required to mine, process, and deliver
the raw materials. A byproduct energy credit is included for the magnesia
FGD process. This represents the energy for production of an equivalent
quantity of producer acid.
The FGD systems are assumed to begin downstream from the fly ash
removal system and to end at the stack plenum. Fly ash removal and
disposal and a stack plenum are considered necessary power plant facil-
ities and are not included in the FGD costs.
DESIGN PREMISES
The utility plant design and operation is based on Federal Energy
Regulatory Commission (FERC) historical data and TVA experience. The
conditions used are representative of a typical modern boiler less than
10 years old for which FGD systems would most likely be considered. A
midwestern location typical of Illinois, Indiana, and Kentucky is used
because of the concentration of medium to high sulfur coal supplies and
power plants in that area.
Emission Standards
NSPS established by EPA (Federal Register, 1971) specify a maximum
emission, based on heat input, of 0.10 Ib/MBtu for particulate matter
and 1.2 Ib/MBtu for S02 in large coal-fired utility boilers. The process
design premises used for this study are based on compliance with these
-------
standards. The revised NSPS (Federal Register, 1979) are not used In
this study because boilers existing in the time frame used (through
1983) will not be affected by this more stringent standard.
Actual SOX removal efficiencies required to meet emission standards
vary according to the sulfur content of the coal. Table 3 shows the
efficiencies calculated for the sulfur contents and combustion condi-
tions used in this study. In addition, a case variation is included to
evaluate the effect of 90% SOX removal efficiency on costs.
TABLE 3. REQUIRED REMOVAL EFFICIENCIES
Sulfur content Degree of particle Degree S02
of fuel, % removal, wt % 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
Fuels
The coal compositions are composites of several hundred samples
representing major U.S. coal production areas. To represent the range
of sulfur contents in coals now being burned, sulfur contents of 2.0%,
3.5%, and 5.0%, dry basis, are used. The coal has a heating value of
10,500 Btu/lb, as fired, and an ash content of 16%, as fired. The com-
position and flow rates for the base-case conditions are shown in Table 4.
The oil-fired variation uses a No. 6 fuel oil (Table 5) with 2.5%
sulfur and 0.1% ash and with a high heating value of 144,000 Btu/gal.
Power Plant Design
Power units up to 1300 MW in size are operated in the United States
today. For new units scheduled for startup through 1980 the sizes range
from about 80 MW to 1300 MW (Kidder, Peabody & Co., 1978). Although
much of the future power production will be from units of 500 MW or
larger, many older units and some new units of 200 MW or less will
continue in operation for many years. The choice of unit sizes used in
this evaluation is based on this anticipated power unit size distribution.
10
-------
TABLE 4. COAL COMPOSITIONS AND FLOW RATES AT VARYING SULFUR LEVELS
(500-MW new unit, 9,000 Btu/kWh heat rate,
10,500 Btu/lb high heating value of coal)
Base case, 3.5%
sulfur (dry basis)
Coal
components
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Chlorine
Ash
Water
Total
Wt %,
as fired
57.56
4.14
1.29
7.00
3.12
0.15
16.00
10.47
100.00
Lb/hr,
as fired
246,800
17,700
5,500
30,000
13,400
600
68,600
46,000
428,600
2.0%
(dry
Wt %,
as fired
58.03
4.17
1.30
7.81
1.80
0.15
16.00
10.74
100.00
sulfur
basis)
Lb/hr,
as fired
248,700
17,900
5,600
33,500
7,700
600
68,600
46,000
428,600
5.0%
(dry
Wt %,
as fired
56.89
4.09
1.27
6.40
4.46
0.15
16.00
10.74
100.00
sulfur
basis)
Lb/hr,
as fired
244,000
17,500
5,400
27,400
19,100
600
68,600
46,000
428,600
TABLE 5. OIL COMPOSITION AND FLOW RATE
(500-MW existing unit, 9,200
Btu/kWh heat rate, 2.5% sulfur)
Oil components
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Ash
Sediment
Wt %,
as fired
83.66
11.46
0.63
1.25
2.50
0.10
0.40
Lb/hr
204,100
28,000
1,500
3,000
6,100
200
1,000
Total
100.00 243,900
11
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A single, balanced-draft, horizontal, frontal-fired boiler design
is used. Particulate matter removal and boiler induced-draft (ID) fans
are not included in the FGD costs. The boiler ID fans discharge into a
common plenum which is included in the FGD costs. A boiler size of 500-
MW output is used for the base case and sizes of 200- and 1000-MW output
are used for the case variations. The output does not include power
requirements for the FGD system.
Power Plant Operation
An operating life of 30 years is used, based on guidelines suggested
by FERC (1968). The operating schedule, based on TVA experience, is
shown in Table 6. New units are assumed to have a total operating time
of 127,500 hours. Existing units 5 and 10 years old are assumed to have
remaining operating times of 92,500 and 57,500 hours respectively.
TABLE 6. 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 (1973)
data 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 7.
TABLE 7. 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
12
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Flue Gas Composition
Flue gas compositions are based on combustion of pulverized coal
using a total air rate to the air preheater equivalent to 133% of the
stoichiometric requirement. This includes 20% excess air to the boiler
and 13% air inleakage in ducts and at the air preheater. These values
reflect operating experience with TVA 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 SOg and the remainder S02-
The base-case flue gas composition and flow rates calculated from
these conditions are shown in Table 8. The estimated flue gas compositions
for power unit emissions at varying fuel-sulfur levels before fly ash
removal and FGD are given in Table 9 . Calculated flue gas and equiva-
lent S02 emission rates are listed in Table 10.
TABLE 8. CALCULATED BASE-CASE FLUE
GAS COMPOSITION AND FLOW RATE
Flue gas
components
Lb/hr
Aft3/min
(300°F)
N2 3,450,000 1,138,000
02 258,200 74,590
C02 904,200 189,900
S02 25,130 3,626
S03 317 37
NOX (as NO) 3,009 927
HC1 661 168
H20 264.500 135.600
Total 4,906,000 1,543,000
13
-------
TABLE 9. FLUE GAS COMPOSITIONS FOR POWER
UNITS WITHOUT EMISSION CONTROL FACILITIES
Fuel and boiler type
Coal-fired boiler
(horizontal
frontal fired)
Oil-fired boiler
(tangential fired)
Flue gas components,
% by vol
Sulfur content of fuel, % by wt (dry basis)
2.0 3.5 5.0 2.5
N
°2
C02
so2
so3
NOX (as NO)
HC1
H70
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/sft^ (dry)
Gr/sft (wet)
6.67
6.08
6.65
6.06
6.66
6.08
0.036
0.032
Scrubber Design
Scrubber design criteria are based on TVA operating experience,
general power industry operating experience, and information from
process and equipment vendors. The designs are generic to the extent
that they represent most-proven technology rather than a particular
existing installation, although demonstrated, full-scale operational
data predominate. The limestone and lime processes are based on experi-
ence at the Shawnee Steam Plant EPA Test Facility, extensive power
industry experience with these processes, and vendor information. The
magnesia process is based on design data for the TVA Johnsonville mag-
nesia process, on power industry experience, and vendor information.
The 200-MW boiler size is provided with two scrubber trains; the
500-MW and 1,000-MW boiler sizes are provided with four each. All of
the trains are fed from the common plenum. An additional total pressure
drop of 15 inches t^O is assumed for the FGD systems. A booster fan of
this capacity is provided in each train.
Presaturators are used in the limestone and lime processes to cool
and humidify the flue gas. In the magnesia process chlorides are removed
by scrubbing before S02 scrubbing. This also serves to presaturate the
14
-------
TABLE 10. POWER PLANT FLUE GAS AND S02 RATES
Power plant
size, MW
Coal-fired units
200
200
500
500
500 (base case)
500
1,000
1,000
Sulfur content Gas flow Equivalent S02 emission
Type of fuel, % to FGD systems, rate to FGD systems,
plant (dry basis) aft3/min (300°F) Ib S02/hr
Existing
New
Existing
New
New
New
Existing
New
3.5
3.5
3.5
2.0
3.5
5.0
3.5
3.5
652,000
631,000
1,577,000
1,539,000
1,543,000
1,539,000
3,085,000
2,982,000
10,610
10,270
25,690
14,500
25,130
35,920
50,250
48,580
Oil-fired unit
500
Existing
2.5
1,313,000
12,060
-------
flue gas. The assumed percentages of flue gas components removed in the
chloride scrubber are:
Component % removal
S02 5
S03 50
HC1 100
In the limestone and lime processes the presaturator wastes are
discarded in the scrubber waste streams. In the magnesia process the
chloride scrubber waste is discarded in the ash disposal pond.
The scrubbers are equipped with chevron-type mist eliminators which
reduce the entrained moisture content of the scrubbed gas to 0.1%. This
is desirable to reduce the reheating load, decrease deposition and
corrosion in downstream equipment, and reduce particulate matter emission.
Operating conditions for the scrubbers are shown in Table 11.
These conditions are used for both the base case and the case varia-
tions. Scaling factors based on gas and product rates are used to
adjust sizes for conditions other than the base case.
TABLE 11. SCRUBBER OPERATING CONDITIONS
[500-MW units, 3.5% sulfur in coal (dry basis),
1.2 Ib SO /MBtu heat input allowable emission]
Operating conditions
Stoichiometry
Design gas velocity, ft/sec
S02 scrubber
L/G, gal/kft3
Presaturator
S02 scrubber, recycle liquor
Design pressure drop, inches t^O
Oxidation of removed S02 to S0^~ , %
Limestone
1.30
12.5
4
50
13
20
Process
Lime
1.05
12.5
4
45
13
20
Magnesia
1
12
10
15
5
.05
.5
a
a. Proprietary information.
The scrubber design is assumed to be proven. No provisions are
made for additional spares or special sizing to compensate for uncertain
design and operating factors. In the integration of the scrubber system
with the boiler, provision for turndown and maintenance is limited to
provision of the common plenum with dampers to allow individual trains
to be shut down. Scrubber bypass ducts are not provided.
16
-------
Reheat
Reheat of the scrubbed flue gas to 175 F is provided for plume
buoyancy, reduced opacity, and to prevent fan and stack corrosion.
Indirect steam heat, before the flue gas enters the stack plenum, is
used for coal-fired units. Direct-fired oil reheat is used for the oil-
fired case.
Raw Materials
The raw materials used for each process are listed below. Lime-
stone is crushed and wet ground as part of the scrubbing operation. The
other materials are not processed before use.
Property Limestone Lime MgO
Size as received 0-1-3/4 inch 3/4-1-1/4 inch Crystalline powder
Ground size 70% to pass 200 mesh - -
Analysis 90% CaC03 95% CaO 98% MgO
Bulk density,
lb/ft3 95 55 20-30
Waste Disposal
The limestone and lime system sludge disposal consists of pumping
the 15% solids sludge to an earthen-diked, clay-lined pond located 1
mile from the plant site. The pond is designed to minimize the total of
construction and land cost. It is sized for the remaining life of the
power plant, based on seepage and evaporation losses equal to rainfall
and reuse of excess water resulting from natural compaction of the waste
to 40% solids.
Provision for waste disposal for the magnesia system is provided by
the ash pond which is part of the power plant ash system. A portion of
the ash pond cost is allocated to the FGD system to account for the
additional waste disposal cost.
Case Variations
Case variations, consisting of a change in one design premise while
holding the remaining premises at the base-case conditions, are used to
determine the economic effects of ranges of conditions normally encoun-
tered in industry practice. The case variations used are shown below:
17
-------
Premise condition Base case Case variation
Power plant size, MW 500 200, 1000
Power plant remaining
life, years 30 (new) 25, 20
Coal, percent sulfur
(dry weight) 3.5 2.0, 5.0
SO , percent removal 79 90
Oil, weight percent
sulfur - 2.5
The relative quantities of gas and sulfur processed compared with
the base-case quantities are shown in Table 12. The relative throughput
rates are used to calculate an area scale factor which multiplied by the
base case area direct investment gives the corresponding area direct
investment for the case variation. The area investments for the case
variations are exponentially scaled by the relative throughput using a
weighted average scaling exponent calculated from the base case equipment
investment. Areas processing flue gas are scaled on the basis of relative
gas throughput and byproduct processing areas are scaled on the basis of
relative sulfur throughput. Table 12 shows the relative gas and product
throughput rates for each case variation in comparison with the base-case
quantities. The direct, indirect, fixed, and total capital investments
are then calculated by the same procedure described later for the base-
case investment (Tomlinson and others, 1979).
ECONOMIC PREMISES
The economic premises are divided into capital investment costs for
installation of the system and annual revenue requirements for its
operation over the life of the power plant. The premises are further
divided into sections to establish cost areas for comparison and analysis.
Criteria are used which define cost indexes, land, raw material, utility,
energy costs, capital charges, and other factors required for comparative
results. The estimates are made using equipment lists, flow diagrams,
material balances, various layouts for electrical equipment, piping and
instrumentation, plot plans, and other design and operating information.
Cost information is obtained from engineering-contracting, processing,
and equipment companies, TVA purchasing and construction data, and
authoritative publications on costs and estimating [such as Guthrie
(1969), Peters and Timmerhaus (1968), Popper (1970), and The Richardson
Rapid System (1979)] .
The premises are designed to represent projects in which design
begins in mid-1977 and construction is completed in mid-1980, followed
by a mid-1980 startup. Capital costs are assumed 50% expended in mid-
1979. Capital costs are projected to mid-1979 and revenue requirements
are projected to mid-1980. Scaling to other time periods can use mid-
1979 as the basis for capital costs and mid-1980 as the basis for
revenue requirement.
18
-------
TABLE 12. RELATIVE QUANTITIES OF GAS AND SULFUR TO BE
PROCESSED IN COMPARISON WITH THE BASE-CASE QUANTITIES
Relative throughput rate, %
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
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
The premises are based on regulated utility economics. The capital
structure is assumed to be 60% debt and 40% equity. Interest on bonds
is assumed to be 10% and the return to stockholders 14%.
Capital Costs
Capital costs are categorized as direct investment, indirect
investment, contingency, other capital charges, land costs, and working
capital. Total fixed investment consists of the sum of direct and
indirect capital costs and a contingency based on direct and indirect
investment. Total depreciable investment consists of total fixed
investment plus the other capital charges. Investment costs are pro-
jected from historical Chemical Engineering (1975, 1976) annual cost
indexes as shown in Table 13. The costs are based on construction of a
proven design and an orderly construction program without delays or
overruns.
19
-------
TABLE 13. COST INDEXES AND PROJECTIONS
Year 1974 1975 1976a 1977a 1978a 1979a 1980a 1981a
Plant
Material*5
Laborc
165.4
171.2
163.3
182.4
194.7
168.6
197.9
210.3
183.8
214.7
227.1
200.3
232.9
245.3
218.3
251.5
264.9
237.9
271.6
286.1
259.3
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 maintained.
b. Same as index in Chemical Engineering for "equipment, machinery,
supports."
c. Same as index in Chemical Engineering for "construction labor."
Direct Investment—
Direct capital costs include all costs, excluding land, for materials
and labor to install the complete FGD system. Included are site prepara-
tion, excavation, buildings, storage facilities, landscaping, paving,
and fencing. One mile of paved road is also included. Process equipment
includes all major equipment and all equipment ancillary to the major
equipment, such as piping, instrumentation, electrical equipment, and
vehicles. Services, utilities, and miscellaneous costs involved in
construction are estimated as 6£ of the direct investment excluding pond
construction costs.
Indirect Investment—
Indirect investment costs consist of various contractor charges and
fees and construction expenses. The following cost divisions and determi-
nations are used.
Engineering design and supervision—This cost is calculated as a
function of the complexity, of the system as determined by the number of
major equipment items. Battery limit package units and disposal ponds
are treated separately because of the different engineering design
aspects involved. The formula used is:
Engineering design and supervision =
(8900)(1.294)(number of major equipment items)
+ (status factor)(battery limit investment)
+ (0.076)(direct pond investment, in M$)°-07
The status factor for the battery limit package unit is 0.05 to
0.15 depending on the commercial status and design reliability of the
unit.
20
-------
Architect and engineering contractor expense—This expense is
calculated as 25% of the engineering design and supervision costs for
major equipment items and battery limit units plus 10% of engineering
design and supervision costs for pond construction.
Construction expense—This expense includes temporary facilities,
utilities, and equipment used during construction. The expense is
calculated as a. function of direct investment:
0 83
Construction expense =0.25 (direct investment, excluding pond, in M$) "
+0.13 (pond direct investment, in M$)°-83
Contractor fees—Direct investment is also used to determine contractor
fees:
Contractor fees = 0.096 (total direct investment in M$)
Contingency
Contingency is 20% of the sum of direct investment and indirect
investment.
Other Capital Charges
Other capital charges consist of an allowance for startup and
modifications and interest during construction. The allowance for
startup and modifications is 10% of the total fixed investment. Interest
during construction is 12% of the total fixed investment. It is based
on the simple interest which would be accumulated at 10% per year under
the premise construction and expenditure schedule, assuming a 60% debt,
40% equity capital structure.
Land
Total land requirements, including the waste disposal pond, are
assumed to be purchased at the beginning of the project. A land cost of
$3,500 per acre is used.
Working Capital
Working capital consists of money invested in raw materials and
supplies, products in process, and finished products; cash retained for
operating expenses; accounts receivable; accounts payable; and taxes
payable. For these premises, working capital is assumed to be the sum
of 3 weeks of raw material costs, 7 weeks of direct costs, and 7 weeks
of overhead costs.
21
-------
Annual Revenue Requirements
Annual revenue requirements, based on a 7,000 hour per year operating
schedule, use the same operational profile and remaining life assumptions
that are used for the power plant design premises. Costs are projected
to 1980 dollars to represent a mid-1980 startup. The revenue requirements
are divided into direct costs for raw materials and conversion and
indirect costs for capital charges and overheads. Net revenue from
byproduct sale is applied as a credit.
Direct Costs—
Projected direct costs for raw materials, labor, and utilities are
shown in Table 14. Unit costs for steam and electricity are based on
actual production costs, including fuel, labor, depreciation, rate base
return on investment, and taxes. The charge for electricity used by the
FGD system is based on a separate electrical consumer paying full price
for service.
TABLE 14. PROJECTED 1980 UNIT COSTS
FOR RAW MATERIALS, LABOR, AND UTILITIES
Raw materials
$/unit
Limestone
Lime
MgO
Natural gas
Catalyst
Labor
7.00/ton
42.00/ton
300.OO/ton
3.50/kft3
2.50/liter
Operating labor
Analyses
Mobile equipment
Utilities
12.50/man-hr
17.00/man-hr
17.00/man-hr
200 MW 500 MW 1000 MW
Fuel oil (No. 6)
Steam (500 psig)
Process water3
Electricity
0.031
0.029
0.40/gal
2.00/MBtu
0.12/kgal
0.028/kWh
a. Varies according to process-dependent water
requirements.
22
-------
Maintenance costs are a function of the direct investment costs.
They are adjusted for the size and complexity of the system, based on
operating experience with the system or similar operations. Maintenance
costs are assumed to be constant over the life of the plant; the increase
in costs per hour of operation counteracted by the decline in operating
hours. Pond maintenance is treated separately as a constant 3% of the
pond construction costs. Maintenance costs are shown in Table 15.
TABLE 15. ESTIMATED OVERALL ANNUAL MAINTENANCE COSTS
% of direct investment
excluding pond construction3
Process
Limestone
Lime
MgO
200 MW
9
9
8
500 MW
8
8
7
1000 MW
7
7
6
a. Pond maintenance is estimated as 3% of pond
construction cost.
Indirect Costs—
A summary of capital charges, based on regulated utility economics,
is shown in Table 16. Straight-line depreciation is used, based on the
remaining life of the power plant when the FGD system is installed. An
allowance for interim replacement is included. This allowance is increased
from the usual average of about 0.35% because of the unknown life span
of FGD systems. The insurance allowance is based on FERC practice.
Property taxes are included as 1.5% of the total depreciable capital
investment. Cost of capital is based on the assumed capital structure.
Methods of calculating overheads vary. The method used in these
premises is based on information from several sources (Guthrie, 1969;
The Chemical Engineer's Handbook, 1973; Popper, 1970; and Peters and
Timmerhaus, 1968). Plant overhead is assumed to be 50% of the total
conversion cost less utilities. Utilities are excluded to avoid over-
changing energy-intensive processes. Administrative overhead is assumed
to be 10% of the operating labor and supervision cost. Marketing over-
head is based on the marketability of the byproduct. For sulfuric acid
it is assumed to be 10% of the byproduct revenue.
23
-------
TABLE 16. ANNUAL CAPITAL CHARGES FOR POWER INDUSTRY FINANCING
Percentage of total depreciable
capital investment
Years remaining life
Depreciation (straight line, based on
years remaining life of power unit)
Interim replacements (equipment having
less than 30-year life)
Insurance
Property taxes
Total rate applied to original
investment
30
0.7
0.5
1.5
25
0.4
0.5
1.5
20
3.3 4.0 5.0
0.5
1.5
6.0 6.4 7.0
Cost of capital (capital structure assumed
to be 60% debt and 40% equity)
Bonds at 10% interest
Equity0 at 14% return to stockholder
Income taxes (Federal and State)c
Total rate applied to depreciation base
Percentage of unrecovered
capital investment3
6.0
5.6
5.6
17.
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 effect on
capital cost as return on equity.
d. Applied on an average basis, the total annual percentage of original fixed
investment for new (30-year) plants would be 6.0% + 1/2(17.2%) = 14.6%.
The magnesia process is the only process evaluated in this study
that produces a salable byproduct. In the calculation of annual and
lifetime economics, credit from the sale of sulfuric acid is deducted
from the yearly projection of revenue requirements to give the net cost
of the FGD process.
24
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ENERGY PREMISES
The ground-to-ground energy requirements consist of the energy con-
sumed in mining, processing, and transporting the raw materials; the FGD
process energy consumption; and an energy credit for byproduct sulfuric
acid. The byproduct acid is assumed to replace an equivalent quantity
of acid produced from mined sulfur. All raw material energy requirements
are based on the quantity of raw materials (limestone, lime, or magnesia)
consumed by the base-case, 500-MW power plant FGD system. For the
onsite lime calcination plant, however, the raw material energy require-
ments are calculated on the energy consumption of typical, commercial
operations producing larger quantities than those consumed by the FGD
system. The magnesia production processes are based on visits to the
Basic Refractories (division of Basic, Inc.), Gabbs, Nevada, and Port
St. Joe, Florida, magnesia plants. This information was supplemented by
information on a 100,000 metric tons per year seawater magnesia plant
provided by Kaiser Refractories International. The processes used in
this evaluation are generic and represent no particular plant.
For off-highway mobile equipment operation an energy consumption of
0.05 gallons of diesel fuel per horsepower-hour is used (Coal Age,
1979). Limestone processing energy requirements are based on published
information (Rock Products, 1979) and contacts with equipment manufac-
turers, producers, and engineering contractors. Calcination energy
requirements are based on information from the Kennedy Van Saun Corpor-
ation.
Transportation Energy
The bases for energy requirements for transportation of materials
(other than onsite hauling and conveying) are:
Method Btu/ton-mile
Highway 2,400
Rail 750
Water 500
These rates are from independently published U.S. Corps of Engineers
data (American Waterways Operators, 1979).
Highway transportation is assumed for distances of 150 miles or
less. Rail is used for distances of over 150 miles. Water is used as
the transportation method where applicable, such as elemental sulfur
from Port Sulphur, Louisiana. Diesel (No. 2) fuel oil is used as the
fuel for all three transportation methods. A specific gravity of 0.86
and gross heating value of 140,000 Btu/gal are assumed for the diesel
fuel.
25
-------
A transportation distance of 32 miles is used for limestone. This
is based on the average distance from U.S. limestone-producing counties
to existing U.S. power plants. Magnesia transportation distances are
based on the distances from existing producers to the midwestern loca-
tion assumed for the power plant (Chicago is used as the transportation
point). Gabbs, Nevada, is the only U.S. site for commercial magnesite
mining. Sulfur is assumed to be shipped from Port Sulphur, Louisiana.
The transportation distances and methods are:
Miles Method
Limestone 32 Truck
Dolomite 250 Rail
Magnesia from magnesite 120/1,700 Truck/rail
Magnesia from seawater 825 Rail
Sulfur 1,349 Water
Limestone
In the quarrying operation an overburden plus spoil ratio of 0.2 tons
to 1.0 ton of limestone is used. Drilling is assumed to require 4 hp-
hours per ton of limestone. Blasting is assumed to require 2.2 pounds
of 30,000 Btu per pound of explosive per ton of limestone. A 90 Ib/ft^
bulk density for the quarry-run product is used. Hauling to the processing
plant conveyor by the 250-hp front loader is based on a rate of 20 yd3
per hour of quarry-run product.
Limestone processing, consisting of crushing and screening, is
based on the limestone processing plant described in the Systems Estimated
section. The energy requirements are based on the electrical consumption
of the equipment.
Lime Calcination
The onsite lime calcination energy requirements are based on the
energy consumption of the calcination plant described in the Systems
Estimated section. The fuel used is the same coal used in the power
plant. The fuel consumption is 6 MBtu per ton of lime. Electricity
use is determined in the same manner as the FGD electricity use.
Magnesia From Magnesite
The magnesia from magnesite energy requirements are based on an
overburden plus gangue ratio of 1.75 tons per ton of magnesite mined.
Drilling and blasting energy is assumed to be the same for overburden,
gangue, and ore. Drilling requirements are 0.2 gallons of diesel fuel
per ton of material, or 0.55 gallons per ton of magnesite. Blasting
energy is based on 2.2 pounds of 30,000 Btu per pound explosive per ton
of material, or 6.05 pounds per ton of magnesite. The mine haul condi-
tions are assumed to be the same as the quarry haul conditions used for
limestone.
26
-------
Processing energy requirements are based on the magnesia production
plant described in the Systems Estimated section. Diesel fuel is used
as the dryer and furnace fuel,
Magnesia From Seawater
The dolomite quarrying energy requirements are assumed to be the
same as those determined for limestone quarrying. A ratio of 60 tons of
dolomite shipped to 13 tons of magnesia produced is used. The magnesia
production energy requirements are based on the process described in the
Systems Estimated section.
Byproduct Sulfuric Acid Energy Credit
The energy credit for sulfuric acid is based on the net energy
consumed to produce an equivalent quantity of sulfuric acid from Frasch-
mined sulfur. The customary ratio of 0.3 long tons (0.268 short tons)
of sulfur to 1.0 short ton of sulfuric acid is used.
The energy requirements for Frasch mining are based on the use of
5,000 gallons of 330 F water per long ton of sulfur. The water is
assumed heated from 70 F with an overall boiler and thermal transfer
efficiency of 70%. Natural gas with a 1,000 Btu/ft^ gross heating value
(920 Btu/ft net heating value) is used as the fuel.
The energy requirements for conversion of the sulfur to sulfuric
acid are based on the electrical requirements of a typical dual-absorption
contact sulfuric acid plant of 67 kWh per short ton of sulfuric acid
(Chemical Construction Corporation, 1970). These energy requirements
are reduced by the heat generated and used in the sulfuric acid plant
complex. A value of 2.4 MBtu per short ton of sulfuric acid is used.
This energy is subtracted from the total mining, transportation, and
manufacturing energy consumption to determine the energy credit.
27
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SYSTEMS ESTIMATED
Each system estimate is prepared from the process description,
material balance, flow and control diagrams, layout drawings, and
equipment requirements which have been developed from vendor informa-
tion, industry experience, and the premises described in the previous
section. For equitable comparison, an area-by-area format has been used
which divides each system into similar processing steps. Investment
summaries are based on equipment lists which follow the area-by-area
pattern. Material costs are shown in mid-1979 dollars for each item.
The material balance and equipment list are also used in the preparation
of the revenue requirements. Processes for the production of limestone,
lime, magnesia from magnesite, and magnesia from seawater are included
because their energy requirements are part of the ground-to-ground
energy evaluation.
LIMESTONE SLURRY PROCESS
The flow diagram for the limestone slurry process is shown in
Figure 1. The plot plan is shown in Figure 2. Plan and elevations of
the FGD system are shown in Figure 3. A control diagram is shown in
Figure 4.
Delivered limestone, crushed and screened to 0 x 1-1/2 inches at
the quarry and containing 90% CaCO , is unloaded by conveyor and stored
in a 30-day stockpile located about 150 feet from the crushing and
grinding facilities. The limestone is reduced to about 0 x 3/4 inches
using gyratory crushers, wet-ground to 70% minus 200 mesh in 2 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
system about 1,500 feet from the limestone preparation area. In the
absorber recirculation tank makeup limestone slurry is diluted to 15%
solids with scrubber effluent slurry and recycled pond water.
A common plenum is situated downstream from the ESP units and the
power plant ID fans to distribute the gas to the absorbers. Booster
fans are placed between the plenum and the absorber to compensate for
the pressure drop created by the FGD system.
Flue gas is cooled to 127°F to 130°F in a presaturator using
recycled slurry before entering the mobile-bed absorbers. Limestone
slurry, circulating through the absorbers in countercurrent flow to the
cooled flue gas, reacts with the SO . The scrubbers are operated at a
28
-------
STEW FMH
STUM PLANT
1
Figure 1. Limestone slurry process. Base-case flow diagram.
-------
LIMESTONE PILE
OJ
o
COAL
S T 0 R A G
LIMESTONE
PREPARATION
AREA
ROAD
Figure 2. Limestone slurry process. Base-case overall plot plan.
-------
ELECTROSTATIC ^POWER PLANT
PNCCIMTATORS ID FANS
DAMPER (TYP
WHERE SHOWN)
ABSONBER SYSTEM
FO FANS
SLUHMY ^CIRCULATION
PUMPS
PLAN
POWER PLANT-1 ABSORBER SYSTEM-1 PUMP ' RKIRCULATION
ID FAN
FD FAN
PUMP
TANK
ELEVATION
Figure 3. Limestone slurry process.
Mobile-bed scrubber system base-case plan and elevation,
31
-------
CO
ro
HOPPERS, FEEDERS > CONVEYORS
SEAL WATER
TTP rOK ALL
Figure 4. Limestone slurry process. Base-case control diagram.
-------
stoichiometry of 1.3 mols of CaCO per mol of sulfur removed. The
liquid to gas (L/G) ratio is 50 gallons per 103 actual ft3. The absorbers
are equipped with chevron entrainment separators with provisions for top
and bottom wash with fresh makeup water. Scrubber outlet gas is reheated
to 175°F by indirect steam heat before entering the stack plenum.
A bleedstream from the recirculation tank flows by gravity to the
pond feed tank and is pumped one mile to the disposal pond. The slurry
settles to a sludge of about 40% solids. Pond supernate is recycled to
the wet ball mills and to the absorber recirculation tank to maintain
closed-loop operation.
Major Process Areas
The limestone slurry process is divided into the following operating
areas:
1. Materials handling: Area equipment consists of hoppers and con-
veyors to unload limestone to a stockpile and convey it from the
stockpile to in-process storage. Rail and truck facilities are
provided.
2. Feed preparation: This area contains equipment to reduce limestone
to a 70% minus 200 mesh, and prepare a 60% solids slurry feed to
the scrubbers. Included are crushers, ball mills, tanks, agitators,
and pumps.
3. Gas handling; This area consists of one inlet flue gas plenum
interconnecting each of the four flue gas ducts which feed the
absorbers and four booster fans to compensate for the pressure
drop through the FGD system.
4. SOp absorption; Four mobile-bed absorbers, each with a presatu-
rator, recirculation tank, and pump are included.
5. Stack gas reheat; Equipment in this area consists of indirect
steam reheaters and soot blowers for the coal-fired cases. The
oil-fired case uses a direct oil-fired reheater that discharges
directly into the duct on each of the four trains.
6. Solids disposal; This area consists of an agitated pond feed
tank, a pond feed pump, transport lines, and a pond return pump.
Storage Capacity
Storage requirements for raw materials and surge capacities for in-
process streams are listed below.
33
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Limestone storage - 30-day stockpile
Crusher feed bin - 8 hours
Mills product tank - 20 minutes
Slurry feed tank - 8 hours
Pond feed tank - 1 hour
Recirculation tanks - 10 minutes each (includes sufficient capacity
for drain down during shutdown of the scrubbers)
A material balance for the base-case limestone process and a detailed
equipment list by area are given in Tables 17 and 18 respectively.
Solids Disposal
Waste slurry containing 15% solids is pumped to the sludge disposal
pond one mile from the FGD system. The solids settle to form a sludge
of 40% solids. For the base case (new, 500-MW plant burning 3.5% sulfur
coal) the line transporting slurry to the pond is a 12-inch, rubber-
lined, carbon steel pipe. A spare line to the pond is included. Both
lines are trenched. The return line from the pond is a 10-inch, unlined,
carbon steel pipe; no spare is included.
Pond Construction
Optimum pond size and depth, which minimizes the sum of land and
construction costs for each case, are calculated by computer, based on a
square configuration with a diverter dike three-fourths the length of
one side. A pond construction diagram is shown in Figure 5. The pond
is assumed to be constructed on flat land using fill excavated from the
impoundment area for the dikes and lining. A 12-inch lining of impervious
clay is provided from local sources. Total pond depth for the base case
is 19.6 feet with an excavation depth of 3.0 feet. Pond areas for each
case variation are listed in Table 19.
LIMESTONE PRODUCTION
The limestone quarry evaluated in this study is assumed to be a
typical operation involving drilling, blasting, materials handling,
crushing, and sizing. A flowsheet for the limestone production plant
evaluated is shown in Figure 6.
LIME SLURRY PROCESS
The lime slurry process (shown in Figures 7, 8, 9, and 10) is
similar to the limestone process except for details of absorbent prepara-
tion and process chemistry. Pebble lime is stored in silos sized for 14
days storage and conveyed to an 8-hour process silo which supplies the
slakers. The lime is slaked with freshwater and diluted to a 15%
solids slurry with recycled pond water in the slaker tank. A slurry
feed tank provides 6 hours of storage from which the lime slurry is
pumped to recirculation tanks located under the SO absorbers.
34
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TABLE 17. LIMESTONE SLURRY PROCESS
MATERIAL BALANCE
Stream No.
Description
1
2
i
'.
ri
h
7
K
9
1°
Total stream, Ib/hr
sftj/min (60°F)
Temperature, °F
Bom
Soecific eravitv
DH
Undissolved 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
4,516,000
958,000
890
5
Gas to
air heater
4.516.100
958.000
890
Stream No.
Description
1
2
!
4
i
ft
7
8
9
Iff
Total stream, Ib/hr
sft^/min (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
pH
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
5,107,400
1,127,000
127
9
Gas to stack
5,107,400
1,129,000
175
10
Steam to
reheater
93,058
470
500
Stream No,
Description
1
2
)
4
3
ft
7
8
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temoerature. °F
Pressure. csig
a om
Specific gravity
DH
Undissolved solids. %
11
Recycle slurry
for saturation
2,801,100
5,088
1.1
5.3
15
12
Makeup water
to absorber
291,600
583
13
Recycle slurry
to absorber
35,014,000
63,602
1.1
5.3
15
U
Overflow to
pond feed tank
368,300
669
1.1
15
15
Slurry to pond
368,300
669
1.1
15
Stream No.
Description
1
2
1
4
b
ft
/
8
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psig
epm
Specific gravity
PH
Undissolved solids, %
16
Settled sludge
138,100
209
1.32
40
17
Pond water to
wet ball mill
26,600
53
18
Pond water to
recirculation
tank
203,600
407
19
Limestone to
weigh feeder
45,500
20
Slurry to
mills product
tank
72,000
89
1.61
60
(continued)
35
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TABLE 17 (continued)
1
1
!
/,
",
(>
/
H
9
Stream No.
Description
Total stream, Ib/hr
sftj/min (60°F)
Temperature, °F
Pressure, osie
Specific eravitv
Pll
21
Limestone
slurry to
recirculat ion
tank
72,000
89
1.61
H
9
1Q
H
q
10
IU
36
-------
TABLE 18. LIMESTONE SLURRY PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area
1 — Materials Handling
Item No.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Car shaker
Car puller
Hopper, limestone
unloading
Feeder, limestone
unloading
Conveyor, lime-
stone unloading
Conveyor, lime-
stone stocking
(incline)
Conveyor, lime-
stone stocking
Tripper
Mobile equipment
Hopper, reclaim
1
1
1
1
1
1
1
1
1
2
Description
Top mounting with crane
25 hp with 5 hp return
12 ft x 20 ft x 2 ft bottom,
20 ft deep, 2,400 ft3, carbon
steel
Vibrating pan, 42 in. wide x
60 in. long, 3 hp, 250 tons/hr
Belt, 36 in. wide x 10 ft long,
5 hp, 250 tons/hr, 130 ft/min
Belt, 36 in. wide x 320 ft
long, 30 hp, 15° slope, 250
tons/hr, 130 ft/min
Belt, 36 in. wide x 200 ft long,
7-1/2 hp, 250 tons/hr, 130
ft/min
5 hp, 30 ft/min
Dozer, 140 hp
7 ft x 7 ft x 4 ft deep, 60°
Total material
cost, 1979 $
19,900
46,300
5,400
4,400
2,700
103,700
54,400
21,200
55,300
800
11. Feeder, live
limestone storage
12. Pump, tunnel sump
13. Conveyor, live
limestone feed
slope, carbon steel
Vibrating pan, 24 in. wide x
40 in. long, 1 hp, 12 tons/hr
Vertical, 60 gpm, 70 ft head,
5 hp, carbon steel, neoprene
lined
Belt, 30 in. wide x 100 ft
long, 2 hp, 100 tons/hr, 60
ft/min
(continued)
6,500
3,900
22,800
37
-------
TABLE 18 (continued)
14.
15.
16.
17.
18.
19.
Area
1.
2.
3.
4.
5.
Item No.
Conveyor, live 1
limestone feed
(incline)
Elevator, live 1
limestone feed
Bin, crusher 1
feed
Dust collecting 1
system
Dust collecting 1
system
Dust collecting 1
system
Subtotal
2 — Feed Preparation
Item No.
Discharge, feed 2
bin
Feeder, crusher 2
Crusher 2
Ball mill 2
Ball charge
Hoist 1
Description
Belt, 30 in. wide x 190 ft
long, 5 hp, 35 ft lift, 100
tons/hr, 60 ft/min
Continuous bucket, 12 in. x
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,
carbon steel
Cyclone, 2,100 aft^/min, motor
driven fan
Cyclone, 6,200 aft^/min, motor
driven fan
Bag filter, polypropylene bag,
14,400 aft3/min, automatic shaker
system (1/2 cost in feed prepara-
tion area)
Description
Vibrating, 12 tons/hr, w/cover,
carbon steel
Weigh belt, 18 in. wide x 4 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 tons
Total material
cost, 1979 $
47,500
24,300
6,000
5,900
11,400
10,000
452,400
Total material
cost, 1979 $
8,600
9,800
49,300
394,300
20,100
7,900
(continued)
38
-------
TABLE 18 (continued)
Item
6. Tank, mills
product
Lining
7. Agitator, mills
No. Description
1 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
1 36 in. dia, 10 hp neoprene
Total material
cost, 1979 $
1,000
900
14,100
product tank
8. Pump, mills
product tank
9. Tank, slurry
feed
Lining
10. Agitator, slurry
feed tank
11. Pump, slurry
feed tank
12. Dust collecting
system
13. Dust collecting
system
Subtotal
coated
Centrifugal, 89 gpm, 60 ft head,
7-1/2 hp, carbon steel,
neoprene lined
18 ft dia x 22 ft high, 42,800
gal, open top, four 18 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
3 turbines, 72 in. dia, 75 hp,
neoprene coated
Centrifugal, 89 gpm, 60 ft head,
7-1/2 hp, carbon steel, neoprene
lined
Cyclone, 7,200 aft3/min, motor
driven fan
Bag filter, polypropylene bag,
14,400 aft3/min, automatic shaker
system, (1/2 cost in materials
handling area)
4,200
8,300
7,400
64,900
4,200
12,500
10,000
617,500
Area 3—Gas Handling
Item
No.
Description
Total material
cost, 1979 $
1. Fans
Forced draft, 13 in., 890 rpm,
1,250 hp, fluid drive, double
width, double inlet
Subtotal
812.000
812,000
(continued)
39
-------
TABLE 18 (continued)
Area 4—S02 Absorption
Item
No.
Description
Total material
cost, 1979 $
1. 862 absorber
2. Tank, recircula-
tion
Lining
3. Agitator, recircu-
lation tank
4. Pump, presatura-
tor
5. Pump, makeup
water
6. Pump, slurry
recirculation
7. Soot blowers
Subtotal
10
40
Mobile bed, 31 ft long x 14 ft
wide x 40 ft high, 1/4 in.
carbon steel, neoprene lining;
316 stainless steel grids,
nitrile foam spheres, FRP spray
headers, 316 stainless steel
chevron vane entrainment
separator
34 ft dia x 26 ft high, 173,500
gal, open top, four 34 in. wide
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
100 in. dia, 50 hp, neoprene
coated
Centrifugal, 1,274 gpm, 105 ft
head, 75 hp, carbon steel,
neoprene lined
Centrifugal, 1,168 gpm, 150 ft
head, 75 hp, carbon steel
Centrifugal, 7,954 gpm, 105 ft
head, 500 hp, carbon steel,
neoprene lined
Air, retractable
3,274,100
84,300
73,000
197,400
40,900
15,200
362,400
260,000
4,307,300
Area 5—Reheat
Item
No.
Description
Total material
cost, 1979 $
1. Reheater
Steam, tube type, 3,600 ft2, one-
half of tubes made of Inconel
625 and one-half made of Cor-Ten
(continued)
40
856,000
-------
TABLE 18 (continued)
Item
No.
Description
Total material
cost, 1979 $
2. Soot blowers
Subtotal
20 Air, retractable
130.000
986,000
Area 6—Solids Disposal
Item
No.
Description
Total material
cost, 1979 $
1. Tank, pond feed
Lining
2. Agitator, pond
feed tank
3. Pumps, pond feed
4. Pumps, pond
return
Subtotal
13 ft dia x 26 ft high, 25,800
gal, open top, agitator supports,
four 13 in. baffles, carbon steel
1/4 in. neoprene lining
2 turbines, 52 in. dia, 7-1/2 hp,
neoprene coated
Centrifugal, 669 gpm, 100 ft head,
50 hp, carbon steel, neoprene
lined
Centrifugal, 458 gpm, 100 ft head,
30 hp, carbon steel
7,500
5,900
12,000
11,200
7,100
43,700
41
-------
OUTER BOUNDARY
OF POND AREA
'20'
GROUND LEVEL
IO% FREE BOARD
TDPSOL EXCAAT10N
(I FT)
/Y ,
^ CIIR«r>ll
DEPTH OF SLUDGE
_L TOTAL
EXCAVATION DEPTH
POND PERIMETER DIKE
SUBSOIL EXCAVATION
TOPSOC EXC/SVATION
11 FT.)
ORGINAL GROUND LEVEL
SUBSOIL EXCAVATION
POND OIVERTER DIKE
10% FREE BOARD
(TYP OTHER SIDE)
DEPTH OF SLUDGE
i_ TOTAL
EXCAVATION DEPTH
Figure 5. Pond construction diagram.
-------
TABLE 19. LIMESTONE SLURRY PROCESS
ACREAGE REQUIRED FOR WASTE SOLIDS DISPOSAL
Years
remaining
Case life Acres
Coal-Fired Power Unit
1.2 Ib S02/MBtu emission
200 MW Ea 3.5% sulfur 20 79
200 MW Nb 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
1000 MW E 3.5% sulfur 25 383
1000 MW N 3.5% sulfur 30 480
90% S02 removal
500 MW N 3.5% sulfur 30 329
Oil-Fired Power Unit
0.8 Ib S02/MBtu emission
500 MW E 2.5% sulfur 25 110
a. E is existing coal-fired unit.
b. N is new coal-fired unit.
43
-------
Figure 6. Limestone mining and processing flow diagram.
-------
STORAGE
SILO
ELEVATOR
ELECTROSTATIC
meamaon
A9H TO NSPOSAL
LIME
STORAGE
SILO
/
V
0 0«
RECLAIM X
CONVEYOR
LIVE LIME J?.|5|
FEED "ELTS
ELEVATOR
SLAKE RS
\
» 1
*-
AMORKR
FO
FAN
tECIMCULATION
TANK
SLUmtY
FEED
TANK
1
SETTLING POND
Figure 7. Lime slurry process. Base-case flow diagram.
-------
COAL STORAGE
ROAO
SERVICE
BUILDING
500MW UNIT
TURBINE
ROOM
BOILER
ROOM
FUTURE
FUTURE
I
ROAD
Figure 8. Lime slurry process. Base-case overall plot plan.
46
-------
ELEVATION
Figure 9. Lime slurry process. Mobile-bed
scrubber system base-case plan and elevation.
47
-------
STORAGE
SILO
ELEVATOK
Figure 10. Lime slurry process. Base-case control diagram.
-------
Flue gas is cooled to 127°F to 130°F in a presaturator with slurry
from the scrubber system before entering the mobile-bed absorbers. A
recirculating slurry of lime and reacted calcium salts flows through the
absorbers countercurrently to the cooled flue gas to react with and
remove the SO . The stoichiometry is 1.05 mols of CaO per mol of sulfur
removed. The L/G ratio is 45 gallons per 1CH actual ft^. Absorber
design and reheat provisions are the same as the limestone process.
A bleedstream from the recirculation tank, consisting of CaSOo-l/2H20
and CaS04'2H20 with a small quantity of unreacted Ca(OH)2, is pumped one
mile to an earthen-diked, clay-lined pond where it settles to a sludge
of about 40% solids. Pond supernate is returned to the slaker and
recirculation tanks to maintain closed-loop operation.
Major Process Areas
The lime process is divided into the following areas:
1. Materials handling; This area contains equipment for receiving
pebble lime, a lime storage silo, and in-process storage for
supply to the slakers.
2. Feed preparation: Area equipment consists of two parallel slaking
systems for producing a lime slurry of 15% solids.
3. Gas handling! This area contains an inlet plenum, four booster
fans, and four ducts feeding the scrubbers.
4. S02 absorption; Four mobile-bed absorbers, each with presaturator,
mist eliminator, recirculation tank, and pump are included.
5. Stack gas reheat: Equipment in this area consists of indirect
steam reheaters and soot blowers for the coal-fired cases. The
oil-fired unit is designed with one direct oil-fired reheater
that discharges hot combustion gases directly into the duct on
each of the four trains.
6. Solids disposal; Equipment in this area consists of an agitated
pond feed tank, a pond feed pump, transport lines, and a pond
return pump.
Tables 20 and 21 show the material balance and detailed equipment list
by area for the base case.
Storage Capacities
Storage requirements for raw materials and surge capacities for in-
process streams are listed below.
49
-------
TABLE 20. LIME SLURRY PROCESS
MATERIAL BALANCE
Stream No.
Description
2
1
4
',
ft
7
8
<)
10
Total stream, Ib/hr
aft-Vain (6
1
4
5
h
7
8
9
IP,
Total stream, Ib/hr
s£t3/min (60°F)
Temperature. °F
Pressure. psiE
earn
Specific gravity
_EH
Undissolved solids. %
11
Recycle slurry
for saturation
2.651,800
4,817
1.1
5.3
15
12
Makeup water
to absorber
244,279
488
13
Recycle slurry
to absorber
29,832,300
54,190
1.1
5.3
15
14
Overflow to
pond feed tank
306,400
557
1.1
5.3
15
15
Slurry to pond
306,400
597
1.1
5.3
15
Stream No.
Description
1
1
1
4
•i
h
/
H
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psig
Rpm
Specific eravitv
PH
Undissolved solids. %
16
Settled sludge
1 14,400
174
1.32
40
17
Pond water
to slaker
120,400
242
18
Pond water
Co recirculatlon
tank
77,115
154
19
Lime to
weigh feeder
19,625
20
Makeup water
to slaker
46,288
81
(continued)
50
-------
TABLE 20 (continued)
Description
I
2
)
t>
h
7
K
9
JO
Total stream. Ib/hr
^ sf t^/min (60°F)
Temperature, °F
Pressure, psig
gpro
Specific gravity
PH
Undissolved solids, %
21
Lime slurry
:o recircula t ion
tank
161.152
293
1.1
15
H
9
10
h
]T
H
|T
10
51
-------
TABLE 21. LIME SLURRY PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area
1.
2.
3.
4.
5.
6.
7.
8.
Area
1.
1 — Materials Handling
Item No.
Conveyor , lime ]
unloading
(enclosed)
Elevator, lime 1
storage silo
Silo, lime 1
storage
Feeder, reclaim 1
Conveyor, live lime 1
feed (enclosed)
Elevator, live 1
lime feed
Bin, feed 2
Dust collecting 1
system
Subtotal
2 — Feed Preparation
Item No.
Feeder, lime bin 2
discharge
Description
Belt, 24 in. wide x 1500 ft
long, 30 hp, 100 tons/hr,
200 ft/min
Continuous, bucket 16 in. x
8 in. x 11-3/4 in., 75 hp,
130 ft lift, 100 tons/hr,
160 ft/min
47 ft dia x 69 ft straight side
height, 3/8 in. carbon steel
Vibrating pan, 16 in. wide x
60 in. long, 3-1/2 hp, 40 tons/hr
Belt, 18 in. wide x 100 ft long,
2 hp, 40 tons/hr, 150 ft/min
Continuous, bucket 12 in. x 6
in. x 11-3/4 in., 40 hp, 50 ft
lift, 40 tons/hr, 160 ft/min
with diverter gate
11 ft dia x 15 ft straight side
height, w/cover, carbon steel
Polypropylene bag type, 2200
aft3/min, 7-1/2 hp, (1/2 cost in
material handling area)
Description
Vibrating, 3-1/2 hp, carbon
steel
(continued)
52
Total material
cost, 1979 $
307,500
35,400
81,000
3,300
19,500
18,900
7,700
3,100
476.400
Total material
cost, 1979 $
6,600
-------
TABLE 21 (continued)
Item
No.
Description
Total material
cost, 1979 $
2. Feeder, slaker
3. Slaker
4. Tank, slaker
product
Lining
5. Agitator, slaker
product tank
6. Dust collecting
system
7. Pump, slaker
product tank
8. Tank, slurry feed 1
Lining
9. Agitator, slurry
feed tank
10. Pump, slurry feed
tank
Subtotal
Screw, 12 in. dia x 12 ft long,
1 hp, 6 tons/hr
8 ft wide x 31 ft long, 5 hp,
slaker, 2-1/2 hp classifier,
5 tons/hr
8 ft dia x 12 ft high, 4,512
gal, open top, four 8 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
2 turbines, 32 in. dia, 5 hp,
neoprene coated
Polypropylene bag type, 2,200
aft3/min, 7-1/2 hp (1/2 cost in
material handling area)
Centrifugal, 131 gpm, 60 ft head,
5 hp, carbon steel, neoprene
lined
19 ft dia x 37 ft high, 172,500
gal, open top, four 39 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
2 turbines, 76 in. dia, 50 hp,
neoprene coated
Centrifugal, 65 gpm, 60 ft head,
2 hp, carbon steel, neoprene
lined
5,200
47,100
7,400
3,500
18,100
3,000
8,000
17,500
18,600
49,400
10.100
194,500
(continued)
53
-------
TABLE 21 (continued)
Area 3—Gas Handling
Item
No.
Description
Total material
cost, 1979 $
1. Fans
Subtotal
Forced draft, 13 in., 890 rpm,
1,250 hp, fluid drive, double
inlet
812,000
812,000
Area 4—S02 Absorption
Item
No.
Description
Total material
cost. 1979 $
1. SC>2 absorber
2. Tank, recircula-
tion
Lining
3. Agitator, recir-
culation tank
4. Pu«p, presatura-
tor
Pump, makeup
water
Pump, slurry
recirculation
10
Mobile bed, 31 ft long x 14 ft
wide x 40 ft high, 1/4 in.
carbon steel, neoprene lining;
316 stainless steel grids,
nitrile foam spheres, FRP spray
headers, 316 stainless steel
chevron vane entrainment
separator
31 ft dia x 23 ft high, 129,900
gal, open top, four 31 in. wide
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
12 in. dia, 50 hp, neoprene
coated
Centrifugal, 1,272 gpm, 105 ft
head, 75 hp, carbon steel,
neoprene lined
Centrifugal, 1,066 gpm, 150 ft
head, 75 hp, carbon steel
Centrifugal, 7,155 gpm, 105 ft
head, 400 hp, carbon steel,
neoprene lined
(continued)
3,274,100
68,100
68,700
191,800
40,900
27,300
167,300
54
-------
TABLE 21 (continued)
Item No.
7. Soot blowers 40
Subtotal
Description
Air, retractable
Total material
cost, 1979 $
260,000
4,098,200
Area 5 — Reheat
Item No.
1 . Reheater 4
2. Soot blowers 20
Subtotal
Description
Steam, tube type, 3,600 ft2, one-
half of tubes made of Inconel
625 and one-half made of Cor-Ten
Air, retractable
Total material
cost, 1979 $
856,000
130,000
986,000
Area 6 — Solids Disposal
Item No.
1. Tank, pond feed 1
Lining
2. Agitator, pond 1
Description
17 ft dia x 23 ft high, 40,400
gal, open top, agitator supports,
four 17 in. baffles, carbon steel
1/4 in. neoprene lining
2 turbines, 48 in. dia, 7-1/2 hp,
Total material
cost, 1979 $
6,100
5,800
12,000
feed tank
3. Pumps, pond feed
4. Pumps, pond
return
Subtotal
neoprene coated
Centrifugal, 553 gpm, 100 ft
head, 30 hp, carbon steel,
neoprene lined
Centrifugal, 393 gpm, 100 ft
head, 20 hp, carbon steel
9,500
8,500
41,900
55
-------
Lime storage silo - 14 days
Slurry feed tank - 8 hours
Recirculation tanks - 10 minutes (including drain down)
Pond feed tank - 1 hour
Solids Disposal
Waste solids disposal in the lime process is handled in the same
manner as the limestone process.
Pond Construction—
Pond designs are the same as 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 are listed in Table 22.
LIME PRODUCTION
The flow diagram and control diagram for production of lime from
limestone are shown in Figures 11 and 12. The same lime production
process is used in commercial lime manufacture although the commercial
lime plants are generally designed for higher production rates than the
consumption of a single power plant using lime scrubbing.
Lime is produced from limestone by thermal decomposition (calcination)
in the following reaction.
heat
CaC03 -*• CaO + C02 +
Coal, oil, or natural gas may be used as the fuel for calcining.
The process described uses coal. For the oil-fired case variation a
more efficient oil-fired annular shaft kiln process is used. The
annular shaft kiln cannot be used with coal, however.
For onsite production of lime from limestone the process area is
located adjacent to the power plant. Limestone and coal are unloaded
and conveyed to stockpiles. From these they are transferred by conveyor
to the lime process feed bins. The coal is crushed in a hammer mill
prior to pulverizing in an air-swept ball mill.
The coal dust formed in the ball mill is entrained in the air and
blown to a classifier. The larger particles from the classifier are
returned to the ball mill for further reduction. The air-swept fine
coal dust from the classifier is blown by the ball mill exhaust fan into
the combustion chamber of the limestone calciner.
56
-------
TABLE 22. LIME SLURRY PROCESS ACREAGE
REQUIRED FOR WASTE SOLIDS DISPOSAL
Years
remaining
Case life Acres
Coal-Fired Power Unit
1.2 Ib SO /MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 72
200 MW N 3.5% sulfur 30 123
500 MW E 3.5% sulfur 25 198
500 MW N 2.0% sulfur 30 136
• 500 MW N 3.5% sulfur 30 240
500 MW N 5.0% sulfur 30 353
1000 MW E 3.5% sulfur 25 346
1000 MW N 3.5% sulfur 30 430
90% SO- removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 277
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 96
57
-------
CRANE
Ln
00
HOPPERS, FEEDERS AND CONVEYORS
HOPPERS, FEEDERS AND CONVEYORS
Figure 11. Lime from limestone. Base-case flow diagram.
-------
t_n
Figure 12. Lime from limestone. Base-case control diagram.
-------
The limestone is fed through a preheater to a rotary kiln calciner
operating in the temperature range of 2000 F-2400 F. The lime product
is discharged from the calciner to a fluid-bed cooler and transferred to
a storage silo as shown in Figure 13. Dust recovery equipment and a
waste heat boiler are included in the calciner exhaust gas system. The
base-case calcination process is designed for approximately 240 tons of
lime production per day. The material balance for the base-case condi-
tions is shown in Table 23.
The lime from limestone process consists of two major areas—
materials handling and calcining. The equipment requirements and costs
for these areas are described in Table 24.
Storage Capacities
Storage requirements for raw materials and allowance for in-process
streams are listed below.
Raw materials
Limestone storage - 30-day stockpile
Coal storage - 30-day stockpile
In-process
Coal feed bin - 24 hours
Limestone feed bin - 12 hours
Lime dust bin - 8 hours
Lime storage silo - 14 days
Feed bin - 8 hours
MAGNESIA PROCESS
The magnesia process scrubbing system is similar to the limestone
and lime slurry processes. The process includes a chloride prescrubber
not needed in the waste-producing processes, however. The more fundamental
differences are in processing of the spent scrubbing slurry. The scrubber
effluent is dried and calcined to produce magnesia for reuse and SO
which is processed to sulfuric acid.
The flow diagram for the magnesia process is shown in Figure 14.
The control diagram, plot plan, and scrubber system design are shown in
Figures 15, 16, and 17. Makeup and recycled MgO is pneumatically conveyed
to 30-day storage silos. Vibrating screw feeders transfer makeup and
recycled MgO from 8-hour capacity, in-process feed bins to the preslaker
mixer where freshwater is added to wet the MgO thus allowing better
mixing in the slaking tank. Residence time in the mixer is only about 2
minutes to prevent solidification of the concentrated mix. Using centrate
from the centrifuges, slaking is completed in the slaking tank, which
acts as a heat sink for the exothermic reaction, and the Mg(OH) slurry
of about 15% solids is pumped to the absorbers.
60
-------
IMSTC HCXT
SOI LEX
ELEVATION
Figure 13. Lime from limestone. Base-case plan and elevation.
-------
TABLE 23. LIME FROM LIMESTONE
MATERIAL BALANCE
Stream No.
Description
1
2
)
4
h
7
K
9
10
Total stream, Ib/hr
sft^/min (60°F)
Temperature, °F
Pressure, psle
epm
Specific eravitv
pH
Undissolved solids Z
1
Coal to
ball mill
5,607
2
Kiln
combustion air
49,081
10,800
80
3
Limestone
to feed bin
36,973
4
Lime to
contact cooler
18,520
1,900
5
Kiln off-gas to
dust collector
54,829
10,700
550
Description
1
>
1
/4
r,
h
1
8
9
Total stream, Ib/hr
sft^/min (60°F)
Temperature, °F
gpm
Specific gravity
PH
Undissolved solids, %
6
Mechanical
collector lime
dust to elevator
1 ,646
7
Kiln off-gas
to baghouse
53, 101
10,700
300
Lime dust
to dust bin
2,139
h
7
H
9
10
62
-------
TABLE 24 . LIME FROM LIMESTONE
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area
1.
2.
1 — Materials Handling
Item No.
Car shaker, 1
limestone
Car puller, 1
limestone
Description
Top mounting with crane
25 hp with 5 hp return
Total material
cost, 1979 $
19,900
46,300
3. Hopper, limestone
unloading
4. Feeder, limestone
unloading
5. Conveyor, lime-
stone unloading
6. Conveyor, lime-
stone stocking
(incline)
7. Conveyor, lime-
stone stocking
8. Tripper
9. Mobile equipment
10, Hopper, limestone
reclaim
11. Feeder, live
limestone storage
12. Pump, tunnel
sump
13. Conveyor, live
limestone storage
12 ft x 20 ft x 2 ft bottom,
20 ft deep, 2400 ft3, carbon
steel
Vibrating pan, 42 in. wide x
60 in. long, 3 hp, 250 tons/hr
Belt, 36 in. wide x 10 ft long,
5 hp, 250 tons/hr, 130 ft/min
Belt, 36 in. wide x 200 ft long,
50 hp, 20° slope, 250 tons/hr,
130 ft/min
Belt, 36 in. wide x 200 ft long,
7-1/2 hp, 250 tons/hr, 130
ft/min
5 hp, 30 ft/min
Dozer, 140 hp
7 ft x 7 ft, 4 ft deep, 60°
slope, carbon steel
Vibrating pan, 24 in. wide x
40 in. long, 1 hp, 12 tons/hr
Vertical, 60 gpm, 70 ft head,
5 hp, carbon steel, neoprene
lined
Belt, 30 in. wide x 100 ft long,
2 hp, 100 tons/hr, 60 ft/min
(continued)
5,400
4,400
2,700
62,600
54,400
21,200
55,300
800
6,500
3,900
22,800
63
-------
TABLE 24 (continued)
Item
No.
Description
Total material
cost, 1979 $
14. Conveyor, live 1
limestone feed
(incline)
15. Car shaker, coal 1
16. Car puller, coal 1
17. Hopper, coal 1
unloading
18. Feeder, coal 1
unloading
19. Conveyor, coal 1
unloading
20. Conveyor, coal 1
stocking
(incline)
21. Conveyor, coal 1
stocking
22. Tripper 1
23. Hopper, coal 2
reclaim
24. Feeder, coal 2
reclaim
25. Pump, tunnel 2
sump
26. Conveyor, coal
feed
27. Conveyor, coal
feed (incline)
Belt, 30 in. wide x 305 ft long,
15 hp, 20° slope, 100 tons/hr,
60 ft/min
Top mounting with crane
25 hp with 5 hp return
12 ft x 20 ft x 2 ft bottom,
20 ft deep, 2400 ft3, carbon
steel
Vibrating pan, 42 in. wide x
60 in. long, 3 hp, 250 tons/hr
Belt, 36 in. wide x 10 ft long,
5 hp, 250 tons/hr, 130 ft/min
Belt, 36 in. wide x 200 ft long,
25 hp, 20° slope, 250 tons/hr,
130 ft/min
Belt, 36 in. wide x 40 ft long,
2 hp, 250 tons/hr, 130 ft/min
5 hp, 30 ft/min
7 ft x 7 ft, 4 ft deep, 60°
slope, carbon steel
Vibrating pan, 24 in. wide x
40 in. long, 1 hp, 12 tons/hr
Vertical, 60 gpm, 70 ft head,
5 hp, carbon steel, neoprene
lined
Belt, 14 in. wide x 90 ft long,
3 hp, 22 tons/hr, 100 ft/min
Belt, 14 in. wide x 190 ft
long, 5 hp, 20° slope, 3 tons/hr
30 ft/min
(continued)
48,000
19,900
46,300
5,400
4,400
2,700
87,000
11,800
21,200
800
6,500
3,900
16,800
28,600
64
-------
TABLE 24 (continued)
Item
No.
Description
Total material
cost, 1979$
28. Bin, coal feed
Subtotal
13 ft dia x 21 ft straight side
height, w/cover, carbon steel
6,100
637,600
Area 2—Limestone Calcination
Item
No.
Description
Total material
cost, 1979 $
1. Feeder, coal
2. Crusher, coal
3. Ball mill, coal
Ball charge
4. Hoist
5. Classifier, coal
6. Fan, ball mill
exhaust
7. Bin, limestone
feed
8. Preheater, lime-
stone
9. Rotary kiln
10. Dust collector,
primary
11. Fan, dust
collection
Weigh belt, 24 in. wide, 1 hp,
3 tons/hr
Gyratory, Oxl in., 5 hp,
3 tons/hr
Air swept, 7 ft dia x 8-1/2 ft
long, 150 hp, 3 tons/hr
1 Electric, 5 tons
1 95% - 200 mesh, 3 tons/hr
1 Induced draft, 18 in., 50 hp
1 24 ft x 18 ft x 11 ft straight
side height, w/cover, carbon
steel
1 KVS counterflow, refractory
lined
1 10 ft dia x 160 ft long, 100 hp,
carbon steel
1 Cyclone, 19,800 aft^/min
1 Induced draft, 30 in., 150 hp
(continued)
5,400
10,000
105,000
7,000
7,900
7,500
4,100
70,000
225,700
618,100
25,000
7,800
65
-------
TABLE 24 (continued)
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
Item
Waste heat
boiler
Baghouse
Closed loop,
water system
Elevator, lime
dust
Bin, lime dust
Dust collector
Conveyor, lime
dust
Fan, cooler
Cooler, lime
Feeder, lime
cooler discharge
Conveyor, lime
storage (incline)
Elevator, storage
silo
Silo, lime
storage
Feeder , reclaim
No. Description
1 Tube type, 882 ft2, 316L
stainless steel
1 Fiberglass bag type, 15,600
af t^/min
1 Bearing oil cooling system
1 Centrifugal bucket, 5 in. x
3-1/2 in. x 6 in., 1/2 hp, 28 ft
lift, 1 ton/hr, 150 ft/min
1 7 ft dia x 11 ft straight side
height, w/cover, carbon steel
1 Bag filter, 1,100 aft3/min
1 Pneumatic, pressure, 10 hp
1 Forced draft, 20 in., 75 hp
1 12 ft dia, KVS contact cooler,
carbon steel
1 Disc, 36 in., 1/2 hp, 9 tons/hr,
carbon steel
1 Belt, 14 in. wide x 35 ft long,
1 hp, 15° slope, 10 tons/hr,
100 ft/min
1 Continuous, bucket 12 in. x 6
in. x 11-3/4 in., 75 hp, 130 ft
lift, 100 tons/hr, 160 ft/min
1 47 ft dia x 69 ft straight side
height, 3/8 in. carbon steel
1 Vibrating pan, 16 in. wide x
Total material
cost, 1979 $
23,700
200,000
12,000
4,300
2,300
5,500
43,000
2,900
55,300
12,000
8,900
28,400
81,000
3,300
26. Conveyor, live
lime feed
(enclosed)
60 in. long, 3-1/2 hp, 40
tons/hr
Belt, 18 in. wide x 100 ft long,
2 hp, 40 tons/hr, 150 ft/min
(continued)
66
19,500
-------
TABLE 24 (continued)
Item
No.
Description
Total material
cost, 1979 $
27. Elevator, live
lime feed
28. Bin, feed
29. Dust collecting
system
Subtotal
Continuous, bucket 12 in. x 6
in. x 11-3/4 in., 40 hp, 50 ft
lift, 40 tons/hr, 160 ft/min,
with diverter gate
11 ft dia x 15 ft straight side
height, w/cover, carbon steel
Polypropylene bag type, 2,200
aft3/min, 7-1/2 hp (1/2 cost in
feed preparation
18,900
7,700
3,100
1,625,300
67
-------
Figure 14. Magnesia process. Base-case flow diagram.
-------
Figure 15. Magnesia process. Base-case control diagram.
-------
COAL
STORAGE
D
O
OOO
ROAD
Figure 16. Magnesia process. Base-case overall plot plan.
70
-------
ELECTROSTATIC
PRECIPITATORS
WHERE SHOWN)
-POWER PLANT
10 FANS
^-ABSORBER SYSTEM
FD FANS
PLAN
SLURRY RECmcUL&TION
PUMPS
ELEVATION
Figure 17. Spray grid tower absorber system. Base-case plan and elevation.
71
-------
Duct arrangement for this process is the same as for the limestone
process. Four trains supplied by the common plenum, each with a booster
fan, are used. Flue gas is cooled and humidified and approximately 70%
of the chloride is removed in a venturi scrubber using recycle liquor of
a pH of about 1. The chloride remaining in the flue gas is removed in
a spray chamber with three banks of nozzles spraying perpendicularly
to the gas flow. Recycle liquor is sprayed from the first two banks of
nozzles and fresh makeup water is used in the third bank. From the
chloride recycle tank, a bleedstream of chloride-rich liquor overflows
to a neutralizing tank to which agricultural limestone is added. The
neutralized stream is pumped to the ash pond. A mist eliminator, placed
between the spray chamber and the SO- absorber, prevents carryover of
chlorides in entrained water.
The SO- absorber is a spray grid tower designed with a chevron
entrainment separator to prevent slurry and water entrainment in the
cleaned gas stream. Mg(OH)» slurry is circulated countercurrently to
the gas flow and reacts witn the S02 in the flue gas to form magnesium-
sulfur salts, predominately MgSO-j. Makeup slurry is added to the cir-
culation loop. The absorber effluent is collected in a recirculation
tank from which a bleedstream is pumped to the regeneration area.
The regeneration area is shown in Figures 18 and 19. Two parallel
centrifuges receive the 15% solids slurry effluent and concentrate about
90% of the solids to an 85% solids cake. Centrate from the centrifuges
is gravity fed to the centrate tank and is returned to the absorber and
feed preparation areas as needed. Cake from the centrifuges is dried in
a cocurrent oil-fired rotary dryer (Figure 19). A portion of the dryer
off-gas is recycled to the dryer combustion chamber for temperature
control and the remainder is returned to the plenum ahead of the absorber
to be scrubbed along with the flue gas. The solids discharged from the
dryer are transferred to storage.
The solids are calcined in a fluid-bed reactor at about 1600°F.
No. 2 fuel oil is used as the fuel. Reactor off-gas, containing MgO and
S02, flows through a cyclone separator which collects about 80% of the
MgO. The remaining solids are removed in a bag filter. The MgO col-
lected from the cyclones and bag filter is cooled in a rotary-tube
solids cooler and is pneumatically conveyed to the storage silos.
Cleaned reactor off-gas is cooled in a combustion air preheater and
a waste heat boiler. After the addition of air, the gas is fed to a
single contact acid unit (Figures 20 and 21) which produces 98% sulfuric
acid. A 30-day acid storage capacity is provided. Tail gas from the
acid plant is returned to the S02 absorber. A material balance for the
base-case magnesia process is shown in Table 25.
72
-------
RESERVE MtSOs STORAGE BUILDING
RECYCLE M»0
SILO
PRE SLAKE"
MIXER
RECYCLE M«0 STDRASE SILOS
.MAKE-UP MgO /^ l\ /^^^\
FEED SH-O / \ / i \
Vl^/
Figure 18. Magnesia process. Base-case plot plan
regeneration and acid production area.
73
-------
MAKE-UP M«0
STORAGE SILO
PRESUKE MIXER
SLURRY FEED TANK
RECYCI.E M«0 STORAGE
SOLIDS COOLER
Figure 19. Magnesia process. Regeneration area elevation.
-------
r-93% ACID COOLERS
Ul
nnr
SB* AC ID COOLERS
-93% ACID PUMP TANK
a PUMP
-PRODUCT ACID COOLERS
98% ACID PUMP TANK
a PUMP
V
^-PRODUCT a TRANSFER PUMP
- STRIPPING PUMP
CONVERTER
— CONVERTER
COOLING AIR
\ FAN
CONVERTER HEAT
EXCHANGER
-GAS PREHEATER
-MAIN GAS BLOWER
^START-UP FAN
Figure 20. Magnesia process. Base-case acid plant plan.
-------
93% DRYING TOWER
98% ABSORPTION TOWER
STRIPPING
TOWER
VENT
PRIMARY
HEAT EXCHANGERS
CONVERTER COOLING
AIR FAN
CONVERTER
HEAT EXCHANGER
GAS PREHEATER
Figure 21. Magnesia process. Base-case acid plant elevation.
-------
TABLE 25. MAGNESIA SLURRY - REGENERATION PROCESS
MATERIAL BALANCE
2
)
4
•,
h
7
8
9
1°
Stream No.
Description
sft-Vmin (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
PH
Undissolved solids, %
1
Coal to boiler
2
Combustion air
to air heater
1,005,000
80
3
Combustion air
to boiler
906,700
535
4
Gas to
economizer
958,000
890
5
Gas to
air heater
958,000
890
Stream No.
Descript ion
1
2
)
4
5
h
7
8
9
ifl
Total stream, Ib/hr
sftVmin (60UF)
Temperature, "F
Pressure, psig
Kpm
Specific eravitv
pH
Undissolved solids. %
6
Gas to
electrostatic
precipitator
4.960.400
1,056,000
300
7
Boiler flue gas
4.906,500
I,085j300
300
8
Combined gas to
S02 absorber
5,099,400
1,076,000
9
Gas to reheater
5,249,800
1,107,700
127
10
Cas to plenum
5,249,800
1,107,700
175
Stream No.
Description
1
2
J
4
5
h
/
H
9
IU
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psig
Kpm
Specific gravity
PH
Undissolved solids. I
11
Steam to
rehoater
96,650
470
500
12
Makeup water to
chloride
scrubber
194,000
388
13
Pond water
to chloride
recycle tank
158,700
317
1.0
14
Limestone
to chloride
neutralization
926
15
Slurry to
ash pond
182,000
362
1.0
0.1
Stream No .
1
2
1
4
b
h
/
8
9
10
Description
Total stream, Ib/hr
sft^/min (60°F)
Temperature, °F
Pressure, psig
Rpm
Specific gravity
PH
Undissolved solids, %
16
Makeup water
to S02 absorber
29,278
59
17
S02 absorber
effluent
7,137,800
12,966
1.1
15
18
Slurry to
centrifuge
'(97,100
903
1.1
15
19
Centrate
to recycle
416.100
835
1.0
' 2 '
20
Feed to dryer
7^,557
1.6
85
(continued)
77
-------
TABLE 25 (continued)
Stream No.
Description
1
2
\
/,
5
h
7
H
9
10
Total stream, Ib/hr
sftj/rain (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
pH
Jndissoived solids, %
21
Fuel oil
to dryer
4,787
11
0.91
22
Combustion air
to dryer
99,092
21,300
80
23
Dryer gas
to cyclone
48,000
400
24
Cyclone dust
to conveyor
4.469
25
Dryer off-gas
to S02 absorber
147.400
3 1 . 1 00
400
Description
1
•>
1
4
5
h
1
H
9
10-
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure . osift
Epm
Specific eravitv
PH
iinrfissolved solids. % 1
Entrained dust
to conveyor
5.257
Dryer produc t
to conveyor
29.787
250
Steam to fuel
oil heater
738
358
150
Fuel oil
to calciner
2.028
4
0.91
MgS03 to
calciner
".O.4.4.
Stream No.
Description
1
1
4
•>
h
7
H
4
Total stream, Ib/hr
sft^/min (60°F)
Temnerature, F
Pressure, psia
KPm
Specific gravity
DH
31
Calciner off-gas
1 1 . 000
1.600
Cyclone MgO
to solids
11.184
1,600
33
Calciner gas
to combustion
air preheat
55.234
11,000
1,600
34
Combustion air
to air
preheater
29,385
6,200
80
35
Water to waste
heat boiler
6,371
80
13
1.0
Stream No.
H
Description
sft^min (60bF)
Pressure, psifj
Kpm
Specific gravity
PH
Undissolved solids. %
36
Calciner gas
to bag filter
fTTooo
706
37
Quench air to
calciner gas
U.300
38
Gaa to
acid plant
25,300
39
Cooling water
to acid plant
' TjTs
40
Acid plant
off-gas
17.600
(continued)
78
-------
TABLE 25 (continued)
Stream No.
Description
1
!
)
/,
r,
f)
7
K
9
in
Total stream, Ib/hr
sft'/min (6CPF)
Temperature, °F
Pressure. psiE
Epm
Specific gravity
PH
Undlssolved solids, 7.
41
98% sulfurlc
acid to
storage tank
31,500
100
34
1.84
42
Water to
solids cooler
8,018
80
16
1.0
43
Recycle MgO
to conveyor
13,980
200
44
Miscellaneous
handling
losses
419
45
Water to
preslak'e mixer
8,616
80
17
1.0
Stream No.
Description
1
2
1
ri
(->
I
«
y
It)
Total stream, Ib/hr
sft3/min (60°K)
Temperature, °F
Pressure, psiR
EDITI
Specific gravity
oH
Undissolved solids, '/,
46
Recycle MgO
to preslake
mixer
13,561
47
Makeup MgO
to preslake
mixer
419
48
Centrate to
slaking tank
120,300
240
1.0
2
49
Mg(OH)2 slurry
to S02 absorber
142,900
260
1.1
15
II
1
t
I
6
7
H
~9~
10
6
/
H
9
10
79
-------
Major Process Areas
The magnesia process is divided into the following operating areas.
1. Materials handling; This area consists of unloading conveyors
storage silos, transfer conveyors, and feed bins for makeup MgO
and agricultural limestone.
2. Feed preparation: The equipment in this area consists of a
preslaker mixer, slurry feed tank, and an MgO slurry pump.
3. Gas handling; Fan location and duct configuration are the same
as those of the limestone slurry process.
4. S02 absorption: This area includes four spray grid tower absorbers
recirculation tanks, and pumps. '
5. Stack gas reheat; The equipment in this area consists of four
indirect steam reheaters and associated soot blowers for all
coal-fired cases. Oil-fired units have one direct-oil-fired
reheater per duct which discharges hot combustion gases directly
into the duct.
6. Chloride purge; This area includes four chloride prescrubbers
recirculation tanks, associated pumps, and a neutralization tank
and a limestone feeder.
7. Slurry processing; In this area are two centrifuges and a centrate
tank and pumps.
8. Drying; This area includes a rotary dryer, conveyors, an MgSO
storage building and silo, and a fuel storage tank. ^
9. Calcining: This area includes a fluid-bed calciner, heat transfer
equipment, and an MgO cooler and conveyor.
10. Acid production; This area consists of a battery limits single-
contact sulfuric acid unit.
11. Acid storage; This area consists of three storage acid tanks and
discharge pumps.
A description of the equipment items in each area is given in Table 26.
80
-------
TABLE 26. MAGNESIA SLURRY-REGENERATION PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area
1.
2.
3.
4.
1 — Materials Handling
Item
Conveyor, makeup
Mgo
Silo, makeup Mgo
storage
Bin, makeup MgO
feed
Feeder, makeup
No. Description
1 Pneumatic, pressure, 100 hp
1 26 ft dia x 41 ft straight side
height, w/cover, carbon steel
1 9 ft dia x 15 ft straight side
height, w/cover, carbon steel
1 Vibrating screw, 8 in. dia x
Total material
cost, 1979 $
80,000
23,400
3,100
5,500
MgO
5. Conveyor, recycle
MgO feed
6. Bin, recycle MgO
feed
7. Feeder, recycle
MgO
43 in. long, 1 hp, 900 ft3/hr,
419 Ib/hr
1 Pneumatic, pressure, 10 hp
9 ft dia x 15 ft straight side
height, w/cover, carbon steel
Vibrating screw, 8 in. dia x
43 in. long, 1 hp, 900 ft3/hr,
7 tons/hr
8. Car shaker 1
9. Conveyor, limestone 1
10. Silo, limestone 1
storage
11. Feeder, limestone 1
storage silo
discharge
12. Bin, limestone 1
feed
Subtotal
Top mounting with crane
Pneumatic, pressure, 75 hp
19 ft dia x 29 ft straight side
height, w/cover, carbon steel
Rotary stargate, 1 hp
6 ft dia x 9 ft straight side
height, w/cover, carbon steel
43,000
3,100
5,500
19,900
102,900
13,000
1,300
1,200
301,900
(continued)
81
-------
TABLE 26 (continued)
Area 2—Feed Preparation
Item
No.
Description
Total material
cost. 1979 $
1. Preslaker mixer
2. Tank, slurry feed
Lining
3. Agitator, slurry
feed tank
4. Pump, MgO slurry
feed tank
Blade, 12 in. dia x 8 ft long,
5 hp
27 ft dia x 27 ft high, 115,600
gal, open top, four 27 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
108 in. dia, 30 hp, neoprene
coated
Centrifugal, 271 gpm, 150 ft
head, 25 hp, carbon steel,
neoprene coated
5,800
14,900
16,600
33,100
11,600
Subtotal
Area 3 — Gas Handling
Item No. Description
1. Fans 4 Forced draft, 15 in., 890 rpm,
1,500 hp, fluid drive, double
width, double inlet
Subtotal
82,000
Total material
cost, 1979 $
840,000
840,000
Area 4 — S02 Absorption
Item No. Description
1. S02 absorber 4 Spray grid tower, 29 ft long x
Total material
cost, 1979 $
3,274,100
15 ft wide x 38 ft high, 1/4 in.
carbon steel, neoprene lining;
FRP spray headers, 316 stain-
less steel chevron vane entrain-
ment separator
(continued)
82
-------
TABLE 26 (continued)
Item
No.
Description
Total material
cost. 1979 $
2. Tank, SC>2
absorber,
recirculation
Lining
Agitator, SC>2
absorber
recirculation
tank
Pump, SO2
absorber recycle
2. Soot blowers
Subtotal
23 ft dia x 11-1/2 ft high,
35,700 gal, open top, four 23 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
92 in. dia, 15 hp, neoprene
coated
Centrifugal, 3,230 gpm, 100 ft
head, 200 hp, carbon steel,
neoprene lined
27,100
20
one-half of tubes made of
Inconel 625 and one-half made
of Cor-Ten
Air, retractable
28,200
80,800
99,700
5.
6.
Pump, makeup 4 Centrifugal, 926 gpm, 150 ft 67,200
water head, 75 hp, carbon steel
Soot blowers 20 Air, retractable
Subtotal
130,000
3,707,100
Area
1.
Subtotal
5— Reheat
Item
Reheat er
3,707,100
Total material
No. Description cost, 1979 $
4 Steam, tube type, 3,754 ft2, 858,000
130,000
988,000
(continued)
83
-------
TABLE 26 (continued)
Area 6—Chloride Purge
Item
No.
Description
Total material
cost. 1979 $
1. Chloride scrubber 4
2. Tank, chloride
recycle
Lining
3. Agitator, chloride
recycle tank
4. Pumps, chloride
recycle (venturi)
5. Pumps, chloride
recycle (spray
chamber)
6. Feeder, lime feed
bin discharge
7. Tank, chloride
neutralization
Lining
8. Agitator, chloride
neutralization
tank
9. Pump, chloride
purge
10. Pump, pond water 2
return
Subtotal
Combination venturi-spray
chamber, venturi - 13 ft dia x
25 ft high, spray chamber -
20 ft long x 29 ft wide x 9 ft
high, Hastelloy G spray headers
chevron vane entrainment
separators
14 ft dia x 11 ft high, 12,700
gal, open top, four 14 in.
baffles, agitator supports,
carbon steel
1/4 in. neoprene lining
56 in. dia, 5 hp, neoprene
coated
Centrifugal, 60 ft head,
100 hp, carbon steel, neoprene
lined
Centrifugal, 150 ft head,
250 hp, carbon steel, neoprene
lined
Weigh feeder, 3/4 hp, 722 Ib/hr
13 ft dia x 11 ft high, 10,900
gal, open top, four 13 in.
baffles, carbon steel
1/4 in. neoprene lined
64 in. dia, 7-1/2 hp, neoprene
coated
Centrifugal, 362 gpm, 200 ft
head, 40 hp, carbon steel,
neoprene lined
Centrifugal, 317 gpm, 150 ft
head, 25 hp, carbon steel,
neoprene lined
1,834,200
29,300
14,800
36,100
118,200
212,600
5,300
5,900
4,000
12,000
21,100
18,200
2.311.700
(continued)
84
-------
TABLE 26 (continued)
Area 7—Slurry Processing
Item
No.
Description
Total material
cost, 1979 $
1. Centrifuge
2. Tank, centrate
40 in. dia x 140 in. long,
solid bowl, stainless steel,
300 hp
14 ft dia x 7 ft high, 8,100
gal, open top, four 14 in.
baffles, agitator supports,
carbon steel
654,000
2,400
3.
4.
5.
Area
1.
2.
3.
4.
5.
Lining
Agitator,
centrate tank
Pump, centrate
Conveyor , dryer
feed
Subtotal
8— Drying
Item
Dryer, MgSC-3
Fan, combustion
air
Tank, fuel oil
Heater, fuel
oil
Pump, fuel oil
1/4 in. neoprene lined
1 56 in. dia, 2 hp, neoprene
coated
2 Centrifugal, 835 gpm, 150 ft
head, 75 hp, carbon steel,
neoprene lined
1 Screw, 15 ft long x 16 in. dia,
5 hp, 40 tons/hr, carbon steel
No. Description
1 Rotary, 15 ft dia x 90 ft long,
150 hp, carbon steel
1 Forced draft, 5 in., 30 hp
1 56 ft dia x 28 ft high, 515,900
gal, w/cover, carbon steel
1 Steam, tube type, 177 ft2,
carbon steel
2 Centrifugal, 10 gpm, 150 ft head,
2,300
4,600
27,800
4,400
695,500
Total material
cost, 1979 $
1,299,300
15,800
51,100
12,000
6,800
2 hp, carbon steel
(continued)
85
-------
TABLE 26 (continued)
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
Item
Conveyor, dryer
product
Conveyor, MgS03
Bin, MgS03
storage hold
Feeder, MgS03
storage
Conveyor, reserve
MgSC>3 storage
Tripper
Bucket tractor,
mobile equipment
Hopper, MgS03
reserve storage
Feeder, reserve
MgS03
Conveyor, reserve
MgS03 feed
Silo, MgSC>3 live
storage
Feeder, calciner
(enclosed)
Conveyor,
calciner feed
Dust collector
Dust collector
Blower, dryer
off-gas
Subtotal
No. Description
1 Screw, 15 ft long x 16 in. dia,
15 hp , 18 tons/hr, carbon steel
1 Pneumatic, pressure, 100 hp
1 5 ft dia x 7 ft straight side
height, w/cover, carbon steel
1 Belt, 14 in. wide, 1 hp, 16
tons/hr
1 Belt, 14 in. wide x 100 ft long,
2 hp, 16 tons/hr, 100 ft/min
1 5 hp, 30 ft/min
1 Scraper tractor, 1-1/2 yd3
capacity
1 7 ft x 7 ft x 7 ft deep, 60°
slope, carbon steel
1 Rotary stargate, 2 hp, 50
tons/hr
1 Pneumatic, pressure, 100 hp
1 17 ft dia x 26 ft straight side
height, w/cover, carbon steel
1 Weigh belt, 18 in. wide, 1 hp,
16 tons/hr
1 Belt, 18 in. wide x 10 ft long,
1 hp, 16 tons/hr, 100 ft/min
1 Cyclone, 81,000 aft3/min
1 Bag filter, 81,000 aft3/min
1 Induced draft, 23 in., 300 hp
(continued)
86
Total material
cost, 1979 $
4,400
80,000
700
10,000
17,300
18,000
48,800
400
7,900
80,000
10,200
8,500
2,000
43,600
50,000
114,100
1,880.900
-------
TABLE 26 (continued)
Area 9—Calcining
Item
No.
Description
Total material
cost, 1979 $
1. Calciner
2. Dust collector
3. Air preheater
4. Waste heat
boiler
5. Cooler, solids
6. Bin, MgO cooler
1 Fluid bed, 12 ft x 40 ft
high, 12 in. fire brick, 10 in.
insulating brick, carbon steel
shell
1 Multiclone, 43,700 aft3/min
1 Tube type, 9,347 ft2, 316L
stainless steel
1 Tube type, 529 ft2, 316L
stainless steel
1 Tubed shell type, 4,963 ft2,
6 ft dia x 50 ft long, 15 hp,
twenty-seven 3 in. tubes
1 5 ft dia x 8 ft straight side
height, w/cover, carbon steel
405,000
58,000
132,200
20,200
225,000
1,400
7.
8.
9.
10.
11.
Dust collector
Fan, combustion
air
Fan, oxidation
air
Conveyor, recycle
Silo, recycle MgO
storage
Vibrators
Subtotal
1
1
1
MgOl
4
16
Bag filter, 43,800 aftj/min
Forced draft, 214 in., 200 hp
Forced draft, 10 in., 40 hp
Pneumatic, pressure, 10 hp
41 ft dia x 62 ft straight side
height, w/cover, carbon steel
1/2 hp
36,000
21,800
15,400
43,000
266,400
21,500
1,245,900
(continued)
87
-------
TABLE 26 (continued)
Area 10—98% Sulfuric Acid Production
Item
No.
Description
Total material
cost, 1979 $
1.
Complete
unit
Subtotal
Complete 98% sulfuric acid
system
1,985,500
1.985.500
Area 11—Acid Storage and Shipping
Item
No.
Description
Total material
cost, 1979 $
1. Tanks, sulfuric
acid storage
2. Pump, tank
discharge
Subtotal
56 ft dia x 28 ft high, 575,200
gal, w/cover, carbon steel
Centrifugal, 400 gptn, 100 ft
head, 40 hp, carbon steel
224,700
10,500
235,206
88
-------
Storage Capacity
Storage requirements for raw materials and allowances for in-
process streams are listed below.
Raw materials
Makeup MgO storage silo - 30 days
Limestone storage silo - 30 days
In-process storage
Makeup MgO feed bin - 34 hours
Recycle MgO feed bin - 1 hour
Limestone feed bin - 1 day
Slurry feed tank - 1 hour
SOo absorber recirculation tank - 3 minutes
Chloride neutralization tank - 30 minutes
Centrate tank - 10 minutes
Fuel oil tank - 30 days
MgSOo live storage silo - 8 hours
Reserve MgS03 storage building - 15 days
Recycle MgO storage silo - 15 days
Sulfuric acid storage tanks - 30 days
MAGNESIA PRODUCTION
Two distinctly different methods of producing magnesia are employed
in the United States. One process is based on an adequate source of
magnesite (MgC03) ore. Currently the only such plant operating in the
United States is located at Gabbs, Nevada, at the site of large magnesite
deposits. The processing varies with both the grade of ore being extracted
and the product specifications which are determined by the magnesia end
use. The production of chemically active magnesia such as that used in
FGD systems requires the most extensive processing.
m
The other process is based on the use of seawater and either high-
..iagnesium limestone or dolomite [MgCa(C03)2] . The economical use of
this process requires a location near seawater and an adequate source of
dolomite or limestone. Dolomite is preferred because of its magnesium
content. The process to be described is based on an operation which
uses dolomite with approximately 50% MgCO^ and 50% CaCO .
Since some of the information regarding these processes is of a
proprietary nature, their description is not as detailed as that pre-
sented in the widely practiced production of lime from limestone.
Control systems, plan and elevation drawings, and equipment costs are
not Included. Enough information was obtained, however, for the energy
requirements assessment shown in the Economic Evaluation and Comparison
section of this report. Both processes described are based on the
production of chemically active magnesia suitable for use in FGD systems.
89
-------
Magnesia From Magnesite
The flow diagram for this process is shown in Figure 22. Magnesite
is selectively mined in a typical quarry operation involving drilling,
blasting, loading, and hauling to the plant site. There it is crushed
and sized to remove wastes and stockpiled according to grade. From the
stockpile it is further beneficiated in a heavy medium separation system
utilizing ferrosilicon and water. The magnesite recovered from the
heavy medium separation is then ground and further beneficiated in a
flotation system followed by washing and thickening. The underflow from
the thickener, consisting of 60% solids, is further dewatered in a
rotary disc filter. The filter cake containing about 95% MgCO is then
dried in a rotary dryer. The product from the dryer is then fed to a
hearth furnace which serves as the calciner for the following reaction.
heat
+ MgO + C0t
The hearth furnace is operated in the temperature range of 1600°F to
1800 F. The magnesia product is then cooled in a rotary drum cooler and
sent to storage and shipping. The material balance and fuel require-
ments for this process are presented in Table 27. Either fuel oil or
natural gas is used depending upon cost and availability. No. 6 fuel
oil is used in the case shown.
Major Process Areas
The magnesite magnesia process is divided into the following areas
1. Magnesite mining: The equipment in this area includes the drilling
equipment, a front-end loader, and trucks.
2. Magnesite sizing: This area includes a jaw crusher, conveyors,
classifying screens, and a cone crusher.
3. Separation; This area consists of a heavy medium separator and
its supporting equipment such as pumps and screens, conveyors,
and storage silos.
4 . Flotation and washing; The area equipment includes a rod mill
ball mill, classifier, cyclone, flotation cells, pumps, and a
washing tank.
5. Drying; Drying equipment consists of a filter, rotary dryer, and
storage silo.
6. Calcining and storage; This final area includes conveyors, a
hearth furnace, a rotary cooler, and a shipping storage silo.
The major equipment and horsepower requirements for each of these areas
are shown in Table 28.
90
-------
MINING
MAGNESITE
SIZING
SOLUTION
/
SEPARATION
(HMS)
4
GRINDING
FRESH 5
FLOTATION
FRES
WAT
7
" " .
:n
J_
r
_J LL
WASHING
TANK
TO RECYCLE a
DISPOSAL POND
Figure 22. Magnesia from magnesite. Flow diagram.
-------
TABLE 27. MAGNESIA FROM MAGNESITE
MATERIAL BALANCE
Stream No.
Description
I
'I
1
'<
h
J
H
9
1°
Total stream, Ib/hr
sft3/min (60°?)
Temperature, °F
Pressure, psig
gpm
Specific gravity
pH
Undissolved solids, %
1
Magnesite to
HMS unit
145,700
2
Ferrosilicon
solution to
HMS unit
74,800
3
Waste to
disposal pond
167, 800
4
MgC03 to
grinding
52,700
5
Fresh water
to flotation
351.800
703
1.0
Stream No.
Description
1
•>
1
4
3
h
7
H
9
10
Total stream. Ib/hr
sft-l/min (60°F)
Temperature, UF
Pressure, pslg
gpm
Specific gravity
pH
Undissolved solids, %
6
Waste to
disposal pond
354.700
709
1.1
7
MgC03 to
washing
thickener
49.900
38
2.6
85
8
Fresh
water to
washing
thickener
197
1.0
9
Washing
thickener
overflow
79,300
157
1.01
1.1
10
Washing
thickener
underflow
to filter
69,300
71
1.96
60
Stream No.
Description
1
>
1
^
5
h
1
H
9
IU
Total stream. Ib/hr
sft^/min (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
PH
Undissolved solids1 %
11
Filtrate to
disposal pond
46
1.0
12
MgC03 to
rotary dryer
46,200
13
Combustion
air to
rotary dryer
18.010
3,300
14
Oil to
rotary dryer
516
I
0.91
15
MgC03 to
hearth
furnace
41,600
400
Stream No.
I
1
h
/
H
9
10
Description
sft3/min (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
PH
Undissolved solids, %
16
Combustion
air to
hearth
furnace
8.400
17
Oil to
hearth
furnace
6
0.91
18
MgO to
cooler
1,600
19
MgO
to storage
and shipping
125
92
-------
TABLE 28. MAGNESIA FROM MAGNESITE
MAJOR EQUIPMENT LIST AND HORSEPOWER
Equipment list Horsepower
Mining
Compressor 300
Front-end loader 270
Truck 237
Sizing
Feeder 15
Jaw crusher 150
Conveyor (3) 1-1/2
Conveyor (2) 2, 3, 5, &
10
Cone crusher
Separation
Heavy medium separator 120
Flotation and washing
Rod mill 250
Ball mill 500
Pumps (3) 2 & 1-1/2
Pumps (3) 3
Thickener 2
Drying
Filters 5 & 7-1/2
Rotary dryer 3
Conveyor 3
Calcination and storage
Hearth furnace 75
Rotary cooler 10
Elevator 5
Conveyor 3
93
-------
Magnesia From Seawater
The flow diagram for this process is shown in Figure 23. This
process produces magnesia from seawater and dolomite. A Gulf Coast
location is assumed. Dolomite is shipped by rail to the plant from
quarries in Alabama and Georgia. The dolomite rock received has been
crushed to approximately 1-1/2 inch diameter prior to shipping. It is
stockpiled over an underground conveyor system which feeds a rotary kiln
which serves as the calciner for the decomposition of dolomite.
heat
MgCa(C03)2 -> CaO + MgO + 2CO^
The 15-foot diameter by 265-foot-long kiln is fired with No. 6 fuel
oil and operates at approximately 2500 F. Product from the kiln is
cooled and stored prior to further processing. Exhaust gas from the
kiln is treated for dust removal and the material recovered is conveyed
to storage.
Seawater is pumped from the Gulf of Mexico to a slaker where the
calcined dolomite from storage is next processed. A simplified form of
the reaction which takes place in the slaker is as follows.
CaO + MgO + 2H20 + Mg*4" -> Mg(OH)2 + MgO + Ca(OH)2
This material is pumped to a thickener from which the magnesium hydroxide
and magnesia are removed as underflow and the clarified seawater containing
calcium hydroxide is returned to the Gulf. The reaction forming magnesium
hydroxide continues in the thickener.
The thickener underflow containing the magnesium hydroxide and
magnesia is then washed in a series of wash tanks to remove impurities
and salt. Slurry with 18% solids from the final washer is filtered in
rotary disc filters. The filter cake with 54% solids is pumped to the
rotary hearth furnace where, at a temperature of up to 1800°F, the mag-
nesium hydroxide is decomposed to magnesia.
heat
Mg(OH)2 -* MgO + H20 +
The calcined material is cooled in a rotary cooler and sent to storage
and shipping. Material balance and fuel requirements are shown in
Table 29.
Major Process Areas
The seawater magnesia process is divided into the following areas.
1. Mining; This area includes drilling equipment, a front-end
loader, and trucks for a quarry operation.
2. Dolomite sizing and shipping: Ore crushing and sizing equipment
is the same as the limestone classifying equipment.
94
-------
Ui
DOLOMITE
OR
LIMESTONE
MINING
DOLOMITE
SIZING
AND
SHIPPING
RAW
MATERIALS
HANDLING
/
/
Figure 23. Magnesia from seawater. Flow diagram.
-------
TABLE 29. MAGNESIA FROM SEAWATER
MATERIAL BALANCE
Stream No.
Description
1
•1.
i
4
r)
h
/
K
9
10
Total stream. Ib/hr
sftVmin (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
PH
Undissolved solids, %
1
Dolomite to
rotary kiln
60.000
2
Combustion
air to
rotary kiln
129,700
28,400
3
Oil to
rotary kiln
5.072
11
0.91
4
Calcined
dolomite
to cooler
31,200
2,500
5
Calcined
dolomite
to slaker
31,200
130
Stream No.
1
2
(
4
5
f>
7
H
9
iSL
Description
Total stream, Ib/hr
sft^/mln (60°F)
Temperature, °F
Pressure, psig
gpm
Specific gravity
DH
Undissolved solids, %
6
Seawater to
slaker tank
3.998.500
7,990
7
Slurry to
thickener
8,375
1.0
0.7
8
Thickener
overflow
8,044
1.0
0.3
9
Thickener
underflow to
washing
165.600
301
1.1
10
Washing
overflow
to slaking
161,700
323
1.0
Stream No.
>
i
4
>
H
9
11)
Description
Total stream. Ib/hr
sft-Vmin (60°F)
Temperature, UF
Pressure, psig
gpm
Specific gravity
pH
Undissolved solids, %
11
Washing
overflow
to sea
161.700
323
1.0
12
Fresh water
to washing
249,900
499
1.0
13
Magnesia
slurry to
filter
92,000
:.53
1.2
18
14
Filtrate
to sea
61,300
122
1.0
15
Magnesia
filter cake
to hearth
furnace
34,800
41
1.7
1
i
)
"T
Description
~sft3/min (60°F)
Temperature. °F
Pressure, psig
Rpm
Specific gravity
pH
Undissolved solids X
Combustion
air to
hearth
furnace
15.300
1 17 1
Oil to
hearth
furnace
0.91
1 ^ 1
MgO to
cooler
1,800
19
MgO to
storage
and shipping
125
96
-------
3. Raw materials handling; Hoppers and conveyors similar to those
in the limestone slurry process materials handling area unload
the dolomite from railcars to a stockpile and then to the rotary
kiln for calcination.
4. Calcination dolomite: The equipment in this area includes a
rotary kiln, rotary solids cooler, mixer for hydration, retention
tank, classifier, and grinding mill.
5. Wet system; This area has a reactor, a thickener, a series of
washing tanks and associated pumps, and a filter.
6. Magnesia calcination, storage, and shipping; This area includes
a calcining hearth furnace, a conveyor, storage silos, and con-
veyor for loading the magnesia on railcars.
The major equipment items and horsepower requirements are shown in
Table 30.
97
-------
TABLE 30. MAGNESIA PRODUCTION FROM SEAWATER
MAJOR EQUIPMENT LIST AND HORSEPOWER
Equipment list Horsepower
Mining
Compressor 30
Front-end loader 270
Truck 237
Sizing and shipping
Feeder 15
Conveyor (6) 1
Jaw crusher 40
Cone crusher 30
Raw materials handling
Conveyors 5, 10, 15, &
75
Dolomite calcination
Kiln 150
Pump (2) 1.5
Cooler 10
Hammer mill 50
Wet system
Pumps (2) 5
Pumps (4) 100
Pumps (2) 200
Pumps (2) 500
Agitator 5 & 15
Pumps (4) 3
Pumps (6) 7.5
Pumps (2) 10 & 40
Filter 10
Magnesia calcination, storage,
and shipping
Pump (2) 3
Hearth furnace 75
Conveyor 10 & 15
98
-------
ECONOMIC AND ENERGY EVALUATION AND COMPARISON
Capital investment and first-year annual revenue requirements were
calculated for the base cases and all of the case variations. In addi-
tion, lifetime revenue requirements were calculated for the base cases
and the power plant size case variations. Detailed results are tabulated
in the appendix. In all cases the magnesia process costs include a
credit for acid sales, as shown in the detailed results in the appendix.
The case variations of power plant size and remaining life, coal
sulfur content, removal efficiency, and oil fuel are designed to illus-
trate the costs associated with ranges of conditions common in the
utility industry. While they cannot define all of the combinations
possible, they should be useful in projecting the results to other
combinations of conditions.
A ground-to-ground energy assessment was made for the base-case
conditions of the four processes. This assessment tabulates the total
energy consumption for production and transportation of raw materials as
well as FGD and waste disposal energy consumption. For the magnesia
process an energy credit is assigned based on the equivalent energy
consumption for production of an equal quantity of acid produced from
sulfur delivered from Port Sulphur, Louisiana, including energy required
for mining and delivery of sulfur as well as sulfuric acid net processing
energy.
CAPITAL INVESTMENT
Capital investment summaries of the base cases and case variations
for each of the processes are shown in Tables 31 through 34. For the
same conditions the capital investments of the four processes differ by
up to 45%.
The limestone slurry process has 1979 capital investments ranging
from $25,121,000 (126 $/kW) for an existing 200-MW power plant to
$75,075,000 (75 $/kW) for an existing 1,000-MW power plant. For the
base-case conditions (a new 500-MW power plant burning 3.5% sulfur coal)
the limestone slurry process capital investment is $48,943,000 (98 $/kW).
The lime slurry process using purchased lime has capital investments
ranging from $22,758,000 (114 $/kW) for an existing 200-MW power plant
to $71,098,000 (71 $/kW) for an existing 1,000-MW power plant. For the
base case the capital investment is $45,319,000 (90 $/kW).
99
-------
TABLE 31. LIMESTONE SLURRY PROCESS
TOTAL CAPITAL INVESTMENT SUMMARY
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 25,121,000 126
200 MW N 3.5% sulfur 30 25,529,000 128
500 MW E 3.5% sulfur 25 50,406,000 101
500 MW N 2.0% sulfur 30 39,848,000 80
* 500 MW N 3.5% sulfur 30 48,943,000 98
500 MW N 5.0% sulfur 30 54,797,000 110
1,000 MW E 3.5% sulfur 25 75,075,000 75
1,000 MW N 3.5% sulfur 30 71,730,000 71
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 50,649,000 101
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 38,636,000 77
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.
Unfixed 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.
100
-------
TABLE 32. LIME SLURRY PROCESS
TOTAL CAPITAL INVESTMENT SUMMARY
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 22,758,000 114
200 MW N 3.5% sulfur 30 22,798,000 114
500 MW E 3.5% sulfur 25 46,446,000 93
500 MW N 2.0% sulfur 30 36,947,000 74
• 500 MW N 3.5% sulfur 30 45,319,000 90
500 MW N 5.0% sulfur 30 50,293,000 101
1,000 MW E 3.5% sulfur 25 71,098,000 71
1,000 MW N 3.5% sulfur 30 67,654,000 68
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 46,909,000 94
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur 25 35,811,000 72
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.
Unfixed 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.
101
-------
TABLE 33. LIME SLURRY PROCESS WITH ONSITE CALCINATION
TOTAL CAPITAL INVESTMENT SUMMARY
Case
Years
remaining
life
Total capital
investment, $ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.
200 MW N 3.
500 MW E 3.
500 MW N 2.
5%
5%
5%
0%
sulfur
sulfur
sulfur
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; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur
20
30
25
30
30
30
25
30
30
28,292,000
28,371,000
55,039,000
43,407,000
53,860,000
61,137,000
82,812,000
79,667,000
55,910,000
142
142
110
87
108
122
83
80
112
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
42,391,000
85
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.
Unfixed 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.
102
-------
TABLE 34. MAGNESIA PROCESS
TOTAL CAPITAL INVESTMENT SUMMARY
Years
remaining Total capital
Case life investment, $ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.5% sulfur 20 35,119,000 176
200 MW N 3.5% sulfur 30 34,439,000 172
500 MW E 3.5% sulfur 25 66,837,000 134
500 MW N 2.0% sulfur 30 53,703,000 108
• 500 MW N 3.5% sulfur 30 65,911,000 132
500 MW N 5.0% sulfur 30 75,805,000 152
1,000 MW E 3.5% sulfur 25 103,641,000 104
1,000 MW N 3.5% sulfur 30 101,353,000 101
90% S02 removal
500 MW N 3.5% sulfur 30 68,620,000 137
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW E 2.5% sulfur 25 42,635,000 85
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.
Credit for byproduct acid included.
103
-------
The lime slurry process using lime calcined onsite has capital
investments ranging from $28,292,000 (142 $/kW) for an existing 200-MW
power plant to $82,812,000 (83 $/kW) for an existing 1,000-MW power
plant. For the base case the capital investment is $53,860,000 (108 $/kW).
The magnesia process has capital investments ranging from $34,439,000
(172 $/kW) for an existing 200-MW power plant to $103,641,000 (104 $/kW)
for an existing 1,000-MW power plant. For the base case the capital
investment is $65,911,000 (132 $/kW).
The cost differences are further illustrated by the breakdown of
base-case process equipment costs by area shown in Tables 35 through 38.
Base Case
The differences in capital investment between the lime slurry
process using purchased lime and the limestone slurry process is the
result of the simpler feed preparation requirements for lime and the
higher utilization rate of lime compared with limestone. The lime does
not require crushing and milling equipment and the lower stoichiometry
of the lime process allows the use of smaller equipment than the lime-
stone process. The higher lime utilization also results in a lower pond
construction cost ranging from 9% for the existing 200-MW unit to 16%
for the 5% sulfur coal, 500-MW unit.
These capital cost advantages for the lime slurry process are
counteracted in the lime slurry process with onsite calcination by the
additional equipment required in the materials handling area and by the
limestone calcining equipment. The additional processing equipment
required to calcine the limestone increases the base-case direct invest-
ment by 19%.
The primary reason for the higher capital investment costs for the
magnesia process is the difference between the cost of sludge ponding
and the cost of regenerating the MgO. Base-case limestone pond construc-
tion direct cost is $5,145,000 and waste disposal costs are $1,688,000
including land. The direct investment for the base-case magnesia slurry
processing, drying, and calcination areas is $8,871,000. The recovery
system requires that chloride be removed before entering the S09 absorber,
which adds another $5,066,000 for chloride scrubbing. (The effect of
conditions under which the chloride scrubber could be omitted and the
effect of sludge fixation on the cost differentials are discussed below.)
The acid production, and storage and shipping areas also add an additional
$6,994,000. The costs related to spent slurry processing are thus about
three times greater for the recovery process than for the waste-producing
processes. The elimination of pond land and construction costs does not
compensate for the additional equipment costs required for the recovery
process.
104
-------
TABLE 35. LIMESTONE SLURRY FROCESS BASE CASE
AREA PROCESS EQUIPMENT AND INSTALLATION COSTS (k$)
Materials
handl ing
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Excavation and site preparation
Subtotal
Percent of total direct investment
452
143
13
3
-
-
113
454
256
91
63
159
11
3
1
4
-
-
_
1,767
6.8
Feed
preparation
618
116
180
87
16
13
55
211
-
-
92
174
66
16
1
7
39
68
_
1,758
6.7
Gas
handling
812
78
-
-
1,562
1,187
12
51
-
19
195
347
46
8
-
1
-
-
_
4,318
16.5
S02
absorption
4,307
749
1,539
484
-
-
80
223
181
441
163
277
426
79
4
21
-
-
_
8,974
34.4
Stack gas Solids
reheat disposal
986 44
122 25
57 885
38 367
-
-
13
37
2
12
1 66
2 197
63 6
12 2
3
1 20
-
-
9
1,282 1,688
4.9 6.5
Total
7,219
1,233
2,674
979
1,578
1,200
273
976
439
563
580
1,156
618
120
9
54
39
68
9
19,787
7. of total
direct
investment
27.6
4.7
10 2
3.8
6.0
4.6
1.1
3.7
1.7
2.2
2.2
4.4
2.4
0.5
-
0.2
0.2
0.3
-
75.8
% of total
capital
investment
14.7
2.5
5.5
2.0
3.2
2.4
0.6
2.0
0.9
1.2
1.2
2.4
1.3
0.2
-
0.1
0.1
0.1
-
40.4
Note: mid-1979 cost basis.
-------
TABLE 36. LIME SLURRY PROCESS BASE CASE
AREA PROCESS EQUIPMENT AND INSTALLATION COSTS (k$)
Materials Feed
handling preparation
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Structural
Material
Labor
i_i Electrical
O Material
°" Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Excavation and site preparation
Subtotal
Percent of total direct investment
476
403
11
7
23
12
88
438
123
185
82
94
12
6
1
8
-
-
9
1,978
8.3
195
77
62
40
7
6
21
81
8
18
49
57
21
5
2
11
-
-
-
660
2.8
Gas
handling
812
78
-
-
1,562
1,187
12
51
-
19
195
347
46
8
-
1
-
-
-
4,318
18.0
S02 Stack gas
absorption reheat
4,098 986
693 122
1,458 57
459 38
-
-
76
211
171
418
154 1
263 2
403 63
76 12
4
20 1
-
--
-
8,504 1,282
35.5 5.3
Solids
disposal
42
24
844
350
-
-
13
37
2
12
64
190
6
2
3
19
-
-
8
1,616
6.7
% of total
direct
Total investment
6,609
1,397
2,432
894
1,592
1,205
210
318
304
652
545
953
551
109
10
60
-
_
17
18,358
27
.6
5.8
10
3
6
5
0
3
1
2
2
4
2
0
0
76
.1
.7
.6
.0
.9
.4
.3
.7
.3
.0
.3
.5
-
.3
-
_
_
.6
7, of total
capital
investment
14.
3.
5.
2.
3.
2.
0.
1.
0.
1.
1.
2.
1.
0.
-
0.
-
_
-
40.
6
1
4
0
5
7
5
8
7
4
2
1
2
2
1
5
Note: mid-1979 cost basis.
-------
TABLE 37. LIME SLURRY PROCESS WITH ONSITE CALCINATION BASE CASE
AREA PROCESS EQUIPMENT AND INSTALLATION COSTS (k$)
Materials
handling
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundation
j_, Material
O Labor
"-J Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Excavation and site preparation
Subtotal
Percent of total direct investment
641
203
21
4
38
30
160
641
361
127
89
223
16
4
2
10
-
2,570
9.0
Limestone
calcination
1,625
1,361
11
4
90
46
23
113
22
34
95
108
90
17
3
12
-
3,654
12.8
Feed
preparation
195
77
62
40
7
6
21
81
8
18
49
57
21
5
2
11
-
660
2.3
Gas
handling
812
78
-
-
1,562
1,187
12
51
-
19
195
347
46
8
-
1
-
4,318
15.2
S02
absorption
4,098
693
1,458
459
-
-
76
211
171
418
154
263
403
76
4
20
-
8,504
29.9
Stack gas
reheat
986
122
57
38
-
-
-
-
-
-
1
2
63
12
-
1
-
1,282
4.5
Solids
disposal
42
24
844
350
-
-
13
37
2
12
64
190
6
2
3
19
8
1,616
5.7
Total
8,399
2,558
2,453
895
1,697
1,269
305
1,134
564
628
647
1,190
645
124
14
74
8
22,604
7, of total
direct
investment
29 ,
9.
8.
3.
6.
4.
1.
4.
2.
2.
2.
4.
2.
0.
-
0.
-
79.
.5
.0
6
1
0
4
1
0
0
2
3
2
3
4
3
4
% of total
capital
investment
15.6
4.7
4.6
1.7
3.2
2.4
0.6
2.1
1.0
1.2
1.2
2.2
1.2
0.2
-
0.1
-
42.0
Note: mid-1979 cost basis.
-------
TABLE 38. MAGNESIA PROCESS BASE CASE
AREA EQUIPMENT AND INSTALLATION COSTS (k$)
Materials
handling
Direct Investment
Equipment
Material
Labor
Piping and Insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Structural
Material
Labor
Electrical
I—1 Material
O Labor
OO Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Excavation and site preparation
Battery limits
Subtotal
Percent of total direct investment
302
172
2
2
3
2
5
28
17
8
53
53
31
11
2
13
-
_
_
_
704
2.0
Feed
preparation
82
54
50
34
10
4
_
-
13
7
7
7
20
8
2
5
-
_
_
_
303
0.9
Gas
handling
840
82
-
-
1,562
1,187
12
53
-
20
300
539
21
8
-
1
-
_
_
-
4,625
13.1
S02
absorption
3,707
442
317
62
-
-
25
99
159
48
98
176
216
56
5
37
-
_
-
-
5,447
15.4
Stack gas Chloride Slurry
reheat purge Processing
988 2,297
154 585
12 775
10 364
-
-
33
130
150
45
147
265
24 225
8 34
2
2 14
-
_
-
-
1,198 5,066
3.4 14.3
696
77
44
28
10
5
B
31
6
2
81
80
26
8
1
7
-
-
-
-
1,110
3.1
Drying Calcining
1.881
2,355
17
19
171
160
34
ISO
38
22
85
85
26
10
1
3
210
251
-
-
5,518
15.7
1,246
542
34
34
50
22
16
73
22
32
32
31
68
23
2
16
-
-
-
-
2,243
6.3
Acid Acid
235
352
23
8
-
-
29
147
15
56
12
11
31
10
_ ..
-
-
_
65
6,000
6,000 994
17.0 2.8
;
12,274
4,815
1,274
561
1,806
1,380
162
711
420
240
815
1,247
688
176
15
98
210
251
65
6,000
33,208
direct
34.7
13.6
3.6
1.6
5.1
3.9
0.5
2.0
1.2
0.7
2.3
3.5
2.0
0.5
_
0.3
0.6
0.7
0.2
17.0
94.0
capital
18.6
7.4
1.9
0.9
2.7
2.1
0.2
1.2
0.6
0.4
1.2
1.9
1.0
0.3
-
0.1
0.3
0.4
0.1
9.1
53.9
Rote: mU-1979 cost bails.
-------
The magnesia process has much lower materials handling and preparation
costs and substantially lower S02 absorption costs. The gas handling
costs are slightly higher than the other processes because of the waste
streams from the recovery area that are bled to the scrubber system.
The 862 absorption costs are lower because greater reactivity of the MgO
permits the use of a simpler scrubber.
Case Variations
Figure 24 illustrates the effect of new power unit size on the four
processes. The three waste-producing process costs begin to level off
at about a 1,000-MW power plant size while the magnesia process cost
continues to increase. The magnesia process has much more equipment and
the equipment it has in common with the three waste-producing processes,
such as flue gas booster fans and stack gas reheaters, are larger and
more expensive because of the additional gas streams from the rotary
dryer and the acid plant. Since the magnesia process is more equipment-
intensive there is less economy of scale for it than for the waste-
producing processes.
This characteristic is also seen in the waste-producing processes.
The limestone slurry process and the lime slurry process each have very
similar equipment, both in number and in cost. The absolute increase in
capital investment from the 500-MW to 1,000-MW power plant size is very
nearly the same for both. The lime slurry process with onsite calcination,
with its limestone calcination area, has more equipment and the capital
investment increases at a higher rate with increasing power plant size
than it does in the limestone slurry process. The same pattern is seen
in the existing units.
Figure 25 shows the change in unit investment cost ($/kW) with
power unit size. The unit investment curves reflect the same informa-
tion found in the capital investment graphs.
The effect of sulfur content is shown in Figure 26 for coal sulfur
contents of 2.0%, 3.5%, and 5.0%. The effect is similar for all of the
processes. The capital investments are reduced 18% to 19% for the 2.0%
sulfur coal and increased 12% to 15% for the 5.0% sulfur coal, both
compared to the 3.5% sulfur coal. There is a slightly greater increase
in capital investment with coal sulfur content for the magnesia process
because of the extensive equipment requirements for product processing.
The effect of 90% S02 removal, compared with the base case 79%
removal, is slight for all of the processes. The effect is an increase
in the raw material, scrubber, and scrubber effluent processing areas
which increases capital investment by 3% to 4%.
The use of a 2.5% sulfur fuel oil reduces capital investment about
20%, compared to the base case, for the waste-producing processes. The
lower cost is largely the result of the lower sulfur content and the
109
-------
120
100
3.5% sulfur in coal
1.2 Ib SCL/MBtu
7000 hour annual operation
80
60
40
20
X Limestone
O Lime
A Lime with calcination
D Magnesia
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 24. All processes. Effect of power unit size
on capital investment: new coal-fired units.
110
-------
250
T
T
200 _
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
150
H
O
H
W
C/3
H
M
;=>
100
50
X Limestone
0 Lime
A Lime with calcination
D Magnesia
I
200
400 600
800
1000
POWER UNIT SIZE
Figure 25. All processes. Effect of power unit size
on unit investment cost, $/kW: new coal-fired units.
Ill
-------
200
T
I
1.2 Ib SC>2/MBtu emission limit
7000 hour annual operation
150
H
O
H
W
I
W
100
50
X Limestone
0 Lime
A Lime with calcination
Q Magnesia
% SULFUR IN COAL
Figure 26. All processes. Effect of sulfur content of coal
on unit investment cost, $/kW: new 500-MW coal-fired units.
112
-------
reduced gas rate associated with oil fuel. The oil-fuel magnesia case
is reduced 36% compared with the base case. The greater cost reduction in
this case is a result of elimination of the chloride removal system in
addition to the cost reductions associated with lower sulfur and gas
rates.
ANNUAL REVENUE REQUIREMENTS
The detailed results for each process are shown in the appendix and
are summarized in Tables 39 through 42. When comparing results, it
should be remembered that limestone and the lime processes are waste-
producing processes and magnesia is a recovery process; therefore, a
credit for the sale of sulfuric acid at $25 per ton is included in the
magnesia process annual revenue requirements.
The ranking of annual revenue requirements for the processes is
about the same as the capital investment rankings. Revenue requirements
for the limestone slurry process range from $7,147,200 (5.11 mills/kWh)
for a new 200-MW, 3.5% sulfur coal-fired unit to $23,122,300 (3.30 mills/kWh)
for an existing 1,000-MW, 3.5% sulfur coal-fired unit. The base case is
$14,082,600 (4.02 mills/kWh). The annual revenue requirements for the lime
slurry process using purchased lime range from $7,213,200 (5.15 mills/kWh)
for the new, 200-MW coal-fired unit to $25,387,500 (3.63 tnills/kWh).
The base case is $14,887,700 (4.25 mills/kWh). For the lime slurry
process with onsite calcination, they range from $8,022,800 (5.73 mills/kWh)
to $25,456,200 (3.64 mills/kWh). The base case is $15,558,500 (4.45
mills/kWh).
The sulfuric-acid-producing magnesia process has greater annual
revenue requirements than the waste-producing processes. The base-case
cost is an average of 19% higher than the three base-case waste-producing
processes. The annual revenue requirements for the magnesia process
range from $9,273,500 (6.62 mills/kWh) for the new 200-MW, 3.5% sulfur
coal-fired unit to $28,812,300 (4.12 mills/kWh) for the existing 1,000-
MW, 3.5% sulfur coal-fired unit. The base case is $17,664,600 (5.05 mills/kWh),
The annual revenue requirements for the four base cases are further illus-
trated by the area breakdown of the direct costs in Tables 43-46.
In comparing the base-case direct costs, the greatest difference
between the limestone slurry process and the lime slurry process is in
raw material costs. The cost for limestone is 0.32 mills/kWh, compared
with 0.82 mills/kWh for lime. The slightly lower conversion costs and
indirect costs for the lime slurry process do not fully compensate for
this difference, making the limestone slurry process the lowest of the
four processes in revenue requirements.
113
-------
TABLE 39. LIMESTONE SLURRY PROCESS
TOTAL ANNUAL REVENUE REQUIREMENTS SUMMARY
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
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
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30
7,469,000
7,147,200
14,771,500
11,637,200
14,082,600
15,898,600
23,122,300
21,761,300
14,557,400
34
11
4.22
3.32
4.02
54
30
3.11
4.15
11.79
11.66
9.63
7.76
9.39
10.60
7.71
7.50
9.70
0.56
0.55
0.46
0.37
0.45
0.50
0.37
0.36
0.46
503
499
413
718
402
293
330
332
356
Oil-Fired Power Unit
0.8 Ib SO2/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur
25
11,557,700
3.30
2.16
0.36
778
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 40. LIME SLURRY PROCESS
TOTAL ANNUAL REVENUE REQUIREMENTS SUMMARY
Case
Years Total annual
remaining revenue
life requirements Mills/kWh
$/ton (bbl)
of coal (oil)
burned
$/MBtu
heat input
$/ton
sulfur
removed
Coal-Fired Power Unit
1.2 Ib SC>2/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
200 MW E 3.5% sulfur 20 7,591,000
200 MW N 3.5% sulfur 30 7,213,200
500 MW E 3.5% sulfur 25 15,518,400
500 MW N 2.0% sulfur 30 11,710,600
» 500 MW N 3.5% sulfur 30 14,887,700
500 MW N 5.0% sulfur 30 17,372,400
1,000 MW E 3.5% sulfur 25 25,387,500
1,000 MW N 3.5% sulfur 30 23,916,100
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30 15,593,800
5.42
5.15
4.43
3.35
4.25
4.96
3.63
3.42
4.46
11.99
11.76
10.12
7.81
9.92
11.58
8.46
8.25
10.40
0.57
0.56
0.48
0.37
0.47
0.55
0.40
0.39
0.50
514
504
434
723
425
321
363
353
381
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur
25
11,576,000
3.31
2.16
0.36
780
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 41. LIME SLURRY PROCESS WITH ONSITE CALCINATION
TOTAL ANNUAL REVENUE REQUIREMENTS SUMMARY
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
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
90% S02 removal; onsite
solids disposal (ponding)
500 MW N 3.5% sulfur 30
8,429,400
8,022,800
16,194,900
12,601,100
15,558,500
17,836,300
25,456,200
24,125,800
16,161,800
6.02
5.73
4.63
3.60
4.45
10
,64
3.45
4.62
13.31
13.08
10.56
8.40
10.37
11.89
8.49
8.32
10.77
0.63
0.62
0.50
0.40
0.49
0.57
0.40
0.40
0.51
570
561
452
778
445
329
364
357
395
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission; onsite
solids disposal (ponding)
500 MW E 2.5% sulfur
25
12,793,100
3.66
2.39
0.40
868
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 42. MAGNESIA PROCESS
TOTAL NET ANNUAL REVENUE REQUIREMENTS SUMMARY
Case
Years
remaining
life
Total gross
annual revenue
requirements
Total net
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
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
d 1,000 MW N 3.5% sulfur 30
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
10,948,300
10,378,500
21,072,800
15,905,700
20,487,900
24,562,500
34,214,800
32,961,000
21,551,200
9,808,300
9,273,500
18,312,800
14,663,200
17,787,900
20,407,500
28,812,300
27,738,500
18,473,700
7.01
6.62
5.23
4.19
5.08
5.83
4.12
3.96
5.28
15.48
15.12
11.94
9.77
11.86
13.60
9.60
9.56
12.31
0.74
0.72
0.57
0.47
0.56
0.65
0.46
0.46
0.59
669
653
515
914
512
380
415
417
464
13,367,600
12,177,600
3.48
2.28
0.38
818
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.
a. Credit for sulfuric acid sale not included.
b. Credit for sulfuric acid sale included.
-------
TABLE 43. LIMESTONE SLURRY PROCESS BASE CASE
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Services, Total Total % of
Materials Feed Gas S02 Stack gas Solids utilities, and Pond annual annual annual rev
Total handling p rgg_ar_a_lllon handling^ Absorption reheat d isposal, miscel laneous Construe t ion quant it ies doll ara requireme
Total direct investment, S 26,119,000 1,767,000 1,758,000 4,318,000 8,974,000 1,282,000 1,688,000 1,187,000 5,145,000
Total depreciable investment, $ 46,898,000
Total capital investment, $ 48,943,000
Unit Raw
Direct Costs cost, S material
Delivered raw materials
Limestone 7.00/ton
Annual quantity, tons 159,300
Annual cost, $ j^llj, 100
1,115,100
Subtotal conversion costs 25,500 213,500 300,200 1,123,400 1,572,600 1,101,000 198,400 112,400 154,400 4,801,400 34.14
Total direct costs 1,140,600 213,500 300,200 1,123,400 1,572,600 1,101,000 198,400 112,400 154,400 5,916,500 42.06
Percent of total direct costs 19.28 3.61 5.07 18,99 26.58 18.61 3.35 1.90 2.61
Conversion costs
Operating labor and supervision 12.50/man-hr
Annual quantity, nian-hr 4,200 6,600 1,690 8,500 1.500 3,500 - - 25.990
Annual cost, S 52,500 82,500 21,100 106,200 18,800 43 800 - - 324,900 2.31
Utilities
Steam 2.00/MBtu
Annual quantity, MBtu - 489.BOO _ 489,800
Annual cost, S - 979,600 _ 979,600 6.96
Process water 0.12/kgal
Annual quantity, kgal - 243,400 - - - 243,400
Annual cost, S - 29,200 - - - - 29,200 0.21
Electricity 0.029/kWh
Annual quantity, kWh 675,000 2,657,000 26,100,000 23,699,000 - 456 000 600,000 - 54,188,000
Annual cost, $ 19,600 77,100 756,900 687,300 - 13,200 17,400 - 1,571,500 11.17
Maintenance (labor and material)
Annual cost, S 141,400 140,600 345,400 717,900 102.600 135,000 95,000 154,400 1,832,300 13.04
Analyses 17.00/man-hr
Annual quantity, man-hr 1,500 - 1,880 ~ 380 - - 3,760
Annual cost, S 25^500 ^__-__ - _-_ 32,000
-------
TABLE 44. LIME SLURRY PROCESS BASE CASE
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Total direct investment, $
Total depreciable investment, $
Total capital investnent, $
Direct Costs
Delivered raw materials
Liae
Annual quantity, tons
Annual cost, $
Materials Feed
Total handling preparation
23,964,000 1,978,000 660,000
43,126,000
45,319,000
Unit Raw
cost, $ material
42.00/ton
68,600
2,881,200
2.881.200
Services, Total Total
Gas S02 Stack gas Solids utilities, and Pond annual annual
handling absorption reheat disposal miscellaneous construction quantities dollars
4,318,000 8,504,000 1,282,000 1,616,000 1,101,000 4,505,000 23,964,000
68,600
2,881,200
2.881.200
X of
annual revenue
requirements
19.35
19.35
Conversion costs
Operating labor and supervision 12.50/man-hr
Annual quantity, man-hr
Annual cost, 5
Utilities
Stean 2.00/MBtu
Annual quantity, MBtu
Annual cost, $
Process vater 0.12/kgal
Annual quantity, kgal
Annual cost, $
Electricity 0.029/kWh
Annual quant i ty, kUh
Annual coat, $
Maintenance (labor and material)
Annual cost, $
Analyses 17.00/man-hr
Annual quantity, oan-hr
Annual cost, $
Subtotal conversion costs
Total direct costs
4,200
52,500
_
_
825,700
23,900
158,200
1 , 500
25,500
25,500 234,600
2,906,700 234,600
39.66 3.20
6,600
82,500
_
-
582,000
16,900
52,800
-
152,200
152,200
2.08
1,690
21,100
-
-
26.099,500
756,900
345,400
1,880
32.000
1,155,400
1,155,400
15.76
8,500
106,200
_
232,600
27,900
18,739,000
543,400
680,300
-
1,357,800
1,357,800
18.52
1.500
18,800
488,400
976.800
-
-
102,600
380
6j400
1,104,600
1 ,104,600
IS. 07
3,500
43,800
-
-
161,800 600,000
4,700 17,400
129,300 88,100
-
177,800 105,500
177,800 105,500
2.43 1.44
25,990
324,900
488,400
976,800
232,600
27,900
47,008,000
1,363,200
135,200 1,691,900
63,900
135,200 4,448,600
135,200 7,329,800
1.84
2.18
6.56
0.19
9.16
11.36
0.43
29.88
49.23
-------
TABLE 45. LIME SLURRY PROCESS WITH ONSITE CALCINATION
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Total depreciable investment, $
Total capital investment, $
Djrec t^Cpets
Delivered raw materials
Limestone
Annual quantity, tons
Annual cost, $
Coal
Annual quantity, tons.
Annual cost, $
Subtotal raw materials cost
Conversion costs
Operating labor and supervision
Annual quantity, man-hr
Annual cost. $
Utilities
Steam
Annual quantity, HBtu
Annual cost, $
H* Process water
tO Annual quantity, kgal
CD Annual cost, $
Electricity
Annual quantity, kWh
Annual cost, $
Heat credit
Annual quantity, HBtu
Annual credit, $
Maintenance (labor and material)
Annual cost, $
Analyses
Annual quantity, man-hr
Annual cost, $
Subtotal conversion costs
Total direct costs
Materials LlaeBton*. Feed
Total hand ling calcination preparation
siia2i'.ooo ' * '
53,860,000
Unit Raw
cost, $ material
7. 007 ton
129.400
905,800
25.00/ton
19,630
490.800
1,396,600
12.SO/man-hr
4,200 11,680 6.600
52.500 146.000 82,500
2.00/MBtu
_
_
0,12/kgal
_
_
0.029/kUh
1,093,600 4,948,900 582,000
31,700 143,500 16,900
25,100
(50, 200)
205,600 292.300 52,800
1.500 1.500 940
25.500 25.500 16.000
25,500 289,800 547,600 152,200
1,422,100 289,800 547,600 152.200
21.98 4.48 8.46 2.35
Services, Total Total
* * ' ' 1.282,000 1.616.000 1.35 , . . . .
129,400
905,800
19,630
490.800
1,396,600
1,690 8,500 1,500 3,500 - - 37,670
21,100 106.200 18,800 43,800 - - 470,900
488,400 - 488,400
976,800 - 976,800
235,600 - - - - 235,600
28,300 - - - - 28,300
26,099,500 18,739,000 - 161,800 600,000 - 52,224,800
756,900 543,400 - 4,700 17,400 - 1,514,500
- - - 25,100
- - - - - - (50,200)
345,400 680,300 102,600 129,300 108,500 135,200 2,052,000
1,880 380 - - 4,700
32.000 - 6,400 - - 79 900
1,155,400 1,358,200 1,104,600 177,800 125,900 135,200 5,072,200
1,155,400 1,358,200 1.104,600 177,800 125,900 135,200 6,468,800
17.86 21.00 17.08 2.75 1.95 2.09
I of
5.82
3.16
8.98
3.03
6.28
0.18
9.73
(0.32)
13.19
0.51
32.60
41.58
-------
TABLE 46. MAGNESIA PROCESS BASE CASE
ANNUAL REVENUE REQUIREMENTS DIRECT COSTS
Total direct investment, $
Total depreciable investment, $
Total capital Investment, $
Direct Costs
Delivered raw materials
MgO
Annual quantity, tons
Annual cost, $
Catalyst
Annual quantity, liters
Annual cost, $
Agricultural limestone
Annual quantity, tons
Annual cost, $
Subtotal raw materials coat
Conversion costs
Operating labor and supervision
Annual quantity, m*n-hr
Annual coat, $
Utilities
Fuel oil
Annual quantity, gal
Annual cost, $
Steam
Annual quantity, MBtu
Annual cost, $
Process water
Annual quantity, kgal
Annual cost, $
Electricity
Annual quantity, fcWh
Annual cost, $
Heat credit
Annual quantity, MBtu
Annual credit, $
Maintenance (labor and material)
Annual cost, $
Analyses
Annual quantity, man-hr
Annual cost, $
Subtotal conversion costs
Total direct costs
Percent of total direct costs
Materials Feed Ga. soz Stack gas Chloride slurr,
Total handling preparation handling absorption reheat nurse processing
%-1%'ISS, 7°4>00° 3°3>00° MW.OOO 5,447,000 1.198,000 5,066,000 1,110,000
O4,JO5,OOU
65,911,000
Unit Raw
coat, $ material
300.00/ton
1,470
441,000
2.50/llter 1.80O
4,500
15.00/ton
3,240
48.600
494,100
12.50/nan-hr
1,750 4,510 970 5,390 970 5,390 4 510
21,900 56,400 12,100 67,400 12,100 67,400 56 400
*
0.40/8*1
- -
- - - - _
2.00/MBtu
499,000
- - - 998,000
0.1 2 /kgal
7,200 - 24,800 - 163,000
900 - 3,000 - 19,600
0.029/kWh
98J.OOO 313,000 31,320,000 5,272,000 - 7,716,000 3,560,000
28,400 9,100 908,300 152.900 - 223,800 103 200
2.00/MBtu
- -
- - - - — _
49,300 21,200 322,800 380,300 82,900 353,600 77 700
17. 00 /man-hr
425 - - - 1,140 - 760 435
7,200 - - 19,400 - 12.900 7,4OO
7,200 99,600 87,600 1,243,200 623,000 1,093,000 677,300 244,700
501,300 99,600 87,600 1,243,200 623,000 1,093,000 677,300 244,700
5.55 1.10 0.97 13.78 6.90 12.11 7. SO 2.71
(continued)
-------
TABLE 46 (continued)
NO
tsj
Total direct investment, S
Total capital Investment, $
Direct Costs
Delivered raw materials
MgO
Annual quantity, tons
Annual cost, $
Catalyst
Annual quantity, liters
Annual cost, $
Agricultural limestone
Annual quantity, tons
Annual cost, $
Conversion costs
Operating labor and supervision
Annual quantity, man-hr
Annual cost, $
Utilities
Fuel oil
Annual quantity, gal
Annual cost, $
Steam
Annual quantity, HBtu
Annual cost, $
Process water
Annual quantity, kgal
Annual cost, $
Electricity
Annual quantity, kWh
Annual cost, $
Heat credit
Annual quantity, KBtu
Annual credit, $
Maintenance (labor and material)
Annual cost, $
Analyses
Annual quantity, man-hr
Annual cost, S
Subtotal conversion costs
Total direct costs
Percent of total direct costs
Drying
5,518,000
4,650
58,100
4,608,000
1,843,100
4,400
8,800
-
-
3,701,000
107,300
-
~
385 ,300
1,275
21.700
2,424,300
2,424,300
26.86
Services, Total
Acid Acid utilities, and Pond annual
2,243,000 6,000,000 994,000 1,992,000 154,000
1,470
1,800
3,240
4,650 11,730 2,980 - -47 50o
58,100 146,600 37,300
1,678.000 - . . 6,286,000
671,200 - - -
" - - 503,400
12,200 2,152,000 - - - 2 359 200
1,500 258,100 - - -
1,425,000 6,655,000 209,000 600.000 - 61 752 000
41,300 193,000 6,100 17,400
135,600 - - . _ 135,600
(271,200) - - - -
156,000 417,900 68,600 148,400 4,600
1,275 2,550 640 - - 8,500
21,700 43,300 10^900
678,600 1,058,900 122,900 165,800 4,600
678,600 1,058,900 122,900 165,800 4,600
7.52 11.73 1.36 1.84 0.05
Total
annual
dollars
35,354,000
441,000
4,500
48,600
494,100
593,800
2,514,300
1,006,800
283,100
1,790,800
(271,200)
2,468,600
144,500
8,530,700
9,024,800
% of annual
revenue
requirements
2.48
0.03
0.27
2.78
3.34
14.13
5.66
1.59
10.07
(1.52)
13.88
0.81
47.96
50.74
-------
Utility costs for the two lime slurry variations do not differ
greatly. Calcination fuel is classified as a raw material and a heat
credit from the calcination plant partially offsets the higher elec-
tricity cost.
The lime slurry process with onsite calcination has lower raw
material costs (0,40 mill/kWh) than the lime slurry process using
purchased lime. The higher operating labor and maintenance conversion
costs and higher indirect costs arising from the calcination plant more
than offset the lower raw material costs.
The magnesia process has the lowest raw material costs (0.14 mill/kWh);
however, utility costs (1.52 mills/kWh), including a reduction for a
heat credit, are double those for the waste-producing processes. Fuel
oil cost (0.72 mill/kWh) is the largest element in the magnesia process
utility costs. Utility costs and the higher indirect costs resulting
from the higher capital investment are the major differences between the
magnesia process and the waste-producing processes. Byproduct acid
sales result in a net credit (sales less 10% marketing) of 0.69 mill/kWh,
a reduction of 15% in the gross revenue requirements.
Case Variations
The effects of power plant size and coal sulfur contents on annual
revenue requirements are shown in Figures 27-29. The magnesia process
costs include the credit for acid sales.
The costs for each process show similar behavior. The lime slurry
process and limestone slurry process costs diverge as power plant size
and coal sulfur content increase, however. Much of this is due to the
large cost differences between lime and limestone. The raw material
costs are a higher percentage of total annual revenue requirements for
the lime process than for the limestone or magnesia processes. There-
fore, it benefits less from the capital investment (fixed cost) scale
economies as the power plant size increases. The magnesia process,
which requires little raw material, and the lime slurry process with
onsite calcination, which uses limestone, increase at about the same
rate as the limestone slurry process from 200 MW to 1,000 MW. The lime
slurry process revenue requirements increase an average of 31% more than
the other three processes over the same range of power unit sizes.
The revenue requirements of the limestone and lime slurry processes
become equal slightly below the 200-MW power unit size and at about 1.5%
sulfur coal. Thus, the lime slurry process using purchased lime appears
to be more economical than the limestone slurry process for situations
in which raw material consumption is low (small power units or low-
sulfur coal). The limestone slurry process becomes increasingly more
economical, compared with the lime slurry process, as power unit size or
coal sulfur content increases.
123
-------
30
24
18
12
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
Acid sales credit included for
the magnesia process
X Limestone
O Lime
A Lime with calcination
D Magnesia
1
1
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 27. All processes. Effect of power unit size on
annual revenue requirements: new coal-fired units.
124
-------
25
20
H
S5
W
O*
w
W
15
10
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
Acid sales credit included for the
magnesia process
X Limestone
O Lime
A Lime with calcination
0 Magnesia
SULFUR IN COAL, %
Figure 28. All processes. Effect of sulfur content of coal
on annual revenue requirements: new 500-MW coal-fired units.
125
-------
p
w
s
g
o
S5
o
H
H
en
O
w
PH
O
w
20
15
10
X Limestone
O Lime
A Lime with calcination
P Magnesia
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
800
700
600
500
400
300
200
Q
H
>
O
8
H
O
H
I
100
W
1
1
I
I
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 29. All processes. Effect of power unit size on average unit
operating cost, $/ton of coal burned: new 500-MW coal-fired units.
126
-------
As coal sulfur content Increases from 2% to 5% the percent increase
in revenue requirements for the limestone slurry process is 136%, followed
by the lime slurry process with onsite calcination with 142%, and the
lime slurry process with 148%. The magnesia process has the largest
increase of 154%.
These curves also show that the lime slurry process and the lime
slurry process with onsite calcination annual revenue requirements
approach each other as the size of the power units and coal sulfur
content increase. Extrapolation of the curves shows that the revenue
requirements become equal at about 1,150 MW for 3.5% sulfur coal. For
existing units the curves meet at about 1,050 MW. These are the points
at which the calcination area becomes economical and can produce lime at
a cost equal to the purchased lime cost. For units burning higher
sulfur coal this occurs at a lower power unit size. For instance, for
units burning 5% sulfur coal, onsite calcination becomes more economical
than purchased lime above about 750 MW.
Another factor that has a large influence on annual revenue require-
ments is a large total capital investment. The limestone, lime, and
lime-with-onsite calcination processes have base-case total capital
investment ranging from $45,319,000 for the lime slurry process to
$53,860,000 for the lime slurry process with onsite calcination process.
This results in corresponding capital charges of $6,485,000 for the lime
slurry process and $7,741,200 for the lime slurry process with onsite
calcination. The magnesia process base-case capital investment is
$65,894,000 which results in $9,528,800 in capital charges. This is an
average of 35% more than the capital charges for the waste-producing
processes.
Variations in Economic Factors
Costs and charge rates were varied from the base-case values to
determine the effect of changes in economic factor's on total costs. The
factors evaluated and the ranges of variation are listed in Table 47.
Each range corresponds to differences in design or cost which might be
encountered in site-specific applications. Limestone prices, for example,
represent the effect of plant location. Operating labor cost might also
be affected by plant location.
The sensitivities of the limestone slurry process and the lime
slurry process costs to raw material cost variations are generally the
same for all three processes and for both power plant size and coal
sulfur variations.
The typical effect of different operating labor costs at different
power unit sizes on annual revenue requirements for the four processes
is shown for the limestone slurry and lime slurry processes in Figures
30 and 31, respectively. Figure 32 shows how operating labor cost
affects the annual revenue requirements for new 500-MW units burning
coal with different sulfur concentrations.
127
-------
TABLE 47. SENSITIVITY VARIATIONS STUDIED IN THE ECONOMIC COST PROJECTIONS
Item
Process
Power ^
description0
Annual revenue requirements
Base value
Range of variations
oo
Raw material price
Operating labor
Maintenance
Capital charges
Product revenue
Limestone
Lime
Lime with
calcination
Limestone
Lime
Magnesia
Lime
Magnesia
Magnesia
Magnesia
1 and 2 Limestone, $7/ton
1 Lime, $42/ton
1 Limestone, $7/ton
1 and 2 Labor, $12.50/man-hr
1 Labor, $12.50/man-hr
2 Labor, $12.50/man-hr
1 8% of direct investment excluding
pond construction plus 3% of
pond construction
1 and 2 Average capital charges, 6.0%
of total depreciable investment
plus 8.6% of total capital
investment
1 and 2 100% sulfuric acid, $25/ton
57%-186% of base case
83%-155% of base case
57%-186% of base case
100%-300% of base case
100%-300% of base case
100%-300% of base case
75%-150% of base case
75%-150% of base case
67%-l60% of base case
a. Power unit description
1. New power units: 200, 500 and 1,000 MW; 3.5% sulfur in coal.
2. New power unit, 2.0%, 3.5%, and 5.0% sulfur in coal.
-------
30
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
25
H
"Z
W
Pi
M
G
o-
W
w
W
20
15
10
300%
200%
Base
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 30. Limestone slurry process. Effect of power unit size
and variations in operating labor cost on annual revenue
requirements: new coal-fired units.
129
-------
30
I
I
I
CO
W
2
W
O-
w
W
W
w
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
25
20
15
10
300%
200%
Base"
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 31. Lime slurry process. Effect of power unit size
and variations in operating labor cost on annual revenue
requirements: new coal-fired units.
130
-------
25
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
Acid sales credit included for the
magnesia process
20
H
§
w
w
15
10
300%
200%
Base
300%
200%
Base
D Magnesia process
X Limestone process
12345
SULFUR IN COAL, %
Figure 32 . Magnesia and limestone processes. Effect of sulfur
in coal and variations in operating labor cost on
annual revenue requirements: new 500-MW units.
131
-------
Figure 33 shows the effect of varying maintenance cost on annual
revenue requirements for the lime slurry process with onsite calcination
at different power unit sizes. Figure 34 shows the results of changes
in maintenance cost for the magnesia process at various coal sulfur
concentrations. The other processes have similar reactions to changes
in maintenance cost shown in these figures.
Figures 35 and 36 show the effect of increased and decreased capital
charges on annual revenue requirements for the magnesia process. The
capital charges are dependent on both the rate and amount of the capital
investment for the process. Since the magnesia process has the largest
capital investment there is a larger increase in capital charges than
for the waste-producing processes with lower capital investments. The
relationships of the curves to each other are the same for each process
as they diverge at the larger power unit size and higher sulfur coal.
The byproduct sales revenue credited to the revenue requirements
reduces the annual revenue requirements between 8% for a new 500-MW unit
using 2% sulfur coal and 21% for a new 500-MW unit using 5% sulfur.
Figure 37 shows the effect of sulfuric acid price on annual income from
sulfuric acid sales. Figure 38 illustrates how this change in byproduct
sales price affects the annual revenue requirements. Figures 39 and 40
show the effect of sulfuric acid sales price on annual byproduct revenue
and annual revenue requirements for new 500-MW units using coals with
various sulfur contents. By increasing the sale price of sulfuric acid
to $40 per ton the annual revenue requirements for the new 3.5% sulfur
coal-fired units are brought into the range of the waste-producing
processes. At $49 per ton for sulfuric acid, the base-case magnesia
process annual revenue requirements are the same as the base-case lime
slurry process with onsite calcination. For the new 1,000-MW power
plants and $46 per ton for sulfuric acid, the magnesia process annual
revenue requirements are about the same as those of the lime slurry
processes.
The sensitivity of the limestone, lime, and lime-with-calcination
processes to various raw material costs are shown in Figures 41-44. The
effect of varying raw material costs on annual revenue requirements is
generally the same for all three waste-producing processes. The magnesia
process, however, uses such a relatively small amount of makeup MgO that
there is little effect on the annual revenue requirements. Figure 42
shows the effect of limestone cost on the annual revenue requirements
for the limestone and lime-with-calcination processes for different coal
sulfur contents.
Lifetime Revenue Requirements
Lifetime revenue requirements for the base cases and all of the
case variations are shown in the appendix. These tables provide a
computer-calculated year-by-year tabulation of operating conditions and
revenue requirements. The calculations are based on the design and cost
132
-------
30
T
T
3.5% sulfur ±n coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
24
18
O*
W
w
w
12
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 33 . Lime slurry process with onsite calcination. Effect
of power unit size and variations in maintenance cost on annual
revenue requirements: new coal-fired units.
133
-------
25.
20
1.5
cx
w
w
PS
10
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
Acid sales credit included
12345
SULFUR IN COAL, %
Figure 34. Magnesia process. Effect of sulfur in coal and
variations in maintenance cost on annual revenue
requirements: new 500-MW units.
134
-------
40
3.5% sulfur in coal
1.2 Ib SO /MBtu emission limit
7000 hour annual operation
32
H
23
Cd
O"
W
W
W
W
Crf
24
75%
16
I
200
400 600
POWER UNIT SIZE
800
1000
Figure 35. Magnesia process. Effect of power unit size and
variations in capital charges on annual revenue
requirements: new coal-fired units.
135
-------
30
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
Acid sales credit included
•CO-
IS
CO
H
H
W
W
W
W
24
18
12
12345
SULFUR IN COAL, %
Figure 36 . Magnesia process. Effect of sulfur in coal and
variations in capital charges on annual revenue
requirements: new 500-MW units.
136
-------
T
I
T
10
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
co
w
CO
H
o
!=)
§
pa
w
g
o
a
$25/ton
(base case)
$15/ton
200
400 600 800
1000
POWER UNIT SIZE, MW
Figure 37. Magnesia process. Effect of power unit size
and variations in sulfuric acid price on total annual income
from byproduct sales: new coal-fired units.
137
-------
40
3.5% sulfur in coal
1.2 Ib SCL/MBtu emission limit
7000 hour annual operation
$0/ton
30
c/o
H
w
Pi
M
P
w
Pi
w
w
pi
20
10
X Limestone
Q Magnesia
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 38. Magnesia process compared with limestone.
Effect of power unit size and variations in sulfuric acid sale
price on annual revenue requirements: new coal-fired units.
138
-------
T
T
w
to
§
OS
PL,
3
I
5
u
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
$25/ton .
(base case)
$15/ton
SULFUR IN COAL, %
Figure 39. Magnesia process. Effect of sulfur in coal
and variations in sulfuric acid price on total annual
income from byproduct sales: new 500-MW units.
139
-------
5
30
24
C/O
H
§
C4
W
18
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
12
$0/t
on
case)
X Limestone
D Magnesia
SULFUR IN COAL, %
Figure 40. Magnesia process compared with limestone.
Effect of sulfur in coal and variations in sulfuric acid
price on annual revenue requirements: new 500-MW units.
140
-------
T
T
T
25
20
15
W
10
3.5% sulfur coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
$13/ton
$10/ton
****$?/ton
$4/ton
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 41. Limestone slurry process. Effect of power unit
size and variations in limestone price on annual revenue
requirements: new coal-fired units.
141
-------
20
15
10
0
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
X Limestone
& Lime with onsite calcination
5.0% sulfur
5.0% sulfur
3.5% sulfur
3.5% sulfur
2.0% sulfur
2.0% sulfur
05 10 15
COST OF LIMESTONE, $/TON
Figure 42. Lime slurry process with onsite calcination and
limestone slurry process. Effect of sulfur in coal and
variations in limestone price on annual revenue
requirements: new 500-MW units.
142
-------
30
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
25
CO
H
PS
B-
w
pi
w
§
Pi
20
15
10
$137 tor
10/ton
..$7/ton
$4/toTi
200
400
600
800
1000
POWER UNIT SIZE
Figure 43 . Lime slurry process with onsite calcination. Effect
of power unit size and variations in limestone price on annual
revenue requirements: new coal-fired units.
143
-------
30
H
2
w
Cd
H
o-
W
w
w
w
25
20
15
10
3.5% sulfur in coal
1.2 Ib S02/MBtu emission limit
7000 hour annual operation
$65/ton
$55/ton
$50/ton
$42/toiT
$35/ton
I
I
I
200
400 600 800
POWER UNIT SIZE, MW
1000
Figure 44. Lime slurry process. Effect of power unit size and
variations in lime price on annual revenue requirements:
new coal-fired units.
144
-------
factors described in the premises except that capital charges are based
on the undepreciated investment. Total and discounted costs are shown
for the magnesia process. The net revenue column shows the credit of
$22.50 per ton for 100% sulfuric acid ($25.00 per ton less 10% for
marketing).
The differences in the 30-year cumulative net increase in power
costs among the four processes show the effect of higher yearly operating
cost over the life of the power plant. The lime slurry process base
case is $7,700,000 (2%) more than base-case limestone slurry process
while the lime slurry process with onsite calcination is $37,800,000
(11%) more and the base-case magnesia process is $102,039,200 (28%) more
than the limestone slurry process. Because of the shorter operating
time in the later years of plant life and the decrease in the cost of
capital, the average yearly operating cost is about two-thirds of what
it would be if each year had the first-year operating cost. The cumulative
lifetime costs for the four processes at varied sulfur removals are
compared in Table A8.
TABLE A3. COMPARISON OF CUMULATIVE LIFETIME DISCOUNTED
PROCESS COSTS FOR DIFFERENT SO REMOVAL LEVELS
Cumulative lifetime discounted
process cost, mills/kWh (base case)
79% SO- removal
Increase resulting
from increased
Process
Limestone
Lime
Lime with onsite
calcination
Magnesia
(1.2 lb-S00/MBtu)
5.64
5.76
6.23
7.93
90% SO,, removal
L
5.83
6.01
6.47
8.31
mills/kWh
0.19
0.25
0.24
0.38
%
3.4
4.3
3.9
4.6
a. Credit for acid sales included.
Sale of the sulfuric acid in the magnesia process reduces the
lifetime operating cost approximately 10% for base-case conditions.
Table 49 is a summary of the lifetime sulfuric acid production and
credit for all magnesia process case variations.
The variation of levelized revenue requirements with power unit
size for new power units is shown in Figure 45 and the variation with
coal sulfur content is shown in Figure 46. A factor for the effect of
inflation is not included.
145
-------
TABLE 49. MAGNESIA PROCESS
LIFETIME SULFURIC ACID PRODUCTION AND CREDIT
Case
Years Lifetime production Net revenue,
remaining 100% sulfuric acid, $/short ton
life short tons sulfuric acid
Cumulative revenue
Actual,
mills/kWh
Discounted,
mills/kWh
Coal-Fired Power Unit
1.2 Ib S02/MBtu heat input
allowable emission
200 MW E 3.5% sulfur
200 MW N
500 MW E
500 MW N
3.5% sulfur
3.5% sulfur
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
375,000
805,500
1,459,500
906,000
1,966,500
3,027,000
2,855,500
3,805,500
2,242,500
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
0.74
0.71
0.71
0.32
0.69
1.07
0.69
0.67
0.79
0.73
0.71
0.71
0.32
0.69
1.07
0.69
0.67
0.80
25
629,000
22.50
0.30
0.31
-------
1600
X Limestone
O Lime
^ Lime with onsite calcination
Magnesia (credit for acid sales
included)
p
Cn
o
H
H
•Z.
w
§-
a
w
P
§
I
55
Pi
w
t-0
1200
800
400
3.5Z sulfur in coal
1.2 Ib SO.,/MBtu emission limit
200
26
22
18
14
10
$
o
o
H
H
13
o-
w
a
w
H
t-H
a
o
w
t>J
w
w
200
400
600
800
1000
POWER UNIT SIZE, MW
Figure 4r). AU processes. Kffec-.t of power unit size on levelized unit
revenue requi rc-ments: new coal-fired units.
147
-------
o
H
g
S3
1500
g- 1000
w
W
500
1.2 lb S02/MBtu emission
limit
7000 hour annual operation
Credit for acid sales
included in the magnesia
process
X Limestone
O Lime
A Lime with onsite calcination
D Magnesia
1.2 lb S02/MBtu emission limit
7000 hour annual operation
2 3
SULFUR IN COAL
Figure 46. All processes. Effect of sulfur in coal on levelized
unit revenue requirements: new 500-MW units.
148
-------
The effect of raw material costs on the limestone slurry and lime
slurry processes shown in the first-year revenue requirements comparison
is illustrated more graphically in the levelized lifetime revenue require-
ments comparison. In the latter case the lime slurry process has lower
lifetime revenue requirements for lower raw material consumption condi-
tions (2% sulfur coal, 200-MW power plant) than the limestone slurry
process.
Alternate Particulate Removal and Waste Disposal Comparison
In this evaluation costs for the collection and disposal of fly ash
are not included because the costs are common to all of the processes.
Other possible, perhaps more site-specific, combinations of fly ash and
S02 removal processes are possible, however. For example, land avail-
ability or environmental considerations could preclude ponding as a
disposal method. A possible alternative for the magnesia process is the
use of a wet particulate scrubber to attain the 0.1 Ib/MBtu NSPS. This
would eliminate the need of separate chloride scrubbing and disposal.
The effects of these modifications are shown in Tables A-31, A-32,
A-123, and A-124 in the appendix and are summarized in Table 50. The
base-case limestone slurry process was modified to include a fixation
and landfill disposal process previously evaluated by TVA (Barrier and
others, 1978, 1979). The sludge was dewatered and blended with dry fly
ash and lime to form a solid which was trucked to a landfill. A credit
for the cost of a fly ash pond was included. The magnesia process was
modified by increasing the chloride scrubber capacity to attain 0.10
Ib/MBtu particulate removal and credit for the ESP replaced was given.
The credits make these process modifications comparable to the base-case
conditions, which exclude ESP costs.
TABLE 50. CASE VARIATIONS FOR MAGNESIA PROCESS WET PARTICULATE SCRUBBING
AND LIMESTONE PROCESS WASTE FIXATION AND LANDFILL DISPOSAL
Annual
net revenue
Capital requirements,
Process investment, $/kW
Limestone, base case
Limestone, fixation-landfill
Magnesia, base case
Magnesia, particulate scrubbing
98
80
132
116
mllls/kWh
4.02
4.62
5.08
4.97
a. Including byproduct sulfuric acid credit at $25 per ton.
149
-------
For both processes there is a reduction in capital costs. In the
limestone slurry process the reduction is largely the result of elimina-
tion of the pond costs. In the magnesia process the reduction is the
result of the ESP credit, which is much larger than the increased costs
for combined particulate and chloride scrubbing.
In annual revenue requirements, however, there is only a 0.37
mill/kWh difference between the processes, compared to a 1.06 mills/kWh
difference for the base cases. The increase in the limestone slurry
process costs is largely the result of greatly increased labor and
supervision costs, particularly for disposal operations. The reduction
in the magnesia process costs is the result of decreased conversion
costs because of the ESP credit and decreased capital charges.
ENERGY EVALUATION AND COMPARISON
In addition to the energy required within the battery limits of an
FGD system, use of the technology also consumes energy in the preparation
of raw materials and in disposal of byproducts; the total is defined as
ground-to-ground energy requirements. The ground-to-ground energy require-
ments represent all energy withdrawn from a hypothetical total-available-
energy reservoir because of operation of the particular FGD process. In
the case of byproduct acid production, the acid replaces acid that would
have been produced by conventional means. Thus, in terms of the ground-
to-ground energy concept, it represents energy that was not withdrawn
from the hypothetical reservoir. It therefore represents an energy
credit for the process. The component energy uses considered in the
ground-to-ground assessment are:
(1) Mining, separation, and sizing of absorbent
(2) Processing prior to delivery to FGD process
(3) Transportation to power plant
(4) FGD battery limits
(a) Electricity
(b) Heat
(5) Byproduct disposal
(a) Electricity
(b) Fuel
A summary of the total energy requirements expressed as equivalent
heat per unit of sulfur removed is shown in Figure 47 for the following
absorbents:
(1) Limestone
(2) Lime (calcined onsite)
(3) Magnesia from magnesite
(4) Magnesia from seawater
150
-------
25 -
20 -
! -
'
;
-
-
10
.
DTr
11 Ah
H Mi
1S3 Tr
DSt
b>
1 Sti
2 Rlt
3 Co.-
4 Fu«
ansportation
D
sorbent processing
ning
tal net energy consumption
ilfuric acid
'product credit ^
x\
;am
;ctricity
11 1
;1 oil
1
.
^ < -
iii
i
i
2 >-H
!
B
.
*
I
1
1
I
1
i
\
I
.
i
-
pMM
-
Limestone Lime with onsite Magnesia from Magnesia from
calcination magnesite seawater
Figure 47. Total energy requirement per pound
of sulfur removed. Base case.
151
-------
Onsite calcination of lime and purchased lime energy requirements were
so close that the latter was eliminated from the comparison. Development
of the various components is described below.
Mining, Separation, and Sizing
In order to compare costs on a similar basis, the energy require-
ments per ton of absorbent were first estimated. These were translated
to energy requirements per pound of sulfur removed. The comparisons are
shown in Figure 48. The range is from 0.191 MBtu for limestone, which
is usually quarried from near-surface thick deposits, to 1.2 MBtu for
the magnesite which occurs in relatively thin beds with considerable
interbedded waste material. About 2 tons of limestone are needed to
make 1 ton of lime; 2-3/4 tons of crude ore are required for 1 ton of
magnesite; and about 4.5 tons of dolomite, MgCa(CO ) are used in the
preparation of 1 ton of magnesia by the seawater process. The varying
quantities of raw materials are reflected in the range of energy usage
to produce 1 ton of absorbent. The consumption rate in the FGD process
varies with the type of absorbent. Therefore the relative contribution
of mining, separation, and sizing to overall energy requirements based
on sulfur removed, as shown in Figure 49, is not proportional to the
energy requirements per ton of absorbent.
Absorbent Processing
The energy requirements for processing the sized raw material into
the absorbent varies widely, as shown in Figure 50. Limestone requires
no further processing except size reduction from 0 x 1-1/2 to 70% minus
200 mesh; the energy for this grinding operation is included in the FGD
battery limits estimate. The energy requirements for calcining limestone
to produce lime are 6.27 MBtu per ton of lime produced. The energy
requirements to produce magnesia from magnesite ore are 7.61 MBtu per
ton. It is slightly higher than lime, in spite of a lower calcining
temperature, because more ore must be processed. Magnesia from seawater
has energy requirements of slightly over 24 MBtu per ton of magnesia.
This high energy use results from the relatively low magnesium concen-
tration in the raw materials and the high temperatures required for
thermal decomposition of the raw and intermediate materials.
Transportation
The energy requirements for transporting the absorbents also varies
over a wide range, as shown in Figure 51. The short distance from
quarry to power plant (a national average of 32 miles, calculated from
limestone quarry and power plant location data, is used) results in the
low energy requirements for transportation of limestone of 0.077 MBtu
per ton. The lime transportation energy requirements of 0.145 MBtu per
ton of lime is a reflection of the limestone to lime equivalent weights
and processing losses. Magnesia from magnesite has the highest transporta-
tion energy requirements, 1.563 MBtu per ton of magnesia, because of the
location of the only U.S. commercial magnesite deposit in Gabbs, Nevada,
152
-------
1.5
§
E-i
r
4J
1.0
-"
Jkl
0.5
o
-
M
H
-
fl
—
PC
0.5
0
Limestone
Lime with
calcination
Magnesia Magnesia
from from
magnesite seawater
Figure 48. Mining, separation, and sizing energy
requirements per ton of absorbent.
Limestone Lime with Magnesia Magnesia
onsite from from
calcination magnesite seawater
Figure 49. Mining, separation, and sizing energy
requirements per pound sulfur removed. Base case.
-------
.
I
»J
t
LO
1.5
2.0
o
-
1.5
0.
n
Lime with Magnesia Magnesia
onsite from from
calcination magnesite seawater
Figure 50. Absorbent processing energy require-
ments per ton of absorbent production.
Limestone Lime with Magnesia Magnesia
onsite from from
calcination magnesite seawater
Figure 51. Transportation energy require-
ments per ton of absorbent.
-------
with respect to the base-case location in the Chicago area. The trans-
portation energy requirements of 0.806 MBtu per ton for magnesia from
seawater reflects the dual energy expenditures in shipping dolomite to
the Florida plant location and magnesia from Florida to the Chicago area.
Cumulative Energy Requirements for Delivered Absorbents
The energy requirements per ton of absorbent delivered to the base-
case power plant location are presented in Figure 52. Limestone, with
low mining and transportation costs and no chemical processing require-
ments, has a cumulative energy requirement of only 0.268 MBtu per ton of
limestone delivered. Lime, principally because of the calcining energy
requirements, is over 25 times as energy-intensive, with a total energy
consumption of 6.777 MBtu per ton. Magnesia from magnesite has higher
energy requirements of 10.376 MBtu per ton of delivered magnesia. The
highest energy requirements are for magnesia from seawater which requires
25.096 MBtu per ton of magnesia delivered. Processing energy is the
dominant element in the total energy requirements of all the delivered
absorbents except limestone. These results are summarized in Table 51
which also shows the base-case quantities of each absorbent needed
per hour.
TABLE 51. ABSORBENT ENERGY REQUIREMENTS
Mining, separation
and sizing
Absorbent
processing
Transport
Total energy
requirement,
MBtu/ton,
delivered to
power plant
Limestone
0.191
0.077
0.268
Lime onsite
calcination
Magnesia from
magnesite
0.360
6.272
0.145
6.777
1.20
7.613
1.563
10.376
Magnesia from
seawater
0.882
24.008
0.806
25.696
Lb absorbent con-
sumed per Ib of
sulfur removed 4.58 1.98 0.043
Btu per Ib sulfur
removed 614 6,697 219a
0.04a
542a
a. Includes only makeup MgO,
requirements.
Regeneration of MgO is included in FGD energy
155
-------
30
25
20
o
H
15
10
0
jMining, separation, and sizing
Absorbent processing
Transportation
Limestone Lime with onsite Magnesia from Magnesia from
calcination magnesite seawater
Figure 52. Total energy requirements per ton of"absorbent.
156
-------
The hourly consumption of limestone in the 500-MW base case is over
100 times that of magnesia. Lime consumption is almost 50 times the
magnesia consumption. The differences in absorbent consumption for the
three processes result in the lime slurry process having substantially
higher absorbent energy requirements (6.7 kBtu per Ib sulfur removed)
than the limestone slurry process or the magnesia process using either
of the magnesia sources. Magnesia from magnesite is, in fact, the least
energy-intensive absorbent (0.22 kBtu per Ib sulfur removed) in terms of
material delivered to the power plant. The processing energy requirements
are shown in Figure 53. Transportation energy requirements are shown in
Figure 54.
FGD Process Battery Limits
The energy requirements for operation of the FGD processes are
summarized in Table 52. The energy requirements for the FGD process are
the major portion of the total, as shown in Figure 55. For the lime
slurry and limestone slurry processes the energy needs are about equally
divided between electricity to power the equipment and thermal energy
for reheat to 175 F. For the magnesia process, the heat for calcining
the magnesium sulfite adds a substantial amount to the energy require-
ment and accounts for almost one-half of the total in the FGD process.
TABLE 52. FGD ENERGY ALLOTMENT
(Base case: 500 MW, 3.5% sulfur)
Btu/lb Sulfur Removed
Steam Electricity Fuel oil Heat credit Total
Limestone 7,047 7,017 - - 14,064
Lime 7,047 6,087 - - 13,134
Magnesia (with
magnesite or seawater) 7,251 7,956 12,187 (1,209) 26,185
Byproduct Disposal
With the lime and limestone process, the byproduct is a waste
material and disposal of untreated sludge by pumping to an onsite
storage pond as assumed in this study requires only a small fraction of
the total; however, if treatment is required by future regulations and
the treated sludge is handled offsite, the energy penalty could be
substantial.
157
-------
co
-
J
E
v.
--
a
-
0
0.20
g
ojO.15
g
:
cn
pe
a
0.1C
0.0
r
Lime with Magnesia Magnesia
onsite from from
calcination magnesite seawater
Figure 53. Absorbent processing energy require-
ments per pound sulfur removed. Base case.
Limestone Lime with Magnesia Magnesia
onsite from from
calcination magnesite seawater
Figure 54. Transportation energy require-
ments per pound sulfur removed. Base case.
-------
30
25
20
15
10
.
-5
1 Steam «^
2 Elect
3 Fuel
4 Heat
•M
M
ric
oil
ere
1
1
n
i
ity
dit
1
NXS\
SSN\
]
:
1
I
1
1
•
Limestone
Lime with
onsite
calcination
Magnesia
from
magnesite
Magnesia from
seawater
Figure 55. FGD energy requirements per pound
of sulfur removed. Base case.
159
-------
The byproduct from the magnesia process is sulfuric acid, a standard
commercial chemical. The electrical energy for pumping the acid from
the acid plant to storage and from storage to transport vehicles is
small. The energy in the form of fuel for transport vehicles to deliver
the product will vary depending on method and distance of shipment. In
this study, the transportation of acid to final destination has not been
included in the energy assessment because marketing was beyond the scope
of the study. For the base-case Chicago area, there is an existing
sulfuric acid demand nearby. Sulfuric acid would probably be shipped by
tractor trailer. The energy requirements for highway transportation for
a 25-mile distance would be 0.120 MBtu per ton of acid. This amounts to
0.87 gallons of diesel fuel consumed per ton of sulfuric acid shipped.
In this shipping example, the magnesia process ground-to-ground energy
requirements would be increased by 0.88%. Since rail shipments consume
less than one-third the energy for trucking per ton-mile, the acid could
be shipped 160 miles by rail with the same energy consumption of the 25-
mile truck shipment.
Byproduct Sulfuric Acid Energy Credit
Sulfuric acid is normally produced from elemental sulfur that is
mined by the Frasch method, an energy-intensive operation. Natural gas
is the usual fuel. Replacement of acid produced from sulfur with
recovered byproduct acid will conserve the energy used in mining, trans-
portation, and conversion of sulfur to sulfuric acid. Offsetting these
energy savings, the heat generated from combustion of sulfur is not
available and must be deducted in an energy balance. (The potential
combustion energy in the unmined sulfur is, however, available for
future use.)
The component energy changes and the net effect of these on the
ground-to-ground energy requirements for the magnesia process are shown
in Table 53.
Total Ground-to-Ground Energy Requirements
A summary of the component energy requirements is shown in Table 54.
The same data were shown previously in Figure 47.
160
-------
TABLE 53. ENERGY REQUIRED FOR PRODUCTION OF SULFURIC ACID FROM SULFUR
(108,000 tons of 100% H2SO, per year)
Energy required,
Energy expenditure Btu/lb sulfur removed
Sulfur mining (natural gas) 7,940
Sulfur transport (diesel oil) 343
Sulfuric acid production
(electricity) 937
Heat recovery in sulfuric acid
production (steam) -3,729
Net energy requirements 5,491
a. Based on 108,000 tons of 100% H2S04 per year (the quantity
produced in the base-case magnesia process).
TABLE 54. GROUND-TO-GROUND ENERGY REQUIREMENTS ASSESSMENT
Btu/LB SULFUR REMOVED
Lime-with-onsite Magnesia-
Limestone calcination maenesite
Mining
Absorbent processing
Transportation
FGD
Sludge disposal
Total
Byproduct credit
Net total
MBtu/kWh
% difference from
limestone process
% of total power
unit energy output
438
-
176
14,042
22
14,678
—
14,678
291
0
3.24
356
6,198
143
13,165
15
19,877
—
19,877
395
35
4.39
25
161
33
26,387
-
26,658
(5,491)
21,115
420
44
4.67
Magnesia-
seawater
18
507
17
26,387
—
26,929
(5,491)
21,438
426
46
4.73
161
-------
Previous assessments of FGD-only energy requirements have indicated
a substantial energy penalty for the magnesia scrubbing process compared
to the limestone slurry and lime slurry processes. This ground-to-
ground assessment results in a substantial reduction in the relative
energy differences. The magnesia process requires only 44% to 46% more
energy than the limestone scrubbing process. In the FGD-only assessment
magnesia consumed about 88% more energy. Moreover, the energy require-
ments difference between magnesia and lime scrubbing is narrowed from
over 100%, for the FGD battery limits, to about 7% in the ground-to-
ground comparison. The differences in the ground-to-ground and FGD-only
energy comparison are illustrated below.
Energy requirements as percent above lowest process
FGD-only Ground-to-ground
Limestone 7% 0%
Lime 0% 35%
Magnesia (from magnesite) 100% 44%
Magnesia (from seawater) 100% 46%
162
-------
CONCLUSIONS
The conclusions of this study have been summarized for capital
investment, annual revenue requirements, ground-to-ground energy require-
ments, and process status. They are listed as follows.
CAPITAL INVESTMENT
1. The capital investments for all three processes are substantially
increased over the results reported in 1975 (McGlamery and others).
While the ranking of the three processes has not changed, the
magnesia process capital investment has increased at a greater
rate than those for the other processes. The principal reasons
for this are changes and additions in the less mature magnesia
process (such as materials-handling changes and chloride purge
addition) and inflation effects.
2. The lime process continues to have the lowest capital investment
requirements followed closely by limestone. Lime-with-onsite
calcination is substantially higher than limestone and magnesia
has the highest capital requirements. This relative ranking can
be expected to continue unless process improvements are pursued
with MgO scrubbing as they have been with limestone and lime
scrubbing.
3. In the oil-fired case variation the difference between capital
investments for the magnesia and lime-with-onsite calcination is
negligible. Elimination of the chloride purge and fly ash dis-
posal systems (not required for oil firing) reduces the magnesia
capital requirements almost to those of the lime-with-onsite-
calcination system.
4. The influence of waste disposal pond capital costs is greater for
the smaller (200 MW) power plants. Economies of scale reduce
this influence substantially with the larger (500 and 1000 MW)
plants.
5. The capital investment costs related to spent-slurry processing
in the magnesia process are about three times greater than capital
investment disposal costs in the waste-producing processes.
Elimination of pond costs does not compensate for the additional
equipment requirements of the magnesia process.
163
-------
6. The removal of 90% of the S02 to meet the revised NSPS (as
opposed to the base-case removal to 1.2 Ib SCL/MBtu heat input of
the former NSPS) has only a small effect on the capital investments
for all three processes.
7. As the coal sulfur content increases, the magnesia and lime-
with-onsite-calcination processes capital requirements increase
at a slightly greater rate than those for limestone and lime
processes. This is to be expected because of the more complicated
(more items of equipment) magnesia and lime-with-onsite-calcination
processes.
ANNUAL REVENUE REQUIREMENTS
1. The ranking of the processes by annual revenue requirements has
not changed from that of the earlier evaluation (McGlamery and
others). For the base-case conditions limestone is lowest (4.02
mills per kWh), followed by lime (4.25 mills per kWh), lime-with-
onsite calcination (4.45 mills per kWh), and magnesia (5.05 mills
per kWh, including credit for acid sales).
2. The range of annual revenue requirements is significantly narrower
than the range of capital investment requirements. The base-case
revenue requirements difference between the limestone to magnesia
processes is under 26% whereas the base-case capital investment
for the magnesia process is over 45% greater than that for the
lime process.
3. As found in earlier studies, the annual revenue requirements per
kWh are reduced substantially for all processes as the power
plant size is increased from 200 to 1000 MW. The reduction in
mills per kWh is about the same for the limestone, lime-with-
onsite calcination, and magnesia processes. The lime process
with its lower capital investment, is slightly less sensitive'to
scale-up economies.
4. Lime is the highest cost absorbent in terms of dollars per ton of
sulfur removed. The lime process is also the least capital-
intensive and therefore benefits less than the others in scale-un
economies resulting from increased sulfur content of the fuel.
The lime-with-onsite-calcination process increase in annual
revenue requirements is less than for the lime process due to the
improved economics of onsite calcination at the higher rates
required for higher sulfur fuel.
5. There are conditions under which the Hme process is more economic
to operate than the limestone process. The higher capital charges
for the limestone process, relative to the lime process, make
164
-------
this possible. The lime process has lower revenue requirements
at low raw material consumption levels (small plant size, low-
sulfur coal, and low heat rate) and the limestone process has
lower revenue requirements at high raw material consumption
levels. Slightly below the 200-MW power plant size with 3.5%
sulfur coal, the lime process has lower annual revenue require-
ments. At the 500-MW power plant size, the lime process becomes
more economical with coal sulfur contents below approximately
1.5%.
The economic feasibility of onsite calcination of limestone is
very sensitive to power plant size and sulfur content of the
coal. At the 3.5% sulfur level and delivered costs of $7 and $42
per ton for limestone and lime the break-even power plant size
for the onsite calcination is approximately 1150 MW. With a coal
sulfur content of 5.0%, the minimum power plant size for economical
onsite calcination is approximately 750 MW.
If limestone slurry ponding is not a practical option and fixation
with landfill disposal is utilized, the annual revenue requirements
increase about 15%, despite a reduction in capital requirements
for the fixation-landfill option. Increased labor and materials
costs for fixation-landfill disposal more than offset the capital
requirements reduction.
ENERGY REQUIREMENTS
1. The energy consumed per ton of absorbent delivered to the power
plant (including mining, processing, and transportation energy)
varies almost one hundredfold from limestone (0.27 MBtu per ton)
to magnesia from seawater (25.7 MBtu per ton), however, the
energy use associated with the delivered absorbent is less signifi-
cant when related to the total energy requirement expressed as
energy per unit of sulfur removed.
2. The byproduct credit for reduced energy consumption caused by the
replacement of conventional sulfuric acid production from sulfur
with FGD byproduct acid is a significant element (54.5 MBtu per
hour) of the base-case magnesia process. The application of this
energy credit reduces the total ground-to-ground energy requirements
of the magnesia process by one-fifth.
3. The energy requirements advantage of lime over magnesia within
the FGD process battery limits is nearly eliminated in the ground-
to-ground comparison. The energy advantage of the limestone FGD
process over the magnesia process is reduced over one-half when
compared with the magnesia process on the ground-to-ground basis.
165
-------
PROCESS DEVELOPMENT
The lime and limestone scrubbing technologies are the most highly
developed and most utilized systems in the United States. The magnesia
process, however, is relatively immature and requires additional develop-
ment and demonstration to determine the long-term effects of contaminant
buildup in recycled magnesia, the need for and type of chloride purge
and calcining operation reliability as well as other information which
can be developed only with experience in long-term operation of the
completely integrated system.
166
-------
REFERENCES
Barrier, J. W., H. L. Faucett, and L. J. Henson, 1978. Economics of
Disposal of Lime/Limestone Scrubbing Wastes: Untreated and Chemically
Treated Wastes. Bulletin Y-123, Tennessee Valley Authority, Muscle
Shoals, Alabama; EPA-600/7-78-023a, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina.
Barrier, J. W., H. L. Faucett, and L. J. Henson, 1979. Economics of
Disposal of Lime/Limestone Scrubbing Wastes: Sludge/Flyash Blending
and Gypsum Systems. Bulletin Y-140, Tennessee Valley Authority,
Muscle Shoals, Alabama; EPA-600/7-79-069, U.S. Environmental Pro-
tection Agency, Research Triangle Park, North Carolina.
Chemical Construction Corporation, 1970. Engineering Analysis of
Emissions Control Technology for Sulfuric Acid Manufacturing Processes.
Vol. 1, Chemical Construction Corporation, Consulting Division New
York; NTIS PB 190 393.
Chemical Engineering, 1975-1976. Economic Indicators. Vols. 82 and 83
(all issues).
Chemical Engineers Handbook, 1973. 5th edition, R. H. Perry and C. H.
Chilton, editors, McGraw-Hill, New York.
Coal Age, 1979. Hints on Off-Highway Fuel Savings. 84(4):133, 136.
Duval, W. A. Jr., W. R. Gallagher, R. G. Knight, C. R. Kolarz, and R. J.
McLaren, 1978. State-of-the-Art of FGD Sludge Fixation. EPRI FP-
671, Project 786-1, Final Report. Electric Power Research Institute,
Palo Alto, California.
Electrical World, 1977a. Generation - The Fuels Outlook. 187(5):39.
Electrical World, 1977b. Annual Statistical Report - Declining Orders
Signal Danger. 187(6):50-55.
Federal Register, 1971. Standards of Performance for New Stationary
Sources. 36(247), Part II.
Federal Register, 1979. New Stationary Sources Performance Standards;
Electric Utility Steam Generating Units. 44(113):33580-33624.
167
-------
FERC, 1968. Hydroelectric Power Evaluation, FPC P-35 and Supplement
No. 1, FPC P-38 (1969). Federal Energy Regulatory Commission, U.S.
Government Printing Office, Washington, DC.
FERC, 1973. Steam-Electric Construction Cost and Annual Production
Expenses, Twenty-Fourth Annual Supplement - 1971. Federal Energy
Regulatory Commission, U.S. Government Printing Office, Washington
DC. '
Guthrie, K. M., 1969. Capital Cost Estimating. Chemical Engineering
76(6):114-142.
Kennedy, F. M. and S. V. Tomlinson, 1978. Flue Gas Desulfurization in
the United States - 1977. Bulletin Y-125, Tennessee Valley Authority
Muscle Shoals, Alabama; ANL/ECT-3, Appendix F, Environmental Control
Implications of Generating Electric Power from Coal, Argonne Nation 1
Laboratory, Argonne, Illinois.
Kidder, Peabody & Company, 1978. Electric Utility Generating
Equipment: Status Report on Fossil Boilers. Kidder, Peabody, &
Company, Inc.
Lowell, Phillip S., Meserole, Frank B., Parsons, Terry B., 1977. Precipi-
tation Characteristics of Magnesium Sulfite Hydrates in Magnesium
Oxide Scrubbing. EPA-600/7-77-109.
McGlamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson, L. J
Benson, S. V. Tomlinson, and J. F. Young, 1975. Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes. Bullet-1
Y-90, Tennessee Valley Authority, Muscle Shoals, Alabama; EPA- U
600/2-75-006, U.S. Environmental Protection Agency, Washington DC
McGlamery, G. G., Torstrick, R. L., J. P. Simpson, and J. F. Phillips J
1973. Conceptual Design and Cost Study, Sulfur Oxide Removal from "'
Stack Gas Magnesia Scrubbing - Regeneration: Production of Concen-
trated Sulfuric Acid. Bulletin Y-61, Tennessee Valley Authority
Muscle Shoals, Alabama; EPA-R2-73-244, U.S. Environmental Protection
Agency, Office of Research and Monitoring, Washington, DC.
Peters, M. S., and K. D. Timmerhaus, 1968. Plant Design and Economics
for Chemical Engineers. 2nd edition, McGraw-Hill, New York DO
106-108. ' vv'
Popper, Herbert, 1970. Modern Cost Engineering Technique. MeGraw
Hill, New York.
The Richardson Rapid System, 1978. Process Plant Construction Estimate
Standards. Vols. 1, 3, and 4, 1978-1979 edition, Richardson Engi-
neering Services, Inc., Solana Beach, California.
168
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Rock Products, 1977. Union Lime Company's Ouplaas Works. 80(6): 48-51,
84-88.
Rossoff, J., P. P. Leo, and R. B. Fling, 1978. Landfill and Ponding
Concepts for FGD Sludge Disposal. Preprint of paper presented at
U.S. Environmental Protection Agency Industry Briefing, Research
Triangle Park, North Carolina, August 29, 1978.
Smith, M., and Melia, M., 1979. EPA Utility FGD Survey: July-September
1979. EPA-600/7-79-022f, U.S. Environmental Protection Agency,
Washington, DC.
Tomlinson, S. V., F. M. Kennedy, F. A. Sudhoff, and R. L. Torstrick,
1979. Definitive SO Control Process Evaluations: Limestone,
Double-Alkali, and Citrate FGD Processes. Bulletin ECDP B-4,
Tennessee Valley Authority, Muscle Shoals, Alabama; EPA-600/7-79-
177, U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina.
169
-------
APPENDIX A
TOTAL CAPITAL INVESTMENT, AVERAGE ANNUAL REVENUE REQUIREMENT,
AND LIFETIME REVENUE REQUIREMENT TABLES - ALL PROCESSES AND CASE VARIATIONS
171
-------
TABLE A-l. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200-MW existing)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
tanks, agitators, and pumps)
Cas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and danpers from reheater and stack)
502 absorption (two mobile-bed scrubbers including presatu-
rator and encrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal, 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, $
1,078,000
1,213,000
2,203,000
4,308,000
584,000
1,418,000
10,804,000
648,000
11,452,000
1,444,000
12,896,000
869,000
203,000
2,068,000
670,000
3,810,000
3,341,000
20,047,000
1,860,000
2,406,000
24,313,000
295,000
513,000
25,121,000
(S126/kW)
% of
total direct
investment
8.4
9.4
17.1
33.4
4.5
11.0
83.8
5J)_
88.8
11.2
100.0
6.8
1.6
16.0
5.2
29.6
25.9
155.5
14.4
18.6
188.5
2.3
4.0
194.8
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
172
-------
TABLE A-2. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2QO-MW existing)
Direct Costs
Delivered 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
67,200 tons
7.00/ton
16,440 man-hr 12.50/man-hr
206,800 MBtu
102,800 kgal
23,224,600 kWh
2.00/MBtu
0.12/kgal
0.031/kWh
1,980 man-hr 17.00/man-hr
470,400
470,400
205,500
6.30
6.30
2.75
413,600
12,300
720,000
1,074,000
33,700
2,459,100
2,929,500
5.54
0.16
9.64
14.38
0.45
32.92
39.22
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 annual revenue requirements
1,701,900
2,160,400
656,600
20,600
4,539,500
7,469,000
22.79
28.92
8.79
0.28
60.78
100.00
Equivalent unit revenue requirements
$/ton coal $/MBtu heat $/ton
Mills/kWh burned . input S removed
5.34
11.79
0.56
509
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.
Sulfur removed, 14,670 short tons/yr; solids disposal, 77,790 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $12,896,000; total depreciable investment, $24,313,000; and total
capital investment, $25,121,000.
All tons shown are 2,000 Ib.
173
-------
TABLE A-3
LIMESTONE SLURRY PROCESS VARIATION FRUM BASE CASE: 200 MW EXISTING REGULATED CD. KCQMUMICS
TUTAL CAPITAL INVESTMKN1 25121000
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT NET
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TinN, REQUIREMENT, CUNSUMPTION, CONTRUL
UNIT KW-HR/ MILLION BTU TQNS COAL PROCESS, DRY
START KW /YEAR /YEAR TONS/YEAR SOLIDS
1
4
5 .
6
7
8
9
10 - -
11 5000 9500000 452400 10500 55600
1? 5000 9500000 452400 10500 55600
13 5000 9500000 452400 105QO 55600
14 5000 9500000 452400 105QO 55600
15 .5000 _ 2500000 -S52SQQ 10500 53600
16 3500 6650000 316700 7300 38900
17 3500 6650000 316700 7300 38900
18 3500 6650000 316700 7300 38900
19 3500 6650000 316700 7300 38900
20 3500- 6650000 -316700 7300 - 38900 . _
21 15QO 2850000 135700 3100 16700
2? 1500 2B5000C 135700 3100 16700
23 1500 2850000 1357QO 3100 16700
24 1500 2850000 135700 3100 16700
25 1500 2850000 -135700 3100 16700 -
26 1500 2850000 135700 3100 16700
27 1500 2850000 135700 3100 16700
28 1500 2850000 135700 3100 16700
29 1500 2850000 135700 3100 16700
30 1500- 2850000 135700 3100- 16700
TOT 57500 109250000 5202500 120000 639500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PE« KILOWATT-HOUR
CENTS PE* MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PRnCESS COST DISCOUNTED AT 11.2* TO INITIAL YEAR, DOLLARS
LEVELIZEO INCREASE (DECREASE) IN UNIT OPERATING CUST EO.UIVALENT TO DISCO
DOLLARS PER TON OF COAL BURNED
MILLS PE» KILOWATT-HOUR
CENTS PE* MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
REVENUE,
$/TON
DRY
SOLIDS
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
Q»Q-
0,0
0,0
0.0
0,0
_0»0
UNTED PRQC
TCTA,
OP, ct ST
INCLUDING
REGILAIEK TUTAL
RCI FIR NET
PCWEK SALES
COPA Y, REVENUE,
t/YE R S/YEAR
9073400
8664300
865520C
844610C
B232QCQ
73987CO
71896CC
6980SCO
617 1400
6S622CG
54181CC
5209COO
49999CC
47908CC
4581200
43726CC
41635CO
3954400
3745300
1229500CO
23.63
10.69
112.54
1024.58
5659130C
tss ccsr CVER
21.58
9.76
1C2.75
932.31
O O O O G
0
0
0
D
D
0
0
0
0
Q
0
0
0
0
Q_
0
0.0
0.0
0.0
0.0
0
LIFE DF
0.0
0.0
0.0
0.0
NFT ANNUAL CUMULATIVE
INCREASE NET INCREASE
(INCREASE) (DECREASE)
IM COST OF IN COST OF
POWER, POWER,
J >
9073400
8864300
8655200
8446100
_ -8237000
73*8700
7189600
69805QO
6771400
- 6562300
5418100
5209000
4999900
4790800
_ 45B170Q
4372600
4163500
3954400
3745300
_. 3536200.
122950000
23.63
10.69
112.54
1024.58
56591300
POWER UNIT
21.58
9.7*
102.75
932.31
9073400
17937700
26592900
35039000
-43276000
50674700
57864300
64844800
71616200
-26128300
83596600
88805600
93805500
98596300
--10317BOOO
107550600
111714100
115668500
119413800
--122950000
-------
TABLE A-4. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW)
% of
total direct
Investment. S Investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (two mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculatlon tanks,
agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal, slurry disposal pumps,
and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Fond 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
972,000
1,195,000
1,850,000
4,038,000
569,000
1,266,000
9,890,000
593,000
10,483,000
2,598,000
13,081,000
916,000
207,000
2,045,000
678,000
3,846,000
3,385,000
20,312,000
1,771,000
2.437,000
24,520,000
514,000
495,000
25,529,000
($128/kW)
7.4
9.1
14.1
30.9
4.4
9.7
75.6
4.5
80.1
19.9
100.0
7.0
1.6
15.6
5.2
29.4
25.9
155.3
13.5
18.6
187.4
3.9
3.8
195.1
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
175
-------
TABLE A-5. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REOUIREMENTS
(Variation from base case: 200 MW)
Direct Costs
Delivered 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
65.500 tons
7.00/ton
16,440 man-hr 12.50/man-hr
200,300 MBtu
100,100 kgal
22,512,000 kWh
2.00/MBtu
0.12/kgal
0.031/kWh
1,980 man-hr 17.00/man-hr
458.500
458,500
205,500
400,600
12,000
697,900
1,021,400
33.700
2,371,100
2,829,600
6.42
6.42
2.88
5.60
0.17
9.76
14.29
0.47
33.17
39.59
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 annual revenue requirements
1,471,200
2,195,500
630,300
20.600
4,317,600
7,147,200
20.58
30.72
8.82
0.29
60.41
100.00
Equivalent unit revenue requirements
Mills/kWh
5.11
$/ton coal
burned
11.66
$/MBtu heat
input
0.55
$/ton
S removed
503
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.
Sulfur removed, 14,210 short tons/yr; solids disposal, 75,310 trms/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $13,081,000; total depreciable investment, $24,520,000; and total
capital investment, $25,529,000.
All tons shown are 2,000 Ib.
176
-------
TABLE A-6
LIMESTONE SLURRY PROCESS VARIATION FRUM BASE CASE: ZOO MW REGULATED CO. ECONHMlCS
TOTAL CAPITAL INVESTMENT
25529000
VEARS ANNUAL POWER UNIT
AFTER OPERA- HEAT
POWER TION, REQUIREMENT/
UNIT KW-HR/ MILLION BTU
ST*RT KM /YEAR
1 7000 12880000
2 7000 12880000
? 7000 12880000
4 7000 12880000
J 20,00 12BSOQQC__.
6 7000 12880000
7 7000 12880000
8 7000 12B8000C
? 7000 12880000
-18_ _ 2000 12&SOOQO...
11 5000 9200000
12 5000 9200000
1? 5000 920000C
14 5000 9200000
-15 _ 2000 2200000. .-
16 3500 6440000
17 3500 6440000
18 3500 6440000
19 3500 6440000
20 3500 64400QQ _.
2J 1500 2760000
22 1500 2760000
23 1500 2760000
24 1500 2760000
2J ISOO 22&OOQC
26 ISOO 2760000
27 1500 2760000
21 1500 2760000
29 1500 2760000
.30 1500 276.0000—
SULFUR
REMOVED
POWER UNIT 8Y
FUEL POLLUTION
CONSUMPTION, CONTROL
IONS COAL PROCESS/
/YEAR TONS/YEAR
TCTAl
BY-PRODUCT QP, CCST
RATE/ INCLL01NC
EQUIVALENT NET REVfcNUE, REGLLA1EC
TONS/ YEAR S/TCIN RCI F-;R
PCViER
DRV DRV COPA'.Y,
SOLIDS SOLIDS I/YESR
613300 14200 75300 0.0 93435CC
613300 14200 75300 0.0 9202^00
613300 14200 75300 0.0 9C623CC
613300 14200 75300 0.0 89218CC
-613300 _ 14200 25300 _Q«Q_ 8281200
613300 14200 753OO P.O 86406CO
613300 14200 75300 0.0 85000CO
613300 14200 75300 0.0 83595CO
613300 14200 75300 0.0 62189CC
613300 14200 - - 25300 Q^O BC2B3CO
438100 10200
438100 10200
438100 10200
438100 10200
438100 10200...
306700 7100
306700 7100
306700 7100
306700 7100
3Q6ZQQ 2100
TOTAL
NET
SALES
REVENUE/
*/YEAR
0
0
0
0
Q
0
0
0
0
0
NFT ANNUAL CUMULATIVE
INCREASE NET INtREAS
(DECREASE) {DECREASE)
IN CUST OF IN COST OF
POKER, PUfcER,
t »
9343500 9343500
9202900 18546400
9062300 27603700
8921800 36530500
B2S120C £(5311200
8640600 53952300
8500000 62452330
8359500 70311800
82IH900 79y30700
807.8300 87109000
53800 0.0 71439CO 0 7143900 94252900
53800 0.0 7CC34CC 0 7003400 101256300
53800 0.0 6862BCC O 6662600 106119100
53800 0.0 67222CO 0 6722200 114341300
53600 0»0 fiSBlfiCU Q 6.521600 121422800
37700 0.0 58074CO 0 5807400 127230300
37700 0.0 54666CC C 5666800 132997100
37700 0.0 5526200 C 5526200 13b423300
37700 0.0 53B56CC 0 5385600 143808900
_ 37700 • 0,0 5245100 C 5245100 149054Can
131400 3000 16100 0.0 4158600
131400 3000 16100 0.0 4C18000
131400 3000 16100 0.0 38774CO
131400 3000 16100 0.0 37368CC
._ 131400 3000 16100 _ 0.0. 35S&3.CC
131400 3000 16100 0.0 3455 /CC
131400 3000 16100 0.0 33151CC
131400 3000 16100 0.0 31745CO
131400 3000 16100 0.0 3C340CC
131400 3000 16100 0.0 2BS34CO_.
0
0
0
o
Q
0
0
0
0
4158600 153212600
4018000 157230600
3877400 161108000
3736800 164844800
3536300 16.fi4.4HQO
3455700 171896800
3315100 175211900
3174500 1763B6400
3034010 181420400
2823430 1B4313BOO
TOT 127500 234600000 11171000 258500 13715OO
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
HOLLARS PER TON Of CGAL BURNED
HILLS PE». KILOWATT-HOUR
CENTS PEP MILLION BTU HEAT INPUT
DOLLARS PE« TON OF SULFUR REMOVED
PRDCESS COST DISCOUNTED AT 11.2* TO INITIAL YEAR/ DOLLARS
18*313800
16.5C
7.23
78.57
713.01
67C5C90C
0.0
0.0
0.0
0.0
0
LEVELIZEO INCREASE (DECREASE) IN UNIT DERATING CuST EQUIVALENT Tu DISCOUNTED PROCESS CCSl CVER LIFE UF
DOLLARS PER TON OF COAL BURNED 15.C3 0.0
HILLS PE* KILOWATT-HOJR 6.59 0.0
CENTS PE« MILLION STU HEAT INPUT 71.58 o.o
DOLLARS PE« TON OF SULFUR REMOVED 649.09 0.0
184313800
16.50
7.23
78.57
713.11
6705Q900
UNIT
15.03
6.59
71.58
49.D9
-------
TABLE A-7. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500-MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment spearators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
1,944,000
1,899,000
5,111,000
9,512,000
1,312,000
1,857,000
21,635,000
1,298,000
22,933,000
A, 084, OOP
27,017,000
1,186,000
267,000
3,784,000
1,176,000
6,413,000
6,686,000
40,116,000
3,603,000
4,814,000
48,533,000
820,000
1,053,000
50,406,000
($101/kW)
7.
7.
18.
35.
4.
6.
80.
4.
84.
15.
100.
4.
1.
14.
4.
23.
24.
148.
13.
17.
179.
3.
3.
186.
2
0
9
2
9
9
1
8
9
1
0
4
0
0
4
8
7
5
3
8
6
0
9
5
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process Invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
178
-------
TABLE A-8. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500-MW existing)
Direct Costs
Delivered 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
163,100 tons
7.00/ton
25,990 man-hr 12.50/man-hr
1,141,700
1,141,700
324,900
7.73
7.73
2.20
55,
500
250
377
3
,700
,100
,000
,760
MBtu
kgal
kWh
man-hr
2.
0.
0.
17.
00/MBtu
12/kgal
029/kWh
00 /man-hr
1
1
1
4
6
,001,
30,
,605,
,957,
63,
,983,
,125,
400
000
900
200
900
300
000
6
0
10
13
0
33
41
.78
.20
.87
.25
.43
.73
.46
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 annual revenue requirements
3,106,100
4,334,900
1,173,000
32,500
8,646,500
14,771,500
21.03
29.35
7.94
0.22
58.54
100.00
Equivalent unit revenue requirements
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.22
9.63
0.46
416
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.
Sulfur removed, 35,530 short tons/yr; solids disposal, 188,300 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $27,017,000; total depreciable investment, $48,533,000; and total
capital investment, $50,406,000.
All tons shown are 2,000 Ib.
179
-------
TABLE A-9
LIMESTONE SLURRY PROCESS VARIATION F»rjM BASF CASE: 500 .'•'* EXISTING ,REGOL«Tfti CL1. EClllllJMCS
TJTAL CAPITAL
50*06000
TCIAL
SULFUR '1Y-PROIJUCT UP. CCS1
REMOVID RATE, INCLL01NL,
YEARS ANNUAL POhER UNIT -'OWER UNIT BY EQUIVALENT NtT REVENUE, RFGLLA'Er TUTAL
AFTER OPERA- • HEAT FUEL POLLUTION TONS/YEAR S/ION Rt I F- K NE I
POWER TION, REOUIRtMEM, CONSUMPTION, CONTROL PChEr SALES
UNIT KM-HR/ MILLION 8TU ^ONS COAL PROCESS, URY DRY CCPPA' Y, KEVENIJt,
START KK /YEAR /YEAR TONS/YEAR SOLIDS SULICS */YE H »/Y£AR
1
3
*
6 7QOO 32200000 Ii33300 35500 188300 0.5 1943lfrE6
7 7000 3220OOOO 1533300 355QO 188300 0.0 19C97/CC
8 7000 3220000C 1533300 35500 188300 O.O 18763KCO
9 7000 3220000C 1533300 35500 188300 n.O 184299CC
.10 2000 322QUQQC 1533300 352QQ 188300 0.0. ._ IflCSftCGC
11 5000 2300000C 1095200 25400 134500 0.0 16C38000
12 5000 2300000C 1095200 254QO 134500 0.0 157C41CC
13 5000 23000000 1095200 25400 134500 0.0 15370XCO
1* 5000 23000000 1095200 25400 134500 0.0 15C363CO
_1J 5QQQ 230QUQQO 1Q252QQ _ 2540Q 134530 0*0. 162C24CC
16 3500 16100900 766700 178QO 94200 0.0 13CC4LCO
17 3500 16100000 766700 17800 94200 0.0 12670200
18 3500 16100000 766700 17800 94200 0.0 123363CC
19 3SQO 16100000 766700 178QO 94200 0.0 12CC24CC
_2Q 3500 16100000 266200 . 1ZBOQ 942QQ Q»Q- 116fifl5.CC
21 1500 6900000 328600 7600 40400 0.0 93265CO
22 1500 6900000 328600 7600 40400 0.0 S9946CC
23 1500 6900000 328600 7600 40400 0.0 8660 ''CO
24 1500 69QOOOO 328600 7600 40400 0.0 8326rCC
24. _ 1500 69QQQQQ 328600 _ 26QQ 40400 Q»Q_ _7.S92'JCC
26 1500 6900000 328600 7600 40400 0.0 7659CCO
27 1500 6900000 328600 7600 40400 0.0 7325 JCC
28 1500 6900000 328600 76QO 40400 C.O 6S912CC
24 1500 6900000 328600 7600 40400 0.0 66572CC
30 15.00 69QOQOO - -328600 26QQ. 4Q4QQ 0*0. 63233CQ
TOT 92500 425500000 20262000 469500 2489000 3106108CO
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF C'JAL BURNED 15.33
•••ILLS Pfca KILDHATT-HilJR 6.72
CENTS PER MILLION BTU HEAT INPUT 73. cc
DOLLARS PER TON OF SULFUR REMOVED 661.58
PROCESS COST DISCOUNTED AT 11-2X TO INITIAL YEAR, DOLLARS 128C7670C
LEVELIZED INCREASE (DECREASE) IN UNIT 3PERATINC CuST EQUIVALENT Tu DISCOUNTED PROCESS CCS! lV»;R
DOLLARS >>ER TON OF CI1AL RJRNEO 13.66
HILLS PER KILOWATT-HOJR s.<;s
CENTS PFR MILLION P.TU HEAT INPUT es.c7
DOLLARS i'E>< TON OF SULFUR REMOVED 589. M
n
u
0
0
0
0
C
0
0
c
0
c
0
o
0
0-
0
u
n
c
0
0.0
0.0
0.0
0.0
c
LIFE OF
0.0
0.0
0.0
0.0
KCT A^'JUAL
INCHEASC
OECREASF)
I!l COST HF
POWfci*,
V
19(197700
18763800
18429900
- 18Q26QQQ
16038030
15704100
15370200
15036300
13004,100
12336300
120O2400
1166dSOU
9321*500
8994600
8660700
8326800
76*9000
7325100
6991200
6657200
_ 6323300
•M0610B1P
15.33
6.72
73.00
661. 5M
128076700
P/'KER UNIT
13.66
5.99
65. J7
5*9.94
CU/.L-LAF IVE
NtT I«LREASt
(UtCXtASt >
IN CJST JF
POV.ER,
>
3d529300
57293100
75723QOO
.93319000
109S57000
125561100
14Q9J13UO
155967600
183074100
196J44300
2Ud6»0600
220663QOO
232351530
2*1660000
250674630
259335300
267662100
283314030
29Q039100
297630300
3042B7500
-------
TABLE A-10. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 27, sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrairanent spearators, recirculatlon tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
979,000
1,195,000 .
4,120,000
8,346,000
1,222,000
1,317.000
17,172,000
1,030,000
18,202,000
2,800,000
21,002,000
1,142,000
263,000
3,084,000
971,000
5,460,000
5,292,000
31,754,000
2,895,000
3,811,000
38,460,000
563,000
825,000
39,848,000
($80/kW)
4.7
5.7
19.6
39.7
5.8
6.3
81.8
4.9
86.7
13.3
100.0
5.4
1.3
14.7
4.6
26.0
25.2
151.2
13.8
18.1
183.1
2.7
3.9
189.7
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
181
-------
TABLE A-ll. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
£ of average
annual revenue
requirements
Direct Costs
Delivered 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
75,300 tons
7.00/ton
23,280 man-hr 12.50/man-hr
527.100
527,100
291,000
4.53
4.53
2.50
488,500 MBtu
205,000 kgal
52,141,000 kWh
3,370 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17 . 00/man-hr
977,000
24,600
1,512,100
1,540,200
57 , 300
4,402,200
4,929,300
8.40
0.21
12.99
13.24
0.49
37.83
42.36
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.OX 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 annual revenue requirements
2,307,600
3,426,900
944,300
29,100
6,707,900
11,637,200
19.83
29.45
8.11
0.25
57.64
100.00
Equivalent unit revenue requirements
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
3.32
7.76
0.37
725
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.
Sulfur removed, 16,050 short tons/yr; solids disposal, 85,260 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $21,002,000; total depreciable investment, $38,460,000; and total
capital investment, $39,848,000.
All tons shown are 2,000 Ib.
182
-------
TABLE A-12
LlMESTONe" SLURRV PROCESS VA»JATIl1N FR;!M BASF CAbE: 2.OX S RFijUlATEI.i CU. tC"NO.'IICS
00
TiJTAL CAPITAL INVESTME'I!
39S4800O
SULFUR
REMOVED
YEARS ANNUAL PDWER UNIT JQWER UNIT BY
AFTER OPERA- MEAT FUEL POLLUTION
POWER TION, REQUIRFMEM, c INSU^PTION, CUNTRUL
UNIT KW-HR/ MILLION BTU IONS CCAL PROCESS,
START KW /YEAR /YEAR TONS/YEAR
T 7000 3150000C ISOOOOO 16100
? 7000 3150000C 1500000 16100
3 7000 315P900C 1 50QOOO 16100
« 7000 315000DC 1500000 16100
4 20QQ_ JISQQOOC 15.QQQQQ 1&1QQ
6 7ooo 315OOOOO 1500000 16100
t 7.100 31500000 1500000 16100
B 7000 31500000 1500000 16100
9 7000 3150000C 1500000 1610C
IP 7QQQ 2JSODDQO liOOQJQ . 1&1QQ
1) 5000 22500000 1071400 11500
1? 500O 2250000C 1071400 115QC
13 5000 22500000 1Q71400 11500
1* 5000 22500000 1071400 11500
iJ JQQO, 225QuaQO 1021400 115BC
16 3500 15750000 750000 8000
17 35QO 15750000 750000 8000
18 3500 15750000 750000 8000
19 35QO 15750000 750OOO 8000
20 3500 15250000 250000 8000
21 1500 675000C 321400 3400
2? 15QO 675000C 321400 34QO
23 15QO 6750000 321400 3400
24 1500 675000C 321400 3400
25 X50Q 6I5QOOC _ .321400 2400 .-
Z6 15QO ~ ~ 6750000 321400 3400
27 1500 6750000 3214QO 3*00
28 ISQO 675000C 321400 3400
29 15QO 6750(300 321400 34QO
30 150.0, 6250QQC - -32140Q 3400
bY-PRODOCT
KATE/
tQ'UVALtNT
TuNS/YEAR
DRV
SLiLIOS
85300
S5300
85300
85300
853QO- —
85300
B5300
85300
85300
S53QO
60900
60900
60900
60900
6U2QO
42600
42600
42600
42600
426.00 — .
18300
18300
18300
13300
133QQ
18300
18300
18300
10300
1B3QO
TOT 1275QO 573750000 27321000 292500 1553500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TQN OF COAL BURNED
IILLS PE^ KILOWATT-HOUR
CENTS fEK BILLION BTU HEAT INPUT
HOLLARS PER TON OF SULFUR REMOVED
PROCESS COST nlSCOUNTEO AT 11.2* TO INITIAL YEAR* OULLAHS
LEVELIZEO INCREASl. (CtCh61SE) IN UNIT DERATING CiiSl EQUIVALENT Til
DOLLARS •>{.* TON OF C'.IAL PURNED
MILLS PE» KILOWATT-H.JJR
CENTS PER MILLION RTU HEAT INPUT
I'tlLLAKS f>E"< TQM HF Si.'LFUR RE^Ovfi''
TL'TAu
OP. C'.ST
NLI RFVfMUE/ RECLLAIti: TJTiL
»/T,jN *( I F; R MET
PCk.b« SALES
D«Y Ct^PA1 Yj KFVENUI-*
SULIDS t/YE, R »/YEAR
0.0
3,0
0.0
__0»0.
0.0
0.0
0.0
0.0
Q.Q-
o.o
0.0
0.0
0.0
0.0
0.0
0.0
o.n
B.fl-
o.o
0,0
0.0
0.3
o.o
0.0
0.0
0.0
DISCOUNTED
14645^00
14t24'.cc
144C39CC
13962SCC
131424CC
135219CO
133C14CC
_13Cfi02CQ
1147Z5CC
112520CC
11C31SCC
1CE11CCC
1C5S05.CC
92720CC
9C51SCC
sesicco
FtlO'CC
E3SOOCO
6334?CO
5693'CO
5623200
5452 'CO
5232^00
scii'-co
47911CC
1C. "2
4. t.-4
51.53
101C.P5
10SC4910C
PKCJCESS CCS! LVhR
4.24
47. 17
923. 5C
C
0
Q.
o
r-t
a
t-
0
0
0
i
i)
0
0
0
o
a.
0
0
0
0
0
0.0
0.0
0.0
0.0
0
LIFE UF
0.0
0.0
0.0
0.3
NCT A'VvUAL
INCKfc ASc
I'i CfjST JF
PnhER,
%
14624400
14403900
141324J3
139IS290C
137424:30
13521900
13301401
11472500
112'>20'io
11031500
loaiioon
1Q52Q6QQ
9272000
9051500
8831000
S61.7SOO
B32uoao
6555200
6334700
61142 n
5893700
5452700
5232230
5011600
4791100
4S2Q.6JC
295673400
10.82
4.64
51.53
1013. ab
108049101
P'lWgK UNI f
9. "JO
4.24
47.17
923. bn
NET ncREASt
(OEC-
-------
TABLE A-13. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
Z of
total direct
Investment, $ Investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators.
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
tanks, agitators, and pumps)
Gas handling (common £eed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
ducts and dampers from reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
1,767,000
1,758,000
4,318,000
8,974,000
1,282,000
1,688,000
19,787,000
1,187,000
20,974,000
5,145,000
26,119,000
1,218,000
270,000
3,632,000
1,146,000
6,266,000
6,477,000
38,862,000
3,372,000
4,664,000
46,898,000
1,030,000
1,015,000
48,943,000
($98/kW)
6.8
6.7
16.5
34.4
4.9
6.5
75.8
4.5
80.3
19.7
100.0
4.7
1.0
13.9
4.4
24.0
24,8
148.8
12.9
17.9
179.6
3.9
3.9
187.4
Basis
ISIS
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESF.
Construction labor shortages with accompanying overtime pay incentive not considered.
184
-------
TABLE A-14. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Direct Costs
Delivered 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
159,300 tons
7.00/ton
25,990 man-hr 12.50/man-hr
1.115,100
1,115,100
324,900
489,800 MBtu
243,400 kgal
54,188,000 kWh
3,760 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
979,600
29,200
1,571,500
1,832,300
63,900
4,801,400
5,916,500
7.92
7..92
2.31
6.96
0.21
11.15
13.01
0.45
34.09
42.01
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 annual revenue requirements
2,813,900
4,209,100
1,110,600
32.500
8,166,100
14,082,600
19.98
29.89
7.89
0.23
57.99
100.00
Equivalent unit revenue requirements
$/ton coal S/MBtu heat $/ton
Mtlls/kWh burned input S removed
4.02
9.39
0.45
405
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.
Sulfur removed, 34,750 short tons/yr; solids disposal, 184,200 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $26,119,000; total depreciable investment, $46,898,000; and total
capital investment, $48,943,000.
All tons shown are 2,000 Ib.
185
-------
TABLE A-15
LIMF.STONt SLl/KRY PkGCF.bb HASt CAbE: 500 Co 3.?* b ht<;ULATti. CO.
TOTAL CArlTAL 1
ul «,>L»-M1
f-tAl FlJ^.L POLLUTION fu\*>/Yt;AH
RE ou iKtNt-.NT t CONSUMPTION* CJNTHUL
MILLION bTU TCNS COAL f-RbCESS* U-.Y
/YtAK /YFAn TUmb
31500000 1500000
31500000 1500(100
31aOOOUO IbOOUOU
315UOOIJO 1500000
31500000 J50000C
31500000 1500000
31500000 1500000
31500000 l^OOOOO
31500000 1SOOCOO
315Q(jJ)Dg J5JflUj)0
22500000 1071400
22500000 1071-tOO
2250000U 1071 U U
?500
73 UU
/bOU
'buu
7500
75UU
7bOO
75 UU
-JiDiL
e J450U
SOLlub
lo»200
La*200
104^00
104<:00
lut^pg
184200
lo«<;00
104200
184^00
1_Q4200
131000
131600
131eOO
1 jlouo
1 JlftOvJ
•»21uu
V21UO
S2100
•»2100
^2 1 Uty
3S5UO
J'JDUO
J-J500
J'JbOO
JSbUO
J>."iOO
J'lDOO
3-J500
J9o00
J^5p P
3355500
NF.T HEV
$/I
Dh
FNU
ON
Y
TliTAL
OP. COST
INCLUCINfa
IE. REGULATED TOTAL
riOI FOR rtET
POwtW SALES
COUU4NY. REVtNUt.
SOLIDS •S/fr:»R t/YtAR
0.
0.
i).
U.
0.
U.
1).
0.
II.
IJ .
0.
1).
0.
0.
U.
U.
0.
0.
li
0.
U.
0.
(J.
0
0
0
0
0
0
0
0
0
Q
0
0
0
0
V
0
0
0
0
(j
0
0
0
0
I«f93300
18024400
1775530U
174M6600
i'21 7^0SJ
lb94d'»OU
16680000
164U10U
16142200
^t«7330Jj
1 393830U
13669400
13400100
13131700
1 2H*b2UOi)
11?76',OU
1100POOU
1073^100
10470200
10201304
7S.99&00
7730800
7461900
71931)00
U
0
0
0
Jl_
0
0
0
0
v
0
0
0
0
(f
0
0
0
0
p
0
0
0
0
NtT ANNUAL
INC«E«SF
(UECRE4SE)
IN COST OF
PO»EH.
t
16293300
18024400
17755500
174H6600
±12121$$
16948900
16680000
16411100
16142200
1 5873300
139.38300
13669400
13400500
13131700
1 2b*S2400
11276900
11008000
10739100
10470200
10201300
7999600
7730800
7461900
7193000
CUMULuTIVt
NET INCREASE
(OFCBFASEI
IN COST OF
POWEX.
*
18293300
36317700
54073200
7l559aO(,
po 7 775QO
10=726400
122406400
13981750U
1S4959700
1 70P 3^000
184771300
19S440700
211841200
224972900
2.3.783S70I)
249112600
260120600
2708S9700
281329400
291531200
299530800
307261600
314723500
32191650U
0.0 6924100 0 6924100 32AR4060G
U.
a.
0.
0.
iLt
0
0
0
0
0
6655200
bJ86300
61 1 7400
5M4rtbOO
5^79/00
359427700
0
0
0
0
p
0
6655200
b3S6300
6117400
5648500
5579700
3b9427700
33S49560U
341rtH21QO
34799V50U
35384SOOO
3.5. 54^7 700
AVEh»Gt INCREASE (DEcntA5t> IN UNIT jt-tKATi^c- co^i
UOLLAHS PEH TON Oh CO«L V
HILLS Pt» RlLO«ATT-nOUR
CFTNTS HEK MILLION rt F O ^tA
UCLLAnS PEK TON Or SULFLl-
DISCOUNTED 4T 11. c* TO 1N1TUL
UKNt 0
F liliHUT
REMCvEO
13.16 U.
5.64 0.
42.t>5 0.
566.47 0.
ff.t«i t'OLLAKb 13171SOQO
LEYELIZ^U IMCKEASt (DECREASE) IN UNIT OPERATING COST c
UOLL4*S PEW TON OF COAL *-
MILLb PER KILO-AIT-hOUR
UWNtf,
OoI»ttLtiiT 10
CISCOL'MFD
CENTS PEP MILLION HFU htAT iNi-uT
UOLlAf'S Pi* TON Of bULFo^
Kt^Owti;
I-WOCESS COST OVER LIFE
12.03 0.
5.16 0.
57.28 0.
516.24 0.
p
0
0
0
0
OF
0
0
0
0
13.16
5.64
62.65
b66.47
131219500
POWER UNIT
12.03
5.16
57.28
518.24
-------
TABLE A-16. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling Choppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
1,944,000
2,057,000
4,327,000
8,974,000
1,283,000
1,992,000
20,577,000
1,235,000
21,812,000
7,553,000
29,365,000
1,285,000
277,000
3,925,000
1,253,000
6,740,000
7,221,000
43,326,000
3,577,000
5,199,000
52,102,000
1,511,000
1,184,000
54,797,000
($no/kw)
6.6
7.0
14.7
30.6
4.4
6.8
70.1
4.2
74.3
25.7
100.0
4.4
0.9
13.4
4.3
23.0
24.6
147.6
12.2
17.7
177.5
5.1
4.0
186.6
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
187
-------
TABLE A-17. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Direct Costs
Delivered 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
244,700 tons
7.00/ton
27,910 man-hr 12.50/man-hr
1.712.900
1,712,900
348,900
531,900 MBtu
283,200 kgal
56,227,000 kWh
4,040 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
1,063,800
34,000
1,630,600
1,971,600
68,700
5,117,600
6,830,500
10.77
10.77
2.20
6.69
0.21
10.26
12.40
0.43
32.19
42.96
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 annual revenue requirements
3,126,100
4,712,500
1,194,600
34.900
9,068,100
15,898,600
19.66
29.64
7.52
0.22
57.04
100.00
Equivalent unit revenue requirements
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.54
10.60
0.50
296
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.
Sulfur removed, 53,730 short tons/yr; solids disposal, 285,140 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $29,365,000; total depreciable investment, $52,102,000; and total
capital investment, $54,797,000.
All tons shown are 2,000 Ib.
188
-------
TABLE A-18
00
VO
LIMESTONE SLUHKY K-rlOtESS VAKiATlO*. F«OP BASE CAsfc : o.u* S -(ti3UL»It;i Ci». FCi>MJ«ICS
Crtt-ITAL I-T.Vt>T"tivr 3A797000
YtAWS ANNUAL POWSK UM T
AFTER OPEKA- HEM
PGHtR TION. KEuUIHtxtNT
UMT KH-HH/ "ULL'ioN hTu
START K* /YEAK
1
2
3
4
5
6
7
8
9
11
12
13
14
17
18
19
22
23
y>
A> r\> fw rv iv 1
a « * -4 9- 1
1
7000
7000
7000
7000
JJUlJL,
7000
7000
7000
7000
5000
bOOO
5000
5000
3500
3500
3500
3500
1500
1500
1500
1500
15M-
1500
1500
1500
1500
IbOO
TOT 127500
LIFETIME
PrtOCESS COST
JlbOUJOO
31bOuUOO
31500000
31500000
JlSpuoop
31300000
31bOl/UOO
31bOOUOO
J1500UOO
22400000
22bOOOOO
22500000
22500000
15750000
15750000
lD7buOOO
15750(100
6750000
67^0000
0750000
0750000
0750000
6750000
6750000
6750000
PC«f< OM I i?Y
HIF.L t'OLLUTlOiM
. COSSUMt'TlON. COraTfOL
lUiMb CUAL HKUCtSSt
/Yt«h T(JNS/Yt«h
IbOUOOO
laUUOOO
IbOOOOO
1SUUOOO
IbOOOOO
IbOOOOo
iotitiuao
1-.UOOOU
IbOOOOU
1 jn»uo
1071*00
1071«OU
1071*00
7SOOOO
750000
75000U
J21*OU
321*OU
321*00
J21*OU
J£l*00
321*00
321*00
S>j7ou
bJ70li
b37uu
_iJji!l_
Sl7uU
b37'ju
SJ700
..ajjilfi
JKHI>0
JptOO
3n«l>0
3«*('O
2tV>00
llbOO
11500
llbUU
1JSUU
llhOO
llbllly
llbOli
HbilO
AVERAGE II\CriEASE (UtCnEASE) IN Ui.lT ut-t-Al
UULLA^^ HErt T0t>* 0»- COAL fUH^EU
MILLS PtH MLU*ATf-Huux
CENTS ftn BILLION t)TU Ht«T iN^LiT
UOLLAHS PErl Ti,lv OF SOLFOn (rtM)»to
OISCGUfcTEO AT 11.2* To IMT1AL tEftrt. OaL
MY-K-iOOiiCr
SOLUS
2HS100
285100
**H^ i Q 0
203/00
20J700
203700
203700
(>v
l*2t>00
1*^(500
1*2*00
bllOO
61100
bllOu
6110G
ollia/
6i ion
61100
61100
hllDG
61100
b 1 **3SOO
riM, cuiT
"^ET Kp vENOf*
>/ TON
OKY
SOLlUS
u.o
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
ViV
0.0
0.0
0.0
0.0
0.0
0.0
U.O
0.0
o.o
TOTAL
OP. COST
INCLUDING
. HEGULATEO
KOI fW
CO»"PANYt
20612900
20314200
20015500
19716700
19119300
1852191)0
10223200
15700*00
15401600
15102900
14804200
14b05500
12090200
12391500
12092800
1179*100
898*500
8685800
t»387100
0088*00
7*91000
7193300
6893500
6594HOO
6296100
40506«500
1*.83
6.35
70.60
*13.97
147935*00
NET ANNUAL CUMULATIVE
TOTAL INCREASE *ET INCREASE
NET (DECREASE) (DECREASE)
SALES IN COST OF IN COST OF
REVENUE • POnEWi POKE* i
S/YEAK * «
0 2061?900 20612900
0 2031*200 40927100
0 20015500 60942600
0 19716700 80659300
0_ 19*18000 10(1077300
0
0
0
0
(1
0
0
0
tt_
0
0
0
0
0^
0
0
0
0
...SL
0
0
0
0
Qj
0
0.0
0.0
0.0
o.o
0
19119300 119196600
18820600 138017200
18521900 1S6539100
18223200 174762300
JL79245QO 1S24S6J.SO
15700400 208387200
15401600 223788800
15102400 23BS91700
14804200 253695900
1*505500 269201*00
12690200 280891600
12391500 293283100
12092800 305375900
11794100 317170000
114953.00 329665300
898*500 337649800
8685800 346335600
8387100 354722700
8088400 362811)00
7789700 370600800
7491900 378091800
719*300 385284100
6893500 392177600
6594800 398772400
6296]00 405068500
405068500
14.83
6.35
70.60
413.97
147935400
LEVELlZtO INCREASE (DtCKtAit) IN UMT OfkKATlub COST
OOLLAHb PEc TUN OF CUAL rtUH.Mt'J
MILLS PEH MLU«ATT-«UU«
CENTS fE« MILLIO« «TO nt»T IIM-»UI
oOLLAWS PE« fUKi OF ^ULFu* «t"»JVEU
TO
PWuCESS COST OVER LIFE OF POKER UNIT
13.5ft O.U 13.56
5.81 0.0 5.81
6*.58 0.0 6*.58
378.7* 0.0 378.74
-------
TABLE A-19. LPIESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000-MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling Choppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (four raoible-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, slurry disposal pumps,
and pond vater 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
2,438,000
2,444,000
8,690,000
14,358,000
2,026,000
2,363,000
32,319,000
1,939,000
34,258,000
6,856,000
41,114,000
1,266,000
275,000
5,339,000
1,618,000
8,498,000
9,923,000
59,535,000
5,268,000
7,144,000
71,947,000
1,376,000
1,752,000
75,075,000
($75/kW)
5.9
6.0
21.1
34.9
4.9
5.8
78.6
4.7
83.3
16.7
100.0
3.1
0.7
13.0
3.9
20.7
24.1
144.8
12.8
17.4
175.0
3.3
4.3
182.6
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
190
-------
TABLE A-20. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000-MW existing)
—
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered 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
318,500 tons
7.00/ton
36,750 man-hr 12.50/man-hr
979,600 MBtu
486,800 kgal
107,775,000 kWh
6,110 man-hr
2,229.500
2,229,500
459,400
2.00/MBtu
0.12/kgal
0.028/kWh
17.00/man-hr
1,959,200
58,400
3,017,700
2,603,700
103,900
8,202,300
10,431,800
9.64
9.64
1.99
8.48
0.25
13.05
11.26
0.45
35.48
45.12
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 annual revenue requirements
4,604,600
6,456,500
1,583,500
45,900
12,690,500
23,122,300
19.91
27.92
6.85
0.20
54.88
100.00
Mills/kWh
$/ton coal
burned
$/MBtu heat
input
$/ton
S removed
Equivalent unit revenue requirements
3.30
7.71
0.37
333
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, 2,999,900 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Sulfur removed, 69,490 short tons/yr; solids disposal, 368,400 tons/yr calcium solids Including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $41,114,000; total depreciable investment, $59,535,000; and total
capital investment, $75,075,000.
All tons shown are 2,000 Ib.
191
-------
TABLE A-21
LIHESTONF SLOHHY PHOCESS V»i»I»TIOH. fnO' r-Abt. CAbt'• 1.000 »* t*lbTli\0 WEGCLAltD CO.
IO1AL CAP1IAL IM^tblftM 73075000
YEA*S
AFtcH
"0»E*<
UNIT
STAHT
1
2
3
4
~~6
7
b
9
. Ji
11
1*
1J
14
jb
lb
17
10
19
i*"
?1
t't
2J
24
£K
?6
j7
itt
29
30
TOl
ANNUAL
OPERA-
TION.
KW-HH/
KW
7000
7000
7000
7000
7GOO
SOOO
5000
5000
5000
SOOO
3500
3500
3500
3bOO
_J5Jm
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
92500
LIFETIME
PROCESS COM
LEVELI^EO
PO*EH UNIT
ritAI
RE'JUIrtEl»El\T « C
MILLION HTU
/YEAH
63000000
63000000
63000000
63000000
63OOOOOO
45000000
45UOOOOO
45000000
45UOOOCO
tsooonoo
JlbUOOOO
3150UOOO
31500000
31500000
J15.poo.Qi/
13bOOOOO
13500000
13500000
13bOOOOO
13500000
13500000
13500000
13500000
13500000
1 3bO^)000
8325UOOOO
AVERAGE INCHEASf.
DOLLARS
HILLS PE
CENTb Hfc
DOLLARS
DISCOUNTED AT
PCtaEH tMT
FUEL
OKbUMi-no*
TONS COAL
/YKAH
3000000
3000000
3000000
3000000
30Qooo,p
2142900
2143SOO
214290U
^)4?VOP
1500000
150000U
IbUOOOO
1500000
1500000
642900
642SOO
64^900
642*>00
642900
6*2900
64<>90Q
642900
64290U
6*/?SOO
39643500
^tovto
bY
PCLLOUO'i
« CONTKOL
"'T.^1
TOTAL
OP. COST
iMCLUOlNb
tUUl»»LKNl NET KtvEMJEt HEOULATEO
TONS/Yf.AH
5/
TUN
^MOCtiS. Ortf OHY
TONS/»EA><
CVbUU
b<»3UU
6S300
69SOU
h^^uy
*ybUU
H960U
4960U
HVhOU
49buu
3470U
3470U
34^00
3470J
3470U
1 4*f UO
1 4900
1«40V
14<>ob
^44^/0
1490U
149UO
JfyOO
14VOU
14** bu
SJBUOU
SOcIUS
364400
Jbt*40U
J66400
3bt)400
Jfi tf 4 U tf
dD3£Ou
<263200
«!6320 0
^bJfJO
263/^00
1O4^0U
lottoo
Id4200
1H420U
lai^oo
/d-,00
/fH900
76SOO
/CSOO
7H90U
/b-,00
78VOO
7d9UO
769UO
/dSOU
4B6dUOU
SOLICS
0
0
u
0
u
0
u
b
u
0
0
0
u
SL
0
u
0
u
g.
0
0
0
0
Q
.0
.U
.0
.0
*O^Gb.O,G
2*637*00
24142BOO
23647800
21152800
226S7(jfli)
19^bb*00
19361400
1RK66400
13371400
17H7640.Q
141)54900
13bb9SOU
13064900
13S69900
JP074I.OO
11579900
11084400
10589900
10094900
9S99900
476199000
TOTAL
NET
SALES
KEVENUE.
S/YEAI.
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
NET ANNUAL
INCREASE
(DtCKCASE)
IN COST OF
POUER.
$
30060800
29565800
29070800
28b7b800
28080,800
24637800
24142800
23647800
23152800
22657800
19656400
19361400
18866400
18371400
17876400
14054900
13559900
1306*900
12569900
12074900
11579900
110R4900
10589900
10094900
9599900
476199000
CUMULATIVE
NET INCREASE
(OECHEASE)
IN COST OF
POtaEW,
f
3006080U
59626600
68697400
117273200
145354000
169991800
194134600
217782400
240935200
263593000
283449400
302R10800
32167T200
340048600
357925000
371979900
365539UOO
3S8604700
41117*600
423249500
434829400
445914300
456504200
466599100
476199040
•utC^EASt) IN LNiT oetNATiNfc cnsi
PEn TON OF
COAL HUkKtu
* KILO«ATT-rOUrf
w HILLION
PEW TON OF
eiTU rtAT INPUT
bULFLH «tMOi/eo
11.2* TO INJTUL YEAK. UULLAKS
INCKEASE (DECREASE) IN UMI OPERATING COST
OCLLAhS
PE» TON OF
COAL rtUrtNtU
tuUIvALtNT To
DISCOUNTED
MILLS PEK KiLo»ATT-r«ou«
CENTS Hfcrf MILLION
DOLLARS
PEH TON OF
bru HtAl INPUT
bULFLH xtHOVtO
12.01
5.1S
57.20
518. 7«
1973*9300
0.0
0.0
0.0
0.0
0
PKOC£SS COST OVER LIFE OF
10.76
4.61
bl.2b
464.66
0.0
0.0
0.0
0.0
12.01
5.15
57.20
518.74
197349300
POKER UNIT
10.76
4.61
51.25
464.68
-------
TABLE A-22. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW)
X of
total direct
Investment, S investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators.
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entralnment separators, reclrculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onslte disposal, 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
2,209,000
2,250,000
7,135,000
13,192,000
1,875,000
2,144,000
28,805,000
1,728,000
30,533,000
8,547,000
39,080,000
1,310,000
280,000
5,040,000
1,557,000
8,187,000
9.453,000
56,720,000
4,817,000
6,806,000
68,343,000
1,717,000
1,670,000
71,730,000
($71/kW)
5.6
5.8
18.3
33.7
4.8
5.5
73.7
4.4
78.1
21.9
100.0
3.4
0.7
12.9
4.0
21.0
24.2
145.2
12.3
17.4
174.9
4.4
4.3
183.6
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
193
-------
TABLE A-23. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW)
Direct Costs
Delivered 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
Annua1
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
305,200 tons
7.00/ton
36,750 man-hr 12.50/man-hr
2,136,400
2,136,400
459,400
946,800 MBtu
527,000 kgal
104,201,000 kWh
6,100 man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
17.00/man-hr
1,893,600
63,200
2,917,600
2,393,700
103,700
7,831,200
9,967,600
9.82
9.82
2.11
8.70
0.29
13.41
11.00
0.48
35.99
45.81
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 annual revenue requirements
4,100,600
6,168,800
1,478,400
45.900
11,793,700
21,761,300
18.84
28.35
6.79
0.21
54.19
100.00
Equivalent unit revenue requirements
S/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
3.11
7.50
0.36
327
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.
Sulfur removed, 66,540 uhort tons/yr; solids disposal, 356,140 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $39,080,000; total depreciable investment, $68,343,000; and total
capital investment, $71,730,000.
All tons shown are 2,000 lb.
194
-------
TABLE A-24
SLURRY PROCESS l/A-IiTlON FROM '(ASF CASE: 1,000 "W «Er.'.lLAT(-0 C.J. ECdNUHICS
CAPITAL INVESTMF.NI
71730000
VEARS ANNUAL
AFTER OPERA-
POWER TIC1N,
UNIT KW-HR/
START KW
POWER UNIT
HEAT
MILLION BTU
/YEAR
'•[ME« UNIT
FUEL
CilNSunpTIDN,
IONS COAL
/Yf AR
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
4Y-PRUDUCT
RATE,
EQUIVALENT
TiiNS/VFAK
DRY
SOL IDS
TCTAI
DP. CrST
»/TnN
DPy
SOLIDS
REGLLA'EU
RCI f\ «
cc^PA•
TOTAL
MET
SALts
REVENUE*
NI"T A'-J^iUAL
INCREASE
("ECREASt)
!•> CCiST L1F
POWES,
t
MET iNCntASt
(DECREASE)
IN CCIST OF
PJn'ER,
6
7
8
9
-10
11
1?
1»
1*
-ii
1»
17
18
19
.20
21
22
23
24
_2J
2*
27
28
29
-30
7000
7000
7000
7300
ZOQO.
7000
7000
7000
7000
20.00
5000
5000
5000
5()00
5DQQ
3500
3500
3500
3500
3§QO—
1500
1500
1500
15QO
15.00
1500
1500
1500
1500
1500
60900000
60900000
6090000C
609QOOOO
...60200000-
6090000C
60900000
60900000
60900000
...60200000-
43500000
4350000C
4350000(1
435riOOOO
...43500000-
30450000
30450000
30450000
3Q45000C
...304.50000.
1305000C
13050000
13050000
13050000
... 1305QOQO-.
13050000
13050000
13050000
1305000C
...13Q500QQ-.
2900000
2900000
290QOOO
290QOOO
-2200000-
2900000
2900000
2900000
2900000
-220QOOQ-.
2071400
2071*00
2071*00
2Q7i*oo
.2021400-.
145QOOO
145QOOO
145QOOO
1450000
.14*0000 —
621400
621400
621400
621*00
-.6.21400 —
621*00
621*00
621*00
621*00
.-621400.-
66500
66500
66500
66500
..66500.
66500
56500
66500
665QO
47500
47500
47500
47500
-47.500.-
33300
33300
33300
33300
-33300..
1*300
1*300
14300
143QO
.14200..
14300
143QO
143oo
143QO
.14300--
356200
356200
356200
356200
3562QQ-.
356200
356200
356200
356200
350200..
25*400
25**00
25*400
254400
25.4400,.
178100
178100
178100
17B100
12B1QQ..
76300
76300
76300
76300
26300..
76300
76300
76300
76300
2630D--
0.0
0.0
0.0
0,0
-Q.Q-.
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»Q_.
0.0
0,0
n.o
0.0
~0?0~~
0.0
0,0
0.0
-Q«0._
27932400
27932*CC 0
275*ObCO n
271*8'CO n 271*8700
26756SCC 0 26756900
-26365CCO 0 263550QQ-
25573?CO '0 25973200
ZSSfll'.CO 0 255«14JO
251895CC O 25139500
247977CC 0 2*797700
.2i*C59CC 0 24405300-
211963CC 0 21196300
2CBC*5CC n 2080*500
2C412?co 0 20412700
2CC20«CT f> 20020800
-1S4220CC Q 12622QQQ-
17C349CO fi 17034900
166430CO C> 16643000
16251^00 C 16251ZOO
158594CC 0 15B59400
-1546J5CQ 0 15452500-
119C46CO 0 11904600
1151Z3CO 0 1151280,1
111209CC 0 1112y9JO
1C7291CO 0 107a«l!.10
.103222CO U 1Q3223UQ .
95454CO 0 9945400
9553&CO D 9553600
9161BCC 0 9161800
87699CC n 8769900
..B2261CO U S3261QO-
2/932400
55472900
82621600
109379500
---1352435UO
1&1716700
187299100
212467600
237285300
---2il62l2UO
Z826b75DO
303692COO
324104700
344125500
.--2&2254SQO
3307b9400
3974324QO
4136b3600
429543000
.--4S5010500
456915100
4b<427900
«79b48800
490277900
--500615200
510560600
520114200
529276000
538345900
TOT 127500 110925000C 52821000
LIFETIME AVERAGE INCREASE (DECREASE)
1212000 6*87500
IM UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
546424CCO
0
54642*000
MILLS
CENTS
KILGWATT-HOJR
MILLION BTU HEAT INPUT
3*
29
HOLLARS c£R TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT
1C
*
49.26
*5C.84
20041 lOCC
_ 11.2* TO INITIAL YEAR, DOLLARS
LEVEL'ZFD INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TII DISCOUNTED PROCESS CLST
HOLLARS PER TON OF CTAL BURNED 9.5C
MILLS PE^
-------
TABLE A-25. LIMESTONE SLURRY PROCESS
SW1MARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% S02 removal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists.
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
Basis
1,802,000
1,828,000
4,323,000
8,974,000
1,283,000
1,789,000
19,999,000
1,200,000
•31 I QQ Aftf\
£.1 » 1 77 , UUU
5,867,000
27,066,000
1,239,000
273,000
3,718,000
1,177,000
6,407,000
6,695,000
40,168,000
3,430,000
4.820,000
48,418,000
1,175,000
1,056,000
50,649,000
($101/kW)
Evaluation represents project beginning mid-1977, ending mid-1980. Average
6.7
6.7
16.0
33.2
4.7
6.6
73.9
4.4
7ft "*
to . J
21.7
100.0
4.6
1.0
13.7
4.4
23.7
24.7
148.4
12.7
17.8
178.9
4.3
3.9
187.1
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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process Invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
196
-------
TABLE A-26. LIMESTONE SLTJRRY PROCESS
ANNUAL REVENUE REDUIRE1ENTS
(Variation from base case:
90% S02 removal)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered 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
182,400 tons
7.00/ton
25,990 man-hr 12.50/man-hr
1.276.800
1,276,800
324,900
489,500 MBtu
254,400 kgal
54,715,000 kWh
3 , 7 60 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
979,000
30,500
1,586,700
1,871,900
63,900
4,856,900
6,133,700
_8.77
8.77
2.23
6.72
0.21
10.90
12.86
0.44
33.36
42.13
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 annual revenue requirements
2,905,100
4,355,800
1,130,400
32,500
8,423,800
14,557,400
19.96
29.92
7.77
0.22
57.87
100.00
Equivalent unit revenue requirements
Mills/kVfh
$/ton coal
burned
4.15
9.70
$/MBtu heat
input
0.46
$/ton
S removed
366
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.
Sulfur removed, 39,800 short tons/yr; solids disposal, 215,250 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $27,066,000; total depreciable investment, $48,418,000; and total
capital investment, $50,649,000.
All tons shown are 2,000 Ib.
197
-------
TABLE A-27
LIMESTONE SLURRY PROCESS VARIATION FROM BASF CA5E: 90* $02 REVIVAL KE&UuATED CU.
TUTAL CAPITAL INVESTMENT 506*9000
YEARS ANNUAL
AFTER CPERA-
POWER TION,
UNIT KW-HR/
START K*
POWER UNIT PO«ER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION,
MILLION BTU IONS CHAL
/YEAR
/YEAR
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TUNS/YEAR
HY-PRODUCT
RATE/
EQUIVALENT
TUNS/YEAR
DRY
SOLIDS
NfrT RfVfNUfc,
DRY
SOUI'S
TLTAL
OP, ClSl
INCLUDING
REC-UA'tC
Ri;i f! R
PCfcE*
COPA'.Y,
TUTAL
NEI
SALES
REVENUE,
»/YEAR
INCRtASE
(^ECREASF.)
I'l COST OF
POKER,
*
CUMULATIVE
NtT INCREASE
(DtCRtASE)
IN CdST OF
PUkif.R,
$
oo
1 7000
2 7000
3 7000
4 7000
__5 2000—
6 7000
7 7000
8 7000
9 7000
-10 2000—
11 5000
12 5000
13 5000
14 5000
-15 5000—
16 3500
17 3500
18 3500
19 3500
-20 35QQ—.
21 1500
22 1500
23 1500
2* 1500
.23 1500...
26 1500
27 1500
28 1500
2? 1500
.30 1300—
31500000
31500000
31500000
3150000C
...315QQQQC.
31500000
31500000
3150000C
31500000
... 31500000.
22500000
22500000
22500000
22500000
...22500000.
15750000
15750000
1575000C
1575000C
.-15250000-
6750000
6750000
6750000
6750000
—6250000..
6750000
6750000
6750000
6750000
6250000-.
1500000
1500000
1500000
1500000
.1500000-
1500000
1500000
1500000
1500000
.1500000-
1071400
1071400
1071400
1071400
.1021400.
750000
750000
75QOOO
750000
.-2500QQ-.
321400
321400
321400
321400
-3214QQ-.
321400
321400
321400
321400
-321*00--
39800
39800
39800
39800
__32flQQ
39800
39800
39800
39800
—32BQO
28400
28400
284QO
284QO
..2B4QO
19900
19900
19900
19900
..12200
8500
8500
8500
8500
..8500
8500
8500
8500
8500
..6500
215300
215300
215300
215300
215300...
215300
215300
215300
215300
2153QQ-.
153800
153800
153BOO
153800
l53flQQ_.
107600
107600
107600
107600
102600—
46100
46100
46100
46100
46100-.
46100
46100
46100
46100
40100...
0.0
0,0
0,0
0.0
0,0
O.O
0.0
0.0
0,0
0*0
0.0
0,0
0,0
0.0
Q»0
0.0
0.0
0,0
0.0
Q.Q
0.0
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0*0
189149CC
18t373CO
183597CO
ieCB2^CC
..12804600.
175270CC
172494CC
16S718CO
16694ZCC
--164160CQ-.
144114CC
14l33dCC
138562CC
135786CO
..133C110C..
18914900
18637300
18359700
180«?200
113816CO
111040CO
108264CC
..10546800..
82718CO
79942CO
77166CO
74390CO
..21614CO—
68839CO
66C63CC
63287CO
6C511CO
..57.235CC—,
0 17527000
0 17249400
0 16971800
0 16694200
__0 1641660Q-.
0 14411400
0 141338QO
0 13856200
0 13578600
— fl 1330HUQ..
0 11659200
0 11381600
0 11104000
C 10826400
"~C 8271800"
0 799*200
0 7716600
0 7439000
._0 2161400.-
0 6883900
0 6606300
0 6328700
0 6051100
_Q 5223500—
1S914900
37552200
55911900
73994100
. — 21229200
109325700
126575100
143546900
1602411UO
.-126652200
191069100
205202900
219059100
232637700
.-245238800
257598000
268979600
280083600
290910000
_
309730600
317724BOO
325441AOO
332880400
346925700
3S3532000
359860700
365911800
.3216S5300
TOT 127500 573750000 27321000 724500 3921000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS P£ft TON OF COAL BURNED
HILLS PER KKOWATT-HOJR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11. 2* TO INITIAL YEAR/ DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT DPERATING cosr EQUIVALENT TU
DOLLARS PER TON OF COAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
3716S53CO
13. 6C
5.83
64.78
513. C2
13568930C
DISCOUNTED PROCESS CCSI LVER
12. 44
5.33
59.23
468.66
0
0.0
0.0
0.0
0.0
0
LIFt UF
0.0
0.0
0.0
0.0
371695300
13.60
5.83
64. 7B
513.02
135689300
pnwER UNIT
12.44
5.33
59.23
468.36
-------
TABLE A-28. LIMESTONE SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists.
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers Including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four direct oil reheaters)
Solids disposal (onslte disposal, 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
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 f $
1,078,000
1,213,000
4,447,000
8,436,000
726,000
1,418,000
17,318,000
1,039T000
18,357,000
2,020.000
20,377,000
1,112,000
260,000
3,031,000
949,000
5,352,000
5,146,000
30,875,000
2,885,000
3,705,000
37,465,000
357,000
814,000
38,636,000
($77/kW)
% of
total direct
investment
5.3
5.9
21.8
41.4
3.6
7.0
85.0
5.1
90.1
9.9
100.0
5.4
1.3
14.9
4.7
26.3
25.2
151.5
14.2
18.2
183.9
1.7
4.0
189.6
Evaluation represents project beginning mid-1977, ending mid-1980
for scaling, mid-1979. ending mid 1980.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only pumps are spared
Disposal pond located 1 mile from power plant.
Investment requirements for fly ash removal an/f ^=-~
ment estimate begins vith coin fee'd^num!™? e
v
verage cost basis
num™ e o
Construction labor shortage, wlth accompanying overtime pay
, ,
oT h
not considered.
199
-------
TABLE A-29. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE RETIREMENTS
(Variation from base case: oil-fired, existing)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
70,200 tons
Direct Costs
Delivered raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Oil
Process water
Electricity
Maintenance
Labor and material
Analyses
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, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
7.00/ton
24,860 man-hr 12.50/man-hr
491.400
491,400
310,800
2,881,300 gal
178,400 kgal
44,449,000 kWh
3,600 man-hr
0.40/gal
0.12/kgal
0.029/kWh
17.00/man-hr
1,152,500
21,400
1,289,000
1,529,200
61,200
4,364,100
4,855,500
2,397,800
3,322,700
950,600
31.100
6,702,200
11,557,700
,_4.25
4.25
2.69
20.75
28.75
8.22
_0.27
57.99
100.00
Equivalent unit revenue requirements
Mills/kWh
3.30
S/bbl oil
burned
2.16
$/MBtu heat
input
0.36
$/ton
S removed
777
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.
Sulfur removed, 14,880 short tons/yr; solids disposal, 63,030 tons/yr calcium solids includi
only hydrate water. g
Investment and revenue requirement for removal and disposal of fly ash excluded
Total direct investment, $20,377,000; total depreciable investment, $37 465 000- anH t- * i
capital investment, $38,636,000. ' ' ' tOtal
All tons shown are 2,000 Ib.
200
-------
TABLE A-30
LIMESTONE SLURRY PROCESS VARIATION FROM BASE CASE: OIL-FIRED, EXISTING RtGUlATFn CD. 1-CLM.MlCS
TOTAL CAPITAL INVESTMEI-41 3&636000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
POWER UNIT
HEAT
REQUIREMENT,
MILLION BTU
/YEAR
POWER UNIT
FUEL
CONSUMPTION,
BARRELS OIL
/YEAR
SULFUR
REMOVED
8Y
POLLUTION
CONTROL
PKQCESS;
TONS/YEAR
BY-PRUOUCT
RATE,
EQUIVALENT
TONS/YEAR
DRY
SULIOS
NET RFVENUE,
DRY
SHLIDS
TCTAl
OP, CuST
1NCLLUING
REGLLAIEC
RCl FUR
PCWER
CCKPAKY,
TOTAL-
NET
SALES
REVENUE,
I/YEAR
NET ANNUAL
INCREASE
PI CfjST OF
POfcER,
CUMULATIVE
NET MCREASt
(DECREASE)
IN COST OF
POWER,
I
1
2
3
4
-.5.
6
a
9
-10-
11
1?
13
_{L
IT
1*
19
*
22
23
.3.
26
27
28
2?
-30-
7000
7000
7000
7000
..2000.
5000
5000
5000
5000
.-5000-
3500
3500
3500
3500
..3500.
1500
1500
1500
1500
— 1500.
1500
1500
1500
1500
...1500.
32200000
32200000
32200000
32200000
.32200000.
23000000
23000000
23000000
23000000
16100000
1610000C
16100000
16100000
.16100.000.
690000C
6900000
690000C
6900000
6900000.
6900000
690000C
6900000
6900000
6900000.
5324100
5324100
5324100
5324100
5324100-
3602900
3802900
3802900
3802900
3BQ22QQ-
2662000
2662000
2662000
2662000
2662000-
1140900
1140900
114Q900
1140900
1140900.
114Q900
114Q900
1140900
1140900
1140900.
14900
14900
14900
14900
14900.
10600
10600
106QO
10600
10600.
7400
7400
7400
7400
1400.
3200
3200
3200
3200
3200.
3200
3200
3200
3200
320Q.
63000
63000
63000
63000
.63000
45000
45000
41000
45000
-45000
31500
31500
31500
31500
.31500
13500
13500
13500
13500
.13500
13500
13500
13500
13500
.13500
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
n.o
.0.0
0.0
0.0
c.o
0.0
-Q.Q
TOt 92500 42550000C 70354000 196500 832500
LIFETIME AVERAGE INCREASE (INCREASE) IS UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PEP MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.2% TO INITIAL YEAR, DOLLARS
151314CO
14873600
146159CC
14358LCC
141004CO.
124758CO
1221BOCO
U9603CO
11702500
U444SCQ.
101046CO
9G466CO
95891CO
93313CO
9C2360C.
72209CO
69631CO
67051CO
64476CO
618.92CC.
5S32100
56743CO
54166CO
51588CO
SSQliCO.
2414360CO
3.43
5.'2 2
56.74
1228.66
9964470C
LEVELIZEO INCREASE (CECREiSt) IN UNIT OPERATING COST EQUIVALENT TQ OISCOUNTEO PROCESS CCS1 CVER
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
HOLLARS PER TON OF SULFUR REMQvEn
3.06
4.66
50.63
1096.42
C
0
0
0
------ Q
0
0
0
0
------ C
0
0
0
0
...... U
0
0
0
0
..... _D
0
0
0
C
------ C
0.0
0.0
0.0
0.0
0
LIFE UF
0.0
0.0
0.0
0.0
14873600
14615900
1435*100
141004211...
12475830
122)8000
119*0300
11702500
15131400
30005000
44&20900
56979000
..23029430
10104600
9fl468DO
9689100
9331300
907.3600..
7220900
69631QO
6705400
6447600
—6.19S90Q-
5932100
5674300
5416600
5158800
4S0110Q.
241436000
3.43
5.22
56.7*
1228.68
99664700
UNIT
3.06
4.66
50.63
1096.42
97773200
109733500
121436000
-132flflOflDO
142985400
1S2432290
162421300
171752600
.l&Qa262DO
188047100
195010200
201715600
208163200
.214353100
220lb5200
225959500
231376100
236534900
-2414J6.QOO
-------
TABLE A-31. LIMESTONE SLURRY PROCESS
OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500 MW, 3.5% sulfur)
withTOCS process sludge fixation and land disposal)
7. oE
total direct
Investment, $ iiiyestment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators.
bins, shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoists,
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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Sludge fixation (thickener, filters, and mixer)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding mobile equipment
Mobile equipment
Fly ash pond cost credit
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Con t rsc tor f 66 s
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
3,688,000
1,758,000
4,318,000
8,974,000
1,282,000
2,389,000
22,409,000
1,345,000
23,754,000
581,000
(4,339,000)
19,996,000
1,129,000
282,000
3,466,000
923,000
5,300,000
5,090,000
30,886,000
3,089,000
3,706,000
37,681,000
544, 000
1.526,000
39,751,000
($RO/kW)
18.4
8.8
21.7
44.9
6.4
11.9
112.1
6.7
118.8
2.9
(21.7)
100.0
5.6
1.4
17.4
4.6
29.0
25.5
154.5
15.4
18.5
188.4
2.7
7.6
198.8
^ — .- — -— - •
Basis
'Evaluation 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.
Landfill located 1 mile from power plant.
FSP rosts of $9,614,000 not shown.
Construction la^or shortages with accompanying overtime pay incentive not considered.
202
-------
TABLE A-32. LIMESTONE SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500 MW, 3.5% sulfur,
with IUCS process sludge fixation and land disposal)
Annual
quantity
Direct Costs
Delivered raw materials
Limestone 159,300 tons
Ground lime 16,216 tons
Total raw materials cost
Conversion costs
Operating labor and supervision
FGD plant 72,950 man-hr
Solids disposal 43,800 man-hr
Utilities
Steam 489,800 MBtu
Process water 243,400 kgal
Electricity 58,452,000 kWh
Maintenance
Labor and material
Analyses 5,100 man-hr
Disposal operations (Land prepar-
ation, trucks, earthmoving equip-
ment, and fuel oil)
Total direct costs
Unit
cost. $
7.00/ton
53.00/ton
12.50/man-hr
17.00/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,115,100
859,400
1,974,500
911,900
744,600
979,600
29,200
1,695,100
1,900,300
86,700
120,200
6 467 600
8,442,100
6.90
5.31
12.21
5.64
4.61
6.06
o.ia
10.48
11.75
0.54
0.74
40 .00
52.21
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 annual revenue requirements
Equivalent unit revenue requirements
2,260,900
3,418,600
1,881,900
165,700
7,727,100
16,169,200
Mills/kWh
13.98
21 . 15
11.64
1.02
47.79
100.00
$/ton
$/ton coal $/MBtu heat sulfur
burned input removed
4.62
10.78
0.51
465
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.
Sulfur removed, 34,750 short tons/yr; solids disposal, 184,200 tons/yr calcium solids including
only hydrate water.
ESP annual revenue requirements of $1,975,000 not shown.
Total direct investment, $19,996,000; total depreciable investment, $37,681,000; and total
capital investment, 339,751,000.
All tons shown are 2,000 Ib.
203
-------
TABLE A-33. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200-MW existing)
% of
total direct
Investment. $ investment
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, tanks, agitators, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
SC>2 absorption (two mobile-bed scrubbers including presatu-
rator and entrainment separators, 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
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1,088,000
437,000
2,202,000
4,082,000
590,000
1,357,000
9,756,000
585,000
10,341,000
1,316,000
11,657,000
690,000
159,000
1,901,000
621,000
3,371,000
3,006,000
18,034,000
1f.T) f\f\(\
)D / Z i UUU
2,164,000
21,870,000
265,000
623,000
22,758,000
($114/kW)
9.4
3.7
18. 9
35.0
5.1
11.6
83.7
5.0
88.7
11.3
100.0
5.9
1.4
16.3
5.3
28.9
25.8
154.7
U"l
• J
18.6
187.6
2.3
5.3
195.2
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process Invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
204
-------
TABLE A-34. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200-MW existing)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered raw materials
Lime
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
29,000 tons
206,200 MBtu
98,200 kgal
20,193,000 kWh
42.00/ton
16,440 man-hr 12. 50/man-hr
2.00/MBtu
0.12/kgal
0.031/kWh
1,980 man-hr 17.00/man-hr
1.218.000
1,218,000
205,500
412,400
11,800
626,000
970,200
33,700
2,259,600
3,477,600
16.04
16.04
2.71
5.43
0.16
8.25
12.78
0.44
29.77
45.81
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 7.0% of total depreciable
investment
Average of 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 annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 5.42 11.98
1,530,900
1,957,200
604,700
20,600
4,113,400
7,591,000
$/MBtu heat $/ton
input S removed
0.57 517
20.17
25.78
7.97
0.27
54.19
100.00
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.
Sulfur removed, 14,670 short tons/yr; solids disposal, 64,800 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $11,657,000; total depreciable investment, $21,870,000; and total
capital investment, $22,758,000.
All tons shown are 2,000 Ib.
205
-------
TABLE A-35
LIME SLURRY PROCESS VARIATION FROM BASE CASE: 200 hi EXISTING REGULATEU CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 22758000
YEARS
AFTER
POKER
UNIT
START
1
2
3
4
5
6
7
8
9
" li
o 12
0> 13
14
jj
16
17
18
19
20
21
22
23
24
25
26
27
28
29
-3a
ANNUAL
OPERA-
TION.
KW-HR/
KW
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
POWER UNIT
HEAT
REQUIREMENT.
MILLION BTU
/YEAM
9500000
9500000
9500000
9500000
9500000
6650000
665UOOO
6630000
6650000
6,65UDpp
28SOOOO
£050000
2830000
2850000
<>tiSUUOO
2B5UOOO
2B50000
2850000
2*30000
^CibUJDO
PONEK UNIT
FUEL
CONSUMPTION!
TONS COAL
/YEA*
452400
432400
452400
452400
452400
316700
316700
316700
316700
316700
135700
135700
135700
13570U
133700
133700
135700
135700
135700
135700
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS?
TONS/YEAR
10500
10500
10SOO
10500
10500
7300
7300
7300
7300
7300
JlOO
3100
3100
3100
3100
3100
3100
3100
3100
3100
BY-PRODUCT
HATE.
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
46300
46300
46300
46300
46.JOO
32400
32400
32400
32400
32400
13900
13900
13900
13900
13900
13900
13900
13900
13900
13900
NET REVENUE?
S/TON
DRY
SOLIDS
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
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY?
S/YEAR
8933200
8745100
8557000
8368900
aia.g8.pg
7221400
7033300
6845200
6657100
6469000
5155600
4967500
4779400
4591300
4403200
4215100
4027100
3839000
3650900
3462UOO
TOTAL
NET
SALES
REVENUE?
S/YEAR
0
0
0
0
g
0
0
0
0
0
0
0
0
0
g
0
0
0
0
q
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER i
*
8933200
8745100
8557000
8368900
8180800
7221400
7033300
6845200
6657100
6469DOD
5155600
4967500
4779400
4591300
4403200
4215100
4027100
3839000
3650900
3462000
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER?
t
8933200
17678300
26235300
34604200
42795900
50006400
57039700
63884900
70542000
I24110JO
82166600
87134100
91913500
96504800
_10i)9_08JU)0
105123100
109150200
112989200
116640100
_12flUJ23J)0
TOT 57500 109250000 3202500 120000 532500
LIFETIME AVERAGE INCREASE (OECHEASE) IN UNIT OPERATING COST
DOLLARS fEri TON OF COAL rtURNEU
MILLS PER KILOWATT-MOON
CENTS Ptri MILLION BlU HEAT INPUT
DOLLAKS PEM TON OF SULFUR RE.MOVE0
PROCESS COST DISCOUNTED AT 11.2* TO INITIAL YEAR* DOLLARS
120102900
23.09
10.44
109.93
1000.86
55535900
LEVELI2ED INCREASE (DECKtASt) IN UNIT OPERATING COST EUUIVALENT TO DISCOUNTED PROCESS COST OVER
DOLLARS HEM TON OF CUAL BURNED 21.18
MILLS Ptfl KILOKATT-HOUK 9.58
CENTS PEM MILLION BTU HtAT INPUT 100.84
UOLLAKS PER TON OF SULFUR HtMOVED 914.92
0 120102900
0.0 23.09
0.0 10.44
0.0 109.93
0.0 1000.86
0 55535900
LIFE OF POWER UNIT
0.0 21.18
0.0 9.58
0.0 100.84
0.0 914.92
-------
TABLE A-36. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW)
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers including presatu-
rator and entrainment separators, 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
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
1,009,000
403,000
1,857,000
3,827,000
564,000
1,212,000
8,872,000
532,000
2,236.000
11,640,000
729,000
163,000
1,860,000
620,000
3,372,000
3,002,000
18,014,000
1,578,000
2,162,000
21,754,000
444,000
600,000
22,798,000
($114/kW)
% of
total direct
investment
8.6
3.5
16.0
32.9
4.8
10.4
76.2
4.6
19.2
100.0
6.3
1.4
16.0
5.3
29.0
25.8
154.8
13.6
18.5
186.9
3.8
5.2
195.9
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
207
-------
TABLE A-37. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW)
Direct Costs
Delivered raw materials
Lime
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
28,100 tons
199,700 MBtu
95,100 kgal
19,576,000 kWh
42.00/ton
16,440 man-hr 12.50/man-hr
2.00/MBtu
0.12/kgal
0.031/kWh
1,980 man-hr 17.00/man-hr
1,180,200
1,180,200
205,500
399,400
11,400
606,900
913,400
33.700
2,170,300
3,350,500
16.36
16.36
2.85
5.54
0.16
8.41
12.66
0.47
30.09
46.45
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 annual revenue requirements
1,305,200
1,960,600
576,300
20,600
3,862,700
7,213,200
18.09
27.18
7.99
0.29
53.55
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
5.15
11.76
$/MBtu heat
Input
0.56
$/ton
S removed
508
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.
Sulfur removed, 14,210 short tons/yr; solids disposal, 63,600 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirements for removal and disposal of fly ash excluded.
Total direct investment, $11,640,000; total depreciable investment, $21,754,000; and total
capital investment, $22,798,000.
All tons shown are 2,000 Ib.
208
-------
TABLE A-38
LIME SLURRY PROCESS VAKlATlOK HCH bASE CASt: 200 ma REGULATED CO. ECONOMICS
TOTAL CAPITAL iNVtbTwtNT 2279*000
N3
\O
YEARS ANNUAL PO*ER UNIT
AFTER OPERA- ntAl
POMtR TION, MCUUlHt«£NT«
UKIT KW-HH/ MILLION «Tu
START KM
1 7000
2 7000
3 7000
4 7000
5 Iflflfl
6 7000
7 7000
U 7000
9 7000
JO 'pop
11 5000
12 5000
13 5000
14 5000
IS 5000
16 3500
17 3500
18 3500
19 3500
20 3.5PP
21 1500
22 1500
23 1500
24 1500
ac 15,00.
26 IbOO
27 1500
28 1500
29 1500
3fl 15OO
TOT 127500
LIFETIME
/YtAK
124HUOOO
12B80000
128I5UOOO
12880000
l/ptjuopo
12unuOoO
120&UOOO
128UUOOO
120HUOOO
1286UOQQ
9200000
9200000
9200000
4200000
y20UOup
6440000
044JOOO
0440000
o»«l/oOO
,644000p
276UOOO
276JOOO
2700000
2760000
?760000
£761/000
2760000
276dUon
2760UOG
ii*mi$si
234600000
AVERAGE INCREASE
SULFOrt rtY-PRODOCT
KtxOVtU KATE,
HO«tK O^MlT bY tUOlvALENT
FutL POLLUTION IONS/YEAR
CUNbU*>PTIOi<<> CONTnOL
TONb COAL P*OCtSS» OMY
/YtA-< TONS/YEAR S>OL1OS
613300
61330D
61330U
PlJJOO
613300
613300
013300
blJJOO
613300
51330"
43»-100
43H100
43U100
•»3f 1OO
»JH100
1»h700
306700
306/00
J06700
306700
1J140U
13140U
13140U
Ul»00
A31*0j/
131400
131400
131404
131404
i-mon
11171000 c
l»20u
14200
1»200
1*200
\tavv
14200
14200
It^OO
14200
l42Up
10200
10200
lOlOb
10200
1U20O
7100
7100
7100
7100
T1PB
30UO
3000
3000
3000
^piju
3oao
JOOO
JOUO
3000
3^000
E>H5(io
(UtCitAbt) IN UNIT UPthATlHG
63600
63600
63600
63600
63600
63600
63600
63600
63600
^3^00
45400
45400
45400
45400
454UO
31HOO
31800
31800
31BOO
jJJ*69
13600
13t>00
13600
13600
J JfiOO
13600
13600
13600
13600
13600
llbHOOO
COiT
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
t/TON ROI FOR
HOMER
ORY COMPANY.
SOLIOS I/YEAR
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
o.o
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
P,q
LI0LLAK6 PtR IGn Oh COAL «URiifcO
MlLLi ft.it MLiUATT-hUUK
CENTS PtR "ilLLION HTU H£AT INPUT
PROCESS COST
LEVELI/ED
LfOLLAnS
DISCOUNTED AT
h-t« ION OK SULFUR 1
11.2* TO INITIAL YEAR, UOLL*RS
INCKtASE (UtCKLObc) IN UNIT OPERATING COST EuUlKALLNT TO
OOLLAMS
CILLb Pt
PtH TO* Oh COAL ctoi
R ^ILO«ATT-h>OUR
CtdTS PtN MILLION BTU MLAT
UOLLAKS
«rttO
INHOT
DISCOUNTED
ri-R TON Oh SULFUR RtMOVtO
9174000
9044200
8924500
8799800
8675100
8550400
8425700
8300900
8176200
sosisog
6983100
6058400
6733600
6608900
648420 0.
5616300
5491600
5366900
5242100
5117400
3909800
3785100
3660400
3535700
3410900
3286200
3161500
3036800
2912100
27R7400
180115700
16.12
7.06
76.78
696.77
65974200
PROCESS COST OVER
14.79
6.44
70.43
638.67
TOTAL
NET
SALES
REVENUE.
S/YEAH
0
0
0
0
0
0
D
0
0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POKER, POWER,
%
9174000
9049200
8924500
6799800
I
9174000
18223200
27147700
35947500
8675100 44622600
8550400
8425700
8300900
8176200
53173000
61598700
69899600
74075800
S_ 8051500 86127300
0
0
0
0
g
0
0
0
0
6903100
6858400
6733600
6608900
fi*9*2.op
5616300
5491600
5366900
5242100
93110400
99968800'
106702400
113311300
-LISISSSJO
125411800
130903400
136270300
14)512400
4_ 5117400 1*6629900
0
0
0
0
. r S
0
0
0
0
p
0
0.0
0.0
0.0
0.0
0
LIFE OF
O.O
0.0
0.0
0.0
3409ROO
3785100
3660400
3535700
3410900
3286200
3161500
3036800
2912100
2787400
1H0115700
16.12
7.06
76.78
696.77
65974200
PO*E* UNIT
14.79
6.49
70.43
638.67
150539600
154324700
157985100
161520600
IW2J1IJ)0
168217900
171379400
174416200
177328300
asimsjwo
-------
TABLE A-39. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500-MW existing)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, tanks, agitators, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum Co absorber, exhaust gas
ducts and dampers from absorber to reheater and stack)
SC>2 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, 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
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
2,018,000
668,000
5,095,000
9,014,000
1,308,000
1,778,000
19,881,000
1,193,000
21,074,000
3,583,000
24,657,000
1,065,000
240,000
3,513,000
1,097,000
5,915,000
6,114,000
36,686,000
3,310,000
4,402,000
44,398,000
708,000
1,340,000
46,446,000
(S93/kW)
8.2
2.7
20.7
36.6
5.3
7.2
80.7
4.8
85.5
14.5
100.0
4.3
1.0
14.3
4.4
24.0
24.8
148.8
13.4
17.9
180.1
2.9
5.4
188.4
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
210
-------
TABLE A-40. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 50Q-**W existing)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered raw materials
Lime
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
70,400 tons
42.00/ton
25,990 man-hr 12.50/man-hr
2,956.800
2,956,800
324,900
499,200 MBtu
237,600 kgal
48,038,000 kWh
3,760 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
998,400
28,500
1,393,100
1,793,400
63,900
4,602,200
7,559,000
19.05
19.05
2.09
6.43
0.18
8.98
11.57
0.41
29.66
48.71
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 annual revenue requirements
$/ton coal
Mills/kWh burned
Equivalent unit revenue requirements 4.43 10.12
2,841,500
3,994,300
1,091,100
32,500
7,959,400
15,518,400
$/MBtu heat $/ton
input S removed
0.48 437
18.31
25.74
7.03
0.21
51.29
100.00
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.
Sulfur removed, 35,530 short tons/yr; solids disposal, 159,100 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $24,657,000; total depreciable investment, $44,398,000; and total
capital investment, $46,446,000.
All tons shown are 2,000 Ib.
211
-------
TABLE A-41
LIME SLURRY PHOCtSS VARIATION FROM bASE CASt: bOO MM tXlbTlNG HtfcULATEU CO. ECONOMICS
TOTAL CAPITAL lN»tST*tNT 46446000
N>
H"
N>
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
&
6
7
a
9
IP
11
12
13
14
^g
16
17
18
19
20
21
22
23
24
2s!
26
27
28
29
_3.A
TOT
ANNUAL
OPERA-
TION.
KW-HR/
KM
7000
7000
7000
7000
7000
5000
5000
5000
5000
5BOP
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
}500
92500
LIFETIME
POWER UNIT
KEAT
POWtR UNIT
f-U£L
SULFUR
KtHUVtO
BY
POLLUTION
UY-PROOUCT
RATE.
EuuIVALENT
TONS/YEAR
NET REVENUE.
WTON
REQUIREMENT. CONSUMPTION. CONTROL
MILLION MTU
/YtAR
32200000
32200000
3220UOOO
32200000
32£QO,J)f)0,
23000000
23000000
23000000
23000000
23000000
16100000
16100000
16101/000
16100000
16jpoouq
6900000
6900000
6900000
6900000
6,ypoo(io
6900000
6900000
6900000
6900000
6900000
425500000
TONS COAL
/YtA*
1633300
153J300
15J3300
1533300
IMiUJL
1095200
1U95200
10*5200
1095200
1095^00
766700
766700
766700
766700
7667oy
328600
328600
328600
328600
32.06PB
328600
328600
32860U
328600
328600
20262000
AVERAGE INCREASE (oecHtAst
DOLLARS
HER TON OF
PROCESS.
TONS/YtAR
35500
35500
35500
35500
35500
25*00
23400
25400
25400
2.&4VO
17800
17600
17BOO
17800
ITflPO
7600
7600
7600
7600
760G
7600
7600
7600
7600
76f(|
469500
0«Y
bOLIOS
159100
159100
la* 100
159100
i 591 no
113600
113600
113600
113600
1 1 36QI)
79600
79600
79&00
79600
79600
34100
34100
34100
34100
34100
34100
34100
34100
34100
3*,">P
2102500
DRY
SOLIDS
0.0
0.0
0.0
0.0
OfO.
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
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY.
S/YEAR
19808900
19503500
19198000
18892500
18587100
16146000
15840600
15535100
15229700
1492420Q
12950700
12645200
12339000
12034300
1172H800
9025300
8719800
8414400
8108900
7S0350Q
7498000
7192600
6687100
6S81700
6276200
311871900
TOTAL
NET
SALES
REVENUE.
S/YEAR
n
0
0
0
o
0
0
0
0
Q
0
0
0
0
o
0
0
0
0
0
0
0
0
0
n
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
*
1900*900
19503500
19198000
18892500
1858710?
16146000
15840600
15535100
15229700
14924200
12950700
12645200
12339800
12034300
H72SHPD
9025300
8719800
8414400
8104900
7803500
7498000
7192600
6387100
6581700
6276200
311871900
CUMULATIVE
MET INCREASE
(DECREASE)
IN COST OF
POWER.
S
19808900
39312400
5R510400
77402900
959900/00
112136000-
127976600
143511700
15874)400
_113.&656.fl0
186616300
199261500
211601300
223635600
_2J5i644DO
244389700
253109500
2615Z3900
269632800
_gj24_34Jj!IO
284934300
292126900
299014000
305595700
311971900
) IN UNIT OPERATING COST
COAL BURMED
MILLS PER KILOnATT-HOUR
CENTS Ptrt MILLION
PROCESS COST
LEVELIZED
DOLLARS
DISCOUNTED AT
PER TON OF
UTU HEAT INPUT
SULFUR REMOVED
11.2* TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS
MILLS ft
P£N TON OF
COAL UURNEO
EQUIVALENT
15.39
6.74
73.30
664.26
129754600
0.0
0.0
0.0
0.0
TO DISCOUNTED PROCESS COST OVER LIFE
:K «iL«"AT7-HOUK
CENTS ft* MILLION UTU HEAT INPUT
DOLLMS
PiH JON Of
SULFUR tfEHUVEO
13.84
6.06
65.92
597.67
0.0
0.0
0.0
O.tf
0
OF
15.39
6.74
73.30
664.26
129754600
POwER UNIT
13.04
6.06
65.92
597.67
-------
TABLE A-42. LIME SLURRY ^ROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2.0% sulfur)
* of
total direct
Investment, $ investment
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, tanks, agitators, and
pumps)
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to absorber, exhaust gas
SO 2 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onslte 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
1,009,000
430,000
41 fit nnn
, 1UZ ,UUU
7,909,000
1,218,000
1,260,000
15,928,000
956,000
16,884,000
2,481,000
19,365,000
1,026,000
236,000
2,887,000
913,000
5,062,000
4.885,000
29,312,000
2,683,OQC
3,517.000
35,512,000
494.000
941.000
36.947,000
(S74/WO
5.2
2.2
21.2
40.8
6.3
6.5
82.3
4.9
87.2
12.8
100.0
5.3
1.2
14.9
4.7
26.1
25.2
151.3
13.9
18.2
183.4
2.6
4.9
190.9
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average coat 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP
Construction labor shortages with accompanying overtiae pay incentive not considered.
213
-------
TABLE A-43. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Direct Costs
Delivered raw materials
Lime
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
32,700 tons
42.00/ton
23,280 man-hr 12.50/man-hr
1,373,400
1,373,400
291,000
46
3
488
200
,161
,370
,400
,600
,000
MBtu
kgal
kWh
man-hr
2
0
0
17
.00/MBtu
.12/kgal
,029/kWh
,00 /man-hr
1
1
4
5
976
24
,338
,425
57
,113
,486
,800
,100
,700
,200
,300
,100
,500
11.73
11.73
2.48
8.34
0.21
11.43
12.17
0.49
35.12
46.85
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 annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.35
2,130,700
3,177,500
886,800
29,100
6,224,100
11,710,600
$/ton coal $/MBtu heat $/ton
burned input S removed
7.81 0.37 730
18.19
27.14
7.57
0.25
53.15
100.00
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,0(10 hr/yr.
Coal burned, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Sulfur removed, 16,050 short tons/yr; solids disposal, 21,000 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $19,365,000; total depreciable Investment, $35,512,000; and total
capital investment, $36,947,000.
All tons shown are 2,000 Ib.
214
-------
TABLE A-44
LIMt SLURhY ^fiUCtSS VARIATION t-ritM B*S>E CASH: HY
/rt-.A- TOIVS/YLA*< SOLIUS
1->UIH'00
i^iiooou
IPOOOOO
l3i;t'KOO
InlOO
16100
IhlOO
lelOC
21000
21000
21000
21000
TOTAL
DI*. cosr
INCLUDING
NET rcEV£NUE> WtbULaTHO
»/TON HOI row
POwt"*
(JHY COMPANY.
SOLIDS */YtAU
0.0
0.0
0.0
O.O
14HH>Jl 00
146 A 4 5i)r)
144H09QI)
14277300
TOTAL
NET
SiXLti
0
0
0
0
NET ANNUAL
INCKEASE
(DECREASE)
IN COST OF
fG*EK.
$
14H»moO
146B4500
14480900
1473uO'JO
»)7buU06
ij7>uq|(ij
i/37bUUI;0
AVEKA.it ll.CWtAat
KULLANS
id M4UO
1 J / 1 4 0 0
lu/140U
1U7140U
Jj2jj4^j^
?30««()
( 3 0 U 0 0
/ b U 0 0 0
?3i;uOO
3^1400
J«dl400
3C1400
J£i4GO
^«il4(iu
JC 1400
J2l«()0
Jc^l400
32140.J
.i£l41H!
27jili)uu
(liLCxfcASt
KtH IOM Of
11300
1 1300
11300
11300
1 l^UO
lOilO
Hl>l>U
«ooo
"OUO
rj)pi;
340u
3400
3400
J40U
41» OO
J4ln/
3400
3400
3400
34UO
^V^b.,0
) liv UNIT UHtKATIfJb
COAL nUHMtll
15000
15000
1SOOO
15000
151' 00,
10300
10500
11)300
insoo
I 0 ^ Q 0
4300
4500
4500
4300
tbuu
4500
4300
4300
4300
4|2^^
C(;ST
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
pro
0.0
o.o
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
i^lLLb HC.K *1L J« A T 1 -nou»«
CtNTb Pf< I'iLLl'liM
PHOCtSb COST
LEVELLED
OULLOks
OISCOONTtD AT
ftn ro« of
•iTO HtaT IIMHUT
SULFUK HC.M
!!.«:» To 1MT1AL Yt««« OOLLAf-s
IwC^hlSt (DtCKt^bt) I« U.'.IT Oft"ATI/«CJ CubT £u
UULLAKb
i-iLLb Ht
Ptri !(Ji1 Ol-
rt KILl/fftTI'
Ct.^Tb ffc« i-iILLlO'Y
uOLL»>Hb
*"tK lOft Of
COAL rtOK.ltU
-nuUK
dTu nt"i liiKUT
SULFOrt HtHUVtU
iii>/ALf "»T
TO DISCOUNTED
131*70100
13666500
13462900
13259301)
^3055700
11303309
11099901)
10M96300
10692709
104891Q5
907060J
8867000
M663400
8459800
0
0
0
0
II
0
0
0
0
o
0
0
0
n
13670104
136665*0
13462900
13259300
M6274600
99941100
113404000
126663300
__iifiS52J!Jl_ J397_19J)J)0
11301500
11099900
10H96300
10692700
lfl4*9.LOJj
9070600
8S67000
8663400
8459800
151022500
162122400
173018700
183711400
i942J) 0.5.0.0
203271100
212138100
220801500
22.dl
106927POO
PO»E* ovi r
9.10
4.20
46.68
913.91
243809400
249897600
2557B2200
261463?00
_2fi4>SaJ)6J)0
272214400
277284600
282151200
286814200
_23J2!3.6.flO
-------
TABLE A-45. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
X of
total direct
Inveatment, $ investment
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers Including presatu-
rator and entrainment separators, tanks, agitators, and
pumps )
Stack gas reheat (four Indirect steam reheatera)
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
1,978,000
660,000
4,318,000
8,504,000
1,282,000
1,616,000
18,358,000
1.101,000
19,459,000
4,505,000
23,964,000
1,095,000
243,000
3,391,000
1,073,000
5,802,000
5,953,000
35,719,000
3,121,000
4,286,000
43,126,000
895,000
1,298,000
45,319,000
($90/kW)
8.3
2.8
18.0
35.5
5.3
6.7
76.6
4.6
81.2
18.8
100.0
4.6
1.0
14.1
4.5
24.2
24.8
149.0
13.0
17.9
179.9
3.7
5.4
189.0
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process Invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay Incentive not considered.
216
-------
TABLE A-46. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Direct Costs
Delivered raw materials
Lime
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
68,600 tons
42.00/ton
25,990 man-hr 12.50/man-hr
2,881,200
2,881,200
324,900
488,400 MBtu
232,600 kgal
47,008,000 kWh
3,760 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17 . 00/man-hr
976,800
27,900
1,363,200
1,691,900
63,900
4,448,600
7,329,800
19.35
19.35
2.18
6.56
0.19
9.16
11.36
0.43
29.88
49.23
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, 10% of operating labor
Total indirect costs
Total annual revenue requirements
2,587,600
3,897,400
1,040,400
32,500
7,557,900
14,887,700
17.38
26.18
6.99
0.22
50.77
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
4.25
9.92
$/MBtu heat
input
0.47
$/ton
S removed
428
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.
Sulfur removed, 34,750 short tons/yr; solids disposal, 153,600 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $23,964,000; total depreciable investment, $43,126,000; and total
capital investment, $45,319,000.
All tons shown are 2,000 Ib.
217
-------
TABLE A-47
5LOKKT
3.b»
>!hO>ULATti' CO. ECONOMICS
co
4331*000
YEAHS ANNUAL
AFTEf OPEfiA-
POWEM TION.
UMT K*-nkV
STANT K»
1 7000
2 7000
3 7000
4 7000
5 7pop
6 7000
7 7000
B 7000
9 7000
buLKUrt ar-^rtOnuCT
HtlUVtU X«TE«
P()«£H Uf»IT HO-.rt o^l f e>Y r iHiIVALr.».T
HEAf rUhL PULLUT1UM TOiMb/YtAK
t
730U
7500
7bOO
7aOO
z^uu
63«b()o
(OtCHtA'jr.) IN U.rflT Ul'tnwTINO
^*t^ Tut^ Of" COAL
HUHUfcL,1
lbjr>uO
Ib3o00
Ib36i)0
IbjnOO
1 b3faOii
Ib3600
Ib3b'i0
1^3600
IbJhui)
15 JbOO
109700
10*700
10*700
109700
1^*701!
7fc«00
76600
76800
?6nOO
7^800
32*00
32*00
32*00
32*00
32*01J
32900
32*00
32*9'l
32900
_3iiUA
2^97bOO
COST
TOTAL
OP. COST
iNCLUDIMi
.vKT HfcVEwUc. HEGULATKD
t/TOIx. r*OI f(>H
POHfcH
OKY COMPANY.
i-OLlUS t/YtAR
0.0
0.0
0.0
0.0
O.JO.
0.0
0.0
0.0
o.o
o.o
0.0
0.0
0.0
0.0
rt . 0
U.O
0.0
0.0
0.0
n. 0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
•vILLb Htr. MLU-«AT f-nUUrf
CtfcTb Hc« .".ILLllM aTu rttfcT IrvHUt
uOLL'Kb r'trt Fi/N Ot- SULt"U>« yiMI»tU
PROCESS COST
LEVELIZEO
OISC(,•U^TtL) AT
INCKtASt u01Q
14241300
13994000
13746600
13499500
1^2300
11388300
11141100
10o93Sf)0
1064bbOO
j £3,993. 0,0
7(130700
7583403
7336200
7081900
I\ET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE)
SALE* IN COST OF IN COST OF
%/VEAK
0
0
0
0
Q
0
0
0
0
i_
0
0
0
0
*
1H785300
18b3HOOO
1«2*0800
18043500
177963. 0.0
17549000
17301800
17054500
16807300
16560JJOO
14241300
13994000
13746800
13499500
X
1S7B5300
37323300
55614100
73657600
21*53.9.0.0
109002900
126304700
143359200
160166500
—1I6126JJJ10
1909678ITO
204961800
218708600
232208100
H_ 13252300 245460400
n
0
0
0
Q
0
0
0
0
6041700 fl
6b9440fl
6347200
6099900
5852700
56.Pb.tQil
367110000
13.44
5.76
63. *H
578.58
U5036700
fKUCESS COST OVE><
12. 3H
5.31
0
0
0
0
Jl
0
0.0
0.0
o.o
0.0
0
LIFE OF
0.0
O.o
11388300
11141100
10893800
10646600
10,3993.1)0
7830700
7583400
7336?00
7083900
6JJ41JJ1J1_
6594400
6347200
6099900
585?700
367110000
13.44
5.76
63.98
37H.b!i
135036700
KOWE* UNIT
12.38
S.31
256848700
267989800
27A883600
289530200
^^9229^00
307760200
315343600
322679800
329768700
33*6^0400
343204800
349552000
355651*00
361504600
3671^QOOO
Cc'vTs Htn
' BTo ritAl IlvkuT
TON Of SoLFuK Sc«0»tU
5«,95 O.i) 5H.95
533.3? 0.0 533.32
-------
TABLE A-48. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5.0% sulfur)
Direct Investment
Materials handling (£eeders> conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers including presatu-
rator and entrainment separators, 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 , $
2,294,000
836,000
4,318,000
8,504,000
1,282,000
1,907,000
19,141,000
1,148,000
20,289,000
6,318,000
26,607,000
1,148,000
248,000
3,641,000
1,162,000
6,199,000
6,561,000
39,367,000
3,305,000
4,724,000
47,396,000
1,256,000
1,641,000
50,293,000
(SlOl/kW)
7, of
total direct
investment
8.6
3.1
16.2
32.0
4.8
7.2
71.9
4.4
76.3
23.7
100.0
4.3
0.9
13.7
4.4
23.3
24.7
148.0
12.4
17.7
178.1
4.7
6.2
189.0
Basis
Evaluation 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 I mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
219
-------
TABLE A-49. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.05? sulfur)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
reouirements
Direct Costs
Delivered raw materials
Lime
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
105,400 tons
42.00/ton
27,910 man-hr 12.50/man-hr
4.426,800
4,426,800
348,900
47
488,400 MBtu
264,500 kgal
,852,000 kWh
4,040 man-hr
2.00/MBtu
0. 12/kgal
0.029/kWh
17.00/man-hr
976,800
31,700
1,387,700
1,812,700
68,700
4,626,500
9,053,300
25.48
25.48
2.01
5.62
0.18
7.00
10.43
0.40
26.63
52.11
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
2,843,800
4,325,200
1,115,200
34.900
8,319,100
17,372,400
47.89
100.00
Equivalent unit revenue requirements
Mills/kWh
4.96
$/ton coal
burned
11.58
$/MBtu heat
input
0.55
$/ton
S removed
323
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.
Sulfur removed, 53,730 short tons/yr; solids disposal, 238,700 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $26,607,000; total depreciable investment, $47,396,000; and total
capital investment, $50,293,000.
All tons shown are 2,000 Ib.
220
-------
TABLE A-50
LIME SLURRY PROCESS «««U!ICFv F«0« rJASE CASE: 5.0* S REOULATED CO. ECONOMICS
roT«L CAPITAL INVESTMENT 50293000
to
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
1 0
11
12
13
14
15
16
17
18
19
29
21
22
23
24
25 .
26
27
28
29
3.0
ANNUAL Po«tM UMi
OPERA- Mt*T
TION.
REWUIrttHEM.
K«-HRX MILLION oTU
KW
7000
7000
7000
7000
-ISUISL
7000
7000
7000
7000
70OO
5000
5000
5000
5000
5OOO
3500
3500
3500
3500
3SOO
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 127500
LIFETIME
XYcArf
31500000
31bOUOOO
31500000
3150UOOO
31500000
3ibOOJOO
31500000
31500000
31500000
31bOOi)uO
22500000
22500000
22500000
22500000
2/>SOUOOO
15750000
1575UOOO
1575JOOO
15750000
15" 750000
6750000
6750000
67500(10
67bUOOO
1,750000
6750000
6750000
6750000
6750000
6750000
573750000
SULFUR wY-PROOUCT
REMOVED RATE,
PUtfER U.'MlT BY EQUIVALENT
FUEL POLLUTION
CONSUMPTION* CONTHUL
TUNS COAL PROCESS*
/YEAH TONS/YEA*
15(10000 53700
1500000 53700
1500000 53700
1500000 53700
1^00000 53700
IbOOOOO 53700
1500000 53700
IbOOOOO 53700
1500000 53700
1900000 53700
1071400 30400
1071400 3U400
1071400 38400
1071400 3b400
1O71«I)U 3««00
750000 26900
750000 26900
750000 26900
750000 26900
7bOOflO ?h«00
321400 11500
321400 11500
321400 llbOO
321400 11500
321400 UbUfl
321400 11500
321400 11500
321400 11500
321400 11500
321400 11500
27321000 970500
AVERAGE INCREASE (otcwEASE) IN UNIT OPEKATING
DOLLARS
PER TON OF COAL BURNED
TONS/YEAR
DRY
SOLIDS
23H700
238700
238700
238700
238700
238700
23B700
238700
238700
238700
170500
170500
170500
170500
1705DO
119400
119400
119400
114400
119400
51200
51200
51200
51200
51200
51200
51200
51200
51200
51£00
4346500
COST
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
SXTON ROI FOR
DRY
POWER
COMPANY*
SOLIDS SXYEAR
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
0.0
0.0
0.0
0.0
0.0
0.0
MILLS PErt KILOWATT-HOUR
CENTS PER MILLION 8TU MEAT INPUT
PROCESS
COST
LEVEL UED
DOLLARS
DISCOUNTED AT
PER TON OF SULFUR REMOVEO
11.2* TO INITIAL YEAR* DOLLARS
INCREASE (DECREASE) IN UMT OPERATING COST EQUIVALENT TO
UOLLAHS
PER TUN OF COAL BORNEO
DISCOUNTED
MILLS PEn KILOWATT-HOUR
CENTS PtR MILLION 6TU HEAT INPUT
UOLLMHa
PEK TON OF SULFUR REMOVED
21697800
21426100
21154300
20882600
20610800
20339100
20067300
19795600
19523900
19252100
16418100
16146300
15874600
15602800
15331100
13070000
12798200
12526500
12254700
41983000
8881100
8609400
8337700
8065900
779420p
7522400
7250700
6978900
6707200
6435500
423337900
15.49
6.64
73.78
432.64
156135800
PROCESS COST OVER
14.31
6.13
68.16
399.73
TOTAL
NET
SALES
REVENUE
JXYEAR
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
LIFE OF
0.0
0.0
0.0
0.0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
• POWER*
%
21697800
21426100
21154300
20882600
2061000°
20339100
20067300
19795600
19523900
19252100
16418100
16146300
15874600
15602800
15331]00
13070000
12798200
12526500
12254700
119830,90
8881100
8609400
8337700
8065900
7794?00
7522400
7250700
6978900
6707200
6435500
423337900
15.49
6.64
73.78
432.64
156135800
POWER UNIT
14.31
6.13
68.16
399.73
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER*
S
21697800
43123900
64278200
85160800
105771600
126110700
146178000
165973600
185497500
204749600
221167700
237314000-
253188600
268791400
284122500
297192500
309990700
322517200
334771900
346754900
355636000
364245400
372583100
380649000
388443200
39S965600
403216300
410195200
416902400
423337900
-------
TABLE A-51. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVEST?TCNT
(Variation from base case: 1,000-MW existing)
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers including presatu-
rator and entrainment separators, tanks, agitators, and
pumps)
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, $
2,967,000
966,000
8,679,000
13,606,000
2,026,000
2,262,000
30,506,000
1,830,000
32,336,000
6,203,000
38,539,000
1,145,000
248,000
5,068,000
i;540,000
8,001,000
9,308,000
55,848,000
4 , 964 , 000
6,702,000
67,514,000
1,238,000
2,346,000
71,098,000
($71/kW)
% of
total direct
investment
7.7
2.5
22.5
35.3
5.3
5.9
79.2
4.7
83.9
16.1
100.0
3.0
0.6
13.2
4.0
20.8
24.1
144.9
12.9
17.4
175.2
3.2
6.1
184.5
Basis
ISIS
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered
222
-------
TABLE A-52. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW existing)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered raw materials
Lime
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
137,200 tons
36,750 man-hr
42.00/ton
12.50/man-hr
5,762,400
5,762,400
459,400
976,700 MBtu
465,300 kgal
93,415,000 kWh
6,100 man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
17.00/man-hr
1,953,400
55,800
2,615,600
2,449,600
103,700
7,637,500
13,399,900
22.70
22.70
1.81
7.69
0.22
10.30
9.65
0.41
30.08
52.78
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 annual revenue requirements
4,320,900
6,114,400
1,506,400
45,900
11,987,600
25,387,500
17.02
24.09
5.93
0.18
47.22
100.00
Equivalent unit revenue requirements
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
3.63
8.46
0.40
365
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, 2,999,900 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Sulfur removed, 69,490 short tons/yr; solids disposal, 307,200 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $38,539,000; total depreciable investment, $67,514,000; and total
capital investment, $71,098,000.
All tons shown are 2,000 Ib.
223
-------
TABLE A-53
LIME SLURRY PROCESS VARIATION FnO« d«SE CASE: l.UOu M* EXISTING REliULATEO CO. ECONOMICS
TOTAL CAPITAL iNVESTxtwT 71098000
to
IS)
YEARS ANNUAL PO*EK UMT
AFTER OPERA- Mt A t
POMCR TION. REUulREMENT.
UMT KW-HR/ MILLION rtTU
START K» /YEA*
1
2
3
6
7
a
9
JO
11
12
13
14
15
16
17
18
19
_20
21
22
23
24
25
26
27
26
29
30
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
_3iflO_
1500
1500
1500
1500
-15JUL
1500
1500
1500
1500
1500
TOT 92500
LIFETIME
63000000
63000000
63000000
63000000
6:jOODOOO
450000CO
4500i>000
45000000
45000000
*900UOOO
31500000
31500000
31500000
31500000
3|bllUOOO
13500000
1350UOOO
13500000
13500000
13i9t}vVf/Q
13506000
13500000
13500000
13500000
ijsgflflpg.
83250UOOO
SULFoK bY-PRODUCT
REMOVED KATE.
PG«tR U^IT 6Y EUUIVALENT
FUEL POLLUTION TONS/YEAR
CONSUMPTION. CONTROL
TONS C.OAL PROCESS. ORY
/Yt»t» TONS/YEAR SOLIDS
3000000
3000000
30UOOOO
3000000
jououno
2142900
2142*00
21 42*00
21*2*00
^ 1 **>*00
1500000
IbUOUOO
IbUOUOO
lauouoo
IboOOOO
642900
642900
642900
642*00
b^290u
64£*00
b4£900
b*2900
642900
6*2*00
3*6*3500 1
6*500
69300
69500
6*500
4V600
*VoOO
**600
4*600
*<*600
34700
34700
34700
34700
34700
14900
1*900
1*900
1*900
J4VOO
1*900
1*900
1*900
14900
14900
ilBOOO
AVERAbt INCREASE (utCwtAst) IN ONIT OPERATING
DOLLAHS
307200
307200
307200
307200
307200
219400
21*400
219*00
219400
21*400
153600
153600
153600
153600
153600
6SUOO
65800
6SttOO
65bOO
65600
65800
65800
65800
65800
65800
4059000
COST
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
I/TON ROI FOR
POWER
DRY COMPANY.
SOLIDS S/YEAR
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
Q
0
0
0
0
p,
PER TON OF COAL bURNkD
HILLS PtK IULC*ATT-HOL'R
CENTS PEN MILLION 6TU MEAT
PROCESS
COST
LEVELI2EO
DOLLARS
DISCOUNTED AT
PER TON OF SULFUR
INPUT
REMOVED
11. I* TO INITIAL YEAK. DOLLARS
INCREASE (DECREASE) IN UnIT OPERATING COST EQUIVALENT TO
UPLLARS
PEw TON OK COAL *>u
RNEU
DISCOUNTED
HILLS PER KILO«ATT-HGUR
CENTS PtH MILLION uTU HEAT
DOLLARS
INPUT
PtK TO* OF SULFUR WtMOVtU
31952400
31487900
31023300
30558800
30094300
25832100
25367600
24903100
24438600
23974100
20570400
20105900
19641400
19176900
1871P400
14090200
13625700
13161200
12696700
; 22J229fl
11767700
11303200
10838700
10374200
9909700
497838700
12.56
5.38
59.80
542.31
208358300
PROCESS COST OVER
11.36
4.87
54.10
490.60
TOTAL
NET
SALES
REVENUE.
S/YEAR
0
0
0
0
D_
0
0
0
0
o
0
0
0
0
I)
0
0
0
0
NET ANNUAL CUMULATIVE
INCHEASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
PO«ER. POWER.
f t
31952400
31487900
31023300
30551800
300943flp
25832100
25367600
24903100
24438600
23974)00
20570400
2010S900
19641400
19176900
Ifl71?400
14090200
13625700
13161200
12696700
31952400
63*40300
94463600
125022400
-15511 6JDO
180948800
206316400
231219500
255658100
27 963220 0
300202600
320308500
339949900
359126800
_3278_3S_2J}0
391929400
405555100
418716300
431413000
_JL 12232200 443645200
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
11767700
11303200
10838700
10374200
9909700
49783*700
12.56
5.38
59.80
54?. 31
208358300
POWER UNIT
11.36
4.87
54.10
490.60
455412900
466716100
477554800
487929000
49 7 8387J) 0
-------
TABLE A-54. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW)
X of
total direct
Investment, $ investment
Direct -Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers including presatu-
rator and entrainment separators, 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
2,670,000
948,000
7,125,000
12,501,000
1,872,000
2,052,000
27,168,000
1,630,000
28,798,000
7,678,000
36,476,000
1,185,000
251,000
4,772,000
1,477,000
7,685,000
8,832,000
52,993,000
4,532,000
6,359,000
63,884,000
1,530,000
2,240,000
67,654,000
($68/kW)
7.4
2.6
19.5
34.3
5.1
5.6
74.5
4.5
79.0
21.0
100.0
3.2
0.7
13.2
4.0
21.1
24.2
145.3
12.4
17.4
175.1
4.2
6.1
185.4
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process Invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
225
-------
TABLE A-55. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered raw materials
Lime
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
131,600 tons
42.00/ton
36,750 man-hr 12.50/man-hr
5,527,200
5,527,200
459,400
944,200 MBtu
503,500 kgal
90,320,000 kWh
6,100 man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
17.00/man-hr
1,888,400
60,400
2,529,000
2,246,200
103,700
7,287,100
12,814,300
23.11
23.11
1.92
7.90
0.25
10.58
9.39
0.43
30.47
53.58
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 annual revenue requirements
3,833,000
5,818,200
1,404,700
45,900
11,101,800
23,916,100
16.03
24.33
5.87
0_.J19
46.42
100.00
Equivalent unit revenue requirements
$/ton coal S/MBtu heat $/ton
Mllls/kWh burned input S removed
3,42
8.25
0.39
359
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.
Sulfur removed, 66,540 short tons/yr; solids disposal, 297,000 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,476,000; total depreciable investment, $63,884,000; and total
capital investment, $67,654,000.
All tons shown are 2,000 Ib.
226
-------
TABLE A-56
LIMt SLURHY PROCESS
rmj,* n«SE CASE! 1.000 »* wfcbULATEU CO. tCONOflCS
GfoL CArlTAL INVtsT»tNT 6765*000
K>
bOLFOK HY-PUOL'OCT
rlfcMOVtO RATE,
YEARS ANNUAL POotH UNIT HUi.f< UNIT BY tUUl VALtuT
AFTER OPEHA- ntAT FUEL POLLUTION TONS/YtAK
POWER TION, REUUlMtMtwT. CONSUMPTION, COi»TnOL
UMT Kw-HH/ rtlLLlOn "TO TumS C04L PROCESS, t)«Y
STAKT KM /rt»n /Ytaw
1
2
3
4
^
6
7
U
9
1£
U
12
13
14
15 .
16
17
18
19
2.Q
£J
22
23
24
.25
26
27
28
£9
JJ)
TOT
7000
7000
7000
7000
_IILfi£_
7000
7000
7000
7000
_IflJ2li_
5000
5000
SOUO
5000
6090000K
60900000
60900000
6090UOOO
op9ijuy^j)
60900000
00900000
6090UOOO
60900000
&M<*$l^Mjl!l
43500000
43500000
43SOUOOO
43500000
f. t u 0 0 0 0
i£900 0 0 0
2^00000
i-«UOOOO
TQmS/YEAP SOLIOS
6f?UO
66500
66bOO
66bOO
297000
297000
29 7000
297 000
TOTAL
OP. COST
INCLUUINti
NET HEVENOE, WtTOULATt'O
»/TON KOI FOR
POWER
OP.Y COMPANY,
SOLIOS S/YEAO
0
0
0
0
.0
.0
.0
.0
29734700
2936M400
29002100
28635900
TOTAL
NET
SALES
REVENUE,
S/YEOH
0
0
0
0
NET ANNUAL CUMULATIVE
INCREASE MET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST CF
t
2973*700
2936«400
29002100
26635900
*
29734700
59103100
88105200
116741100
.^ fJ^OlJPUO 6b50l) 297000 0.0 28269600 0 2826^600 145010700
C^UOUUU
ooooo
^*>0 0 0 0 0
^^0 0 0 00
jt*7^!}!'!!^
<;o714«o
7 1 40 0
2 0 7 1 4 0 0
66500
6ob')0
66500
6^300
SttQS
47500
47500
»7sOO
4/300
297000
29/000
297000
297000
297000
212100
212100
212100
212100
SOOIf 43500000 «:u71»00 W500 ?1?100
3500
3500
3500
3500
3.5Jlii_
1500
1500
1500
1500
304bOJOO
304boOOO
30450000
30450000
jj^bjjj^jjj
13050000
13050000
1305UOOO
13050000
lUbOuuO
14SUOOO
14SHOOO
1*-5JUI)U
I^t2jj^ijij
621400
621400
o21«00
6^1400
J5P.O 1305UOOO t>2l»0u
1500
1500
1500
1500
15PV
127500
LIFETIME
1305UUOI)
13050000
13050000
13050000
1305.JJDV9, ,
1109250000
AVERAGE INCxtast
uOLLAhS
MILLS PL
bdl40U
6C1400
6214UO
o1^^J^
32SC1000
33JOO
33300
33300
33300
j^j.y.,0.
14300
14300
14300
l430u
^ 430 G
14300
14300
1<»300
l«30b
_ 1*300
U12000
(OtC".t«St> IN UNIT OPfcHATIivli
PEn TON Or
H RlLUKATT
CtiyTs PtK ••< ILL I ON
PROCESS COST
LEVELIZED
UOLLAHb
DISCOUNTED AT
PtK TUN Uf-
COAL pUKMto
-HOOK
oTO HEAT INPoT
SuLFUK RthOvtO
148600
148500
14H500
14«bOO
14H5Qii d
63600
63600
63600
63600
636OO
63600
03600
63600
63600
63600
54fl¥00n
COST
0
0
0
0
(1
0
0
0
0
0
0
0
0
0
.0
.0
.0
.0
^0
.0
.0
.0
.0
IP
.0
.0
.0
.0
27903300
27537000
27170800
26804500
£6^3^£oy
22439200
22073000
21706700
21340400
20974200
17798600
17432300
17066000
16699800
0.0 16333500
0
0
0
0
0
0
0
0
0
0
.0
.0
.0
.0
if)
.0
.0
.0
.0
t<»
11. d* TO INITIAL YE»K« UOLL««S
INCREASE (DECREASE) IN u«
liJLL««=>
PC« TON or
IT OPERATING LOST E-JUI VALfc'MT TO
COAL tfUKi^tb
DISCOUNTED
MLLb PLH MLUxATT-HoliH
CENTS ftft MILLION
KOLLAHb)
PtK I UN Or
dTo HtAT If-PUl
SULFu* KEf-iOvto
11998700
11632400
11266200
10899900
1053J600
10167300
9801100
9434400
9068500
H702200
57B232900
10. 9S
4.54
52.13
477.09
213855700
PROCESS COST OVER
10.14
4.20
48.29
442.12
0
0
0
0
Q
0
0
0
0
__J!
0
0
0
0
27903300
27537000
27170800
26H04500
£643*200
22439200
22073000
21706700
21340400
20974200
17793600
17432300
1706*000
16699800
172914000
200451000
227621800
254426300
_2fl3fiS*5.90
303303700
325376700
347083400.
368423800
_3.393.9BOflO
407196600
42*628900
44169*900
458394700
. S 16333500 *147292BO
0
0
0
0
Q
0
0
0
0
o
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
11998700
11632400
11266200
10899900
1 0533600
10167300
9801100
9434800
9068500
87p2gOO
578232900
10.95
4.54
52.13
477.09
213855700
POxEP ONIT
10.14
4.20
4P.29
442.12
486726900
498359300
509625500
520525400
531 Q5.9QDO
541226300
551027400
560462200
569530700
_52tf£329jDO
-------
TABLE A-57. LIME SLURRY PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% S02 removal)
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers including presatu-
rator and entralnment separators, 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, $
2,176,000
709,000
4,318,000
8,504,000
1,282,000
1,713,000
18,702,000
1,122,000
19,824,000
5,001,000
24,825,000
1,110,000
244,000
3,477,000
1,103,000
5,934,000
6,152,000
36,911,000
3,191,000
4,429,000
44,531,000
991,000
1,387,000
46,909,000
($94/kW)
% of
total direct
investment
8.8
2.9
17.4
34.2
5.2
6.9
75.4
4.5
79.9
20.1
100.0
4.5
1.0
14.0
4.4
23.9
24.8
148.7
12.9
17.8
179.4
4.0
5.6
189.0
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
228
-------
TABLE A-58. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% SO- removal)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered raw materials
Lime
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
78,400 tons
25,990 man-hr
42.00/ton
12.50/man-hr
3,292,800
3,292,800
324,900
488,400 MBtu
240,500 kgal
47,226,000 kWh
3,760 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
976,800
28,900
1,369,600
1,736,000
63,900
4,500,100
7,792,900
21.12
21.12
2.08
6.26
0.19
8.78
11.14
0.41
28.86
49.98
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 annual revenue requirements
2,671,900
4,034,100
1,062,400
32,500
7,800,900
15,593,800
17.13
25.87
6.81
0.21
50.02
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
4.46
10.40
$/MBtu heat
input
0.50
$/ton
S removed
392
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.
Sulfur removed, 39,800 short tons/yr; solids disposal, 177,800 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $24,825,000; total depreciable investment, $44,531,000; and total
capital investment, $46,909,000.
All tons shown are 2,000 Ib.
229
-------
TABLE A-59
SLUHHY PHoCtss VAKIAUOK (-«o« nAit-: tAbt': vu*. suit
FOI6L CAPITAL
*Et>uLMTt'J CO. ECONOMICS
46*0*000
YEAMS ANNUAL
AFTE* OPEKA-
Po»tfi TION«
UNIT K«-HH/
ST.,
1
2
3
4
£
6
7
a
9
ii)
11
12
13
14
1C
16
17
18
19
u»PTIu\» Lur.TKGL MOflF.w SALES IN COST OF IN COST OF
MtLLlOi- *TO T\;i
ic^doUUu
Ss b u(j 0 hi)
l-37bJOOO
lo75UOuo
1*1 7biiOO 0
167-3UOOO
/Yt.fl^ TOiNS/Yr.sx b(;LlOS
IbOOOOu 3***3uu
InoOuOU j^dOo
IbOvlOOO 3voUO
IbOuoOO 3vhOu
^^yn^oii 3s»o'JO
lr>ODuOu j^eoo
l^OHOOO J'jrtaO
Ib'd'iOOo 3>»nou
IbOOOOU 3V"OO
1 = UOU(|0 3"»«UO
4071400 i.Tulu
lu'140u H^4uO
1U'1400 2f.400
IU'1400 2f>-»OU
Iu71**fl0 k')400
730000 1WUU
/b0
177HOO
17 7«00
177WOO
J77HOI)
177«(H)
177800
177WJU
1 771*00
1.7JbUO
127000
12700U
127000
127000
1 2 7 1*00
8M*00
fl«*UO
i^-yoo
8--JUO
2fl 3500 ISfbuOOil ^bOOOU 1**DO dn^Oij
£1
22
23
£4
25
26
,>7
28
2*
?o
TOT
1500
1500
1500
1500
15C. 0.
1500
1500
1500
1500
1275UO
LIFETIME
b 7 b u ij 0 0
b 7bOOO 0
6 7 S 0 0 0 0
tj/buooo
n 7 b. il i) 0 0
67SOUHO
6 7buOO 41
6 7 b u D 0 0
ti 7bO U (j 0
fi^bJi^VQ
5737buO')fl
AVE^IAbE lr»C*tA->e
UOLLAKb
"ILLS ft
J21»00 cbUO
Jel400 pbOO
Jil4()j -sbuo
JCI1400 bbuo
J^i^i'^ ^t?*'^
J214fil/ cbOO
j«r»»0o dbOO
J214UO B500
J^1400 cb'JO
j£ i* 0 U *?T?*^ V
C7J21000 72.300
(DtCrftAat) IN UU1T OfEKATINfa
t^tn TUN OF COAL rtUKNED
n ^ILOilOO
3^101)
3234500
COST
bOLIUS
0.0
0.0
0.0
0.0
0.4
0.0
0.0
0.0
0.0
9*9
0.0
0.0
0.0
0.0
O.Q
0.0
0.0
0.0
O.I)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CENTS fen >"ILLlo« bTO HtAT 1NHUT
PKOCtSS COST
bULLOKb
OISCOONTEU »T
r'trf TON OF SOLFO" Kt^OvEJ
11.2-t TO INITIAL YtAH. UULLAKb
S/YtA* S/YEAK *
1*628100
1*372800
1*117500
188A2200
18606*00
18351600
18096200
17B40900
17585600
17330300
14«71700
14616400
14361000
I4iob7no
1 38504*10
11H7H100
11622800
11367503
11112100
J 08561500
8143100
7887800
7632500
7377200
7121 800.
6866500
6611200
6355900
6100600
SgAC^An
383376500
14.03
6.01
66.82
529.16
141124500
0
0
0
0
0
0
0
0
0
0
0
0
a.
0
0
0
0
0
0
0
0
0
p.
0
0
0
0
a.
0
0.0
0.0
0.0
0.0
0
1*628100
1*372800
19117500
1886??00
1£630,0
14871700
146164QO
14361000
1410S700
1 3850400
11878100
1162280')
11367500
11112100
10856850
8143100
7887800
7632500
7377200
7121990
6866500
6611200
6355900
6100600
. 5845300
383376500
14.03
6.01
66.82
529.16
141124500
s
19628100
39000*00
58118400
769H0600
95557550
11393*100
132035300
149876200
167461800
1*9663800
214280200
228A41200
242746900
-256537J .00
26P47S400
2800*8200
291465700
302577800
JI3A3*.M)0
321577700
329465500
337098000
344475200
J515S2JJJ)0
358463500
365074700
371430600
377531200
Jfl3i7.65.DO
LEVELIZtl) INCHtASt IDtCMt»5t) IN U>>IT OPt"*TlArto COST tulll i/ALtNT TO OISCOONTEO "rtoCESS COST OVErt LIFE OF POnErt UNIT
UOLLAKS P£« TOM OF COAL nuntJtO 12.94 0.0 12.*4
MILLS fci MLUoATT-liouHi 5.54 0.0 5.54
CENTS KtK BILLION bTu MtflT INPOT 61.60 0.0 61.60
TUN OF SOLFUH HtHOVtU 487.65 0.0 487.05
-------
TABLE A-60. LIME SLURRY PROCESS
SUMJiARY OF ESTI?1ATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
Direct Investment
Materials handling (feeders, conveyors, elevators, and
silos)
Feed preparation (feeders, slaker, 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 mobile-bed scrubbers including presatu-
rator and entrainment separators, tanks, agitators, and
pumps)
Stack gas reheat (four direct oil reheaters)
Solids disposal (onslte 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, $
1,088,000
420,000
4,448,000
7,994,000
731,000
1,357,000
16,038,000
962,000
17,000,000
1,754,000
18,754,000
998,000
233,000
2,833,000
891,000
4,955,000
4,742,000
28,451,000
2,670,000
3,414,000
34,535,000
357,000
919,000
35,811,000
($72/kW)
% of
total direct
investment
5.8
2.2
23.7
42.7
3.9
7.2
85.5
5.1
90.6
9.4
100.0
5.3
1.2
15.1
4.8
26.4
25.3
151.7
14.2
18.2
184.1
1.9
4.9
190.9
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
231
-------
TABLE A-61. LIME SLURRY PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Direct Costs
Delivered raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Oil
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
30,200 tons
42.00/ton
24,900 man-hr 12.50/man-hr
.1,2 6814 00
1,268,400
311,300
2,872,900 gal
173,700 kgal
39,270,000 kWh
3,600 man-hr
0.40/gal
0.12/kgal
0.029/kWh
17.00/man-hr
1,149,200
20,800
1,138,800
1,412,600
61,200
4,093,900
5,362,300
10.95
10.95
2.69
9.93
0.18
9.84
12.20
0.53
35.37
46.32
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 annual revenue requirements
2,210,200
3,079,800
892,600
31.100
6,213,700
11,576,000
19.09
26.61
7.71
0.27
53.68
100.00
Equivalent unit revenue requirements
Mills/kWh
$/bbl oil
burned
3.31
2.16
$/MBtu heat
input
0.36
$/ton
S removed
778
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.
Sulfur removed, 14,880 short tons/yr; solids disposal 65,570 tons/yr calcium solids Including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $18,754,000; total depreciable investment, $34,535,000; and total
capital investment, $35,811,000.
All tons shown are 2,000 Ib.
232
-------
TABLE A-62
LIMfc SLURRY PROCESS VARIATION KHQN b«St CASt: OIL-FIKEU, EXISTING
TOTAL CAPITAL INVESTMENT
35811000
Co
U)
SULFl/R
Kti"OvtU
YEARS ANNUAL POHtrt UNIT fGfctK UNIT bY
AFTER OPERA- MEAT FUEL POLLUTION
POkER TION. REQUIREMENT. CONSUMPTION, CONTROL
UMT KK-HR/ MILLION RTU B«RntLS'ClL PROCESS,
STAHT IV* /YEAH /YfcA« TONS/YtAR
1
2
3
4
6 7000 31500000 5eOS300 14900
7 7000 31500000 S20B300 14900
8 7000 31500000 biOdjOO 1*900
9 7000 31500000 SiOeaOO 14900
10 7000 31bOUOnO 5^0t}3.0,0 14?0o
11 5000 ^300000 3720200 10600
12 5000 22500000 372U200 10600
13 5000 22300000 3720^00 10600
14 5000 22500000 J720200 10600
J5 5000 22500000 J7«ip20U 1060U
16 3500 15750UOO COU4200 7400
17 3500 15750000 260420(1 7400
lb 3500 15750000 2604200 7400
19 3500 15750000 2604200 7400
?0 3500 15750000 2t>0420.q 7400
21 1500 6750000 1116100 3200
22 1500 6750000 1116100 3260
23 1500 6750000 1116100 3200
24 1500 6750000 1116100 3200
25 _1§PO 6.7SUOOO 1116100 J«?00
26 1500 6750000 1116100 3200
27 1500 6750000 1116100 3200
26 1500 675uOOO 111610U 3200
29 1500 6750000 1116100 3200
30 l^oy, ^TSoOtyo il^6,\(/j) J20.U
TOT 92500 416250000 6HH24500 196500
MY-PRODUCT
RATE,
EQUIVALENT
IONS/YEAR
DRY
SOLIUS
14«00
14HOO
14bOO
14t)00
14HOO
10600
10600
10600
10600
1 Q6Q 0
7400
7400
7400
7400
7400
3200
3200
3200
32UO
3200
3200
3200
3200
3200
3.20. D
196000
NET HEVENUE.
S/TON
'DRY
SOLIDS
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
0.0
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
14866100
14648500
14410900
14173300
1393S700
12185400
11947800
11710200
11472600
11235000
9808800
9571200
9333600
9096000
8858400
6893700
6656100
6*18500
6180900
5943300
5705700
5466100
5230500
4992900
4755390
235518500
TOTAL
NET
SALES
REVENUE,
t/Y£AR
0
0
0
0
JL
0
0
0
0
A
0
0
0
0
A
0
0
0
0
o
0
0
0
0
0
0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECPEASE)
IN COST OF IN COST OF
PO»ER, POKER,
* S
14666100 14886100
14648500 29534600
14410900 43945500
14173300 58118800
13935700 12554550
12185400 84239900
11947800 96187700
11710200 107897900
11472600 119370500
}1235(00 130605500
9808800 140414300
9571200 149985500
9333600 159319100
9096000 168415100
8858400 177273500
6893700 184167200
6656100 190823300
6418500 197241800
6180900 203422700
5943300 209366000
5705700 215071700
5468100 220539800
5230500 225770300
4992900 230763200
4755300 235518540
235518500
LIFETIME AVERAGE INCREASE (DECREASE) IN UMT OPERATING COST
OOLLARS PER bARHtL OF OIL bURNEO
HILLS PtR KILOWATT-HOUR
CENTS PER MILLION BTU MEAT INPUT
UOLLARb PER TON OF SULFUR REnOVEU
PROCESS COST DISCOUNTED AT 11.2* TO INITIAL YEAR, UULLAWS
LEVELIZEO INCREASE (DECREASE) IN UNIT OPLRATINII COST
UOLLARs PER riARREL OF OIL bUWNEU
HILLS PER KILOATT-HOUH
CENTS PEH MILLION BTU MEAT INPUT
UOLLARS PER TON OF SULFUR REMOVED
EuUI
-------
TABLE A-63. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200-MW existing)
, — . — . :
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (two mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal, 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, $
1,558,000
2,273,000
437,000
2,202,000
4,082,000
590,000
1,357,000
12,499,000
750,000
13,249,000
1,316,000
14,565,000
1,001,000
237.000
2,298,000
735,000
4,271,000
3,767,000
22,603,000
2,129,000
2.712.000
27,444,000
265,000
583,000
28,292,000
($141/kW)
;: of
total direct
investment
10.7
15.6
3.0
15.1
28.0
4.1
9.3
85.8
5.2
91.0
_!..o
100.0
6.9
1.6
15.8
— L-.0
29.3
25.9
155.2
14.6
18.6
188.4
1.8
4.0
194.2
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
234
-------
TABLE A-64. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200-MW existing)
Direct Costs
Delivered raw materials
Limestone
Coal
Annual
quantity
54,640 tons
8,290 tons
Unit
cost, $
7.00/ton
25.00/ton
Total
annual
cost, $
382,500
207,300
% of average
annual revenue
requirements
4.54
2.46
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
23,830 man-hr 12.50/man-hr
206,200 MBtu
101,000 kgal
22,396,000 kWh
10,600 MBtu
2.00/MBtu
0.12/kgal
0.031/kWh
2.00/MBtu
2,480 man-hr 17.00/man-hr
589,800
297,900
412,400
12,100
694,300
(21,200)
1,231,900
42,200
2,669,600
3,259,400
7.00
3.53
4.89
0.14
8.24
(0.25)
14.62
0.50
31.67
38.67
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, 507. of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
1,921,100
2,433,100
786,000
29,800
5,170,000
8,429,400
22.79
28.86
9.33
0.35
61.33
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
$/MBtu heat
input
6.02
13.31
0.63
S/ton
S removed
575
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.
Sulfur removed, 14,670 short tons/yr; solids disposal 64,800 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $14,565,000; total depreciable investment, $27,444,000; and total
capital investment, $28,292,000.
All tons shown are 2,000 Ib.
235
-------
TABLE A-65
LIME SLURRY PROCESS *ITn CALCINATION VARIATION )• ROM bASE CASE: 200 MM EXISTING REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 2M292000
SULFUR tiY-PROOUCT
REMOVED RATE*
YEARS ANNUAL P0«trt UNIT HUwEK UNIT BY EQUIVALENT
AFTER OPERA- HtAT FUtL_ POLLUTION
PO»ER TIONt REQUIREMENT? CONSUMPTION. CONTkOL
UNIT KW-HR/ MILLION tjTU TOHb COAL fROCEbS.
START K« /YEAH /YtAH TONS/YtAR
1
2
3
4
5
6
7
8
9
11 5000 9500000 4b2«00 lUbOO
12 5000 9500000 <»b2400 liibOO
13 5000 •ybOOOOO 452400 10500
14 bOOG 9500000 452400 10500
If 5000 9500000 4524QO IflSGU
16 3500 6650000 316700 7300
17 3500 6650000 316700 7300
18 3500 6650000 316700 7300
19 3500 6650000 J16700 7300
SQ 3500 6650000 Jlfa700 73UO
21 1500 2850000 135700 3100
22 1500 2850000 135700 3100
23 1500 2850000 135700 3100
24 1500 2850000 135700 3100
25 15tfo 2.8501)00 id'sKQQ 34^0
26 1500 2850000 133700 3100
27 1500 2850000 135700 3100
28 1500 2850000 13b700 3100
29 1500 2850000 13b700 3100
30 1500 2850000 1357QO 3100
TOT 57500 109250000 5202500 120000
LIFETIME AVERAGE INCREASE. (UtCHEASfc) IN UNIT OPERATING
DOLLARS HE* TON OF COAL dUMEU
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
UOLLARi PER TON OK SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.2* TO INITIAL YEAR. OOLLAHS
TONS/YEAR
DRY
SOLIDS
46300
46300
46300
46300
46300
32400
32400
32400
32400
J2400
13900
13900
13900
13900
139QO
13900
13900
13900
13900
13900
532500
COST
LEVtLIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER FUN OF COAL BURNED
MILLS PtR KILOwATT-hOUR
CENTS *>EH MILLION bTU HEAT INPUT
DOLLAR* PER TCN OF SULFUR REMOVED
NET HE VENUE.
S/TON
DRY
SOLIDS
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
TOTAL
OP. COST
INCLUDING
REGULATED
RUI FOR
POWER
COMPANY.
S/YEAR
10409000
10173000
9937000
9701000
9465000
8496800
8260800
8024800
77R8800
755280Q
6214500
5978500
5742500
5506500
5270^00
5034400
4798400
4562400
4326400
409p40p
141333500
27.17
12.29
129.37
1177.78
65007700
DISCOUNTED PROCESS COST OVER
24.79
11.21
118.03
1070.97
TOTAL
NET
SALES
REVENUE.
S/YEAR
0
0
0
0
0
0
0
0
0
f)
0
0
0
0
o
0
0
0
0
o
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
POrfER.
*
10409000
10173000
9937000
9701000
2ifi5fiim_
8496800
8260800
8024800
7788800
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
PO«ER<
S
10409000
20582000
30519000
40220000
£9g£5j)jgO
56181800
66442600
74467400
82256200
,1552900 89809000
6214500
5978500
5742500
5506500
5270500
5034400
4798400
4562400
4326400
40 9J) JJJ J}
141333500
27.17
12.29
129.37
1177.78
65007700
POWER UNIT
24.79
11.21
118.03
1070.97
96023500
102002000
107744500
113251000
) 1 P52 1 5 0 0
123555900
128354300
132916700
137243100
-H13335QO
-------
TABLE A-66. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case; 200 MW)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (two mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculatlon tanks,
agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal, slurry disposal pumps,
and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
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
1,529,000
2,233,000
403,000
1,857,000
3,827,000
564,000
1,212,000
11,625,000
698,000
12,323,000
2,236,000
14,559,000
1,040,000
240,000
2,264,000
735,000
4,279,000
3,768,000
22,606,000
2,037,000
2,713.000
27,356,000
451,000
564,000
28,371,000
($142/kW)
10.5
15.3
2.8
12.8
26.3
3.9
0.8
79.8
4.8
84.6
15.4
100.0
7.1
1.6
15.6
5.0
29.4
25.9
155.3
1.4
18.6
187.9
3.1
_JLil
194.9
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
237
-------
TABLE A-67. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REOUIREMENTS
(Variation from base case: 200 MW)
Direct Costs
Delivered raw materials
Limestone
Coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
52,910 tons
8,030 tons
23,830 man-hr
199,700 MBtu
97,800 kgal
21,790,400 kWh
10,300 MBtu
2,480 man-hr
Unit
cost, $
7.00/ton
25.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.031/kvm
2.00/MBtu
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
370,400
200,800
571,200
297,900
399,400
11,700
675,500
(20,600)
1,176,200
42,200
2,582,300
3,153,500
4.62
2.50
7.12
3.71
4.98
0.15
8.42
(0.26)
14.66
0.53
32.19
39.31
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 annual revenue requirements
1,641,400
2,439,900
758,200
29,800
4,869,300
8,022,800
20.46
30.41
9.45
0.37
60.69
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
$/MBtu heat
input
5.73
13.03
0.62
$/ton
S removed
565
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.
Sulfur removed, 14,210 short tons/yr; solids disposal 63,600 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $14,559,000; total depreciable investment, $27,356,000; and total
capital investment, $28,371,000.
All tons shown are 2,000 Ib.
238
-------
TABLE A-68
LIME .SLURRY PROCESS WITH CALCINATION VARIATION MOM BASE CASE: 200 M* REGULATED CO. ECONOMICS
TOTAL CAPITAL iKVEbTMtNT 26371000
NJ
UJ
YEARS
AFTER
POWER
UMT
START
1
2
3
4
5
6
7
8
9
JO
11
12
13
14
15
16
17
18
19
20
21
22
23
24
_£5
26
27
29
_3.fl
TOT
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
__1PJA_
7000
7000
7000
7000
__mai_
5000
5000
5000
5000
5. 00 0
3500
3500
3500
3500
__35flO_
1500
1500
1500
1500
1500.
1500
1500
1500
1500
1500
127500
LIFETIME
POWER UNIT
HEAT
REQUIREMENT,
MILLION 8TU
/YEAR
12880000
12880000
12880000
12880000
1288000J)
12880000
12880000
12880000
12880000
12880000
9200000
9200000
9200000
9200000
9200000
6440000
6440000
6440000
6440000
6,441)000
2760000
2760000
2760000
2760000
2760000
2760000
2760000
2760000
2760000
$760000
234600000
POKER UNIT
FUEL
CONSUMPTION*
TONS COAL
/YEAH
613300
613300
613300
613300
fe 1 33AQ
613300
613300
61330U
613300
613300
438100
438100
43S100
438100
43M100
306700
306700
306700
306700
3JJ6JD.O.
131400
131400
131400
131400
131400
131*00
131400
131400
131400
131400
11171000
AVERAGE 1NCKEASE (DECREASE)
DOLLARS
PER TON OK
SULFUR
REMOVEU
«Y
POLLUTION
CONTROL
PROCESS*
TONS/YEAR
14200
142(10
14200
14200
14^00
14200
14200
14200
14200
1*200
10200
10200
10200
10200
10?QD
7100
7100
7100
7100
710p
3000
3000
3000
3000
_ 3000
3000
3000
3000
3000
3QUO
25«bOO
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
DRY
SOLIOS
56600
56600
56600
56600
S6600
56600
56600
56600
56600
56,600
40400
40400
40400
40400
40400
28300
28300
26300
28300
2IJ300
12100
12100
12100
12100
12100
18100
12100
12100
12100
12100
1030500
NET REVENUE,
S/TON
DRY
SOLIOS
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
q.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY*
S/YEAR
10463600
10306800
10149900
9993100
9B3620Q
9679*00
9522500
9365700
9208800
9052000
8012800
7856000
7699200
7542300
7385500
6520800
6364000
6207100
6050300
5893400
4670300
4513400
4356600
4199700
4042900
3886000
3729200
3572300
3415500
3258700
206754000
TOTAL
NET
SALES
REVENUE.
S/YEAR
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER*
s
10463600
10306800
10149900
9993100
0 9836200
0
0
0
0
n,
0
0
0
0
9679400
9522500
9365700
9308000
9052000
8012800
7856000
7699200
7542300
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
*
10*6360(T
20770400
30920300
40913400
52X4.24 .00
60429000
69951500
79317200
88526000
975 7QQQ o
105590800
1134468OO
1211*6000
128688300
0 73855QD J36013800
0
0
0
0
o
0
0
0
0
i_
0
0
0
0
0
0
6520800
6364000
6207100
6050300
5893400
4670300
4513400
4356600
4199700
4J}4.220_fl_
3886000
3729200
3572300
3*15500
3258700
206754000
14259*600
1*8958600
155165700
16J216000
167109*00
171779700
176293100
1806*9700
184849400
_lfifi£3.£ AQ o
192778300
196507500
200079800
203495300
_ 20^754000
IN U'
-------
TABLE A-69. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500-MW existing)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
SOj absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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, $
2,604,000
3,698,000
668,000
5,095,000
9,014,000
1,308,000
1,778,000
24,165,000
1,450,000
25,615,000
3,583,000
29,198,000
1,653,000
386,000
4,065,000
1,247,000
7,351,000
7,310,000
43,859,000
4,028,000
5,263,000
53,150,000
722,000
1,167,000
55,039,000
($110/kW)
X of
total direct
investment
8.9
12.7
2.3
17.4
30.9
4.5
6.1
82.8
5.0
87.7
12.3
100.0
5.7
1.3
13.9
4.3
25.2
25.0
150.2
13.8
18.0
182.0
2.5
4.0
188.5
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
240
-------
TABLE A-70. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500-MW existing)
Direct Costs
Delivered raw materials
Limestone
Coal
Annual
quantity
132,280 tons
20,060 tons
Unit
cost, $
7.00/ton
25.00/ton
Total
annual
cost, $
926,000
501,500
% of average
annual revenue
requirements
5.71
3.10
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
37,670 man-hr 12.50/man-hr
1,427,500
470,900
8.81
2.91
499,200 MBtu
244,500 kgal
53,370,900 kWh
25,700 MBtu
4,700 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
998,400
29,300
1,547,800
(51,400)
2,156,700
79,900
5,231,500
6,659,000
6.16
0.18
9.56
(0.32)
13.32
0.50
32.31
41.12
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.42 of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, SOZ of conversion costs less utilities
Administrative, 10Z of operating labor
Total indirect costs
Total annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 4.63
3,401,600
4,733,400
1,353,800
47,100
9,535,900
16,194,900
$/ton coal $/MBtu heat
burned input
10.56 0.50
21.00
29.22
8.36
0.29
58.88
100.00
$/ton
S removed
456
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.
Sulfur removed, 35,530 short tons/yr; solids disposal 159,100 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $29,198,000; total depreciable investment, $53,150,000; and total
capital investment, $55,039,000.
All tons shown are 2,000 Ib.
241
-------
TABLE A-71
LIME SLURRY PROCESS WITH CALCINATION VARIATION FROM BASE CASE: 500 MM EXISTING REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 55039000
NJ
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION 6TU TONS COAL PROCESS, DRY
/YEAR /YEAR TONS/YEAR SOLIDS
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
I/TON ROI FOR NET
POWER SALES
DRY COMPANY, REVENUE,
SOLIDS S/YEAR S/YEAR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
S S
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Pfi
21
22
23
24
7000
7000
7000
7000
700D
5000
SOOO
5000
SOOO
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
26 1500
27 1500
26 1500
29 1500
Jp 1500
TOT 92500
LIFETIME
PROCESS COST
LEVELIZED
32200000
32200000
32200000
32200000
32200000
23000000
23000000
23000000
23000000
23000000
16100000
16100000
16100000
16100000
16100000
6900000
6900000
6900000
6900000
6900(100
6900000
6900000
6900000
6900000
6904000
1533300
1533300
1533300
1533300
1533300
1095200
1095200
1095200
1095200
1095200
766700
766700
766700
766700
766700
326600
328600
328600
328600
328600
328600
328600
328600
328600
328600
35500
35500
35500
35500
35500
25400
25400
25400
35*00
25400
17800
17800
17800
17800
17800
7600
7600
7600
7600
7600
7600
7600
7600
7600
7600
159100
159100
159100
159100
159100
113600
113600
113600
113600
113600
79600
79600
79600
79600
79600
34100
34100
34100
34100
34100
34100
34100
34100
34100
34100
425500000 20262000 469500 2102500
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
DISCOUNTED AT 11. 2* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT
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
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
10
.0
.0
.0
.0
• 0
.0
.0
.0
.0
• ft
.0
.0
.0
.0
.0
TO DISCOUNTED
21284300
20918600
20553000
20187300
19621600
17584600
17219000
16853300
16487600
16122000
14270800
13905100
13539400
13173800
12808100
10244300
9878700
9513900
9147300
8781600
8416000
8050300
7684600
7319000
6953300
340716600
16.82
7.37
80.07
725.70
140392600
PROCESS COST OVER
14.98
6.56
71.33
646.67
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
LIFE OF
0.0
0.0
0.0
0.0
21284300
20918600
20553000
20187300
19621600
17584600
17219000
16853300
16487600
16122000
14270800
13905100
13539400
13173800
12808100
10244300
9878700
9513000
9147300
8781600
8416000
8050300
7684600
7319000
6953300
340716600
16.82
7.37
80.07
725.70
140392600
POWER UNIT
14.96
6.56
71.33
646.67
21284300
42202900
62755900
82943200
10?764800
120349400
137568400
154421700
170909300
187031300
201302100
215207200
228746600
241920400
2541285J10
264972800
274651500
284364500
293511800
30?293400
310709400
318759700
326444300
333763300
910716600
-------
TABLE A-72. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2% sulfur)
7. of
total direct
Investment, $ investment
Direct Investment
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
1,637,000
2,383,000
430,000
4,102,000
7,909,000
1,218,000
1,260,000
18,939,000
1,136,000
20,075,000
2,481,000
22,556,000
1,614,000
383,000
3,290,000
1.025.000
6,312,000
5,774,000
34,642,000
3,216,000
4,157,000
42,015,000
501,000
891,000
43,407,000
($87/kW)
7.3
10.6
1.9
18.2
35.1
5.4
5.6
84.0
5.0
89.0
11.0
100.0
7.2
1.7
14.6
4.5
28.0
25.6
153.6
14.3
18.4
186.3
2.2
4.0
192.5
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
243
-------
TABLE A-73. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Direct Costs
Delivered raw materials
Limestone
Coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
59,540 tons
9,030 tons
33,750 man-hr
488,400 MBtu
202,800 kgal
49,082,500 kWh
11,500 MBtu
4,210 man-hr
Unit
cost, $
7.00/ton
25.00/ton
1 2 . 50/man-hr
2.00/MBta
0.12/kgal
0.029/kWh
2.00/MBtu
1 7 . 00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
416,800
225,800
642,600
421,900
976,800
24,300
1,423,400
(23,000)
1,680,400
71,600
4,575,400
5,218,000
3.31
1.79
5.10
3.35
7.75
0.19
11.30
(0.18)
13.34
0.56
36.31
41.41
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
Total indirect costs
Total annual revenue requirements
Equivalent unit revenue requirements
2,520,900
3,733,000
1,087,000
42,200
7,383,100
12,601,100
$/ton coal S/MBtu heat
Mills/kWh burned input
3.60 8.40 0.40
20.01
29.62
8.63
0.33
58.59
100.00
$/ton
S removed
785
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.
Sulfur removed, 16,050 short tons/yr; solids disposal 21,000 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,556,000; total depreciable investment, $42,015,000; and total
capital investment, $43,407,000.
All tons shown are 2,000 Ib.
244
-------
TABLE A-74
LIME SLURRY PROCESS WITH CALCINATION VARIATION FROH BASE CASE: 2.0% s REGULATED co. ECONOMICS
TOTAL CAPITAL INVESTMENT 43407000
Ln
YEARS ANNUAL
AFTER OPERA-
PO»ER TION.
UNIT KW-HR/
START KM
1 7000
2 7000
3 7000
4 7000
5 70QO
6 7000
7 7000
fl 7000
9 7000
ID 7000
11 SOOO
12 5000
13 5000
14 SOOO
}? 5000
16 3500
17 3500
18 3500
19 3500
2J 3500
21 1500
22 1500
23 1500
24 1500
•ft 1500 .
26 1500
27 1500
28 1500
29 1500
1p 1500
TOT 127500
SULFUR
REMOVED
POKER UNIT POncK UNIT BY
MEAT FUEL POLLUTION
REQUIREMENT. CONSUMPTION. CONTROL
MILLION BUI TONS COAL PROCESS.
/YEAH /YEAH TONS/YEAH
31500000 1500000 16100
31500000 IbOOOOO 16100
31500000 1500000 16100
31500000 1500000 16100
31500000 1SOOOOO 16100
31500000 IbOOOOO 16100
31500000 IbOOOOO 16100
31500000 1500000 16100
31500000 1500000 16100
315000pO ISQOQOO 16,100
22500000 1071400 11500
22500000 1071400 11500
22500000 1071400 11500
22500000 1071400 11500
22500000 1071400 H^OO
15750000 TbuOOO «000
15750000 750000 HOOO
15750000 750000 BOOO
15750000 750000 eOOO
15750000 7SOOOO 8000
6750000 321400 3400
6750000 321400 3400
6750000 321400 3400
6750000 321400 3400
6750000 321400 ^»00
6750000 321400 3400
6750000 321400 3400
6750000 321400 3400
6750000 321400 J400
6750000 32140.0 3400
573750000 27J21000 292500
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
DRY
SOLIDS
21000
21000
21000
21000
?1PQ4
21000
21000
21000
21000
2)000
15000
15000
15000
15000
15000
10500
10500
10500
10500
10500
4500
4500
4500
4500
4500
4500
4500
4500
4500
4500
382500
NET REVENUE.
S/TON
DRY
SOLIDS
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
q.o
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
TOTAL
OP. COST
INCLUDING
REGULATED
901 FOR
POWER
COMPANY.
S/YEAR
16335500
16094600
15853700
15612800
15372gop
15131100
14890200
14649300
14408400
14167500
12460700
12219900
11979000
11738100
11497200
10091100
9850200
9609300
9368500
9127600
7158500
6917600
6676700
6435800
6194900
5954100
5713200
5472300
5231400
4990500
321201700
TOTAL
NET
SALES
REVENUEi
S/YEAR
0
0
0
0
g
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4L
0
0
0
0
p
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
%
16335500
16094600
15853700
15612800
15372000
15131100
14890200
14649300
1440S400
1*1675.00
12460700
12219900
11979000
11738100
11497200
10091100
9850200
9609300
9368500
9127600
7158500
6917600
6676700
6435800
6194900
5954100
5713200
5472300
5231400
4990500
321201700
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
%
16335500
32430100
4B283800
63896600
2224££J)0
94399700
109289900
123939200
130347600
1525}5100
164975800
17719S70J)
189174700
20P912800
212410000
222501100
232351300
241960600
25J329100
260456700
267615200
274532800
281209500
287645300
_2£344.J|j>j)0
299794300
305507500
310979800
316211200
321201700
LIFETIME AVERAGE INCREASE (Dl-CREASE) IN UNIT OPERATING COST
PROCESS COST
LEVELIZEO
DOLLARS HER TON OF COAL BORNEO
HILLS PER KILOwATT-HOUR
CENTS PtR MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.2* TO INITIAL YEAH. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION dTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
11.76
5.04
55.98
1098.13
117199000
DISCOUNTED PROCESS COST OVER
10.74
4.60
51.16
1001.70
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
11.76
5.04
55.98
1098.13
117199000
POWER UNIT
10.74
4.60
51.16
1001.70
-------
TABLE A-75. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
% of
total direct
Investment, $ 1 nvestment
Direct Investment
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans.
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
SC>2 absorption (four mobile-bed scrubbers Including presatu-
rator and entralnment separators, recirculation tanks.
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
Cont ingency
Total fixed Investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
2,570,000
3,654,000
660,000
4,318,000
8,504,000
1,282,000
1,616,000
22,604,000
1,356,000
23,960,000
4,505,000
28,465,000
1,683,000
389,000
3,944,000
1.223,000
7,239,000
7,141,000
42,845,000
3,834,000
5,142,000
51,821,000
909,000
1,130,000
53,860,000
($108/kW)
9.0
12.8
2.3
15.2
29.9
4.5
5.7
79.4
4.8
84.2
15.8
100.0
5.9
1.4
13.8
4.3
25.4
25. 1
150.5
13.5
18.1
182.1
3.2
4.0
189.3
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basts
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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FCD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
246
-------
TABLE A-76. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Direct Costs
Delivered raw materials
Limestone
Coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
129,400 tons
19,630 tons
37,670 man-hr
488,400 MBtu
235,600 kgal
52,224,800 kWh
25,100 MBtu
4,700 man-hr
Unit
cost, $
7.00/ton
25.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2 . 00/MBtu
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
905,800
490,800
1,396,600
470,900
976,800
28,300
1,514,500
(50,200)
2,052,000
79,900
5,072,200
6,468,800
5.83
3.15
8.98
3.03
6.28
0.18
9.73
(0.32)
13.19
0.51
32.60
41.58
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 annual revenue requirements
3,109,300
4,631,900
1,301,400
47,100
9,089,700
15,558,500
19.98
29.78
8.36
0.30
58.42
100.00
Equivalent unit revenue requirements
Mills/kWh
4.45
$/ton coal
burned
S/MBtu heat
input
10.37
0.49
$/ton
S removed
448
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.
Sulfur removed, 34,750 short tons/yr; solids disposal 153,600 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $28,465,000; total depreciable investment, $51,821,000; and total
capital investment, $53,860,000.
All tons shown are 2,000 Ib.
247
-------
TABLE A-77
LIME- SLURRY PROCESS «ITH CALCINATION BASfc CASE: 500 M« 3.5* S REtoULATEU CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 6366oooo
co
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KM-HR/
START KH
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
10 7Q°0
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
2ft 3SOO
21 1500
22 1500
23 1500
24 1500
?
-------
TABLE A-78. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5% sulfur)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks.
agitators, and pumps)
Stack gas reheat (four Indirect steam reheaters)
Solids disposal (onsite disposal, 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
Construccion 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
3,300,000
4,630,000
836,000
4,318,000
8,504,000
1,282,000
1,907,000
24,777,000
1,487,000
26,264,000
6,318,000
32,582,000
1,735,000
395,000
4,368,000
1,356,000
7,854,000
8,087,000
48,523,000
4,220,000
5,823,000
58,566,000
1,277,000
1,344,000
61,187,000
($122/kH)
10.1
14.2
2.6
13.3
26.1
3.9
5.9
76.0
4.6
80.6
19.4
100.0
5.3
1.2
13.4
4.2
24.1
24.8
148.9
13.0
17.8
179.7
3.9
4.2
187.8
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
249
-------
TABLE A-79. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Direct Costs
Delivered raw materials
Limestone
Coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
199,040 tons
30,190 tons
40,460 man-hr
488,400 MBtu
275,000 kgal
55,356,700 kWh
38,600 MBtu
5,050 man-hr
Unit
cost, $
7.00/ton
25.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,393,300
754,800
2,148,100
505,800
976,800
33,000
1,605,300
(77,200)
2,290,700
85,900
5,420,300
7,568,400
7.81
4.23
12.04
2.84
5.48
0.18
9.00
(0.43)
12.84
0.48
30.39
42.43
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, D0% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
3,514,000
5,262,100
1,441,200
50,600
10,267,900
17,836,300
19.70
29.50
8.08
0.29
57.57
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
$/MBtu heat
input
5.10
11.89
0.57
$/ton
S removed
332
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.
Sulfur removed, 53,730 short tons/yr; solids disposal 238,700 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $32,582,000; total depreciable investment, $58,566,000; and total
capital investment, $61,187,000.
All tons shown are 2,000 Ib.
250
-------
TABLE A-80
LIME 'SLURRY PROCESS "ITH CALCINATION VARIATION FROK BASE CASE: 5.0* S REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 61187000
NJ
m
SULFUR BY-PRODUCT
REMOVED RATEt
YEARS ANNUAL POKER UNIT PG«ER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POKER TION* REQUIREMENT. CONSUMPTION. CONTROL
UNIT K»-HR/ MILLION tfTU TONS COAL PROCESS* DRY
START K»
1
2
3
4
5
6
7
8
9
10
11
12
13
14
lj
16
17
18
19
2Q
21
22
23
24
25
26
27
26
29
30
TOT
7000
7000
7000
7000
7OOO
7000
7000
7000
7000
7000
5000
5000
SOOO
SOOO
-5JU2JL.
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
127500
LIFETIME
PROCESS COST
LEVELIZEO
/YEAR /YEAR TONS/YEAR SOLIDS
31500000 IbOOOOO 53700
31500000 1500000 53700
31500000 IbOOOOO 53700
31500000 1500UOO 53700
3|^ouag() J5UOOOO 5.3700
31500000 1500000 S3700
31500000 1500000 5370U
31500000 1500000 5370U
31500000 IbOOOOO 53700
3150UOOO isqoooo 53700
22500000 1071400 3*400
22500000 1071400 38*0b
22500000 1071400 38400
22500000 1071400 38400
225011000 1U71400 3jj}^0
15750000 750000 26900
15750000 750000 26900
15750000 750000 26S>00
15750000 750000 26901)
15.J50000 750000 2690D
6750000 321400 llbOO
6750000 321400 11500
6750000 321400 11SOO
6750000 321400 11500
6754000 321400 llbOD
6750000 321400 11500
6750000 321400 11500
6750000 321400 11500
6750000 3dl400 llbOU
675J1000 321400 1J500
573750000 27321000 9T8bOU
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF COAL BUKNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION bTU MEAT INPUT
UOLLARb PEH TON OF SULFUR REMOVEU
DISCOUNTED AT 11.2* TO INITIAL YEAR. DOLLARS
238700
238700
238700
238700
238700
238700
238700
238700
238700
238700
170500
170500
170500
170500
170500
119400
119400
119400
119400
119400
51200
51200
51200
51200
51200
51200
51200
51200
51200
51200
4348500
COST
INCREASE (DECREASE) IN UNIT OPERATING COST tuUIVALENT TO
DOLLARS PtR TON UF COAL HORNED
MILLS PER K1LOKATT-HOUR
CENTS PER MILLION dTU HtAl INPUT
DOLLARS PER TON Oh SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE* REGULATED
S/TON ROI FOR
POKER
DRY COMPANY*
SOLIDS S/YEAR
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
p.o
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
p.o
DISCOUNTED
23100300
22764500
22428700
22092900
21757200
21421400
21085600
20749800
20414000
200J8300
17613100
17277300
16941500
16605700
16270000
14249900
13914100
13578300
13242600
12906800
10094400
9758600
9422800
9087100
8751300
8415500
8079700
7743900
7408200
7072400
454325900
16.63
7.13
79.19
464.31
16S621300
PROCESS COST OVER
15.20
6.51
72.38
424.53
TOTAL
NET
SALES
REVENUE*
S/YEAR
0
0
0
0
g
0
0
0
0
p
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER* POWER*
S
23100300
22764500
22428700
22092900
21757200
21421400
21085600
20749800
20414000
20Q78300
17613100
17277300
16941500
16605700
16270000
14249900
13914100
13578300
13242600
$
23100300
45864800
68293500
90386*00
^ ^ 214360 0
133565000
154650600
175400400
195814400
21589270 0
233505804
250783100
267724600
284330300
30P600300
314850200
328764300
342342600
355585200
1290.6900 368492000
10044400
9758600
9422800
9087190
378586400
388345000
397767800
406854900
8751300 415606200
8*15500
8079700
7743900
7408200
424021700
438101400
439845300
447253500
7QI?4.00 454325900
454325900
16.63
7.13
79.19
464.31
165821300
POWER UNIT
15.20
6.51
72.38
424.53
-------
TABLE A-81. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000-MW existing)
Z of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
3,843,000
5,350,000
966 , 000
8,679,000
13,606,000
2,026,000
2,262,000
36,732,000
2,204,000
38,936,000
6,203,000
45,139,000
1,732,000
394,000
5,814,000
1,737,000
9,677,000
10,963,000
65,779,000
5,958,000
7,894,000
79,631,000
1,238,000
1,943,000
82,812,000
($83/kW)
8.5
11.9
2.1
19.2
30.2
4.5
5.0
81.4
4.9
86.3
13.7
100.0
3.8
0.9
12.9
3.8
21.4
24.3
145.7
13.2
17.5
176.4
2.7
4.4
183.5
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process Invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
252
-------
TABLE A-82. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000-MW existing)
Direct Costs
Delivered raw materials
Limestone
Coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
258,810 tons
39,250 tons
53,270 man-hr
976,700 MBtu
478,400 kgal
103,849,600 kWh
50,200 MBtu
7,630 man-hr
Unit
cost, $
7.00/ton
25.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
2.00/MBtu
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,811,700
981,300
2,793,000
665,900
1,953,400
57,400
2,907,800
(100,400)
2,911,600
129,700
8,525,400
11,318,400
7.12
3.85
10.97
2.62
7.67
0.22
11.42
0.39
11.44
0.51
33.49
44.46
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, 5014 of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Equivalent unit revenue requirements
5,096,400
7,121,800
1,853,600
66,000
14,137,800
25,456,200
$/ton coal $/MBtu heat
Mills/kWh burned input
3.64 8.49 Q.40
20.02
27.93
7.28
0.26
55.54
100.00
$/ton
S removed
366
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, 2,999,900 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Sulfur removed, 69,490 short tons/yr; solids disposal 307,200 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $45,139,000; total depreciable investment, $79,631,000; and total
capital investment, $82,812,000.
All tons shown are 2,000 Ib.
253
-------
TABLE A-83
LIME" SLUWHY PHOCESS KITH CALCINATION VAHIATIUN FKUM bASt CASE: l.GOO "tn EXISTING REGULATED CO. ECONOMICS
TOF«L CAPITAL INVESTMENT H2812000
NS
Ui
SULFUH HY-HrtOOUCT
KEWOVEO «ATh«
YEARS ANNUAL POtiEH UNIT PunLH UNIT «Y EQUIVALENT
AFTER OPERA- MEAT I-UEL POLLUTIUN TONS/YEAR
POWER TION» HEUUIHE«ENT» CUNSUMP1 !<>*• CONTnOL
UMT KW-Hf/ MILLION isTU TONS COAL PKOCtSSi U*Y
START K" XYEAN /Yt»« TONS/YEAH SULIUS
1
2
3
4
__5.
6
7
B
9
ll"
12
13
14
16~
17
10
19
21~
22
23
24
26
27
28
29
3S
7000 63000000 JUOOOOO 6950U
7000 63000000 3UUOOOO 69=>00
7000 63000000 JUOOOOO 69500
7000 63000000 JUUOOOO 69bOU
7QOO 6300000P JlJUOOno 69bOO
5000 450000UO 2142900 49bOO
5000 45000000 2142SOO 4^600
5000 45000000 2142900 49600
5000 45000000 214^900 49600
3500 31500000 ibOOOOO 34700
3500 31500000 1300000 3470U
3500 JlSuuOUO 1900UOO 347UO
3500 31500000 1500000 34700
3500. 3150L>p00 l^OOQfiO 34700
1500 13500000 6«29QO 14900
1500 13500000 642400 14900
1500 13500000 6429QU 14900
1500 13500000 642900 14900
1500 1350UOOO 642900 14900
1500 13500000 642900 14900
1500 135UOOUO 642900 14900
15tO 13500000 642900 14900
15(10 13500000 64290U 14900
307?00
307200
307200
307200
219400
219400
219400
21V400
153600
153600
153600
153600
65800
6530U
65800
65MOO
65dOO
65800
65800
65800
65800
TOT 92500 BJ2500000 39643500 910000 4059000
LIFETIME AVERAGE INCREASE (UtCHEASt) IN UNIT OPEKATING COST
DOLLAKb PEH TON OF COAL BURNED
MILLS P£x KILOnATT-HUUR
CENTS PEH MILLION 8TU HEAT INPUT
OOLLAhi PEH TON' OF SULFUH REMOVED
PROCESS COST DISCOUNTED AT 11.2* To INITIAL fEAftt UOLLAHS
LEVELIZED INCREASE (OECXtASt) tN UiMlT OPERATING COST EuUIVALENT TO
OOLLArtS PEW TON OK COAL SUrtNED
MILLS PEK MLOWATT-HOUR
CENTS PErt MILLION 8TU HEAT INPUT
UOLLAHS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NtT HEVENUtf HEGULATEO
t/TOM HOI FOH
POWER
DHY COMPANY.
SOLIDS S/YEAR
0.0 33112200
0.0 32564300
0.0 32016500
0.0 31468600
0.0 30920700
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
q.o
0.0
0.0
0.0
0.0
0.0
DISCOUNTED
27179400
26631500
26083700
25535800
?4?88000
21932500
21384700
20836800
20289000
19741100
15554600
15006800
14458900
13911100
13363200
12815400
12267500
11719700
11171800
5fe5577800
13.26
5.68
63.13
572.52
217588900
PROCESS COST OVER
11.87
5.09
66.50
512.34
NET ANNUAL
TOTAL INCREASE
NET (DECREASE)
SALEb IN COST OF
REVENUE. POWER*
S/YEAH «
0 33112200
0 32564300
0 32016500
0 31464600
$ 30920700
0
0
0
0
fl
0
0
0
0
0
0
0
0
0
p_
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
27179400
26631500
26083700
25535800
24988000
21932500
21384700
20836800
20289000
19741100
15554600
15006800
14458900
13911100
13363200
12815400
12267500
1171970D
11171800
10.62,4000
525577800
13.26
5.68
63.13
572.52
217584900
POWER UNIT
11.87
5.09
56.50
51?. 34
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER »
S
33112200
65676500
97693000
129161600
l6.flM2i?J)0
1872617-00
213893200
239976900
265512700
__22.S5Jlfil.OO
312433200
333817900
354654700
374943700
3S46J4JJ10
410239400
425246200
439705100
453616200
479794800
492062300
503782000
514953600
-------
TABLE A-84. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins., shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including preaatu-
rator and eotrainment separators, recirculation tanks.
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, slurry disposal pumps,
and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total proctss areas excluding pond construction
Pond construction
Total direct Investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
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
3,768,000
5,251,000
948,000
7,125,000
12,501,000
1,872,000
2,052,000
33,517,000
2,011,000
35,528,000
7,678,000
43,206,000
1,772,000
398,000
5,547,000
1,680,000
9,397,000
10,521,000
63,124,000
5,545,000
7,575,000
76,244,000
1,558,000
^865,000
79,667,000
($80/kW)
8.7
12.2
2.2
16.5
28.9
4.3
4.7
77.6
4.7
82.2
17.8
100.0
4.1
0.9
12.8
3.9
21.7
24.4
146.1
12.9
17.5
176.5
3.6
4.3
184.4
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FCD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay Incentive not considered.
255
-------
TABLE A-85. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW)
Direct Costs
Delivered raw materials
Limestone
Coal
Annual
quantity
250,200 tons
37,900 tons
Unit
cost, $
7.00/ton
25.00/ton
Total
annual
cost, $
1,751,400
947,500
% of average
annual revenue
requirements
7.26
3.93
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
53,270 man-hr 12.50/man-hr
944,200 MBtu
517,600 kgal
100,406,200 kWh
48,500 MBtu
7,630 man-hr
2,698,900
665,900
11.19
2.76
2.00/MBtu
0.12/kgal
0.028/kWh
2.00/MBtu
17.00/man-hr
1,888,400
62,100
2,811,400
(97,000)
2,717,300
129,700
8,177,800
10,876,700
7.83
0.26
11.65
(0.40)
11.26
0.54
33.90
45.09
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
Total indirect costs
Total annual revenue requirements
4,574,600
6,851,400
1,756,500
66.600
13,249,100
24,125,800
18.96
28.40
7.28
0.27
54.91
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
3.45
8.32
$/MBtu heat
input
0.40
$/ton
S removed
363
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.
Sulfur removed, 66,540 short tons/yr; solids disposal 297,000 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $43,206,000; total depreciable investment, $76,244,000; and total
capital investment, $79,667,000.
All tons shown are 2,000 Ib.
256
-------
TABLE A-86
Lint <;LURHY
»ITM t«LCi-.*.iiJi" VAHIAHOW »-KU*,
T-JTaL C
CASE: i.ooo H»» *E
Ui
YEARS ANNUAL pome* UMT
AFTER OREkt- utaT
POWER TION. KtUUlKti*tNT »
U*IT K«-H*/ MILL10» HTU
STArtT Kn /It.kf
1 7000 60400000
2 7000 6040000,0
3 7000 bo9ol/000
4 7000 oi)400ul)0
5 7000 bU^UUOuO
6 7000 bU4UOOUO
7 7000 b090oUO<>
10 7000 6JVOJUUO
11 5000 4330oOuo
12 5000 4*300000
13 5000 43bOOOOO
14 5000 43300000
15 50Q.G, 4i3uoGu(j
16 350u 30»boDUO
17 3500 J04aOuOO
IB 3500 30fbi)0i)0
19 3500 304boOUO
20 3500 3*)4bOOOO
21 150(j 1303uOOO
22 1500 130300UO
23 1500 13030000
24 1500 iJObUOOO
?5 15pp IjuSouPO
26 1500 1303oi)i!0
27 1500 13030000
28 1500 UObooitO
29 1500 1*030000
o/j 1500 i J jJbo UjjO
TOT 127500 11092301)00
bULFUK
^EixO«trJTIO00.0 i^fc^OO
fu/ltOO 47SOO
^071*00 47300
2U71400 473UO
2071»00 47500
<';?4;i.ioo )33uo
li5Ulj(;U 33300
fidltOO 143UI)
nidl»0o 1430U
ntltUU 14JUO
oi?l400 1»3UO
?jj;J»iii) IftJOO
•321*00 1430U
S£:i«00 If30b
tiil»OO 1-fJUU
cirl»'JO 1*300
^^l^pO If 300
3£olltiGU 1»U
LIFETIME AVEHAbt !<\CwtMbt U>tC*tASt) IN UNIT I'PtHATIr
UULLAHb
MlLLi H
Cfc".Tb K
L/OLLf.HIb
PwOCESS COST OISCUUt.Ttl/ «T
LEVELI2EO IiMCKtAbt (litt«
tiULLAhs
rcK T'jfv 0»- CUAL 1U*'it.i>
t« nILO <4 FT-MUUK
t« -ILL ION OTU nt«T IftiKUT
''Er* T0'< Oh SULFU" «tMO»tU
KATE.
EUU1VALENT
TOMS/YEAK
OHY
SOL I OS
247000
297000
247000
297006
2970UO
247000
297000
297000
247000
2970QO
212100
212100
212100
212100
2JgJO}
146500
14U500
14^300
14BSOO
14*SOO
636UO
63600
6 J600
63600
bjb'JO
63000
63600
6.1600
63bOO
636 00
340VOOO
»vj COST
mtT Kt^ENU
*/TON
OMY
bOLIOS
0.0
0.0
0.0
4.0
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
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
!!.«:* TO INITIAL rtorf. OOLLA^S
tA3C) 1»< UivIT iiftHATlNb COST
Pt« -TUN OH CUAL MUKntO
MviJI VALfT TU
OiSCOUNTEO
flLLb t-ttt HlLu»4t I-HOUX
>;t^T•5 P
OULLAxs
23 0
0 11091700 566847400
0 10644500 577492400
0 10207400 587699HOO
0 9770300 597470100
^L 9333JHU 6068JJ32DO
0 606803200
0.0 11.49
0.0 4.76
0.0 54.70
0.0 500.66
0 222326600
LIFE OF PO«E« UNIT
0.0 10.54
0.0 4.37
0.0 50.20
0.0 459.64
-------
TABLE A-87. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% SO removal)
I of
total direct
Investment, $ Investment
Direct Investment
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, waste heat boilers, and elevators)
Feed preparation (feeders, slaker, 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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal, 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
2,773,000
3,925,000
709,000
4,318,000
8,504,000
1,282,000
1,713,000
24,617,000
1,393,000
29,617,000
5,001,000
29,618,000
1,698,000
391,000
4,064,000
1,261,000
7,414,000
7,406,000
44,438,000
3,944,000
5,333,000
53,715,000
1,009,000
1,186,000
55,910,000
(S112/kW)
9.4
13.3
2.4
14.6
28.6
4.3
5.8
78.4
4.7
83.1
16.9
100.0
5.7
1.3
13.7
4.3
25.0
25.0
150.0
13.3
18.1
181.4
3.4
4.0
188.8
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
258
-------
TABLE A-88. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% removal)
Direct Costs
Delivered raw materials
Limestone
Coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
147,420 tons
22,360 tons
37,670 man-hr
488,400 MBtu
247,800 kgal
53,035,000 kWh
28,600 MBtu
4,700 man-hr
Unit
cost, $
7.00/ton
25.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,031,900
559,000
1,590,900
470,900
976,800
29,700
1 ,538,000
(57,200)
2,119,400
79,900
5,157,500
6,748,400
6.38
3.46
9.84
2.91
6.04
0.18
9.53
(0.35)
13.12
0.49
31.91
41.76
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 annual revenue requirements
3,222,900
4,808,300
1,335,100
47.100
9,413,400
16,161,300
19.94
29.75
8.26
0.29
58.24
100.00
Equivalent unit revenue requirements
S/ton coal $/MBtu heat $/ton
Mills/kWh burned input _ _S removed
4.62
10.78
0.51
406
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.
Sulfur removed, 39,800 short tons/yr; solids disposal 177,800 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $29,618,000; total depreciable investment, $53,715,000; and total
capital investment, $55,910,000.
All tons shown are 2,000 Ib.
259
-------
TABLE A-89
LINE SLURRY PROCESS «ITH CALCIfi«TlUix VAK1ATIOK FMOw bAbt C«SE: *0* REMOVAL REGULATED CO. ECONOMICS
ToT«L CAPITAL I«iVtbTwtf
o
YEARS ANNUAL
AFTER OPERA-
POtER TION.
UNIT Kn-HH/
START Kt>
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
IQ 700P
11 5000
12 6000
13 5000
14 5000
1§ 5000
16 3500
17 3SOO
16 3500
19 3500
20 35.00.
21 1500
22 1500
£3 1500
24 1500
£5 1500
26 1500
27 1500
28 1500
29 1500
30. )500
TOT 127500
LIFETIHE
PROCESS COST
LEVEL IZED
bULFoi<
KtuOVtU
POrfER UNIT PUwtR UnlT BY
MEAT FUEL i ' POLLUTION
HE.yuIKt.KtNT. CU(\b JbOOGOO frZtiV
223000UO 107140U 2b4UO
22bOOOOO 1071400 2o40u
22500000 1071400 2B40G
22500000 1071400 24«i)0
/»2SOUOOO >l7^0p 2»40U
1575UOOO 760000 194UO
15750000 730000 144UO
13750000 750000 lv*00
Ib7bu000 750000 14900
1575uOnft 750000 1940U
6750000 3el4UO O500
075UOOO 3
HILLS PtR K1LO*ATT-HOUK
CENTS PEN MILLION bTU HEAT INPUT
DULLAHb PCK TON OF SULFUH rltcOVtU
EUUIVALENT
TO DISCOUNTED
15.10
6.47
71.89
S69.35
1S0492HOO
0.0
0.0
0.0
0.0
0
PMUCESS COST OVER LIFE OF
13.80
5.91
65.69
520.02
0.0
0.0
0.0
0.0
15.10
6.47
71.89
569.35
150492800
POWER UNIT
13.80
5.91
65.69
520.02
-------
TABLE A-90. LIME SLURRY PROCESS WITH CALCINATION
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
Investment, $
% of
total direct
investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevators,
bins, shaker, puller, and mobile equipment)
Limestone calcination (feeders, crusher, ball mill, fans,
bins, rotary kiln, dust collectors, waste heat boiler, and
elevators)
Feed preparation (feeders, slakers, dust collector, 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 reheater and stack)
S02 absorption (four mobile-bed scrubbers including presatu-
rator and entrainment separators, recirculation tanks,
agitators, and pumps)
Stack gas reheat (four direct oil reheaters)
Solids disposal (onsite disposal, 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
1,599,000
2,100,000
420,000
4,448,000
7,994,000
731,000
1,357,000
18,649,000
1,119,000
19,768,000
2,482,000
22,250,000
1,326,000
311,000
3,252,000
1,014,000
5,903,000
5,631,000
33,784,000
3,130,000
4,054,000
40,968,000
497,000
926,000
42,391,000
($85/kW)
7.2
9.4
1.9
20.0
35.9
3.3
6.1
83.8
5.0
88.8
11.2
100.0
6.0
1.4
14.6
4.5
26.5
25.3
151.8
14.1
18.2
184.1
2.2
4.2
190.5
Basis
Evaluation 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 mile from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process invest-
ment estimate begins with common feed plenum downstream of the ESP.
261
-------
TABLE A-91. LIME SLURRY PROCESS WITH CALCINATION
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Direct Costs
Delivered raw materials
Limestone
Fuel oil
Annual
quantity
57,040 tons
1,048,600 gal
Unit
cost, $
7.00/ton
0.40/gal
Total
annual
cost, $
399,300
419,400
% of average
annual revenue
requirements
3.12
3.28
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Oil
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
36,040 man-hr 12.50/man-hr
818,700
450,500
2,872,900 gal
176,600 kgal
41,962,100 kWh
4,500 man-hr
0.40/gal
0.12/kgal
0.029/kWh
17.00/man-hr
1,149,200
21,200
1,216,900
1,655,900
76,500
4,570,200
5,388,900
6.40
3.52
8.98
0.17
9.51
12.94
0.60
35.72
42.12
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4£ 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, 107. of operating labor
Total indirect costs
Total average annual revenue requirements
2,622,000
3,645,600
1,091,500
45.100
7,404,200
12,793,100
20.50
28.50
8.53
0.35
57.88
100.00
$/bbl oil $/MBtu heat S/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements
3.66
2.39
0.40
860
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.
Sulfur removed, 14,880 short tons/yr; solids disposal 65,570 tons/yr calcium solids including
only hydrate water.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,250,000; total depreciable investment, $40,968,000; and total
capital investment, $42,391,000.
All tons shown are 2,000 Ib.
262
-------
TABLE A-92
u>
Hwt SLIMHY HwOCtbs »ITH CALCINATION I/AH I AT ION r-«0.- Ttbt CASE: '(IL-K lnc.!)« MISTING ^FSULATFO CO. ECONOMICS
TulAL CAPITAL ItwtsT'lLK f 42391000
YtAKS ANMUAL «c»tK UMT
AFTtW OHEKA- 1-ltAT
POUtW I ION. HEUUInt«t.»jT«
UMT Md-HK/ i-'ILLlO'V r-TU
STAMT Kfc /rtun
!-<:••• KH u »I f
f-uKL
Ht^Ol/tU
PULLUHO.-J
CONTROL
TuuS/YFA"
S Oil
•MY
SOL I US
TOTAL
OP. COST
I'lCL.Ul)I'>"3 NET AMNlUL CUHULATIVI;:
HnioLATRu TOTAL iNC*e»st ^.ST tMC^EAst
r<01 i-u" NET (DECREASE) (OECxeASE)
•''IKES SALfb IN COST OF le, COST OF
COnPA^Yi h£VEN(JF« fO*F9« PO»E><«
S/YEAi< */YKA« % t
16711-3(10
331*1100
44?*4riMnO
6515*700
1M47700
13787500
13505600
10S031SGO
121255600
134197500
lb«034100
1033100:)
--UM492.i)JJ-
7^-11*00
LIFETIME AVErtAbt
PROCESS COST
LE/ELI/f.C
DULL Arts
OlSCOUf ffcU Af
IwCxKaSt ('.)tC«t «Sr. ) I
DO iv^ouu oo6b()00
(urC-^tAbt) IN Ur-il f UHtKATIMj CObT
t-c" -!"«~tL uh OIL oo«'«tU
* <\1LU*A Tl -hou«
« -'ILLlOrj nTU nt»T I.XPU"!
*Er TUM or SULKU^i «t»UVtu
11. £< 1C iMTliL Yt*^« uOLL««-,
3.MO
5.7X
62.78
1362.92
110177900
Ct'-fi ft
E'«')IVALt«T TO UISCOUNTED PHOCESS COST OVFV
< ")»>;.«tu Of OIL ^i.:«vti; 3.39
>1L(..." ir-Huo« 5.15
••ILL !').< nTu rtt'it 1--.-U1 55.9H
« )'.,» Of SouFo- t.r-1'.vtu 1216. D9
17^5»17 )U
149H72700
_a999_il9jO
207911100
?15618dOO
2230*4500
243630400
255945100
261679700
.26713^*50
-------
TABLE A-93. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200-MW existing)
Z of
total direct
Investment, $ investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 (two spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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
406,000
187,000
2,063,000
2,380,000
531,000
2,229,000
623,000
3,587,000
1,216,000
3,282,000
582,000
17,086,000
1,025,000
18,111,000
65,000
18,176,000
1,313,000
326,000
2,781,000
870,000
5,290,000
4,693,000
28,159,000
2,810,000
3,379,000
34,348,000
15,000
756,000
35,119,000
($176/kW)
2.2
1.0
11.4
13.1
2.9
12.3
3.4
19.7
6.7
18.1
3.2
94.0
5.6
99.6
0.4
100.0
7.2
1.8
15.3
4.8
29.1
25.8
154.9
15.5
18.6
189.0
0.1
4.1
193.2
Basis
Evaluation 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 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.
264
-------
TABLE A-94. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200-MW existing)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, S
Total
annual
cost, $
% of average
annual revenue
requirements
620 tons
760 liters
1,370 tons
30,000 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
186,000
1,900
20,600
208,500
375,000
2,654,000 gal
212,600 MBtu
996,100 kgal
26,419,000 kWh
57,300 MBtu
4,480 man-hr
0.40/gal
2.00/MBtu
0.12 /kgal
0.031/kWh
2.00/MBtu
17.00/man-hr
1,061,600
425,200
119,500
819,000
(114,600)
1,450,800
76,200
4,212,700
4,421,200
1.90
0.02
0.21
2.13
3.82
10.82
4.34
1.22
8.35
(1.17)
14.79
0.78
42.95
45.08
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
Marketing, 10% of byproduct sales revenue
Total Indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 45,600 tons
Net annual revenue requirements
Equivalent unit revenue requirements
2,404,400
3,020,200
951,000
37,500
114,000
6,527,100
10,948,300
25.00/ton (1,140,000)
9,808,300
$/ton coal $/MBtu heat
Mills/kWh burned input
7.01 15.48 0.74
24.51
30.79
9.70
0.38
1.16
66.54
111.62
(11.62)
100.00
$/ton
sulfur
removed
669
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.
Sulfur removed, 14,670 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $18,176,000; total depreciable investment, $34,348,000; and total
capital investment, $35,119,000.
All tons shown are 2,000 Ib.
265
-------
TABLE -
MAGNESIA PROCESS VARIATION F*C« r«Atik C»^ff: 200 M« tXIsTlMb rttbULATEO CO. ECONOMICS
TOTAL CAKJTAL iNVtSTMENI 3511*000
NJ
YEARS ANNUAL
AFTER OPERA-
POtoER TION.
UNIT 'Kto-HP/
START KW
SULFU* HY-PHUOUCT
KEMUVED KATE.
POKER UNIT POWFK UiMiT BY EUUlVALENT
HEAT FUEL POLLUTION TONS/ttAH
REQUIREMENT* CONSUMPTION. CONTROL
MILLION 8TU TONS COAL P»OCEbS» 100*
/YEAR /YEAH' TONS/YtAri SULFUKIC ACID
TOTAL
OP. COST
INCLUDING
NtT KEVENUE. KEGULATEO TOTAL
S/TON f(OI FOR NET
POWER SALES
lOOt COMPANY* HEVENUEt
SULfUrtIC ACIU S/YEAR S^YEAR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER t POKER t
S S
1
2
3
4
5
b
7
S
9
IP
11 5000
12 5000
13 5000
14 5000
IS 5000
16 3500
17 3500
Id 3SOO
19 3500
fU 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 57500
LIFETIME
PKOCESS COST
LEVELIZED
9500000 4S240U 10-iUO
9500000 452400 10500
9500000 453400 iOaOO
9500000 452400 lObOO
950,00,00 4b2nOO lU^UiJ
6650000 316700 7JOU
6650000 316700 73UO
6650000 316700 730U
6650000 31f>700 73UO
66§POOOa 316JOQ 73uu
2850000 135700 310U
2850000 136700 31UO
28SOOOO 135700 3100
3850000 135700 3100
28.5059H 13570M JlOO
2850000 135700 3100
2850000 135700 3100
2850000 13S7UJ J100
2B50000 135700 3100
2850000 135700 3100
109250000 52U250U 120000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PEfl TON OF COAL HUKNEO
MILLS PER K1LOH4TT-HOUH
CENTS PER MILLION bru ME»T IMPUT
DOLLARS PEh TON OF SULFUh kE*OVEO
DISCOUNTED AT 11.2* TO INITIAL YEArt» JOLLArtS
32600
J2600
32600
32600
32600
22400
22800
22000
22UOU
2260U
VBOO
VHOO
»tiOO
^000
*«00
vaoo
taoo
9800
9HOO
980U
375000
COST
INCREASE (DECREASE) IN UNIT O^E^ATI'NU CuST EQUIVALENT
DOLLASS PER TON OF COAL flUHlMtJ
HILLS PEh MLO«ATT-MOUrt
CENTS PER MILLION BTO HEAT INPUT
DOLLARS PEH TON OF SULFUU HEMOVEU
22.50
22.59
22.50
22. 5»
Zd.bd
22. bfl
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22. bS
22.50
22.50
22.50
22.50
22.50
22.50
TO DISCOUNTED
13184000
12888600
12593200
12297800
12002400
10717400
10422000
10126600
9831200
9535800
7769000
7473600
7178300
6B82900
6587500
6292100
5996700
5701300
5405900
5110500
177996800
34.21
15.48
162.93
1483.31
82098300
PKBCESS COST OVER
31.30
14.16
149.07
1352.53
733500
?33500
733500
733500
H33SOLI
513000
613000
513000
513000
613000
220500
320500
220500
220500
220500
220500
220500
220500
220500
220500
8437500
1.62
0.74
7.73
70.32
4252300
LIFE OF
1.62
0.73
7.72
70.06
12450500
12155100
11859700
11564300
11268900
10204400
9909000
9613600
9318200
9022804
7548500
7253100
6957000
6662400
6367000
6071600
5776200
5480800
5185400
4890000
169559300
32.59
14.74
155.20
1412.99
77846000
POWER UNIT
29.68
13.43
141.35
1282.47
12450500
24605600
36465300
48029600
592985.00
69502900
79411900
89025506
98343700
107366500
114915000
122168100
129125900
135788300
142155300
148226900
154003100
159483900
164669300
169559300
-------
TABLE A-96. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW)
2 of
total direct
Investment, $ Investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 (two spray grid towers, Including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (two Indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calclner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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
397,000
184,000
2,017,000
2,326,000
519,000
2,178,000
609,000
3,526,000
1,189,000
3,210,000
571,000
16,726,000
1,004,000
17,730,000
63,000
17,793,000
1,308,000
325,000
2,731,000
856,000
5,220,000
4,603,000
27,616,000
2,756,000
3,314,000
33,686,000
15,000
738,000
34,439,000
($172/kW)
2.3
1.1
11.3
13.1
2.9
12.2
3.4
19.8
6.7
18.0
3.2
94.0
5.6
99.6
0.4
100.0
7.4
1.8
15.3
4.8
29.3
25.9
155.2
15.5
18.6
189.3
0.1
4.1
193.5
Basis
Evaluation 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 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.
267
-------
TABLE A-97. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost. $
600 tons 300.00/ton
727 liters 2.50/liter
1,330 tons 15.00/ton
30,000 man-hr 12.50/man-hr
180,000
1,800
20.000
201,800
375,000
% of average
annual revenue
requirements
1.94
0.02
0.22
2.18
4.04
2,570,000 gal
205,900 MBtu
964,700 kgal
25,605,000 kWh
55,400 MBtu
4,480 man-hr
0.40/gal
2. 00 /MBtu
0.1 2 /kgal
0.031/kWh
2. 00 /MBtu
17.00/man-hr
1,028,000
411,800
115,800
793,800
(110,800)
1,420,200
76,200
4,110,000
4,311,800
11.09
4.44
1.25
8.56
(1.19)
15.31
0.82
44.32
46.50
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 44,200 tons
Net annual revenue requirements
Equivalent unit revenue requirements
2,021,200
2,961,800
935,700
37,500
110,500
6,066,700
10,378,500
25.00/ton (1,105,000)
9,273,500
$/ton coal $/MBtu heat
Mills/kUh burned input
6.62 15.12 0.72
21.80
31.94
10.09
0.40
1.19
65.42
111.92
(11.92)
100.00
$/ton
sulfur
removed
653
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.
Sulfur removed, 14,210 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct Investment, $17,793,000; total depreciable investment, $33,686,000; and total
capital investment, $34,439,000.
All tons shown are 2,000 Ib.
268
-------
TABLE A-98
MAGNESIA PROCESS VARI«TION
HO niit CA^r. : Ji-0 «i« nHjUL*TEi) CO. ECONOMICS
TgTaL CAPITAL I*vtSTML'\F 3443VOOO
to
ON
\O
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
6
9
Ifl
11
12
13
14
15
16
17
18
19
20
21
22
23
24
?5
26
27
28
29
3P
ANNUAL
OPERA-
TION.
KW-HR/
KW
7000
7000
7000
7000
700O
7000
7000
7000
7000
70QO .
5000
5000
5000
5000
50DQ
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 127500
POWER UNIT
MEAT
REQUIREMENT.
MILLION *TU
/YEAR
12880000
128HOOOO
12H80000
12880000
12880000
12880000
12880000
12880000
12880000
, I288oogq
9200000
9200000
9200000
9200000
920UOOO
6440000
6440000
6440000
6440000
64400UO
276001)0
2760000
2760000
2760000
_2760000
2760000
2760fl:JO
27600JO
27600)0
2760(100
234600000
Pv;«r> UNIT
FUEL
CONSULT I j«
TONS C04L
/Yt4n
6133JO
* 1 3 1 (I U
M3300
ft 1 J 3 ') U
fe}, 3.300
613390
*13300
M33'*vi
613300
filial')
43*lH'J
H.*-U «>l|
*3^i Jj
43-JOO
30*700
lunM'J
1'JfcMo
3 '-• •> 7 li U
306 70 G
1 3 1 * 0 o
131f)u
131*HU
1 3 1 * 0 U
1 3 J4QM
131400
131-.00
1H«0(I
131400
13J400
11171J30
LIFETIME AVERAGE INCRE»SE (OECnEaac)
OOLLAPS
MILLS PI
PE* T0i« OF
E3 "ULO*4TT-
CENTS PER »«ILLIO« *
PhocESS COST
LEVELIZED
DOLL«KS
DISCOUNTED AT
PEK TON OF
SoLfUK
HC'iOVtO
aY
POLLUTION
. CU'vTkuL
HKOCfcbS.
bY-HKOUOCT
M«TE.
(nJUIV«LtNT
TONS/YtAK
100«
TONi/YEMH SULFUKilC «C1U
14200
14^00
i«2oi
14100
14200
14200
14£00
14200
1<»00
1020V
lu^ou
Ib200
iO^UU
71oO
7100
71DO
71uO
7 1 U h
3jOb
JJUO
3oUb
3000
30ti(I
3000
3000
300U
3000
3000
2shr>0o
Z^UO
4*^00
f4200
4*2t)0
44200
»*200
44200
4*200
44200
31600
31600
31600
31600
31600
22100
22100
22100
22100
£21 (J Q
9b30
93UO
vsao
9boO
JbJO
9500
9500
9300
9bOU
9500
805500
KtT KtvEN'
*/TON
100«
bULFUKlG
22.59
22.56
22.50
22.59
22. SO
22.59
22. bW
22.5V
22.50
22. f>*
22.59
22.59
22.50
22.50
22.50
22.50
22. bU
22.59
22.54
2«!. SB
22.59
22.59
22.59
22.50
22.50
2*i UULLAKS
INCREASE (DECREASE) IK O*I T o^tHftTl^fa COST
DOLLARS
PF« TO» OK
COAL -E1 KlLOoATT-oOlJf!
CENTS DEf) .''ILL ION *TU M£«T I*PUI
DOLL»°S
<>?•< TC-v OF
SOLFO'? Kt^OVEU
23.26
10.19
110.74
1004.98
94920400
1.63
0.71
7.73
70.11
7233800
PH6CESS COST OVER LIFE OF
21.28
9.32
101.33
918.88
1.62
0.71
7.72
70.03
21.63
9.40
103.01
934.67
87686600
POWER UNIT
19.66
8.61
93.61
848.85
-------
TABLE A-99. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500-MW existing)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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, $
714,000
307,000
A, 694, 000
5, SAO ,000
1,217,000
5,152,000
1,127,000
5,579,000
2,279,000
6,090,000
1,008,000
33,707,000
2,022,000
35,729,000
157,000
35,886,000
1,888,000
469,000
4,891,000
1,459,000
8,707,000
8,918,000
53,511,000
5,336,000
6,421,000
65,268,000
39,000
1,530,000
66,837,000
($134/kW)
7. of
total direct
investment
2.0
0.9
13.1
15.4
3.4
14.4
3.1
15.5
6.4
17.0
2.8
94.0
5.6
99.6
0.4
100.0
5.3
1.3
13.6
4.1
24.3
24.8
149.1
14.9
17.9
181.9
0.1
4.2
186.2
Basis
Evaluation 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 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.
270
-------
TABLE A-100. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500-MW
existing)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
1,500 tons
1,800 liters
3,310 tons
300.00/ton
2.50/liter
15.00/ton
47,500 man-hr 12.50/man-hr
450,000
4,500
49,700
504,200
593,800
2.46
0.02
0.27
2.75
3.24
6,426,000 gal
514,600 MBtu
2,411,600 kgal
63,110,000 kWh
138,600 MBtu
8,500 man-hr
0.40/gal
2.00/MBtu
0.1 2 /kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
2,570,400
1,029,200
289,400
1,830,200
(277,200)
2,505,700
144,500
8,686,000
9,190,200
14.04
5.62
1.58
9.99
(1.51)
13.68
0.79
47.43
50.18
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 byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 110,400 tons
Net annual revenue requirements
Equivalent unit revenue requirements
4,177,200
5,748,000
1,622,000
59,400
276,000
11,882,600
21 ,072,800
25.00/ton (2,760,000)
18,312,800
$/ton coal S/MBtu he;
Mills/kWh burned input
5.23 11.94 0.57
22.81
31.39
8.86
0.32
1.51
64.89
115.07
(15.07)
100.00
S/ton
it sulfur
removed
515
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.
Sulfur removed, 35,530 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $35,886,000; total depreciable investment, $65,268,000; and total
capital investment, $66,837,000.
All tons shown are 2,000 Ib.
271
-------
TABLE A-101
MAGNESIA PROCESS VARIATION FkOf r>«iE C«at: 300 H« EXISTING KEbULATEU CO. ECONOMICS
TOT«L CAKlfAL I'.ivtSTMENT 66837000
ro
YEARS ANNUAL
AFTER OPERA-
POHER TION.
UNIT KM-HR/
START KW
SULI-OH rtY-PWOOUCT
HE40VLU KATE,
POKEH UNIT Pf,wE« UNIT bY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTKOL
MILLION dTU TONS CC-.L PKUCESS. 100*
/YEAR /YE«K TotiS/YF.AK SULFUKIC ACIO
TOTAL
0». COST
INCLUDING
NET REVENUE. REGULATED
S/TON ROI FOX
POXEH
1004 COMPANY*
SULFUHIC ACID S/YEAR
TOTAL
NET
SALES
REVENUE,
S/YEAR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
PONEri> POHER.
s s
1
2
3
4
$
6
7
8
9
11
12
13
14
16
17
16
21
22
23
2*
?!>
26
27
26
29
3P
7000
7000
7000
7000
7000
5000
5000
5000
3000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 92500
LIFETIME
PROCESS COST
LEVEL IZEO
32200000
32200000
32200000
32200000
23000000
23000000
23000000
23000000
23000000
16100000
16100000
16100000
16100000
16100000
6900000
6900000
6900000
6900000
690000Q
690OAOO
6900000
6900000
6900000
6900000
1533300
1533300
153330U
1533JJO
1 ^233 ^ M
1 0^52 0 0
1095200
766700
7 *• h 7 0 o
7UO
17dOO
17rtOO
7600
7oOO
7600
7hUO
7oOO
7r>UO
119400
110*110
11U400
*io«op
7S900
76900
74900
35200
33200
23700
23700
2J/UU
2J/OU
23700
23700
2J700
23700
425500001) 20?62i)00 4o93i)0 1439500
AVERAGE INCREASE (DECREASE) IN UMT OPtKATlNG COST
OOLLASS PFft TON OF COAL HUxNEO
MILLS PE* KlLO»»TT-nOU*
CENTS PER MILLION «TU H£»T I.vPUT
OOLL*«S PER TO* of bOLFu* «E*OvfcO
DISCOUNTED AT 11. 2« TO INITIAL YtArt. L>OLL«rtS
INCREASE (DECREASE) IN UM1 OPE-<«TI«v& COST EQUIVALENT
DOLLARS PF* TON O^ COAL rtUVMtU
MILLS PER KlLO«ATT-riuU*
CENTS "ER MILLIOw rtlU rtCAT IrtPUT
DOLLARS PE" TC^ OF bULFo* KfcriOVEU
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
22.
5ft
50
50
30
59
t>0
50
SO
50
SO
50
50
SU
50
S|
50
50
56
56
TO DISCOUNT ED
26980106
26S31000
26082000
25632900
22139900
21690700
21241700
20792000
20343600
17851200
17402100
16953100
16504000
16055000
12624800
12175700
11726700
11277600
10828600
10379600
9930500
4481500
9032400
8.583400
2484000
2484000
2464000
2484000
2484000
1775300
1775300
1775300
1775300
1775300
1242000
1342000
1242000
1242000
1242000
633300
633300
933300
633300
533300
633300
533300
533300
633300
533300
427424500 32839500
21. U9 1.62
9.24 0.71
100.45 7.72
910.38 64.94
177151100 15187600
PrlHCESS COST OVER LIFE OF
18.90 1.62
8.28 0.71
90.00 7.72
815.99 69.96
24496100
24047000
23598000
23148900
22699900
20364500
19415400
19466400
19017300
18568300
16609200
16160100
15711100
15262000
14813000
12091500
11642400
11193400
10744300
1 02953(0
9846300
9397200
8948200
6499100
8050100
394385000
19.47
8.53
92.73
840.44
161963500
POWER UNIT
17.26
7.57
62.28
746.03
24496100
46543100
72141100
95290000
11798~99QO
138354400
158269800
177736200
196753500
215321800
231931000
248091100
263802200
279064200
29387720.0
305966700
317611100
328804500
339548600
349844100
359690400
369087600
378035800
386534900
394585000
-------
TABLE A-102. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2.0% sulfur)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entralnment
Stack gas reheat (four Indirect steam reheaters)
Chloride purge (four chloride scrubbers and entralnment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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, $
428,000
196,000
4,625,000
5 447 000
lJ98ioOO
5,066,000
659,000
3,741,000
1,292,000
3,486,000
614,000
26,752,000
1,605,000
28,357,000
154,000
28,511,000
1,705,000
423,000
4,042,000
1,225,000
7,395,000
7,181,000
43,087,000
4,293,000
5,171,000
52,551,000
42,000
1,110,000
53,703,000
($107/kW)
% of
total direct
investment
1.5
0.7
16.2
1 Q 1
i y * i
4.3
17.8
2.3
13.1
4.5
12.2
2.2
93.8
5.6
99.5
0.5
100.0
6.0
1.5
14.2
4.3
26.0
25.2
151.2
15.1
18.1
184.4
0.1
3.9
188.4
Basis
Evaluation 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 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.
273
-------
TABLE A-103. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
coat. $
680 tons 300.OO/ton
816 liters 2.50/liter
3,240 tons 15.00/ton
42,600 man-hr
12.50/man-hr
204,000
2,000
48.600
254,600
532,500
2,892,000 gal
503,400 MBtu
1,321,900 kgal
52,658,000 kWh
62,400 MBtu
7,620 man-hr
0.40/gal
2. 00 /MBtu
0.1 2 /kgal
0.029/kWh
2. 00 /MBtu
17.00/man-hr
1,156,800
1,006,800
158,600
1,527,100
(124,800)
1,989,600
129,500
6,376,100
6,630,700
% of average
annual revenue
requirements
1.39
0.01
0.34
1.74
3.63
7.89
6.87
1.08
10.41
(0.85)
13.57
0.88
43.48
45.22
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 byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 49,700 tons
Net annual revenue requirements
Equivalent unit revenue requirements
3,153,100
4,618,500
1,325,800
53,300
124,300
9,275,000
15,905,700
25.00/ton (1,242,500)
14,663,200
$/ton coal $/MBtu heat
Mills/kWh burned input
4.19 9.77 0.47
21.50
31.50
9.04
0.36
0.85
63.25
108.47
(8.47)
100.00
$/ton
sulfur
removed
914
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.
Sulfur removed, 16,050 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $28,511,000; total depreciable investment, $52,551,000; and total
capital investment, $53,703,000.
All tons shown are 2,000 Ib.
274
-------
TABLE A-104
PROCESS VAWlATIOr>. FKOM BASE LASEJ 2.0* S KEGULATEU CO. ECONOMICS
TOTAL CAPITAL INVESTMENT
;J703000
Ln
SJLFUH BY-PKOOUCT
REMOVED HATE.
YtARS ANNUAL POWER UMT PCwER UMT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAH
POWER TION. REOUIHEMfNT. CONSUMPTION. CONTROL
UNIT KW-HK/ MILLION BTU TONS COAL PROCESS' loot
START
1
2
3
«
Jj
6
7
a
4
IJj
11
it
13
14
jja
16
17
18
19
KM
7000
7000
7000
7000
2000
7000
7000
7000
7000
JMO-
5000
5000
5000
5000
£MO_
3500
3500
3500
3500
£1! 35J>0
21
22
23
24
1500
1500
1500
1500
2i isnn
26
27
29
30
1500
1500
1500
1500
15JQ
TUT 127500
LIFETIME
/YEAH
J1500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
22500000
22500000
22500000
22500000
22504000
15750000
15750000
15750000
15750000
15750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
573750000
AVERAGE INCREASE
DOLLARS
/YEAH
1500000
150000U
1500000
1500000
1500JJOO
1500000
1500000
1500000
1500000
1540000
1071400
1071400
1071400
1071400
IOII^PO
750000
750000
750000
750000
750000
321400
321400
321400
321400
_J21400
321400
321400
321400
321400
J21440
27321000
TONS/YEAR SULFURIC ACID
16100
16100
1610U
lolOO
16104
1610U
16100
1610U
1610U
16104
11500
11500
UbOO
11500
11504
uooo
8000
8000
8000
JOOJ1
3400
3400
3400
340U
3404
3400
3400
3400
3400
3400
292500
(DECREASE) IN LNIT OPERATING
PER TON OF
COAL fiURNEU
49700
49700
49700
49700
49700,
49700
49700
49700
4S700
49700
35500
35500
JSbOO
J5500
J5500,
24900
24VOO
24900
14900
£4<;Qn
10700
10TOO
10700
10700
107PQ
10700
10700
10700
10700
107PP
906000
COST
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
i/ION ROI FOH
POWER
100* COMPANY?
SLLFURIC
22
22
22
22
22
22
22
22
22
^2
22
22
22
2OUR
CENTS PFR MILLION
PfrUCESS
COST
LEVELLED
DOLLARS
DISCOUNTED AT
PEH TON OF
STU HEAT INPUT
SULFUrf REMOVED
11.2* TO INITIAL YE*R. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT
DOLLARS
PEH TON OF
COAL BURNED
TO DISCOUNTED
MILLS PER KILOHATT-I-OUR
CENTS PER MILLION
DOLLARS
PER TON Of-
BTU MEAT INPUT
bULFLR HEMOVEO
ACID 1/YEAO
20399900
20098600
19797300
19496000
19194700
1B893500
18592200
18290900
17989600
17688300
15517100
15215800
14914500
14613200
J431J90.il
12528900
l?227e.OO
11926300
11625100
1J323800
8837300
8536000
8234700
7933400
7632100
7330800
7029500
672B200
642690U
6125604
399459700
14.62
6.27
69.62
1365.67
146164200
TOTAL
NET
SALES
REVENUE.
S/YEAR
1118300
1118300
1118300
1118300
11 18300
1118300
1118300
1118300
1118300
1J18300
798800
796800
798800
798800
7988JO
560300
560300
560300
560300
500:300
240800
240800
240800
240800
£408, 0,1}
240800
240800
240800
240800
240800
20386500
0.75
0.32
3.55
69.69
8134600
PROCESS COST OVER LIFE OF
13.40
5.74
63.80
1249.27
0.75
0.32
3.55
69.53
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
S
19281600
18980300
18679000
18377700
18076400
17775200
17473900
17172600
16871300
16570050
14718300
14417000
14115700
13814400
115.13J0J!
11968600
11667300
11366000
11064800
10763504
8596500
8295200
7993900
7692600
739J304
7090000
6788700
6487400
6186100
b884600
379073200
13.87
5.95
66.07
1295.98
138029600
POWER UNIT
12.65
5.42
60.25
1179.74
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER*
t
19281600
38261900
56940900
75316600
,332 95.0JJU
111170200
129644100
145816700
16P688000
—129£5&£SI o
193976300
208393300
222509000
23*323400
£49.83. 65JO
261805100
27347240U
284S36400
2959U3200
3-fl66..6.6.240
315263200
323558400
331552300
339244900
3. A66362.QO
353726200
360514900
367002300
373168400
3790 73200
-------
TABLE A-105. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
Z of
total direct
Investment, S investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators.
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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
704,000
303,000
4,625,000
5,447,000
1,198,000
5,066,000
1,110,000
5,518,000
2,243,000
6,000,000
994,000
33,208,000
1,992,000
35,200,000
154,000
35,354,000
1,881,000
467,000
4,831,000
1,442,000
8,621,000
8,795,000
52,770,000
5,262,000
6.333,000
64,365,000
42,000
1,504,000
65,911,000
($132/kW)
2.0
0.9
13.1
15.4
3.4
14.3
3.1
15.7
6.3
17.0
2.8
94.0
5.6
99.6
0.4
100.0
5.3
1.3
13.7
4.1
24.4
24.9
149.3
14.9
17.9
182.1
0.1
4.2
186.4
Basis
Evaluation 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 punps 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.
276
-------
TABLE A-106. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Annual
quantity
Direct Coats
Delivered raw materials
MgO 1,470 tons
Catalyst 1,800 liters
Agricultural limestone 3,240 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 47 , 500 man-hr
Utilities
Fuel oil 6,286,000 gal
Steam 503,400 MBtu
Process water 2,359,200 kgal
Electricity 61,752,000 kWh
Heat credit 135,600 MBtu
Maintenance
Labor and material
Analyses 8,500 man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0* of total depreciable
investment
Average cost of capital and taxes at 8.62
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10X of operating labor
Marketing, 10X of byproduct sales revenue
Total Indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100Z sulfurlc acid 108,000 tons
Net annual revenue requirements
Equivalent unit revenue requirements
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
300.00/ton 441,000
2.50/liter 4,500
15.00/ton 48,600
494,100
12.50/man-hr 593,800
0.40/gal 2,514,300
2.00/MBtu 1,006,800
0.12/kgal 283,100
0.029/kWh 1,790,800
2.00/MBtu (271,200)
2,468,600
17.00/man-hr 144,500
8,530,700
9,024,800
3,861,900
5,668,300
1,603,500
59,400
270,000
11,463,100
20,487,900
25.00/ton (2,700,000)
17,787,900
$/ton coal $/MBtu heat
Mills /kwh burned input
5.08 11.86 0.56
2.48
0.03
0.27
2.78
3.34
14.13
5.66
1.59
10.07
(1.52)
13.88
0.81
47.96
50.74
21.71
31.87
9.01
0.33
1.52
64.44
115.18
(15.18)
100.00
$/ton
sulfur
removed
512
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.
Sulfur removed, 34,750 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $35,354,000; total depreciable investment, $64,365,000; and total
capital investment, $65,911,000.
All tons shown are 2,000 Ib.
277
-------
TABLE A-107
MAfcNESIA PROCESS BASE CASE: SOU W*» 3.S* S HtGULATEO CO. ECONOMICS
TOTAL CAPITAL INVESTMtwT
65911000
N>
^J
CO
SuLFlIK rtY-PHOUUCT
-it>ioVfcU RATE.
YEARS ANNUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 700Q
6 7000
7 7000
8 7000
9 7000
1U 7000
11 5000
12 5000
13 5000
14 5000
}B 500.Q
16 3500
17 3300
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
?5 1500
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZEO
POWER UNIT PO.EK UNIT at EUUli/ALEMT
HEAT FUEL POLLUTION T<
REQUIREMENT. CONSUMPTION. CONTROL
MILLION BTU TONS COAL P-*OCtSS. 10U*
/YEAH /YF.A* TONS/YEAR SULFUHIC ACID
31500000 1SOOOOO 34e>00
31500000 1500000 34aOO
31500000 1500000 34nOO
31500000 1500000 34HOO
3150000Q 1500000 3*«OU
31500000 1500000 34»00
31500000 1500000 34«00
31500000 1500000 34dOO
31500000 ISOOOOtl 34*00
31500000 ISOOoOO 34ijUO
22500000 1071*00 £r*-*00
22500000 1071*00 2**UO
22500000 1071400 24400
22500000 1071400 24900
225QOpQQ 1Q71400 24*00
15750000 750000 17*00
15750000 750000 17*00
15750000 750000 17*00
15750000 750000 17400
15750000 75000U 17*OU
6750000 321400 7sOO
6750000 321400 T?OH
6750000 321400 7nuO
6750000 321400 7=>0u
6750000 321*00 7500
6750000 321400 7t>00
6750000 321400 75UO
6750000 321400 7500
6750000 321400 7oOO
6750000 321400 7500
573750000 27321000 634300
AVERAGE INCREASE (OECHEASE) IN UNIT OPERATING
DOLLARS »ER TON OF COAL HUKNtO
MILLS PER KILOWATT-nOUH
CENTS PER MILLlOf. dTU MEAT IuHUT
OOLL»SS PEhi TOfv OF aULFu* KtMOVEO
DISCOUNTEO AT 11.2* TO INITIAL YtArt» DOLLARS
looooo
looooo
lOaOoo
lOdOOO
lOdOOO
lOetOOU
loaooo
lOdOOO
luaooo
lObOOu
77100
77100
77100
77100
77100
940UO
54000
S4000
34000
54000
23100
23100
23100
231UO
23100
23100
23100
23100
23100
23100
COST
INCREASE (DECREASE) IN U*IT OPERATING CuST EQUIVALENT
DOLLARS PER TON OF COAL 1UKNEU
MILLS PEP KILOxATT-MOurt
CENTS P£0 MILLION iTU HEAT INPUT
DOLLARS PER TON OF SULFUR RErtOWEO
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
S/TON
loot
SULFUMIC
22.50
32.50
22.59
22.59
22.56
22.59
22. 5U
22.50
22.50
22.50
22.56
22.5*
22.50
22.50
22.50
£<:.!> II
22. 5«
22.58
22.50
22.50
22.50
22.50
22.50
22.50
22. 58
22.5*
22.50
22.59
22.50
22.59
TO DlbCOUNftO
ROI FOR
POWER
COMPANY.
ACID S/YEAR
25886600
25517600
2S148300
24779500
24410500
24041SOO
23672*00
23303400
22934400
225^5*00
19647800
19278600
18909600
18540600
18171700
15795700
15426700
15057700
1468U600
143^9600
11020800
10651700
10282700
9913700
9544700
9175600
8806600
8437600
8068600
7699500
505698500
18. 61
7.93
88.14
797.00
185574300
TOTAL
NET
SALES
REVENUE.
S/YEAR
2*30000
2*30000
2*30000
2*30000
2*30000
2*30000
2*30000
2*30000
2*30000
2*30000
1734800
1734800
1734800
1134800
1134800
1215000
1215000
1315000
1215000
1215000
619800
519800
619800
519800
619800
519800
619800
619800
519600
519800
44247000
1.62
0.69
7.71
69.73
17*70500
PH6CESS COST OVER LIFE OF
17.01
7.29
81.01
732.92
1.62
0.69
7.72
69.79
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
S
23456600
23087600
22718&00
22349600
21980&pO
216115OO
21242400
20873400
20504400
20135400
17913000
17544000
17175000
16806000
16436900
1*580700
1*211700
13842700
13473600
13104600
10501000
10131900
9762900
9393900
9024900
8655800
8286800
7917800
7548800
7179700
461451600
16.89
7.24
80.43
727.27
167903800
POWER UNIT
15.39
6.60
73.29
663.13
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
*
23456600
46544200
69262700
91612200
113592700
13520*200
156446600
177320000
19782*400
217959800
235872800
253*16800
270591800
287397800
30383*700
318*15*00
332627100
3*6*69800
3599*3*00
3739*80.0.0
3835*9000
393680900
403443800
412837700
421862600
430518400
438805200
446723000
454271800
461*51500
-------
TABLE A-108. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5.0% sulfur)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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, $
927,000
386,000
4,625,000
5,447,000
1,198,000
5,066,000
1,481,000
6,842,000
3,046,000
8,112,000
1,298,000
38,428,000
2_,306,000
40,734,000
154,000
40,888,000
2,029,000
504 ,000
5,450,000
1,611,000
9,594,000
10,096,000
60,578,000
6,042,000
7,269,000
73,889,000
42,000
1,874,000
75,805,000
($152/kW)
% of
total direct
investment
2.3
0.9
11.4
13.3
2.9
12.4
3.6
16.8
7.4
19.8
3.2
94.0
5.6
99.6
0.4
100.0
5.0
1.2
13.4
3.9
23.5
24.7
148.2
14.8
17.7
180.7
0.1
4.6
185.3
Basis
Evaluation 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 fly ash 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.
279
-------
TABLE A-109. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
coat, $
Total
annual
cost. $
% of average
annual revenue
requirements
2,260 tons
2,800 liters
3,240 tons
300.00/ton
2.50/liter
15.00/ton
51,000 man-hr 12.50/man-hr
678,000
7,000
48.600
733,600
637,500
9,668,000 gal
503,400 MBtu
3,393,200 kgal
71,017,000 kWh
208,600 MBtu
9,130 man-hr
0.40/gal
2.00/MBtu
0.1 2 /kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
3,867,200
1,006,800
407,200
2,059,500
(417,200)
2,856,000
155,200
10,572,200
11,305,800
3.32
0.03
0.24
3.59
3.12
18.96
4.93
2.00
10.09
(2.04)
13.99
0.76
51.81
55.40
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfurlc acid 166,200 tons
Net annual revenue requirements
Equivalent unit revenue requirements
4,433,300
6,519,200
1,824,400
63,800
416.000
13,256,700
24,562,500
25.00/ton (4,155,000)
20,407,500
$/ton coal $/MBtu heat
Mills/kWh burned input
5.83 13.60 0.65
21.72
31.95
8.94
0.31
2.04
64.96
120.36
(20.36)
100.00
$/ton
sulfur
removed
380
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.
Sulfur removed, 53,730 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $40,888,000; total depreciable Investment, $73,889,000; and total
capital investment, $75,805,000.
All tons shown are 2,000 Ib.
280
-------
TABLE A-110
MAGNESIA PROCESS VARIATION F00
J300B
JboOO
336UU
33-50U
JbbUO
302/OOU
*G COsT
TOTAL
OP. COST
INCLUDING
NET MbvEnuEt KEfULATED
t/TON
1(IO«
SULFUHIC
22.30
22.50
22.30
22.50
22.50
22. b*
22.58
22. So
?£.3» "ILLlflN «TU H£sT 1NHI/T
PKOCESS COST
LEVEL I ZED
DOLLA-IS
DISCOUNTED AT
P£« TON OF
•jULFUH HEmOVEl)
11.2* TO INITIAL rtAK. UOLLAKS
INCREASE (DECREASE) IN Ui»I
HOLLARS
MILLS PE
PEK TON 'Jt
f O^EHATlNlj COST
CUAL -IUKNEO
EQUIVALENT Td
OISCOUNTEO
u KILO**TT-HOUH
CENTS P£w BILLION y
l-OLLA-'S
PFK TCA uK
T'J Ht'«T INHUT
bULFu* KE«0»EU
ROI FOR
POnER
COMPANY.
ACIU J/YEAR
30666100
302*2*00
2^81rtaOO
29395200
2H971300
2B5*7900
2(1124200
27700600
27277000
26653300
23234300
22810700
22367000
21963400
21539800
18610200
1(1186600
17762900
17339300
16915700
12062200
12438000
12015000
11591300
11167700
107*4100
10320400
9896800
9473200
9049500
597905700
21.88
9.38
104.21
611.04
21994*300
TOTAL
NET
SALES
REVENUE.
i/YEA*
3739500
3739500
3739500
3739500
3739500
3739500
3739500
3739500
3739500
3739500
2*70800
2*70800
2*70800
2*70800
2*70800
1869000
1869800
1869600
1869800
1069(500
801000
801000
801000
801000
801000
80100U
801000
801000
801000
B01000
68*08000
2.49
1.07
11.87
69.60
27195100
PROCESS COST OVER LIFE OF
20.16
8.64
96.01
563.09
2.49
1.07
11.87
69.62
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
PO«EH,
S
26926600
26502900
26079300
25655700
25232000
24808400
24384700
23961100
23537500
23113800
20563500
20139900
19716200
19292*00
18869000
16740400
16316800
15893100
15469500
15045900
12061200
11637600
11214000
10790300
10J66700
9943100
9519400
9095800
8672200
H?»8300
529797700
19.39
8.31
92.34
541.44
192749200
HOMER UNIT
17.67
7.57
84.14
493.47
CUMULATIVE
NET INCREASE
(DECREASE!
IN COST OF
POKER t
S
26926600
53429500
79508800
10516450(1
130396500
155204900
179589600
203550700
227088200
25020200U
270765500
290905400
310621600
329914200
3*8783200
365523600
381840400
397733500
413203000
428248900
440310100
451947700
463161700
473952000
484318700
494261800
503781200
512877000
521549200
529797700
-------
TABLE A-111. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000-MW existing)
Z of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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
1,097,000
447,000
7,409,000
9,418,000
1,973,000
8,521,000
1,766,000
7,802,000
3,670,000
9,750,000
1,528,000
53,381,000
3,203,000
56,584,000
308.000
56,892,000
2,295,000
569,000
7,172,000
2,070,000
12,106,000
13,800,000
82,798,000
8,249,000
9,935,000
100,982,000
66,000
2,593,000
103,641,000
($104/kW)
1.9
0.8
13.0
16.6
3.5
15.0
3.1
13.7
6.5
17.1
2.7
93.9
5.6
99.5
0.5
100.0
4.0
1.0
12.6
3.6
21.2
24.3
145.5
14.5
17.5
177.5
0.1
4.6
182.2
Basis
Evaluation 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 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.
282
-------
TABLE A-112. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW existing)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost. $
Total
annual
cost, $
% of average
annual revenue
requirements
2,940 tons
3,600 liters
6,480 tons
300.00/ton
2.50/liter
15.00/ton
67,200 man-hr 12.50/man-hr
882,000
9,000
97,200
988,200
840,000
12,572,000 gal
1,006,900 MBtu
4,718,400 kgal
122,905,000 kWh
271,200 MBtu
13,810 man-hr
0.40/gal
2. 00 /MBtu
0.12/kgal
0.028/kWh
2.00/MBtu
17. 00 /man-hr
5,028,800
2,013,800
566,200
3,441,300
(542,400)
3,404,300
234,800
14,986,800
15,975,000
3.06
0.03
0.34
3.43
2.92
17.45
6.99
1.97
11.94
(1.88)
11.82
0.81
52.02
55.45
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 byproduct sales revenue
Total Indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100?. sulfurlc acid 216,100 tons
Net annual revenue requirements
Equivalent unit revenue requirements
6,462,800
8,913,100
2,239,600
84,000
540,300
18,239,800
34,214,800
25.00/ton (5,402,500)
28,812,300
$/ton coal $/MBtu heat
Mills/kWh burned input
4.12 9.60 0.46
22.43
30.93
7.77
0.29
1.88
63.30
118.75
(18.75)
100.00
S/ton
sulfur
removed
415
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, 2,999,900 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Sulfur removed, 69,490 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $56,892,000; total depreciable investment, $100,982,000; and total
capital investment, $103,641,000.
All tons shown are 2,000 Ib.
283
-------
TABLE A-113
MAGNESIA PROCESS VARIATION FROM BASE CASE: 1.000 M» EXISTING rtEGULATEO CO. ECONSMICS
TOTAL CAPITAL INVESTMENT I03b4iooo
ro
oo
YEARS ANNUAL
AFTER OPERA-
POMER TION.
UNIT KH-HR/
START KH
1
2
3
4
6 7000
7 7000
e 7000
9 7000
10 7000
11 5000
1* 5000
13 5000
14 5000
Jt> 5000
16 3500
17 3500
18 3500
19 3500
2>p 3500
21 1500
22 1500
23 1500
24 1500
£5 1500
26 1500
27 1500
28 1500
29 1500
30 IfiOA
TOT 92500
LIFETIME
SULFUR ttY-PROOUCT
KEMOVEU KATt.
POWER UNIT PO.EH UNIT BY tUUlVALENT
HEAT FUEL POLLUTION TONS/YtAH
REQUIREMENT. CONSUMPTION. CONTROL
MILLION BTU TONS COAL PROCESS. 100%
/YEAR /YFAR TONS/YEAH SULFUMIC ACID
63000000 3000000
63000000 3000000
63000000 3000000
63000000 3000000
63000000 3000000
45000000 2142900
45000000 2142900
45000000 2142900
45000000 2142900
45000000 21*2900
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
13500000 642900
13500000 642900
13500000 642900
13500000 642900
13500000 642900
13500000 642900
13500000 642900
13500000 642900
13500000 642900
13500000 642900
832500000 39643500
69500
69300
69600
09500
69SOO
49600
49600
49600
49600
49600
34709
34706
J4700
34700
3470U
1490B
1490U
14900
14900
14900
14900
14900
14900
14900
14900
910000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
216100
216100
216100
216100
216100
134400
154400
134400
194400
1S4400
10(4000
10BOOO
1 00000
loaooo
1 OHO 00
46300
46300
46300
46300
46300
46300
46300
46300
46300
46300
2dbb500
COST
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
I/TON ROI FOR
POME*
100% COMPANY.
SULFUrtIC ACID S/YEAR
22.50
22.50
22. b»
22.50
22.50
22.59
22.51
22.50
22.5*
22.58
22.5*
22.50
22.5*
22.5B
22.51
22.5*
22.59
22.5*
22.58
22. 5B
22.5*
22.5*
22.5*
22.5*
22.50
DOLLARS PER TON OF COAL BUftNtU
MILLS PER KILOHATT-HOUR
CENTS PER MILLION «TU HEAT INPUT
PROCESS COST
LEVEL I ZED
DOLLARS PER TON OF SULFUR
DISCOUNTED AT 11.2* TO INITIAL
KEMOVEU
YEARt DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT
TO DISCOUNTEB
DOLLARS PER TON OF COAL BUfcNED
MILLS PER KILOWATT-MOO*
CEMTS PER MILLION 8TU NEAT INPUT
OOLLMS P£R TOM OF SULFUR
HErtOKO
43261300
42566500
41871700
41177000
40432200
35260500
34565700
33870900
33176200
32481400
28258600
27563800
26869000
26174300
25479500
19728500
19033700
18338900
17644200
16949400
16254700
15559900
14865100
14170400
134756OO
679079000
17.13
7.34
81.57
739.7*
282889900
TOTAL
NET
SALES
REVENUE.
S/YEAR
4862300
4862300
4862300
4862300
4862,100
3*74000
3*74000
3*74000
3*74000
3*7400O
2*30000
2*30000
2*30000
2*30000
2*30000
1*41800
1*41800
1*41800
1*41800
1*41800
1*41800
1*41800
1*41800
1*41800
1*4 la oo
64249800
1.62
0.69
7.72
69.99
29122600
PROCESS COST OVER LIFE OF
15.43
6.61
73.46
666.09
1.62
0.69
7.7Z
99.98
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(UECREASE) (DECREASE)
IN COST OF IN COST OF
POrtER* POWER.
t $
38399000
37704200
37009400
36314700
35619900
31786500
31091700
30396900
29702200
29007400
25828600
25133800
24439000
23744300
230*9500
18686700
17991900
17297100
16602*00
15907*00
15212900
14518100
13823300
131286*0
124338OO
614829SOO
15.51
6.6S
73.85
669.75
2531673*0
POKER UNIT
13.81
5.92
6S.74
596.11
38399000
76103200
113112600
149427300
185047200
21683-3700
247925400
278322300
308024500
337031900
362860500
387994300
412433300
436177600
459227100
477913800
495905700
513202800
529805200
545712800
560925700
575*43800
589267100
602395700
614fl2950O
-------
TABLE A-114. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW)
X of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, Including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calclner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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
1,074,000
438,000
7,243,000
9,167,000
1,925,000
8,308,000
1,726,000
7,670,000
3,582,000
9,516,000
1,496,000
52,145,000
3,129,000
55,274,000
298,000
55,572,000
2,278,000
564,000
7,034,000
2,034.000
11,910,000
13,496,000
80,978,000
8,068,000
9,717.000
98,763,000
69,000
2,521.000
101,353,000
($101 /kH)
1.9
0.8
13.0
16.5
3.5
14.9
3.1
13.8
6.4
17.1
2.7
93.8
5.7
99.5
0.5
100.0
4.1
1.0
12.6
3.7
21.4
24.3
145.7
14.5
17.5
177.7
0.1
4.5
182.3
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaline
mid-1979. 8>
Stack gas reheat to 175 F by Indirect steam reheat.
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.
285
-------
TABLE A-115. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
2,840 tons
3,410 liters
6,260 tons
67,200 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
852,000
8,500
93.900
954,400
840,000
12,153,000 gal
973,300 MBtu
4,561,100 kgal
118,826,000 kWh
262,200 MBtu
13,810 man-hr
0.40/gal
2. 00 /MBtu
0.12/kgal
0.028/kWh
2. 00 /MBtu
17. 00 /man-hr
4,861,200
1,946,600
547,300
3,327,100
(524,400)
3,325,400
234,800
14,558,000
15,512,400
3.07
0.03
0.34
3.44
3.03
17.53
7.02
1.97
11.99
(1.89)
11.99
0.85
52.49
55.93
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.07, 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 byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 208,900 tons
Net annual revenue requirements
Equivalent unit revenue requirements
5,925,800
8,716,400
2,200,100
84,000
522,300
17,448,600
32,961,000
25.00/ton (5,222,500)
27,738,500
$/ton coal $/MBtu heat
Mllls/kWh burned input
3.96 9.56 0.46
21.36
31.42
7.93
0.31
1.88
62.90
118.83
(18.83)
100.00
$/ton
sulfur
removed
417
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.
Sulfur removed, 66,540 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $55,572,000; total depreciable investment, $98,763,000; and total
capital investment, $101,353,000.
All tons shown are 2,000 Ib.
286
-------
TABLE A-116
HA6NESIA PPOCESS VARIATION FRCw BASE CASE: 1.000 HM rlEGULATtU CO. ECONOMICS
TOTAL CAPITAL iNvtsTMENT 101353000
NI
00
SULFU* lY-PrtOOUCT
Ht>OVtO
*ATE.
lEARS ANNUAL POHER UNIT PO»ER UNIT BY EUUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION
POMER TION. REQUIREMENT* CONSUMPTION* CONTROL
UNIT KM-HR/ MILLION BTU TONS COAL PrIOCESSt
TONS/YEAH
100*
START KM /YEAH /YEA* TONS/YEAH SULFOxIC ACIO
1 7000 60900000 2900000 66bOO
2 7000 60900000 2900000 66600
3 7000 60900000 2900000 66300
4 7000 60900000 2900000 66500
5 7000 60900000 2900000 66bOO
6 7000 60900000 2900000 66300
7 7000 60900000 2900000 66bOO
6 7000 60900000 2900000 66500
V 7000 60900000 2900000 66300
10 7000 60900000 2900000 66bOO
11 SOOO 43500000 2071400 47500
12 5000 43SOOOOO 2071400 47500
13 5000 43500000 20T1400 47500
14 5000 43500000 2071400 47500
15 5000 43500000 2071400 47500
16 3500 30450000 1450000 33300
17 3500 30450000 1450000 33300
16 3500 30450000 1450000 33300
19 3500 30450000 1450000 33300
?0 3500 30450000 1450000 33300
21 1500 13050000 621400 1430*
22 1500 13050000 621400 14300
23 1500 13050000 621400 14300
24 1500 13050000 621400 14300
25 1500 13050000 621400 14300
26 1500 13050000 621400 14300
27 1500 13050000 621400 14309
28 1500 13050000 621400 14300
29 1500 13050000 621400 14300
3P 1500 13050000 621400 14300
TOT 127500 1109250000 52821000 1212000
LIFETIME AVERA6E INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 8TU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.2* TO INITIAL VEARt DOLLARS
208900
200900
208900
200900
208900
206900
208*00
208900
20d900
208900
149200
149200
149200
149200
149200
104500
104500
104500
104500
104500
44800
44800
44800
44800
44800
44800
44800
44800
44800
44800
3805500
COST
LEVELIZEO INCREASE (DECREASE) IN UNIT OPERATING COST EOUJVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU MEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET BE VENUE. REGULATED
S/TOft
1001
SULFURIC
22.50
22.50
32.5*
22.50
22. 5«
22.51
22.51
22.5*
22.50
22. 5i
22.5*
22.5*
32.59
22.59
22.50
22.59
22.59
32.59
22.50
22. St)
22.59
22.59
22.59
22.59
22.59
22.59
22.59
22.59
22.59
22.50
DISCOUNTED
ROI FOR
POMER
COMPANY*
ACIO S/VEAR
41155300
40589100
40022800
39456600
38890400
38324100
37757900
37191600
36625400
36059100
31097509
30531300
29965000
29398800
28832500
24838900
24272700
23706400
23140200
22573900
17092200
16526009
15959700
15393500
14827200
14261000
13694700
13128500
12562300
11996000
799870600
15.14
6.27
72.11
659.96
294910900
90TAL
NET
SALES
REVENUE*
S/VEAR
4*00300
4*00300
4900300
4900300
410031)0
4100300
4*00300
4*00300
4*00900
4*00300
3*57000
3*57000
3157000
3357000
3957000
2951300
2951300
2951300
2951300
2951300
1*08000
1*08000
1*08000
1908000
1908000
1908000
1908000
1908000
1908000
1908000
85*24500
1.62
0.67
7.72
70.65
34184000
PROCESS COST OVER tIFE OF
13. VB
5.79
66.59
609.70
1.62
0.67
7.72
70.67
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POMER •
%
364SS900
3588*800
35322SOO
34756300
34190160
33623*00
33057600
32491300
31925100
31358800
27740600
27174300
2660*900
26041*00
25475500
22487*00
21921400
21355100
20788900
20222*00
16084200
15518000
14951700
14385500
13819300
13253000
12686700
12120500
11554300
10988000
714246100
13.52
5.60
64.39
589.31
260726900
POMER UNIT
12.36
5.12
58.87
539.03
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POMER t
S
36455000
72343800
107666300
142422600
176612700
210236500
243294100
275785400
307710500
33906*300
366809800
393984100
420592100
446633900
4721094OO
494597000
516518400
537873500
558662400
578885000
594969200
610487200
625438900
639824400
653643600
666896600
679583300
691703800
703258100
714246100
-------
TABLE A-117. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% S02 removal)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four Indirect steam reheaters)
Chloride purge (four chloride scrubbers and encrainment separators.
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calclner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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, $
765,000
326,000
4,625,000
5.447,000
1,198,000
5,066,000
1,211,000
5,888,000
2,461,000
6,576,000
1,077,000
34,640,000
2,078,000
36,718,000
154,000
36,872,000
1,922,000
477,000
5,002,000
1,489.000
8,890,000
9,152.000
54,914,000
5,476,000
6,590,000
66,980,000
42,000
1.598.000
68,620,000
($137/kW)
— ~
% of
total direct
investment
2.1
0.9
12.5
14.8
3.2
13.7
3.3
16.0
6.7
17.9
2.9
94.0
5.6
99.6
0.4
100.0
5.2
1.3
13.6
4.0
24.1
24.8
148.9
14.9
17.9
181.7
0.1
4.3
186.1
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaline
mid-1979.
Stack gas reheat to 175°F by indirect steam reheat.
Minimum in-process storage; only punps 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 overtine pay Incentive not considered.
288
-------
TABLE A-118. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% S02 removal)
Direct Costa
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
1,680 tons 300.00/ton
2,100 liters 2.50/liter
3,240 tons 15.00/ton
A7,300 man-hr 12.50/man-hr
504,000
5,300
48.600
557,900
593,800
7,161,000 gal
503,400 MBtu
2,626,700 kgal
64, 097, 000 kWh
154,500 MBtu
8,500 man-hr
0.40/gal
2. 00 /MBtu
0.12/kgal
0.029/kWh
2. 00 /MBtu
17.00/man-hr
2,864,400
1,006,800
315,200
1,858,800
(309,000)
2,574,900
144,500
9,049,400
9,607,300
2.73
0.03
0.26
3.02
3.21
15.51
5.45
1.71
10.06
(1.67)
13.94
0.78
48.99
52.01
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6. OX of total depreciable
investment
Average cost of capital and taxes at 8.6TE
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10! of byproduct sales revenue
Total indirect costs
Cross average annual revenue requirements
Byproduct Sales Revenue
100Z sulfuric acid 123.100 tons
Net annual revenue requirements
Equivalent unit revenue requirements
4,018,800
5,901,300
1,656,600
59,400
307,800
11,943,900
21,551.200
25.00/ton (3,077.500)
18,473,700
S/ton coal S/MBtu heat
Mills/kWh burned Input
5.28 12.31 0.59
21.75
31.94
8.97
0.32
1.67
64.65
116.66
(16.66)
100.00
S/ton
sulfur
removed
464
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.
Sulfur removed, 39,800 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,872,000; total depreciable investment, $66,980,000; and total
capital investment, $68,620,000.
All tons shown are 2,000 Ib.
289
-------
TABLE A-119
(S3
<0
O
MAGNESIA PROCESS VARIATION FHO« BASE CASE: 40* so2 REMOVAL ntouLATto co. ECONOMICS
TOTAL CAPITAL INVESTMENT 68t>2*oou
TOTAL
SULFUR -IY-HROUUCT OP. COST
REMOVED RATE. INCLUDING
YEARS ANNUAL POWER UNIT PO*ER UNIT BY EQUIVALENT NET REVENUE. REGULATED
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAK S/TON RUI FUR
PO»ER TION. REQUIREMENT. CONSULT ION. CONTROL POwER
UNIT KW-HR/ MILLION 8TU TONS COAL PROCESS, 100* 100) COMPANY.
START KM
1
2
3
4
S
6
7
a
9
ID
11
12
13
14
,15
16
17
18
19
2O
21
22
23
24
2S
26
27
26
29
30
TOT
7000
7000
7000
7000
70DO
7000
7000
7000
7000
7000
5000
5000
5000
5000
SOOO
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
127500
LIFETIME
/YEAR /YE»R
31500000
31500000
31500000
31500000
3150000p
31500000
31500000
31500000
31500000
315poggp
22500000
22500000
22500000
22500000
22500000
15750000
15750000
15750000
15750000
157SOOOO
6750000
6750000
6750000
6750000
67SOOOO
6750.000
6750000
6750000
6750000
6750000
573750000
AVERAGE INCREASE
15000UO
1500000
1500000
15UOOOO
15,00090
1500000
1500000
1500000
1500000
1500000
107140U
1071400
1071400
1071400
1071490
750000
750000
750000
750000
750000
321400
321400
321400
321400
J21400
321400
321400
321400
321400
3P1400
27321000
TONS/YEAR SULFURIC ACID
39800
39100
39100
39800
39400
39000
39800
39HOO
39600
39000
2H400
28400
28400
28400
28400
19900
19900
19900
19900
IWQU
8-»oo
6500
6500
8500
6500
6500
6500
8500
6500
8500
724500
(DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF
MILLS PER
CENTS PER
COAL BUKMEO
123100
12J100
123100
123100
^3100
123100
123100
123100
123100
123100
67900
87900
87900
87900
879UO
61600
61600
61600
61600
61600
26400
26400
26400
26400
26400
26400
26400
26400
26400
26400
2242500
COST
SULFURIC
22. 5«
22.5*1
22.50
22.50
22.5P
22.50
22.50
22.50
32.58
22.58
22.50
22. 5#
32.50
22.50
22. 5»
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22. Si)
KILOWATT-HOUR
MILLION
DOLLARS PER TON OF
PROCESS COST
LEVEL I ZED
BTU HEAT INPUT
bULFUrt KEMOVED
DISCOUNTED AT 11.2% TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS HErt TON OF
HILLS PER
CENJS pep
KILOWATT1
COAL TURNED
-HOUR
OISCOUNTE8
MILLION BTU HEAT 1HPUT
OOLL*HS PEH TOU OF
SULfU* KEHOW
ACID i/YEUR
27145000
2t>7olOOO
26377000
25993000
25608900
2S224900
2404090V
24456900
24072600
23688800
20591e!00
20207200
19623100
19439100
19055100
|6536800
16152700
15768700
15384700
15000700
11509000
11124900
10740900
10356900
9972900
9588800
9204800
8820800
8436800
8052700
529937000
19.40
8.31
92.36
731.45
194608000
IOTAL
NET
SALES
REVENUE.
J/YEAR
1769800
£769800
2769800
2769800
2769800
2769800
2769800
2969800
2769800
2|69800
1*77800
1977800
1977800
1977600
\
-------
TABLE A-120. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-firedt existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer , 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 spray grid towers, including entrainroent
separators, tanks, agitators, and pumps)
Stack gas reheat (four direct steam reheaters)
Chloride purge
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfuric acid)
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
417,000
191,000
4,764,000
5,173,000
1,063,000
542,000
3,664,000
1,254,000
3,384,000
598,000
21,150,000
1,269,000
22,419,000
1,366,000
341,000
3,303,000
1,020,000
6,030,000
5,690,000
34,139,000
3,414,000
4,097,000
41,650,000
27,000
958,000
42,635,000
(S85/kW)
1.9
0.9
21.2
23.1
4.7
2.9
16.3
5.6
15.1
2.7
94.3
5.7
100.0
6.1
1.5
14.7
4.5
26.9
25.4
152. 3
15.2
18.3
185.8
0.1
4.4
190.3
Basis
Evaluation 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 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.
291
-------
TABLE A-121. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Direct Costs
Delivered raw materials
MgO
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
650 tons
790 liters
45,400 man-hr
5.232,000 gal
1,217,800 kgal
39,018,000 kWh
59,800 MBtu
8,100 man-hr
Unit
cost, $
300. 00 /ton
2.50/liter
12.50/man-hr
0.40/gal
0.1 2 /kgal
0.029/kWh
2. 00 /MBtu
17. 00 /man-hr
Total % of average
annual annual revenue
cost. $ requirements
195,000
2.000
197,000
567,500
2,092,800
146,100
1,131,500
(119,600)
1,569,300
137,700
5,525,300
5,722,300
1.58
0.02
1.60
4.60
17.79
1.19
9.18
(0.60)
12.73
1.12
46.01
47.61
Indirect Costs
Capital charges
Depreciation, Interim replacements, and
insurance at 6.4Z of total depreciable
Investment
Average cost of capital and taxes at 8.6Z
of total capital investment
Overheads
Plant, 50Z of conversion costs less utilities
Administrative, 101 of operating labor
Marketing, 10Z of byproduct sales revenue
Total indirect costs
Cross average annual revenue requirements
Byproduct Sales Revenue
1002 sulfurlc acid 47,600 tons
Net annual revenue requirements
Equivalent unit revenue requirements
2,665,600
3,666,600
1,137,300
56,800
119,000
7,645,300
13,367,600
25.00/ton (1,190,000)
12,177,600
$/bbl oil $/MBtu heat
Mills/kWh burned input
3.48 2.28 0.38
21.63
29.76
9.23
0.46
0.97
62.04
109.65
(9.65)
100.00
$/ton
sulfur
removed
818
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plane, 25 yr.
Power unit on-strean time, 7,000 hr/yr.
Oil burned, 5,350,000 bbl/yr, 9,200 Btu/kUh.
Stack gas reheat to 175°F.
Sulfur removed, 14,880 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct Investment, $22,419,000; total depreciable investment, $41,650,000; and total
capital investment, $42,655,000.
All tons shown are 2,000 Ib.
292
-------
TABLE A-122
MAGNESIA PROCESS VARIATION FROM BASE CASE I OIL-FIREDt EXISTING REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 4263SOOO
to
vo
u>
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POMER TION, REQUIREMENT* CONSUMPTION* CONTROL
UNIT KW-HR/ MILLION BTU BARRELS OIL PROCESS* 100%
START KM /YEAR /YEAR TONS/YEAR SULFURIC ACIO
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
1QOX COMPANY,
SULFURIC ACIO S/YEAR
NET ANNUAL
TOTAL INCREASE
NET (DECREASE)
SALES IN COST OF
REVENUE. POMER,
f/VEAR S
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
S
1
2
3
4
5
6
7
e
9
10
11
12
13
14
15
16
17
ie
19
2fl_
21
22
23
24
25
26
27
28
29
3«__
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
350O
I SCO
1500
1500
1500
1500
1500
1900
1500
1500
1500
TOT 92500
LIFETIME
PROCESS COST
LEVELIZED
31500000 5208300 14900
31500000 5206300 14900
31500000 5206300 14900
31500000 5206300 14900
31500000 5200300 14900
22500000 3720200 10600
22500000 3720200 10600
22500000 3720200 10600
22500000 3720200 10600
7750000A 3720200 10600
1S750000 2604200 7400
15750000 2604200 7400
15750000 2604200 7400
15750000 2604200 7400
is75aaaa 2604200 7400
6750000 1116100 3200
6750000 1116100 3200
6750000 1116100 3200
6750000 1116100 3200
«7*oaao in«ioo 3200
6750000 1116100 3200
6750000 1116100 3200
6750000 1116100 3200
6750000 1116100 3200
6750000 1116100 3200
47600
47600
47600
47600
47600
34000
34000
34000
34000
34000
23800
23800
23800
23600
23800
10200
10200
10200
10200
10200
10200
10200
10200
10200
416250000 68S24500 196500 629000
AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU MEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.2% TO INITIAL YEAR, DOLLARS
INCREASE 1 DECREASE I IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22. SO
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
17193000
16906500
16619900
16333400
16046800
14145300
13858700
13572200
13285600
12999100
11433600
11147000
10860500
10573900
10287400
8115900
7629400
7542600
7256300
6969700
6683200
6396600
6110100
5823500
5537000
1071000
1071000
1071000
1071000
1071000
765000
765000
765000
765000
7651100
535500
535500
535500
535500
S35500
229500
229500
229500
229500
229500
229500
229500
229500
229500
229SOO
273527400 14152500
3.97 0.20
5.91 0.30
65.71 3.40
1392.00 72.03
113119800 6546800
DISCOUNTED PROCESS COST OVER LIFE OF
3.55 0.20
5.29 0.31
58.75 3.40
1244.44 72.02
16122000
15835500
15548900
15262400
14975800
13380300
13093700
12807200
12520600
12234100
10898100
10611500
10325000
10038400
9751900
7886400
7599900
7313300
7026800
6740200
6453700
6167100
5880600
5594000
5307500
259374900
3.77
5.61
62.31
1319.97
106573000
POWER UNIT
3.35
4.96
55.35
1172.42
16122000
31957500
47506400
62768800
7774.46PO
91124900
104218600
117025800
129546400
141760500
152678600
163290100
173615100
183653500
193405400
201291800
208691700
216205000
223231800
. 2.U9720QO
236425700
242592800
248473400
254067400
2S?374.?P.O
-------
TABLE A-123. MAGNESIA PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: wet scrubbing fly ash removal)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, 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 spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Fly ash removal (four scrubbers and entrainment separators,
tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator, and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfurlc acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfurlc acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
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
Interest during construction
Total depreciable Investment
ESP cost credit
Net depreciable Investment
Land
Working capital
Total capital investment
Investment , $
704,000
303,000
4,906,000
5,447,000
1,198,000
5,482,000
1,110,0.10
5,518,000
2,243,000
6,000,000
994 ,000
33,905,000
2,034,000
35,939,000
154,000
36,093,000
1.881,000
368,000
4,915,000
1,465,000
8,629,000
8,944,000
53,666,000
5 1 351 ,000
6,440,000
65,457,000
(9.614.000)
55,843,000
641,000
1,610,000
58,094,000
($116/kW)
% of
total direct
Investment
2.0
0.8
13.6
15.1
3.3
15.2
3.1
15,3
6.2
16.6
2.8
94.0
5.6
99.6
0.4
100.0
5.2
1.0
13.6
4.1
23.9
24.8
148.7
14.8
17.8
181.3
(26.6)
154.7
1.8
4.5
161.0
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaline
mid-1979. *'
Stack gas reheat to 175°F by Indirect stean reheat.
Minimum in-process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
294
-------
TABLE A-124. MAGNESIA PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: wet scrubbing fly ash removal)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Electricity credit (ESP)
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost. $
X of average
annual revenue
requirements
1,470 tons
1,800 liters
3,240 tons
300.00/ton
2.50/liter
15.00/ton
47,500 man-hr 12.50/man-hr
441,000
4,500
48.600
494,100
593,800
6,286,000 gal
503,400 MBtu
2,359,200 kgal
93.084,000 kWh
7,115,000 kWh
135,600 MBtu
8,860 man-hr
0.40/gal
2.00/MBtu
0.1 2 /kgal
0.029/kWh
0.029/kWh
2.00/MBtu
17.00/man-hr
2,514,400
1,006,800
283,100
2,699,400
(206,300)
(271,200)
2,520,400
150,600
9,291,000
9,785,100
2.53
0.03
0.28
2.84
3.41
14.46
5.79
1.63
15.52
(1.19)
(1.56)
14.49
0.87
53.42
56.26
Indirect Costs
Capital charges
Depreciation, Interim replacements, and
insurance at 6.OX of net depreciable
Investment
Average cost of capital and taxes at 8.6%
of total capital Investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10X of operating labor
Marketing, 10Z of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
3,350,600
4,996,100
1,632,400
59,400
270.000
10,308,500
20,093,600
19.26
28.72
9.39
0.34
1.55
59.26
115.52
Byproduct Sales Revenue
100Z sulfuric acid
Net annual revenue requirements
Equivalent unit revenue requirements
108,000 tons 25.00/ton (2,700
17,393
$/ton coal
Mllls/kWh burned
4.97 11.59
,000)
,600
$/MBtu heat
input
0.55
(15.52)
100.00
$/ton
sulfur
removed
501
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 Jons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
Sulfur removed, 34,750 short tons/yr.
Total direct Investment, $36,093,000; net depreciable Investment, $55,843,000; and total
capital investment, $58,094,000.
All tons shown are 2,000 Ib.
295
-------
TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
\ REPORT NO.
JEPA-600/7-80-Opl
4 TITLE AND SUBTITLE
Definitive SOx Control Process Evaluations:
Limestone, Lime, and Magnesia FGD Processes
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
January 1980
6. PERFORMING ORGANIZATION CODE
7 AL-THOHlS)
K.D.Anderson, J.W.Barrier, W.E.O'Brien, and
S. V.Tomlinson
9 PERFORMING ORGANIZATION NAME AND ADDRESS
TVA, Office of Power
Emission Control Development Projects
Muscle Shoals, Alabama 35660
8. PERFORMING ORGANIZATION REPORT NO.
ECDP-B7
1O. PROGRAM ELEMENT NO.
INE624A
11. CONTRACT/GRANT NO.
EPA IAG-D9-E721-BI
(TVA TV-41967A)
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final: 6/78 - 9/79
14. SPONSORING AGENCY CODE
EPA/600/13
15 SUPPLEMENTARY NOTES
919/541-2915.
IERL-RTP project officer is O.J. Chatlynne, Mail Drop 61,
16 ABSTRACT rpne repOrt gives economic and ground-to-ground energy evaluations of
limestone slurry, lime slurry, and magnesia (producing sulfuric acid) flue gas desul-
furization (FGD) processes. The lime slurry process, using purchased lime and
lime calcined onsite, remains lower in capital investment (90 #/kW for the base-case
500-MW power plant burning 3 .5% sulfur coal) than the limestone slurry process
(98 #AW). The limestone slurry process remains lower in annual revenue require-
ments (4.02 millsAWh) than the lime slurry process (4.25 millsAWh). The mag-
nesia process is about one-third higher in capital investment (132 $AW) and one-
fourth high in annual revenue requirements (5.05 mills AWh including credit for
acid sales) than the limestone slurry process, because of absorbent-recovery and
acid-producing complexities. The lime slurry process using purchased lime is more
economical than the limestone slurry process at low absorbent consumption rates
(below about 200 MW or 2% sulfur coal). Onsite lime calcination becomes economical
compared to purchased lime for larger power plants and higher coal sulfur levels
(about 1000 MW with 3. 5% sulfur coal, 750 MW with 5% sulfur coal). The limestone
slurry process has the lowest overall (raw material, FGD, and disposal) energy
requirements <26% less than lime and 30% less than magnesia).
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Flue Gases
Desulfurlzation
Sulfur Oxides
Calcium Carbonates
Calcium Oxides
Magnesium Oxides
Slurries
Scrubbers
b.IDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
c. COSATI Field/Group
13B
21B
07A,07D
07B
11G
131
DlS
Release to Public
19. SECURITY CLASS (This Report/
Unclassified
20 SECURITY CLASS (Thij page)
21. NO. OF PAGES'
325
Unclassified
22. PRICE
Form 2220-1 (»-7J)
296
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