EPA
TVA
United States
Environmental Protection
Agency
Industrial Environmental
Research Laboratory
Research Triangle Park, NC 27711
EPA-600/7-81-099
June 1981
Tennessee Valley
Authority
Office of Power
Energy Demonstrations
and Technology
Muscle Shoals, AL 35660
EDT-121
Definitive SOX Control
Process Evaluations:
Aqueous Carbonate and
Wellman-Lord (Acid, Allied Chemical,
and Resox) FGD Technologies
Jnteragency
Energy/Environment
R&D Program Report
-------
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.
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-600/7-81-099
TVA EDT-121
JUNE 1981
Definitive SOX Control
Process Evaluations:
Aqueous Carbonate and
Wellman-Lord (Acid, Allied Chemical,
and Resox) FGD Technologies
by
J. R. Byrd. K. D. Anderson.
S. V. Tomlinson, and R. L. Torstrick
TVA, Office of Power
Energy Demonstrations and Technology
Muscle Shoals, AL 35660
EPA-IAG-D9-E721-BI
Program Element No. INE827
EPA Project Officer: M. A. Maxwell
Industrial Environmental Research Laboratory
Office of Environment) Engineering and Technology
Research Triangle Park. NC 27711
Prepared for
U. S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington. DC 20460
fl.ff. Imdrorniffnial Protection
}•;-;•;-;:<• i :.'. LV,. -rv (,V"L~16)
iic^i „. .<... -...:,v.-.li '-••.-••^t, Boom 167Q
Chica.g'0,. XL
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DISCLAIMER
This report was prepared by the Tennessee Valley Authority and has
been reviewed by the Office of Energy, Minerals, and Industry, U.S.
Environmental Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the views and
policies of the Tennessee Valley Authority or the U.S. Environmental
Protection Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.
ii
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ABSTRACT
Economic evaluations were made of the Rockwell International aqueous
carbonate process (ACP) and versions of the Wellman-Lord process incorpora-
ting a sulfuric acid plant and the Foster Wheeler Resox® and Allied
Chemical coal reduction processes for sulfur production. The ACP uses a
spray dryer flue gas desulfurization (FGD) system and molten salt reduction
with coal to make sulfur. For a 500-MW power plant burning 3.5% sulfur
coal capital investments for the ACP and the Wellman-Lord acid, Resox,
and Allied processes are 119, 131, 138, and 141 $/kW respectively.
Annual revenue requirements are 4.81, 5.11, 6.03, and 5.94 mills/kWh
respectively. The ACP has a major cost advantage because it incorporates
final fly ash and chloride removal as process functions. Fly ash removal
credits and Wellman-Lord chloride control costs essentially determine
the capital investment relationships of the processes. The ACP has a
major advantage in annual revenue requirements because it does not need
process or reheat steam. Wellman-Lord process costs are the same for
all three versions. The cost differences result from end plant costs to
produce acid or sulfur. The cost relationship could be affected by
further development. The ACP, Resox, and Allied processes have not been
operated as commercial FGD systems.
iii
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Abstract
Figures
Tables .' . .
Abbreviations and Conversion
Executive Summary
Introduction . . .
Process Background ^nd Descrip
Sodium-Based FGD Processes .
Dry Absorption
The Rockwell International A
Wellman-Lord Process . . . .
Resox® Coal-Reduction Proces
Allied Chemical Coal/SC>2 Red
Glaus Process
Design and Economic Premises .
Design Premises
Emission Standards . . . .
Fuels
Power Plant Design . . . .
Power Plant Operation . .
Flue Gas Composition . . .
Removal Efficiencies . . .
Absorber Design
Reheat
Raw Materials
Waste Disposal
Case Variations . . . . .
Economic Premises . . . . .
Capital Investment , . . .
Annual Revenue Requirement
Byproduct Credits . . . .
Lifetime Revenue
Requiremei its
Systems Estimated
Aqueous Carbonate Process
Materials Handling Area
Gas Handling and Fly Ash C
S02 Absorption and Removal
CONTENTS
ic tors
:ion
iction Process
illection Areas
Areas
iii
vii
viii
x
xiii
1
3
3
4
6
8
11
12
13
15
15
16
16
17
17
18
21
21
23
23
23
24
24
26
28
30
30
32
32
49
49
49
-------
Reduction Area 50
Off-Gas Treatment Area 51
Carbonation Area 51
Sulfur Production and Storage Areas 52
Wellman-Lord Process 53
Wellman-Lord/Sulfuric Acid Process 53
Materials Handling Area 59
Gas Handling Area 59
Chloride Neutralization Area 59
S02 Absorption and Reheat Areas 74
Sulfate Crystallization Area 75
Regeneration Area 75
Sulfuric Acid Production Area 76
Storage Capacity 77
, Wellman-Lord/Resox Process 77
Sulfur Production Area 78
Storage Capacity 88
Wellman-Lord/Allied Chemical Coal/S02 Reduction Process ... 89
Sulfur Production Area 89
Storage Capacity 104
Results 105
Capital Investment 105
Case Variations 113
Annual Revenue Requirements 116
Case Variations 126
Lifetime Revenue Requirements 129
Variations in Economic Factors 136
Energy Requirements 140
Conclusions 143
Comparison with Previous Studies 145
Recommendations 147
References 148
Appendix A 153
VI
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Number
S-l Aqueous carbonate proces
S-2 Wellman-Lord, Resox, and
1 Aqueous carbonate proces
2 Aqueous carbonate proces;
3 Aqueous carbonate proces;
4 Aqueous carbonate proces;
5 Wellman-Lord process floi
6 Wellman-Lord process plo
7 Wellman-Lord process regi
8 Wellman-Lord process regi
9 Sulfuric acid unit flow i
10 Resox unit flow diagram
11 Resox unit layout drawin;
12 Allied Chemical coal/S02
13 Allied Chemical coal/S02
14 Effect of power plant si:
15 Effect of coal sulfur
16 Effect of power plant si
17 Effect of coal sulfur
Allied processes
3 flow diagram
s plot plan
elevation drawing
i regeneration area layout drawing-
diagram
: plan
>neration area elevation drawing
jneration area layout drawing ' • •
liagram
FIGURES
reduction unit flow diagram. . • •
reduction unit layout drawing. • •
;e on capital investment
content on capital investment ....
:e on annual revenue requirements •
content on annual revenue requirements
Page
xvi
xviii
33
37
38
39
54
60
61
62
63
80
83
91
95
114
115
127
128
vii
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TABLES
Number Page
S-l Capital Investment xxiii
S-2 Annual Revenue Requirements xxiv
S-3 Lifetime Revenue Requirements xxvii
1 Coal Compositions and Flow Rates at Varying Sulfur Levels ... 16
2 Oil Composition and Rate 17
3 Base-Case Flue Gas Composition and Rate 19
4 Flue Gas Compositions Without Emission Control Facilities ... 19
5 Power Plant Flue Gas and SC>2 Rates 20
6 Absorber Operating Conditions 22
7 Relative Quantities of Gas and Sulfur in Comparison with
Base-Case Quantities 25
8 Cost Indexes and Projections 26
9 Projected 1980 Unit Costs for Raw Materials, Labor,
Utilities, and Credits for Byproducts 29
10 Overall Annual Maintenance Costs 30
11 Annual Capital Charges for Power Industry Financing 31
12 Aqueous Carbonate Process Base-Case Material Balance 34
13 Aqueous Carbonate Process Base-Case Equipment List 40
14 Wellman-Lord/Sulfuric Acid Process Base-Case Material Balance • 55
15 Sulfuric Acid Unit Base-Case Material Balance 64
16 Wellman-Lord/Sulfuric Acid Process Base-Case Equipment List • • 65
17 Wellman-Lord Process Base-Case Material Balance for Resox Case 79
18 Resox Unit Base-Case Material Balance 81
19 Wellman-Lord/Resox Process Base-Case Equipment List 84
20 Wellman-Lord Process Base-Case Material Balance for
Allied Chemical Coal/S02 Reduction Case 90
21 Allied Chemical Coal/S02 Reduction Unit Base-Case
Material Balance 92
22 Wellman-Lord/Allied Chemical Coal/S02 Reduction Process
Base-Case Equipment List 96
23 Aqueous Carbonate Process Capital Investment 106
24 Wellman-Lord/Sulfuric Acid Process Capital Investment 107
25 Wellman-Lord/Resox Process Capital Investment 108
26 Wellman-Lord/Allied Chemical Coal/S02 Reduction Process
Capital Investment 109
27 Direct Capital Investment by Processing Area for New
500-MW Power Plants with 2.0%, 3.5%, and 5.0% Sulfur Coal . . Ill
28 Direct Capital Investment Costs by Processing Area for
Existing 200-MW, 500-MW, and 1000-MW Power Plants 112
viii
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TABLES (continued)
Number
29 Wellman-Lord Processes
and Fly Ash Removal •
30 Capital Investment by Pro
Power Plants
31 Aqueous Carbonate Process
32 Wellman-Lord/Sulfuric Acitl
33 Wellman-Lord/Resox Procesp
34 Wellman-Lord/Allied Chemi
Annual Revenue R«
35 Annual Revenue Requiremen
500-MW Power Plants with
36 Annual Revenue Requiremen
200-MW, 500-MW, and 1000
37 Wellman-Lord Processes
Wet-Scrubbing Fly Ash
38 Annual Revenue Requirement
Power Plants • •
39 Aqueous Carbonate Process
40 Wellman-Lord/Sulfuric
Requirements ....
41 Wellman-Lord/Resox Proces
42 Wellman-Lord/Allied
43 Effect of Cost Variations
on Annual Revenue Requir
44 Effect of Cost Variations
on Annual Revenue Requir
45 Importance of Annual
Different Power Plant
46 Energy Requirements •
Caiital
:s Process Cost Elements for New
2.0%, 3.5%, and 5.0% Sulfur Coal
: Cost Elements for Existing
•MW Power Plants
Anlual Revenue Requirements with
Removal . .
Cost Elements for Oil-Fired
Reveiue
Investment with Wet-Scrubbing
:essing Area for Oil-Fired
Annual Revenue Requirements • . .
Annual Revenue Requirements . . .
Annual Revenue Requirements • • •
:al Coal/S02 Reduction Process
Lifetime Revenue Requirements
Process Lifetime Revenue
Size
3 Lifetime Revenue Requirements . .
s Lifetime Revenue Requirements .
at Different Power Unit Sizes
sments
at Different Coal Sulfur Contents
sments
Requirement Cost Elements for
ze and Coal Sulfur Contents . . . .
117
118
119
120
121
122
124
125
130
131
132
133
134
135
137
138
139
141
IX
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ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
ac acre kWh
aft-Vmin actual cubic feet per Ib
minute L/G
bbl barrel
Btu British thermal unit
°F degrees Fahrenheit
dia diameter M
FGD flue gas desulfurization mi
ft feet mo
square feet MW
cubic feet ppm
gal gallon psig
gpm gallons per minute rpm
gr grain sec
hp horsepower sft-Vmin
hr hour
in. inch SS
k thousand yr
kW kilowatt
kilowatthour
pound
liquid-to-gas ratio in gallons
per thousand actual cubic
feet of gas at outlet
conditions
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
x
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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
equivalents.
British
Metric
ac
bbl
Btu
OF
ft
ft2
rtj
ft/min
ft3/min
gal
H- gpm
i gr
gr/ft3
hp
in.
Ib
lb/ft3
Ib/hr
psi
mi
rpm
sft3/min
ton
ton, long
ton/hr
acre
barrels of oila
British thermal unit
degrees Fahrenheit minus 32
feet
square feet
CUDIC feet
feet per minute
cubic feet per minute
gallons (U.S.)
gallons per minute
grains
grains per cubic foot
horsepower
inches
pounds
pounds per cubic foot
pounds per hour
pounds per square inch
miles
revolutions per minute
standard cubic feet per
minute (60°F)
tons (short)b
tons (long)b
tons per hour
a. Forty-two U.S. gallons per barrel of
b. All tons, including tons of sulfur,
0.405
158.97
0.252
0.5556
30.48
0.0929
U.UZOJZ
0.508
0.000472
3.785
0.06308
0.0648
2.288
0.746
2.54
0.4536
16.02
0.126
6895
1609
0.1047
1.6077
0.9072
1.016
0.252
oil.
are expressed
hectare
liters
kilocalories
degrees Celsius
centimeters
square meters
CUDIC meters
centimeters per second
cubic meters per second
liters
liters per second
grams
grams per cubic meter
kilowatts
centimeters
kilograms
kilograms per cubic meter
grams per second
pascals (newton per square meter)
meters
radians per second
normal cubic meters per
hour (0°C)
metric tons
metric tons
kilograms per second
in short tons in this report.
ha
L
kcal
°C
cm
m2
o —
m-"
cm/S
m3/s -
L
L/s
g
g/m3
kW
cm
kg
kg/mj
g/s
Pa (N/m2)
m
rad/s
m3/h
tonne
tonne
kg/s
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DEFINITIVE
AQUEOUS CA
(ACID, ALL
F
INTRODUCTION
For more than a decade, t
conducted a program of systema
utility flue gas desulfurizati
Many of these studies have bee
Protection Agency (EPA) as par
program. The analyses are has
utility power plant conditions
and most useful application an
so that comparisons among proc
applicable.
The basis of the analyses
a 500-MW power unit at a midwe
assess the effects of power un
ments, and other conditions li
based on regulated utility ecc
investment to construct the FG
operation.
This study is the third o
recent trends in FGD technolog
the Wellman—Lord process evalu
nologies, dry FGD processes us
sulfur from concentrated SC>2
PROCESS BACKGROUND AND DESCRII
The Rockwell Internationa
both spray dryer FGD and coal
in the earlier study, the Wei]
that is processed to sulfuric
incorporates numerous technics
CONTROL PROCESS EVALUATIONS;
.BONATE AND WELLMAN-LORD
!ED CHEMICAL, AND RESOX®)
ID TECHNOLOGIES
[ECUTIVE SUMMARY
Tennessee Valley Authority (TVA) has
;ic analysis of the economics of electric
(FGD) processes and related technology.
i sponsored by the U.S. Environmental
; of their FGD research and development
;d as closely as possible on current U.S.
in which FGD is likely to find the widest
1 conform to a consistent basis of analysis
;sses will be equitable and generally
is a conceptual design of the process for
stern coal-fired power plant. Case variations
it size and fuel conditions, FGD require-
cely to affect FGD costs. The FGD economics,
lomics, are developed for both capital
) system and revenue requirements for its
E a series begun in 1977 to evaluate
and energy use. In addition to updating
ition, it deals with two emerging tech-
Lng spray dryers and processes that produce
sing coal as the reducing agent.
CION
L aqueous carbonate process (AGP) combines
reduction to produce elemental sulfur. As
nan-Lord process is used to produce S02
acid or elemental sulfur. This study
L changes made in the Wellman-Lord process
xiii
-------
(R^
during the past few years. Both the Resox process, under development
by the Foster Wheeler Energy Corporation, and the Allied Chemical
coal/S02 reduction process, being developed by the Allied Chemical
Corporation,are end plants that process the off-gas of an FGD system to
sulfur. A sulfuric acid producing version of the process is included
for comparison.
The processes differ considerably in stage of development. -The
Wellman-Lord process is in commercial FGD use. Sulfuric acid plants and
the Glaus process used in the AGP and Allied unit are standard industrial
technology. The spray dryer portion of the AGP has had considerable
pilot-scale development but the recovery process has not yet been evaluated
as part of an FGD system. The Resox and Allied processes have been
developed on a pilot scale and the Resox unit has been operated as part
of an FGD demonstration system.
Aqueous Carbonate Process
Dry absorption FGD, in which the reaction products are collected as
dry particulate matter, has the potential of reducing or eliminating
several disadvantages of wet scrubbing FGD. Corrosion and scaling
associated with wet scrubbing and saturated flue gas are greatly reduced
or eliminated; flue gas pressure drops are reduced and handling and
processing of large volumes of liquid are eliminated; little or no flue
gas reheating is required. In addition, integration of fly ash removal
with the FGD system is easier. The high removal efficiencies and absorbent
utilization rates of wet scrubbing are, however, difficult or impossible
to attain under some conditions, particularly if the absorbent is injected
as a powder. Introduction of the absorbent in a limited quantity of
liquid using a spray dryer increases removal efficiency by improving
dispersion and allowing limited liquid phase reaction. Most of the
advantages of dry injection are retained since the liquid evaporates in
the spray dryer, producing particulate matter and leaving the flue gas
unsaturated.
The use of a highly reactive absorbent is important in dry absorption
FGD. Sodium-based absorbents are thus particularly attractive for dry
absorption FGD use. Soda ash is presently the most practical spray
dryer absorbent because it is a generally available industrial chemical
and less expensive than other suitable sodium compounds. Its cost,
however, makes recovery of the absorbent desirable in a generally appli-
cable FGD process, as it does in wet scrubbing processes. The most
direct route involves reduction to Na2S followed by carbonation to
produce Na2CC>3 and H2S. The salts are reduced in molten form because
they melt before efficient reaction temperatures are reached. The
procedures are well developed pulp and paper technology.
Rockwell International began studies of spray dryer FGD and molten
salt reduction of sodium sulfur salts in the early 1970's. The spray
dryer studies evolved into a waste-producing spray dryer FGD process
that has had extensive pilot-scale evaluation. Several full-sized units
xiv
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are being constructed. The same spray dryer technology is used in the
ACP. The reduction and regeneration portions of .the AGP have not been
integrated with the spray dryer portion of the process in an operating
FGD system; however, a demonstration-sized system is under construction.
A flow diagram for the ACP is shown in Figure S-l. Mechanical
collectors situated upstream from the power plant ID fans remove 85% of
the fly ash. The flue gas then enters the FGD pl'enum and is distributed
to the spray dryer - ESP trains. The flue gas enters at the top of the
cylindrical spray dryer and passes downward through an atomized solution
of Na2C03 produced by three rotary-disk atomizers. The solution is
evaporated in the dryer, forming particles of ^2803, some Na2S04, and
unreacted Na2C03 that are carried out through the conical bottom and
removed, with the remaining fly ash, in an ESP. The flue gas is cooled
to only 170°F and thus requires no reheating.
The particulate matter is pneumatically conveyed to storage bins
from which it is withdrawn, blended with finely ground power plant coal
in metered quantities, and pneumatically injected into the bottoms of
the reduction reactors. Each reactor is a refractory-lined vessel that
operates about one-half full of molten salt. Preheated air is also
blown into the bottom of the reactor to maintain the temperature at
1800°F by oxidation of some of the coal. The reduced salt, primarily
Na2S, overflows from the middle of the reactor and is quenched and
dissolved. The off-gas is cleaned by scrubbing with water for use in
the regeneration process as a C02 source. Since an appreciable quantity
of chlorides are vaporized in the reactors, the cleaning process also
serves as a chloride purge to control the level of chlorides in the
regeneration system.
The salt solution is treated in a series of liquid-phase, unheated
reactions, first in a precarbonator with recycled I^S to produce NaHS,
and then with off-gas and recycled C02 in a crystallizer and carbonator
to produce NaHC03 and H2S. The precarbonator contains a filter loop to
remove residual fly ash and reducer ash. Part of the I^S stream is
recycled to the precarbonator; the remainder is processed to sulfur in a
conventional Glaus unit. The NaHC03 is heated in a decomposer with
steam generated by the reactor off-gas coolers to produce CC^, which is
recycled to the carbonator, and Na2C03, which is reused in the spray
dryers.
Glaus Unit
The Glaus process is widely used for the catalytic vapor-stage
oxidation of I^S to sulfur. The feed stream is partially oxidized to
S(>2 at about 2000°F, directly forming a considerable percentage of
sulfur. The gas is cooled in steam boilers to condense and remove the
sulfur, then reheated to 450°F to 500 F and passed through a bed of
catalyst such as alumina where the t^S and S02 react to form sulfur and
H20. The off-gas is then cooled to 300°F in a steam boiler to remove
the sulfur. The gas is then passed through a second catalytic converter.
Two-stage conversion usually results in a total conversion of about 90%.
xv
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CYCLONES
FLUE GAS
Na2C03
SOLUTION
1
GAS CLEANING
C02
CLAUS UNIT
MAKE UP Na2C03
NaeC03 SOLUTION
SULFUR
CARBONATOR-
CRYSTALLIZER
NaHCO
DECOMPOSER
Figure S-l. Aqueous carbonate process.
-------
In FGD applications some variations from conventional Glaus plant
design are possible. In the Allied process the feed gas contains both
SC>2 and t^S and partial oxidation is not necessary. Additional converters
and tail-gas emission control are also not necessary for the AGP and
Allied processes because the tail gas can be returned to the FGD system.
Wellman-Lord
In addition to dry absorption methods described above, flue gas SC>2
can be removed and later regenerated (as a concentrated off-gas) in a
sodium-based wet scrubbing processes in which the absorption reaction
produces NaHSO-j. The NaHS03 can then be thermally decomposed to
and S02« The S02 can, by careful control of process conditions, be
either directly reduced to sulfur or converted to sulfuric acid. The
Wellman-Lord process included in this study is a wet scrubbing process
that uses a solution of Na2S03, formed by addition of soda ash to the
scrubbing liquid, as the absorbent. The absorbent is regenerated and
S02 is produced by heating it under vacuum in evaporators. Chloride
removal upstream of the FGD system is required in most applications to
prevent accumulation of corrosive chlorides in the scrubber liquid.
In addition removal of the sulfates which are formed by the oxidation of
sodium sulfite and also tend to accumulate in the scrubber liquid is
required.
The concentrated SC>2 off-gas can be used to produce sulfuric acid
in a conventional sulfuric acid unit or it can be reduced to sulfur.
For sulfuric acid production a single-contact, single-absorption acid
plant of conventional commercial design can be used. In the three
commercial utility applications of the process in the United States,
the S02 is reduced to sulfur by the Allied Chemical methane (natural-
gas) reduction process. Processes using coal, a more desirable reducing
agent because of its price and availability, are not in large-scale FGD
use but the Resox process and the Allied Chemical coal/S02 reduction
process have been evaluated on a pilot-plant, prototype, or smaller
scale.
The Wellman-Lord process, shown in Figure S-2, with the Resox and
Allied units, is similar for all three versions. Minor changes in flue
gas quantities, because of different quantities of tail gas returned
from the byproduct manufacturing area, and in off-gas composition,
because of different requirements in the byproduct manufacturing area,
are the only modifications. Neither has an appreciable effect on overall
design.
For the Wellman-Lord process, fly ash is first removed by the power
plant ESP's. The flue gas then enters the FGD system plenum and is
distributed to the absorber trains. Each train consists of a prescrubber
for chloride control, a cast concrete absorber containing three valve
trays and two chimney trays, a mist eliminator, a reheater, and an ID
booster fan. The scrubbing solution flows countercurrently through the
absorber without overall recycling although it is recirculated independ-
ently in each valve tray. The 862 in the flue gas reacts with the
solution to form NaHSC>3 and a small amount of
xvii
-------
H-
H-
PRESCRUB8ER-
ABSORBERS
REHEATERS
TO STACK
EVAPORATORS
CRYSTALLIZER
FLUE
GAS
vw
CHLORIDES
Na2S03
WELLMAN-LORD
CONDENSERS
—»
S02
STRIPPER
FEED HOPPER
CLAUS UNIT
"HRACITE »
REACTOR
S02 »
SPENT „_
ANTHRACITE
n
\ /
REA
COAL SAND^
CONDENSER -J-S— (^
e. »>TAIL GAS .,
1 COAL GRINDING
T HANDLING
SULFUR S02
CTOR COOLER-FILTERj-
~ *1
J~*lvJ *) 0.
WASTE
SOLIDS ^«
SULFUR
ALLIED
TA|L GAS
RESOX
Figure S-2. Wellman-Lord, Resox, and Allied processes.
-------
A portion of the absorber effluent is concentrated by evaporation
to selectively crystallize Na2S04, which is dried and stored as a by-
product. The evaporator effluent is recombined with the main absorber
effluent stream and they are heated to decompose the NaHS03 to
and S02- Two trains of double-effect evaporators are used. The first-
effect evaporators are steam heated to 205 F at 10 psia; the second-
effect evaporators are heated by first-effect vapor to 170 F at 4.5
psia. The uncondensed vapors from the second-effect evaporator heaters
and the second-effect evaporator vapors are passed through two-stage
condensers to reduce the H20 content. The condensate is combined with
the second-effect evaporator heater condensate and they are steam-
stripped to remove S02- The stripper overhead is returned to the second-
effect condensers . Further 1^0 is removed by compressing the vapor from
the second-effect condensers. The final S02 content of the off-gas is
controlled by the condenser design and operating conditions to meet the
byproduct manufacturing area requirements.
A purge stream is removed from the first-effect evaporator bottoms
to control ^28203 and combined with the Na2S04 stream to the dryer.
The evaporator bottoms, primarily Na2S03, are then combined and returned
to the absorbent preparation area. Sodium losses are replenished by
addition of Na2C03 to the scrubbing solution.
Sulfuric Acid Unit
A standard single-contact, single-absorption, 98% efficient acid
unit is used. Feed gas from the Wellman-Lord system contains 64 mole %
S02- The tail gas is returned to the flue gas ducts upstream from the
Wellman-Lord system.
Resox Unit
The Resox process, developed by Foster Wheeler Energy Corporation,
is based on the direct reduction of S02 by anthracite. The reactor
requires an H20:S02 molar ratio of 2:1 to 3:1 and careful control of
conditions to minimize formation of H2S. Anthracite is used because a
nonagglomerating coal is required.
The Resox unit contains three reactor modules, each containing four
reactor sections. The modules are refractory-lined carbon steel vessels
without internal compartmentalization. The individual reactors are
formed by four individual anthracite feed tubes and four discharge
hoppers on each module. Anthracite is conveyed to hoppers above each
feed tube and fills the reactor. Spent anthracite is withdrawn from the
discharge hoppers at a controlled rate to provide approximately 2 moles
of carbon per mole of S02- The anthracite in the feed tubes and discharge
hoppers serves as a gas seal.
The feed gas from the Wellman-Lord system contains 40 mole % S02
and 60 mole % H20. The remaining H20 to achieve the 2:1 E^O to SC>2 ratio
for optimum conversion is provided by the incinerator gas, anthracite
moisture, and the combustion of anthracite. A small amount of air is
xix
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added to maintain the reactor temperature and the gas is heated to 750 F
by injection of incinerator gas. The gas is then injected into the
reactors through a manifold system near the vertical midpoint and flows
upward, rising to a temperature of about 1300 F in the main reaction
zone. Most of the S02 is reduced to sulfur vapor. The off-gas contains
8% to 10% S2. The remainder is H20, C02, N2, and small amounts of S02,
H2S, and other sulfur compounds. It leaves the reactor at about 700°F and
passes through a shell and tube heat exchanger where the sulfur is
condensed and removed. The remaining gas is incinerated to convert the
sulfur compounds to S02 and returned to the flue gas ducts upstream from
the Wellman-Lord system.
Allied Unit
The Allied unit has coal grinding and drying equipment and handling
equipment to blend it with a small amount of makeup silica sand to form
the reducing medium. The type of coal and the S02:H20 ratio are not
critical. Power plant coal is ground and dried in an impact mill in an
inert gas atmosphere and collected in a cyclone collector followed by a
bag filter. Some of the wet inert gas is vented and the rest is dried
for reuse and for blanketing in the storage and feed system. The ground
coal is conveyed from a storage bin to consecutive reactor feed hoppers
isolated by gas locks so that the reactor can be charged at the 24 psia
reactor pressure. From the second lock hopper the coal-sand mixture is
fed to the reactor by screw conveyor. The coal rate is controlled to
provide a 1.3:1.1:1.0 ratio of C:H2:S02.
A single refractory-lined reactor is used. A small amount of air
to maintain the reactor temperature at 1500°F to 1800°F is mixed with
the 85 mole % S02 feed gas from the Wellman-Lord system and injected
into the bottom of the reactor. The gas fluidizes the coal-sand mixture
and rises to 1500°F to 1800°F as it flows through the bed. The portion
of the reactor above the bed is enlarged to reduce particulate matter
carryover and increase the reaction time. Most of the particulate
matter in the gas leaving the reactor is removed in a cyclone separator.
The gas consists of about 15% S2, 7% H2S, 55% C02, H20, N2, and minor
amounts of other sulfur compounds.
The gas is scrubbed with liquid sulfur in a venturi scrubber to
condense the sulfur vapor and remove particulate matter. The gas is
then passed through a Glaus unit to convert the H2S to sulfur. The
Glaus unit tail gas is incinerated and returned to the flue gas ducts
upstream from the Wellman-Lord system. A portion of the liquid sulfur
from the sulfur scrubber is cooled and used in the scrubber. The
remainder is filtered, combined with the Glaus unit sulfur, and pumped
to storage.
xx
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PREMISES
These processes are evaluated on the same set of design and economic
premises used in the two earlier studies of this series.
Design Premises
The base case is a new 500-MW frontal-fired power unit burning
10,500 Btu/lb pulverized coal containing 3.5% sulfur and 16% ash. It is
assumed that 95% of the sulfur is emitted as SOX (99% S02) and 80% of
the ash is emitted as fly ash. Emission control facilities are designed
to meet the 1971 new-source performance standards (NSPS) of 1.2 Ib of
S02 and 0.1 Ib of particulate matter per MBtu of heat input. [The revised
NSPS (1979) were promulgated after this study was initiated and underway;
impacts of the revised NSPS are therefore not included in this report.]
The power unit is assumed to have a 30-year, 127,500-hour life and to
operate 7,000 hours the first year. Power unit case variations consist
of new and existing (20-year life) 200-MW units, an existing (25-year
life) 500-MW unit, new and existing (25-year life) 1,000-MW units, 2%
and 5% sulfur coal, and an existing (25-year life) 500-MW unit fired
with 2.5% sulfur oil.
FGD system design is based on vendor information and appropriate
industry design practice. The system begins with a plenum downstream
from the power unit ID fans and ends with ducting to the stack plenum.
Two absorber trains are used for 200-MW units and four trains for 500-
and 1000-MW units. No spares or bypasses are used. For the AGP,
mechanical fly ash collectors upstream from the power unit ID fans are
also included. Each ACP absorber train consists of a mechanical collector,
a spray dryer, an ESP, and an ID booster fan. Each Wellman-Lord absorber
train consists of a FD booster fan, a chloride prescrubber, an S02
absorber, and a flue gas reheater. The regeneration systems are generally
single-train designs except for some subsystems. FGD case variations
consist of wet-scrubbing fly ash removal, 90% S02 removal, and Resox and
Allied units sized for the same quantities of sulfur production at 90%
of the design conversion efficiencies. [Since neither of these processes
represent proven technologies, this case will show the effect on the
process economics if the Resox or Allied units achieve only 90% of the
design conversion of S02 to sulfur.]
Fly ash removal costs are not included in the base-case Wellman-
Lord process FGD costs. Since ESP's are an inherent part of the ACP, a
credit is applied to the ACP costs for new plants because separate ESP's
for fly ash removal are unnecessary. For existing plants it is assumed
that the ESP's are already installed and only ESP operating costs are
credited.
Economic Premises
The economic premises provide for determination of the capital
investment for installation of the FGD system and revenue requirements
xxi
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for its operation. The premises are based on a regulated utility with a
60% debt, 40% equity capital structure. Costs are based on vendor
information, TVA data, and published information.
Capital investment costs consist of direct costs, indirect costs,
land, and working capital. The costs are projected to mid-1979, repre-
senting a mid-1977 to mid-1980 construction period with a 50% expenditure
by mid-1979. Direct capital costs cover process equipment, piping and
insulation, foundations and structural, excavation and site preparation,
roads and railroads, electrical equipment, instrumentation, and buildings.
Indirect capital costs consist of engineering design and super-
vision, architect and engineering contractor expenses, construction
expenses, contractor fees, contingency, allowance for startup and modifi-
cations, and interest during construction. Working capital and land
costs are included separately.
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 into direct costs for raw materials,
labor, utilities, maintenance, and analyses and indirect costs for
capital charges, overheads, and byproduct marketing costs. Byproduct
sales revenue is deducted from the total cost to obtain the net annual
revenue requirements. Byproduct credit is given for sulfur, sulfuric
acid, sodium sulfate, and spent anthracite.
RESULTS
The capital investment results are summarized in Table S-l and the
annual revenue requirements are summarized in Table S-2.
Capital Investment
The AGP has the lowest capital investment for new plants (119 $/kW
for the 500-MW base case), followed in order of increasing capital
investment by the Wellman-Lord/sulfuric acid (131 $/kW), Wellman-Lord/Resox
(138 $/kW), and Wellman-Lord/Allied (141 $/kW) processes. For existing
plants, the Wellman-Lord/sulfuric acid process has the lowest capital
investment (132 $/kW for the 500-MW case), followed by the ACP (136 $/kW),
Wellman-Lord/Resox process (139 $/kW), and the Wellman-Lord/Allied
process (142 $/kW). The range is not large, however. For the base case
the maximum difference is 18% and for all existing plants the maximum
difference is 11%.
The major cost differences between the ACP and the Wellman-Lord
processes lie in the ESP credit given to the ACP for new plant installa-
tions and the chloride removal equipment of the Wellman-Lord processes.
For the base cases, the direct cost ESP credit is 9.4 $/kW and the
chloride removal direct cost is 9.8 $/kW. For existing plants, in which
xxii
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TABLE S-l. CAPITAL INVESTMENT
X
X
H-
H-
H-
Case
Coal-Fired Power Unit
1.2 Ib S02 /MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW, 3.5% sulfur
500 MW, 3.5% sulfur
500 MW, 2.0% sulfur
6 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
1,000 MW, 3.5% sulfur
1,000 MW, 3.5% sulfur
90% S02 removal
500 MW, 3.5% sulfur
Lower (90% of base case)
sulfur conversion factor
Wet-scrubbing fly ash
removal
Oil-Fired Power Unit
0.8 Ib S02 /MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
Years
remaining
lifea
20
30
25
30
30
30
25
30
30
30
30
25
ACP
k$
34,841
30,670
68,249
43,583
59,702
71,410
109,563
93,161
62,886
-
—
49,199
We llman-Lo r d /
sulfuric acid
$/kW
174
153
136
87
119
143
110
93
126
-
—
98
k$
34,207
33,578
66,227
51,633
65,360
76,779
103,691
101,411
68,475
-
58,178
40,379
$/kW
171
168
132
103
131
154
104
101
137
-
116
81
Wellman-Lord/
Resox
k$
36,119
35,447
69,690
53,627
68,771
81,371
109,166
106,776
72,198
71,240
61,641
42,324
$/kW
181
177
139
107
138
163
109
107
144
142
123
85
Wellman-Lord/
Allied
k$
37,994
37,428
71,167
55,578
70,338
82,323
109,247
107,148
73,643
72,655
63,217
44,074
$/kW
190
187
142
111
141
165
109
107
147
145
126
88
Basis: Midwestern power plant, mid-1979 costs.
a. A 127,500-hour, 30-year lifetime is used. FGD facilities for cases with 30 years of remaining life
are constructed simultaneously with the power plant; others are retrofit installations.
-------
TABLE S-2. ANNUAL REVENUE REQUIREMENTS
Case
Years
remaining
life3
ACP
Mills/
k$ kWh
Wellman-Lord/
sulfuric acid
Mills/
k$ kWh
Wellman-Lord/
Resox
Mills/
k$ kWh
Wellman-Lord/
Allied
Mills/
k$ kWh
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur 20
200 MW, 3.5% sulfur 30
500 MW, 3.5% sulfur 25
500 MW, 2.0% sulfur 30
o 500 MW, 3.5% sulfur 30
500 MW, 5.0% sulfur 30
1,000 MW, 3.5% sulfur 25
1,000 MW, 3.5% sulfur 30
90% S02 removal
500 MW, 3.5% sulfur 30
Lower (90% of base case)
sulfur conversion factor 30
Wet-scrubbing fly ash
removal 30
10,010
8,724
18,957
12,026
7.15
6.23
5.42
3.44
9,659
9,140
18,415
14,071
6.90
6.53
5.26
4.02
11,141
10,558
21,709
15,629
7.96
7.54
6.20
4.47
11,277
10,702
21,366
15,720
8.05
7.64
6.10
4.49
16,820 4.81 17,892 5.11 21,107 6.03 20,788 5.94
20,708
30,427
26,517
17,851
92
35
3.79
21,220
29,464
28,363
6.06
4.21
4.05
5.10 18,764 5.36
26,044
35,615
34,303
22,393
22,140
7.44
5.09
4.90
6.40
6.33
25,267
34,386
33,167
17,310 4.95 20,530 5.87
21,709
20,212
7.22
4.91
4.74
21,965 6.28
6.20
5.77
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
13,254
3.79 11,993 3.43
13,501
3.!
13,571
Basis: Midwestern power plant, mid-1980 costs.
a. A 127,500-hour, 30-year lifetime is used. FGD facilities for cases with 30 years of remaining life are
constructed simultaneously with the power plant; others are retrofit installations.
-------
the ESP credit is not given, there is little difference in capital
investment between the ACP and the Wellman-Lord processes. For the oil-
fired case, an existing plant that does not require chloride removal,
the ACP has the highest capital investment.
In comparison of direct costs by processing area, the three Wellman-
Lord processes are equivalent in all areas except byproduct manufacturing.
The different off-gas and tail-gas compositions for the three end plants
have little effect on the Wellman-Lord process costs. The ACP has
slightly higher gas handling costs because of the additional ESP ductwork.
The ACP absorption-collection-area costs are about twice those of the
Wellman-Lord processes because of the ESP's included. With the ESP
credit for new plants applied to this area, the costs are equivalent to
the Wellman-Lord absorption-collection area. Chloride removal is an
important Wellman-Lord processing area cost, similar in costs to the S02
absorption-collection area. Regeneration area costs are about one-third
higher for the ACP but the ACP costs include chloride removal. Conversely,
the ACP byproduct manufacturing area costs are much lower than the
Wellman-Lord byproduct manufacturing area costs. The combined regenera-
tion and byproduct manufacturing area costs are similar for the ACP and
Wellman-Lord processes.
In comparison of the byproduct manufacturing area costs of the
three Wellman-Lord processes, the sulfuric acid version is lowest and
the Resox and Allied versions 22% and 35% higher. The Resox unit has
higher reactor costs because of complex piping and support structure.
The Allied unit, however, has higher coal grinding and sulfur collection
costs.
In case variations, increasing power unit size results in economies
of scale, in terms of FGD cost per unit of power capacity, for all
processes. Increasing coal sulfur content from 2% to 5% increases ACP
capital investment about two-thirds and the Wellman-Lord processes
capital investment about 50%. The larger ACP increase occurs because a
larger percentage of its costs is directly related to sulfur rates.
SOX removal efficiencies and S02 conversion efficiencies have little
effect on capital investment. Combined wet-scrubbing fly ash and chloride
removal increase the prescrubber costs only 8%, by 0.8 $/kW. Applying
an ESP credit of 9.4 $/kW results in a substantial reduction in overall
fly ash and SOX emission control costs for the Wellman-Lord processes.
Capital investment for all processes is lower for the oil-fired
case than for the base case because of lower flue gas and sulfur rates.
The Wellman-Lord processes capital investments are further reduced
because chloride removal is not required.
Annual Revenue Requirements
The annual revenue requirements for the ACP and Wellman-Lord
processes follow the same general pattern as capital investments for new
and existing plants because of the indirect costs based on capital
investment. For the 500-MW base cases, the annual revenue requirements
xxv
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for the AGP are 4.81 mills/kWh, followed by the Wellman-Lord/sulfuric
acid process at 5.11 mills/kWh, the Wellman-Lord/Allied process at 5.94
mills/kWh, and the Wellman-Lord/Resox process at 6.03 mills/kWh. Direct
costs, consisting of raw material and conversion costs, for the. ACP are
one-fifth to two-fifths lower in all cases. Reducing coal costs are the
largest raw material cost for all three sulfur-producing processes. The
ACP utility costs are one-half those of the Wellman-Lord processes,
primarily because it requires no process and reheat steam. About one-
third of its utility requirements are for fuel oil, however. Fuel oil
price increases could increase ACP utility costs disproportionally,
compared with the Wellman-Lord processes.
Among the Wellman-Lord processes, the sulfuric acid version has the
lowest annual revenue requirements because of lower raw material costs,
lower byproduct manufacturing costs, and a higher byproduct credit. The
Allied version has slightly lower annual revenue requirements than the
Resox version. This is largely because of lower raw material costs for
reducing coal for the Allied version, and in spite of the additional
byproduct credit to the Resox version for spent anthracite.
The annual revenue requirements for the FGD processes are sensitive
to unit size and coal sulfur level and are relatively insensitive to
increased SOX removal efficiency, reduced S02 conversion, and combined
wet-scrubbing fly ash removal. The annual revenue requirements for each
of the FGD processes approximately triple as the power unit size increases
from 200 to 1000 MW. The economy of scale for the larger units results
from more efficient use of labor, supervision, and maintenance and lower
indirect costs. Annual revenue requirements increase 70% for the ACP
and 50% to 60% for the Wellman-Lord processes as coal sulfur content
increases from 2% to 5%. Raw material costs more than triple; utility,
labor, supervision, and maintenance costs double; indirect costs increase
one-half; and byproduct credits more than triple. For the oil-fired
case the three sulfur-producing processes are essentially equivalent in
annual revenue requirements, primarily because of reduced indirect costs
for the Wellman-Lord versions.
Energy requirements for the ACP are about one-third those of the
Wellman-Lord processes, primarily because it does not require steam.
About one-third of its energy requirements are in the form of fuel oil,
however. The gross energy requirements, primarily steam and electricity,
are similar for the three Wellman-Lord processes. An ene~gy credit for
spent anthracite reduces the Resox version energy requirements about
one-fifth, however.
Lifetime Revenue Requirements
The lifetime revenue requirements are shown in Table S-3. The cost
relationships are similar to those of the annual revenue requirements
but higher because of the declining operating schedule with increasing
age.
xxvi
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TABLE S-3. LIFETIME REVENUE REQUIREMENTS
Case
Coal-Fired Power
Unit
Years
remaining
life3
Mills /kWh
ACP
Actual
LevelizedD
Wellman-Lord/sulfuric acid Wellman-Lord/Resox
Actual
Levelizedb
Actual
Levelized"
Wellman-Lord/Allied
Actual Levelizedb
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW,
200 MW,
500 MW,
500 MW,
« 500 MW,
500 MW,
1,000 MW,
1,000 MW,
3.5%
3.5%
3.5%
2.0%
3.5%
5.0%
3.5%
3.5%
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
20
30
25
30
30
30
25
30
14.88
8.81
8.79
4.88
6.77
8.26
7.01
5.30
13.52
8.80
8.78
4.43
6.17
7.55
6.23
4.85
14.36
9.28
8.49
5.69
7.22
8.54
6.71
5.67
13.07
8.45
7.54
5.19
6.60
7.81
5.98
5.20
15.82
10.45
9.61
6.20
8.26
10.08
7.73
6.61
14.47
9.57
8.60
5.68
7.59
9.29
6.96
6.11
16.32
10.71
9.58
6.29
8.22
9.89
7.56
6.46
14.90
9.78
8.56
5.75
7.54
9.10
6.79
5.96
90% S02 removal
500 MW, 3.5% sulfur 30
Lower (90% of base case)
sulftfr conversion factor 30
Wet-scrubbing fly ash
removal 30
7.17
6.54
7.57
6.92
6.84
6.27
8.74
6.43
7.87
8.04
7.23
7.27
8.66
5.55
7.83
7.95
7.86
7.21
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
6.23
5.50
5.42
4.82
5.95
5.33
6.05
5.41
a. Plants with 30 years of remaining life are new, with 127,500 hours of operating life. Plants with 25 years of remaining life
have 92,500 hours of operating life. Plants with 20 years of remaining life have 57,500 hours of operating life.
b. Discounted at 11.6%.
-------
CONCLUSIONS
Integration of fly ash and chloride removal functions with the FGD
process is a major factor in the capital investment relationships of the
ACP and the Wellman-Lord processes. Actual capital investments, exclusive
of ESP credits, are similar for both processes. Under various circum-
stances in which fly ash removal credits and chloride removal requirements
differ either the ACP or the Wellman-Lord process could have the lower
capital investment.
The annual revenue requirements follow the same general relationships
among the processes as the capital investments as a result of indirect
costs related to capital investment. The ACP is substantially lower in
direct costs than the three Wellman-Lord processes, primarily because it
does not require process or reheat steam. Among the larger direct cost
elements of annual revenue requirements of all four processes are
maintenance, operating labor and supervision, electricity, steam, raw
materials, and byproduct credit.
Energy requirements for the ACP are much lower than those of the
Wellman-Lord processes because it does not require process and reheat
steam. The gross energy requirements (without byproduct energy credits)
of the three Wellman-Lord processes are similar.
Insofar as stage of development may be likely to affect cost relation-
ships, the ACP can be considered most susceptible to cost changes because
the regeneration system has not been demonstrated in a utility FGD
installation. The Resox and Allied units are in a similar stage of
development but represent a smaller portion of the overall FGD costs.
COMPARISON WITH PREVIOUS STUDIES
In the previous studies of this series five other processes were
evaluated using the same premises. Three, the limestone, lime, and
double alkali processes, produce a waste slurry that is disposed of in
a pond. A slurry of magnesium oxide is used as the scrubbing medium in
the magnesia process. The spent slurry is dewatered, dried, and
thermally decomposed to regenerate the magnesium oxide and produce S02
which is converted to sulfuric acid in a conventional acid plant. The
citrate process is a wet scrubbing process using a sodium citrate solution
as the absorbent. The absorbent is regenerated and the SOX compounds
reduced to elemental sulfur by liquid-phase reduction using H2S. The
H2S is produced by reducing some of the product sulfur using natural
gas.
The base-case costs for each of the nine processes are shown below.
Except for the ACP the costs fall into separate groupings of waste-,
acid-, and sulfur-producing processes in both capital investment and
annual revenue requirements. The difference in cost between the waste-
producing and acid-producing processes is essentially for absorbent
regeneration; ponding costs and acid plant costs do not differ greatly
xxviii
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and raw material costs do not differ sufficiently to produce large cost
differences. The higher costs for sulfur-producing processes are the
result of the added costs for reduction of sulfur oxides. Here coal
reduction holds a strong advantage over other fossil reducing agents.
In the citrate process, 16% of the annual revenue requirements are for
natural gas to produce H2S.
FGD process economics5
Annual
Capital investment, revenue requirement,
$/kW mills/kWh
Waste Processes
Limestone 98 4.02
Lime 90 4.25
Double alkali 101 4.19
Sulfuric Acid Processes
Magnesia 132 5.08
WeiIman-Lord/sulfuric acid 131 5.11
Sulfur Processes
ACP 119 4.81
Wellman-Lord/Resox 138 6.03
Wellman-Lord/Allied 141 5.94
Citrate 143 6.44
a. Although the accuracy limits associated with cost estimates of this
type are normally -20, +40%, when comparing FGD process cost
estimates of similar type, the accuracy limits are on the order
of ±10%.
The lower costs for the ACP compared with the other sulfur-producing
processes are largely the result of the combination of fly ash and SOX
particulate matter removal. For the existing plant case variation,
which mainly differs from the base case in having no ESP credit, the ACP
capital investment is 136 $/kW and the annual revenue requirements are
5.42 mills/kWh.
xxix
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RECOMMENDATIONS
The nine processes in this series of evaluations are in diverse
stages of continuing development. Future design and operating information
will probably have important economic effects, as will economic and
environmental regulation changes. The processes evaluated in this
series should be monitored and reassessed as further information becomes
available. The cost relationships of well-developed, waste-producing
processes should be reassessed in respect to changing waste-disposal
practices. The economic effects of the quantities and types of energy
requirements should also continue to be emphasized.
xxx
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DEFINITIVE SOX CONTROL PROCESS EVALUATIONS:
AQUEOUS CARBONATE AND WELLMAN-LORD
(ACID, ALLIED CHEMICAL, AND RESOX®)
FGD TECHNOLOGIES
INTRODUCTION
For more than a decade, the Tennessee Valley Authority (TVA) has
conducted a program of systematic analysis of the economics of flue gas
desulfurization (FGD) processes and related technology for electric
utility power plants. During this period both the comprehensive environ-
mental legislation now regulating sulfur oxides (SOX) emissions and much
of the FGD technology to conform to the regulations have evolved. TVA's
economic evaluation procedures have similarly evolved and expanded to
meet the demands of legislative, technical, and economic changes. Many
of these studies have been sponsored by the U.S. Environmental Protection
Agency (EPA) as part of its FGD research and development program. The
basic objective is, first, to present economic analyses based as closely
as possible on current U.S. utility power plant conditions in which FGD
is likely to find the widest and most useful application and, second, to
conform to a consistent basis of analysis so that comparisons among
processes will be both equitable and generally applicable.
The basis of the analyses is a conceptual design of a process for
a 500-MW power unit at a midwestern coal-fired power plant. From this
base-case condition, case variations are developed to assess the effects
of power unit size and fuel conditions, FGD requirements, and other
conditions likely to affect FGD costs. The FGD economics are based on
regulated utility economics. They are developed for both capital invest-
ment to construct the FGD system and revenue requirements for its operation.
For most of these studies the FGD design is based on control of SOX and
particulate matter emission to meet the 1.2 Ib of S02 and 0.1 Ib of
particulate matter per MBtu of heat input promulgated by the 1971 new-
source performance standards (Federal Register, 1971). The more stringent
revised new-source performance standards (NSPS) promulgated in 1979 (Federal
Register, 1979) will apply to new power plants coming on line by the
mid-1980fs, beyond the period upon which this study is based.
For many of these studies the limestone wet scrubbing process has
served as a standard against which other FGD processes could be compared.
Although this widely used and relatively economical process still serves
as a useful standard, the increasing comprehensiveness of environmental
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regulations and the growth of FGD technology now often demand more
complex comparisons. The growing recognition of the economic and
legislative restrictions on waste disposal may, for example, require a
careful economic assessment of numerous process variations. The emerging
spray dryer FGD technology has the promise of reducing many characteristic
disadvantages of wet scrubbing processes. The continuing development of
regeneration processes offers an increasingly diverse selection of
alternates to waste-producing processes. Not only the quantity but the
type of raw materials and utilities required have also become increasingly
important as energy costs have risen.
This study is the third of a series begun in 1977 to evaluate
recent trends in FGD technology and energy use. The first two studies
(Tomlinson et al., 1979; Anderson et al., 1980) dealt with both new and
updated FGD processes and also addressed the question of overall energy
consumption of FGD processes. This study deals with two emerging tech-
nologies, the so-called dry FGD processes using spray dryers and processes
that produce sulfur from concentrated S0% using coal as the reducing
agent. Spray dryer FGD has developed rapidly in the past few years. It
holds promise of avoiding the large volumes of liquid and related corrosion,
scaling, and flue gas reheating that are associated with wet scrubbing
FGD. Its removal efficiency with high-sulfur coals remains to be
demonstrated, however. The use of coal as a reducing agent similarly
holds promise as a method of avoiding the use of scarce and cost-sensitive
reducing agents such as natural gas. Although such use of coal is not a
new technology it has only recently been applied to FGD processes in a
systematic manner.
The Rockwell International aqueous carbonate process (ACP) combines
both spray dryer FGD and coal reduction. It is presently the most
advanced of spray dryer regeneration processes and the only one to have
advanced to the construction of a demonstration unit. Both the Resox"
process, under developmemt by the Foster Wheeler Energy Corporation, and
the Allied Chemical coal/S02 reduction process, being developed by the
Allied Chemical Corporation, are in an intermediate stage of development.
Both are end plants, in the manner of a sulfuric acid plant or a Glaus
plant, that process the off-gas of an FGD system. The Wellman-Lord
process is used in this study for the FGD system. It is one of the most
advanced of regeneration FGD processes and has been evaluated in earlier
TVA economic studies (McGlamery et al., 1975) and by others (Beychok,
1980). It is included in this study because of the numerous technical
changes made in the process since the earlier studies.
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PROCESS BACKGROUND AND DESCRIPTION
SODIUM-BASED FGD PROCESSES
Sodium-based FGD processes have not been widely used in electric
utility applications in spite of the favorable solubility and reactivity
characteristics of sodium-based absorbents. The high cost of sodium
absorbents, compared with limestone, or even lime, has been a deterent
to processes in which a sodium-salt waste is produced. Environmental
problems with the highly soluble sodium-salt waste could also be an
obstacle in some climates. Most sodium-based FGD processes are either
double-alkali or recovery processes. In the double-alkali processes,
the sodium-based scrubbing solution is treated with a precipitant such
as limestone or lime to form a calcium-sulfur salt waste and regenerate
the sodium solution for reuse. Variations of this process are offered
by several vendors (Kaplan, 1979). A generic double-alkali process was
evaluated in a previous study in this series of economic evaluations
(Tomlinson et al., 1979). In recovery processes the absorbent is also
recovered, but instead of a calcium-sulfur salt waste, sulfur or a
sulfur compound is produced.
Under some site-specific circumstances processes producing a
sodium-based waste have proved desirable. FGD systems using Na2C03 are
in operation at the Reid Gardner Station of Nevada Power where the waste
is disposed of in an evaporation pond. In addition, the dry absorbent
waste-producing processes based on sodium, which are discussed below,
have created considerable interest, particularly in the West. Waste-
producing sodium processes are thus far regional, however, confined to
locations where lower-cost natural sodium salts are available or where
low-sulfur coal reduces absorbent requirements, and where the climate
allays concerns about the soluble waste.
Among these sodium-based recovery processes producing a salable
byproduct, the Wellman-Lord process is the most widely used (Laseke and
Devitt, 1979). The Wellman-Lord process evaluated in this study is an
updated version of the one previously evaluated, using slightly different
design and economic premises, in an earlier TVA study (McGlamery et al.,
1975). The Rockwell International AGP, which is also evaluated in this
study, is the first sodium-based recovery process to use a spray dryer
for 862 removal. Another sodium-based, sulfur-producing process, the
citrate process, was evaluated in an earlier phase of these studies
(Tomlinson et al., 1979).
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Some sodium-based recovery processes are more adaptable to sulfur
production than to sulfuric acid production. The Wellman-Lord process,
which produces a concentrated SC>2 off -gas, can be adapted to either,
although the off-gas must be diluted for processing in a standard contact
acid plant. The AGP produces H^S, which can be converted to sulfur
using established technology. The citrate process is designed to produce
sulfur directly by reactions in solution. In contrast, processes producing
a dilute, 02-rich S02 off-gas such as the magnesia process (Anderson et
al., 1980) require further off-gas processing before the S02 can be
economically reduced to sulfur.
The reduction of sulfur from oxidized states to elemental sulfur,
either directly or through intermediates, is widely practiced in the
chemical industry. Several processes are used in the paper industry for
recovery of sulfur during regeneration of pulp digestion liquor (Tomlinson,
1968). The relatively straightforward reduction chemistry is complicated,
however, by the thermodynamic tendency for the sulfur to go to the
sulfide under many practical operating conditions. The proper feedstock
and careful control of conditions are necessary for the direct reduction
of sulfur oxides to elemental sulfur. However, if the sulfide species
is H2S, it can be readily oxidized to elemental sulfur by a number of
routes, including the familiar Glaus converter (Maddox and Burns, 1968)
widely used ifr industry.
The reduction of sulfur in the form of Na2S03 and Na2S04 presents
additional processing problems (Lowell, 1978). Unlike the sulfites and
sulfates of some cations, such as magnesium, which can be thermally
decomposed to the oxide and S02, the corresponding sodium salts melt and
disproportionate to Na2S and Na2SO^. Therefore the reduction must be
performed in a molten salt bath reactor at a high temperature. Since
much of the sulfur is reduced to the sulfide form, it must be oxidized
to elemental sulfur.
A number of processes exist for carbonation of Na2S solutions to
produce Na2C03 and elemental sulfur. Many of these are associated with
pulp liquor processing in the paper industry (Tomlinson, 1968). The
carbonation process used in the ACP is a variation of these processes,
developed specifically for the ACP.
DRY ABSORPTION
Dry absorption, or "dry sorption," has been described as "any
process that directly produces a dry product ..." (Lutz and Chatlynne,
1979). Included in this definition are processes using direct injection
of dry absorbents into the boiler or flue gas as well as processes which
use a spray dryer. Dry absorption processes have several potential
economic and technical advantages over wet FGD processes that have been
long recognized by those concerned with 862 emission control (Tennessee
Valley Authority, 1968). These advantages have been widely discussed
(Bechtel, 1976; Lutz and Chatlynne, 1979; Davis et al., 1979). Paramount
are the simplicity and operational flexibility of the process, reduced
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energy requirements, production of a dry product, and the opportunity
for simultaneous collection of fly ash and sulfur-salt waste.
Direct injection of lime was investigated in the early part of this
century (Air Pollution Control Association, 1977). Widespread interest,
however, paralleled the development of practical particulate matter
control devices for flue gas in the 1960's, particularly fabric filters.
The use of fabric filters for collection has the advantage of providing
additional contact of flue gas and unreacted absorbent as it passes
through the built-up solids on the filters. Bechtel (1976) has summarized
early electric utility investigations of direct injection of dry adsorbents
and the development of particulate matter control technology in utility
applications.
A number of absorbents were evaluated during these studies, including
dolomite, limestone, quicklime, hydrated lime, sodium bicarbonate, soda
ash, and nahcolite. Bechtel (1976) in summarizing these studies concluded
that only sodium-based absorbents were sufficiently reactive to warrant
further investigation in dry-injection FGD processes. Of the absorbents
tested, nahcolite (a naturally occurring sodium bicarbonate) proved most
effective, exceeding both soda ash and manufactured sodium bicarbonate
in removal efficiency. Nahcolite has, therefore, attracted much attention
for use in dry absorption FGD processes (Lutz et al., 1979; Rajaram et
al., 1979). Large reserves exist in Colorado but are not presently
mined because of economic and environmental uncertainties. Commercial
sodium bicarbonate is prohibitively expensive for use as a nonregenerated
absorbent and soda ash, although less expensive, is considerably less
efficient than sodium bicarbonate.
Notwithstanding the poor utilization rates and removal efficiencies
of most absorbents, the high cost of the most effective absorbents, and
the present unavailability of the most promising absorbent, development
work has continued (Lutz and Chatlynne, 1979). By the early 1970's,
however, the potential of dry-collection FGD processes demonstrated in
the early dry-injection studies had led to further refinements. One of
these was to increase the reactivity of the injected absorbent by
introducing it into the flue gas as a solution or slurry, with the
concentration adjusted for complete evaporation of the water before
collection of the resulting particles. The increase in efficiency
permits higher removal efficiencies and greater absorbent utilization,
thus expanding the scope of potential application to higher sulfur coals
as well as increasing the number of potential absorbents. Commercial
spray dryer technology was available for adaptation to this purpose. In
fact, spray dryers of sizes and types directly adaptable to FGD had been
in commercial use for decades before their use in FGD technology.
The union of spray drying and particulate matter collection, both
well-developed technologies, in an FGD process has proved fruitful.
Atomics International (then a separate division of Rockwell Inter-
national) began pilot-scale tests at Mohave Station in 1972 and at Bowen
Engineering, Inc., (now Stork-Bowen Engineering, Inc.) in 1973. By 1977,
in a joint venture with Wheelabrator-Frye, Rockwell International began
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operating a 3000-aft3/min pilot plant at the Leland Olds Station of the
Basin Electric Power Cooperative (Janssen and Eriksen, 1979). This was
a study for a nonregenerable FGD system to be installed at the Coyote
Station, a lignite-fired power plant planned by a consortium headed by the
Otter Tail Power Company. Soda ash, lime, fly ash, and lime - fly ash
mixtures were evaluated as absorbem.3, and an ESP and a baghouse for
particulate collection. As a result of this program, Rockwell Inter-
national and Wheelabrator-Frye received the contract for the FGD system
on the 410-MW Coyote Unit 1. The FGD system, scheduled for operation in
1981, will use soda ash as the absorbent and a fabric filter baghouse for
particulate collection.
Three other companies constructed pilot plants for the Coyote
project. Niro Atomizer, Inc., a spray dryer manufacturer, began research
on FGD in 1975. In 1977 they formed a joint venture with the Western
Precipitation Division of Joy Manufacturing Company to build a 20,000-
aft3/min pilot plant at the Hoot Lake Station of the Otter Tail Power
Company. Babcock and Wilcox operated an 8,000-acfm unit of the William J.
Neal No. 2 unit using an ESP for collection. The Carborundum Company
built a 10,000-acfm pilot plant at Leland Olds No. 1 using a De Laval
spray dryer and a baghouse for collection.
All of these pilot plants were installed on lignite-fired boilers
and the contracted commercial units will be on lignite-fired units. The
lignite sulfur contents will range from 0.88% to 0.54% and the removal
efficiencies from 62% to 85% (Smith et al., 1979). The spray-dryer
process has yet to be demonstrated on high-sulfur coals at removal
efficiencies sufficient to meet the revised NSPS (Federal Register,
1979) with economically acceptable absorbent utilization. Several other
companies are now investigating spray-dryer FGD technology. Most, but
not all, of these are involved with investigations using low-sulfur
western coals.
Spray-dryer FGD thus appears an attractive technology. However,
there are two problems associated with sodium-based spray dryer FGD that
seem unlikely to be alleviated by technical advances. These are the
high cost of the sodium-based absorbents and the solubility of the result-
ing sodium-salt wastes. As in the case of high-cost absorbents in wet
scrubbing processes there is the possibility of regenerating the absorbent
and producing a marketable sulfur compound. Thus far, the most advanced
of such processes is the ACP included in this study.
THE ROCKWELL INTERNATIONAL ACP
The ACP (see flow diagram, Figure 1) uses a spray-dryer system
similar to the one used in the Rockwell International/Wheelabrator Frye
two-stage open-loop process. In the ACP, however, some fly ash is
removed from the flue gas before it enters the spray dryer to facilitate
processing of the sodium-sulfur salts. Flue gas entering the spray
dryer contacts an atomized solution of soda ash. The process, contrary
to normal spray-drying technology, uses three rotary atomizers per dryer
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for redundancy and turndown capacity. Moore et al. (1979) have discussed
the rationale for the use of multiple atomizers. The S02 in the flue
gas reacts with the Na2C03 to form Na2S03 (and some Na2S04). The sulfur
salts and unreacted absorbent are converted to particulate matter as the
liquid evaporates and are collected, along with residual fly ash, in
conventional particulate matter removal equipment.
The collected particulate matter is combined with a carbon source
such as petroleum coke or coal and passed through a molten-salt reactor.
Sufficient excess carbon is added to maintain the reaction temperature
of 1700°F to 1900°F (927°C to 1038°C). Air is blown through the melt to
maintain the reaction temperature. The reactions, in simplified form,
are:
Na2S03(lq) + 3/2C(s) •*• Na2S(lq) + 3/2C02(g)
Na2S04(lq) + 2C(s) -> Na2S(lq) + 2C02(g)
C(s) + 02(g) -> C02(g) + heat
According to Gehri and Oldenkamp (1976), the Na2S03 probably does not
react directly but disproportionates to Na2S04. Also, the oxidation of
carbon probably proceeds along the pathway:
Na2S + 202 -»• Na2S04 + heat
Na2S04 + 2C -*• Na2S + 2C02
The overflow from the reducer—consisting of Na2S, fly ash, and
other impurities—is quenched, shattered with steam, and dissolved to
form a "green liquor." The green liquor is a highly alkaline solution
of sodium sulfide, and sodium hydrosulfide and sodium hydroxide formed
by hydrolysis of the sulfide. The green liquor (the name comes from
wood pulping technology in which the liquid is colored by iron compounds)
is treated in a precarbonator with a portion of the hydrogen sulfide
generated in later stages of the process to form NaHS:
Na2S(aq) + H2S(g) -»• 2NaHS(aq)
NaOH(aq) + H2S(g) -> NaHS(aq) + H20(aq)
The solution in the precarbonator is also circulated through a filter
loop to remove solids, mostly fly ash.
The NaHS is converted to NaHC03 and then to Na2C03 in a two-stage
process using C02 obtained from the reducer and decomposer off-gas. The
overall reactions are:
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NaHS(aq) + C02(g) + H20 -> NaHC03(aq) + H2S(g)
2NaHS(aq) + C02(g) + H20 -> Na2C03(aq) + 2H2S(g)
The H2S stream is divided, part returning to the precarbonator and the
remainder to a Glaus plant. The NaHC03 is then thermally decomposed in
a decomposer.
2NaHC03(aq) •> Na2C03(aq) + H20 + C02(g)
The Na2C03 solution, with makeup soda ash added, is reused in the process.
The reducer off-gas is used to heat the reducer air and produce
process steam before being scrubbed to remove particulate matter. The
cleaned gas, rich in C02, but also containing CO and H2S, is used in the
carbonation process. Because of the high temperature of the reduction
reaction, the off-gas is enriched in chlorides removed from the flue
gas. A stream withdrawn from the off-gas cooling tower thus serves as a
chloride purge. The process also includes a waste gas incinerator for
the Glaus plant tail gas, the precarbonator off-gas, and tail gas from
the reducer off-gas treatment system.
Rockwell International began development of the AGP regeneration
system in the early 1970's at their molten salt test facility. Pilot-
scale evaluations were made of molten-bath reduction of sodium-sulfur
salts using petroleum coke as the reducing agent. Separate tests were
made of the filtration characteristics of solutions of the reduced salt.
Although commercial processes exist for the processing of the reduced
salt, Rockwell developed their own proprietary process.
The AGP has not been demonstrated in its entirety in a power plant
installation. A 100-MW scrubbing, 60-MW regeneration unit is, however,
being installed at Niagara Mohawk Power Corporation's Huntley Steam
Station (Binns and Aldrich, 1978). Construction on the unit began in
1979.
WELLMAN-LORD PROCESS
The Wellman-Lord process (see flow diagram, Figure 5) was developed
by Davy Powergas in the mid-1960's as a potassium-based process (Sulfur,
1967). This version was tested on a pilot-plant scale at the Tampa
Electric Company and later at the Baltimore Gas and Electric Company.
The first sodium-based process was installed at an Olin Corporation
sulfuric acid plant at Paulsboro, New Jersey, in 1970. In the 1970's
the process was installed on a number of oil-fired boilers, sulfuric
acid plants, and Glaus plants in the United States and Japan. By 1978
twenty-four commercial installations were in operation, scrubbing 4.3
million sft3/min of gas (Davy Powergas, 1979). According to Davy
Powergas (Gaur, 1978) all of these units achieved greater than 90% S02
8
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removal efficiency and had an absorption-area on-stream efficiency of
over 97%. The largest of these applications is on a 220-MW oil-fired
peaking plant in Japan, in which the system has been able to successfully
follow load changes of 35% to 150% of rated capacity.
The first coal-fired boiler applications are now operating on a
115-MW unit at the Dean H. Mitchell Station of Northern Indiana Public
Service Company and on two units of about 350 MW each at the San Juan
Station of the Public Service Company of New Mexico. Two additional
units of over 1000 MW total capacity are under construction at the San
Juan plant (Smith et al., 1979).
The NIPSCO plant, amply described in the literature (Mann and
Christman, 1976; Ross et al., 1979; Link and Ponder, 1978), is a demon-
stration project partially funded by EPA to demonstrate an FGD process
producing elemental sulfur. The installation represented the first
combination of the Wellman-Lord process with the Allied Chemical methane
(natural-gas) reduction process. The unit was started up in 1977 and
has completed performance testing.
The Wellman-Lord process is a sodium-based process which utilizes
the inherent solubilities of sodium compounds as well as the relative
solubilities of the different species. The scrubbing medium is a solution
of Na2S03 that reacts with S02 absorbed from the flue gas to form NaHS03,
Na2S03(aq) + S02(aq) + H20 -> 2NaHS03(aq)
Because the bisulfite is about twice as soluble as the sulfite at the
absorber conditions used, a saturated scrubbing solution can be used
without formation of solids or potential scale formation in the absorber.
The use of a highly concentrated scrubbing solution, in addition to
reducing the quantity of liquor handled, reduces oxygen absorption, thus
reducing oxidation of the sulfite. Oxidation to sulfate occurs along
two pathways in the absorption section, reaction of the sulfite with
dissolved oxygen and with dissolved 803.
Na2S03(aq) + l/202(aq) -> Na2S04(aq)
2Na2S03(aq) + S03(aq) + H20 -> Na2S04(aq) + 2NaHS03(aq)
An antioxidant that was formerly added to the scrubber liquor (but
has not proven economically feasible) is no longer used. Instead Davy
Powergas has redesigned the absorption system such that at the design
conditions used in this study only about 3% of the S02 absorbed is
converted to sulfate (including that formed in the recovery section, as
discussed below).
The formation of sulfate in the Wellman-Lord process must be minimized
because the sulfate "remains in solution as an inert common-ion component
and can eventually decrease the reactivity of the solution. This is
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accomplished by the crystallization of Na2SC>4 in a purge stream by
taking advantage of the lower solubility of the sulfate compared with
the sulfite and particularly the bisulfite. The purge stream is concen-
trated by evaporation and the crystalline solid formed (consisting of
about two-thirds Na2SC>4 and one-third Na2S03) is removed and dried.
Although the technology for reduction of Na2SO^ is known (Tomlinson,
1968), it has not been used in FGD applications of the Wellman-Lord
process. Davy Powergas is, however, investigating processes for conver-
sion of the Na2SO^ to a sodium compound reusable in the process (Radian,
1977).
The Na2SC>4 is a potentially marketable product. About 1.3 million
tons is produced annually in the United States from natural deposits and
as a byproduct of chemical processes. Over half is used in kraft paper
manufacture, a use anticipated to decline in the future (Pulp and Paper,
1979).
The NaHS03-rich solution from the absorber and the sulfate purge
evaporator is regenerated by evaporative heating under vacuum.
2NaHS03(aq) -> Na2S03(s) + S02(g) + H20(g)
The reaction is favored by the lower solubility of Na2S03 which is
removed from solution and redissolved for reuse.
In addition to the previously mentioned sulfite oxidation reaction
and the 803 absorption reaction which take place in the absorber, other
reactions which further reduce the quantity of active absorbent occur
during regeneration.
6NaHS03(aq) ->• 2Na2S04(s) + Na2S203(aq) + 2S02(g) + 3H20(g)
2NaHS03(aq) + 2Na2S03(aq) -> 2Na2S04(aq) + Na2S203(aq) + H20
Most of the Na2S04 returns to the absorber system and is controlled
by the sulfate purge. The concentration of the relatively small quantity
of highly soluble Na2S203 formed is controlled by a liquid purge stream
which is combined with the sulfate purge solids. These reactions are
also reduced by operating the regeneration process at the lowest practical
temperature.
Sodium losses are replaced by addition of soda ash to the scrubber
solution.
Na2C03(aq) + S02(aq) -> Na2S03(aq) + C02(g)
The evaporator off-gas is dewatered, by cooling and compression to
atmospheric pressure, to a concentration of about 96% S02. The S02 can
be liquefied, processed to H2S04» or reduced to elemental sulfur. All
three routes have been used, in the United States or Japan. Conventional
10
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technology is well known for liquefaction and I^SC^ production. Reduction
to elemental sulfur, a more tractable, and in some aspects a more widely
marketable product (O'Brien and Anders, 1979), is the method used at the
three commercial Wellman-Lord utility FGD systems now in operation in
the United States (Gaur, 1979). The Allied Chemical methane (natural-
gas) reduction process discussed below is used at these installations.
RESOX® COAL-REDUCTION PROCESS
The Resox process (see flow diagram, Figure 10) is being developed
by the Foster Wheeler Energy Corporation. It is based on the direct
reduction of 862 to sulfur by passing it through a bed of anthracite
coal at an elevated temperature. Steam and air are added to the inlet
SC>2 stream as essential components of the reduction reactions. According
to Foster Wheeler (Steiner et al., 1974) the water acts synergistically
to permit high conversions at lower operating temperatures. The air
acts as an oxidizing agent to control volatiles and maintain the reaction
temperature. By careful control of conditions, particularly temperature
and residence time, Foster Wheeler claims a conversion of 862 to sulfur
of 90%. The operating temperature is 1100°F to 1500°F and the gas
residence time is 3 to 8 seconds, depending on the coal used and the S02
feed stream characteristics. Neither 862 nor steam reacts readily with
carbon at the temperatures used in the Resox process. Since the quantity
of steam entering the reactor is about the same as the quantity leaving,
it has been postulated that carbon is the primary reducing agent, with
carbon-water reaction products serving as intermediaries (Radian, 1976).
C + H20 •> H2 + CO
S02 + 2H2 •* S + 2H20
Catalytic effects of the anthracite coal, perhaps specific to this or
similar coals, have also been suggested (Radian, 1977).
Stoichiometry is not considered a critical factor if excess carbon
is available. A stoichiometric molar ratio of about 2 carbon to 1
sulfur is used. The spent coal from the reactor thus contains appreciable
fuel value. Its use as a boiler fuel (Radian, 1977) or as a carbon
adsorbent has also been suggested. The use of anthracite instead of
other coals has been dictated thus far by the need of a free-flowing,
nonvolatile coal. Foster Wheeler has evaluated other coals but has
found them less practical because of caking and hydrocarbon contamina-
tion of the sulfur.
The Resox system consists of a vertical reactor into which rice-
size (3/16 to 5/16 inch) anthracite coal is fed from an overhead hopper.
The spent coal consisting of char and ash is withdrawn at a controlled
rate at the bottom of the reactor to control the anthracite residence
time, which is about 12 hours. The S02~rich gas is mixed with air, and
steam if necessary, and injected around the periphery of the reactor
11
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near the vertical midpoint. The quantity of air added is controlled to
oxidize volatiles and oxidize sufficient coal to maintain the reaction
temperature. The off-gas is composed of sulfur vapor, water vapor, CC>2»
and minor amounts of H2S, SC^, COS, arid other reaction products. The
off-gas is passed through a shell and tube heat exchanger where the
sulfur is condensed. The remaining off-gas is either returned to the
boiler or incinerated and then returned to the FGD system.
Foster Wheeler began studies of the Resox process in the late
1960's (Steiner et al., 1974). Following studies to establish operating
conditions, a demonstration unit was constructed at the Scholz Steam
Plant of Gulf Power Company as part of a demonstration unit of the
Bergbau-Forschung FGD process (Strum et al., 1976). The Bergbau-Forschung
process, for which Foster Wheeler is the U.S. licensee, is a carbon
adsorption, regeneration process that produces an S0£ gas stream suitable
for processing in a Resox unit. The demonstration unit was tested in
1975 and 1976 although only limited data were obtained before expiration
of the test program. Subsequently, a Resox unit was installed at the
Kellerman Power Station in Lunen, Federal Republic of Germany, again in
conjunction with the Bergbau-Forschung process (Knoblauch and Goldschmidt,
1976). This unit was operated from June 1978 to June 1979 (Steiner, et
al., 1980). During about half of this test period, the unit was operated
on a simulated feed gas of the composition produced by the Wellman-Lord
process. The Resox process is also being installed on a 10-MW experimental
chemically active fluidized-bed boiler at the La Palma Power Station of
the Central Power and Light Company of Corpus Christi, Texas.
ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
The Allied Chemical coal/S02 reduction process (see flow diagram,
Figure 12) is an outgrowth of their S02 reduction process using methane
(natural gas), which has been operational since 1970. In addition to
other applications, the methane reduction process is used with Wellman-
Lord scrubbing systems at Mitchell Station and San Juan Station. Pilot-
plant studies based on earlier research were begun on the coal reduction
variation in 1973. Since then continuing development has defined process
and control techniques and improved yields and efficiencies to the
extent that Allied believes the process has a good potential for successful
commercial application (Allied Chemical, 1978). In addition, operational
conditions for a number of different types of coal have been defined.
The coal reduction process uses ground coal as the reducing agent.
The coal is ground and dried in an inert atmosphere, combined with
quartz sand, and injected into the bottom of a reactor vessel. The S02~
rich off-gas from the FGD system is combined with a small amount of air
and injected at the bottom of the reactor. The gases move upward,
fluidizing the bed. About 75% to 80% of the S02 is reduced to elemental
sulfur vapor during its passage through the bed and during contact with
coal particles in a low-velocity settling chamber above the bed. The
temperature of the reactor is controlled at 1500°F to 1800°F (816°C to
982°C), depending on optimum reaction temperature for the particular
coal used, by controlling bed depth and flow rates.
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Particulate matter (consisting of ash, char, and some sand) is
partially removed from the reactor off-gas in a cyclone separator. The
off-gas (consisting of sulfur vapor, S02, various gaseous reaction
products, volatilized impurities, and residual particulate matter) is
scrubbed with molten sulfur in a venturi ejector to condense the sulfur
vapor and remove the remaining particulate matter. The molten sulfur
used in the ejector is cooled by water injection in the molten sulfur
circulation system. Molten sulfur is withdrawn from the system,
filtered, and pumped to storage.
Cleaned gas from the ejector, containing residual sulfur as H2S
and S02, is passed through a two-stage Glaus unit to increase the overall
conversion of SC>2 to sulfur to about 96%. Glaus unit tail gas is incine-
rated and recycled to the scrubber system. Because of sulfur losses in
both the cyclone dust and the filter cake, sulfur recovery is reduced to
90 molar % of the S02 in the feed stream.
The process also includes an inert gas generator, various feed
preheaters using process streams, and a waste heat boiler which produces
process steam.
Glaus Process
The Glaus process has been used in numerous variations since the
19th century for the catalytic vapor-stage oxidation of H2S to sulfur
(Maddox and Burns, 1968). The reaction proceeds in two steps:
2H2S + 302 -> 2S02 + 2H20
2H2S + S02 -* 3/8S8 4- 2H20
Both reactions are highly exothermic, particularly the first. To optimize
conversion conditions, the feed stream is partially oxidized to S02 at
about 2000°F. Under these conditions, a considerable percentage of
sulfur is formed directly. The gas is cooled in a high-pressure steam
boiler and further cooled to 300°F in a low-pressure steam generator to
condense and remove the sulfur. The gas is reheated to 450°F to 500°F,
the optimum conversion temperature, and passed through a bed of catalyst
such as alumina where the second reaction shown above occurs. The off-
gas is then cooled to 300°F in a low-pressure steam generator to remove
the sulfur. The gas is then passed through a second catalytic converter.
Two-stage conversion usually results in a total conversion of about 90%.
In conventional plants additional converters are usually preferable to
reduce tail-gas processing. Many design variations are used to meet
specific needs. A widely used variation is the split-stream process in
which the H2S in a side stream of the feed gas is completely oxidized to
S02 and recombined with the remaining gas. This reduces difficulties in
processing impure feed gas but usually results in a lower conversion.
In FGD applications some variations from conventional Glaus plant
design are possible. In some processes, such as the Allied process, the
13
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feed gas contains both SC>2 and I^S and partial oxidation is not necessary.
In addition, additional converters and tail-gas emission control are not
necessary because the tail gas can be returned to the FGD system.
14
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DESIGN AND ECONOMIC PREMISES
The premises used in this study have been developed by TVA, EPA,
and others during similar economic evaluations made since 1967. They
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, SOX removal efficiency, and process variations. Because of the
decreased emphasis on oil as a utility fuel, only one oil-fired variation
is included. The economic premises are selected to include the many
factors affecting FGD costs. They establish conditions for determination
of capital costs for installation of the FGD system and first-year
annual revenue requirements for its operation. Lifetime revenue require-
ments for each year of the systems' operating life are also calculated.
Normally, the base-case FGD systems are assumed to begin downstream
from the fly ash removal system and boiler ID fans and to end at the
stack plenum. Fly ash removal and disposal and a stack plenum are
considered necessary power plant facilities and are not included in the
FGD costs.
In previous FGD economic analyses in this series of evaluations,
fly ash removal and disposal were not included in the costs because they
were independent functions. In the AGP, however, fly ash collection can
be performed in the same equipment used to collect the sulfur-salt
particulate matter. Also, in case variations involving wet scrubbing
for fly ash removal, ESP's are not required. When fly ash collection is
an integral part of the FGD process, appropriate credit for ESP costs
is included. By applying these costs as credits, equitable economic
comparisons with other FGD processes evaluated in this series are
facilitated.
DESIGN PREMISES
The power plant design and operation is based on Federal Energy
Regulatory Commission (FERC) historical data and TVA experience. The
conditions represent a typical modern boiler 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.
15
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Emission Standards
NSPS promulgated by EPA in 1971 (Federal Register, 1971) are used.
These NSPS specify a maximum SC>2 emission of 1.2 Ib/MBtu and a maximum
particulate matter emission of 0.1 Ib/MBtu, based on heat input, for
large coal-fired boilers. The revised NSPS promulgated by EPA in 1979
(Federal Register, 1979) are not used because boilers existing in the
time period used in this study would not be affected by these regulations.
The revised NSPS retain the same SC>2 maximum emission standard and, in
addition, require between 70% and 90% S02 emission reduction for all
levels of sulfur input in the raw coal. If all S02 emission control
were performed by FGD, the 3.5% and 5.0% sulfur coals would require
removal efficiencies approaching 90%, as represented by the case vari-
ations discussed below.
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 coals have a heating value of
10,500 Btu/lb, as fired, arid an ash content of 16%, as fired. The
composition and flow rates for the base-case conditions are shown in
Table 1. The oil-fired variation uses a No. 6 fuel oil (Table 2) with
2.5% sulfur and 0.1% ash and with a high heating value of 144,000
Btu/gal.
TABLE 1. 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)
Coal
components
Base case, 3.5%
sulfur (dry basis)
Wt %, Lb/hr,
as fired as fired
2.0%
sulfur (dry basis)
Wt %, Lb/hr,
as fired as fired
5.0%
sulfur (dry basis)
Wt %, Lb/hr,
as fired as fired
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Chlorine
Ash
Water
57.56
4.14
1.29
7.00
3.12
0.15
16.00
10.47
246,800
17,700
5,500
30,000
13,400
600
68,600
46,000
58.03
4.17
1.30
7.81
1.80
0.15
16.00
10.74
248,700
17,900
5,600
33,500
7,700
600
68,600
46,000
56.89
4.09
1.27
6.40
4.46
0.15
16.00
10.74
Total 100.00
428,600 100.00
428,600 100.00
244,000
17,500
5,400
27,400
19,100
600
68,600
46,000
428,600
16
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TABLE 2. OIL COMPOSITION AND RATE
(500-MW existing unit, 9,200
Btu/kWh heat rate, 2.5% sulfur)
Wt %
Oil components as fired Lb/hr
Carbon 83.66 204,100
Hydrogen 11.46 28,000
Nitrogen 0.63 1,500
Oxygen 1.25 3,000
Sulfur 2.50 6,100
Ash 0.10 200
Sediment 0.40 1.000
Total 100.00 243,900
Power Plant Design
For new power units scheduled for startup through 1980, the sizes
range from about 80 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.
A single, balanced-draft, horizontal, frontal-fired boiler design
is used. Boiler 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. For the ACP, the particulate matter cyclone collectors (which
are included in the FGD costs) are located upstream from the boiler ID
fans. 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 below. 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.
17
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Operating year
Capacity
factor, %
Annual
operating
time, hr
1-10 80 7,000
11-15 57 5,000
16-20 40 3,500
21-30 17 1,500
Average for 30-yr life 48.5 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 shown below.
Size, MW Status Her*- rate, Btu/kWh
1,000 New 8,700
1,000 Existing 9,000
500 New 9,000
500 Existing 9,200
200 New 9,200
200 Existing 9,500
Flue Gas Composition
Flue gas compositions are based on combustion of pulverized coal
using a total air rate equivalent to 133% of the stoichiometric require-
ment. 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 803 and the remainder
The base-case flue gas composition and flow rate calculated from
these conditions are shown in Table 3. The estimated flue gas compositions
for power unit emissions at varying fuel-sulfur levels before fly ash
removal and FGD are shown in Table 4. Calculated flue gas and equivalent
S02 emission rates are shown in Table 5.
18
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TABLE 3. BASE-CASE FLUE GAS
COMPOSITION AND RATE
Flue gas
components
Lb/hr
02
co2
so2
S03
NOX (as NO)
HC1
H20
3,450,000
2^3,200
904,200
25,330
317
3,009
661
264,500
Aft3/min
(300°F)
,138,000
74,590
.18^,900
3,626
37
927
168
135.600
Total 4,906,000 1,543,000
Table 4. FLUE GAS COMPOSITIONS 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
N2
02
C02
S02
S03
NOX (as NO)
HC1
H20
73.68
4.83
12.44
0.14
0.0014
0.06
0.01
8.84
73.76
4.83
12.31
0.24
0.0024
0.06
0.01
8.79
73.80
4.84
12.20
0.34
0.0034
0.06
0.01
8.75
73.60
2.54
11.96
0.13
0.0013
0.02
-
11.75
Fly Ash Loading
Gr/sft3 (dry)
Gr/sft3 (wet)
6.67
6.08
6.65
6.06
6.66
6.08
0.036
0.032
19
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N>
O
TABLE 5. POWER PLANT FLUE GAS AND SO? RATES
Power plant
size, MW
Coal-fired units
200
200
500
500
500 (base case)
500
1,000
1,000
Type
plant
Existing
New
Existing
New
New
New
Existing
New
Sulfur content
of fuel, %
(dry basis)
3.5
3.5
3.5
2.0
3.5
5.0
3,5
3.5
Gas flow
to FGD systems,
aft3/min (300°F)
652,000
631,000
1,577,000
1,539,000
1,543,000
1,539,000
3,085,000
2,982,000
Equivalent S02 emission
rate to FGD systems,
Ib S02/hr
10,610
10,27.0
25,690
14,500
25,130
35,920
50,250
48,580
Oil-fired unit
500
Existing
2.5
1,313,000
12,060
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Removal Efficiencies
Actual SOX removal efficiencies required to meet the 1.2 Ib S02/MBtu
emission standards vary according to the sulfur content of the coal.
Shown below are the efficiencies calculated for the sulfur contents and
combustion conditions used in this study. In addition, a case variation
is included to evaluate the effect of 90% SOX removal efficiency on
costs.
Sulfur content Degree of Degree of
of fuel, % particulate removal, wt % SO? 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
Absorber Design
Absorber design criteria are based on vendor-supplied data, appli-
cable TVA operating experience, and general power industry operating
experience. The designs are generic to the extent that they represent
most-proven technology rather than a particular existing installation.
Technical design and operating data were supplied by the vendors of each
process.
The 200-MW boiler size is provided with two absorber trains; the
500- and 1000-MW boiler sizes are provided with four each. All of the
trains are fed from the common plenum. Booster fans, sized to compensate
for the pressure drop in the FGD system, are provided in each train.
In all the processes except the ACP, chlorides are removed in a
prescrubber upstream of the S02 absorber. This also serves to presaturate
the flue gas. The assumed percentages of flue gas components removed in
the chloride scrubber are: 0% S02, 25% 803, and 100% HC1. In the ACP,
chlorides are removed in the regeneration process. In all processes the
chloride waste is discarded in the ash disposal pond.
TheiWellman-Lord absorbers 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 Wellman-Lord absorbers and the ACP
spray dryers are shown in Table 6. These conditions are used for both
the base case and the case variations. Scaling factors based on gas and
product rates are used to adjust sizes for conditions other than the
base case.
21
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TABLE 6. ABSORBER OPERATING CONDITIONS
[500-MW units, 3.5% sulfur in coal (dry basis),
1.2 Ib S02/MBtu heat input allowable emission]
Process
Operating conditions
Aqueous
carbonate
We llman-Lo r d/
3 ill f uric acid
Wellman-Lord/
Resox
Wellman-Lord/
Allied Chemical
coal/S02
reduction
N>
Design gas velocity, ft/sec
S02 scrubber
L/G, gal/kft3
Prescrubber
S02 absorber, recycle liquor
Design pressure drop, inches
Oxidation of removed S02 to SO^
12.5
15
20
10
10
3
19
3
10
10
3
19
3
10
10
3
19
3
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The absorber 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 absorber 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. Absorber bypass ducts are not provided.
Reheat
In the Wellman-Lord processes, reheat of the scrubbed flue gas to
175°F is provided for plume buoyancy, to reduced opacity, and to prevent
fan and stack corrosion. Indirect steam heat is used for coal-fired
cases. Direct-fired oil reheat is used for the oil-fired cases. The
ACP does not require reheat.
Raw Materials
The major raw materials required are soda ash, anthracite, and
power-plant coal. The power-plant coal is described in the power-plant
fuel premises. The same light bulk soda ash is used for both the Wellman-
Lord processes and the ACP. It is assumed to be in powder form (100% to
pass a U.S. No. 100 screen), contain 99.5% Na2C03, and have a dry bulk
density of 35 lb/ft3.
The anthracite is rice size (ASTM, 1979), a size designation in
which the coal passes a 5/16-inch round-hole screen and is retained on a
3/16-inch round-hole screen. The anthracite composition used is shown
below.
Ultimate analysis, % Proximate analysis, wt %
C 81.8 Moisture 4.1
H 3.1 Volatiles 6.0
N 0.9 Fixed carbon 80.8
0 4.4 Ash 9.1
S 0.7
Ash 9.1
Other raw materials required are catalysts, agricultural limestone,
filter aids, and silica sand. Standard commercial grades are used,
based on vendor recommendations.
Waste Disposal
The power plant ash pond is used for waste disposal. A portion of
the ash pond cost is allocated to the FGD system to account for the
additional waste disposal cost.
23
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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 encountered
in industry practice. The case variations used are shown below:
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)
SOX, percent removal
Oil, weight percent
sulfur
Alternate S02 con-
version rate
3.5 2.0, 5.0
79 (3.5% S) 90
2.5
90% (Resox) 90% of base case
96% (Allied)
Wet-scrubbing fly
ash removal No
Yes (W-L systems)
The relative quantities of gas and sulfur processed compared with
the base-case quantities are shown in Table 7. The relative throughput
rates are used to calculate a processing area scale factor, which multi-
plied by the base-case processing area direct investment gives the
corresponding processing area direct investment for the case variation.
ECONOMIC PREMISES
The economic premises define procedures for determining capital
investment costs for installation of the FGD system and annual revenue
requirements for its operation. 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), The Richardson
Rapid System (1979), and Modern Cost Engineering (1979).
24
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TABLE 7. RELATIVE QUANTITIES OF GAS AND SULFUR
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
25
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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.
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 Investment
Capital investment costs consist of 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 invest-
ment plus the other capital charges. Investment costs are projected
from Chemical Engineering (1975, 1976) annual cost indexes as shown in
Table 8. The costs are based on construction of a proven design and an
orderly construction program without delays or overruns.
TABLE 8. COST INDEXES AND PROJECTIONS
Year
Plant
Materialb
Laborc
1974
165.4
171.2
163.3
1975
182.4
194.7
168.6
1976a
197.9
210.3
183.8
1977a
214.7
227.1
200.3
1978a
232.9
245.3
218.3
1979a
251.5
264.9
237.9
1980a
271.6
286.1
259.3
1981a
293.3
309.0
282.6
a. Projections. Although actual cost indexes are available for 1976-
1978, projections for these years are used 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."
26
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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, concrete
foundations, structure, 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 incremental
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$)
A status factor of 0.07 is used for all battery-limits units in
this study.
Architect and engineering contractor expense—This expense is
calculated as 25% of the engineering design and supervision costs for
major equipment items and battery-limits units plus 10% of engineering
design and supervision costs for incremental 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$)
0 83
+0.13 (pond direct investment, in M$)
Contractor fees—Direct investment is also used to determine con-
tractor fees:
Contractor fees = 0.096 (total direct investment in M$)
27
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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
$3500 per acre is used.
Working Capital—
Working capital is money representing the cash flow of normal
operation. In 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.
Annual Revenue Requirements
Annual revenue requirements, based on a 7000 hour per year operating
schedule, use the same operational profile and remaining life assumptions
that are used in the power plant design premises. Costs are projected
to 1980 dollars to represent a mid-1980 startup. The revenue require-
ments 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 9. 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 its being a separate electrical consumer paying
full price for service.
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. The mainte-
nance percentages are assumed to be constant over the life of the plant.
Incremental pond maintenance is treated separately as a constant 3% of
the incremental pond construction costs. Maintenance costs are shown in
Table 10.
28
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TABLE 9. PROJECTED 1980 UNIT COSTS FOR RAW MATERIALS,
LABOR, UTILITIES, AND CREDITS FOR BYPRODUCTS
$/unit
Raw Materials
Na2C03
Coal
Anthracite coal
Agricultural limestone
Filter aid
Sand
103.00/ton
25.00/ton
60.00/ton
15.00/ton
189.00/ton
7.50/ton
Labor
Operating labor
Analyses
Mobile equipment
12.50/man-hr
17.00/man-hr
17.00/man-hr
Utilities
Fuel oil (No. 6)
Steam
Process watera
Boiler feedwater
Electricity
200 MW
500 MW
0.40/galb
2.00/MBtu
0.12/kgal
0.92/kgal
1,000 MW
0.031/kWh 0.029/kWh 0.028/kWh
Credit for Byproducts
Sulfur
Sulfuric acid (100%)
Sodium sulfate
Anthracite (spent)
40.00/tonc
25.00/ton
23.00/ton
25.00/ton
a. Varies according to process-dependent water requirements.
b. Because of the need to maintain comparability with pre-
viously published FGD studies, this unit cost was retained.
c. Short tons.
29
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TABLE 10. OVERALL ANNUAL MAINTENANCE COSTS
% of direct investment
excluding pond construction3
Process 200 MW 500 MW 1000 MW
Aqueous carbonate 876
Wellman-Lord/sulfuric acid 765
Wellman-Lord/Resox 765
Wellman-Lord/Allied Chemical
coal/S02 reduction , 765
a. Pond maintenance is estimated as 3% of the incremental
pond construction cost.
Indirect Costs—
A summary of capital charges, based on regulated utility economics,
is shown in Table 11. Straight-line depreciation is used, based on the
remaining life of the power plant when the FGD system is installed. The
allowance for interim replacement is increased from the usual average of
about 0.35% because of the uncertain 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.
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 overhead is assumed
to be 10% of the byproduct revenue.
Byproduct Credits
In the calculation of annual and lifetime economics, credit from
the sale of byproducts is deducted from the revenue requirements to give
the net revenue requirements of the FGD process. The byproduct credit
applied is based on the selling price of the byproduct. An overhead of
10% of this credit is included in indirect costs for marketing expense.
In addition to sulfur and sulfuric acid, byproduct credits are given for
sodium sulfate produced by the Wellman-Lord process and spent anthracite
produced by the Resox process are shown in Table 9.
Lifetime Revenue Requirements
Lifetime revenue requirements reflect the changing operating costs
as operating time changes and the rate base declines because of depreci-
ation. In addition, the revenue requirements can be discounted to
reflect the time value of money. The lifetime revenue requirements in
this study are calculated in the same manner as the annual revenue
30
-------
requirements except that the capital charges are based on the declining
undepreciated investment. The discounted lifetime revenue requirements
are discounted at 11.6% to the initial year of operation.
TABLE 11. ANNUAL CAPITAL CHARGES FOR POWER INDUSTRY FINANCING
Percentage of total depreciable
capital investment
Years remaining life 30 25 20
Depreciation (straight line, based on
years remaining life of power unit) 3.3 4.0 5.0
Interim replacements (equipment having
less than 30-year life) 0.7 0.4
Insurance 0.5 0.5 0.5
Property taxes 1.5 1.5 1.5
Total rate applied to original
investment 6.0 6.4 7.0
Percentage of unrecovered
capital investment
Cost of capital (capital structure assumed
to be 60% debt and 40% equity)
Bonds at 10% interest 6.0
Equity3 at 14% return to stockholder 5.6
Income taxes (Federal and State)b 5.6
Total rate applied to depreciation base 17.2C
a. Contains retained earnings and dividends.
b. Federal and State income taxes are assumed to have the same effect on
capital cost as return on equity.
c. 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%.
31
-------
SYSTEMS ESTIMATED
The base-case FGD systems that serve as the bases of the cost
estimates are conceptual designs prepared from process descriptions,
material balances, flow and control diagrams, layout drawings, and
equipment lists. The designs are developed from vendor information,
industry experience, and the premises described in the previous section.
For equitable comparison, an area-by-area format is used that divides
each system into similar processing steps. Capital investment summaries
are based on equipment lists that follow the area-by-area pattern.
Both the AGP and Wellman-Lord processes can be considered as
absorption-regeneration systems that supply an end plant producing a
marketable product. The ACP, with an integral reduction step, is pro-
vided with a Glaus unit end plant because sulfur is the obvious economi-
cally desirable product. There are several feasible end plants for the
Wellman-Lord process, however. The process incorporating the sulfuric
acid end plant is included to represent an alternate byproduct and to
provide a process using conventional technology for comparison with the
coal reduction processes. With the exception of the Glaus and sulfuric
acid units, the general designs are based on vendor information. The
designs represent late-1979 technology and design philosophy. They are
based on the power plant conditions given in the premises, however, and
do not represent a particular existing or planned installation.
AQUEOUS CARBONATE PROCESS
This is the first full economic evaluation of the ACP made by TVA,
although TVA recently made a preliminary evaluation of the Rockwell
International/Wheelabrator Fry open-loop process, which uses similar
spray dryer technology (Burnett and O'Brien, 1980). The ACP used for
the base-case conditions (a new 500-MW power plant using 3.5% sulfur
coal) has four gas and reduction reactor trains and one regeneration
train. Case variations follow a similar design except that the 200-MW
case variations have only two gas trains. The flow diagram and the
material balance are shown in Figure 1 and Table 12 respectively. The
design drawings for the base case are shown in Figures 2-4.
The ACP is divided into nine operating areas: materials handling,
gas handling, fly ash collection, S02 absorption and removal, reduction,
off-gas treatment, carbonation, sulfur production, and sulfur storage
and shipment. The equipment list, itemized by area, is shown in ,
Table 13. The costs shown in Table 13 are purchase costs and do not
include costs for erection.
32
-------
TO
CLAUS TAIL GAS
INCINERATOR
[ —
DEHUMOFER
J
A
J
OFF-GAS
25
QUENCH
SCRUBBER
t t_
TS!
-&
P
TO
CLAUS TAIL GAS
INCINERATOR
t.
FEED GAS
FROM
CRYSTALLIZER
U>
Figure 1. Aqueous carbonate process flow diagram.
-------
TABLE 12. AQUEOUS CARBONATE PROCESS
BASE-CASE MATERIAL BALANCE
Stream No.
Description
1
2
j
4
5
6
7
8
9
in
Total stream. Ib/hr
sft^/min (60°F)
Temperature, °F
Pressure, psia
spin
Specific gravity
pH
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
966,700
535
4
Gas to
air
heater
4,516,100
958,000
705
5
Gas to
mechanical
collectors
4,960,400
-
1,056,000
300
Stream No.
1
i
)
4
b
6
7
8
9
19
Description
Total stream, Ib/hr
sft->/min C&OOF)
Temperature, UF
Pressure, psia
gpm
Specific gravity
PH
Undissolved solids, %
6
Ash to ash
pond
46,600
7
Gas
to boiler
plenum
4.913.800
1,056,000
300
8
Gas to
spray dryer
5,034.000
1,077,500
300
9
Gas to
electrostatic
precipitator
5.283.200
1,113,700
170
10
Gas to
stack
5,204.900
1,113,700
170
1
2
j
4
5
h
/
8
9
10
Stream No.
Description
Total stream, Ib/hr
sft^/min (60°F)
Temperature, °F
Pressure, psia
gpm
Specific gravity
pH
Undissolved solids, %
11
Particulate
to
particulate
silo
78,300
12
Coal to
reducer
feed hopper
14,500
13
Conveying
air to
reducer
8,000
1,727
80
14
Particulate-
coal mixture
to reducer
92,800
15
Reducer
off-gas to
recuperator
79,900
17,100
1,800
Stream No.
1
2
1
4
b
6
/
8
9
10
Description
Total stream, Ib/hr
sft^/min, (60°F)
Temperature, UF
Pressure, psia
gpm
Specific gravity
PH
Undissolved solids, %
16
Combustion
air to
reducer
40,100
8,594
1,000
17
Steam from
waste heat
boiler
24,100
377
190
18
Peducer
off-gas to
off-gas
treatment area
79,900
17,100
560
19
Salt melt
to quench
tank
61,000
1,800
102
1.2
20
Steam to
shatter
jets
12,600
377
190
(continued)
34
-------
TABLE 12 (continued)
2
1
4
5
6
7
H
9
10
Description
Total stream, Ib/hr
sft3/min (60°F)
Temperature. °F
Pressure, psia
fpm
pecific gravity
pH
Undissolved solids, 7,
21
Makeup
water to
quench tank
172,800
80
345
1.0
22
Quench off-gas
to off-gas
12,600
2,690
220
23
Off-gas from
treatment area
83.300
17,835
100
24
Treatment
area off-gas
59.70C
12.783
inr
25
Makeup water
to off -gas
15,200
80
30
Stream No.
Description
1
?
)
4
5
6
7
8
y
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, "F
Pressure, psia
gpm
Specific gravity
pH
Undissolved solids, %
26
Chloride
purge
24.400
100
49
27
Green liquor
to
storage tank
233.800
220
389
1.2
28
Green liquor
to
ash filter
250.500
110
501
1.2
29
Wash water
to
ash filter
q.fifir
19
in
Ash to
disposal
11 4nn
50
Stream No.
Description
1
•;
j
4
5
6
7
8
9
10
Total stream, Ib/hr
sft3/min, (60°F)
Temperature, °F
Pressure, psia
gpm
Specific gravity
pH
Undissolved solids, %
31
Green liquor
filtrate to
precarbonator
246,600
110
411
1.2
32
Green liquor
to
crystallizer
249.200
110
415
1.2
33
Feed to
carbonator
252.200
110
420
K2
34
Feed to
decomposer
257.000
130.
428
1.2
35
Feed to
solution
storage tank
MS, 300
254
19?
i .90
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
Total stream, Ib/hr
sft^/min, (60°F)
Temperature, °F
Pressure, psia
gpm
Specific gravity
pH
Undissolved solids. %
36
Water to
raw material
storage tank
6,310
80
13
1.0
37
Makeup
absorbent
solution to
solution
storage tank
9.400
16
1.0
38
Rich
absorbent
solution to
spray dryer
244,700
489
1.2
39
Absorbent
solution to
spray dryer
249.200
498
1.2
40
Feed to
reboiler
1.933.300
254
3.219
1.20
(continued)
35
-------
TABLE 12 (continued)
Stream No.
Description
1
2
)
4
5
6
7
8
9
10
Total stream, Ib/hr
sft3/min f60°Fl
Temperature , op
Pressure, psia
gpm
Specific gravity
pH
Undissolved solids, %
41
Steam to
decomposer
reboiler
37,700
377
190
42
Decomposer
off-gas
to carbonator
21,700
1,951
90
43
Combined
off-gas to
carbonator
81,400
15^57
118
37
44
Carbonator
off-gas to
crystallizer
76,60C
1 1; 1 =i9
11C
32
45
Crystallizer
off-gas to
Glaus unit
36,800
11.003
118
22
Stream No.
1
2
i
4
b
6
7
8
9
10
Description
Total stream, Ib/hr
sft^/min (600F)
Temperature, °F
Pressure, psia
gpm
Specific gravity
pH
Undissolved solids. %
46
Crystallizer
off- gas to
36,800
11,003
118
22
47
Precarbonator
off-gas to
17,500
4,060
100
48
Air to
Claus unit
4,000
871
80
49
Sulfur to
receiving
pit
10,400
330
10
2.07
50
Steam to
sulfur receiving
pit
23
377
190
Stream No.
1
2
j
4
^,
6
/
8
9
10
Description
Total stream, .Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure. DSia
spm
Specific gravltv
pH
Undissolved QnliHQ "/„
51
Steam to
sulfur storage
tank
2.600
177
iqn
52
Claus tail-
gas to
incinerator
30 r 400
fi.SIR
77S
53
Fuel oil to
incinerator
2,500
s
n.qi
54
Combustion
air to
incinerator
4fir?00
q sqn
275
55
Off-gas to
incinerator
41.100
8.792
100
Stream No.
Description
1
2
i
4
b
h
1
H
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia
gpm
Specific gravity
PH
Undissolved solids, %
56
Incinerator
tail-gas to
flue gas ducts
120,200
23,785
600
57
Steam from
incinerator
20,800
377
190
58
High pressure
steam from
Claus unit
36,200
377
190
36
-------
OJ
X—X—X—X—X—
-X—X—X X-
c
X—X—X
SERVICE
BLDG
TURBINE
ROOM
BOILER
ROOM
o
CLAUS PLANT
ROAD
OOOO 1
O fl >-v
(J
O O
o o o oi
o o o o
OOo;o
Figure 2. Aqueous carbonate process plot plan.
-------
r
HULTKLONES
OO
Figure 3. Aqueous carbonate process elevation drawing.
-------
SOLUTION STOftAQC
U>
VO
HOPPB1S f- ^x "^SBS
0 (T) © ©
X / ^-K' ncr-nuafwr
O
o o ( - -t -
0
PMECAflBONATOH
SOLUTIOtMTOWMX
CLAUS PLANT
Figure 4. Aqueous carbonate process regeneration area layout drawing.
-------
TABLE 13. AQUEOUS CARBONATE PROCESS
BASE-CASE EQUIPMENT LIST
Area 1—Materials Handling
Item
No.
Description
Total material
cost, 1979 $
1. Car shaker
2. Tank, soda ash 1
storage
Pump, soda ash
recirculating
Pump, soda ash
feed
5. Dust collecting
system
Subtotal
Top mounting with crane,
20 hp shaker, 7-1/2 hp crane
40 ft dia x 40 ft high,
376,000 gal, w/cover, carbon
steel, insulated (30 day
storage)
Centrifugal, 16 gpm, 50 ft
head, 1/2 hp, carbon steel,
insulated (1 operating,
1 spare)
Centrifugal, 16 gpm, 50 ft
head, 1/2 hp, carbon steel,
insulated (1 operating,
1 spare)
Bag filter, polypropylene bag,
4000 aft3/min, automatic
shaker system
19,900
71,600
3,300
3,300
12,200
110,300
Area 2—Gas Handling
Item
No.
Description
Total material
cost, 1979 $
1. Fans
Subtotal
Induced draft, 337,300 aft3/min
15 in. static head, 875 rpm,
1250 hp, fluid drive, double
width, double inlet
812,000
812,000
(continued)
40
-------
TABLE 13 (continued)
Area 3—Fly Ash Collection
Item
No.
Description
Total material
cost. 1979 $
1. Mechanical
collector
Subtotal
Multiclone, 85% collection
efficiency, 30-1/2 ft x 10-1/2
ft x 25-1/2 ft high, cast iron
shell with abrasion resistant
tubes
337,200
337,200
Area 4—S09 Absorption and Removal
Item
No.
Description
Total material
cost, 1979 $
1. Spray dryer
2. Electrostatic
precipitator
3. Conveyor, particu-
late matter to
silo
4. Silo, particulate
Bin activator
5. Tank, solution
feed
7. Pump, solution
feed
Subtotal
2
2
6. Agitator, solution 2
feed tank
12
42 ft dia x 65 ft high with
4 (1 spare) rotary atomizers,
carbon steel
99.34% collection efficiency,
350 ft2 SCA
Pneumatic, negative pressure
conveying system, 35 ton/hr,
200 hp
32 ft dia x 32 ft straight
side, 25,750 ft3, 60° slope,
carbon steel (12-hour capacity
each)
37-1/2 ft dia x 38 ft high,
313,900 gal, w/cover, carbon
steel, neoprene lined (12-hour
capacity each)
Side mounted, 150 in. dia, 150
hp, neoprene coated
Centrifugal, 400 gpm, 250 ft.
head, 50 hp, carbon steel,
neoprene lined (8 operating,
4 spares)
2,898,000
2,282,000
118,100
58,000
22,700
150,200
316,000
102,600
5,947,600
(continued)
41
-------
TABLE 13(continued)
Area 5—Reduction
Item
No.
Description
Total material
cost. 1979 $
1.
2.
Feeder, raw coal
retrieval
Conveyor, raw coal
2
1
Vibrating pan, 12 in. wide x
48 in. long, 35 ton/hr, 0.5 hp
Belt, 14 in. wide x 1500 ft
3,200
280,000
retrieval
3. Silo, raw coal
4. Grinding mill
5. Elevator, ground 1
coal feed
6. Silo, coal
7.
8.
9.
Bin activator
Feeder, coal
silo
10. Hopper, reducer
solids feed
11. Conveyor, reducer
solids feed
12. Reducer air
system
1
1
Feeder, particulate 1
silo
Conveyor, reducer 1
feed transfer
long, 30 ft lift, 10 hp, 32
ton/hr, 200 ft/min
20 ft dia x 24 ft straight side, 13,200
7,500 ft3, 60° slope, carbon
steel (24-hour capacity)
Giant roller mill system 536,700
(includes grinding and dust
control equipment), 23 tons/hr
Continuous bucket, 12 in. x 7 in. 9,500
x 11-3/4 in., 3 hp, 50 ft lift,
23 ton/hr, 150 ft/min
24 ft dia x 24 ft straight 16,700
side, 10,900 ft3, 60° slope,
carbon steel (24-hour capacity)
11,400
Vibrating pan, 10 in. wide x 900
36 in. long, 7.5 ton/hr, 1/2 hp
Vibrating pan, 24 in. wide x 3,200
36 in. long, 35 ton/hr, 2 hp
Pneumatic, positive pressure 143,000
conveying system, 42 ton/hr,
200 hp
9 ft dia x 9 ft straight side, 6,000
575 ft3, carbon steel
(1-hour capacity each)
Pneumatic, positive pressure 148,800
conveying system, 10.5 ton/hr,
50 hp
Oil-free compressors, 3,500 416,000
ft3/min, 350 hp (3 operating,
1 spare)
(continued)
42
-------
TABLE 13 (continued)
13.
14.
15.
16.
17.
18.
19.
Area
1.
2.
3.
4.
Item No .
Reducer 4
Recuperator, 4
reducer air
Soot blowers 40
Waste heat 4
boiler
Quench tank 4
Agitator, quench 4
tank
Pump, quench tank 8
recirculating
Subtotal
6 — Off-Gas Treatment
Item No .
Scrubber, reducer 4
off-gas
Dehumidification 1
tower
Pump, tower 2
recirculating
Quench off-gas 4
scrubber
Description
18 ft dia x 34 ft highR
Mono f rax A and Alfrax"
lined carbon steel, with air
feed and solids feed nozzles
and preheat burner
Shell and tube heat exchanger,
200 ft^, 304 stainless steel
Air, retractable
Shell and tube heat exchanger,
410 ft^, carbon steel
10 ft dia x 14 ft high, 5,900
gal operating capacity, carbon
steel with 304 stainless steel
overlay in gas space
Side entering, 15 hp, neoprene
coated
Centrifugal, 100 gpm, 100 ft
head, 7-1/2 hp, carbon steel,
neoprene lined (4 operating,
4 spares)
Description
Variable throat venturi, 3950
sft3/min, 40 in. AP
Packed column, 10 ft dia x 15 ft
high, 10 ft of 2-in. Rashig
rings, 316 stainless steel shell
Centrifugal, 500 gpm, 100 ft head
25 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
Tray tower, 2 ft dia x 7 ft high,
304 stainless steel
(continued)
43
Total material
cost, 1979 $
3,192,400
40,000
260,000
59,300
18,900
10,500
29,200
5,198,900
Total material
cost, 1979 $
111,300
17,600
9,100
12,000
-------
TABLE 13 (continued)
Item
No.
Description
Total material
cost, 1979 $
5. Fan, quench
off-gas
Pump, quench
scrubber recircu-
lating
Cooler, recircu-
lating water
8. Fans, reducer
off-gas
9. Tank, chloride- 1
ash purge
10. Agitator, chloride- 1
ash tank
11. Pump, chloride- 2
ash disposal
Subtotal
Centrifugal, 600 aft3/min,
20 in. static head, 5 hp, carbon
steel, asphalt coated
Centrifugal, 150 gpm, 100 ft head,
25 hp, carbon steel, neoprene
lined (2 operating, 2 spares)
Plate and frame type heat
exchanger, 3200 ft^, carbon
steel with titanium plates
(1 operating, 1 spare)
Centrifugal, 9000 aft3/min,
60 in. static head, 125 hp,
304 stainless steel
(2 operating, 1 spare)
10 ft dia x 10 ft high, 5870
gal, carbon steel, neoprene
lined (30-minute capacity)
40 in. dia, 7.5 hp, neoprene
coated
Centrifugal, 83 gpm, 100 ft
head, 10 hp (1 operating,
1 spare)
7,200
18,200
132,600
43,200
4,700
12,000
1,800
369,700
Area 7—Carbonation
Item
No.
Description
Total material
cost, 1979 $
1. Tank, green
liquor storage
2. Agitator, green
liquor storage
tank
40 ft dia x 30 ft high, 282,000
gal, w/cover, carbon steel
epoxy-lined (12-hour capacity)
Side entering, 75 hp, neoprene
coated
(continued)
49,100
130,000
44
-------
TABLE 13 (continued)
Item
No.
Description
Total material
cost, 1979 $
3. Cooler, green
liquor
4. Pump, pre- 2
carbonator feed
5. Precarbonator
i. Pump, filter feed 2
surge tank
7. Tank, filter feed 1
surge
8. Agitator, filter
feed surge tank
9. Pump, filter
feed
10. Filter
11. Pump, filtrate
recirculating
12. Tank, filtrate
surge
13. Agitator, filtrate 1
surge tank
14. Pump, pre- 2
carbonator recycle
Plate and frame type heat 142,000
exchanger, 3600 ft2, carbon
steel with titanium plates
(1 operating, 1 spare)
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
Sieve tray column, 8 ft dia x 63,900
60 ft high, 316L stainless
steel
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene-
lined (1 operating, 1 spare)
25 ft dia x 26 ft high, 34,100
96,000 gal, w/cover, carbon
steel, neoprene-lined
(4-hour capacity)
Side entering, 50 hp, neoprene 68,000
coated
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
Rotary precoat type, 6 ft dia x 178,600
8 ft long, 151 ft2, 40 hp, 316
stainless steel
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
25 ft dia x 26 ft high, 96,000 34,100
gal, w/cover, carbon steel,
neoprene-lined (4-hour capacity)
Side entering, 50 hp, neoprene 68,000
coated
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
(continued)
45
-------
TABLE 13 (continued)
Item
No.
Description
Total material
cost, 1979 $
15. Cooler, precarbo- 2
nator interstage
16. Pump, crystal- 2
lizer feed
17. Crystallizer
18. Pump, carbonater 2
feed
19. Cooler, crystal- 2
lizer effluent
20. Carbonator
21. Pump, decomposer 2
feed
22. Decomposer
23. Pump, mixing tank
feed
24. Cooler, decom-
poser effluent
25. Pump, decomposer 2
reboiler feed
Plate and frame type heat 155,600
exchanger, 4050 ft*, carbon
steel with titanium plates
(1 operating, 1 spare)
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene lined
(1 operating, 1 spare)
Sieve tray column, 12 ft dia x 83,700
58 ft high, 316 stainless steel
Centrifugal, 400 gpm, 100 ft 9,100
head, 25 hp, carbon steel,
neoprene lined (1 operating,
1 spare)
Plate and frame type heat 80,000
exchanger, 1500 ft^ carbon
steel with titanium plates
(1 operating, 1 spare)
Sieve tray column, 10 ft dia x 74,600
58 ft high, 316 stainless steel
Centrifugal, 400 gpm, 100 ft 9,100
head, 25 hp, carbon steel,
neoprene lined (1 operating,
1 spare)
Sieve tray column, 10 ft dia x 79,900
62 ft high, Incoloy 800 lined
with carbon steel shell
Centrifugal, 400 gpm, 100 ft head, 9,100
25 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
Plate and frame type heat 123,000
exchanger, 2870 ft , carbon
steel with titanium plates
(1 operating, 1 spare)
Centrifugal, 2600 gpm, 60 ft head, 22,100
100 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
(continued)
46
-------
TABLE 13 (continued)
Item
No.
Description
Total material
cost. 1979 $
26. Reboiler,
decomposer
27. Condenser, 1
decomposer
28. Compressor, process 3
off-gas
Subtotal
Shell and tube heat exchanger,
4400 ft2, 304 stainless steel
shell with Carpenter alloy 20
tubes (1 operating, 1 spare)
Shell and tube heat exchanger
2250 ft2, 304 stainless steel
Centrifugal, 6200 sft^/min,
700 hp, 304 stainless steel
(2 operating, 1 spare)
Heater
2. Pump, sulfur
transfer
carbon steel, insulated
Steam, 100 ft2, 400 ft of 1-in.
chedule 40, carbon steel
Centrifugal, 12 gpm, 100 ft
head, 2 hp, steam traced and
insulated, carbon steel
(1 operating, 1 spare)
(continued)
226,300
41,900
501,000
2,307,800
Area
1.
Area
1.
8 — Sulfur Production
Item No .
Glaus unit 1
Subtotal
9 — Sulfur Storage
Item No .
Pit, sulfur 1
receiving
Description
j-stage Glaus unit complete,
96% efficient, 123 tons of
sulfur/day (battery limits
cost)
Description
10 ft long x 10 ft wide x
10 ft high, 1000 ft3, w/ cover,
Total material
cost, 1979 $
3,045,000
3,045,000
Total material
cost, 1979 $
5,500
700
2,100
47
-------
TABLE 13(continued)
Item
No.
Description
Total material
cost, 1979 $
3. Tank, sulfur
storage
Heater
45 ft dia x! 46 ft high, 547,300
gal, w/cover, carbon steel,
insulated
Steam, 300 ft3, 1200 ft of 1-in.
Schedule 40, carbonx steel
94,700
2,100
4. Pump, sulfur
shipping
Subtotal
Centrifugal^ 60 gpm, 100 ft
head, 5 hp, steam traced and
insulated, carbon steel
(1 operating, 1 spare)
5,000
110,100
48
-------
Materials Handling Area
Dry soda ash containing 99.8% Na2C03 is unloaded from pneumatic-
equipped transporters and stored as a wet slurry in a covered tank with
a 30-day capacity. Storage of sodium carbonate in slurry form is well
known in the chemical industry and is economically advantageous because
the equipment needed for slurry storage is significantly smaller. Dry
soda ash with a bulk density of 35 lb/ft^ is transformed into a wet
sodium carbonate monohydrate with a bulk density of 56 lb/ft-% thereby
decreasing the volume needed to store equal weights of the material.
The storage tank is insulated to keep the contents above 105°F to avoid
the formation of the heptahydrate and decahydrate, which are difficult
to dissolve. The monohydrate, however, readily dissolves. Maintenance
of tank temperature is not difficult since a considerable amount of heat
is evolved in the charging process by the heats of solution and monohydra-
tion. The transition from water to a slurry creates a temperature rise
of 60°F. The saturated solution above the slurry is 32% by weight
Na2C03. As this solution is removed to supply the system makeup require-
ments, process condensate at about 140°F is sparged into the tank bottom
to dissolve some Na2C03'H20 and replenish the tt^COg solution. The
initial temperature rise and the addition of 140°F condensate eliminate
the need for an external heat supply to the insulated tank.
Gas Handling and Fly Ash Collection Areas
This area consists of all flue gas ductwork between the power plant
ID fans and the stack plenum. The four power plant ID fans discharge
into a common plenum that is connected by individual ducts to each of
the four spray dryers. The spray dryers are connected individually to
the four ESP's. Each ESP is connected to a downstream ID fan, which
compensates for the 15 in. t^O pressure drop in the FGD system. The ID
fans discharge into the stack plenum. All ductwork between the power
plant ID fans and the stack plenum, and the FGD ID fans, is included in
the FGD costs.
In addition, four cyclone collectors, situated between the boiler
air heaters and the power plant ID fans, are included in the FGD costs.
These collectors remove 85% of the fly ash to facilitate subsequent
absorbent processing. Fly ash handling and disposal costs are not
included in FGD costs.
S02 Absorption and Removal Areas
The ACP uses four trains of spray dryer absorbers and ESP's. The
spray dryers are carbon steel, 42-foot diameter, 65-foot high, conical-
bottom vessels. Four rotary-disk atomizers, driven by vertically mounted
motors, are installed in the top of each spray dryer. Under normal
conditions, three atomizers are operated and the fourth serves as a
spare. The absorbent solution is pumped from the solution feed tank at
a concentration of about 23% Na2C03- This is diluted with water at a
rate controlled by the S02 content of the cleaned flue gas. The diluted
solution is pumped to the atomizers at a rate controlled by the tempera-
ture of the flue gas leaving the spray dryer.
49
-------
The flue gas enters the top of the spray dryer at 300°F through a
distribution plenum and passes downward through the atomized Na2C03
solution. The S02 and HC1 in the flue gas react with the Na2CC>3 to
form Na2S03, Na2S04, and NaCl, which, with the unreacted Na2C03, form
particulate matter as the liquid* in the Na2C03 solution is evaporated.
The sodium-salt particulate matter, along with the fly ash remaining in
the flue gas, is carried out of the bottom of the spray dryer in the
flue gas, which is cooled to 170°F by evaporation of the liquid.
The flue gas passes through an ESP designed for a collection
efficiency of 99.34% with a specific collecting area (SCA) of 350 ft2
per kaft-Vmin of flue gas. The cleaned flue gas passes through the FGD
ID fan and enters the stack plenum at 170°F without reheating. The
particulate matter from the four ESP's is transferred to two carbon-
steel particulate matter silos in a negative-pressure pneumatic conveying
system. Each silo has a capacity of 12 hours.
Reduction Area
In this area the particulate matter is blended with ground power
plant coal and the sulfur salts are reduced to Na2$ in four trains of
molten salt reducers. The melt, containing Na2S, other sodium compounds,
and residual solids, is quenched and dissolved for further processing.
The off-gas is sent to the off-gas processing area.
Coal from the power plant stockpile is conveyed to a raw coal silo.
The coal is ground to 80% to pass 200 mesh in two roller mills and
conveyed by bucket elevator to a 24-hour-capacity ground coal silo.
The sodium-salt particulate matter and the ground coal are metered
with weigh feeders into a pneumatic conveying system and transferred to
the four reducer feed hoppers. The feed rate of the sodium-salt particu-
late matter is based on the CO:C02 ratio in the reducer off-gas. The
coal feed rate is based on the reducer melt temperature. For the base
case, a total of 78,300 Ib/hr of particulate matter and 14,500 Ib/hr of
coal are fed to the four reducers.
Each reducer consists of a cylindrical carbon steel vessel 18 feet
in diameter and 34 feet high. The bottom half of the reducer is lined
with 6 inches of Alfrax 66® overlain by 15 inches of Monofrax A®, both
alumina refractory materials. The bottom of the reducer is a truncated
cone containing 3 solids injection nozzles and 16 combustion air injection
nozzles. The reduced melt (sometimes called smelt) is withdrawn through
overflow nozzles about 10 feet from the bottom. The off-gas is withdrawn
through vents in the top of the reducer. Each reducer is equipped with
a steam-water shatter jet and quench tank for the melt and a recuperator
and waste heat boiler for the off-gas. The recuperator is equipped with
fuel-oil heating equipment to heat combustion air during startup and
downtimes. The particulate matter - coal mixture is discharged from the
reducer feed hopper through rotary air locks into a pneumatic conveying
system, which blows it into the reducer through the injection nozzles.
Simultaneously, combustion air, heated to 1000°F by the reducer off-gas,
50
-------
is injected through the air nozzles. The molten bed is maintained at
1800°F by control of the combustion air and coal rates. The reduced
melt from the overflow nozzles flows by gravity to the quench tank.
Steam and water are injected into the overflow line between the reducer
and the quench tank to solidify and shatter the melt. The shattered
melt is dissolved by addition of water to the agitated quench tank to
form green liquor.
The green liquor contains about 24% total solids, of which about
40% is Na2S, about 15% each is Na2C03, Na2S04, and Na2Si03, 6% is NaCl
(the equilibrium recycle level), and the rest is fly ash and other
insoluble material.
The C02~rich off-gas from the reducer is passed through a recuperator,
where it is cooled to 1000°F in heating the reducer combustion air, and
through a waste heat boiler, where it is cooled to 560°F in producing
steam. The off-gas is then sent to the off-gas treatment area.
Off-Gas Treatment Area
The reducer off-gas is about one-half N2 and one-third C02 and
contains about 2% particulate matter (NaCl, Na2C03, Na2S04>. The off-
gas is scrubbed with water in a variable-throat venturi and dehumidified
in a packed column. Water withdrawn from the bottom of the dehumidifier
is pumped through a water-cooled plate and frame heat exchanger and into
the scrubber. A purge stream containing the particulates removed from
the off-gas is discharged to a tank from which it is pumped to the ash
pond. In addition to cooling and cleaning the off-gas, this treatment
also serves as a chloride purge mechanism. About one-third of the
chlorides entering the reducer leave it in the off-gas and are removed
from the system in the purge stream. A separate scrubber is used for
each reactor. One dehumidifier is used for all four scrubbers. The
quench tank off-gas, consisting of steam and reducer off-gas, is scrubbed
with water in a tray tower. A separate scrubber is used for each of the
four quench tanks. The treated gas is combined with the treated reducer
off-gas. About two-thirds of the treated gas is returned to the carbo-
nation process. The remainder is sent to the Glaus unit incinerator.
Carbonation Area
In this area the green liquor is processed in a series of steps
that produce H2S and Na2C03. Reducer off-gas from the off-gas treatment
area and decomposer off-gas are used as the C02 source. A single train
of process equipment is used.
Green liquor from the green liquor storage tank is first treated in
the precarbonator with a portion of the product t^S to form NaHS. The
precarbonator is a sieve tray column 8 feet in diameter and 60 feet
high, which operates at 100°F and atmospheric pressure. The H^S passes
upward, countercurrently to the green liquor flow. The precarbonator
off-gas is piped to the Glaus unit incinerator. A sidestream is with-
drawn from the precarbonator and filtered in a rotary filter to remove
51
-------
fly ash that is in the particulate matter feed to the reducer and the
solids from the reducer coal. This sidestream also serves to control
the precarbonator temperature. The filtrate is passed through a plate
and frame, water-cooled heat exchanger before being returned to the
precarbonator. Surge tanks are included in the filter loop to allow
filter downtime for precoating. The filter cake is disposed of in the
power plant ash pit. The precarbonator bottoms, a solution of about 30%
solids consisting of about 55% NaHS, 5% NaCl, and the remainder
Na2C03, and Na2SO^, are pumped to the crystallizer and carbonator.
The crystallizer and carbonator, both sieve tray columns 58 feet
high and 12 and 10 feet in diameter, respectively, are used to treat the
NaHS with C02 to form NaHC03 and H^S. The gas stream, consisting of the
combined treated reactor off-gas and decomposer off-gas streams, containing
about 54% C02> flows countercurrently to the liquid stream through the
carbonator and crystallizer. Small qu Cities of water are added to
each vessel to control concentrations. .ie crystallizer operates at
118°F and 7 psig; the carbonator operates at 110°F and 17 psig. Conversion
is roughly r in each vessel. The crystallizer off-gas consists of
about 30% H2S, 40% N2, and 16% C0£ with some H20, CO, and 02. Half of
this stream is sent to the Glaus unit and ha3 f is sent to the precarbo-
nator. The bottoms from the carbonator contax about 32% solids composed
of about 87% NaHC03, 9% Na2S04, and 4% N ^ - The carbonator bottoms are
pumped to the decomposer through a heat excha .ger to exchange heat with
the decomposer bottoms.
The r">. ,^^ose.r is also a sieve tray column, 10 feet in diameter and
62 feet hi*'., in which the NaHC03-rich liquid is ' jated at 254°F at 12
psig to form Na2C03. The liquid is heated by circulation through a
shelj. and tube heat exchanger. The bottoms, cou.-J.ning about 28% solids
composed of 82% Na2C03, 13% Na2S04, and 5% NaCi, are pumped to the
solution feed tank for reuse. The overhead vapor, which is almost all
C02, is combined with the reducer off-gas for use in the carbonator and
crystallizer.
Sulfur Production and Storage Areas
The sulfur production area includes a battery limits Glaus unit.
This unit is a conventional three-stage Glaus plant consisting of a
reaction furnace and waste-heat boiler, three converter and condenser
stages, a coalescer to strip sulfur from the off-gas, and an oil-fired
tail gas incinerator. The incinerator is also used to burn excess
reactor off-gas and precarbonator off-gas, neither of which contains
appreciable combustibles. For the base case, the flow rate to the Glaus
unit is about 37,000 Ib/hr of gas containing about 30% H2S. Conversion
is 96%, producing about 10,000 Ib/hr of sulfur. About 30,000 Ib/hr of
Glaus unit off-gas and 40,000 Ib/hr of ACP off-gas are burned in ie
incinerator, returning about 430 Ib/hr of sulfur to the flue gas. The
Glaus plant sulfur is pumped to a steam-heated receiving pit 10 feet
square and 10 feet deep, f r'- ., which it is pumped to a steam-heated, 30-
day-capacity storage tank.
52
-------
WELLMAN-LOKD PROCESS
TVA previously evaluated the Wellman-Lord process in 1975 (McGlamery
et al., 1975) using the Allied Chemical methane (natural gas) reduction
process for production of sulfur. The design and economic premises upon
which the evaluations are based have been updated since 1975. There
have also been significant design changes in the Wellman-Lord process
since the 1975 study. The soda ash is stored as a slurry instead of as
a dry solid. A prescrubber has been added to prevent chloride buildup
in the absorbent liquid. All stainless steel is now 316 SS rather than
304 SS. The absorber design is now based on cast concrete construction.
A filter has been added to remove residue particulate matter from the
scrubber effluent. The use of an antioxidant to control sulfate formation
has been discontinued and sulfate formation is minimized by control of
scrubbing conditions. Sulfate formation has been reduced and only 17%
of the scrubber effluent is processed to remove sulfates. This is now
done in a steam-heated evaporator rather than a chiller-crystallizer.
The 17% rate is based on design guarantees for the Northern Indiana
Public Service Company's Mitchell Station unit. Recent operating
experience there, and at the Public Service of New Mexico's San Juan
Station, has shown lower sulfate formation rates. For the base-case
conditions used in this study, the soda ash consumption is 1800 Ib/hr
and the dryer product is 2300 Ib/hr. Based on the operating data, the
rates would be 1500 Ib/hr of soda ash and 1900 Ib/hr of dryer product.
Basically, the same Wellman-Lord process is used for all three end-
plant cases. Minor changes in process design and overall flow rates are
required to satisfy the requirements of the particular end plants. In
particular, the S02:H20 ratio of the product gas differs because of end-
plant process requirements and the quantity of S02 in the product gas
differs because of different quantities of S02 in the tail gas returned
to the Wellman-Lord system. The Wellman-Lord process for the sulfuric
acid case is described in full. This description also applies to *;he
Resox" and Allied Chemical coal/S02 reduction processes except for the
process-specific differences described for these two processes.
WELLMAN-LORD/SULFURIC ACID PROCESS
This process incorporates a conventional contact sulfuric acid unit
with the Wellman-Lord process. The base-case process (a new 500-MW
power plant using 3.5% sulfur coal) has four gas trains and, with the
exception of the evaporator section, a single regeneration train. Case
variations follow a similar design except that the 200-MW case variations
have two gas trains. A single, appropriately sized, sulfuric acid unit
is used for all cases.
The base-case Wellman-Lord process flow diagram is shown in Figure 5.
The material balance shown in Table 14 applies to all three processes,
with the exceptions for Wellman-Lord/Resox and Wellman-Lord/Allied
processes specified later in the discussion of these processes. The
53
-------
Ui
ATMOSPHERE
DUST (],
ILLECTORI P^
UMESTONE
FEED
BIN
f
NE
-•-B-
Figure 5. Wellman-Lord process flow diagram.
-------
TABLE 14. WELLMAN-LORD/SULFURIC ACID PROCESS
BASE CASE MATERIAL BALANCE
Stream No.
Description
i
2
j
4
5
6
7
8
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
gprn
Specific gravity
pH
Undissolved solids, %
1
Coal to boiler
428,600
2
Combustion air
to air heater
4,546,200
1,005,000
ISO
3
Combustion air
to boiler
4,101,800
906,700
535
4
Gas to
air heater
4,516,100
958,000
705
5
Gas to
electrostatic
precipitator
4,960,400
1,056,000
300
Stream No.
Description
1
2
i
4
b
6
7
8
9
1°,
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, ps'-'a (in. WG)
gpm
Specific gravity
pH
Undissolved solids, %
6
Gas
to plenum
4,905,800
1,056,000
300
7
Gas to
FD fan
4,980,600
1,070,200
298
8
Gas to chloride
scrubber
4,980,600
1,070,200
311
(19)
9
Gas to absorber
5,195,300
1,143,800
130
(13)
10
Gas to reheater
5,181,200
1,143,900
134
(4)
Stream No.
1
I
J
4
b
6
/
8
9
10
Description
Total stream, Ib/hr
sft3/min (60°F)
Temcerature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
PH
Undissolved solids, %
11
Gas to stack
5,181,200
1,145,800
175
12
Steam to
reheater
79,700
470
515
13
Makeup water
to chloride
scrubber
225,400
80
450
14
Pond water to
recirculation
tank
55,400
80
110
15
*
Mist eliminator
wash water to
S02 absorber
100.000
80
200
Stream No.
1
2
j
4
5
6
7
H
9
10
Description
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
PH
Undissolved solids, %
16
Absorber
effluent
to filter
390,400
134
600
1.3
17
A
Sluicing water
to filter
150,100
80
300
18
Filtered
effluent
to absorber
product tank
390,300
134
600
1.3
19
*Filter
sluice to
effluent sump
150,700
80
300
20
Filter aid to
precoat tank
(100 Ibl
.Intermittent streams, 24 hour average rates for streams 15 and 17 are 1.5 and 6 gpm respectively.
(continued)
55
-------
TABLE 14 (continued)
Stream No.
Description
1
2
J
4
5
6
7
8
9
10
Total stream, Ib/hr
s£t3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
pH
Undissolved solids, %
21
Chloride
scrubber
effluent to
neutralization
tank
66.100
130
130
1.01
1
22
Limestone to
neutralization
tank
900
23
Neutralized
waste to
ash pond
66,900
130
1.01
24
Heated
absorber
product
390.300
145
600
1.3
25
Condensate
to dissolving
tank
231.800
143
460
Stream No.
Description
I
I
i
4
5
6
7
8
9
If)
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
PH
Undissolved solids, %
26
Heated
absorber product
to evaporator
preheaters
370,000
152
570
1.3
27
Heated
absorber product
to sulfate
crystallizer
66.400
145
102
1.3
28
Sulfate
crystallizer
liquor to
centrate tank
41.500
205
60
1.34
29
Sulfate
crystallizer
condensate
to clean
condensate tank
20.000
161
40
30
Crystallizer
bottoms
to centrifuge
6.600
205
8
1.6
30
Stream No.
Description
1
2
J
4
5
6
7
8
y
10
Total stream, Ib/hr
sft3/mln (60°F)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
pH
Undissolved solids, %
31
Centrifuge cake
to dryer
2,000
205
90
32
Dryer product
o storage
2,300
270
33
Steam to dryer
1,400
470
515
34
Sulfate
crystallizer
liquor
to regeneration
area
46,100
205
70
1.34
35
Steam
to sulfate
crystallizer
20,000
250
30
Stream No.
Description
1
2
i
4
5
6
/
8
y
JO
Total stream. Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
Epm
Specific gravity
T>H
Undissolved solids. %
36
Sulfate
crystallizer
vapor
to regeneration
area
18.300
6,300
205
10
37
Feed
to second
effect
evaporator
159.100
170
240
1.3
38
Second effect
evaporator
condensate
to stripper
93.700
187
190
39
First
effect vapor
to primary
condenser
53.800
16,100
187
4.5
40
Second effect
evaporator
liquor to
dissolving tank
61.800
170
70
1.66
50
(continued)
56
-------
TABLE 14 (continued)
Stream No.
Description
1
2
1
4
•i
6
7
K
q
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
pH
Undissolved solids, %
41
Second
effect vapor
to primary
condenser
97,400
32,100
170
4.5
42
Combined vapor
to primary
condenser
151,200
48,200
176
4.5
43
Cooling water
to condensers
4,783,700
80
9,560
44
Steam
to stripper
9,000
250
30
45
S02~rich gas
to compressor
22,100
2,900
110
3.5
Stream No.
Description
I
2
3
4
5
6
7
8
9
If)
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
PH
Undissolved solids, %
46
Feed to
first effect
evaporator
210,900
205
320
1.3
47
First
effect vapor
to second
effect heater
129,100
42,500
205
10
48
Steam
to first
effect heater
127,200
250
30
49
First effect
evaporator
liquor
to decanter
81,900
205
100
1.66
50
50
Decanter
underflow to
dissolving tank
80,600
205
100
1.66
51
Stream No.
Description
1
2
)
4
5
f-
7
8
9
10
Total stream, Ib/hr
sft3/min (60°F)
Temperature. °F
Pressure, psia (in. WG)
Epm
Specific gravity
PH
Undissolved solids, %
51
Condensate to
second effect
feed preheater
25,900
250
50
52
Condensate to
first effect
feed preheater
101,300
250
200
53
Condensate from
second effect
feed preheater
25,900
166
50
54
Condensate from
first effect
feed preheater
101,300
167
200
55
Stripper
bottoms
to absorber
product heater
231,800
157
460
Stream No.
Description
1
2
3
4
5
6
/
«
9
10
Total stream, Ib/hr
sft3/min (60AF)
Temperature, °F
Pressure, psia (in. WG)
gpm
Specific gravity
pH
Undissolved solids, %
56
Condensate
to soda ash
storage tank
3,800
143
8
57
Makeup
soda ash to
storage tank
1.800
58
Soda ash
solution to
dissolving tank
5,600
110
9
1.33
59
Scrubbing
solution
to S02 absorber
375,200
153
600
1.26
60
Dissolving
tank vent
to plenum
800
110
153
(continued)
57
-------
TABLE 14 (continued)
Stream No.
1
2
j
4
5
6
7
8
9
10
Description
Total stream, Ib/hr
sft3/min (60°F)
Temperature, °F
Pressure, psia (in. WG)
spm
Specific gravity
PH
Undissolved solids, %
61
Dryer offgas
to plenum
1,000
320
270
62
Thiosulfate
purge to dryer
1,300
205
2
1.26
63
Acid plant
tailgas
to plenum
73,000
16,000
170
64
Combined gases
to plenum
74,800
16,400
170
65
SC>2-rich gas
to end plant
22.100
2,930
382
15
58
-------
design drawings shown in Figures 6-8 apply to all three processes. The
flow diagram and the base-case material balance for the sulfuric acid
unit are shown in Figure 9 and Table 15 respectively.
The Wellman-Lord/ sulf uric acid process is divided into nine operating
areas: materials handling, gas handling, chloride removal, S02 absorption,
stack gas reheat, sulfate crystallization, regeneration, sulfuric acid
production, and acid storage and shipment. Table 16 contains a descrip-
tion of the equipment items in each area and the purchase cost of the
equipment. The costs in Table 16 are the purchase cost only and do not
include cost of erection.
Expenditures for all flue gas ductwork are accounted for in the gas
handling area. The acid production area investment is a battery-limits
quotation by a sulfuric acid unit vendor. In addition to the previously
described direct investment components, the acid unit estimate shown in
Table 16 includes all indirect investment costs incurred by the vendor.
This indirect cost is 45% of the battery-limits quotation.
Materials Handling Area
Dry soda ash containing 99.8% Na2C03 is unloaded from pneumatic
equipped transporters and stored as a wet slurry in a tank with a 30-day
capacity. The storage system is the same as the one described for the
ACP. Minor equipment differences are the result of different process
requirements and vendor design differences. As this solution is removed
to supply the system makeup requirements, process condensate at about
140°F is sparged into the tank bottom to dissolve Na2C03'H20 and
replenish the Na2C03 solution.
Gas Handling Area
A common plenum is situated downstream from the ESP units and the
power plant ID fans to distribute gas to the four trains of the absorption
system. A booster forced-draft (FD) fan in each train between the
plenum and the absorber compensates for the pressure drop through the
FGD system. This study assumes the flue gas enters the plenum at 300°F.
Mixing 300°F flue gas with 170°F recycle gas from the sulfuric acid unit
produces a mixture of gases at 298°F. A temperature rise to 311°F is
used, assuming that the gas contains the adiabatic heat of compression
and all frictional heat generated. After passing through the FGD system
and reheater the flue gas of each train is ducted to the stack plenum.
All equipment downstream from the power plant ID fans and upstream from
the stack plenum is included in the FGD costs .
Chloride Neutralization Area
The flue gas is first cooled and humidified and approximately 70%
of the chloride is removed in a low-energy venturi scrubber upstream
from each S02 scrubber. The venturi scrubbers use recycle pond liquor.
Further chloride removal is accomplished in a spray chamber equipped
with three banks of nozzles spraying perpendicularly to the gas flow.
59
-------
_
o
Q
Figure 6. Wellman-Lord process plot plan.
-------
2nd EFFECT
EVAPORATOR CRYSTALLIZER
ABSORBER FEED TANK
PRODUCT
FILTER
SOLUTION
HEATERS
CRYSTALLIZER
ABSORBER PRODUCT TANK
LIMESTONE
STORAGE SILO
ELEVATION A-A
SODA ASH
STORAGE TANK
SULFATE STORAGE
SILO
\ /
ELEVATION B-B
Figure 7. Wellman-Lord process regeneration area elevation drawing.
-------
PROCESS AND MOTOR CONTROL BUILDING
LABORATORY AND LOCKER ROOMS
PRIMARY CONDENSERS (ABOVE)
SECONDARY CONDENSERSIBELOW
SULFATE
CRYSTALLIZER
EVAPORATOR
CRYSTALLIZERS
EVAPORATOR
CRYSTALLIZERS
SULFATE
STORAGE
SILO
ABSORBER
PRODUCT TANK
LIMESTONE
STORAGE SILO
SODA ASH
STORAGE TANK
Figure 8. Wellman-Lord process regeneration area layout drawing.
-------
CONDENSATE
FROM
FLASH DRUM
SO: RICH GAS STREAM
FROM
WELLMAN-LORD UNIT
TO
NO 3 AND 4
EXCHANGERS
NO 4
EXCHANGER
START-UP
HEATER
STEAM TO
WELLMAN- LORD
PLANT
NO 2 AND 3
EXCHANGERS
- CONDENSATE FROM WELLMAN-LORD PLANT
CONDENSATE
FLASH DRUM
CONDENSATE
- FROM NO 5
EXCHANGER
TO NO. 5 EXCHANGER -
PRODUCT SULFURIC ACID
TAILGAS TO WELLMAN-LORD UNIT
COOLING WATER
Figure 9. Sulfuric acid unit flow diagram.
-------
TABLE i^. 3ULFURIC ACID UNIT
BASE CASE MATERIAL BALANCE
Stream No.
Description
i
2
j
4
5
6
7
8
9
10
Total stream, Ib/hr
3ftJ/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
PH
Undissolved solids, %
1
Gas from
Wellman-l-o.-d
plant
22.100
2,930
382
15
2
PI- tass air
77.300
16,900
80
3
Process water
2.840
80
6
4
Cooling water
1.050.800
80
2.100
5
Condensate from
Wellman-Lord
plant
6,800
165
14
Stream No.
1
2
!
4
b
6
7
8
9
IP,
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
PH
Undissolved solids, 7,
6
Steam to
Wellman-Lord
' .nt
6,800
250
30
7
Tail gas to S02
absorber
73.000
16,000
170
8
982 H2S04
29,200
110
32
1.82
64
-------
TABLE 16. WELLMAN-LORD/SULFURIC ACID PROCESS
BASE-CASE EQUIPMENT LIST
Area 1—Material Handling
Item
No.
Description
Total material
cost. 3979 $
1. Car shaker
2. Tank, soda ash 1
storage
3. Pump, soda ash 2
feed
4. Dust collecting 1
system
5. Conveyor,
limestone
6. Silo, limestone
storage
7. Bin, limestone 1
feed
Subtotal
Top mounting with crane, 20 hp
shaker, 7-1/2 hp crane
33 ft dia x 32-1/2 ft high,
207,950 gal, w/cover, carbon
steel, insulated, 3 spargers
in bottom (30-day capacity)
Centrifugal, 9 gpm, 60 ft head,
1/2 hp, carbon steel
(1 operating, 1 spare)
Bag filter, polypropylene bag,
4,000 aft-Ymin, automatic shaker
system
Pneumatic, positive pressure, con-
veying system, 41 tons/hr, 75 hp
19 ft dia x 29 ft straight side,
8,200 ft3, 60° slope, 3/8 in.
carbon steel hopper
(30-day capacity)
5-1/2 ft dia x 8-1/2 ft straight
side height, w/cover, 30° cone
hopper, carbon steel
(8-hr capacity)
19,900
38,400
3,300
12,200
102,900
13,000
1,500
191,200
Area 2—Gas Handling
Item
No.
Description
Total material
cost, 1979 $
1. Fans
Subtotal
Forced draft, 390,000 aft3/min,
19.7 in. static head, 1,750 hp
fluid drive, double width,
double inlet
864,000
864,000
(continued)
65
-------
TABLE 16 (continued)
Area 3—Chloride Neutralization
Item
No.
Description
Total material
cost, 1979 $
1. Chloride scrubber 4
Venturi-spray chamber combina-
tion, venturi: 13 ft dia x
25 ft overall height, variable
throat, carbon steel, elastomer
and tile lined, Hastelloy G
throat
1,834,200
2. Tank,
recirculation
Agitator, recir-
culation tank
Pump, venturi
recirculation
Pump, spray
chamber
recirculation
Tank,
neutralization
7. Agitator, neu-
tralization tank
Spray chamber: 24 ft x 20 ft x
11 ft high, carbon steel,
elastomer and tile lined,
Hastelloy G nozzles with
stellite tips; Hastelloy G mist
eliminator
20 ft dia x 6 ft high, 14,100 gal,
w/cover, four 20 in. baffles,
agitator supports, carbon steel,
neoprene lined, insulated
(10-min capacity)
80 in. dia, 1-1/2 hp, neoprene
coated
Centrifugal, 3,140 gpm, 60 ft
head, 100 hp, carbon steel,
neoprene lined
(4 operating, 4 spares)
Centrifugal, 3,140 gpm, 150 ft
head, 250 hp, carbon steel,
neoprene lined
(4 operating, 4 spares)
11-1/2 ft dia x 6 ft high, 4,660
gal, w/cover, four 11-1/2 in.
baffles, agitator supports,
carbon steel, neoprene lined,
insulated (30-min capacity)
46 in. dia, 1 hp, neoprene
coated
29,400
15,200
118,200
212,500
2,700
2,700
(continued)
66
-------
TABLE 16 (continued)
Item
No.
Description
Total material
cost. 1979 $
8. Pump, pond feed
9. Pump, pond
water return
10. Feeder, lime-
stone feed bin
discharge
11. Pump, raw water
12. Pump, chloride
scrubber water
booster
Subtotal
Centrifugal, 130 gpm, 150 ft
head, 15 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Centrifugal, 300 gpm, 150 ft
head, 25 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Weigh, screw, 6 in. dia x 10
ft long, 1 hp, 900 Ib/hr
Centrifugal, 650 gpm, 150 ft
head, 60 hp, carbon steel
(1 operating, 1 spare)
Centrifugal, 450 gpm, 150 ft
head, 40 hp, carbon steel
(1 operating, 1 spare)
11,200
16,200
5,300
18,200
17,000
2.282,800
Area 4—S09 Absorption
Item
No.
Description
Total material
cost, 1979 $
1. S02 absorber
Pump, S02
absorber
recirculation
Pump, absorber
effluent
4 Valve tray, 24 ft x 24 ft x 50 1,414,400
ft high, concrete, tile lined,
insulated, 3-316 stainlesss steel
valve trays, 2-316 stainless steel
chimney trays, 1-316 stainless
steel mist eliminator
16 Centrifugal, 550 gpm, 20 ft 60,700
head, 10 hp, carbon steel,
neoprene lined
(12 operating, 4 spares)
8 Centrifugal, 150 gpm, 200 ft 65,600
head, 25 hp, carbon steel,
neoprene lined
(4 operating, 4 spares)
(continued)
67
-------
TABLE 16 (continued)
Item
No.
Description
Total material
cost, 1979 $
4. Filter, 2
absorber product
5. Sump, effluent 1
6. Agitator,
effluent sump
7. Pump, effluent
8. Tank, absorber 1
product
9. Pump, absorber 2
product tank
10. Heater, absorber 1
product
11. Soot blowers 20
Subtotal
Pressure leaf, 60 in. dia x
11 ft long, 800 ft2, 316
stainless steel, insulated
8 ft x 8 ft x 8 ft deep,
concrete, tile lined,
grating covered
32 in. dia, 2 hp, neoprene
coated
Centrifugal, submerged, 100 gpm,
60 ft head, 5 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
54-1/2 ft dia x 54-1/2 ft high,-
951,100 gal, w/cover, concrete,
tile lined, insulated
(24-hr capacity)
Centrifugal, 600 gpm, 100 ft
head, 50 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Plate and frame type heat
exchanger, 350 ft2, 316
stainless steel, insulated
Air, retractable
202,800
7,000
6,200
5,300
157,000
11,600
8,300
130.000
2,068.900
Area 5—Reheat
Item
No.
Description
Total material
cost. 1979 $
1. Reheaters
2. Soot blowers
Subtotal
4 Steam, tube type, 3,170 ft2,
one-half tubes made of Inconel
625, and one-half made of
Cor-Ten
20 Air, retractable
787,200
130,000
917.200
(continued)
68
-------
TABLE 16 (confirmed)
Area 6—Sulfate Crystallization
Item
No.
Description
Total material
cost. 1979 $
1. Preheater,
crystallizer
feed
2. Cry&callizer,
sulfate
Heater
Recirculation
pump
3. Receiver,
condensate
4. Pump,
condensate
5. Pump, centrifuge
feed
6. Centrifuge
7. Tank, centrate
8. Agitator,
centrate tank
9. Pump, centrate
tank
10. Dryer
1 Plate and frame type, 80 ft2, 3,600
316 stainless steel, insulated
1 9 ft dia x 12 ft straight side, 651,800
316 stainless steel, insulated
1 Shell and tube type, 3,000 ft2,
316 stainless steel tubes and
heads, carbon steel shell,
insulated
1 Axial, 18,000 gpm, 15 ft head,
250 hp, 316 stainless steel
1 2 ft dia x 4 ft high, 90 gal,
w/cover, carbon steel, insulated
2 Centrifugal, 40 gpm, 60 ft
head, 2 hp, carbon steel
(1 operating, 1 spare)
2 Centrifugal, 8 gpm, 60 ft head,
3/4 hp, 316 stainless steel
(1 operating, 1 spare)
1 Solid bowl, continuous, 30 hp,
316 stainless steel
1 5 ft dia x 5-1/2 ft high, 810
gal, w/cover, four 5-in. baffles,
agitator supports, 316 stainless
steel, insulated (10-min capacity)
1 2 turbines, 20 in. dia, 1-1/2 hp,
316 stainless steel
2 Centrifugal, 70 gpm, 100 ft
head, 7-1/2 hp, 316 stainless
steel
(1 operating, 1 spare)
1 Mechanidally agitated, twin 262,200
screw, 316 stainless steel,
insulated
(continued)
69
300
3,400
4,800
80,800
8,000
3,800
7,600
-------
TABLE 16 (continued)
Item
No.
Description
Total material
cost, 1979 $
11. Dust collecting
system
12. Hopper, sulfate
surge
13. Conveyor,
sulfate
14. Silo, sulfate
storage
15. Feeder, sulfate
silo discharge
Subtotal
1 Bag filter, polypropylene bag,
450 aft^/min, automatic shaker
system
1 6-1/2 ft dia x 9 ft high, 280
ft^, w/cover, carbon steel
1 Pneumatic, positive pressure,
conveying system, 1 ton/hr,
10 hp
1 28 ft dia x 41-1/2 ft straight
side height, 25,550 ft3, 60°
slope, 3/8 in. carbon steel
hopper (30-day capacity)
1 Vibrating pan, 2 hp, 100 tons/hr
9,000
4,500
36,000
34,900
3,800
1.114.500
Area 7—Regeneration
Item
No.
Description
Total material
cost. 1979 $
1. Preheater, first
effect evapora-
tor feed
2. Preheater,
second effect
evaporator feed
3. Evaporator
system, double
effect unit
including:
Evaporator,
first effect
Heater, first
effect
Plate and frame type, 300 ft2
316 stainless steel, insulated
Plate and frame, 90 ft , 316
stainless steel, insulated
16 ft dia x 16 ft straight
side height, 316 stainless steel,
insulated
Shell and tube type, 8,900 ft2,
316 stainless steel tubes and
heads, carbon steel shell,
insulated
(continued)
70
6,800
3,700
2,616,300
-------
TABLE 16 (continued)
Item
No.
Description
Total material
cost, 1979 $
4.
5.
6.
7.
Pumps, first
effect recircu-
lation
Evaporator,
second effect
Heater, second
effect
Pumps, second
effect recircu-
lation
Receiver, first
effect conden-
sate
Receiver, second
effect conden-
sate
Pump, first
effect conden-
sate
Pump, second
effect conden-
sate
8. Tank, dissolving 1
9. Agitator, 1
dissolving tank
10. Pump, dissolving 2
tank
Axial, 62,000 gpm, 15 ft head,
900 hp, 316 stainless steel
(2 operating, 0 spare)
16 ft dia x 16 ft straight side
height, 316 stainless steel,
insulated
Shell and tube type, 13,300 ft2,
316 stainless steel tubes, heads,
and shell, insulated
Axial, 45,000 gpm, 15 ft head,
600 hp, 316 stainless steel
(2 operating, 0 spare)
3-1/2 ft dia x 4 ft high, 290
gal, w/cover, carbon steel,
insulated
3 ft dia x 4 ft high, 210 gal,
w/cover, 316 stainless steel,
insulated
Centrifugal, 130 gpm, 60 ft head,
5 hp, carbon steel
(2 operating, 2 spares)
Centrifugal, 90 gpm, 60 ft head,
5 hp, 316 stainless steel
(2 operating, 2 spares)
14-1/2 ft dia x 15-1/2 ft high,
19,150 gal, w/cover, four 14-1/2
in. baffles, agitator supports,
carbon steel, neoprene lined,
insulated (30-min capacity)
2 turbines, 58 in. dia, 7-1/2 hp,
neoprene coated
Centrifugal, 580 gpm, 100 ft head,
40 hp, carbon steel, neoprene
lined
(1 operating, 1 spare)
(continued)
1,100
7,000
10,600
15,600
14,200
12,000
10,500
71
-------
TABLE 16 (continued)
Item
No.
Description
Total material
cost, 1979 $
11. Separator,
mother liquor
12. Pump, mother
liquor
13. Tank, absorber
feed
14. Pump, absorber
feed tank
15. Stripper
16. Pump, stripper
17.
18.
Condenser,
primary
Condenser,
secondary
19. Pump, cooling
water
20. Blower, product
gas
21. Tank, central
condensate
4 ft dia x 2 ft straight side,
60° slope, 316 stainless steel,
insulated
Centrifugal, 2 gpm, 60 ft head,
1/2 hp, 316 stainless steel,
(1 operating, 1 spare)
54-1/2 ft dia x 54-1/2 ft high,
951,130 gal, w/cover, concrete,
tile lined, insulated
(24-hr capacity)
Centrifugal, 580 gpm, 100 ft
head, 40 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
4-1/2 ft dia x 20 ft overall
height, packed tower, 316
stainless steel, insulated
Centrifugal, 460 gpm, 100 ft
head, 25 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Shell and tube type, 5,100 ft2,
316 stainless steel tubes, heads,
and shell
Shell and tube type, 4,100 ft2,
316 stainless steel tubes, heads,
and shell
Centrifugal, 4,780 gpm, 150 ft
head, 400 hp, carbon steel,
neoprene lined
(2 operating, 2 spares)
Centrifugal, single stage, 2,930
sft3/min, 500 hp, 316 stainless
steel
8-1/2 ft dia x 8-1/2 ft high,
3,610 gal, w/cover, carbon steel,
insulated (10-min capacity)
(continued)
72
11,500
3,300
157,000
10,500
51,500
9,100
130,000
111,200
130,600
187,000
2,500
-------
TABLE 16 (continued)
Item
No.
Description
Total material
cost. 1979 $
22. Pump, condensate 2
return
Subtotal
Centrifugal, 310 gpm, 150 ft
head, 25 hp, carbon steel
(1 operating, 1 spare)
16,200
3.518,200
Area 8—98% Sulfuric Acid Production
Item
No.
Description
Total material
cost. 1979 $
1. Complete H2S04
unit
Subtotal
Complete 98% sulfuric acid
system (battery limits cost)
5,600,000
5.600,000
Area 9—Acid Storage and Shipping
Item
No.
Description
Total material
cost. 1979 $
Tank, acid
storage
Pump, acid
storage tank
discharge
Subtotal
49 ft dia x 50 ft high, 705,400
gal, w/cover, carbon steel,
insulated (15-day capacity each)
Centrifugal, 400 gpm, 100 ft
head, 40 hp, carbon steel,
insulated
(1 operating, 1 spare)
185,800
10,500
196,300
73
-------
Recycle liquor is sprayed from the first two banks and fresh ma ,ap
water from the third bank. From the chloride scrubber recycle ':• ks a
bleedstream of chloride-rich liquor overflows to a neutralizi' ,, tank to
which agricultural limestone is added. The neutralized wast , .-'ream is
pumped to the existing power plant ash pond. It is assumed .aat 85% of
the water in this waste stream is returned to the chloride recycle tank.
A chevron mist eliminator, placed between the spray chamber and the SC>2
absorber, prevents the carryover of chlorides to the absorber by removing
most of the entrained water.
S02 Absorption and Reheat Areas
The Wellman-Lord S0£ absorbers consist of four self-supporting,
tile-lined, reinforced-concrete vessels that share common walls and rest
on the ground. According to the manufacturer, the initial cost is lower
than that for either a neoprene-lined carbon steel or 316 stainless
steel vessel because of the common wall arrangement and the elimination
of a superstructure to support the vessels. The vessels can be designed
to support internal and external equipment. They are also claimed to
require less maintenance and to be more reliable than alloy steels or
elastomer-lined steels.
The S02 absorbers are valve tray towers with three valve trays,
each separated by a chimney tray, and a chevron mist eliminator. The
chimney trays provide adequate gas-liquid contact during periods when
rapid liquid-rate changes are made in response to changing flue gas
rates. The Na2S03~rich scrubbing solution is individually recirculated
around each valve tray to provide a higher degree of countercurrent
contact between the flue gas and the liquor. Fresh solution is intro-
duced above the top SC>2 absorber valve tray and successively overflows
from each valve tray into the next until it reaches the bottom of the
tower. Most of the absorbed S02 reacts with Na2SC>3 and H20 to produce
NaHSOs. In addition, a relatively small amount of Na2SC>4 is formed by
reaction of Na2S03 with 803 and C>2- The spent absorber effluent is
collected in the bottom section of the tower, filtered in a precoat-type
pressure leaf filter to remove residual fly ash, and pumped to a 24-
hour-capacity surge tank. Two filters, on line alternately, serve all
four absorbers. The filters are periodically sluiced with pond water,
which is dumped to a sump and used in the chloride scrubber. From the
surge tank about 17% of the effluent is pumped to the sulfate crystalli-
zation area and the remainder is pumped to the regeneration area.
The flue gas enters the absorber at 130°F and the cleaned, satu-
rated gas leaves the absorber at about 134°F, a temperature higher than
the typical FGD absorber exit temperature of 127°F, because the regener-
ated scrubbing solution enters at 150°F and because the highly concen-
trated sodium-salt scrubbing liquor solution has a boiling point
elevation of 5°F, resulting in less evaporative cooling. It is also
assumed that heat loss to the environment through the absorber walls is
negligible because the absorber is well insulated. The cleaned gas is
first passed through a chevron mist eliminator to reduce the entrained
moisture to 0.1% and is then heated to 175°F in an indirect steam
reheater before entering the stack plenum.
74
-------
Sulfate Crystallization Area
About 17% of the scrubber effluent is processed to remove
by selective crystallization in a single steam-heated, forced-circulation,
single-effect evaporator operating at 10 psia and 205°F. The bottoms,
consisting of a slurry enriched in Na2SC>4, are centrifuged to produce a
90% solids cake. The centrifuge cake is dried in a steam-heated,
mechanically agitated dryer to produce a byproduct that is about two-
thirds Na2S04 and one-third ^2803. The byproduct is conveyed pneu-
matically to a 30-day-capacity silo for storage until sale. The centrate
is combined with clear evaporator overflow and the resulting NaHS03~
enriched solution is pumped to the regeneration area.
Regeneration Area
The regeneration area consists of two trains of double-effect,
forced-circulation evaporators, a two-train condenser system, a stripper,
a compressor, and a dissolving tank. The first-effect evaporators
operate at 10 psia and 205°F. The second-effect evaporators operate at
4.5 psia and 170°F. The evaporator feed stream is scrubber effluent
combined with liquid from the sulfate removal section. The feed is
divided into two streams and heated from 152°F to the evaporator operating
temperatures. One stream (60% of the total) is pumped to the first-
effect evaporators and the other stream (40% of the total) is pumped to
the second-effect evaporators. In the evaporators, the feed stream is
heated at a controlled rate to produce an overhead vapor of S02 and 1^0
and to produce a bottoms slurry enriched in Na2S03 crystals. The
heating medium for the first-effect evaporators is steam. The first-
effect vapor and the sulfate crystallizer vapor are combined and used as
the heating medium in the second-effect evaporators.
The bottoms from the second-effect evaporators flow to a dissolving
tank. Highly soluble ^28203 is formed in the first-effect evaporators
because of their higher operating temperature. To control ^28203
concentration, first-effect evaporator bottoms are routed through a
decanter. A small liquid purge stream overflows to the sulfate dryer
and the underflow flows to the dissolving tank.
About 60% of the vapor heating the second-effect evaporators con-
denses and is pumped to a steam-stripper where S02 is removed. The
stripper also treats condensate from the condenser system. Saturated
250°F steam supplied to the bottom of the stripper countercurrently
contacts the condensate in a packed bed to remove S02- The stripper
operates at about 4 psia.
The uncondensed first-effect vapor from the second-effect heaters
is combined with second-effect evaporator overhead vapor and the combined
gas stream, containing about 96 mole % t^O, flows through the condenser
system. Each of the two trains in the condenser system contains two
water-cooled condensers arranged in series. In the primary condensers
about two-thirds of the water vapor is condensed. The remaining gas is
combined with the overhead vapor from the stripper and the mixture flows
75
-------
to the secondary condensers. In the secondary condensers, the gas is
cooled to about 110°F and dried by 1^0 condensation to about 36 mole %
H20. The cooled, dried gas at about 3.5 psia is compressed to atmospheric
pressure by a single-stage dry centrifugal compressor and routed to the
SC>2 processing unit.
Condensate from the primary and secondary condensers, along with
condensate from the second-effect evaporator heaters, is treated in the
stripper to remove dissolved S02- The stripped condensate is cooled by
heat exchange with absorber effluent and mixed with evaporator bottoms
in the dissolving tank to dissolve the ^2863 crystals. Na2CC>3 solution
is added to the mixture to replenish sodium lost from the system in the
dryer product. The resulting liquor is pumped to a 24-hour-capacity
surge tank for storage until it is needed in the absorbers.
Sulfuric Acid Production Area
The 64 mole % S02 stream from the Wellman-Lord process is converted
to t^SO^ in a conventional 98% efficient, single-contact, single-absorption
acid unit. The S02~rich gas stream is drawn into a packed drying tower
along with sufficient air to produce a 10 mole % 802 concentration at
the converter inlet. In the drying tower, the gas is passed counter-
currently to a stream of 93% t^SO^. The acid enters the tower at 110°F,
is heated to 150°F by dilution with absorbed water, and is recirculated
through a cooler to the top of the tower. Since there is insufficient
water in the 802 - air stream for the reaction between 803 and H20,
additional water is added to drying tower recycle stream. To maintain a
93% t^SO^ concentration in the drying tower recycle stream, some of the
byproduct 98% acid must be added to the stream.
The drying tower recycle stream also contains dissolved 802- To
remove the 802, some of the 93% acid produced in the drying tower system
is withdrawn and routed to a packed stripper. The dissolved 862 is
stripped by countercurrently contacting the acid with air. The S02 and
air mixture is routed to the main gas stream leaving the drying tower.
The stripped acid is added to the 803 absorption tower to maintain the
proper acid concentration. Entrainment separators in the stripper and
dryer prevent carryover of acid mist in the gas streams. The combined
stripper and dryer gas is passed through two heat exchangers in series
where it is preheated to 820°F with hot gases from the first and last
beds of the 802/803 converter. After preheating, the gas is routed
through a four-bed catalytic converter where 98% conversion of 802 to
803 is achieved. The exit conditions from each bed are: (1) 1150°F
and 63% conversion, (2) 965°F and 90% conversion, (3) 855°F and 97%
conversion, and (4) 805°F and 98% conversion. The inlet temperature is
820°F for each bed except bed 4 which has an inlet temperature of
800°F. As discussed previously, gas from beds 1 and 4 is used to pre-
heat the converter feed stream. The resulting gas, at 505°F, is further
cooled to 400°F in heat exchanger 5. The heat recovered in the heat
exchangers produces 15 psig steam for use in the Wellman-Lord evaporators.
76
-------
The 400°F SC^-rich gas flows to the 863 absorption tower where 863
is absorbed in a recirculating 98% t^SO^ stream. The acid is heated
from 170°F to 220°F in cooling the gas and absorbing the 803. The acid
from the tower flows through a cooler to control temperature. As discussed
previously, the water balance for the reaction between 863 and 1^0 is
maintained by adding to the absorber loop some 93% acid from the dryer-
stripper loop. The 98% product acid is withdrawn from the absorber
loop, cooled to 110°F, and pumped to 30-day-capacity storage tanks.
The gas stream from the absorption tower is at a temperature of
170°F and contains about 2500 ppm 802- After passing through an entrain-
ment separator in the absorption tower to remove entrained acid mist,
the gas is routed to the flue gas ducts and reenters the Wellman-Lord
absorber system.
Storage Capacity
The storage capacity of all tanks and silos is shown in Table 14 as
part of the equipment description. Facilities are provided for 30-
day storage of all raw materials and products for the process. These
include the soda ash storage tank, limestone storage silo, sulfate
storage silo, and acid storage tanks. Intermediate in-process storage
of limestone in the feed bin is 8 hours. Residence times in the neutrali-
zation tank and in the dissolving tank are 30 minutes to allow sufficient
time for reactions occurring in those vessels. The absorber product
tank and absorber feed tank each have 24 hours capacity. During operation,
these two vessels isolate downstream equipment from certain fluctuating
conditions. The vessels enable more efficient control and operation of
equipment by providing stable conditions in feedstreams. Furthermore,
the vessels are useful during outages of the power plant because the
equipment downstream of the 802 absorption system can continue to operate,
thus eliminating some shutdown situations. Likewise, during outages in
either the acid unit or the regeneration area, the 802 absorbers can
continue to operate, thus preventing a power plant shutdown to avoid
violation of emission regulations. The chloride scrubber recirculation
tank, centrate tank, and central condensate tank exist primarily to
provide a volume upstream of pumps. Each of these tanks has a 10-minute
capacity and all condensate receivers have 2-minute capacities.
WELLMAN-LORD/RESOX PROCESS
The Resox unit requires a feed gas with a 2:1 to 3:1 molar ratio of
H20 to S02 for optimum reducing conditions. This is provided by modifying
the Wellman-Lord condensers and compressor to produce an off-gas containing
60 mole % H20 (the remaining 1^0 is supplied by the incinerator gas and
anthracite moistures and from anthracite combustion) instead of the 36
mole % H20 off-gas produced for the sulfuric acid unit. The quantity of
802 in tne off-gas is also 7% greater than it is for the sulfuric acid
case because of the greater quantity returned to the absorbers in the
tail gas. Otherwise, the Wellman-Lord process remains the same as for
the sulfuric acid case. The flow diagram, plot plan, and elevation and
77
-------
layout drawings are the same as shown in Figures 5-8. The material
balance is also the same as shown in Table 14 except for the flows shown
in Table 17.
The Resox unit produces gaseous elemental sulfur in a moving bed
reactor by reducing SC>2 with rice-sized anthracite. Anthracite is used
because of its low volatile content and nonagglomerating characteristics.
For the base-case conditions, the Resox reactor design consists of three
separate modules, each containing four reactors. The reactors, however,
are not physically separate entities. Each module of four reactors is
equipped with four 70° discharge hoppers and four coal inlets, but there
are no internal walls to separate the reactors. The modules are con-
structed of refractory-lined carbon steel. The reactors are designed
for a superficial gas velocity of 1 ft/sec and a superficial gas residence
time of 4 seconds at full load conditions. Anthracite residence time is
about 12 hours.
No mechanical seals are provided at either the coal inlet or dis-
charge. Gas at atmospheric pressure enters the vessel just above the
discharge hoppers so that the coal in the hoppers acts as a seal for the
reactor bottom. The anthracite feed rate is controlled by the flow rate
of spent anthracite withdrawn from the reactor discharge hoppers. There
are no mechanical feeders above the reactors; coal flows from the feed
bin to the reactors in spider-leg feed tubes, providing a continuous
column of anthracite above the reactors. This column of coal seals the
vessel at the top. Pressure drop in the Resox unit is overcome by an ID
fan downstream from *:he reactors. There is thus no tendency for the gas
to leak through the anthracite seals at the ends of the reactors. The
Resox unit flow diagram and material balance are shown in Figure, 10
and Table 18. The Resox unit layout drawing is shown in Figure 11. The
Resox equipment list (including Wellman-Lord equipment differing from
that listed in Table 16) is shown in Table 19.
The Wellman-Lord/Resox process is divided into nine operating
areas: materials handling, gas handling, chloride removal, S02 absorp-
tion, stack gas reheat, sulfate crystallization, regeneration, sulfur
production, and sulfur storage. The description of the Wellman-Lord/
sulfuric acid process is applicable to the first seven areas.
Sulfur Production Area
Anthracite System—
Rice-sized anthracite coal is received by rail and conveyed to a
30-day stockpile located about 100 feet from the Resox reactors. From
the stockpile, the coal is transported to a feed bin above the three
reactor modules. Anthracite flows by gravity through the feed bin, feed
tubes, and reactors. The flow rate is controlled to provide roughly 2
moles of carbon for each mole of S02 by varying the withdrawal rate of
spent anthracite from the reactor. Spent anthracite leaves the reactors
at 300°F. The anthracite looses about 50% of its weight in the reactor
and is devolatilized but still retains its original size and shape. The
spent anthracite is composed mainly of fixed carbon and ash, and possesses
78
-------
TABLE 17. WELLMAN-LORD PROCESS
BASE-CASE MATERIAL BALANCE
FOR RESOX CASE
(Refer to Table 7)
Stream No.
Description
1
j
4
5
h
8
9
iP_
Total stream, Ib/hr
Sft-Vmin (60°F)
Temperature (°F)
Pressure (psia)
Gpm
11
Gas to stack
5,144,100
1,135,900
175
12
Steam to
reheater
79,200
470
515
Cooling water
to condensers
4,568,000
80
9,130
Resox plant
tall gas to
plenum
54.300
12,200
300
S02~rlch gas
to Resox
plant
29.400
i 5,200
385
15
__
6
7
8
9_
10
__
4
5
6
7
8
9
10
79
-------
oo
o
CONVEYOR-
ELEVATOR
SO -RICH GAS FROM
WELLMAN-LORD UNIT
SPENT
ANTHRACITE e
TO
BOILER
SULFUR
TAIL6AS TO
WELLMAN-LORD UNIT
*^-|
SULFUR RECEIVING
PIT
• CONDENSATE
Figure 10, Resox unit flow diagram.
-------
TABLE 18. RESOX UNIT
BASE-CASE MATERIAL BALANCE
1
2
)
4
i
h
/
8
9
10
Stroam Nn .
escript
Total stream. Ib/hr
Sft3/min f60°F1
Temperature, °F
Pressure, psia
Gpm
Specif ic gravity
PH
Undissolved solids, %
1
Anthracite to
9,500
2
S02-rich gas
to feed gas
P
29,400
5,200
385
15
T
Air to Resox
5,200
1,100
80
i
Incinerator
gas to Resox
15.300
3,500
1,500
5
Combined gas
to Resox
49.900
9.800
750
Stream No.
1
2
)
<*
5
6
/
8
9
UL
Description
Total stream, Ib/hr
Sft3/min (60°^
Temperature , OF
Pressure, psia
Gpm
Specific gravity
PH
Undissolved solids, %
6
Spent
anthracite
to boiler
4,900
7
Gas to
sulfur
condenser
54,400
11,400
650
8
Condensate
to sulfur
condenser
11,500
165
20
9
Steam to
Wellman-Lord
plant
11,500
250
30
10
Gas
to fan
45,100
10,500
295
13.4
Stream No.
2
J
4
5
6
a
9
10
Description
Total stream, Ib/hr
Sft3/min (60°F)
Temperature , °F
Pressure , psia
Gpm
Specific gravity
.J>H
Undissolved solids, %
11
Gas to
incinerator
45,100
10,500
335
15.6
12
Incinerator
gas
69,600
15,700
1,500
13
Incinerator
gas to air
preheater
54,300
12,200
1,500
14
Fuel oil
to incinerator
800
2
0.87
15
Air to
incinerator fan
23,700
5,200
80
14.7
1
2
)
4
5
6
8
9
10
Description
btt-Vmin (60 F)
Temperature , UF
Pressure, psia
lipm
Specific gravity
pH
Undissolved solids, %
16
Air to air
preheater
23,700
5,200
100
15.9
1 17
Air to
incinerator
23,700
5,200
1,100
1 is
Tail gas to
waste heat
boiler
54,300
12,200
1,155
19
Tail gas to
S02 absorber
54,300
12,200
300
20
Condensate
to waste
heat boiler
14,200
165
30
(continued)
81
-------
TABLE 18 (continued)
Stream No.
Description
1
2
3
4
5
ft
7
8
9
1°
Total stream,- Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
PH
TJndissolved solids , %
21
Steam to
Wellman-Lord
plant
14,200
250
30
22
Steam to
receiving pit
and sulfur
storage tank
2,400
298
65
23
Sulfur to
storage
and shipping
9,360
280
10
1.78
2
3
4
T"
6
7
8
9
10
5
fe
7
8
9
10
I
2
')
4
5
6
7
8
9
10
82
-------
00
OJ
SULFUR
RECEIVING
PIT
SULFUR CONDENSER
TAILGAS FAN
WASTE
HEAT BOILER
LIVE
ANTHRACITE
FEED
CONVEYOR-
ELEVATOR
RESOX REACTOR,
INCINERATOR
AIR FAN
RESOX REACTOR
ANTHRACITE
FEED BIN
RESOX REACTOR
INCINERATOR
AIR PREHEATER
AIR FAN
T
Figure 11. Resox unit layout drawing.
-------
TABLE 19. WELLMAN-LORD/RESOX PROCESS
BASE-CASE EQUIPMENT LIST
Areas 1-4 and Area 6 have the same equipment and costs as those
for the Wellman-Lord/sulfuric acid process shown in Table 11.
Area 5—Reheat
Item
No.
Description
1. Reheaters
Subtotal
Steam, tube type, 3,150 ft2,
one-half tubes made of Inconel
625 and one-half made of Cor-Ten
Total material
cost, 1979 $
All equipment items, descriptions, and costs are identical to
Wellman-Lord/sulfuric acid process except for:
787,200
917.200
Area 7—Regeneration
Item
No.
Description
18. Condenser,
secondary
19. Pump, cooling
water
20. Blower, product
gas
Subtotal
Shell and tube type, 3,450
ft2, 316 stainless steel
tubes, heads, and shell
Centrifugal, 4,360 gpm, 150
ft head, 400 hp, carbon steel,
neoprene lined (2 operating,
2 spares)
Centrifugal, single stage,
5,200 sft3/min, 900 hp,
316 stainless steel
Total material
cost, 1979 $
All equipment items, descriptions, and costs are identical to
Wellman-Lord/sulfuric acid process except for:
98,600
130,600
262,800
3,581,400
Area 8—Sulfur Production (Resox Plant)
Item
No.
Description
Total material
cost, 1979 $
1. Car puller
25 hp with 5 hp return
(continued)
84
50,000
-------
TABLE 19 (continued)
Item
No.
Description
Total material
cost, 1979 $
2. Hopper, anthra- 1
cite unloading
3. Feeder, anthra- 1
cite unloading
4. Conveyor, anthra- 1
cite unloading
5. Conveyor, anthra- 1
cite stocking
(incline)
6. Conveyor, anthra- 1
cite stocking
7. Tripper 1
8. Mobile equipment 1
9. Hopper, anthra-
cite reclaim
10. Feeder, live
anthracite
storage
11. Pump, tunnel
sump
12. Conveyor, live 1
anthracite feed
13. Conveyor-
elevator, live
anthracite feed
14. Bin, anthracite
feed
12 ft x 20 ft x 2 ft bottom,
20 ft deep, 4,800 ft3, carbon
steel
Vibrating pan, 42 in. wide x
60 in. long, 3 hp, 215 tons/hr
Belt, 30 in. wide x 20 ft long,
1 hp, 215 tons/hr, 300 ft/min
Belt, 30 in. wide x 220 ft long,
25 hp, 16° slope, 215 tons/hr,
300 ft/min
Belt, 30 in. wide x 150 ft long,
7-1/2 hp, 215 tons/hr, 300 ft/min
5 hp, 30 ft/min
Scraper tractor, 1-1/2 yd
capacity
2 ft 4 in. x 2 ft 4 in., 4 ft
deep, 60° slope, carbon steel
2 Vibrating pan, 1 hp, 15 tons/hr
Vertical, 60 gpm, 70 ft head,
5 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
Belt, 14 in. wide x 100 ft
long, 1/2 hp, 15 tons/hr,
100 ft/min
Pivoted buckets, 5 in. x 5-1/2
in. x 3 in., 7-1/2 hp, 100 ft
vertical, 45 ft horizontal,
15 tons/hr, 75 ft/min
18 ft dia x 24 ft straight side,
6,100 ft3, w/cover, flat bottom,
carbon steel (24-hr capacity)
(continued)
9,300
4,800
4,600
49,200
34,200
14,800
48,800
11,200
7,000
3,400
17,300
31,000
10,100
85
-------
TABLE 19 (continued)
Item
No.
Description
Total material
cost, 1979 $
15. Tank, fuel oil
storage
16. Pump, fuel oil
17. Fan, air
18. Reactor, Resox
19. Feeder, reactor
discharge
20. Hopper, spent
anthracite
collection
21. Feeder, spent
anthracite
collection
hopper discharge
22. Conveyor, spent
anthracite
23. Conveyor, spent
anthracite
24. Conveyor, spent
anthracite
25. Condenser,
sulfur
12
24 ft dia x 25 ft high, 84,600
gal, w/cover, carbon steel
(30-day capacity)
Centrifugal, 2 gpm, 200 ft head,
1/2 hp, carbon steel
(1 operating, 1 spare)
1,200 aft3/min, 12 in. static
head, 5 hp
12 ft inside length x 12 ft
inside width x 9 ft straight
side height, four 70° hoppers,
carbon steel, refractory lined
Weigh, vibratory, 410 Ib/hr,
316 stainless steel
1 18 ft dia x 9 ft deep, 45°
slope, w/cover, carbon steel
1 Vibrating pan, 1 hp, 4,900 Ib/hr
Vibrating, 6 in. wide x 100 ft
long, 3 hp, 4,900 Ib/hr, carbon
steel, 20 ft/min
Belt, 14 in. wide x 550 ft
long, 1 hp, 4,900 Ib/hr,
20 ft/min
Belt, 14 in. wide x 500 ft
long, 1 hp, 4,900 Ib/hr,
20 ft/min
Shell and tube type, 4,940
ft^ 316 stainless steel tubes,
carbon steel shell, insulated,
with mesh pad, 60 in. dia x 4 in.
thick, 316 stainless steel
entrainment separator
(continued)
86
13,900
2,300
3,800
381,600
15,400
4,400
3,500
22,000
95,200
86,500
153,200
-------
TABLE 19 (continued)
Item
No.
Description
Preheater, air
28.
Fan, air
Waste heat
boiler
Subtotal
Total material
cost, 1979 $
26.
27.
Fan, tail gas
Incinerator
1
1
16,600 aft3/min, 60 in.
static head, 250 hp
8 ft dia x 16 ft long, carbon
42,300
190,000
steel, refractory lined
Shell and tube type, 3,620 ft2,
316 stainless steel tubes,
refractory lined, carbon steel
shell
5,400 aft3/min, 32 in. static
head, 40 hp
Shell and tube type, 3,630 ft2,
316 stainless steel tubes, carbon
steel shell, insulated
126,200
1,436.000
Area 9—Sulfur Storage and Shipping
Item
No.
Description
Total material
cost. 1979 $
1. Pit, sulfur
receiving
Pump, sulfur
transfer
Tank, sulfur
storage
Heater
Pump, sulfur
shipping
Subtotal
10 ft wide x 10 ft long x 10 ft
high, 1,000 ft3, w/cover, carbon
steel, insulated, with 100 ft2,
1 in. Schedule 40, carbon steel
pipe steam heater
Centrifugal, submerged 12 gpm,
100 ft head, 2 hp, carbon steel
(1 operating, 1 spare)
43 ft dia x 42 ft high, 454,400
gal, w/cover, carbon steel,
insulated (30-day capacity)
Steam, 300 ft2, 1,200 ft of
1 in. Schedule 40, carbon steel
Centrifugal, 60 gpm, 100 ft head,
5 hp, steam traced and insulated,
carbon steel (1 operating,
1 spare)
6,200
2,100
86,800
.5,000
100,100
87
-------
a substantial heating value. Collection and conveying equipment is
provided for use of the spent anthracite in the power plant boiler.
Gas and Sulfur System—
The 40 mole % S02 gas from the Wellman-Lord unit is mixed with a
small amount of air and the resulting mixture is heated to 750°F by
direct injection of 1500°F incinerator tail gas. The air is added to
provide oxygen for oxidation of both the anthracite volatiles and a
small amount of anthracite required to maintain the reactor temperature.
The combined gases are distributed to each reactor and flow upward
through the anthracite bed. The temperature in the main reaction zone
is about 1300°F. In addition to sulfur vapor, some H2S, COS, and CS2
are formed in the reactor. A typical reactor off-gas contains, on a
molar basis, about 1% H2S, 1% S02, 8% to 10% S2, 2% to 3% CO, 20% to 25%
C02, 40% to 50% H20, 20% to 25% N2, and trace quantities of COS and CS2.
The off-gas, flowing out the top of the reactor at 650°F to 750°F,
passes through a shell and tube heat exchanger to condense the sulfur
product and produce 15 psig steam. Recovered sulfur, at 280°F to
310°F, is collected and pumped to storage. Uncondensed gases from the
sulfur condenser are routed to an incinerator to oxidize the remaining
sulfur compounds back to S02. No. 2 fuel oil is used as the fuel.
Operation of the incinerator is controlled to provide a molar oxygen
concentration of 2% and a temperature of 1500°F in the incinerator tail
gas. As discussed previously, part of the incinerator tail gas is used
to preheat the reactor feed gas. The remaining tail gas is used to
preheat incinerator air from 80°F to 1100°F in a shell and tube heat
exchanger. During startup, the incinerator tail gas is used to preheat
the anthracite in the reactor. The tail gas leaving the air preheater
at 1155°F is cooled to 300°F in a waste heat boiler and returned to the
Wellman-Lord absorbers. The heat recovered in the waste heat boiler is
used to produce 15 psig steam. Steam produced in the sulfur condenser
and the waste heat boiler is used in the Wellman-Lord evaporators.
Storage Capacity
Allowances for the Wellman-Lord process raw material and in-process
storage are identical in the Resox and sulfuric acid cases. Storage
capacities in the Wellman-Lord process are the same as those of the
Wellman-Lord/sulfuric acid process.
For the Resox unit, anthracite coal is kept in a 30-day stockpile.
In-process storage capacity for anthracite is 24 hours in the anthracite
feed bin. The sulfur receiving pit is capable of holding 12 hours of
sulfur production and 30 days of production may be stored in the sulfur
storage tank.
88
-------
WELLMAN-LORD/ALLIED CHEMICAL COAL/SC^ REDUCTION PROCESS
The Wellman-Lord process used in the Wellman-Lord/Allied process is
similar to the one used in the Wellman-Lord/sulfuric acid process shown
in Figures 5-8. The only differences are in the quantities of sulfur
and water in the off-gas and the off-gas pressure. The quantity of
sulfur is 3% greater than that for the sulfuric acid case because the
96% conversion results in more sulfur being returned to the absorber.
The water is reduced to 15 mole %, the practical minimum attainable,
because it acts as an inert ingredient in the Allied process. The
pressure of the off-gas is also increased to 24 psia because of Allied
process requirements. The Wellman-Lord flow rates that differ from
those of the flow rates of the sulfuric acid case are shown in Table 20.
The Allied unit produces sulfur in a two-step process. Primary
reduction is by coal in a fluidized-bed reactor and secondary conversion
occurs in a modified Glaus unit. The fluidized-bed reduction reactor is
claimed to accept any type of coal or lignite without pretreatment.
Because of this ability to accommodate agglomerating and high-volatile-
content coals, the reactor can use the power plant coal. All cases
evaluated in this study are based on the use of the base-case power
plant coal described in the premises.
The Allied process flow diagram and material balance are shown in
Figure 12 and Table 21. The Allied process equipment layout is shown
in Figure 13. The equipment list for the Wellman-Lord/Allied process
(including Wellman-Lord equipment differing from that in Table 16)
equipment list is shown in Table 22.
The Wellman-Lord/Allied process is divided into the following
operating areas: materials handling, gas handling, chloride removal,
SC>2 absorption, stack gas reheat, sulfate crystallization, regeneration,
sulfur production and sulfur storage. All areas except sulfur production
and sulfur storage are the same as those discussed in the Wellman-
Lord/sulfuric acid process.
The sulfur production area contains all equipment needed by the
Allied process, including coal handling equipment. All equipment needed
for the storage of molten sulfur is included in the sulfur storage area.
Sulfur Production Area
Coal System—
Coal is removed from the power plant stockpile into trenched hoppers
and transported by belt conveyors to the raw coal feed bin. The coal is
then processed in coal drying and grinding facilities to produce a
pulverized and partially dried product. The coal is first ground in an
impact mill that is swept with inert gas. Considerable heat which is
evolved during the grinding process is used to dry the coal. For the
base-case evaluation, the moisture content of the power plant coal is
reduced from about 10% to about 5%. The inert gas stream absorbs the
released moisture and conveys the ground coal out of the mill. The coal
89
-------
TABLE 20. WELLMAN-LORD, PROCESS
BASE CASE MATERIAL BALANCE
FOR ALLIED CHE?1ICAL COAL/S02 REDUCTION CASE
(Refer to Table 7)
Stream No.
Description
J-
2
i
4
b
6
/
8
9
10
Total stream (Ib/hr)
SftJ/min (60°F)
Temperature (°F)
Pressure (psia)
Gpm
11
Gas to stack
5.120.900
1,129.800
134
12
Steam to
reheater
78,800
470
515
43
Cooling water
to condensers
4,853.900
an
9.700
63
Allied plant
tail gas to
plenum
29.300
5,700
300
65
S02-rich gas
to Allied
plant
20.700
2.300
465
24
5
6
~r
8
JL
10
I
2
J
4
JS_
ft
7
8
9
10
4
5
6
7
8
9
10
90
-------
Figure 12. Allied Chemical coal/SC>2 reduction unit flow diagram.
-------
TABLE 21. ALLIED CHEMICAL COAL/S02 REDUCTION UNIT
BASE. CASE MATERIAL BALANCE
Stream No.
i
2
i
4
b
b
1
«
9
10
Description
Total stream, Ib/hr
SftJ/min (60"F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids, %
1
Raw coal
to bin
8,300
2
Processed
coal to
bin
7,500
3
Sand to
reduction
reactor
50
4
Combined solids
to reduction
reactor
5
Gas from
Wellman-
Lord unit
20,700
2,300
465
24
2
1
4
b
6
/
8
9
Description
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, UF
Pressure, psia
Gpm
Specific gravity
PH
Undissolved solids, 7,
6
Air to
reduction
reactor
1,900
400 -
185
24
7
Gas to
preheater
22,600
2,700
430
8
Gas to
reduction
reactor
22,600
2,700
9
Gas to
cyclone
30,100
4,200
1,800
10
Gas to
scrubber
28.100
4,200
1,800
Stream No.
1
2
J
4
5
6
7
8
y
10
Description
Total stream. Ib/hr
Sft-Vmin (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids, %
11
Gas to first
claus feed
preheater
19 , 500
3,400
12
Molten sulfur
to scrubber
1,603,300
1.800
1.78
13
Molten sulfur
to sulfur
cooler
1,603,300
1.800
1.78
14
Steam to
condenser
17,600
6,200
15
Condensate
to tank
17,600
35
Stream No.
1
2
i
4
b
6
7
8
y
IU
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature. °F
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids, %
16
Water to
sulfur cooler
17,600
35
17 1
Gas to first
stage claus
converter
19,500
3,400
425
1 3"5
Gas to
first sulfur
condenser
19,500
3,400
580
19
Gas to second
claus feed
preheater
18,100
3,300
315
20
Gas to second
stage claus
converter
is.ioo '"
3,300
425
(continued)
92
-------
TABLE 21 (continued)
Stream No.
Description
1
2
j
4
5
ft
7
H
9
10
Total stream, Ib/hr
SftJ/min (60UF)
Temperature, UF
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids, %
21
Gas to
second sulfur
condenser
18,100
3,360
460
22
Gas to
incinerator
17,700
3.300
295
23
Incinerator
tail gas
29.300
5.700
1,500
24
Incinerator
gas to first
claus feed
preheater
3.100
600
1.500
25
Incinerator
gas to second
claus feed
preheater
3.600
700
1.500
Stream No.
Description
1
2
i
4
5
h
7
8
9
Iff
Total stream, Ib/hr
SftJ/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
PH
Undissolved solids, %
2b
Incinerator gas
to reduction
reactor feed
gas preheater
22,700
4,400
1,500
27
Recombined
tail gas
to waste
heat boiler
29 , 300
5,700
1,015
28
Tail gas
to S02
absorber
29,300
5,700
300
29
Water to waste
sump and
condensate tank
31,200
110
60
30
Cyclone
waste to
disposal
sump
1,900
S tream No .
Description
1
2
J
4
5
6
7
8
9
10
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids, %
31
*Filter cake
to disposal
6,320
32
Waste to
ash pond
34,600
60
1.1
10
33
Molten sulfur
to sulfur
filter
8,700
310
10
1.78
10
34
Fuel oil
to incinerator
300
1
0.87
35
Air to
incinerator
11,200
2,500
80
Stream No.
1
2
i
4
5
h
1
8
9
10
Description
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids, X
36
Steam to
filter, storage
tank, and
receiving pit
3,000
298
65
37
Condensate to
second sulfur
condenser
850
165
2
1
38
Steam from
second sulfur
condenser
850
260
35
39
Condensate to
first sulfur
condenser
1,560
165
3
1
40
Steam from
first sulfur
condenser
1,560
275
45
*Intermittent stream: 24-hour average rate is 1,580 Ib/hr.
(continued)
93
-------
TABLE 21 (continued)
Stream No.
1
2
S
4
5
6
/
8
9
1U
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, °F
Pressure, psia
Gpm
Specific gravity
PH
Undissolved solids, %
41
Air to
inert gas
generator
1,600
50
80
42
Fuel oil to
inert gas
generator
100
0.2
0.87
43
Condensate
to waste
heat boiler
5.640
165
10
44
Steam from
waste heat
boiler
5.640
298
65
45
Sulfur from
second sulfur
condenser
350
280
0.4
1.78
2
J
5
6
/
8
y
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, UF
Pressure, psia
Gpm
Specific gravity
pH
Undissolved solids 7,
Sulfur from
first sulfur
condenser
1,400
280
1.5
1.78
47
Sulfur from
sulfur filter
7 19fl
290
8
1.78
1 ^ 1
Sulfur to
storage
8,870
10
1.78
94
-------
AIR COOLED
CONDENSER
INCINERATOR
INCINERATOR AIR FAN
PROCESSED
COAL
PNEUMATIC
CONVEYOR
(ACROSS ROAD)
SECOND SULFUR CONDENSER
o
WASTE HEAT
BOILER
FEEDGAS
HEATER
FIRST SULFUR CONDENSER
PREHEATORS
AIR COMPRESSOR
Figure 13. Allied Chemical coal/SC>2 reduction unit layout drawing.
95
-------
TABLE 22. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
BASE-CASE EQUIPMENT LIST
Areas 1-4 and Area 6 have the same equipment and costs as those
for the Wellman-Lord/sulfuric acid process shown in Table 11.
Area 5—Reheat
Item
No.
Description
1. Reheaters
Subtotal
Steam, tube type, 3,140 ft ,
one-half tubes made of Inconel
625 and one-half made of Cor-Ten
Total material
cost, 1979 $
All equipment items, descriptions, and costs are identical to
Wellman-Lord/sulfuric acid process except for:
917,200
917,200
Area 7—Regeneration
Item
No.
Description
Total material
cost, 1979 $
All equipment items, descriptions, and costs are identical to
Wellman-Lord/sulfuric acid process except for:
18. Condenser,
secondary
19. Pump, cooling
water
20. Blower, product
gas
Subtotal
Shell and tube type, 4,310 ft2,
316 stainless steel tubes, heads,
and shell
Centrifugal, 4,850 gpm, 150 ft
head, 400 hp, carbon steel,
neoprene lined (2 operating,
2 spares)
Centrifugal, single stage,
2,280 sft3/min, 600 hp, 316
stainless steel
115,200
130,600
161,900
3.497,100
(continued)
96
-------
TABLE 22 (continued)
Area 8—Sulfur Production (Allied Chemical Coal/SO? Reduction Plant)
Item
No.
Description
Total material
cost. 1979 $
1. Hopper, raw
coal reclaim
2. Feeder, raw
coal storage
3. Pump, tunnel
sump
4. Conveyor, raw
coal feed
Conveyor, raw
coal feed
(incline)
Bin, raw coal
feed
Feeder, raw
coal bin
discharge
Coal processing
facilities
Tank, fuel oil
storage
10. Pump, fuel oil
2 ft 4 in. x 2 ft 4 in., 4 ft
deep, 60° slope, carbon steel
Vibrating pan, 1 hp, 13 tons/hr
Vertical, 60 gpm, 70 ft head,
5 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
Belt, 14 in. wide x 100 ft
long, 1/2 hp, 13 tons/hr,
100 ft/min
Belt, 14 in. wide x 500 ft
long, 3 hp, 8° slope, 13 tons/hr,
100 ft/min
15 ft dia x 23 ft straight side,
4,060 ft3, w/cover, 60° cone
hopper, carbon steel (24-hour
capacity)
Screw, 10 in. dia x 30 ft long,
2 hp, 5 tons/hr
Fluid bed roller mill system,
5 tons/hr, equipment includes:
inert gas generator, feeders,
mill cyclone collector, bag
filter, refrigeration dryer,
dessicant dryer, pneumatic
conveyor, all motors and duct-
work
20 ft dia x 19 ft high, 44,700
gal, w/cover, carbon steel
(30-day capacity)
Centrifugal, 1 gpm, 200 ft head,
1/2 hp, carbon steel
(1 operating, 1 spare)
(continued)
97
11,200
7,000
3,400
17,300
98,800
9,500
20,800
328,500
9,300
2,300
-------
TABLE 22 (continued)
Item
No.
Description
Total material
cost, 1979 $
11. Bin, processed
coal storage
12. Feeder, proc-
essed coal
bin discharge
13. Conveyor, sand
14. Bin, sand
storage
15. Feeder, sand
bin discharge
16. Elevator,
processed coal
17. Bin, lock
18. Conveyor,
reactor feed
15 ft dia x 21 ft straight side, 8,800
3,710 ft3, w/cover, 60° cone
hopper, carbon steel (24-hour
capacity)
Weigh, screw, 9 in. dia x 25 ft 17,500
long, 1 hp, 4 tons/hr
Pneumatic, positive pressure 25,000
conveying system, 2 tons/hr,
10 hp
7 ft dia x 11 ft straight side, 1,200
420 ft3, w/cover, 60° cone hopper,
carbon steel (30-day capacity)
Weigh, screw, 2 in. dia x 15 ft 7,100
long, 1/4 hp, 50 Ib/hr
Continuous, bucket, 8 in. x 5-1/2 10,000
in. x 7-3/4 in., 3 hp, 45 ft lift,
4 tons/hr, 150 ft/min
5 ft dia x 8 ft straight side, 45,000
160 ft3, w/cover, 60° cone
hopper, 316L stainless steel
(1-hour capacity each)
Screw, 9 in. dia x 10 ft long, 50,000
1 hp, 4 tons/hr, 316 stainless
steel
19. Reactor,
reduction
20. Heater, feed
gas
21. Blower, air
7 ft dia bed, 10 ft dia above bed, 200,000
8 ft bed depth, 41 ft overall
height, 1/2 in. carbon steel,
refractory lined
Shell and tube type, 2,530 ft2, 87,800
316L stainless steel tubes,
refractory lined carbon steel
shell
Centrifugal, single stage, 420 45,000
sft3/min, 20 hp
(continued)
98
-------
TABLE 22 (continued)
Item
No.
Description
Total material
cost. 1979 $
22. Cyclone, reduc-
tion reactor
23. Scrubber, gas
24. Tank, separator
Mist eliminator
Heater
25. Pump, sulfur
transfer
26. Cooler, sulfur
Mist eliminator 1
Heater
27. Pump, sulfur
28. Condenser, steam 1
Fan, air
29. Tank, condensate 1
15,400 aft3/min, carbon steel, 35,000
refractory lined
Ejector-venturi, 30 in. dia x 15,000
20 ft overall height, 316
stainless steel
11 ft dia x 11 ft high, 7,820 gal, 60,300
w/cover, 316L stainless steel,
insulated (3-minute capacity)
Mesh pad, 32 in. dia x 4 in.
thick, 316 stainless steel
Steam, 100 ft2, 400 ft of 1 in.
Schedule 40, 316 stainless steel
Centrifugal, submerged, 1,800 gpm, 36,600
60 ft head, 125 hp, 316 stainless
steel (1 operating, 1 spare)
8 ft dia x 8 ft high, 3,010 gal, 55,300
w/cover, 3/8 in. 316L stainless
steel, insulated (1-minute
capacity)
Mesh pad, 42 in. dia x 4 in. thick,
316 stainless steel
Steam, 100 ft2, 400 ft of 1 in.
Schedule 40, 316 stainless steel
Centrifugal, submerged, 1,800 gpm, 44,800
100 ft head, 200 hp, 316 stainless
steel (1 operating, 1 spare)
Air cooled, 25,000 ft2 outside 40,000
surface area, 316L stainless steel
tubes, w/aluminum fins
95,000 aft3/min, 1 in. static head,
25 hp
8 ft dia x 8 ft high, 3,010 gal, 27,800
w/cover, 318 in. 316L stain-
less steel, insulated (1-hour
capacity)
(continued)
99
-------
TABLE 22 (continued)
Item
No.
Description
Total material
cost, 1979 $
30. Pump, conden- 2
sate tank
Centrifugal, submerged 35 gpm,
60 ft head, 2 hp, 316 stainless
steel (1 operating, 1 spare)
5,600
31. Pump, sulfur 2
filter feed
32. Filter, sulfur 1
33. Preheater, first 1
Glaus feed gas
34. Preheater,
second Glaus
feed gas
35. Converter, Glaus
36. Condenser, first
sulfur
37. Condenser,
second sulfur
Mist eliminator
38. Incinerator
Fan, air
39. Boiler, waste
heat
Centrifugal, submerged, 10 gpm, 5,600
150 ft head, 2 hp, 316 stainless
steel (1 operating, 1 spare)
Pressure leaf, 60 in. dia x 11 ft 155,500
long, 800 ft2, 316 stainless steel,
insulated, steam jacketed
Shell and tube type, 180 ft2, 34,700
316L stainless steel tubes,
refractory lined carbon steel
shell
Shell and tube type, 210 ft2, 37,900
316L stainless steel tubes,
refractory lined carbon steel
shell
9-1/2 ft inside dia x 30 ft high, 39,500
5/8 in. carbon steel shell, 1/2 in.
304 stainless steel Catalytic
grids, insulated
Shell and tube type, 710 ft2, 20,400
insulated
Shell and tube type, 520 ft2, 16,500
insulated
Mesh pad, 32 in. dia x 4 in.
thick, 316 stainless steel
5 ft dia x 16 ft long, carbon
steel, refractory lined
2,600 aft3/min, 17 in. static
head, 10 hp
Shell and tube type, 1,100 ft2,
316L stainless steel tubes and
heads, carbon steel shell,
insulated
(continued)
100
89,800
66,300
-------
TABLE 22 (continued)
Item
No.
Description
Total material
cost, 1979 $
40. Sump, waste
41. Agitator,
waste sump
42. Pump, waste
10 ft x 10 ft x 10 ft deep,
concrete, tile lined, grating
covered
48 in. dia, 7-1/2 hp, neoprene
coated
Centrifugal, submerged, 100
gpm, 150 ft head, 10 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
Subtotal
16,200
12,000
5,800
1.826,100
Area 9—Sulfur Storage and Shipping
Item
No.
Description
Total material
cost, 1979 $
1. Pit, sulfur
receiving
Heater
2. Pump, sulfur
3. Tank, sulfur
storage
Heater
4. Pump, sulfur
shipping
Subtotal
10 ft wide x 10 ft long x
10 ft high, 1,000 ft3, w/cover,
carbon steel, insulated
Steam, 100 ft2, 400 ft of
1 in. Schedule 40, carbon steel
Centrifugal, submerged, 12 gpm,
100 ft head, 2 hp, carbon steel
(1 operating, 1 spare)
42 ft dia x 42 ft high,
435,300 gal, w/cover, carbon
steel, insulated (30-day
capacity)
Steam, 300 ft2, 1,200 ft of
1 in. Schedule 40, carbon steel
Centrifugal, 60 gpm, 100 ft
head, 5 hp, steam traced and
insulated, carbon steel
(1 operating, 1 spare)
6,200
2,100
85,500
5,000
98,800
101
-------
is removed from the gas stream by a cyclone separator followed by a bag
filter and is delivered to the processed coal storage bin. Some moisture-
laden inert gas is vented to the atmosphere and the remainder is dried.
A portion of the dried gas is used to provide a dry, inert atmosphere in
the processed coal storage bin and handling equipment. The inert atmosphere
prevents hydration of the dried coal and reduces the potential explosion
hazard. The rest of the dried gas is recycled through the grinding
mill. The inert gas is produced by burning No. 2 fuel oil under con-
trolled combustion conditions.
Reactor Section—
Silica sand is used as the inert material in the fluidized-bed
reduction reactors. A small amount of sand is entrained in the gas
stream leaving the reactors. It is therefore necessary to feed sand to
the reactors to replenish losses. Sand is delivered by truck and pneu-
matically conveyed to a 30-day storage bin. From the storage bin, sand
is supplied to the process as it is needed.
Allied specifies a lock hopper system to feed material into the 24
psia atmosphere within the reduction reactor. This system consists of
two vertically aligned bins situated above an enclosed screw feeder.
Dried coal and makeup sand are elevated to the top bin. Gas-tight gates
below this bin enable it to be filled while feeding from the second bin
into the reduction reactor at a controlled rate using a screw feeder.
Before transferring from the upper bin to the lower bin, a gas-tight
valve above the top bin is closed and the vessel is pressurized to 24
psia. After transferring to the bottom bin, the gates between the bins
are closed and the pressure in the empty upper bin is relieved before
opening the top valve and recharging the depleted bin.
A small quantity of air is mixed with the 85 mole % SC>2 stream from
the Wellman-Lord unit to provide oxygen for oxidation of both the vola-
tiles and enough coal to maintain the reactor temperature. The combined
feed gases are preheated in a shell and tube heat exchanger by the
incinerator tail gas. From the preheater, the air-S02 mixture is routed
to the reduction reactor where it fluidizes the bed of coal and sand.
In the reactor about 75% to 80% of the inlet S02 is reduced to
elemental sulfur by reaction with coal at a temperature between 1500°F
and 1800°F. The freeboard section of the reactor above the fluidized
bed is enlarged to reduce the gas velocity and thus minimize the amount
of partially reacted coal particles and sand escaping in the off-gas
from the reactor. The increased contact time between the coal particles
and the S02 gas also increases the efficiency of coal utilization. The
coal addition rate is not a function of carbon content alone, but is
dependent upon both the carbon and hydrogen content of the coal. For
the particular coal used in this evaluation, carbon and hydrogen addition
rates are roughly 1.3 moles of carbon and 1.1 moles of hydrogen per
mole of S02-
The off-gas leaving the top of the reduction reactor contains
entrained unreacted coal particles, ash, and sand. A typical molar
102
-------
composition for the off-gas is roughly 15% S2, 7% H2S, 1% H2, 18% H20,
7% N2, 3% CO, 3.5% S02, 1% COS, 55.5% C02, and trace amounts of CS2 and
HC1. The HC1 is present in an amount determined" by the chloride content
of the coal. The reduction reactor off-gas is passed through a cyclone
separator to remove the larger particulate matter, which is dumped into
an effluent sump. The partially cleaned gas is passed through an
ejector-venturi where the gas is contacted cocurrently with a recircu-
lating stream of molten sulfur. The ejector-venturi removes the remaining
particulate matter, cools the gas, and condenses the sulfur in the gas.
The cleaned, cooled gas and liquid sulfur are passed to a separator tank
from which the gas is routed to the Glaus converter feed gas preheater.
A mesh pad entrainment separator in the separator tank prevents carryover
of sulfur mist.
Sulfur is withdrawn from the separator tank and the particulate
matter is removed in a steam-heated, pressure-leaf filter. After
filtration, the molten sulfur is pumped to a sulfur storage tank. The
filter cake is dumped into the effluent sump. The cyclone separator
waste and the filter waste from the effluent sump are slurried and
discarded in the power plant fly ash pond.
The remainder of the sulfur collected in the separator tank is
pumped to a sulfur cooling tank where heat absorbed from the gas stream
is removed by vaporization of water injected directly into the tank.
The cooled sulfur is recirculated to the ejector-venturi. Steam from
the sulfur cooler is condensed in an air cooled condenser, collected in
the condensate tank, and returned at a controlled rate to the sulfur
cooler. The condensate tank is vented to the incinerator for removal of
noncondensables. A small amount of water is added to the condensate
tank to replenish water lost in the vent stream.
The gas from the ejector-venturi is routed to a two-stage Glaus
conversion unit where the H2S and S02 react to produce sulfur. Overall
Allied plant conversion of S02 to sulfur is increased to about 96% in
the Glaus unit. However, actual recovery of sulfur product is only 90%
of the sulfur in the S02 fed to the Allied plant because the waste
streams from the sulfur filter and cyclone separator contain some sulfur.
The Glaus unit consists of two shell and tube feed gas preheaters,
two vertical shell and tube sulfur condensers, and a two-bed catalytic
reactor. Process gas, preheated to 425°F, enters the top of the reactor
vessel, travels downward through a bed of alumina catalyst, and leaves
the first stage at 580°F. In the first-stage sulfur condenser, gas from
the first catalyst bed is cooled to 315°F in the tubes and 30 psig steam
is produced in the shell. The gas is then preheated to 425°F before
entering the second-stage catalyst bed. The second-step condenser cools
the gas stream from 460°F to 295°F and produces 20 psig steam. Sulfur
condensed in the two condensers is collected and pumped to a sulfur
storage tank. A mesh pad mist eliminator removes sulfur droplets from
the gas stream as it flows from the second-stage condenser to the
incinerator.
103
-------
The incinerator uses No. 2 fuel oil. It is controlled to produce a
tail gas with a molar oxygen concentration of 2% to insure complete
oxidation of sulfur compounds to SC^. The 1500°F incinerator tail gas
is used to preheat feed gas to both stages of the Glaus unit and to
preheat feed gas to the reduction reactors. During startup, the tail
gas is used to preheat the coal-reduction reactors. After passing
through the preheaters, the tail gas is passed to a waste heat boiler
where the gas is cooled from 1015°F to 300°F and produces 50 psig steam.
The cooled tail gas is recycled to the SC>2 absorber. Steam produced by
the waste heat boiler and sulfur condensers is used to heat the sulfur
lines, the sulfur storage vessels, and the sulfur filter, with the
remainder to be used in the Wellman-Lord evaporators.
Storage Capacity
Allowances for the Wellman-Lord process raw material and in-process
storage are discussed in the Wellman-Lord/sulfuric acid section. For
the Allied process, no allowance is made for a raw coal stockpile. It
is assumed that coal can be removed from the power plant stockpile. In-
process coal storage capacity is 24 hours in the raw coal bin and 24
hours in the processed coal bin. Sand is stored in a 30-day-capacity
bin and there is no intermediate storage. The sulfur receiving pit is
capable of holding 12 hours of sulfur production. The sulfur storage
tanks have a 30-day capacity. The separation tank, sulfur cooler, and
condensate tank have residence times of 4 minutes, 1 minute, and 90
minutes respectively.
104
-------
RESULTS
Detailed capital investment, annual revenue requirement, and
lifetime revenue requirement analyses are shown in the appendix for each
of the processes. Capital investment is based on mid-1979 costs.
Annual revenue requirements are based on a 7000 hr/yr operating schedule
and mid-1980 costs. The lifetime revenue requirements are based on a
declining operating schedule and costs discounted at 11.6% to mid-1980.
All revenue requirements include credits for the applicable byproduct
sulfur, sulfuric acid, sodium sulfate, and spent anthracite. Energy
requirements for the base-case conditions of each process are also
assessed in the discussion.
CAPITAL INVESTMENT
Capital investment summaries for each of the processes are shown in
Tables 23-26. In overall comparisons, the ACP has the lowest capital
investment for cases involving new (30 years of remaining life) power
plants, followed, in order of increasing capital investment, by the
sulfuric acid, Resox, and Allied variations of the Wellman-Lord process.
The range of capital investments is not large, however. For the base
case the maximum difference is 18%. For the case variations the maximum
difference is 28%.
For the case variations involving existing power plants (those with
20 or 25 years of remaining life) a somewhat different situation prevails.
The relative capital investment relationships of the Wellman-Lord processes
remain the same. The capital investments of the ACP, however, are
higher than the capital investments of the corresponding Wellman-Lord/
sulfuric acid process. The range of capital Investments for the four
processes is less for the exisitng plant case variations than for the
new-plant cases; the minimum difference is 5% and the maximum is 11%.
The relatively higher ACP capital investment for existing plants
occurs because no ESP credit is given. The ESP's required for fly ash
removal are assumed to be already installed in existing plants, whereas
a credit is given new (that is, not yet constructed) power plants because
separate ESP's for fly ash collection are not required. In existing
plants the existing ESP's replace the cyclone collectors. The more
efficient fly ash removal also decreases the regeneration area filtration
requirements somewhat, allowing smaller sizes of filtration equipment to
be used.
105
-------
TABLE 23. AQUEOUS CARBONATE PROCESS
CAPITAL INVESTMENT
Years Capital
remaining investment,
Case life3 k$ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur 20 34,841 174
200 MW, 3.5% sulfur 30 30,670 153
500 MW, 3.5% sulfur 25 68,249 136
500 MW, 2.0% sulfur 30 43,583 87
• 500 MW, 3.5% sulfur 30 59,702 119
500 MW, 5.0% sulfur 30 71,410 143
1,000 MW, 3.5% sulfur 25 109,563 110
1,000 MW, 3.5% sulfur 30 93,161 93
90% S02 removal
500 MW, 3.5% sulfur 30 62,886 126
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur 25 49,199 98
a. A 127,500-hour, 30-year lifetime is used. FGD facilities
for cases with 30 years of remaining life are constructed
simultaneously with the power plant; others are retrofit
installations.
106
-------
TABLE 24. WELLMAN-LORD/SULFURIC ACID PROCESS
CAPITAL INVESTMENT
Years Capital
remaining investment,
Case lifea k$ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur 20 34,207 171
200 MW, 3.5% sulfur 30 33,578 168
500 MW, 3.5% sulfur 25 66,227 132
500 MW, 2.0% sulfur 30 51,633 103
• 500 MW, 3.5% sulfur 30 65,360 131
500 MW, 5.0% sulfur 30 76,779 154
1,000 MW, 3.5% sulfur 25 103,691 104
1,000 MW, 3.5% sulfur 30 101,411 101
90% S02 removal
500 MW, 3.5% sulfur 30 68,475 137
Wet-scrubbing fly ash
removal 30 58,178 116
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur 25 40,379 81
a. A 127,500-hour, 30-year lifetime is used. FGD facilities
for cases with 30 years of remaining life are constructed
simultaneously with the power plant; others are retrofit
installations.
107
-------
TABLE 25. WELLMAN-LORD/RESOX PROCESS
CAPITAL INVESTMENT
Case
Years
remaining
lifea
Capital
investment,
k$ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW,
500 MW,
500 MW,
3.5% sulfur
3.5% sulfur
2.0% sulfur
• 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
1,000 MW, 3.5% sulfur
1,000 MW, 3.5% sulfur
90% S02 removal
500 MW, 3.5% sulfur
Lower (90% of base case)
sulfur conversion factor
Wet-scrubbing fly ash
removal
20
30
25
30
30
30
25
30
30
30
30
36,119
35,447
69,690
53,627
68,771
81,371
109,166
106,776
72,198
71,240
61,641
181
177
139
107
138
163
109
107
144
142
123
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
42,324
85
a. A 127,500-hour, 30-year lifetime is used. FGD facilities
for cases with 30 years of remaining life are constructed
simultaneously with the power plant; others are retrofit
installations.
108
-------
TABLE 26. WELLMAN-LORD/ALLIED CHEMICAL COAL/
S02 REDUCTION PROCESS
CAPITAL INVESTMENT
Case
Years
remaining
life3
Capital
investment,
k$ $/kW
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur 20
200 MW, 3.5% sulfur 30
500 MW, 3.5% sulfur 25
500 MW, 2.0% sulfur 30
• 500 MW, 3.5% sulfur 30
500 MW, 5.0% sulfur 30
1,000 MW, 3.5% sulfur 25
1,000 MW, 3.5% sulfur 30
90% S02 removal
500 MW, 3.5% sulfur 30
Lower (90% of base case)
sulfur conversion factor 30
Wet-scrubbing fly ash
removal 30
37,994
37,428
71,167
55,578
70,338
82,323
109,247
107,148
73,643
72,655
63,217
190
187
142
111
141
165
109
107
147
145
126
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
44,074
88
a. A 127,500-hour, 30-year lifetime is used. FGD facilities
for cases with 30 years of remaining life are constructed
simultaneously with the power plant; others are retrofit
installations.
109
-------
This comparison is illustrative of the economic benefits derived
from the combination of flue gas cleaning functions, one of the main
advantages of the AGP in these studies. The Wellman-Lord process case
variations in which chloride and fly ash removal are combined offer a
similar example. In the case of the ACP and similar dry-collection FGD
processes, however, particulate collection and chloride removal are
intrinsic functions, not process options.
For further cost comparisons, the direct capital investment costs
by processing area are shown in Tables 27 and 28. Table 27 shows the
base case and the 2.0% and 5.0% coal sulfur content case variations. Since
the power plants are new, an ESP credit is applied to the ACP. Table 28
shows the 200-, 500-, and 1000-MW existing power plants for which no ESP
credit is applied to the ACP. The materials handling area costs are
minor and essential equivalent for all of the processes. Gas handling
is slightly higher for the ACP than for the Wellman-Lord processes
because of the additional ductwork required for the ESP's. Chloride
removal is a substantial cost element in the Wellman-Lord processes,
accounting in the base cases for about 15% of the process equipment
costs, similar to the costs for S02 absorption. Absorption-collection
process equipment costs for the ACP are about twice that of the Wellman-
Lord processes but the costs include ESP's as well as the spray dryer
absorbers. When ESP credits are applied, the ACP absorption-collection
cost is essentially equivalent to those of the Wellman-Lord processes.
In Tables 27 and 28, costs for flue gas reheat are included in the S02
absorption-collection costs for the Wellman-Lord processes. The reheat
costs are 2.3 $/kW for the 500-MW power plant and 2.5 and 1.8 $/kW for
the 200- and 1000-MW power plants. The ACP does not require flue gas
reheating. The ACP regeneration area costs are about one-third higher
than those of the Wellman-Lord processes. For the ACP, however, this
area also includes the chloride purge and residual fly ash removal. The
ACP also produces t^S, which is readily convertible to sulfur. The S02
produced by the Wellman-Lord regeneration area requires more complicated
treatment to produce a readily marketable byproduct. This is reflected
in the low ACP byproduct manufacturing costs, which are about one-half
those of the Wellman-Lord processes. Overall, the regeneration -
byproduct manufacturing total costs are quite similar for all four
processes. The two factors contributing to cost differences between the
ACP and the Wellman-Lord processes are the new-plant ESP credit for the
ACP and chloride removal in the Wellman-Lord processes. In Table 28,
representing existing plants, the ESP credit is not applied to the ACP
process and its process equipment costs are similar to the Wellman—Lord
process equipment costs.
In comparisons of the three Wellman-Lord process variations, the
only major capital investment cost differences are in the byproduct
manufacturing areas. The different quantities of sulfur recycled in
tail gas returned to the absorbers because of the different design
sulfur recover efficiencies and the different Wellman-Lord off-gas
compositions have a minor effect on costs of the Wellman-Lord process.
The byproduct manufacturing process equipment costs are understandably
lowest for the sulfuric acid unit, although the Resox and Allied units
110
-------
TABLE 27. DIRECT CAPITAL INVESTMENT BY PROCESSING AREA FOR
NEW 500-MW POWER PLANTS WITH 2.0%, 3.5%, and 5.0% SULFUR COAL
$/kW
Processing area
Materials handling
Gas handling
Chloride removal
S0£ absorption-collection3
Fly ash collection
ESP credit
Regeneration"
1 Byproduct manufacture
Total process equipment
Total capital investment
2.0% S
0.5
10.2
-
21.3
1.0
(11.8)
16.0
4.4
41.6
87.2
ACP
3.5% S
0.8
10.2
-
21.3
1.0
(9.4)
27.6
7.5
58.9
119.4
Wellman-Lord/sulfuric acid
5.0% S
1.1
10.2
-
21.3
1.0
(9.4)
37.3
10.0
71.4
142.8
2.0% S
0.6
8.8
9.8
11.0
-
-
12.7
7.6
50.5
103.3
3.5% S
0.9
8.8
9.8
11.0
-
-
21.6
13.0
65.0
130.7
5.0% S
1.1
8.8
9.8
11.0
-
-
29.0
17.5
77.1
153.6
Wellman-Lord/Resox
2.0% S
0.6
8.8
9.8
11.0
—
—
12.9
9.3
52.6
107.3
3.5% S
0.9
8.8
9.8
11.0
—
-
21.9
15.9
68.2
137.5
5.0% S
1.1
8.8
9.8
11.0
—
—
29.4
21.3
81.3
162.7
Wellman-Lord/Allied
2.0% S
0.6
8.8
9.8
11.0
—
-
12.7
11.4
54.3
111.2
o c
-------
TABLE 28. DIRECT CAPITAL INVESTMENT COSTS BY PROCESSING AREA
FOR EXISTING 200-MW, 500-MW, and 1000-MW POWER PLANTS
$/kW
200 MW
ACP
500 MW
Wellman-Lord/sulfuric acid
1000 MW
200 MW
500 MW
1000 MW
Wellman-Lord/Resox
200 MW
500 MW
1000 MW
Wellman-Lord/Allied
200 MW
500 MW
1000 MW
Processing area
\->
fo
Materials handling
Gas handling
Chloride removal
S02 absorption-collection3
Regeneration"
Byproduct manufacture
Total process capital
Total capital investment
1.2
11.3
-
23.4
37.7
10.4
84.1
174.2
0.8
10.3
-
21.7
28.0
7.6
68.4
136.5
0.6
8.1
—
17.9
22.4
6.0
55.1
109.6
1.5
9.8
10.8
12.0
30.0
17.9
82.0
171.0
0.9
8.9
10.0
11.2
21.9
13.2
66.0
132.5
0.6
7.0
8.2
9.4
17.4
10.5
53.1
103.7
1.5
9.8
10.8
12.0
30.4
22.0
86.5
180.6
0.9
8.9
10.0
11.2
22.2
16.1
69.2
139.4
0.6
7.0
8.2
9.4
17.6
12.7
55.6
109.2
1.5
9.8
10.8
12.0
29.9
27.2
91.2
190.0
0.9
8.9
10.0
11.2
21.9
17.8
70.6
142.3
0.6
7.0
8.2
9.4
17.3
12.9
55.5
109.2
a. Consists of ACP spray dryers and ESP's; Wellman-Lord scrubbers and reheat costs of 2.5, 2.3, and 1.8 $/kW for 200-, 500-, and 1000-MW
plants.
b. Includes ACP chloride purge and residual particulate matter removal.
-------
are only 22% and 35% higher than the sulfuric acid unit in process
equipment costs. The overall FGD total capital investments for the
Wellman-Lord/Resox and Wellman-Lord/Allied processes are only 5% and 7%
higher than the total capital investment of the Wellman-Lord/sulfuric
acid process. The higher capital investment for the Allied unit results
from the use of power plant bituminous coal, requiring grinding and
drying facilities, and in a more elaborate sulfur collection and cleaning
facilities. The Allied unit capital investment for coal handling and
processing is twice that of the anthracite handling capital investment
for the Resox unit. The Allied unit capital investment for sulfur
collection and processing is two-thirds higher than that of the Resox
unit. Conversely, the Resox reactor capital investment, which includes
spent anthracite handling, is almost twice that of the Allied unit. The
higher Resox reactor costs are the result of the complex piping and
extensive structural support required for the reactors and anthracite
feed bins. Most of the Allied process equipment is self-supporting.
The Allied unit also has a larger incremental pond cost (0.9 $/kW for
the base case) representing disposal costs of the spent reducing coal.
Case Variations
The expected economy of scale is seen in the results of the power
plant size case variations as shown in Figure 14. The capital investments
approximately double as the power plant size increases from 200 to 500
MW and triple as the size increases from 200 to 1000 MW. The capital
investment per unit of electricity produced thus decreases one-fourth
and two-fourths for the two size increases. The convergence of the
Resox and Allied costs at the 1000-MW power plant size is a result of
scaling factors based on the process complexity. The Allied unit, with
more process equipment, has a slightly higher economy of scale. Even
though Allied has more process equipment, the equipment is all standard.
The Resox reactor and feed bin is not a standard arrangement. The cost
of the Allied grinding equipment (a major cost item) escalates little
with capacity.
Coal sulfur content has a considerable effect on capital investment,
as shown in Figure 15. Costs related to sulfur removal rates are more
than tripled as the coal sulfur content increases from 2% to 5%. (About
3.3 times more sulfur is removed at the 5% coal sulfur content than at
the 2% coal sulfur content to meet the 1.2 Ib S02/MBtu emission limit.)
The processing areas affected are the materials handling, regeneration,
and byproduct manufacturing areas, which more than double in cost. The
result is an increase in cost of 64% for the ACP and about 50% for the
three Wellman-Lord processes as the coal sulfur level increases from 2%
to 5%. The larger increase for the ACP occurs because the ACP has a
larger percentage of capital equipment costs in the processing areas
affected by sulfur removal rates and the ESP credit is higher for the
lower sulfur level because of the lower collection efficiency with
lower-sulfur flue gas.
The data in Figures 14 and 15, in conjunction with the detailed
results in the appendix, can be used to develop correlations of capital
113
-------
200
H
a
w
PM
H
CO
w
150
100
50
120
90
60
30
200
200
I
I
400 600
POWER PLANT SIZE, MW
800
1000
I
I
I
400 600
POWER PLANT SIZE, MW
800
1000
Figure 14. Effect of power plant size on capital investment. 1 - ACP,
2 - Wellman-Lord/sulfuric acid, 3 - Wellman-Lord/Resox,
4 - Wellman-Lord/Allied.
114
-------
200
150
*\
H
100
CM 50
u
120
90
CO
w
60
30
I
2 3
COAL SULFUR CONTENT, %
I
2 3
COAL SULFUR CONTENT, %
Figure 15. Effect of coal sulfur content on capital investment.
1 - ACP, 2 - Wellman-Lord/sulfuric acid, 3 - Wellman-Lord/Resox,
4 - Wellman-Lord/Allied.
115
-------
investment as a function of power plant size and coal sulfur content.
These correlations can be used to project the data to conditions not
treated in this study.
An increase in SOX removal efficiency from the base-case 79% to 90%
results in a small increase in capital investment. The increase is
about 5% for all of the processes and is a result of larger reduction,
regeneration, and byproduct manufacturing costs.
Reduction of the conversion efficiencies of the Resox and Allied
units by 10% of the base-case conversions (90% and 96% respectively)
increases the capital investments by about 3% for both processes.
As a case variation for the Wellman-Lord processes, the chloride
removal scrubbing system was modified to include fly ash removal as
well. For comparison with the base-case conditions and the ACP, an ESP
direct investment credit of 9.4 $/kW is applied to the wet-scrubbing fly
ash removal cases as it is for the ACP. The results are shown in Table 29.
The increase in capital investment for combined fly ash and chloride
removal, as compared with chloride removal alone, is only 0.8 $/kW.
Combining fly ash removal and chloride removal thus results in a substan-
tial reduction in capital investment when the ESP credit is applied.
The case variation for oil-fired power plants shows a different
capital investment relationship between the ACP and the three Wellman-
Lord processes. The capital investments by processing area are shown in
Table 30. For the oil-fired power plants, the ACP has the highest
capital investment, 22% to 12% higher than the three Wellman-Lord
processes. The capital investments of all four processes are lower than
the corresponding existing 500-MW coal-fired power plant capital investments
and the relationship of the three Wellman-Lord variations are unchanged.
The lower capital investments are partially the result of the lower flue
gas rate, fuel sulfur content, and low fly ash content. The major
reduction of capital investment in the Wellman-Lord variations, however,
results from the elimination of about 10 $/kW for chloride removal,
making the absorption-collection area for the Wellman-Lord process
considerably less expensive than the ACP absorption-collection area.
The capital investment relationships of the four processes in other
processing areas remain essentially unchanged from those of the existing
coal-fired cases.
ANNUAL REVENUE REQUIREMENTS
The annual revenue requirements for the four processes are summarized
in Tables 31-34. The annual revenue requirements follow the same general
relationships as the capital investment. For new plants, the ACP has
the lowest annual revenue requirements, followed in order of increasing
cost by the Wellman-Lord/sulfuric acid, Wellman-Lord/Allied, a'nd Wellman-
Lord/Resox processes. For existing plants, the Wellman-Lord/sulfuric
acid process has the lowest annual revenue requirements, followed by the
ACP, the Wellman-Lord/Allied process, and the Wellman-Lord/Resox process.
116
-------
TABLE 29. WELLMAN-LORD PROCESSES CAPITAL INVESTMENT WITH TOT-SCRUBBING AND FLY ASH REMOVAL
Wellman-Lord/sulfuric acid
ACP
base case
Base case
Wet fly
ash removal
$/kW
Wellman-Lord/Resox
Base case
Wet fly
ash removal
Wellman-Lord/Allied
Base case
Wet fly
ash removal
Processing area
H
H"
•-J
Materials handling
Gas handling
Chloride removal
' SC>2 absorption-collection
ESP credit
Fly ash-chloride removal
Regeneration
Byproduct manufacture
Total process equipment
Total capital investment
0.8
10.2
-
22.3
(9.4)
-
27.6
7.5
59.1
119.4
0.9
8.8
9.8
11.0
-
-
21.6
13.0
65.0
130.7
0.9
9.3
-
11.0
(9.4)
10.6
21.6
13.0
56.9
116.4
0.9
8.8
9.8
11.0
-
-
21.9
15.9
68.2
137.5
0.9
9.3
-
11.0
(9.4)
10.6
21.9
15.9
60.1
123.3
0.9
8.8
9.8
11.0
-
-
21.6
17.6
69.6
140.7
0.9
9.3
-
11.0
(9.4)
10.6
21.6
17.6
61.5
126.4
-------
TABLE 30. CAPITAL INVESTMENT BY PROCESSING AREA
FOR OIL-FIRED POWER PLANTS
$/kW
Wellman-Lord/ Wellman-Lord/ Wellman-Lord/
AGP sulfuric acid Resox Allied
Processing area
Materials handling 0.5 0.6 0.6 0.6
Gas handling 9.1 7.8 7.8 7.8
Absorption-collection 18.8 10.6 10.6 10.6
Regeneration 15.6 12.4 12.4 12.3
Byproduct manufacture 4.3 7.4 9.1 11.1
Total process capital 48.2 38.7 40.6 42.5
Total capital investment 98.4 80.7 84.6 88.1
118
-------
TABLE 31. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
Case
Coal-Fired Power
Unit
Years
Annual revenue requirements
remaining
lifea
k$
Mills/
kWh
$/ton fuel
($/bbl oil)
$/MBtu
heat input
$/ton S
removed
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW,
200 MW,
500 MW,
500 MW,
• 500 MW,
500 MW,
1,000 MW,
1,000 MW,
3.5%
3.5%
3.5%
2.0%
3.5%
5.0%
3.5%
3.5%
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
20
30
25
30
30
30
25
30
10
8
18
12
16
20
30
26
,010
,724
,957
,026
,820
,708
,427
,517
7.15
6.23
5.42
3.44
4.81
5.92
4.35
3.79
15
14
12
8
11
13
10
9
.80
.23
.36
.02
.21
.80
.14
.14
0
0
0
0
0
0
0
0
.75
.68
.59
.38
.53
.66
.48
.44
682
614
533
752
484
387
437
394
90% S02 removal
500 MW, 3.5% sulfur
30
17,851 5.10
11.90
0.57
451
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
13,254 3.79
(2.48)
0.41
864
a. A 127,500-hour, 30-year lifetime is used. FGD facilities for cases with 30 years of
remaining life are constructed simultaneously with the power plant; others are retro-
fit installations.
-------
TABLE 32. WELLMAN-LORD/SULFURIC ACID
ANNUAL REVENUE REQUIREMENTS
to
o
Case
Years
remaining
lifea
Annual revenue requirements
k$
Mills/
kWh
$/ton fuel
($/bbl oil)
$/MBtu
heat input
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW, 3.5% sulfur
500 MW, 3.5% sulfur
500 MW, 2.0% sulfur
• 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
1,000 MW, 3.5% sulfur
1,000 MW, 3.5% sulfur
90% S02 removal
500 MW, 3.5% sulfur
Wet-scrubbing fly ash
removal
20
30
25
30
9,659
9,140
18,415
14,071
6.90
6.53
5.26
4.02
15.25
14.91
12.01
9.38
30
30
25
30
30
30
17,892 5.11
21,220
29,464
28,363
6.06
4.21
4.05
18,764 5.36
17,310 4.95
11.93
14.15
9.82
9.78
12.51
11.54
0.73
0.71
0.57
0.45
0.57
0.67
0.47
0.47
0.60
0.55
$/ton S
removed
658
643
518
879
514
397
424
422
474
498
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
11,993 3.43
(2.24)
0.37
782
a. A 127,500-hour, 30-year lifetime is used. FGD facilities for cases with 30 years of
remaining life are constructed simultaneously with the power plant; others are retro-
fit installations.
-------
TABLE 33. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
Years
Annual revenue requirements
remaining
Case lifea k$
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW, 3.5% sulfur
500 MW,. 3.5% sulfur
500 MW, 2.0% sulfur
• 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
1,000 MW, 3.5% sulfur
1,000 MW, 3.5% sulfur
90% S02 removal
500 MW, 3.5% sulfur
Lower (90% of base case)
sulfur conversion factor
Wet-scrubbing fly ash
removal
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
20
30
25
30
30
30
25
30
30
30
30
25
11,141
10,558
21,709
15,629
21,107
26,044
35,615
34,303
22,393
22,140
20,530
13,501
Mills/
kWh
7.96
7.54
6.20
4.47
6.03
7.44
5.09
4.90
6.40
6.33
5.87
3.86
$/ton fuel
($/bbl oil)
17.59
17.22
14.16
10.42
14.07
17.36
11.87
11.83
14.93
14.76
13.69
(2.52)
$/MBtu
heat input
0.84
0.82
0.67
0.50
0.67
0.83
0.57
0.56
0.71
0.70
0.65
0.42
$/ton S
removed
759
742
611
977
607
487
512
510
565
637
590
881
a. A 127,500-hour, 30-year lifetime is used. FGD facilities for cases with 30 years of
remaining life are constructed simultaneously with the power plant; others are retro-
fit installations.
-------
TABLE 34.' WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
Case
Coal-Fired Power
Unit
Years
Annual revenue requirements
remaining
life3 k$
Mills/
kWh
$/ton fuel
($/bbl oil)
$/MBtu
heat input
$/ton S
removed
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW,
200 MW,
500 MW,
500 MW,
• 500 MW,
500 MW,
1,000 MW,
1,000 MW,
3.5%
3.5%
3.5%
2.0%
3.5%
5.0%
3.5%
3.5%
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
20
30
25
30
30
30
25
30
11
10
21
15
20
25
34
33
,277
,702
,366
,720
,788
,267
,386
,167
8.05
7.64
6.10
4.49
5.94
7.22
4.91
4.74
17
17
13
10
13
16
11
11
.80
.45
.93
.48
.86
.84
.46
.44
0
0
0
0
0
0
0
0
.85
.83
.66
.50
.66
.80
.55
.54
768
753
601
982
598
472
494
493
90% S02 removal
500 MW, 3.5% sulfur 30
Lower (90% of base case)
sulfur conversion factor 30
21,965 6.28
21,709 6.20
Wet-scrubbing fly ash
removal
30
20,212
5.77
14.64
14.47
13.47
0.70
0.69
0.64
554
624
581
Oil-Fired Power Unit
0.8 Ib S02/MBtu-heat-input
allowable emission
500 MW, 2.5% sulfur
25
13,571 3.88
(2.54)
0.42
885
a. A 127,500-hour, 30-year lifetime is used. FGD facilities for cases with 30 years of
remaining life are constructed simultaneously with the power plant; others are retro-
fit installations.
-------
For the base case, the maximum difference in annual revenue requirements
is 25%; for the case variations, the maximum difference is 30%.
The cost relationships are the result of the indirect cost capital
charges based on capital investment which compose roughly half of the
annual revenue requirements. The ranking of the processes by capital
investment is thus imprinted upon the annual revenue requirements. In
this case, the relationship of the ACP to the Wellman-Lord processes is
strongly influenced by the ESP capital investment credit for new plants
reflected in the indirect costs. In direct costs, consisting of raw
material and conversion costs, the ACP is one-fifth to two-fifths lower
than the Wellman-Lord processes.
The major cost elements in annual revenue requirements are shown in
Table 35 for the base case and fuel-sulfur case variations and in Table 36
for the existing-plant power plant size case variations. The major
areas of difference are in raw materials, utilities, indirect costs, and
byproduct credits. Labor, supervision, and maintenance costs do not
differ greatly among the four processes.
Reducing coal is the largest raw material cost for all three sulfur-
producing processes, particularly for the Wellman-Lord/Resox process
which uses anthracite. The ACP requires more soda ash than the Wellman-
Lord processes and more reducing coal than the Wellman-Lord/Allied
process, which, like the ACP, also uses power plant coal.
Utilities constitute the largest direct cost for all four processes
and represent the major area of cost difference between the ACP and the
Wellman-Lord processes. The ACP utility costs are less than one-half
those of the Wellman-Lord processes. The ACP requires no power plant
steam, has slightly lower electricity costs, and lower water costs.
About one-third of the ACP utility cost is for fuel oil, however. In
this study fuel oil is priced at $0.40/gal, the price used in previous
evaluations in this series. At escalated fuel oil prices, the utility
cost advantage of the ACP relative to the other processes would be
eroded unless an alternate fuel were used. The main advantages of the
ACP in utility costs, however, are its low process steam requirements
and its absence of flue gas reheat requirements. In addition to larger
process steam requirements, the Wellman-Lord processes require steam for
flue gas reheating.
The annual revenue requirements of the three variations of the
Wellman-Lord process are lowest for the sulfuric acid variation and
essentially equivalent for the Resox and Allied variations. Since the
Wellman-Lord costs are essentially equivalent for all three variations,
the cost differences represent the byproduct manufacturing costs, indirect
costs, and sales credits. Thus the sulfuric acid variation, which has
no raw material costs for byproduct production, the lowest indirect
costs, and the highest byproduct credit, has considerably lower annual
revenue requirements than the sulfur-producing variations.
123
-------
TABLE 35. ANNUAL REVENUE REQUIREMENTS PROCESS COST ELEMENTS
FOR NEW 500-MW POWER PLANTS WITH 2.0%, 3.5%, AND 5.0% SULFUR COAL
Mills/kWh
Raw materials
Soda ash
Anthracite
Coal
Other
Total
Labor and supervision
Utilities
Fuel oil
Steam
Electricity
Water
Heat credit
Total
Maintenance and analysis
Total direct costs
Indirect costs
Byproduct credit
Total
2.0% S
0.15
0.17
0.31
0.17
0.12
0.42
0.01
(0.05)
0.50
0.48
1.46
2.15
(0.19)
3.44
ACP
3.5% S
0.32
0.36
0.68
0.19
0.26
0.56
0.02
(0.11)
0.73
0.67
2.27
2.95
(0.41)
4.81
Wellman-Lord/sulfuric acid
5.0% S
0.49
0.56
1.05
0.20
0.41
0.72
0.03
(0.18)
0.98
0.80
3.03
3.53
(0.64)
5.92
2.0% S
0.09
0.01
0.10
0.15
0.54
0.50
0.08
(0.01)
1.11
0.50
1.86
2.51
(0.35)a
4.02
3.5% S
0.19
0.01
0.20
0.19
0.89
0.64
0.18
(0.03)
1.68
0.63
2.68
3.19
(0.77)b
5.11
5.0% S
0.29
0.02
0.31
0.18
1.24
0.78
0.26
(0.04)
2.24
0.75
3.48
3.77
(1.18)°
6.06
Wellman-Lord/Resox
2.0% S
0.09
0.26
0.01
0.36
0.15
0.04
0.54
0.50
0.07
(0.05)
1.10
0.51
2.13
2.59
(0.25ja'd
4.47
3.5% S
0.19
0.57
0.01
0.77
0.17
0.09
0.90
0.63
0.14
(0.11)
1.65
0.66
3.25
3.32
(0.54)b'e
6.03
5.0% S
0.29
0.87
0.01
1.18
0.18
0.14
1.25
0.77
0.21
(0.16)
2.21
0.78
4.35
3.94
(0.84)c'f
7.44
Wellman-Lord/Allled
2.0% S
0.09
0.10
0.01
0.20
0.15
0.02
0.54
0.50
0.08
(0.02)
1.12
0.53
2.01
2.67
(0.19)a
4.49
3.5% S
0.19
0.21
0.01
0.41
0.17
0.05
0.90
0.64
0.14
(0.03)
1.70
0.68
2.96
3.39
(0.41)b
5.94
5.0% S
0.29
0.32
0.02
0.63
0.18
0.08
1.25
0.78
0.22
(0.05)
2.28
0.79
3.88
3.96
(0.63)°
7.22
a. Includes 0.02 mill/kWh for Na2S04.
b. Includes 0.05 mill/kWh for Na2S04.
c. Includes 0.08 mill/kWh for Na2S04.
d. Includes 0.06 mill/kWh for spent anthracite.
e. Includes 0.12 mill/kWh for spent anthracite.
f. Includes 0.19 mill/kWh for spent anthracite.
-------
TABLE 36. ANNUAL REVENUE REQUIREMENT COST ELEMENTS
FOR EXISTING 200-MW, 500-MW, AND 1000-MW POWER PLANTS
Mills/kWh
ACP
Wellman-Lord/sulfuric acid
200 MW 500 MW 1000 MW
Raw materials
Soda ash
Anthracite
Coal
Other
Total
Labor and supervision
Utilities
Fuel oil
Steam
Electricity
Other
I Heat credit
Total
Maintenance and analysis
Total direct costs
Indirect costs
Byproduct credit
Total
0.34
0.38
0.72
0.34
0.27
0.65
0.03
(0.12)
0.83
1.08
2.96
4.63
(0.44)
7.15
0.33
0.37
0.70
0.19
0.27
0.58
0.02
(0.12)
0.75
0.77
2.41
3.43
(0.42)
5.42
0.32
0.36
0.68
0.12
0.26
0.55
0.01
(0.11)
0.71
0.54
2.06
2.71
(0.41)
4.35
Wellman-Lord/Resox
200 MW 500 MW 1000 MW 200 MW
0.20
0.02
0.22
0.27
0.94
0.73
0.19
(0.03)
1.83
0.92
3.23
4.48
(0.81)a
6.90
0.19
0.02
0.21
0.17
0.91
0.66
0.17
(0.03)
1.71
0.64
2.74
3.31
(0.78)b
5.26
0,19
0.01
0.20
0.12
0.89
0.62
0.17
(0.03)
1.65
0.44
2.41
2.56
(0.76)C
4.21
0.20
0.60
0.01
0.81
0.27
0.10
0.95
0.72
0.14
(0.11)
1.80
0.97
3.85
4.68
(0.58)
7.96
500 MW 1000 MW
0.19
0.58
0.02
0.79
0.17
0.09
0.92
0.65
0.14
(0.11)
1.69
0.67
3.32
3.44
a'd(0.56)b
6.20
0.19
0.57
0.01
0.77
0.12
0.09
0.90
0.61
0.14
(0.11)
1.63
0.45
2.98
2.66
>e(0.55)
5.09
Wellman-Lord/Allied
200 MW 500 MW 1000 MW
0.20
0.22
0.02
0.44
0.27
0.05
0.95
0.73
0.16
(0.04)
1.85
1.02
3.58
4.91
c'f(0.43)a
8.05
0.19
0.21
0.02
0.42
0.17
0.05
0.92
0.66
0.14
(0.03)
1.74
0.69
3.02
3.50
(0.42)b
6.10
0.19
0.21
0.01
0.41
0.12
0.05
0.90
0.62
0.14
(0.03)
1.68
0.46
2.67
2.65
(0.41)c
4.91
a. Includes 0.06 mill/kWh for
b. Includes 0.05 mill/kWh for
c. Includes 0.05 mill/kWh for Na2S04.
d. Includes 0.13 mill/kWh for spent anthracite.
e. Includes 0.13 mill/kWh for spent anthracite
f. Includes 0.12 mill/kWh for spent anthracite.
-------
The two areas of significant cost differences between the Resox and
Allied variations are in reducing coal costs and byproduct revenue. At
the base-case conditions, anthracite for the Resox unit, at 0.57 mill/kWh,
is appreciably more expensive than power plant coal for the Allied unit,
at 0.21 mill/kWh. The byproduct credit for the Wellman-Lord/'Resox
process is 0.54 mill/kWh, compared with 0.41 mill/kWh for the Wellman-
Lord/Allied process, because the Resox credit includes 0.12 mill/kWh for
spent anthracite transferred to the power plant for boiler fuel.
Case Variations
The effect of power unit size on annual revenue requirements is
shown in Figure 16. The annual revenue requirements approximately
double as the power plant size increases from 200 to 500 MW and triple
as the size increases from 200 to 1000 MW. In terms of mills/kWh, the
corresponding decreases are about one-fourth and two-fourth's. Since
costs for raw materials and utilities and byproduct credits are linearly
related to power plant size., the economy of scale is primarily realized
through more efficient use of labor, supervision, and maintenance and
reduced capital charges and overheads.
The effect of coal sulfur content is shown in Figure 17. In contrast
to the effects of power unit size, coal sulfur content has little effect
on labor and supervision costs. Costs directly related to sulfur removed
such as raw material are more than tripled as the coal sulfur content
increases from 2% to 5%. Utility, labor, supervision, and maintenance
costs, related partly to sulfur removed and partly to flue gas rate,
approximately double. Indirect costs increase about one-half. These
cost increases are somewhat offset by a higher byproduct credit and
heat credit paralleling the threefold increase in sulfur removed. The
overall result is an increase in annual revenue requirements of about
70% for the AGP and 50% to 60% for the Wellman-Lord processes, depending
on percentages of costs and credits linearly related to the quantity of
sulfur removed. The AGP, with high raw material costs, high fuel oil
costs, and a smaller byproduct credit, all of which are directly related
to the quantity of sulfur removed, has the largest cost increase. The
Wellman-Lord/sulfuric acid process, with low raw material costs and a
large byproduct credit, has the least.
The varied rates of cost increase result in changing cost relation-
ships as the coal sulfur content increases. The AGP annual revenue
requirements converge with those of the other processes, most obviously
with the Wellman-Lord/sulfuric acid process. The annual revenue require-
ments of the Wellman-Lord/Resox process, slightly less than those of the
Wellman-Lord/Allied process with 2% sulfur coal, become slightly greater
as the coal sulfur content increases. This reversal of position results
from the larger costs for raw materials, particularly anthracite, for
the Resox version, a cost directly related to coal sulfur content.
The annual revenue requirements for 90% S02 removal increase 4% to
6% compared with the base-case 79% removal. The increased costs are
generally distributed through direct and indirect costs, mitigated by a
13% to 17% increase in byproduct credit from the 14% increase in sulfur
removed.
-------
ANNUAL REVENUE REQUIREMENTS, M$
to
l-t
(D
-P- M M
l-h
I I Mi
(D
£3 > o
(D O rt
M hi
M- O
S l-h
(U NJ
0 T)
I I O
tr1 s;
o s; m
i-i (D I-!
D- M
~- M T3
> 3 i-1
i— • w p>
M P P
H- I rr
(D tr1
Cu O CO
• i-i H-
P. N
-~- (D
CO
c o
M 3
s
S
C
pj h-i
n
H- i-i
P- (C
(t
U) 3
C
I (D
rt> 0>
I-1 C
3 (D
I 9
tr1 CD
O 3
i-l rf
re
CO
o
ANNUAL REVENUE REQUIREMENTS, MILLS/KWH
U3
o
•p-
o
-p-
oo
N3
o
o
O
s:
O
O
M
o
o
oo
o
o
o
o
o
o
o
O -P~
s: o
M O
i
M O
v. O
oo
o
o
-P- to
o
o
o
-P-U)
-------
CO
H
w
£3
o-
w
Pi
w
>
w
pi
I
40
2 3
COAL SULFUR CONTENT, %
H
S5
W
H
Cf
W
Pi
w
Ed
Pi
30
20
10
2 3
COAL SULFUR CONTENT, %
Figure 17. Effect of coal sulfur content on annual revenue requirements.
1 - AGP, 2 - Wellman-Lord/sulfuric acid, 3 - Wellman-Lord/Resox,
4 - Wellman-Lord/Allied.
128
-------
For the wet-scrubbing fly ash removal case variation in the Wellman-
Lard processes, annual revenue requirements are reduced about 3% from
the base case. The results are shown in Table 37. Electricity require-
ments are increased about one-half, roughly 0.3 mill/kWh, indirect costs
are decreased about the same amount because of the lower capital charges,
maintenance costs decrease slightly, and there is a small ESP electricity
credit. The capital charges are lower because of the ESP credit applied
to capital investment.
Reduction of the Resox unit and Allied unit sulfur conversion rate
to 90% of the base-case rate also has a minor effect on annual revenue
requirements. Costs are increased about 5%, primarily because of
increased raw material and utility requirements.
The annual revenue requirements for the case variations for oil-
fired power plants, shown in Table 38, have the same relationships as
the capital investments. The Wellman-Lord/sulfuric acid process has the
lowest annual revenue requirements, followed by the ACP, the Wellman-
Lord/Resox process and the Wellman-Lord/Allied process. As in the other
existing power plant case variations, the ACP has the lowest direct
costs but the highest indirect costs. Not only is there no ESP capital
investment credit for the ACP, which increases ACP indirect costs, but
chloride removal costs for the Wellman-Lord processes are eliminated,
which decreases both direct and indirect costs for these processes.
Oil-fired flue gas reheat is used, however, increasing the Wellman-Lord
processes reheating costs about 15%. The overall effect is an improve-
ment in the economics of the Wellman-Lord processes relative to the ACP,
making the three sulfur-producing processes essentially equivalent in
annual revenue requirements.
LIFETIME REVENUE REQUIREMENTS
Computer projections of the year-to-year operating cost and sales
revenue analyses for all case variations for each of the processes are
shown in the appendix. These projections are prepared on a regulated
economics basis as discussed in the premises and correspond to the 30-
year declining operating profile described in the premises. Annual
capital charges are based on the undepreciated investment. Lifetime
costs, both total and discounted at the regulated cost of money (11.6%
for this study), and equivalent unit revenue requirements are shown.
Summarized results of the lifetime revenue requirement projections are
shown in Tables 39-42. The discounted lifetime revenue requirements are
the year-by-year annual revenue requirements discounted to mid-1980
values at 11.6%. The levelized lifetime unit revenue requirements are
obtained by dividing the discounted revenue requirements by the dis-
counted number of units defining the cost.
129
-------
TABLE 37. TOLLMAN-LORD PROCESSES ANNUAL REVENUE REQUIREMENTS WITH TOT-SCRUBBING FLY ASH REMOVAL
Mills /kWh
Wellman-Lord/sulfuric acid Wellman-Lord/Resox
Raw materials
Soda ash
Anthracite
Coal
Other
Total
Labor and supervision
Utilities
Fuel oil
^ Steam
<-o Electricity
Water
Heat credit
Total
Maintenance and analysis
Total direct costs
Indirect costs
Byproduct credit
Total
ACP
base case
0.32
-
0.36
-
0.68
0.19
0.26
-
0.56
0.02
(0.11)
0.73
0.67
2.27
2.95
(0.41)
4.81
Base case
0.19
-
-
0.01
0.20
0.19
-
0.89
0.64
0.18
(0.03)
1.68
0.63
2.68
3.19
(0.77)a
5.11
Wet fly
ash removal
0.19
-
-
0.01
0.20
0.17
-
0.89
0.81
0.17
(0.03)
1.84
0.56
2.86
2.86
(0.77)a
4.95
Base case
0.19
0.57
-
0.01
0.77
0.17
0.09
0.90
0.63
0.14
(0.11)
1.65
0.66
3.25
3.32
(0.54)a'b
6.03
Wet fly
ash removal
0.19
0.57
-
0.01
0.77
0.17
0.09
0.90
0.88
0.14
(0.11)
1.90
0.59
3.43
2.99
(0.54)a>b
5.87
Wellman-Lord/Allied
Base case
0.19
-
0.21
0.01
0.41
0.17
0.05
0.90
0.64
0.14
(0.03)
1.70
0.68
2.96
3.29
(0.41)a
5.94
Wet fly
ash removal
0.19
-
0.21
0.01
0.41
0.17
0.05
0.90
0.89
0.14 .
(0.03)
1.95
0.60
3.13
3.05
(0.41)a
5.77
a. Includes 0.05 mill/kWh for
b. Includes 0.12 mill/kWh for spent anthracite.
-------
TABLE 38. ANNUAL REVENUE REQUIREMENT COST ELEMENTS
FOR OIL-FIRED POWER PLANTS
We 1 Iman-Lo rd /
ACP sulfuric acid
Raw materials
Soda ash
Anthracite
Coal
Other
Total
Labor and Supervision
Utilities
Fuel oil
Steam
Electricity
Water
Heat credit
Total
Maintenance and analysis
Total direct costs
Indirect costs
Byproduct credit
Total
0.14
0.16
0.30
0.18
0.11
0.37
0.01
(0.05)
0.44
0.55
1.48
2.49
(0.18)
3.79
0.08
0.02
0.10
0.16
0.28
0.29
0.44
0.08
(0.01)
1.08
0.39
1.73
2.04
(0.34)
3.42
Mills/kWh
Wellman-Lord/
Resox
0.08
0.25
0.02
0.35
0.16
0.32
0.29
0.44
0.06
(0.05)
1.06
0.41
1.98
2.12
(0.24)
3.86
Wellinan-Lord/
Allied
0.08
0.09
0.02
0.19
0.16
0.30
0.29
0.44
0.07
(0.01)
1.08
0.43
1.86
2.20
(0.18)
3.88
131
-------
TABLE 39. AQUEOUS CARBONATE PROCESS LIFETIME REVENUE REQUIREMENTS
Case
Coal-Fired Power
Unit
Years
Actual lifetime revenue requirements
remaining
life |M$
$/ton (bbl) Mills/
fuel burned kWh
$/MBtu $/ton
heat input S removed
Discounted
M$
Levelized
$/ton (bbl) Mills/
fuel burned kWh
$/MBtu $/ton
heat input S removed
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW,
200 MW,
500 MW,
500 MW,
• 500 MW,
500 MW,
1,000 MW,
1,000 MW,
3.5%
3.5%
3.5%
2.0%
3.5%
5.0%
3.5%
3.5%
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
sulfur
20
30
25
30
30
30
25
30
171,129
224,602
406,539
310,832
431,568
526,826
648,737
675,306
,400
,800
,800
,400
,200
,800
,300
,500
32.
20.
20.
11.
15.
19.
16.
12.
89
11
06
38
80
28
36
78
14
8
8
4
6
8
7
5
.88
.81
.79
.88
.77
.26
.01
.30
1
0
0
0
0
0
0
0
.57
.96
.96
.54
.75
.92
.78
.61
1,426.
868.
864.
1,068.
680.
540.
705.
551.
.08
,87
,98
,15
,71
.34
.53
,72
76,927
79,534
163,138
110,193
153,374
187,635
261,119
204,904
,400
,700
,300
,000
,600
,600
,900
,900
29.
18.
17.
10.
14.
17.
14.
11.
89
27
77
35
40
62
54
70
13
8
7
4
6
7
6
4
.52
.00
.78
.43
.17
.55
.23
.85
1
0
0
0
0
0
0
0
.42
.87
.85
.49
.69
.84
.69
.56
1,292.90
789.03
765.55
970.86
620.95
493.91
626.64
504.94
90% S02 removal
500 MW, 3.5% sulfur 30 456,945,400 16.73 7.17 0.80 633.33 162,492,700 15.26 6.54 0.73 577.85
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW, 2.5% sulfur 25 288,309,000 (4.10) 6.23 0.68 1,420.24 115,274,100 (3.62) 5.50 0.60 1,255.71
-------
TABLE 40. WELLMAN-LORD/SULFURIC ACID PROCESS LIFETIME REVENUE REQUIREMENTS
Years
Actual lifetime revenue requirements
remaining
Case life
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW, 3.5% sulfur
500 MW, 3.5% sulfur
500 MW, 2.0% sulfur
• 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
1,000 MW, 3.5% sulfur
1,000 MW, 3.5% sulfur
90% S02 removal
500 MW, 3.5% sulfur
Wet-scrubbing fly ash
removal
20
30
25
30
30
30
25
30
30
30
165
236
392
362
460
544
620
723
482
435
$/ton (bbl) Mills/
M$ fuel burned kWh
,186,700
,603,300
,857,900
,698,400
,522,800
,696,200
,909,900
,198,500
,738,200
,767,700
31.75
21.18
19.39
13.28
16.86
19.94
15.66
13.69
17.67
15.95
14.36
9.28
8.49
5.69
7.22
8.54
6.71
5.67
7.57
6.84
$/MBtu $/ton
heat input S removed
1.51
1.01
0.92
0.63
0.80
0.95
0.75
0.65
0.84
0.76
1,376
915
835
1,246
726
558
675
590
669
687
.56
.29
.87
.39
.38
.66
.27
.85
.08
.33
Discounted
M$
74,357
83,943
158,055
129,034
163,916
194,008
250,753
258,361
171,861
155,818
Levelized
$/ton (bbl) Mills/
fuel burned kWh
,000
,100
,600
,000
,600
,800
,400
,200
,100
,800
28.90
19.28
17.22
12.12
15.40
18.22
13.96
12.55
16.14
14.63
13.07
8.45
7.54
5.19
6.60
7.81
5.98
5.20
6.92
6.27
$/MBtu $/ton
heat input S removed
1.38
0.92
0.82
0.58
0.73
0.87
0.66
0.60
0.77
0.70
1,249.70
832.77
741.70
1,136.86
663.63
510.68
601.76
541.52
611.17
630.85
Oil-Fired Power Unit
0,8 Ib S02/MBtu heat input
allowable emission
500 MW, 2.5% sulfur
25
250,492,900
(3.56)
5.42
0.59
1,233.96 101,009,400
(3.17)
4.82
0.52
1,100.32
-------
TABLE 41. WELLMAN-LORD/RESOX PROCESS LIFETIME REVENUE REQUIREMENTS
Years
Actual lifetime revenue requirements
remaining
Case life M$
Coal-Fired Power Unit
1.2 Ib S02/MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW, 3.5% sulfur
500 MW, 3.5% sulfur
500 MW, 2.0% sulfur
• 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
1,000 MW, 3.5% sulfur
1,000 MW, 3.5% sulfur
90% S02 removal
500 MW, 3.5% sulfur
Lower (90% of base case)
sulfur conversion factor
Wet-scrubbing fly ash
removal
20
30
25
30
30
30
25
30
30
30
30
182,036,500
266,401,200
444,308,700
395, 304 , 800
526,415,700
642,505,900
714,686,800
842,995,900
556,883,100
550,313,300
501,928,800
$/ton (bbl) Mills/
fuel burned kWh
34.99
23.85
21.93
14.47
19.27
23.52
18.03
15.96
20.38
20.14
18.37
15.83
10.45
9.61
6.20
8.26
10.08
7.73
6.61
8.74
8.63
7.87
$/MBtu ' $/ton
heat input S removed
1.67
1.14
1.04
0.69
0.92
1.12
0.86
0.76
0.97
95.92
0.87
1,516.97
1,030.57
945 . 34
1,358.44
830.31
658.98
777.26
688.72
771.84
868.00
791.69
Discounted
Levelized
$/ton (bbl) Mills/
M$ fuel burned kWh
82,280,200
95,088,900
180,293,300
141,244,100
188,725,900
230,942,600
291,544,000
303,674,300
199,798,800
197,462,000
180,704,800
31.97
21.84
19.64
13.26
17.72
21.69
16.23
14.75
18.76
18.54
16.97
14.47
9.57
8.60
5.68
7.59
9.29
6.96
6.11
8.04
7.95
7.27
$/MBtu $/ton
heat input S removed
1.52
1.04
0.94
0.63
0.84
1.03
0.77
0.70
0.89
0.88
0.81
1,382.86
943.34
846.05
1,244.44
764.07
607.90
699.65
636.50
710.52
799.44
731.60
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW, 2.5% sulfur 25 275,127,300 (3.91) 5.95 ,0.65 1,355.31 111,603,700 (3.50) 5.33 0.58 1,215.73
-------
TABLE 42. WELLMAN-LORD/ALLIED PROCESS LIFETIME REVENUE REQUIREMENTS
Years
Actual lifetime revenue requirements
remaining
Case life M$
Coal-Fired Power Unit
1.2 Ib S02 /MBtu-heat-input
allowable emission
200 MW, 3.5% sulfur
200 MW, 3.5% sulfur
500 MW, 3.5% sulfur
500 MW, 2.0% sulfur
• 500 MW, 3.5% sulfur
500 MW, 5.0% sulfur
,_, 1,000 MW, 3.5% sulfur
U) 1,000 MW, 3.5% sulfur
Ul
90% S02 removal
500 MW, 3.5% sulfur
Lower (90% of base case)
sulfur conversion factor
Wet-scrubbing fly ash
removal
20
30
25
30
30
30
25
30
30
30
30
187,731,200
273,008,800
443,161,400
400,794,500
523,730,600
630,276,400
699,001,900
823,098,700
551,902,400
545,203,800
498,864,500
$/ton (bbl) Mills/
fuel burned kWh
36.08
24.44
21.87
14.67
19.17
23.07
17.63
15.58
20.20
19.96
18.26
16.32
10.71
9.58
6.29
8.22
9.89
7.56
6.46
8.66
8.55
7.83
$/MBtu $/ton
heat input S removed
1.72
1.16
1.04
0.70
0.91
1.10
0.84
0.74
0.96
0.95
0.87
1,564.43
1,056.13
942.90
1,377.30
826.07
646.44
760.20
672.47
764.94
859.94
786.85
Discounted
Levelized
$/ton (bbl) Mills/ $/MBtu $/ton
M$ fuel burned kWh heat input S removed
84,730,400
97,243,900
179,486,900
143,006,400
187,407,000
226,070,100
284,651,200
295,964,400
197,642,300
195,247,500
179,259,300
32.93
22.33
19.55
13.43
17.60
21.23
15.85
14.37
18.56
18.33
16.83
14.90
9.78
8.56
5.75
7.54
9.10
6.79
5.96
7.95
7.86
7.21
1.57
1.06
0.93
0.64
0.84
1.01
0.75
0.68
0.88
0.87
0.80
1,424.04
964.72
842.27
1,259.97
758.73
595.08
683.11
620.34
702.85
790.48
725.75
Oil-Fired Power Unit
0.8 Ib S02/MBtu heat input
allowable emission
500 MW, 2.5% sulfur
25
279,994,100
(3.98)
6.05
0.66
1,379.28 113,361,200
(3.56)
5.41
0.59
1,234.87
-------
VARIATIONS IN ECONOMIC FACTORS
The cost elements composing annual revenue requirements are subject
to numerous technical and economic influences that can alter not only
the operating costs of the processes but their economic relationships to
other processes. The major cost elements of the four processes are soda
ash; reducing coal; the conversion cost elements of operating labor and
supervision, electricity, fuel oil, steam, and maintenance; capital
charges; and byproduct credit. The importance of each varies with the
particular process and with the conditions of operation. Fuel oil, for
example, is an important cost element only for the ACP; also, no reducing
coal is used in the Wellman-Lord/sulfuric acid process. Some, such as
operating labor and supervision, are primarily size-dependent. Others,
such as raw materials, are directly related to the quantity of sulfur
removed. Capital charges, based on capital investment, vary according
to the age—and hence undepreciated capital—of the FGD system. For
these first-year annual revenue requirements capital charges constitute
about one-half of the annual revenue requirements, a proportion diminish-
ing over the life of the FGD system.
To illustrate the effects of various cost elements, the annual
revenue requirements for cost variations in specific cost elements are
shown in Tables 43 and 44. The costs, as a percentage of annual revenue
requirements, are shown in Table 45.
Soda ash costs are 5% or less of the Wellman-Lord processes annual
revenue requirements and 10% or less of the ACP annual revenue requirements.
The ACP is thus more sensitive to soda ash price variations because of
its higher consumption. Similarly, the Wellman-Lord/Resox process is
more sensitive to reducing coal costs, which constitute about 6% to 12%
of its annual revenue requirements, as compared with a maximum of 8% for
the ACP and Wellman-Lord/Allied process.
Operating labor and supervision costs range from 4% to 9% of annual
revenue requirements. They are highest, as a percentage of the total,
for the ACP and essentially equivalent for the three Wellman-Lord process
variations. Fuel oil costs are 3.5% to 6.8% of the ACP annual revenue
requirements, the percentage increasing with both power plant size and
coal sulfur content. Steam costs are 12% to 21% of the annual revenue
requirements for the three Wellman-Lord processes. Electricity costs
are 9% to 13% of annual revenue requirements. Maintenance costs are the
largest element of conversion costs, ranging from 13% to 23% of the
annual revenue requirements. A higher percentage of the ACP annual
revenue requirements is in maintenance costs compared with the Wellman-
Lord processes (although the amount is lower than the Wellman-Lord
processes) and the ACP is thus slightly more sensitive to variations in
maintenance costs.
Capital charges are the largest cost element for all of the processes.
The effect of variations in capital investment declines, however, with
the decline in capital charges with age as the equipment is depreciated.
136
-------
TABLE 43. EFFECT OF COST VARIATIONS AT DIFFERENT POWER UNIT SIZES ON ANNUAL REVENUE REQUIREMENTS
u>
Annual revenue
Cost, % of base value
Soda ash
75%
Base value
125%
150%
Reducing coal
75%
Base value
125%
150%
Operating labor and supervision
Base value
200%
300%
Fuel oil
Base value
150%
200%
250%
Steam
75%
Base
125%
150%
Electricity
75%
Base value
125%
150%
Maintenance
75%
Base value
125%
150%
Capital charges
75%
Base value
125%
150%
Sulfur or sulfuric acid price
50%
Base value
150%
200%
200 MW
8.61
8.72
8.84
8.95
8.59
8.72
8.85
8.98
8.72
9.49
10.25
8.72
8.91
9.10
9.29
-
-
-
-
8.50
8.72
8.95
9.17
8.26
8.72
9.19
9.66
7.62
8.72
9.83
10.94
8.99
8.72
8.46
8.19
ACP
500 MW
16.54
16.82
17.10
17.38
16.50
16.82
17.14
17.45
16.82
17.87
18.92
16.82
17.28
17.74
18.20
-
-
-
-
16.32
16.82
17.32
18.98
15.99
16.82
17.65
18.48
14.66
16.82
18.98
21.13
17.47
16.82
16.17
15.52
Wellman-Lord/sulfuric acid
1000 MW
25.98
26.52
27.05
27.59
25.91
26.52
27.13
27.74
26.52
27.89
29.27
26.52
27.41
28.30
29.19
-
-
-
-
25.58
26.52
27.45
28.39
25.40
26.52
27.63
28.75
23.15
26.52
29.88
33.24
27.78
26.52
25.26
24.00
200 MW
8.67
9.14
9.21
9.27
-
-
-
-
9.14
9.75
10.36
-
-
-
-
8.82
9.14
9.46
9.78
8.89
9.14
9.39
9.64
8.69
9.14
9.59
10.04
7.93
9.14
10.35
11.57
9.61
9.14
8.68
8.22
500 MW
17.73
17.89
18.05
18.22
-
-
-
-
17.89
18.85
19.81
-
-
-
-
17.10
17.89
18.68
19.47
17.32
17.89
18.46
19.03
17.11
17.89
18.68
19.46
15.53
17.89
20.25
22.62
19.20
17.89
16.82
15.82
1000 MW
28.05
28.36
28.68
28.99
-
-
-
-
28.36
29.72
31.08
-
-
-
-
26.84
28.36
29.88
31.41
27.31
28.36
29.42
30.47
27.32
28.36
29.41
30.45
24.70
28.36
32.02
35.68
30.54
28.36
26.19
24.01
requirements, M$
Wellman-Lord/Resox
200 MW
10.49
10.56
10.62
10.69
10.56
10.35
10.76
10.97
10.56
11.17
11.77
-
-
-
-
10.23
10.56
10.88
11.21
10.31
10.56
10.81
11.05
10.08
10.56
11.03
11.51
9.28
10.56
11.84
13.12
10.80
10.56
10.32
10.08
500 MW
20.94
21.11
21.27
21.43
20.60
21.11
21.61
22.12
21.11
22.07
23.03
-
-
-
-
20.31
21.11
21.90
22.69
20.55
21.11
21.67
22.23
20.28
21.11
21.92
22.75
18.63
21.11
23.59
26.07
21.70
21.11
20.52
19.93
1000 MW
33.99
34.30
34.62
34.93
34.30
33.32
35.28
36.26
34.30
35.66
37.02
-
-
-
-
32.77
34.30
35.84
37.37
33.26
34.30
35.35
36.39
33.21
34.30
35.40
36.49
30.46
34.30
38.15
42.00
35.44
34.30
33.16
32.02
Wellman-Lord/Allied
200 MW
10.64
10.70
10.77
10.83
10.63
10.70
10.78
10.85
10.70
11.31
11.92
-
-
-
-
10.38
10.70
11.03
11.35
10.45
10.70
10.95
11.20
10.20
10.70
11.21
11.71
9.35
10.70
12.06
13.41
10.93
10.70
10.47
10.25
500 MW
20.63
20.79
20.95
21.11
20.69
20.79
21.05
21.23
20.79
21.75
22.71
-
-
-
-
19.99
20.79
21.58
22.38
20.23
20.79
21.36
21.93
19.94
20.79
21.63
22.48
18.25
20.79
23.33
25.87
21.35
20.79
20.23
19.67
1000 MW
32.85
33.17
33.48
33.80
32.81
33.17
33.52
33.88
33.17
34.53
35.89
-
-
-
-
31.63
33.17
34.70
36.24
32.11
33.17
34.22
35.28
32.07
33.17
34.26
35.36
29.30
33.17
37.03
40.90
34.24
33.17
32.05
30.98
-------
TABLE 44. EFFECT OF COST VARIATIONS AT DIFFERENT COAL SULFUR
CONTENTS ON ANNUAL REVENUE REQUIREMENTS
OJ
00
Cost, % of base value
Soda ash
75%
Base value
125%
150%
Reducing coal
75%
Base value
125%
150%
Operating labor and supervision
Base value
200%
300%
Fuel oil
Base value
150% (75%)
200% (125%)
250% (150%)
Steam
75%
Base value
125%
150%
Electricity
75%
Base value
125%
150%
Maintenance
75%
Base value
125%
150%
Capital charges
75%
Base value
125%
150%
Sulfur or sulfuric acid price
50%
Base value
150%
200%
2.0% S
11.90
12.03
12.15
12.28
11.88
12.03
12.17
12.32
12.03
13.00
13.97
12.03
12.24
12.45
12.51
-
-
-
-
11.65
12.03
12.40
12.77
11.43
12.03
12.61
13.20
10.45
12.03
13.60
15.18
12.33
12.03
11.73
11.43
ACP
3.5% S
16.54
16.82
17.10
17.38
16.50
16.82
17.14
17.45
16.82
17.87
18.92
16.82
17.28
17.74
18.20
-
-
-
-
16.32
16.82
17.32
18.98
15.99
16.82
17.65
18.48
14.66
16.82
18.98
21.13
17.47
16.82
16.17
15.52
Annual
revenue requirements, M$
Wellman-Lord/sulfuric acid
5.0% S
20.28
20.71
21.13
21.56
25.91
26.52
27.13
27.74
20.71
21.82
22.93
20.71
21.42
22.12
22.83
-
-
-
-
20.07
20.71
21.34
21.97
19.70
20.71
21.71
22.72
18.13
20.71
23.28
25.86
21.71
20.71
19.71
18.70
2.0% S
14.00
14.07
14.15
14.22
-
-
-
-
14.07
14.93
15.79
-
-
-
-
13.59
14.07
14.55
15.02
13.63
14.07
14.56
15.00
13.46
14.07
14.68
15.29
12.20
14.07
15.94
17.81
14.59
14.07
13.55
13.03
3.5% S
17.73
17.89
18.05
18.22
-
-
-
-
17.89
18.85
19.81
-
-
-
-
17.10
17.89
18.68
19.47
17.32
17.89
18.46
19.03
17.11
17.89
18.68
19.46
15.53
17.89
20.25
22.62
19.20
17.89
16.82
15.82
5.0% S
20.97
21.22
21.47
21.72
-
-
-
-
21.22
22.25
23.29
-
-
-
-
20.12
21.22
22.32
23.41
20.53
21.22
21.91
22.60
20.29
21.22
22.15
23.09
18.45
21.22
23.99
26.76
22.95
21.22
19.49
17.76
Wellman-Lord/Resox
2.0% S
15.55
15.63
15.70
15.78
15.40
15.63
15.86
16.09
15.63
16.49
17.35
-
-
-
-
15.15
15.63
16.11
16.59
15.19
15.63
16.07
16.52
15.00
15.63
16.26
16.90
13.69
15.63
17.67
19.51
15.90
15.63
15.35
15.09
3.5% S
20.94
21.11
21.27
21.43
20.60
21.11
21.61
22.12
21.11
22.07
23.03
-
-
-
-
20.31
21.11
21.90
22.69
20.55
21.11
21.67
22.23
20.28
21.11
21.92
22.75
18.63
21.11
23.59
26.07
21.70
21.11
20.52
19.93
5.0% S
25.79
26.04
26.29
26.54
25.27
26.04
26.82
27.60
26.04
27.08
28.11
-
-
-
-
24.94
26.04
27.15
28.26
25.37
26.04
26.72
27.40
25.06
26.04
27.03
28.01
23.11
26.04
28.98
31.91
26.86
26.04
25.04
24.14
Wellman-Lord/Allied
2.0% S
15.65
15.72
15.80
15.87
15.64
15.72
15.80
15.89
15.72
16.57
17.42
-
-
-
-
15.25
15.72
16.19
16.67
15.28
15.72
16.16
16.60
15.07
15.72
16.37
17.02
13.71
15.72
17.73
19.74
15.98
15.72
15.46
15.21
3.5% S
20.63
20.79
20.95
21.11
20.69
20.79
21.05
21.23
20.79
21.75
22.71
-
-
-
-
19.99
20.79
21.58
22.38
20.23
20.79
21.36
21.93
19.94
20.79
21.63
22.48
18.25
20.79
23.33
25.87
21.35
20.79
20.23
19.67
5.0% S
25.02
25.27
25.52
25.77
24.98
25.27
25.55
25.84
25.27
26.30
27.33
-
-
-
-
24.16
25.27
26.38
27.49
24.58
25.27
25.96
26.65
24.27
25.27
26.26
27.26
22.30
25.27
28.24
31.21
26.12
25.27
24.41
23.55
-------
TABLE 45. IMPORTANCE OF ANNUAL REVENUE REQUIREMENT
COST ELEMENTS FOR DIFFERENT POWER PLANT SIZE
AND COAL SULFUR CONTENTS
Percentage of annual revenue requirements
Cost element
Soda ash
200 MW
500 MW
1000 MW
27. sulfur
5% sulfur
Reducing coal
200 MW
500 MW
1000 MW
2% sulfur
5% sulfur
Operating labor and supervision
200 MW
500 MW
1000 MW
27. sulfur
57, sulfur
Fuel oil
200 MW
500 MW
1000 MW
27. sulfur
5% sulfur
Steam
200 MW
500 MW
1000 MW
27. sulfur
5% sulfur
Electricity
200 MW
500 MW
1000 MW
27. sulfur
57. sulfur
Maintenance
200 MW
500 MW
1000 MW
27. sulfur
57. sulfur
Capital charges
200 MW
500 MW
1000 MW
27. sulfur
57. sulfur
Byproduct credit
200 MW
500 MW
1000 MW
2% sulfur
57. sulfur
Wellman-Lord/ Wellman-Lord/
ACP sulfuric acid Resox
5.2
6.6
8.1
4.8
9.4
5.9
7.5
9.2
4.2
8.2
8.7
6.2
5.1
8.0
5.3
4.3
5.4
6.6
3.5
6.8
-
-
-
-
10.0
11.7
13.9
12.0
12.1
22.6
20.8
13.3
20.:
20.5
50.8
51.3
50.7
52.4
49.8
6.1
7.8
9.5
5.0
9.7
2.9
3.6
4.4
2.1
4.7
_
-
_
-
-
6.6
5.3
4.7
6.0
4.8
.
-
-
-
-
13.9
17.4
21.2
13.4
20.4
10.9
12.5
14.7
12.5
12.8
19.6
17.4
14.5
17.2
17.4
53.1
52.8
51.6
53.1
52.3 .
10.1
12.6
15.4
7.4
16.3
2.5
3.0
3.7
1.9
3.8
7.7
9.4
11.2
5.9
12.0
5.7
4.5
3.9
5.4
3.9
_
-
-
-
-
12.2
14.9
17.7
12.1
16.8
9.3
1-0.5
12.0
11.2
10.3
17.9
15.4
12.6
16.0
14.9
48.5
47.0
44.8
49.6
45.0
4.6
5.6
6.7
3.5
7.0
Wellman-Lord/
Allied
2.5
3.1
4.0
1.9
3.8
2.8
3.5
4.2
2.1
6.8
5.6
4.6
4.1
5.4
4.0
_
-
-
-
-
12.0
15.1
18.3
12.0
17.4
9.3
10.8
12.6
11.2
10.8
18.7
16.1
13.1
16.5
15.6
50.6
48.9
46.6
51.2
47.0
4.3
5.4
6.5
3.3
6.8
Basis: New power plants, 3.5% sulfur coal for size variations, 500-MW size for
sulfur variations. Percentages include overheads and marketing expense for oper-
ating labor and supervision, maintenance, and byproduct credit.
139
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Byproduct sales credit is a larger element as a percentage of total
annual revenue requirements for the Wellman-Lord/sulfuric acid process
than for the other processes because of the higher credit for sulfuric
acid, compared with sulfur, combined with the relatively low operating
cost of the process. Byproduct sales credit is a smaller cost element
for the Wellman-Lord/Resox and Wellman-Lord/Allied processes because of
the lower sales credit for sulfur combined with the relatively high
operating costs of the processes. The Wellman-Lord/sulfuric acid process
and the ACP are thus more sensitive, in terms of percentage change, to
variations in byproduct sales credit than the other processes.
In general, no single large cost element unique to a single process
occurs in the annual revenue requirements of the four processes. The
ACP is slightly more sensitive to soda ash cost and the Wellman-Lord/Resox
process is more sensitive to reducing coal (anthracite) cost but the
effects of large cost variations are not severe. Electricity, operating
labor, and maintenance costs are similar for all four processes. Fuel
oil costs for the ACP could become an important cost factor with large
increases in oil costs. A tripling of the 0.40 $/gal price used in this
study, for example, would make fuel oil costs for the ACP roughly equivalent
to the steam costs for the three Wellman-Lord processes. The effect of
changes in capital charges would be about the same for all four processes.
The likelihood of large changes in capital investment, however, can be
considered greater for less developed processes. Thus, the Wellman-
Lord/sulfuric acid process should be less susceptable to annual revenue
requirement variations due to capital charges than the other processes.
The relatively expensive reduction and regeneration portions of the ACP
and the Resox and Allied reduction processes, on the other hand, have
not been commercially demonstrated. Byproduct credits for the Wellman-
Lord/sulfuric acid process are larger, making its annual revenue require-
ments more sensitive to byproduct prices.
ENERGY REQUIREMENTS
The energy requirements of the four processes are shown in Table 46.
The steam and electricity requirements are expressed in terms of the
power plant fuel consumed in producing them. The energy requirements
are for utilities and do not include energy in the reducing coal nor the
energy consumed in production and transportation of raw materials. The
gross energy requirement (the amount of steam, electricity, and fuel
oil required by the process) is reduced by heat credits for steam produced
and used in the processes and, for the Wellman-Lord/Resox process, spent
anthracite sent to the power plant.
The gross energy requirements for the ACP are about one-third those
of the three Wellman-Lord processes, primarily because the ACP does not
require process steam and reheat steam. Process steam constitutes about
one-half and reheat steam an additional one-fifth of the gross energy
requirements of the three Wellman-Lord processes. About 35% of the ACP
gross energy requirements are met by fuel oil, however, compared with
about 5% for the Wellman-Lord/Resox process and 2% for the Wellman-
140
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TABLE 46. ENERGY REQUIREMENTS
Equivalent MBtu/year
Process
ACP
Wellman-Lord/sulfuric acid
Wellman-Lord/Resox
Wellman-Lord/Allied
Reheat
466,100
462,700
460,600
Electricity
611,300
696,300
688,800
698,100
Process steam
1,263,500
1,281,000
1,284,800
Fuel oil
327,500
114,300
61,500
Gross total
938,800
2,425,900
2,546,800
2,505,000
Heat credit
(223,300)
( 53,800)
(565,500)a
( 65,200)
Net total
715,500
2,372,100
1,981,300
2,439,800
Percent of
power unit
input energy
2.27
7.53
6.29
7.75
Basis: Base-case 500-MW power plant. Equivalent energy based on a 90% efficiency for steam generation, 9,000 Btu/kWh for
electricity generation.
a. Includes 35*5,100 MBtu/year for spent anthracite sent to power plant.
-------
Lord/Allied process. The three Wellman-Lord processes are very similar
in gross energy requirement, the major difference being the amount of
fuel oil required. The aet energy requirement for the Wellman-Lord/Resox
process is reduced substantially by the heat credit for spent anthracite.
142
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CONCLUSIONS
The ESP credit and chloride removal costs are the major factors in
the capital investment relationships of the AGP and the Wellman-Lord
processes. The capital cost relativity of the processes depends on both
design and need for particulate and chloride control facilities in
addition to the FGD equipment.
Combining fly ash removal and chloride removal into a single wet-
scrubbing operation in the Wellman-Lord process results in only a
slight increase in capital investment for the scrubber system and,
therefore, a substantial saving in particulate control capital investment.
Among the three Wellman-Lord processes, the cost differences are
the result of the costs of sulfuric acid, Resox, and Allied units. The
changes necessary to accommodate these chemical processing units have
little effect on the total process capital investment.
The capital investments of the Resox and Allied units do not differ
significantly. The Allied unit coal handling and sulfur collection and
handling facilities are more expensive than these areas of the Resox
unit. The Resox reactor area is more expensive than the Allied reactor
area, however. If more complicated coal handling equipment were used
with the Resox unit (to use a coal other than graded anthracite, for
example) its cost could be increased. The same would be true if more
complicated sulfur collection and cleaning equipment were required.
The annual revenue requirements follow the same general relationships
among the processes as the capital investment requirements. This relation-
ship is largely the result of indirect costs related to capital investment.
The AGP is substantially lower in direct costs than the three Wellman-
Lord processes, primarily because it does not require steam. The AGP
has a substantial fuel oil requirement, however; a cost potentially more
sensitive to inflation than the coal-based utility requirements of the
Wellman-Lord processes. Large fuel oil cost increases (from the 0.40
$/gal used in this series of evaluations) would greatly decrease the
utility-cost advantage of the ACP.
There is no significant difference in annual revenue requirements
for the Wellman-Lord process section of the three versions of the Wellman-
Lord process. The cost differences are the result of end plant costs.
The Wellman-Lord/sulfuric acid process has the lowest costs because of
lower raw material, fuel oil, and indirect costs. The Wellman-Lord/Resox
process has slightly higher annual revenue requirements than the Wellman-
Lord/Allied process because of higher reducing coal costs. It also has
143
-------
a higher heat credit, higher byproduct credit, and lower indirect costs
which partially offset the reducing coal costs. The Wellman-Lord/Resox
process is also probably more sensitive to cost variations due to location
because of the geographically limited sources of anthracite.
Increasing power plant size results in a considerable economy of
scale for all of the processes, primarily because of lower labor and
supervision, maintenance, and indirect costs per unit of output at the
larger power plant sizes. The ACP annual revenue requirements increase
more rapidly with increasing coal sulfur content than the other processes
as a result of the higher percentage of its costs directly related to
the quantity of sulfur removed. A similar, less extreme effect is seen
for the Wellman-Lord/Resox process because of the higher raw material
costs.
Energy requirements for the ACP are much lower than those of the
Wellman-Lord processes because it does not require process and reheat
steam. The gross energy requirements of the three Wellman-Lord processes
are similar. The Wellman-Lord/Resox process has lower net energy require-
ments because of a substantial heat credit for spent anthracite.
Considering stage of development as a factor in economic comparison,
the ACP is probably more susceptible to cost changes and the Wellman-
Lord/sulfuric acid process the least. The ACP regeneration system, a
large cost element in the process, has not been demonstrated in utility
FGD applications. The Allied process and the Resox process are in an
early stage of development and may also be considered more susceptible
to cost variations than proven technology such as the Wellman-Lord,
sulfuric acid, and Glaus processes. They represent a smaller portion of
the overall FGD costs than the ACP regeneration area, however. Some
cost advantages of the ACP such as lower energy requirements are unlikely
to be greatly affected by continuing development.
144
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COMPARISON WITH PREVIOUS STUDIES
In the previous studies of this series (Tomlinson et al., 1979;
Anderson et al., 1980) five other processes were evaluated using the
same premises. Three, the limestone, lime, and double-alkali processes,
produce a waste slurry that is disposed of in a pond. In the limestone
process the flue gas is scrubbed with a slurry of ground limestone,
forming calcium-sulfur salts that are discarded by pumping a purge
stream to a disposal pond. The lime process is similar except that a
slurry of lime is used as the scrubbing medium. In the double-alkali
process a solution of sodium sulfite is the scrubbing medium. The spent
solution is regenerated by adding lime, producing calcium-sulfur salts
that are discarded in a disposal pond.
A slurry of magnesium oxide is used as the scrubbing medium in the
magnesia process. The spent slurry is dewatered, dried, and thermally
decomposed to regenerate the magnesium oxide and produce S02 which is
converted to sulfuric acid in a conventional acid plant.
The citrate process is a wet scrubbing process using a sodium
citrate solution as the absorbent. The absorbent is regenerated and the
SOX compounds reduced to elemental sulfur by liquid-phase reduction
using H2S. The t^S is produced by reducing some of the product sulfur
using natural gas.
The base-case costs for each of the nine processes are shown below.
Except for the ACP the costs are more product-controlled than process-
controlled, falling into separate groupings of waste-, acid-, and sulfur-
producing processes in both capital investment and annual revenue require-
ments. The differences in cost between the waste-producing and acid-
producing processes are essentially the costs for absorbent regeneration;
ponding costs and acid plant costs do not differ greatly and raw material
costs do not differ sufficiently to produce large cost differences. The
higher costs for sulfur-producing processes are the result of the added
costs for reduction of sulfur oxides. Here coal reduction holds a
strong advantage over other fossil reducing agents. In the citrate
process, 16% of the annual revenue requirements (1.06 mills/kWh of 6.44
mills/kWh) are for natural gas to produce H2S.
145
-------
Mid-1979 capital Mid-1980 annual revenue
investment, $/kW requirement, mills/kWh
Waste Producing Processes
Limestone 98 4.02
Lime 90 4.25
Double alkali 101 4.19
Sulfuric Acid Processes
Magnesia 132 5.08
Wellman-Lord/sulfuric acid 131 5.11
Sulfur Processes
AGP 119 4.81
Wellman-Lord/Resox 138 6.03
Wellman-Lord/Allied 141 5.94
Citrate 143 6.44
The lower costs for the AGP compared with the other sulfur-producing
processes are largely the result of the combination of fly ash and SOX
particulate matter removal. For the existing plant case variation,
which mainly differs from the base case in having no ESP credit, the AGP
capital investment is 136 $/kW and the annual revenue requirements are
5.42 mills/kWh.
146
-------
RECOMMENDATIONS
The nine processes evaluated in this series of three studies
represent processes of diverse types and widely differing stages of
development. Development and testing of all nine processes is con-
tinuing. As has been demonstrated by comparisons of earlier TVA economic
studies of the same processes with the results of this series, increased
design and operating information has a profound effect on the economics,
both absolute and comparative, of FGD processes. The same effects are
seen from economic and environmental regulation changes. Accurate
economic assessments thus require periodic and thorough reassessment of
both technical and economic data and incorporation of the latest regulatory
restrictions. There is thus a need for periodic economic reevaluation
of FGD processes as well as evaluation of emerging processes. This is
particularly true of the magnesia, ACP, Resox, and Allied processes, all
of which should produce much more extensive information upon which to
base economic evaluations in the near future. Well-developed,waste-
producing processes such as the limestone and double-alkali processes
should also be reassessed not only in respect to technical changes, but
also in view of changing cost patterns in disposal methods. Energy
requirements, both in quantity and type, have also been found to have
increasingly important influences on FGD economics. Assessment of
energy consumption patterns, including types, quantities, and the economic
results of alternate types, should continue to be emphasized in FGD
economic studies.
147
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Protection Agency, Research Triangle Park, N. Car.
152
-------
APPENDIX A
TOTAL CAPITAL INVESTMENT, AVERAGE ANNUAL REVENUE REQUIREMENTS,
AND LIFETIME REVENUE REQUIREMENTS TABLES - ALL PROCESSES AND CASE VARIATIONS
153
-------
TABLE A-l. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW existing)
% of
total direct
Investment, $ ^nvestment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
S02 absorption and removal (two spray dryers, two ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
Reduction (reducers, compressors, reducer-recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Claus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
242,000
2,267,000
4,685,000
4,014,000
1,185,000
2,350,000
1,693,000
379,000
16,815,000
1,009,000
17,824,000
65,000
17,889,000
1,421,000
353,000
2,744,000
859.000
5,377,000
4,653,000
27,919,000
2,785,000
3,350,000
34,054,000
23,000
764,000
34,841,000
1.4
12.7
26.2
22.4
6.6
13.1
9.5
2.1
94.0
5.6
99.6
0.4
100.0
7.9
2.0
15.4
4.8
30.1
26.0
156.1
15.6
18.7
190.4
0.1
4.3
194.8
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
154
-------
TABLE A-2. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW, existing)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
4,550
21,350
37,770
960,000
73,800
28,700
29,282,000
84,900
4,610
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
Unit
cost, $
103.00/ton
25.00/ton
12.50/man-hr
0.40/gal
0.12/kgal
0.92 /kgal
0.031/kWh
2.00/MBtu
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
468
533
6
1,008
472
384
8
26
907
(169
1,427
78
3,135
4,144
,700
,800
,300
,800
,100
,000
,900
,400
,700
,800)
,900
.400
,600
,400
4
5
0
10
4
3
0
0
9
(1
14
0
31
41
.69
.33
.06
.08
.72
.84
.09
.26
.07
.70)
.26
.78
.32
.40
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 sales revenue
Total indirect costs
Gross average annual revenue requirements
2,383,800
2,996,300
989,200
47,200
61,200
6,477,700
10,622;100
23.81
29.93
9.88
0.47
0.62
64.71
105.76
Byproduct Sales Revenue
Elemental sulfur 15,300 tons 40.00/ton (612.000)
Net average annual revenue requirements 10,010,100
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 7.15 15.80
0.75
682
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.
Sulfur removed, 14,680 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $17,889,000; total depreciable investment, $34,054,000; and total
capital investment, $34,841,000.
All tons shown are 2,000 Ib.
155
-------
TABLE A-3
ROCK»ELL INTERNATIONAL CLOSED-LOOP AQUEOUS CARBONATE PROCESS VARIATION FROM BASE CASEI 200 MK EXISTING/ REGULATED co. ECONOMICS
Ui
TOTAL CAPITAL INVESTMENT
34841000
YEARS ANNUAL
AFTER OPERA-
POWER TIONj
UNIT KW-HR/
START KW
I
2
3
4
„ 5
6
7
8
9
1Q
POWER UNIT
HEAT
REQUIREMENT*
MILLION BTU
/YEAR
11 5000 9500000
12 5000 9500000
13 5000 9500000
14 5000 9500000
_15 5uQQ ^ 25QQQQQ .
16 3500
17 3500
18 3500
19 3500
.20 3500__.
21 1500
22 1500
23 15QO
24 1500
.25 150Q__.
26 1500
27 1500
28 1500
29 1500
.30 15QQ__.
6650000
6650000
6650000
6650000
6650020
2850000
2850000
2850000
2850000
2fi5QQUO__.
2850000
2850000
2850000
2850000
28SQQQQ—
PmVER UNIT
FUEL
CONSUMPTION*
TONS COAL
/YEAR
452400
452400
452400
452400
S52SOQ...
316700
316700
316700
316700
. 316200
135700
135700
135700
135700
125200...
135700
1357QO
1357QO
135700
1352QQ
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
BY-PRODUCT
RATE/
EQUIVALENT
TONS/YEAR
ELEMENTAL
SULFUR
NET REVENUE/
*/TON
ELEMENTAL
SULFUR
TOTAL
OP. COST
INCLUDING
REGULATED
RDI FOR
POKER
COMPANY,
*/YEAR
TOTAL
NET
SALES
REVENUE/
t/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER/
t
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POKER/
*
10500 10900 36,00 12963600 392400 12971200 12571200
10500 10900 36.00 12670700 392400 12278300 24849900
10500 10900 36,00 12377800 392400 11985400 36834900
10500 10900 36.00 12065000 3924QO 11692600 48527900
1Q50Q 1QSQO 3fi»UQ 11222100 322&OQ_.._113!S2QQ SSS222QO
7300 7700 36.00 10568300 277200 10291100 70218300
7300 7700 30,00 10275500 277200 9998300 80216600
7300 7700 3c,00 9982600 277200 9705400 89922000
7300 7700 36,00 9689700 277200 9412500 99334900
2300 22QQ 36*00 2336200 2ZZ2QQ 2113200 108136200
3100 3300 36.00 7704200 118800 7585400 116039600
3100 3300 36,00 7411300 118800 7292500 1233321QO
3100 3300 36,00 7118500 118800 6999700 130331800
3100 3300 36.00 6825600 118800 6706800 13703B6QO
3100 3300 36»QQ 6532800 llflUOQ 641400Q 1434526QO
3100 3300 36,00 6239900 118800 6121100 149573700
3100 3300 36,00 5947000 118800 5828200 155401900
3100 3300 36,00 5654200 118800 5535400 160937300
3100 3300 36.00 5361300 118800 5242500 166179800
3100 3300 36*00 5068400 118800— ___4SSS6QQ 121123400
TOT 57500 109250000 5202500 120000 126000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
HILLS PER KILONATT-H3UR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11,6* TO INITIAL YEAR/ DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
HOLLARS PER TON OF COAL BURNED
HILLS PER KILQ'MTT-HQUR
CENTS PER MILLION BTU NEAT INPUT
COLLARS PER TON OF SULFUR REMOVED
175665400 4536000 171129400
33,77 0.88 32.89
15,26 0,40 14,88
160,79 4,15 156.64
1463,88 37.80 1426,08
79166800 2239400 76927400
PROCESS COST OVER LIFE OF POWER UNIT
30,76 0.87 29,89
13,92 0,40 13.52
146,51 4.15 142.36
1330.53 37,63 1292.90
-------
TABLE A-4. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW new)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
Fly ash collection (two cyclone dust collectors)
S02 absorption and removal (two spray dryers, two ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
ESP credit
Reduction (reducers, compressors, reducer- recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Claus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
•
Total process area 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
237,000
2,217,000
209,000
4,578,000
(2,110,000)
3,925,000
1,160,000
2,299,000
1,656,000
370,000
14,541,000
872,000
15,413,000
63,000
15,476,000
1,418,000
353,000
2,433,000
770,000
4,974,000
4,090,000
24,540,000
2,448,000
2,945,000
29,933,000
23,000
714,000
30,670,000
1.5
14.3
1.4
29.5
(13.6)
25.4
7.5
14.9
10.7
2.4
94.0
5.6
99.6
0.4
100.0
9.2
2.3
15.7
5.0
32.2
26.4
158.6
15.8
19.0
193.4
0.1
4.6
198.1
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
157
-------
TABLE A-5. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW)
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Total conversion costs
Total direct costs
Annual
quantity
4,410 tons
20,680 tons
37,770 man-hr
930,000 gal
71,500 kgal
27,800 kgal
28,379,000 kWh
82,200 MBtu
4,610 man-hr
Unit
cost, $
103.00/ton
25.00/ton
12.50/man-hr
0.40/gal
0.12/kgal
0.92/kgal
0.031/kWh
2.00/MBtu
17. 00 /man-hr
Total % of average
annual annual revenue
cost, $ requirements
454,200
517,000
6,100
977,300
472,100
372,000
8,600
25,600
879,700
(164,400)
1,234,900
78.400
2,906,900
3,884,200
5.21
5.93
0.07
11.21
5.41
4.26
0.10
0.29
10.08
(1.88)
14.15
0.90
33.31
44.52
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
1,796,000
2,637,600
892,700
47,200
59,300
5,432,800
9,317,000
20.59
30.23
10.23
0.54
0.68
62.27
106.79
Byproduct Sales Revenue
Elemental sulfur 14,820 tons 40.00/ton (592,800)
Net average annual revenue requirements 8,724,200
(6.79)
100.00
$/ton coal $/MBtu heat $/ton
Mills/kWh burned Input S removed
Equivalent unit revenue requirements 6.23 14.23
0.68
614
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.
Sulfur removed, 14,220 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $15,476,000; total depreciable investment, $29,933,000; and total
capital investment, $30,670,000.
All tons shown are 2,000 Ib.
158
-------
Ui
TABLE A-6
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUtOUS CARBONATE PROCESS VARIATION FROM BASE CASE: 200 MW,REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT
30670000
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KW-HR/
START K»
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
Ifl ?POQ
11 5000
12 5000
13 5000
1* 5000
15 5000
16 3500
17 3500
18 3500
19 3500
po 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
^0 1500
TOT 127500
LIFETIME
PROCESS COST
LEVELI2ED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE? REGULATED TOTAL
HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR NET
REQUIREMENT, CONSUMPTION, CONTROL POWER SALES
MILLION BTU TONS COAL PROCESS, ELEMENTAL ELEMENTAL COMPANY, REVENUE,
/YEAR /YEAR TONS/YEAR SULFUR SULFUR I/YEAR S/YEAR
12880000 613300 14200
12880000 613300 14200
12880000 613300 14200
12680000 613300 14200
12880000 613300 14200
12880000 613300 14200
12B80000 613300 14200
12880000 613300 14200
12880000 613300 14200
1288000fl 613300 14204
9200090 438100 10200
9200000 438100 10200
9200000 438100 10200
9200000 438100 10200
9200000 438100 10200
6440000 306700 7100
6440000 306700 7100
6440000 306700 7100
6440000 306700 7100
6444000 306700 7104
2760000 131400 3000
2760000 131400 3000
2760000 131400 3000
2760000 131400 3000
2760000 J31400 30Q4
2760000 131400 3000
2760000 131400 3000
2760000 131400 JOOO
2760000 131400 3000
2760000 131400 3000
14800
14800
14800
14800
14800
14800
14800
14800
14800
14800
10600
10600
10600
10600
10600
7400
7400
7400
7400
7400
3200
3200
3200
3200
3200
3200
3200
3200
3200
3200
234600000 11171000 258500 270000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
COLLARS HER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HtAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
34*44
36.00
36.00
36.00
36.00
36.00
TO OISCOUNTED
11895400
11733800
11552200
11380600
11209000
11037300
10865700
10694100
10522500
10350800
9090600
8919000
8747400
8575800
8404104
7361500
7189900
7018300
6846700
6675000
5198600
5027000
4855400
4683700
4512100
4340500
4168900
3997300
3825600
365>QOO
234322800
20.98
9.19
99.88
906.47
83319300
PROCESS COST OVER
19.13
8.36
91.11
826.58
532800
532800
532BOO
532800
532800
532800
532800
532800
532800
532800
381600
381600
381600
381600
381600
266400
266400
266400
266400
266400
115200
115200
115200
115200
J1S200
115200
115200
115200
115200
J15200
9720000
0.87
0.38
4.14
37.60
3784600
LIFE OF
0.86
0.38
4.13
37.55
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
j s
11362600
11191000
11019400
10847800
10676200
10504500
10332900
10161300
9989700
9818004
8709000
8537400
8365600
6194200
8022500
7095100
6923500
6751900
6580300
6408600
5083400
4911800
4740200
4568500
4396900
4225300
4053700
3882100
3710400
3538800
224602800
20.11
8.81
95.74
668.87
79534700
POWER UNIT
18.27
8.00
86.98
789.03
11362600
22553600
33573000
44420800
55097000
65601500
75934400
86095700
96085400
105903440
114612400
123149800
131515600
139709800
147732300
154827400
161750900
166502800
175083100
181491700
166575100
191486900
196227100
200795600
2Q5i?25go
209417600
213471500
217353600
221064000
224602800
-------
TABLE A-7. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500 MW existing)
.% of
total direct
Investment, $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
Reduction (reducers, compressors, reducer-recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Claus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
414,000
5,160,000
10,828,000
7,523,000
2,125,000
4,361,000
3,091,000
696,000
34,198,000
2,052,000
36,250,000
157,000
36,407,000
2,173,000
540,000
4,950,000
1,475,000
9,138,000
9,109,000
54,654,000
5,450,000
6,558,000
66,662,000
59,000
1,528,000
68,249,000
1.1
14.2
29.8
20.7
5.8
12.0
8.5
1.9
94.0
5.6
99.6
0.4
100.0
6.0
1.5
13.6
4.0
25.1
25.0
150.1
15.0
18.1
183.2
0.2
4.2
187.6
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
160
-------
TABLE A-8. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500 MW, existing)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
11
51
52
2,325
178
69
70,043
205
8
,020
,700
,000
,000
,800
,500
,000
,500
,760
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
Unit
cost, $
103.
,00/ton
25.00/ton
12.
0.
0.
0.
0
2,
17
.50 /man-hr
.40/gal
,12/kgal
,92/kgal
,029/kWh
,00/MBtu
.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,135
1,292
15
2,442
650
930
21
63
2,031
(411
2,542
148
5,976
8,419
,100
,500
,300
,900
,000
,000
,500
,900
,200
,000)
,200
.900
,700
,600
5
6
0
12
3
4
0
0
10
(2
13
0
31
44
.99
.82
.08
.89
.43
.91
.11
.34
.72
.17)
.41
.78
.53
.41
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
4,266,400
5,869,400
1,670,600
65,000
148,200
12,019,600
20,439,200
22.51
30.96
8.81
0.34
0.78
63.40
107.82
Byproduct Sales Revenue
Elemental sulfur 37,050 tons 40.00/ton (1,482,000) (7.82)
Net average annual revenue requirements 18,957,200 100.00
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 5.42 12.36 0.59
533
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.
Sulfur removed, 35,550 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,407,000; total depreciable investment, $66,662,000; and total
capital investment, $68,249,000.
All tons shown are 2,000 Ib.
161
-------
TABLE A-9
S3
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUEOJS CARBONATE PROCESS VARIATION FROM BASE CASES soo
TOTAL CAPITAL INVESTMENT 682*9000
EXISTING* REGULATED co, ECONOMICS
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
ANNUAL
OPERA-
TION,
KW-HR/
KH
6 7000
7 7000
a 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 ISOO
24 1500
.25 1500—
26 1500
27 1500
28 1500
29 1500
.30 1500— ,
POWER UNIT
HEAT
REQUIREMENT,
MILLION BTU
/YEAR
32200000
32200000
32200000
32200000
-.32200000— •
23000000
23000000
23000000
23000000
.230QQQQO
16100000
16100000
16100000
16100000
161000.20...
6900000
6900000
6900000
6900000
62QflQQQ...
6900000
6900000
6900000
6900000
POWER OMIT
FUEL
CONSUMPTION,
TONS COAL
/YEAR
1533300
1533300
1533300
15333QO
1533300—
1095200
1095200
1095200
1095200
. — 1Q252QQ
766700
766700
766700
766700
2662QQ— .
328600
328600
3286QO
328600
328600...
328600
328600
328600
328600
32B6QQ...
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
35600
35600
35600
356QO
..31600...
25400
25400
25400
25400
25400
17800
17800
17800
17800
12BQO
7600
7600
7600
7600
260Q
7600
7600
7600
7600
IbOO—
BY-PRODUCT
RATE,
EQUIVALENT NET REVENUE,
TONS/YEAR »/TOH
ELEMENTAL ELEMENTAL
SULFUR SULFUR
37100
37100
37100
37100
321QQ
26500
26500
26500
26500
2&5QQ
18500
18500
18500
18500
1B5QQ
7900
7900
7900
7900
22QQ
7900
7900
7900
7900
2200
36,00
30,00
36,00
3l>. 00
36,00
36,00
3t>,00
36,00
36»QQ
36,00
36,00
36.00
36.00
36.00
36,00
30,00
36,00
36«ttQ
36,00
36,00
36,00
36.00
TOTAL
OP, COST
INCLUDING
REGULATED
ROI FOR
POWER
C&MPANY,
t/YEAR
TOTAL
NET
SALES
REVENUE,
t/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POKER,
t
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
26655656 1335666 25269400 2S269500
26146400 13356QO 24810800 5008Q200
256878QO 13356QO 24352200 74432400
25229100 13356QO 23893500 98325900
24220500 1335600 23434200 1212608QO
21939000 954000 20985000 142745800
21480400 954000 20526400 163272200
21021800 954000 20067800 183340000
2C563100 954000 19609100 202949100
2C1045QO S54QQQ 1215Q5QQ 222022600
17765700 666000 17099700 239199300
17307100 666000 16641100 255840400
16848500 666000 16182500 272022900
16389800 666000 15723800 287746700
15231200 666QQQ 152652QQ 3Q3011SOO
12701100 284400 12416700 315428600
12242400 284400 11958000 327386600
11783800 284400 11499400 338886000
11325100 284400 11040700 349926700
10866500 2844QQ..— 1Q5821QQ 36Q5Q8BQO
10407900 284400 10123500 370632300
9949200 284400 9664800 380297100
949C600 284400 9206200 389503300
9032000 284400 8747600 398250900
8523300 284400 6238200 406533800
TOT 92500 4Z5500000 20262000 470000 489500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF C3AL BURNED
MILLS PER KILOWATT-H3JR
CENTS PER MILLION BTJ HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6S TO INITIAL YEAR, DOLLARS
424161800 17622000 40&539800
20,93
9.17
99,69
902,47
171131400
0,87
0.38
4,15
37.49
7993100
L6VELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TON OF COAL BURNED 18,64 0,87
MILLS PER KILOWATT-HOUR 8,17 0.39
CENTS PER MILLION BTU HEAT INPUT 88.76 4.15
OQLLARS PER TON OF SULFUR REMOVED 803.06 37.51
20,06
8,79
95,54
864,98
163138300
PHWER UNIT
17,77
7,78
84,61
765,55
-------
TABLE A-10. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2.0% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
Fly ash collection (four cyclone dust collectors)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
ESP credit
Reduction (reducers, compressors, reducer- recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
filter, heat exchangers, compressor, and pumps)
Sulfur production (Glaus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
255,000
5,084,000
490,000
10,647,000
(5,885,000)
4,265,000
1,254,000
2,497,000
1,797,000
401,000
20,805,000
1,248,000
22,053,000
154,000
22,207,000
2,082,000
518,000
3,287,000
1,013,000
6,900,000
5,821,000
34,928,000
3,477,000
4,191,000
42,596,000
64,000
923,000
43,583,000
1.1
22.9
2.2
47.9
(26.4)
19.3
5.6
11.2
8.1
1.8
93.7
5.6
99.3
0.7
100.0
9.4
2.3
14.8
4.6
31.1
26.2
157.3
15.7
18.8
191.8
0.3
4.2
196.3
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
163
-------
TABLE A-ll. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
4
23
47
1,046
80
31
50,633
92
7
,960
,270
,970
,000
,500
,300
,200
,500
,850
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
103
25
12
0
0
0
0
2
17
Unit
cost, $
.00/ton
.00/ton
. 50/man-hr
.40/gal
.12/kgal
.92/kgal
.029/kWh
.00/MBtu
.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
510
581
6
1,099
599
418
9
28
1,468
(185
1,548
133
4,021
5,121
,900
,800
,900
,600
,600
,400
,700
,800
,400
,000)
,300
,500
,700
,300
4
4
0
9
4
3
0
0
12
(1
12
1
33
42
.24
.84
.06
.14
.99
.48
.08
.24
.21
.54)
.87
.11
.44
.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
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
2,555,800
3,748,200
1,140,700
60,000
66.700
7,571,400
12,692,700
21.25
31.17
9.49
0.50
0.55
62.96
105.54
Byproduct Sales Revenue
Elemental sulfur 16,670 tons 40.00/ton (666,800)
Net average annual revenue requirements 12,025,900
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 3.44
0.38
752
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.
Sulfur removed, 16,000 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,207,000; total depreciable investment, $42,596,000; and total
capital investment, $43,583,000.
All tons shown are 2,000 Ib.
164
-------
Ul
TABLE A-12
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUEOUS CARHONAlE PROCESS VARIATION FROM cASE CASE: 2.0* S COAL, REGULATED CO. ECONOMICS
TOTAL CAPITAL iNVEbTMtNT 43583000
YEARS ANNUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START K»
1 7000
iL 700(1
J 7000
4 7000
b 7QQO
6 7000
7 7000
8 7000
9 7000
1J| ZJLOJL-
11 5000
12 5000
13 5000
14 5000
Jb 5000
16 3500
17 3bOO
IB 3500
19 3500
£Jl_ _35J1J1
21 1500
22 1500
23 1500
24 1500
25 15QO
26 1500
27 1500
26 1500
29 1500
J3.fi _15ji.B
TOT 127500
LIFETIME
PROCESS CUST
LEVELIZEU
SULFUR HY-PRUOUCT
REMOVELl Hftft.
POrfER UNIT POWER UNIT bY EQUIVALENT NET REVENUE,
HEAT FUEL POLLUTION TONb/YEAR S/TON
REQUIREMENT. CONSUMPTION. CONTROL
MILLION HTU TONS COAL PROCESS. ELEMENTAL ELEMENTAL
/YEAR /YEAR TONS/YEAR SULFUR SULFUR
31bUOOUO 150000U 16000
31500000 1500000 16000
31500000 1500000 16000
3150UOOO 1500000 16000
3ibOi)goQ 1500000 . ._I£IKUI
31500000 1500000 IbOOO
3150UOOO 1500000 16000
31bUOOOO 1500000 16000
31300000 1500000 16000
31500000 1500000 l&OOil
22500000 1071400 1140U
22500000 1071400 11400
22500000 1071400 1140U
22500000 1071400 1140U
22bOi)QOQ 10214QQ 1140.U
15750000 750000 8000
15750000 750000 8000
15750000 750000 bOOO
15750000 750000 8000
15.75.00.00 15j)(|QO bOQil
6750000 321400 J400
67bOOOO 321400 340U
67SUOOO 321400 J400
67bOOOO 321400 3400
6750000 321400 3400
6750000 321400 340U
6750000 321400 3400
6750000 321400 3400
6750000 321400 3400
6750000 321400 340il
16700
16700
16700
16700
—ifeiiU!
16700
16700
16700
16700
167CO
11900
11900
11900
11^00
ilSJUL
H300
d300
d300
H300
a3J2JL
3600
3600
3600
3600
3600
3600
3600
3600
3600
3600
5f37bOOOO 27321000 291000 304000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOHATT-HOUR
CENTS PER MILLION BTU HEAT 1NHUI
UOLLAnS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR, OOLLARb
INCREAbt (DECREASE) IN UM 1 OPERATING COST EUUIVALENT
DOLLARS PER TON OF COAL dURNEU
MILLS PER KILOKATT-hOUR
CENTS PER MILLION HTU HEAT INPUT
UCLLAHS PER TON OF SULFUR REMOVED
36.00
36.00
36.00
36.00
36jii!
36.00
36.00
36.00
36.00
J6«8fl
36.00
36.00
36.00
3b.OO
36.00
36.00
36.00
36.00
36.00
36J.QJJ
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36_,0_0
TOTAL
OP. COST
INCLUDING
REGULATED
RUI FOR
POWER
COMPANY,
S/YEAR
16374200
16130000
15885700
15641500
15397300
15153100
14908800
14664600
14420400
J417620J)
12490100
1P245900
12001700
11757500
11513300
10119400
9875200
9631000
9386800
914250J
7185100
6940900
6696700
6452500
6208200
5964000
5719800
5475600
5231300
4987100
TOTAL
NET
SALES
REVENUE,
S/YEAR
601200
601200
601200
601200
_6J!li2JJ
601200
601200
601200
601200
$91200
428400
428400
428400
428400
*2$*$9
298800
298800
298800
298800
£98800
129600
129600
129600
129600
129600
129600
129600
129600
129600
129600
321776400 1094*000
11.78 0.40
5.05 0.17
56.08 1.90
1105.76 37.61
114459300 4266300
TO DISCOUNTED PROCESS COST OVER LIFE OF
10.75 0.40
4.61 0.16
51.18 1.91
1008.45 37.59
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER.
S $
15773000
15528800
15284500
15040300
14796100
14551900
14307600
14063400
13819200
13575000
12061700
11817500
11573300
11329100
11084900
9820600
9576400
9332200
9088000
88437SO
7055500
6811300
6567100
6322900
6078600
5834400
5590200
5346000
5101700
48575QO
310832400
11.38
4.88
54.18
1068.15
110193000
POWER UNIT
10.35
4.43
49.27
970.86
15773000
31301800
46586300
61626600
764227QO
90974600
105282200
119345600
133164800
14673?800
158801500
170619000
182192300
193521400
2J!4.£0.63_0.0
214426900
224003300
233335500
242423500
251267200
258322700
265134000
271701100
278024000
284102600
289937000
295527200
300873200
305974900
310832400
-------
TABLE A-13. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.57. sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
Fly ash collection (four cyclone dust collectors)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
ESP credit
Reduction (reducers, compressors, reducer- recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Glaus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
409,000
5,084,000
490,000
10,647,000
(4,713,000)
7,405,000
2,094,000
4,297,000
3,045,000
686,000
29,444,000
1,767,000
31,211,000
154,000
31,365,000
2,170,000
539,000
4,375,000
1,317,000
8,401,000
7,953,000
47,719,000
4,757,000
5,726,000
58,202,000
64,000
1,436,000
59,702,000
1.3
16.2
1.6
33.9
(15.0)
23.6
6.7
13.7
9.7
2.2
93.9
5.6
99.5
0.5
100.0
6.9
1.7
14.0
4.2
26.8
25.3
152.1
15.2
18.3
185.6
0.2
4.6
190.4
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
166
-------
TABLE A-14. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
10
50
52
2,274
174
68
67,920
201
8
,780
,580
,000
,000
,900
,000
,000
,000
,760
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
103
25
12
0
0
0
0
2
17
Unit
cost, $
.00/ton
.00/ton
.50 /man-hr
.40 /gal
.12/kgal
.92/kgal
.029/kWh
.00/MBtu
.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,110
1,264
15
2,389
650
909
21
62
1,969
(402
2,189
148
5,549
7,939
,300
,500
,000
,800
,000
,600
,000
,600
,700
,000)
,400
,900
,200
,000
6.
7,
0,
14,
3.
5,
0.
0,
11.
(2,
13.
0,
32,
47,
,60
.52
.09
.21
,86
.41
,12
.37
,71
.39)
,02
.89
.99
.20
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
3,492,100
5,134,400
1,494,200
65,000
145,000
10,330,700
18,269,700
20.76
30.53
0.39
0.86
61.42
108.62
Byproduct Sales Revenue
Elemental sulfur 36,240 tons 40.00/ton (1,449,600) (8.62)
Net average annual revenue requirements 16,820,100 100.00
Equivalent unit revenue requirements
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.81 11.21 0.53 484
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.
Sulfur removed, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $31,365,000; total depreciable investment, $58,202,000; and total
capital investment, $59,702,000.
All tons shown are 2,000 Ib.
167
-------
CO
TABLE A-15
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUEOUS CARBONATE PROCESS BASE CASE:500 MW. 3.5« S COAL, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 59702000
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
6 7000
9 7000
10 7000
11 5000
12 6000
13 5000
14 5000
' J5 §pOp
16 3500
17 3500
16 3500
19 3500
?fl 3500
21 1500
22 1500
23 1500
24 1500
25 J500
26 1500
27 1500
26 1500
29 1500
30 1500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE* REGULATED
HEAT FUEL POLLUTION TONS/YEAR i/TON ROI FOR
REQUIREMENT. CONSUMPTION. CONTROL POWER
MILLION BTU TONS COAL PROCESS. ELEMENTAL ELEMENTAL COMPANY.
/YEAR /YEAR TONS/YEAH SULFUR SULFUR S/YEAR
31500000 1500000 34800
31500000 1500000 34600
31500000 1500000 34UOU
31500000 1500000 34600
31500000 1500000 34600
31500000 1500000 34800
31500000 1500000 34800
31500000 1500000 34800
31500000 1500000 34800
31500000 1500000 34800
22500000 1071400 24800
22500000 1071400 24800
22500000 1071400 24800
22500000 1071400 24800
22500000 1071400 24800
15750000 750000 17400
15750000 750000 17400
15750000 750000 17400
15750000 750000 17400
15750000 750000 174011
6750000 321400 7500
6750000 321400 7500
6750000 321400 7500
6750000 321400 7500
6750000 321400 75Q4
6750000 321400 7500
6750000 321400 7500
6750000 321400 7500
6750000 321400 7500
6750000 321400 75.0.4
36200
36200
36200
36200
36200
36200
36200
36200
36200
36200
25900
25900
25900
25900
25900
18100
18100
18100
18100
18100
7800
7800
7800
7800
7800
7800
7800
7800
7800
_7800
573750000 27321000 634000 660000
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 11.6* 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
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.0(1
36.00
36.00
36.00
36.00
3d. 00
36.00
36.00
36.00
36.00
36_.00
36.00
36.00
36.00
36.00
3.6. Q9
TO DISCOUNTED
23259200
22925500
22591t)OU
22258200
21924500
21590800
21257100
20923400
20589700
£Q^560QO
17682600
17348900
17015200
16681500
1634780!)
14244900
13911200
13577500
13243800
12910100
9980500
9646800
931310U
8979400
8645704
8312000
7978300
7644600
7310900
6977204
TOTAL
NET
SALES
REVENUE.
J/YEAR
1303200
1303200
1303200
1303200
1303200
1303200
1303200
1303200
1303200
1303200
932400
932400
932400
932400
932400
651600
651600
651600
651600
651600
280800
280800
280800
280800
280800
280800
280800
280800
280800
280800
455328200 23760000
16.67 0.87
7.14 0.37
79.36 4.14
718.18 37.47
162629800 9255200
PROCESS COST OVER LIFE OF
15.27 0.87
6.54 0.37
72.72 4.14
658.42 37.47
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
21956000
21622300
21288600
20955000
206213QO
20287600
19953900
19620200
19286500
189528J) 0
16750200
16416500
16082800
15749100
15415400
13593300
13259600
12925900
12592200
12258500
9699700
9366000
9032300
8698600
8364900
8031200
7697500
7363800
7030100
66964QO
431568200
15.80
6.77
75.22
680.71
153374600
POWER UNIT
14.40
6.17
68.58
620.95
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
21956000
43578300
64866900
85821900
106443200
126730800
146664700
166304900
185591400
204544200
221294400
237710900
253793700
269542800
28.4959200
298551500
311811100
324737000
337329200
349587740
359287400
368653400
377685700
386364300
394749200
402780400
410477900
417841700
424871800
431568200
-------
TABLE A-16. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5.0% sulfur)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
Fly ash collection (four cyclone dust collectors)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
ESP credit
Reduction (reducers, compressors, reducer-recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Glaus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
532,000
5,084,000
490,000
10,647,000
(4,713,000)
10,056,000
2,783,000
5,810,000
4,080,000
923,000
35,692,000
2,142,000
37,834,000
154,000
37,988,000
2,242,000
557,000
5,128,000
1,523,000
9,450,000
9,488,000
56,926,000
5,677,000
6,831,000
69,434,000
64,000
1,912,000
71,410,000
1
13
1
28
(12
26
7
15
10
2
94
5
99
0
100
5
1
13
4
24
25
149
14
18
182
0
5
188
.4
.4
.3
.0
.4)
.5
.3
.4
.7
.4
.0
.6
.6
.4
.0
.9
.5
.5
.0
.9
.0
.9
.9
.0
.8
.2
.0
.0
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
169
-------
TABLE A-17. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
16
77
54
3,498
269
104
86,377
309
9
,580
,790-
,870
,000
,000
,600
,000
,200
,410
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
Unit
cost, $
103
25
12.
0
0
0
0
2
17
.00/ton
.00/ton
. 50/man-hr
.40/gal
.12/kgal
.92/kgal
.029/kWh
.00/MBtu
.00 /man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,707
1,944
2J3
3f -J 17
,D / D
685
1,399
32
96
2,504
(618
2,653
160
6,913
10.S8R
,700
,800
,100
Ann
,OUU
,900
,200
,300
,200
,900
,400)
,000
,000
,100
.700
8.
9.
0.
17 .
3.
6.
0,
0,
12,
(2.
12,
0,
33
51
.25
,39
,11
, 75
.31
.76
.16
.46
.10
.99)
.81
.77
.38
.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
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
4,166,000
6,141,300
1,749,500
68,600
223,000
12,348,400
22,937,100
20.12
29.66
8.45
0.33
1.08
59.64
110.77
Byproduct Sales Revenue
Elemental sulfur 55,740 tons 40.00/ton (2,229,600)
Net average annual revenue requirements 20,707,500
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 5.92 13.80
0.66
387
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.
Sulfur removed, 53,500 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $37,988,000; total depreciable investment, $69,434,000; and total
capital investment, $71,410,000.
All tons shown are 2,000 Ib.
170
-------
TABLE A-18
ROCKWELL INTERNATIONAL CLUSED-LOOP AQUEOUS CARBONATE PROCESS VARIATION FROM BASE CASE: 5.0% S COAL. REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 71410000
YEARS ANNUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START KW
1
2
3
4
6
7
8
9
11
12
13
14
16
17
18
19
yn
21
22
23
24
-25
26
27
28
29
7000
7000
7000
7000
7000
7000
7000
7000
7000
7QQQ
5000
5000
5000
5000
5QQP
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1BOO
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED
HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
REQUIREMENT, CONSUMPTION. CONTROL POWER
MILLION 6TU TONS CO«L PROCESS. ELEMENTAL ELEMENTAL COMPANY.
/YEAR /YEAR TONS/YEAH SULFUR SULFUR S/YEAR
31500000 1500000 53500
31500000 1500000 53500
31500000 150000U 53500
31500000 1500000 53500
3J5J)AOOJ) 1500000 53500
31500000 1500000 53500
31500000 1500000 53500
31500000 1500000 53500
31500000 1500000 5J500
31500000 1500000 53500
22500000 1071400 38200
22500000 1071400 38200
22500000 1071400 38200
22500000 1071400 38200
22500000 1071400 38200
15750000 750000 26800
15750000 750000 26800
15750000 750000 ' 26800
15750000 750000 26800
15750000 75501° 26804J
6750000 321400 11500
6750000 321400 11500
6750000 321400 11500
6750000 321400 11500
6750000 321*80 11500
6750000 321400 11500
6750000 321400 11500
6750000 321400 11500
6750000 321400 11500
6750000 321400 1150_U
55700
55700
55700
55700
b5700
55700
55700
55700
55700
55700
39800
39800
39800
39800
39800
27900
27900
27900
27900
27900
11900
11900
11900
11900
11900
11900
11900
11900
11900
11900
573750000 27321000 975000 1014500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWJTT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAH. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 3TU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36. OQ
36.00
36.00
36.00
36.00
36.00
TO DISCOUNTED
28855600
28457500
28059400
27661300
27263200
26865200
26467100
26069000
25670900
25272800
21883000
21484900
21086800
20688700
20290600
17543900
17145800
16747700
16349600
15951500
12144800
11746700
11348700
10950600
10552500
10154400
9756300
9358200
8960100
8562000
TOTAL
NET
SALES
REVENUE.
S/YEAR
2005200
2005200
2005200
2005200
2005200
2005200
2005200
2005200
2005200
2905200
1432800
1432800
1432800
1432800
1432800
1004400
1004400
1004400
1004400
1004400
428400
428400
428400
428400
428400
428400
428400
428400
428400
563348800 36522000
20.62 1.34
8.84 0.58
98.19 6.37
577.79 37.45
201873100 14237500
PROCESS COST OVER LIFE OF
18.96 1.34
8.12 0.57
90.27 6.37
531.38 37.47
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER. POWER.
S S
26850400
26452300
26054200
25656100
25258000 ..
24860000
24461900
24063800
23665700
,. 23277600
20450200
20052100
19654000
19255900
18857800
16539500
16141400
15743300
15345200
14947100
11716400
11318300
10920300
10522200
10124100
9726000
9327900
8929800
8531700
8133600
526826800
19.28
8.26
91.82
540.34
187635600
POWER UNIT
17.62
7.55
83.90
493.91
26850400
53302700
79356900
105013000
. 13 02 JIM 0
155131000
179592900
203656700
227322400
--250.5900.flO
271040200
291092300
310746300
330002200
365399500
381540900
397284200
412629400
427576500
439292900
450611200
461531500
472053700
4$?177800
491903800
501231700
510161500
518693200
52692MOO
-------
TABLE A-19. AQUEOtfS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
Reduction (reducers, compressors, reducer-recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Glaus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
8
17
12
3
6
4
1
55
3
58
58
3
7
2
14
14
87
8
10
106
2
109
624
,145
,908
,115
,309
,983
,878
,107
,069
,304
,373
308
,681
,704
921
,358
,120
,103
,557
,341
,703
,481
,885
105
,573
,563
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
1
13
30
20
5
11
8
1
93
5
99
0
100
6
1
12
3
24
24
148
14
17
181
0
4
186
.1
.9
.5
.7
.6
.9
.3
.9
.9
.6
.5
.5
.0
.3
.6
.5
.6
.0
.8
.8
.8
.9
.5
.2
.4
.1
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
172
-------
TABLE A-20. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW existing)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
21
101
68
4,548
349
136
136,469
402
14
,560
,150
,000
,000
,800
,000
,000
,100
,230
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
sian-hr
103
25
12
0
0
0
0
2
17
Unit
cost, $
.00 /ton
.00 /ton
,50/man-hr
.40/gal
.12/kgal
.92/kgal
.028/kWh
.00/MBtu
,00/man-br
Total 7, of average
annual annual revenue
cost, $ requirements
2
2
4
1
3
3
9
14
,220
,528
30
,779
850
,819
42
125
,821
(804
,511
241
,606
,386
,700
,800
.000
,500
,000
,200
,000
,100
,100
,200)
,600
,900
,700
,200
7
8
0
15
2
5
0
0
12
(2
11
0
31
47
.30
.31
.10
.71
.79
.98
.14
.41
.56
.64)
.54
.79
.57
.28
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
6,840,600
9,422,400
2,301,800
85,000
289,900
18,939,700
33,325,900
22.48
30.97
7.57
0.28
0.95
62.25
109.53
Byproduct Sales Revenue
Elemental sulfur 72,480 tons 40.00/ton (2,899,200)
Net average annual revenue requirements 30,426,700
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 4.35 10.14 0.48 437
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.
Sulfur removed, 69,560 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded
Total direct investment, $58,681,000; total depreciable investment, $106,885,000- and total
capital investment, $109,563,000.
All tons shown are 2,000 Ib.
173
-------
TABLE A-21
ROCKWELL IIITERNATJONAL CLOSED-LOOP AQUEOUS CARBONATE PROCESS VARIATION FROM BASE CASEI icoo MW EXISTING, REGULATED ca. ECONOMICS
TOTAL CAPITAL INVESTMENT 109563000
YEARS ANNUAL POWER UNIT
AFTEK OPfRA- HEAT
POWER TIUN, REQUIREMENT,
UNIT KW-HR/ MILLION 9TU
START KW /YEAR
1
3
4
~~6 7000 63000000
7 7JOO 63000000
8 7-JOO 63000000
9 7000 63000000
.10 2000 6.2aQQQQQ__
11 5000 45000000
12 5000 45000000
13 5'JOO 45000000
14 5000 45000000
15 5JOO 45UOOOOQ
16 3500 315QOOOO
17 3500 31500000
18 3500 31500000
19 3500 31500000
.20 35 JO 315QUOQO__,
21 1500 13500000
22 1500 13500000
23 ISrjO 13500000
24 1500 13500000
.25 1500 13500002...
26 1500 13500000
27 1500 13500000
28 1500 1350JOOO
29 I5oo 13500000
.30 ISUQ 13500000...
TOTAL
SULFUR BY-PRODUCT OP, COST
REMOVED RATE, INCLUDING NET ANNUAL CUMULATIVE
POWER 'J'NIT BY EQUIVALENT NET RfcVENUE, REGULATED TuTAL INCREASE NET INCRiASE
FUEL POLLUTION TONS/YEAR */TON RDI FOR NET IDECRFASEI (DECREASE)
CONSUMPTION, CONTROL POWER SALES IN COST OF IN COST OF
TONS C'JAL PROCESS, ELEMENTAL ELEMENTAL COMPANY, REVENUE, POWER, POWER,
/YEAR TONS/YEAR SULFUR SULFUR t/YFAR t/YEAR * *
looOOOo" 69600 72500 36755 43l7l406~~~2610000~"~~40561400 40561400
3000000 69600 72500 36,00 42436100 261000" 39826100 8Q387SOO
3000000 69600 72500 36,00 4170C7QO 2610000 39Q90700 119478200
3000000 69600 72500 36,00 40965300 2610000 38355300 157833SQO
-...3QQQQQQ.. ....... 626QQ. . 225QQ 3.6.*QO 4G230000 ?6loooo 37fe?nnnn iQS453!Snn
2142900 49700 51800 36.00 35422500 1864300 33557700 229011200
21*2900 49700 51800 36,00 3*687100 18648QO 32822300 261833500
2142900 49700 51800 36,00 33951800 18648QP 32037000 293920500
2142900 49700 51BOO 36.00 33216400 18648QO 31351600 325272100
....2142200...-.- . 42200 5.18QQ 36*00 324fllpnn !8/>4Bnrt 3n#»iA3nn 'a^ftRft^nrt
1500000 34800 36200 36,00 28554400 1303200 27251200 383139500
1500000 3*800 36200 36.00 27819100 13032PC 26515900 409655400
1500000 34800 36200 36,00 27083700 1303200 25780300 435435900
1500000 3*800 36200 36,00 26348300 1303200 25Q45100 460481000
642900 U900 15500 36,00 20261800 558000 197038QO 504494600
642900 14900 15500 30tOQ 19526400 558000 18963400 523463000
642 ?00 U900 15500 36,00 18791100 558000 18233100 541696100
6427QO 14900 15500 36,00 1BQ55700 558000 17497700 559193800
-__--6i22QQ___.«. _ 1&2QQ.. 155QQ 36^00 i232D3on 55Sf>no i67A?^nn HTSQ^^iftn
642900 1*900 15500 36,00 16585000 558000 1&027000 591983100
6*2?00 1*900 15500 36.00 15849600 558000 15291600 607274700
6<*2900 14900 15500 36,00 15114200 558000 14556200 621830900
6*2900 1*900 15500 36,00 1437U900 558000 136209QO 035651800
642200 . 14200 14500 3c*i30 13643500 S^Bnnn I3nsi5>inn htBTSTinn
TOT 92500 832500000 39643500 919500 957500
LIFETIME AVEKAGE HCRfftSE (OECRSAS5) IS U»IT OPERATING COST
JQLLASS PER TU
-------
TABLE A-22. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW new)
7. of
total direct
Investment , $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
Fly ash collection (four cyclone dust collectors)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
ESP credit
Reduction (reducers, compressors, reducer- recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
filter, heat exchangers, compressor, and pumps)
Sulfur production (Glaus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
611,000
7,962,000
830,000
17,461,000
(8,526,000)
11,826,000
3,235,000
6,815,000
4,768,000
1,081,000
46,063,000
2,764,000
48,827,000
298,000
49,125,000
3,696,000
919,000
6,350,000
1,852,000
12,817,000
12,388,000
74,330,000
7,403,000
8,920,000
90,653,000
105,000
2,403,000
93,161,000
1.2
16.2
1.7
35.6
(17.4)
24.1
6.6
13.9
9.7
2.2
93.8
5.6
99.4
0.6
100.0
7.5
1.9
12.9
3.8
26.1
25.2
151.3
15.1
18.1
184.5
0.2
4.9
189.6
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
175
-------
TABLE A-23. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
20
97
68
4,396
338
131
131,938
388
14
,840
,780
,000
,700
,100
,500
,000
,700
,230
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
103
25
12
0
0
0
0
2
17
Unit
cost, $
.00/ton
.00/ton
,50/man-hr
.40/gal
.12/kgal
.92/kgal
.028/kWh
.00 /MBtu
.00 /man-hr
Total % of average
annual annual revenue
cost, $ requirements
2
2
4
1
3
2
8
13
,146
,444
29
,620
850
,758
40
121
,694
(777
,938
241
,867
,487
,500
,500
,000
,000
,000
,700
,600
,000
,300
,400)
,600
,900
,700
,700
8
9
0
17
3
6
0
0
13
(2
11
0
33
50
.09
.22
.11
.42
.21
.63
.15
.46
.93
.93)
.08
.91
.44
.86
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
5,439,200
8,011,800
2,015,300
85,000
280,200
15,831,500
29,319,200
20.51
30.21
7.60
0.32
1.06
59.70
110.56
Byproduct Sales Revenue
Elemental sulfur 70,060 tons 40.00/ton (2,802,400)
Net average annual revenue requirements 26,516,800
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 3.79 9.14
0.44
394
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.
Sulfur removed, 67,240 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $49,125,000; total depreciable investment, $90,653,000; and total
capital investment, $93,161,000.
All tons shown are 2,000 Ib.
176
-------
TABLE A-24
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUEOUS CARBONATE PROCESS VARIATION FROM BASE CASE: 1000 MW, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 93161000
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
* 7000
$ 7PPP
6 7000
7 7000
6 7000
9 7000
10 JflflO
11 5000
12 5000
13 5000
14 5000
Jfe 5ppp
16 3500
17 3500
18 3500
19 3500
29 35BO
21 1500
22 1500
23 1500
24 1500
25 }5pp
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED
HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
REQUIREMENT, CONSUMPTION. CONTROL POWER
MILLION BTU TONS COAL PROCESS, ELEMENTAL ELEMENTAL COMPANY,
/YEAR /YEAR TONS/YtAR SULFUR SULFUR S/YEAR
60900000 2900000 67200
60900000 2900000 67200
60900000 2900000 67200
60900000 2900000 67200
6P900pfl() 2900000 67204
60900000 2900000 67200
60900000 2900000 67200
60900000 2900000 67200
60900000 2900000 67200
60900000 2.900.POO 6720.4
43500000 2071400 48000
43500000 2071400 48000
43500000 2071400 48000
43500000 2071400 48000
435GOPOQ 2071400 48000
30450000 1450000 33600
30450000 1450000 33600
30450000 1450000 33600
30450000 14500PO 33600
30454000 1450000 33604
13050000 621400 14400
13050000 621400 14400
13050000 621400 14400
13050000 621400 14400
13050000 621400 1440.0
13050000 621400 14400
13050000 621400 14400
13050000 621400 14400
13050000 621400 14400
13050000 621400 144Q4
70100
70100
70100
70100
70100
70100
70100
70100
70100
. 70100
50000
50000
500PO
bOOOO
SOOOO
35000
35000
35000
35000
35000
15000
15000
15000
15000
15000
15000
15000
15000
15000
JJ)000_
1109250000 52821000 1224000 1276000
AVERAGE INCREASE (OECREASt) 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 11.6* 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
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
36.00
TO DISCOUNTED
37051200
36531400
36011700
35491900
34972204
34452400
33932700
33412900
32893200
32373400
28031500
27511700
26992000
26472200
25952504_
22446700
21927000
21407200
20887500
_ 25367700
15551200
15031500
14511700
13992000
13472204
12952500
12432700
11913000
11393200
1P8735QO
TOTAL
NET
SALES
REVENUE,
S/YEAR
2523600
2523600
2523600
2523600
2523600
2523600
2523600
2523600
2523600
2S22&S9—
1800000
1800000
1800000
1800000
1805000
1260000
1260000
1260000
1260000
12.6POOO
540000
540000
540000
540000
540000
540000
540000
540000
540000
540000
721242500 45936000
13.65 0.87
5.66 0.36
65.02 4.14
589.25 37.53
258817000 17912100
PHOCFSS COST OVER LIFE OF
12.57 0.87
5.21 0.36
59.86 4.14
542.48 37.54
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POxER, POWER,
$ s
34527600
34007800
33488100
32968300
32448600 .
34527600
68535400
102023500
134991800
167440440
3192880P 199369200
31409100 230778300
30889300 261667600
30369600 292037200
29849800 32J887000
26231500
2571170P
25192POP
24672200
24152504
21186700
20667000
20147200
19627500
19107704
348118500
373830200
399022200
423694400
447846900
469033600
489700600
509847800
529475300
..54858.30.40
15011200 563594200
14491500 578085700
13971700 592057400
13452000 605509400
12.932250 618441640
12412500
11892700
11373000
108532PO
10333500
675306500
12.78
5.30
60.88
551.72
240904900
POWER UNIT
11.70
4.85
55.72
504.94
630854100
642746800
654119800
664973000
675306500
-------
TABLE A-25. AQUEOUS CARBONATE PROCESS
SUMMARY 0¥ ESTIMATED CAPITAL INVESTMENT
(Variation from base case:
S02 removal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
Fly ash collection (four cyclone dust collectors)
S0~ absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
ESP credit
Reduction (reducers, compressors, reducer-recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Claus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total process area 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
443,000
5,084,000
490,000
10,647,000
(4,713,000)
8,123,000
2,282,000
4,710,000
3,328,000
750,000
31,144,000
1,869,000
33,013,000
154,000
33,167,000
2,190,000
544,000
4,582,000
1,374,000
8,690,000
8,371,000
50,228,000
5,007,000
6,027,000
61,262,000
64,000
1,560,000
62,886,000
1.3
15.3
1.5
32.1
(14.2)
24.5
6.9
14.2
10.0
2.3
93.9
5.6
99.5
0.5
100.0
6.6
1.6
13.9
4.1
26.2
25.2
151.4
15.1
18.2
184.7
0.2
4.7
185.6
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
178
-------
TABLE A-26. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% S02 removal)
Annual
quantity
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
12
57
52
2,590
199
77
73,150
229
8
,280
,620
,000
,800
,300
,500
,000
,000
,760
tons
tons
man-hr
gal
kgal
kgal
kWh
MBtu
man-hr
103
25
12
0
0
0
0
2
17
Unit
cost, $
.00 /ton
.00/ton
.50/man-hr
.40 /gal
.12 /kgal
.92/kgal
.029/kWh
.00/MBtu
.00/man-hr
Total % of average
annual annual revenue
cost , $ requirements
1,264
1,440
17
2,722
650
1,036
23
71
2,121
(458
2,315
148
5,909
8,631
,800
,500
.100
,400
,000
,300
,900
,300
,400
,000)
,500
,900
,300
,700
7
8
0
15
3
5
0
0
11
(2
12
0
33
48
.09
.07
.10
.26
.64
.81
.13
.40
.88
.57)
.97
.83
.09
.35
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8,6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
3,675,700
5,408,200
1,557,200
65,000
165,200
10,871,300
19,503,000
20.59
30.30
8.72
0.36
0.93
60.90
109.25
Byproduct Sales Revenue
Elemental sulfur 41,290 tons 40.00/ton (1.651,600)
Net average annual revenue requirements 17,851,400
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements 5.10 11.90
0.57
451
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.
Sulfur removed, 39,620 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $33,167,000; total depreciable investment, $61,262,000; and total
capital investment, $62,886,000.
All tons shown are 2,000 Ib.
179
-------
TABEL A-27
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUEOUS CARBONATE PROCESS VARIATION FROM BASE CASE: 90? S REMOVAL. REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMtNT 628B6000
YEARS ANNUAL
AFTER OPERA-
POWER TION»
UNIT KW-hR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
JO 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
21 1500
22 1500
23 1500
24 1500
j=5 1500
26 1500
27 1500
28 1500
29 1500
30. 1500
TOT 127500
LIFETIMF
PROCESS COST
LEVELIZFD
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED KAlE. INCLUDING
POWER UNIT POWER UNIT bY EQUIVALENT NET REVENUE. REGULATED
HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
REQUIREMENT, CONSUMPTION, CONTHOL POWER
MILLION STU TONS COAL PROCESS, ELEMENTAL ELEMENTAL COMPANY,
/YEAR /YEAR TONS/YEAH SULFUR SULFUR I/YEAR
31500000
,31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
22500000
22500000
2P500000
22500000
157500UO
15750000
15750000
15750000
15750000
6750000
6750000
6750000
6750000
6751)000
6750000
6750000
6750000
6750000
1500000
1500000
1500000
1500000
J500.000 .. _
1500000
1500000
1500000
15UOOOO
1500000
1071400
1071400
1071400
1071400
1071400
750000
750000
750000
750000
750000
321400
321400
321400
321400
J2J4QJJ
321400
321400
321400
321400
321400
39600
39600
39600
39600
39600
39600
39600
39600
28300
28300
20300
20300
£43.411
19HOO
19800
19800
19BOO
6^00
0500
850U
BoOO
8500
8500
8500
41300
41300
41300
41300
413_OU
41300
41300
41300
41300
29500
29300
£9500
29500
<:0600
20600
20600
20600
£J26.0_0_
8800
8800
8800
8800
8800
8800
8800
8800
573750000 27321000 721500 751500
AVERAGE INCREASE (DECREAbE) IN UNIT OPERATING Cobf
uOLLAnS PER TON OF COAL SURKEO
MILLb PER KILOnAT T-h'OUH
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PEn TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE) IN UiNlT OPERATING COST EQUIVALENT
UOLLARS PER TON OF COAL yURNEL)
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU htAT INPUT
uOLL^hS PER TON OF SULFUR REMOVED
36
36
36
36
30
36
36
36
_ 36
.
.
.
36.
36.
36.
36.
36*
3b.
3b.
36.
3o.
36
36
36
36
_J6
36
36
36
36
36
.
A
.
.
00
00
00
00
00
00
00
00
0(1
00
00
00
00
"0
00
00
00
00
00
oo
00
00
00
00
00
00
oo
00
TO DISCOUNTED
24746300
24395100
24043800
23692600
22990100
22638800
C2287600
21936400
21585100
18797900
18446600
18095400
17744200
17392900
15121400
14770100
14418900
14067700
10557700
10P06400
9fc55200
9503900
8B01500
H450200
8099000
7747700
739650U
TOTAL
NET
SALES
REVENUE,
i/YEAR
1486800
1486800
1486800
1486800
1486800
1486800
1486800
1486800
1486800
1486800
1062000
1062000
1062000
1062000
1062000
741600
741600
741600
741600
J4J6QO
316800
316800
316800
316800
316800
316800
316800
316800
316800
^83999400 27054000
17.72 0.99
7.59 0.42
84.36 4.72
670.82 37.49
173046200 10553500
PROCESS COST UVER LIFE OF
16.25 0.99
6.96 0.42
77.38 4.72
615.38 37.53
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
23259500
22908300
22557000
22205800
21854504
21503300
21152000
20800800
20449600
17735900
17384600
17033400
16682200
16330900
14379800
14028500
13677300
13326100
129748JJO
10240900
9889600
9538400
9187100
8484700
8133400
7782200
7430900
7Q797p4
456945400
16.73
7.17
79.64
633.33
162492700
POWER UNIT
15.26
6.54
72.66
577.85
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
23259500
46167800
68724800
90930600
... 1-12785.1(10
134288400
155440400
176241200
196690800
__H6ISSi20
234525000
251909600
268943000
285625200
3JU.256JJJO
316335900
330364400
344041700
357367800
370342640
380583500
390473100
400011500
409198600
41SP34540
426519200
434652600
442434800
449865700
_4j$.S 45440
-------
TABLE A-28. AQUEOUS CARBONATE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
% of
total direct
Investment $ investment
Direct Investment
Materials handling and feed preparation (tank and pumps)
Gas handling (common feed plenum, gas ducts and dampers from plenum
to spray dryer, exhaust gas ducts and dampers from ESP's to stack,
and booster fans)
S02 absorption and removal (four spray dryers, four ESP's, silos,
hopper, conveyors, tank, agitator, and pumps)
Reduction (reducers, compressors, reducer- recuperators, waste heat
boilers, reducer air heater, tanks, agitators, and pumps)
Off-gas treatment (venturi scrubber, cooling tower, heat exchangers,
and pumps)
Carbonation (precarbonator, crystallizer, carbonator, decomposer,
filter, heat exchangers, compressor, and pumps)
Sulfur production (Claus plant with tail gas incinerator)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
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
248,000
4,540,000
9,401,000
4,139,000
1,219,000
2,424,000
1,745,000
390,000
24,106,000
1,446,000
25,552,000
2,057,000
514,000
3,682,000
1,127,000
7,380,000
6,586,000
39,518,000
3,952,000
4,742,000
48,212,000
41,000
946,000
49,199,000
1.0
17.8
36.8
16.2
4.8
9.5
6.8
1.5
94.3
5.7
100.0
8.1
2.0
14.4
4.4
28.9
25.8
154.7
15.5
18.6
188.8
0.2
3.7
192.7
Basis
Midwest plant location represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mile from power plant.
Investment requirement 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.
181
-------
TABLE A-29. AQUEOUS CARBONATE PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Direct Costs
Raw materials
Soda ash
Coal
Catalyst
Annual
quantity
4,750 tons
22,290 tons
Unit
cost, $
103.00/ton
25.00/ton
Total
annual
cost, $
489,300
557,300
6,600
% of average
annual revenue
requirements
3.69
4.21
0.05
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Process water
Boiler feedwater
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
50,320 man-hr 12.50/man-hr
1,053,200
629,000
1,002,500 gal
77,100 kgal
30,000 kgal
44,672,000 kWh
88,600 MBtu
8,380 man-hr
0.40/gal
0.12/kgal
0.92/kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
401,000
9,300
27,600
1,295,500
(177,200)
1,788,600
142,500
4,116,300
5,169,500
7.95
4.74
3.02
0.10
0.21
9.77
1.34
13.49
1.07
31.06
39.00
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of sales revenue
Total indirect costs
Gross average annual revenue requirements
3,085,600
4,231,000
1,280,100
62,900
63,900
8,723,600
13,893,100
23.28
31.93
9.66
0.47
0.48
65.82
104.82
Byproduct Sales Revenue
Elemental sulfur 15,980 tons
Net average annual revenue requirements
40.00/ton
(639,200)
13,253,900
$/bbl oil $/MBtu heat
Mills/kWh burned input
$/ton
S removed
Equivalent unit revenue requirements
3.79
2.48
0.41
864
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.
Sulfur removed, 15,330 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $25,552,000; total depreciable investment, $48,212,000; and total
capital investment, $49,199,000.
All tons shown are 2,000 Ib.
182
-------
TABLE A-30
ROCKWELL INTERNATIONAL CLOSED-LOOP AQUEOJS CARBONATE PROCESS VARIATION FROM BASE CASEI OIL FIRED,EXISTING, REGULATED co, ECONDMI
TOTAL CAPITAL INVESTMENT 49199000
00
U)
YEARS
UNIT
START
1
2
3
4
5
ANNUAL
OPERA.
TION,
KW-.HR/
KW
6 7000
7 7000
8 7000
9 7000
.10 2QQQ--
11 5000
12 5000
13 5000
14 5000
.15 5UQ6--
16 3500
17 3500
18 35QO
19 3500
.20 3500.-
21 1500
22 1500
23 1500
24 1300
.25 1500 —
26 1500
27 1500
28 1500
29 1500
.30 1500—
POWER UNIT
HEAT
REQUIREMENT,
MILLION BTg
/YEAR
32200000
32200000
32200000
32200000
.32200000...
23000000
23000000
23000000
23000000
.23000000...
16100000
16100000
16100000
16100000
.16100000 _.
6900000
69QOOOO
6900000
6900000
63QUQOQ
6900000
69QOOOO
6900000
6900000
6200000...
PQ^ER UNIT
FUEL
CONSUMPTION,
BARRELS OIL
/YEAR
5324100
53E41QO
5324100
5324100
5324100—
3802900
3802900
3802900
38029QO
3802200—
2662000
2662000
2662000
2662000
- ..2662000
1140900
1140900
1140900
114Q900
114Q2QQ
1140900
1140900
1140700
11409QO
1140200—
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
15300
15300
15300
15300
13300
11000
11000
11000
11000
11QOU—
7700
7700
7700
7700
2200...
3300
3300
3300
3300
3300...
3300
3300
3300
3300
3300...
BY-PRODUCT
RATE,
EQUIVALENT NfcT
TONS/YEAR
ELEMENTAL
SULFUR
REVENUE,
WTON
ELEMENTAL
SULFUR
16000 3b,00
16000 36,00
16000 36,00
16000 36.00
16000 36*00...
11400 36,00
11400 36,00
11400 36,00
11400 36,00
U40Q 36*00
8000 36,00
8000 3C.CO
8000 36,00
8000 36.00
8QQQ 36*00
3400 36,00
3400 36,00
3400 36.00
3400 30,00
3400- —36*00...
3400 36,00
3400 36,00
3400 36.00
3400 30,00
34QQ 46*00
TOTAL
QP, COST
INCLUDING
REGULATED
ROI FOR
POV«ER
COMPANY,
t/YEAR
183II900
18Q50200
17718500
17386800
1ZQ5S1QQ..
15270400
14938700
14607000
14275300
13243600..
12445600
12113900
11782200
11450500
1111BBQQ..
9029300
8697600
8365900
8034200
2202500..
7370800
7039100
6707400
6375700
6044000..
TOTAL
NET
SALES
REVENUE,
t/YEAR
576000
576000
576000
576000
.— 5Z6QOQ-,
41Q4QO
410400
410*00
410400
41Q4QD-.
288000
288000
2B8000
288000
— 288000-,
122400
122400
122400
122400
_ 12240Q-.
122*00
122400
122400
122400
1224QQ.
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
»
17805900
17474200
17142500
16810800
—16422100.
1486QOOO
14528300
14196600
13864900
13533200.
12157600
11825900
11494200
11162500
..-10830800.
8906900
8575200
8243500
7911800
._ .2380100-
7248400
6916700
6585000
6253300
5221600-
CUMULATIVi
NET INCREASE
(DECREASE)
IN COST QF
POWER,
*
17805900
3528QIOO
52422600
69233400
83212300
100572900
115100800
129297400
143162300
136633900
168853100
180679000
192173200
203335700
—214166300
223073400
231648600
239892100
247803900
—25338*000
2626324QO
269549100
276134100
282387400
— 2883QSOOO
TOT 92500 425500000 70354.100 203000 211000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILQ
-------
TABLE A-31. WELLMAN-LORD/SULFBRIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (two absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
305,000
1,952,000
1,902,000
504,000
2,153,000
1,534,000
4,464,000
3,063,000
520,000
16,397,000
984,000
17,381,000
31,000
17,412,000
1,523,000
380,000
2,681,000
842,000
5,426,000
4,568,000
27,406,000
2,737,000
3,289,000
33,432,000
15,000
760,000
34,207,000
1.8
11.2
10.9
2.9
12.4
8.8
25.6
17.6
3.0
94.2
5.6
99.8
0.2
100.0
8.7
2.3
15.4
4.8
31.2
26.2
157.4
15.7
18.9
192.0
0.1
4.4
196.5
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.
184
-------
TABLE A-32. WELLMAN-LOKD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW existing)
Direct Costs
Raw materials
Sodium carbonate;
Catalyst
Agricultural limestone
Filter aid
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
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
2,660 tons 103.00/ton
760 liters 2.50/liter
1,370 tons 15.00/ton
30 tons 189.00/ton
30,040 man-hr 12.50/man-hr
274,000
1,900
20,600
5,700
302,200
375,500
2.84
0.02
0.21
0.06
3.13
3.89
2
33
657
,150
,012
20
4
,300
,000
,000
,400
,480
MBtu
kgal
kWh
MBtu
man-hr
2
0
0
2
17
.00/MBtu
.12/kgal
.031/kWh
.00/MBtu
.00 /man-hr
1
1
1
4
4
,314
258
,023
(40
,217
76
,224
,526
,600
,000
,400
,800)
,600
,200
,500
,700
13
2
10
(0
12
0
43
46
.60
.67
.59
.42)
.61
.79
.73
.86
jndirect 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
2,340
2,941
834
37
113
6,267
10,794
,200
,800
,700
,600
,500
,800
,500
24
30
8
0
1
64
111
.23
.45
.64
.39
.18
.89
.75
Byproduct Sales Revenue
100% sulfuric acid
Sodium sulfate
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
42,300 tons 25.00/ton 100% (1,057,500) (10.95)
H2S04
3,380 tons 23.00/ton (77,700) (0.80)
9,659,300 100.00
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
6.90 15.25 0.73 658
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, 14,680 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $17,412,000; total depreciable investment, $33,432,000; and total
capital investment, $34,207,000.
All tons shown are 2,000 Ib.
185
-------
TABEL A-33
WELLMAN-LORO/ SULFURIC ACID PROCESS VARIATION FROM BASE CASE: 200 MW EXISTING, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 34207000
00
OS
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS,
/YEAR /YEAR TONS/YEAR
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04 NA2S04
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100* COMPANY,
H2S04 NA2S04 S/YEAR
TOTAL
NET
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
1
2
3
4
5
6
7
8
9
in
11
12
13
14
_J5
16
17
18
19
?0
21
22
23
24
?"i
26
27
28
29
ifl
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 57500
LIFETIME
PROCESS COST
LEVELIZEO
9500000 452400 10500
9500000 452400 10500
9500000 452400 10500
9500000 452400 10500
9500000 452400 1050J
6650000 316700 7300
6650000 316700 7300
6650000 316700 7300
6650000 316700 7300
6650000 316700 1300
2850000 135700 3100
2850000 135700 3100
2850000 135700 3100
2850000 135700 3100
28SOOOp 135700 310J1
2850000 135700 3100
2850000 135700 3100
2850000 135700 3100
2850000 135700 3100
2850000 135700 3.10.Q
30200
30200
30200
30200
302DO
21200
21200
21200
21200
212DO
9100
9100
9100
9100
9100
9100
9100
9100
9100
9100
2400
2400
2400
2400
2400
1700
1700
1700
1700
1700
700
700
700
700
700
700
700
700
700
700
109250000 5202500 120000 348000 27500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 8TU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11. 6« TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 8TU 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
_ 22.5?
22.50
22.50
22.50
22.50
_2ijlS_
22.50
22.50
22.50
22.50
22.50
20.
20.
20.
20.
?«i
20.
20.
20.
20.
PO t
20.
20.
20.
20.
f"t
20.
20.
20.
20.
20.
70
70
70
70
70
70
70
70
70
70
70
70
70
70
70
70
70
70
70
70
12904200
12616700
12329200
12041700
11754100
10459300
10171800
9884300
9596800
930930Q
7545800
7258200
6970700
6683200
6395704
6108200
5820700
5533100
5245600
4958100
173586700
33.37
15.09
158.89
1446.56
78509500
DISCOUNTED PROCESS COST OVER
30.51
13.80
145.29
1319.49
729200
729200
729200
729200
729200
512200
512200
512200
512200
512200
219300
219300
219300
219300
219300
219300
219300
219300
219300
219300
8400000
1.62
0.73
7.69
70.00
4152500
LIFE OF
1.61
0.73
7.68
69.79
12175000
11887500
11600000
11312500
11024900
9947100
9659600
9372100
9084600
8/97100
7326500
7038900
6751400
6463900
61764QO
5888900
5601400
5313800
5026300
47388,30
165186700
31.75
14.36
151.20
1376.56
74357000
POWER UNIT
28.90
13.07
137.61
1249.70
12175000
24062500
35662500
46975000
57999900
67947000
77606600
86978700
96063300
104869400
112186900
119225800
125977200
132441100
13.86JI5.0.0
144506400
150107800
155421600
160447900
165186700
-------
TABLE A-34. WELLMAN-LORD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW new)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (two absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger, ,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
1
2
1
4
2
16
17
17
1
2
5
4
26
2
3
32
33
301
,908
,858
493
,104
,503
,366
,996
509
,038
962
,000
56
,056
,522
379
,637
829
,367
,485
,908
,685
,229
,822
15
741
,578
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
1
11
10
2
12
8
25
17
3
94
5
99
0
100
8
2
15
4
31
26
157
15
18
192
0
4
196
.8
.2
.9
.9
.3
.8
.6
.6
.0
.1
.6
.7
.3
.0
.9
.2
.5
.9
.5
.3
.8
.7
.9
.4
.1
.3
.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.
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.
187
-------
TABLE A-35. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW new)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
2,580 tons 103.00/ton
740 liters 2.50/liter
1,330 tons 15.00/ton
29 tons 189.00/ton
30,040 man-hr 12.50/man-hr
265,700
1,900
20,000
5,500
293,100
375,500
2.91
0.02
0.22
0.06
3.21
4.11
636,500 MBtu
2,082,300 kgal
31,991,000 kWh
19,800 MBtu
4,480 man-hr
2.00/MBtu
0.12/kgal
0.031/kWh
2.00/MBtu
17. 00 /man-hr
1,273,000
249,900
991,700
(39,600)
1,191,700
76,200
4,118,400
4,411,500
13.93
2.73
10.85
(0.43)
.3.04
0.83
45.06
48.27
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
1,969,300
2,887,700
821,700
37,600
109,800
5,826,100
10,237,600
21.55
31.59
8.99
0.41
1.20
63.74
112.01
Byproduct Sales Revenue
100% sulfuric acid
Sodium sulfate
Net average annual revenue requirements
40,900 tons 25.00/ton 100% (1,022,500) (11.19)
H2S04
3,270 tons 23.00/ton (75,200) (0.82)
9,139,900
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
6.53 14.91 0.71 643
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, 14,220 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $17,056,000 ; total depreciable investment, $32,822,000; and total
capital investment, $33,578,000.
All tons shown are 2,000 Ib.
188
-------
oo
VD
TABLE A-36
WELLMAN-LORO/ SULFURIC ACID PROCESS VARIATION FROM BASE CASE: 200 MW» REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 33578000
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KW-HR/
START KW
1
2
3
4
5
6
7
B
9
10
11
12
13
1*
]S
16
17
18
19
2fl
21
22
23
2*
?<=!
26
27
28
29
3°
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS*
/YEAR /YEAR TONS/YEAR
12860000 613300
12860000 613300
12680000 613300
12880000 613300
12880000 613300
12880000 613300
12880000 613300
12880000 613300
12880000 613300
12880000 613300
9200000 438100
9200000 436100
9200000 438100
9200000 438100
9200000 438100
6440000 306700
6440000 306700
6440000 306700
6440000 306700
6440000 306700
2760000 131400
2760000 131400
2760000 131400
2760000 131400
2760000 131400
2760000 131400
2760000 131400
2760000 131400
2760000 131400
2760000 131400
14200
14200
14200
14200
14200
14200
14200
14200
14200
14200
10200
10200
10200
10200
10200
7100
7100
7100
7100
710J1
3000
3000
3000
3000
3000
3000
3000
3000
3000
3AOH
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04 NA2S04
40900
40900
40900
40900
4.0900
40900
40900
40900
40900
40900
29200
29200
29200
29200
29200
20500
20500
20500
20500
2.050Q
8600
8800
8600
6800
8800
8800
8800
8800
8800
8800
3300
3300
3300
3300
3300
3300
3300
3300
3300
3300
2300
2300
2300
2300
2300
1600
1600
1600
1600
1600 _
700
700
700
700
700
700
700
700
700
700
234600000 11171000 258500 745500 59500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 8TU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100% COMPANY,
H2S04 NA2S04 S/YEAR
22.50
£2.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
2g.5Q
22.50
22.50
22.50
22.50
22.55 _
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.55
22.50
22.50
22.50
22.50
??i50
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20, 7j)
20.70
20.70
20.70
20.70
?o.7g_
20.70
20.70
20.70
20.70
.. 23*13
20.70
20.70
20.70
20.70
20.70_
20.70
20.70
20.70
20.70
20.70
13015700
12827500
12639300
12451200
J2P63000
12074800
11886600
11698400
11510200
11322000
9890400
9702200
9514000
9325800
913760D
7967500
7779400
7591200
7403000
7 2.14993-
5586300
5398100
5209900
5021800
4833608
4645400
4457200
4269000
4080800
3892600
TOTAL
NET
SALES
REVENUE,
$/YEAR
968600
988600
988600
988600
98.86QO ,
968600
988600
986600
988600
. -SflflfiOO.
704600
704600
704600
704600
704600
494400
494400
494400
494400
*?4490
212500
212500
212500
212500
212500
212500
212500
212500
212500
..-.,212599
254609300 18006000
22.79 1.61
9.98 0.70
108.53 7.68
984.95 69.66
90960500 7017400
DISCOUNTED PROCESS COST OVER LIFE OF
20.89 1.61
9.15 0.70
99.47 7.67
902.39 69.62
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
$ J
12027100
11838900
11650700
11462600
H274490
11086200
10696000
10709800
10521600
1033340.0
9185800
8997600
8809400
6621200
9.4330Q..O. _
7473100
7285000
7096600
6908600
6729«9« _
5373800
5185600
4997400
4809300
. *6211i!JL_,
4432900
4244700
4056500
3868300
3680100
236603300
21.16
9.28
100.85
915.29
83943100
POWER UNIT
19.28
8.45
91.80
832.77
12027100
23866000
35516700
46979300
.-,.582537HO
69339900
80237900
90947700
101469300
, ,111842.700
120988500
129986100
138795500
147416700
__15584?7.BO
163322800
170607800
177704600
184613200
19J3336J10
196707400
201893000
206890400
211699700
216320840
220753700
224998400
229054900
232923200
...2366433.00
-------
TABLE A-37. WELLMAN-LOKD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500 MW existing)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S(>2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
463,000
4,442,000
4,426,000
1,153,000
4,977,000
2,678,000
8,283,000
5,684,000
908,000
33,014,000
1,981,000
34,995,000
123,000
35,118,000
2,236,000
556,000
4,803,000
1,435,000
9,030,000
8,830,000
52,978,000
5,286,000
6,357,000
64,621,000
39,000
1,567,000
66,227,000
1.
12.
12.
3.
14.
7.
23.
16.
2.
94.
5.
99.
0.
100.
6.
1.
13.
4.
25.
25.
150.
15.
18.
184.
0.
4.
188.
3
6
6
3
2
6
6
2
6
0
6
6
4
0
4
6
6
1
7
1
8
1
1
0
1
5
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.
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.
190
-------
TABLE A-38. WELLMAN-LORD/SULFURIC ACID PROCESS
\
ANNUAL KEVENUB REQUIREMENTS
(Variation from base case: 500 MW existing)
Total % of average
Annual Unit annual annual revenue
quantity cost, ? cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 6,440
Catalyst 1,840
Agricultural limestone 3,310
Filter aid 72
Total raw materials cost
Conversion costs
Operating labor and supervision 47,500
Utilities
Steam 1,591,200
Process water 5,205,600
Electricity 79,074,000
Heat credit 49,500
Maintenance
Labor and material
Analyses 8,500
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 102,300
Sodium sulfate 8,180
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton 663,300
liters 2.50/liter 4,600
tons 15.00/ton 49,700
tons 189.00/ton 13.600
731,200
man-hr 12.50/man-hr 593,800
MBtu 2.00/MBtu 3,182,400
kgal 0.12/kgal 624,700
kWh 0.029/kWh 2,293,100
MBtu 2.00/MBtu (99,000)
2,103,400
man-hr 17.00/man-hr 144,500
8,842,900
9,574,100
4,135,700
5,695,500
1,420,900
59,400
274,600
11,586,100
21,160,200
tons 25.00/ton 100% (2,557,500)
H2S04
tons 23.00/ton (188,100)
18,414,600
$/ton coal $/MBtu heat
Mills /kWh burned input
5.26 12.01 0.57
3.61
0.02
0.27
0.07
3.97
3.22
17.29
3.39
12.46
(0.54)
11.42
0.78
48.02
51.99
22.46
30.93
7.72
0.32
1.49
62.92
114.91
(13.89)
(1.02)
100.00
$/ton
S removed
518
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, 35,550 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $35,118,000; total depreciable investment, $64,621,000; and total
capital investment, $66,227,000.
All tons shown are 2,000 Ib.
191
-------
VO
TABLE A-39
WELLMAN-LORD/ SULFURIC ACID PROCESS VARIATION FROM BASE CASE! 500 MW EXISTING, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 66227000
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TIONi REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION 8TU TONS COAL PROCESS* 100*
START KW /YEAR /YEAR TONS/YEAR H2S04 NA2S04
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100* COMPANY,
H2S04 NA2S04 S/YEAR
TOTAL
NET
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POKER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
1 - - - —
2
3
4
5
6
7
8
9
.JO
11
12
13
1*
.15
16
17
18
19
..20
21
22
23
2*
25
26
27
26
29
_3fl., ...
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 92500
LIFETIME
PROCESS COST
LEVELIZEO
32200000 1533300 35600 102300
32200000 1533300 35600 102300
32200000 1533300 35600 102300
32200000 1533300 35600 102300
32200000 1533300 35600 102309
23000000 1095200 25400 73100
23000000 1095200 25400 73100
23000000 1095200 25400 73100
23000000 1095200 25400 73100
23000000 1095200 ?54flO 73100
16100000 766700 17800 51100
16100000 766700 17800 51100
16100000 766700 17800 51100
16100000 766700 17800 51100
16100000 766700 178qj 51100
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900
6900000 328600 7600 21900.
8200
8200
8200
8200
8200
5800
5600
5600
5800
. 5800
4100
4100
4100
4100
__S.LOJ!_
1600
1800
1800
1BOO
1800
1600
1600
1600
1800
1800
425500000 20262000 470000 1351500 108500
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 11.6% TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
22.50
22.50
22.50
22.50
_ 22.5Q
22.50
22.50
22.50
22.50
- 22,50
22.50
22.50
22.50
22.50
- 22.59
22.50
22.50
22.50
22.50
. 22. 5Q
22.50
22.50
22.50
22.50
_ 22.50
20.70
20.70
20.70
20.70
_2i»XS-
20.70
20.70
20.70
20.70
20. 7Q
20.70
20.70
20.70
20.70
20. 7p
20.70
20.70
20.70
20.70
20.70
27012100
26567600
26123000
25678400
252338QO
22079800
21635200
21190600
20746100
20301500
17739800
17295200
16850600
16406000
15961490
12470000
12025400
11580800
11136200
1069160JJ
20.70 10247000
20.70 9802400
20.70 9357900
20.70 8913300
20.70 846B700
2471500
2471500
2471500
2471500
24IJ500
1764900
1764900
1764900
1764900
1764^900
1234700
1234700
1234700
1234700
1234700
530100
530100
530100
530100
530100
530100
530100
530100
530100
530100
425514400 32656500
21.00 1.61
9.20 0.71
100.00 7.67
905.35 69.48
172852700 14797100
DISCOUNTED PROCESS COST OVER LIFE OF
18.83 1.61
8.25 0.71
89.65 7.67
811.13 69.43
24540600
24096100
23651500
23206900
22762359
20314900
19870300
19425700
18981200
18536600
16505100
16060500
15615900
15171300
14726700
11939900
11495300
11050700
10606100
10.}6J5J?9
9716900
9272300
8827800
8383200
793S4QS
392857900
19.39
8.49
92.33
835.87
158055600
POWER UNIT
17.22
7.54
81.98
741.70
24540600
48636700
72288200
95495100
118257400
138572300
158442600
177868300
196849500
215386100
231691200
247951700
263567600
278738900
293465600
305405500
316900800
327951500
338557600
348719100
358436000
367708300
376536100
384919300
392857900
-------
TABLE A-40. WELMAN-LOSD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2.0% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
318,000
4,376,000
4,352,000
1,136,000
4,894,000
1,619,000
4,742,000
3,254,000
549,000
25,240,000
1,514,000
26,754,000
154,000
26,908,000
2,069,000
514,000
3,853,000
1,172,000
7,608,000
6,903,000
41,419,000
4,127,000
4,970,000
50,516,000
42,000
1,075,000
51,633,000
1.2
16.3
16.2
4.2
18.2
6.0
17.6
12.1
2.0
93.8
5.6
99.4
0.6
100.0
7.7
1.9
14.3
4.4
28.3
25.6
153.9
15.3
18.5
187.7
0.2
4.0
191.9
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.
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.
193
-------
TABLE A-41. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Annual Unit
quantity cost, $
Direct Costs
Raw materials
Sodium carbonate 2,900
Catalyst 830
Agricultural limestone 3,240
Filter aid 32
Total raw materials cost
Conversion costs
Operating labor and supervision 42,550
Utilities
Steam 942,600
Process water 2,445,700
Electricity 60,803,000
Heat credit 22,300
Maintenance
Labor and material
Analyses 7,610
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
inves tment
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 46,100
Sodium sulfate 3,680
Net average annual revenue requirements
tons 103.00/ton
liters 2.50/liter
tons 15.00/ton
tons 189.00/ton
man-hr 12.50/man-hr
MBtu 2.00/MBtu
kgal 0.12/kgal
kWh 0.029/kWh
MBtu 2.00/MBtu
man-hr 17 .00/man-hr
Total % of average
annual annual revenue
cost , $ requirements
298,700
2,100
48,600
6,000
355,400
531,900
1,885,200
293,500
1,763,300
(44,600)
1,609,900
129,400
6,168,600
6,524,000
3,031,000
4,440,400
1,135,600
53,200
123,700
8,783,900
15,307,900
tons 25.00/ton 100% (1,152,500)
H2S04
tons 23.00/ton
$/ton
(84,600)
14,070,800
coal $/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements (net)
4.02 9.
38 0.45
2.12
0.01
0.35
0.04
2.52
3.78
13.40
2.09
12.53
(0.32)
11.44
0.92
43.84
46.36
21.54
31.56
8.07
0.38
0.88
62.43
108.79
(8.19)
(0.60)
100.00
$/ton
S removed
879
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, 16,000 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $26,908,000; total depreciable investment, $50,516,000; and total
capital investment, $51,633,000.
All tons shown are 2,000 Ib.
194
-------
TABLE A-42
WELLMAN-LORD/ SULFURIC ACID PROCESS VARIATION FROM BASE CASE: 2.0* S, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 51633000
VO
Oi
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
f,
6
7
8
9
10
11
12
13
14
15
16
17
1«
19
?0
21
22
23
24
?&
26
27
28
29
3.2
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5009
3500
3500
3500
3500
3500
1500
1500
1500
1500
-r- J59.S.
1500
1500
1500
1500
1500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT. CONSUMPTION. CONTROL
MILLION 8TU TONS COAL PROCESS.
/YEAH /YEAR TONS/YEAR
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
22500000 1071400
22500000 1071400
22500000 1071400
22SOOOOO 1071400
22500000 1071400
15750000 750000
15750000 750000
15750000 750000
15750000 " 750000
15750000 750000
6750000 321400
6750000 321400
6750000 321400
6750000 321400
6750000 321400
6750000 321400
67bOOOO 321400
6750000 321400
6750000 321400
6750000 321* Si
16000
16000
16000
16000
16000
16000
16000
16000
16000
16000
11400
11400
11400
1140U
11*00
8000
8000
8000
8000
8000
3400
3400
3400
3400
3400
3400
3400
3400
3400
3400
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
100%
H2S04 NA2S04
46100
46100
46100
46100
46100
46100
46100
46100
46100
46100
32900
32900
32900
32900
32900
23100
23100
23100
23100
23100
9900
9900
9900
9900
9900
9900
9900
9900
9900
9900
3700
3700
3700
3700
3700
3700
3700
3700
3700
3700
2600
2600
2600
2600
2600
1800
1800
1800
1800
1800
800
800
800
800
800
800
800
800
800
800
573750000 27321000 291000 840000 67000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PEH TON OF SULFUR REMOVED
DISCOUNTED AT 11.6% TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CFNTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100% COMPANY,
H2S04 NA2S04 S/YEAR
22.50
22.50
22.50
22.50
?2,50
22.50
22.50
22.50
22.50
22. Sp
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
2Jj5J)
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22*50
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20. IS
20.70
20.70
20.70
20.70
20. 7Q
20.70
20.70
20.70
20.70
20. 70
20.70
20.70
20.70
20.70
20.70
19624900
19335200
19045600
18756000
18466400
18176700
17887100
17597500
17307800
17018204
14884900
14595200
14305600
14016000
)3726300
11986000
11696400
11406800
11117100
10827500
8424400
8134700
7845100
7555500
7265800
6976200
6686600
6396900
6107300
5817700
TOTAL
NET
SALES
REVENUE,
S/YEAR
1113900
1113900
1113900
1113900
1113900
1113900
1113900
1113900
1113900
1J13900
794100
794100
794100
794100
794100
557100
557100
557100
557100
557100
239400
239400
239400
239400
239400
239400
239400
239400
239400
239400
382987400 20289000
14.02 0.74
6.01 0.32
66.75 3.53
1316.11 69.72
136941100 7907100
DISCOUNTED PROCESS COST OVER LIFE OF
12.86 0.74
5.51 0.32
61.23 3.53
1206.53 69.67
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
$ S
18511000
18221300
17931700
17642100
17352500
17062800
16773200
16483600
16193900
15904300
14090800
13801100
13511500
13221900
12932200
11428900
11139300
10849700
10560000
10270400
8185000
7895300
7605700
7316100
7026400
6736800
6447200
6157500
5867900
5578300
362698400
13.28
5.69
63.22
1246.39
129034000
POWER UNIT
12.12
5.19
57.70
1136.86
18511000
36732300
54664000
72306100
89658600
106721400
123494600
139978200
156172100
172076400
186167200
199968300
213479800
226701700
239633900
251062800
262202100
273051800
283611800
£93882200
302067200
309962500
317568200
324884300
33J9107J10
338647500
345094700
351252200
357120100
362698400
-------
TABLE A-43. WELLMAN-LORD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, fee'ders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
SC>2 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
4
4
1
4
2
8
5
32
1
34
34
2
4
1
8
8
52
5
6
63
1
65
458,
,376,
,352,
,136,
,894,
,641,
,161,
,600,
895,
,513,
,951,
,464,
154,
,618,
,233,
555,
,748,
,420,
,956,
,715,
,289,
,214,
,275,
,778,
42,
,540,
,360,
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
1
12
12
3
14
7
23
16
2
93
5
99
0
100
6
1
13
4
25
25
151
15
18
184
0
4
188
.3
.6
.6
.3
.1
.6
.6
.2
.6
.9
.6
.5
.5
.0
.4
.6
.7
.1
.8
.2
.0
.1
.1
.2
.1
.4
.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.
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.
196
-------
TABLE A-44. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
6,300 tons 103.00/ton
1,800 liters 2.50/liter
3,240 tons 15.00/ton
70 tons 189.00/ton
47,500 man-hr 12.50/man-hr
648,900
4,500
48,600
13,200
715,200
593,800
3.63
0.03
0.27
0.07
4.00
3.32
1,556,600 MBtu
5,092,500 kgal
77,369,900 kWh
48,400 MBtu
8,500 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
3,113,200
611,100
2,243,700
(96,800)
2,072,500
144,500
8,682,000
9,397,200
17.40
3.42
12.54
(0.54)
11.58
0.81
48.53
52.53
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
3,826,700
5,621,000
1,405,400
59,400
268.700
11,181,200
20,578,400
21.39
31.42
7.85
0.33
1.50
62.49
115.02
Byproduct Sales Revenue
100% sulfuric acid 100,100 tons
Sodium sulfate 8,000 tons
Net average annual revenue requirements
25.00/ton
100% H2S04
23.00/ton
(2,502,500)
(184,000)
17,891,900
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
5.11
11.93
0.57
514
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $34,618,000; total depreciable investment, $63,778,000; and total
capital investment, $65,360,000.
All tons shown are 2,000 Ib.
197
-------
TABLE A-45
WELLMAN-LORD/ 5ULFURIC AGIO PROCESS BASE CASE: 500 MM 3.5% S, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 65360000
vo
CO
YEARS ANNUAL
AFTER OPERA-
POMER TIONt
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
B 7000
9 7000
JO 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
20 35PO
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
2B 1500
29 1500
30 1500
TOT 127500
LIFETIME
PROCESS COST
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS,
/YEAR /YEAR TONS/YEAR
31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
31500000
22500000
22500000
22500000
22500000
22500000
15750000
15750000
15750000
15750000
lb750pOQ
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
1500000
1500000
1500000
1500000
1500000
1500000
1500000
1500000
1500000
1500000
1071400
1071400
1071400
1071400
1071400
750000
750000
750000
750000
750000
321400
321400
321400
321400
321400
321400
321400
321400
321400
321400
34800
34800
34800
34800
34800
34800
34800
34800
34800
34BOO
24800
24800
24800
24800
248 Oil
17400
17400
17400
17400
1740.4
7500
7500
7500
7500
75 Oil
7500
7500
7500
750U
7504
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04 NA2S04
100100
100100
100100
100100
100100
100100
100100
100100
100100
100100
71500
71500
71500
71500
7150q
50100
50100
50100
50100
5Q100
21500
21500
21500
21500
21500
21500
21500
21500
21500
21500 _
573750000 27321000 634000 1824000
AVERAGE INCREASE (DECREASE) IN UNIT OPtRATING COST
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
8000
8000
8000
8000
8000
8000
8000
8000
8000
8000
5700
5700
5700
5700
5700
4000
4000
4000
4000
4000
1700
1700
1700
1700
1700
1700
1700
1700
1700
1700
145500
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100% COMPANY,
H2S04 NA2S04 J/YEAR
22.50
22.50
22.50
22.50
.22,50
22.50
22.50
22.50
22.50
££«5Q
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
_£2j5J>
22.50
22.50
22.50
22.50
2?>S
-------
TABLE A-46. WELLMAN-LORD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5.0% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
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
561,000
4,376,000
4,352,000
1,136,000
4,894,000
3,465,000
11,034,000
7,571,000
1,174,000
38,563,000
2,314,000
40,877,000
154,000
41,031,000
2,371,000
590,000
5, 466^000
1,615,000
10,042,000
10,215,000
61,288,000
6,113,000
7,354,000
74,755,000
42,000
1,982,000
76,779,000
1.4
10.7
10.5
2.8
11.9
8.4
26.9
18.5
2.9
94.0
5.6
99.6
0.4
100.0
5.8
1.5
13.3
3.9
24.5
24.9
149.4
14.9
17.9
182.2
0.1
4.8
187.1
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 storagej 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.
199
-------
TABLE A-47. WELLMAN-LORD/SULPURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
9,690 tons 103.00/ton
2,770 liters 2.50/liter
3,240 tons 15.00/ton
108 tons 189.00/ton
51,020 man-hr 12.50/man-hr
998,100
6,900
48,600
20.400
1,074,000
637,800
4.70
0.03
0.23
0.10
5.06
3.00
2,168,500 MBtu
7,730,300 kgal
93,882,000 kWh
74,400 MBtu
9,130 man-hr
2. 00 /MBtu
0.1 2 /kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
4,337,000
927,600
2,722,600
(148,800)
2,457,200
155,200
11,088,600
12,162,600
20.44
4.37
12.83
(9.70)
11.58
0.73
52.25
57.31
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
4,485,300
6,603,000
1,625,100
63,800
413,300
13,190,500
25,353,100
21.14
31.11
7.66
0.30
1.95
62.16
119.47
Byproduct Sales Revenue
1007. sulfuric acid 154,000 tons
Sodium sulfate 12,300 tons
Net average annual revenue requirements
25.00/ton
100% H2S04
23.00/ton
(3,850,000)
(282,900)
21,220,200
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
6.06
14.15
0.67
397
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, 53,500 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $41,031,000; total depreciable investment, $74,755,000; and total
capital investment, $76,779,000.
All tons shown are 2,000 Ib.
200
-------
TABLE A-48
WELLMAN-LORDX SULFURIC ACID PROCESS VARIATION FROM BASE CASE: s.oss s, REGULATED co. ECONOMICS
TOTAL CAPITAL INVESTMENT
76779000
KJ
O
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
10 7000
11 5000
12 5000
13 5000
1+ 5000
15 5000
16 3500
17 3500
18 3500
19 3500
go 3500
21 1500
22 1500
23 1500
24 1500
f5 1500
26 1500
27 1500
28 1500
29 1500
_3fl }500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZEO
SULFUR BY-PRODUCT
REMOVED RATE.
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT. CONSUMPTION. CONTROL
MILLION 6TU TONS COAL PROCESS. 100%
/YEAR /YEAR TONS/YEAR H2S04 NA2S04
31500000 1500000 53500 154000
31500000 1500000 53500 15+000
31500000 1500000 53500 154000
31500000 1500000 53500 154000
3.15.0DOOO J500000 53504 154000
31500000 1500000 53500 154000
31500000 1500000 53500 154000
31500000 1500000 53500 154000
31500000 1500000 53500 154000
31500000 1500000 53504 154000
22500000 1071400 38200 110000
22500000 1071400 36200 110000
22500000 1071+00 38200 110000
22500000 1071400 38200 110000
22504)000 1071400 36204 110000 ..
15750000 750000 26800 77000
15750000 750000 26800 77000
15750000 750000 26800 77000
15750000 750000 26800 77000
15750000 750000 26804 7700Q
6750000 321400 11500 33000
6750000 321400 11500 33000
6750000 321400 11500 33000
6750000 321400 11500 33000
6759000 32149Q 1150J1 33000
6750000 321400 11500 33000
6750000 321400 11500 33000
6750000 321400 11500 33000
6750000 321400 11500 33000
6754000 3.214QO 1150^1 33000
12300
12300
12300
12300
12300
12300
12300
12300
12300
12300
8800
8800
8800
8800
aaoo
6100
6100
6100
6100
6100
2600
2600
2600
2600
2600
2600
2600
2600
2600
2600
573750000 27321000 975000 2805000 223500
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 11.6* TO INITIAL YEAH. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL 8URi\EO
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
J/TON ROI FOR
POWER
100% COMPANY.
H2S04 NA2SO+ I/YEAR
22.50
22.50
22.50
22.50
22t50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
2?. 50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
_22j5J
22.50
22.50
22.50
22.50
22.50
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
2Qt7J>
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.7Q
20.70
20.70
20.70
20.70
20.70
315+3000
3111+400
30685800
30257200
29828600
29400000
28971500
28542900
28114300
27685700
23812400
23383800
22955200
22526600
2209BOOO
18988600
18560100
18131500
17702900
17274304
13014500
12585900
12157300
11728700
11300104
10871500
104+3000
10014400
9585800
9157204
TOTAL
NET
SALES
REVENUE.
S/YEAR
3719600
3719600
3719600
3719600
3719600
3719600
3719600
3719600
3719600
3119600
2657200
2657200
2657200
2657200
2657200
1858800
1858800
1858800
1858800
1858800
796300
796300
796300
796300
796300
796300
796300
796300
796300
796300
612+35200 67739000
22. +2 2. +8
9.61 1.07
106.7+ 11.80
628.14 69.48
220416200 26407400
DISCOUNTED PROCESS COST OVER LIFE OF
20.70 2.48
8.87 1.06
98.56 11.81
580.20 69.52
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER. POWER.
S %
27823+00
2739+800
26966200
26537600
- .2.6.10.? 000 ..
25680+00
25251900
24823300
24394700
23966100
21155200
20726600
20298000
19869+00
... 194*080.0 _
17129800
16701300
16272700
15844100
15+155.Q.Q.
12218200
11789600
11361000
10932400
10503800
10075200
9646700
9218100
8789500
. 83.60.900. ..
544696200
19.9+
8.5+
94.94
558.66
19+008800
POWER UNIT
18.22
7.81
86.75
510.68
27823+00
55218200
8218+400
108722000
134831000
160511+00
185763300
210586600
234981300
2589+7+00
280102600
300829200
321127200
3+0996600
3.60+37+flO
377567200
39+268500
+105+1200
426385300
+41800800
454019000
465808600
477169600
488102000
499605840
508681000
518327700
527545800
536335300
5+4696200
-------
TABLE A-49. WELLMAN-LORD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW existing)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
scrubber to absorber)
SOj absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, drye,r, conveyors, centrifuge, bin, silo,
and feeder)
SC-2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
pond
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
634,000
7,010,000
7,525,000
1,846,000
8,232,000
4,088,000
13,262,000
9,100,000
1,385,000
53,082,000
3,185,000
56,267,000
127,000
56,394,000
2,706,000
674,000
7,114,000
2,057,000
12,551,000
13,789,000
82,734,000
8,261,000
9,928,000
100,923,000
66,000
2,702,000
103,691,000
1.1
12.4
13.3
3.3
14.6
7.2
23.6
16.2
2.5
94.2
5.6
99.8
0.2
100.0
4.8
1.2
12.6
3.6
22.2
24.5
146.7
14.6
17.7
179.0
0.1
4J8
183.9
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.
Investment requirements for fly ash removal and disposal excluded; FED process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
202
-------
TABLE A-50. WELLMAN-LOSD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW existing)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
Unit
cost. $
Total
annual
cost, $
% of average
annual revenue
requirements
12,600 tons 103.00/ton
3,600 liters 2.50/liter
6,480 tons 15.00/ton
140 tons 189.00/ton
67,180 man-hr 12.50/man-hr
1,297,800
9,000
97,200
26,500
1,430,500
839,800
4.41
0.03
0.33
0.09
4.86
2.85
3,113,300 MBtu
10,185,000 kgal
154,140,000 kWh
96,800 MBtu
13,810 man-hr
2.00/MBtu
0.12/kgal
0.028/kWh
2.00/MBtu
17.00/man-hr
6,226,600
1,222,200
4,315,900
(193,600)
2,817,200
234,800
15,462,900
16,893,400
21.13
4.15
14.65
(0.66)
9.56
0.80
52.48
57.34
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
6,459,100
8,917,400
1,945,900
84,000
537,300
17,943,700
34,837,100
21.92
30.27
6.60
0.29
1.82
60.90
118.24
Byproduct Sales Revenue
100% sulfuric acid 200,200 tons
Sodium sulfate 16,000 tons
Net average annual revenue requirements
25.00/ton
100% H2S04
23.00/ton
(5,005,000)
(368,000)
29,464,100
(16.99)
(1.25)
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Milla/kWh burned input S removed
4.21
0.47
424
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, 69,560 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $56,394,000; total depreciable investment, $100,923,000; and total
capital investment, $103,691,000.
All tons shown are 2,000 Ib.
203
-------
TABLE A-51
WELLMAN-LORU/ SULFURIC ACID PROCESS VARIATION FROM 8ASE CASE: 1000MW EXISTING, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 103691000
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION. REQUIREMENT, CONSUMPTION, CONTROL
UNIT' KW-HR/ MILLION BTU TONS COAL PROCESS. 100*
START KW /YEAR /YEAH TONS/YEAR H2S04 NA2S04
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
I/TON ROI FOR
POWER
100* COMPANY.
H2S04 NA2S04 S/YEAR
TOTAL
NET
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
CUMULATIVE
NET INCREASF
(DECREASE)
IN COST OF
POWER,
I
2
3
4
5
6
7
8
9
10
11
u
13
14
15 .
16
17
18
19
21
22
23
24
25 .
26
27
28
29
. 30 _
7000
7000
7000
7000
1000
5000
5000
5000
5000
,.-5.00.0
3500
3500
3500
3500
3590
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 92500
LIFETIME
PROCESS COST
LEVELIZED
63000000 3000000 69600 200200
63000000 3000000 69600 200200
63000000 3000000 69600 200200
63000000 3000000 69600 200200
63000000 3000000 69600 200200
45000000 2142900 49700 143000
45000000 2142900 49700 143000
45000000 2142900 49700 143000
45000000 2142900 49700 143000
4500000(1 2142900 49700 143000
31500000 1500000 34800 100100
31500000 1500000 34800 100100
31500000 1500000 34800 100100
31500000 1500000 34800 100100
31500000 1500000 34804 100100
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
13500000 642900 14900 42900
16000
16000
16000
16000
16000
11400
11400
11400
11400
11400
8000
8000
8000
8000
8000
3400
3400
3400
3400
3400
3400
3400
3400
3400
3400
832500000 39643500 919500 2645500 211000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HtAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HtAT 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
22.50
22.50
22.50
22.50
22.50
_ 22. 5Q
22.50
22.50
22.50
22.50
_ 22.50
20.70
20. 10
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20. 7q
20.70
20.70
20.70
20.70
20.70
20. 70
20.70
20.70
20.70
43890400
43196000
42501700
41807300
41113004
35622500
34928200
34233800
33539500
328451QO
28438500
27744100
27049800
26355400
25661104
19712200
19017800
18323500
17629100
16934800
16240400
15546100
14851700
14157400
13463000
4835700
4835700
4835700
4835700
483.5700
3453500
3453500
3453500
3453500
3453.500
2417900
2417900
2417900
2417900
1035700
1035700
1035700
1035700
1035700
1035700
1035700
1035700
1035700
1035744_
684R02400 63892500
17.27 1.61
7.40 0.69
82.26 7.68
744.76 69.49
279706800 28953400
DISCOUNTED PROCESS COST OVER LIFE OF
15.57 1.61
6.67 0.69
74.15 7.68
671.24 69.48
39054700
38360300
37666000
36971600
36277300
32169000
31474700
30780300
30086000
29391600
26020600
25326200
24631900
23937500
23243200
18676500
17982100
17287800
16593400
15899100
15204700
14510400
13816000
13121700
12427330
620909900
15.66
6.71
74.58
675.27
250753400
POWER UNIT
13.96
5.98
66.47
601.76
39054700
77415000
115081000
152052600
188329900
220498900
251973600
282753900
312839900
342231500
368252100
393578300
418210200
44J147700
465390900
484067400
502049500
519337300
535930700
55J8298QO
567034500
581544900
595360900
608482600
62p90?900
-------
TABLE A-52. WELLMAN-LOED/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW new)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
6
7
1
8
4
12
8
1
51
3
54
55
2
6
2
12
13
80
8
9
98
2
101
624
,853
,324
,802
,026
,001
,943
,882
,356
,811
,109
,920
159
,079
,694
670
,977
,020
,361
,488
,928
,077
,711
,716
69
,626
,411
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
1.
12.
13.
3.
14.
7.
23.
16.
2.
94.
5.
99.
0.
100.
4.
1.
12.
3.
22.
24.
146.
14.
17.
179.
0.
4.
184.
1
4
3
3
6
3
5
1
5
1
6
7
3
0
9
2
6
7
4
5
9
7
6
2
1
8
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.
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.
205
-------
TABLE A-53. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW new)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
Unit
cost, $
Total
annual
cost, $
7. of average
annual revenue
requirements
12,200 tons 103.00/ton
3,480 liters 2.50/liter
6,260 tons 15.00/ton
135 tons 189.00/ton
67,180 man-hr 12.50/man-hr
1,256,600
8,700
93,900
25,500
1,384,700
839,800
4.43
0.03
0.33
0.09
4.88
2.96
3
9
149
,009
,845
,019
93
13
,400
,300
,300
,600
,810
MBtu
kgal
kWh
MBtu
man-hr
2
0
0
2
17
.00 /MBtu
.12/kgal
.028/kWh
,00/MBtu
.00 /man-hr
6
1
4
2
15
16
,018
,181
,172
(187
,750
234
,010
,395
,800
,400
,500
,200)
,800
,800
,900
,600
21
4,
14,
(0.
9.
0,
52.
57,
.22
.17
.71
.66)
,70
.83
.93
.81
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capiLal 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
5,923
8,721
1,912
84
519
17,160
33,555
,000
,300
,700
,000
,300
,300
,900
20.88
30.75
6.74
0.30
1.83
60.50
118.31
Byproduct Sales Revenue
100% sulfuric acid 193,500 tons
Sodium sulfate 15,470 tons
Net average annual revenue requirements
25.00/ton
100% H2S04
23.00/ton
(4,837,500)
(355.800)
28,362,600
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kHh burned input S removed
4.05
9.78
0.47
422
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, 67,240 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $55,079,000 ; total depreciable investment, $98,716,000 ; and total
capital investment, $101,411,000.
All tons shown are 2,000 Ib.
206
-------
TABLE A-54
WELLMAN-LORQ/ SULFURIC ACID PROCESS VARIATION FROM BASE CASE: 1000 MW, fiEGULATEO CO. ECONOMICS
TOTAL CAPITAL INVESTMtNT 101*11000
K>
O
YEARS ANNUAL
AFTER OPERA-
POWER TIONt
UNIT KW-HR/
START KM
1
2
3
4
*!
6
7
8
9
JI)
11
12
13
1*
j«j
16
17
18
19
?o
21
22
23
2*
?")
26
27
26
29
3°
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
J50,p
1500
1500
1500
1500
1500
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR BY-PRODUCT
REMOVED RATE.
POWER UNIT POWER UNIT BY EQUIVALENT
MEAT FUEL POLLUTION TONS/YEAH
REQUIREMENT* CONSUMPTION. CONTROL
MILLION BTU TONS COAL PROCESS? 100%
/YEAR /YEAR TONS/YEAR H2S04 NA2S04
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 67200 193500
60900000 2900000 672.0D 193500
43500000 2071400 48000 138200
43500000 2071400 48000 138200
43500000 2071400 48000 138200
43500000 2071400 48000 138200
43500000 2071400 48000 138200
30450000 1450000 33600 96800
30450000 1450000 33600 96800
30450000 1450000 3J600 96800
30450000 1450000 33600 96800
30450000 1450000 33600 96800
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 14400 41500
13050000 621400 J440J) 41500
15500
15500
15500
15500
15500
15500
15500
15500
15500
15500
11100
11100
11100
11100
11100
7700
7700
7700
7700
7700
3300
3300
3300
3300
3300
3300
3300
3300
3300
3300
1109250000 €2821000 1224000 3525000 282000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PEW KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 11.6* TO INITIAL YEAH. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
S/TOS ROI FOR
POWER
100% COMPANY.
H2S04 NA2S04 S/YEAR
22.50
22.50
22.50
22.50
_2j£j«5_2_
22.50
22.50
22.50
22.50
22.50 _
22.50
22.50
22.50
22.50
22. bO
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
22.50
Si^o
22.50
22.50
22.50
22.50
22.50
20.70
20.70
20.70
20.70
20. 7g
20.70
20.70
20.70
20.70
20. 7J)
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20.70
20,75
20.70
20.70
20.70
20.70
20. 7q
20.70
20.70
20.70
20.70
20.70_
41758300
41192300
40626400
40060400
39494404
38926500
38362500
37796500
37230600
36664600
31444100
30878200
30312200
29746200
29180300
25010200
24444200
23878300
23312300
2274630JL
17075200
16509200
15943200
15377300
J*8ii3gg
14245300
13679400
13113400
12547400
11981500
TOTAL
NET
SALES
REVENUE.
i/YEAR
4674700
4674700
4674700
4674700
46747QO
4674700
4674700
4674700
4674700
*6747QO
3339300
3339300
3339300
3339300
33.39390
2337400
2337400
2337400
2337400
2337400
1002100
1002100
1002100
1002100
1Q02100
1002100
1002100
1002100
1002100
1002100
808350000 85151500
15.30 1.61
6.34 0.67
72.87 7.67
660.42 69.57
291550700 33189500
DISCOUNTED PROCESS COST OVER LIFE OF
14.16 1.61
5.87 0.67
67.43 7.68
611.09 69.57
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER. POWER.
$ $
37083600
36517600
35951700
35385700
34819204
34253800
33687800
33121800
32555900
3)989900
28104800
27538900
26972900
26406900
, £5841000 _
22672800
22106800
21540900
20974900
. 20*0.8900. _
16073100
15507100
14941100
14375200
13809200
13243200
12677300
12111300
11545300
1 0979*01! _
723198500
13.69
5.67
65.20
590.85
258361200
POWER UNIT
12.55
5.20
59.75
541.52
37083600
73601200
109552900
144938600
...179,758.340
214012100
247699900
280821700
313377600
3*5367540
373472300
401011200
427984100
454391000
4S0212J40
502904800
525011600
546552500
567527400
587936340
604009400
619516500
634457600
648832800
66?642000
675885200
688562500
700673800
712219100
723198540
-------
TABLE A-55. WELLMAN-L08D/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% SO, removal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos,' feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
487,000
4,376,000
4,352,000
1,136,000
4,894,000
2,868,000
8,944,000
6,138,000
972,000
34,167,000
2,050,000
36,217,000
154,000
36,371,000
2,271,000
564,000
4,946,000
1,474,000
9,255,000
9,125,000
54,751,000
5,460,000
6,570,000
66,781,000
42,000
1,652,000
68,475,000
1.3
12.0
12.0
3.1
13.5
7.9
24.6
16.9
2.7
94.0
5.6
99.6
0.4
100.0
6.2
1.6
13.6
4.0
25.4
25.1
150.5
15.0
18.1
183.6
0.1
4.5
188.2
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.
208
-------
TABLE A-56. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% S02 removal)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
7,180 tons 103.00/ton
2,050 liters 2.50/liter
3,240 tons 15.00/ton
80 tons 189.00/ton
47,500 man-hr 12.50/man-hr
739,500
5,100
48,600
15,100
808,300
593,800
3.94
0.03
0.26
0.08
4.31
3.16
1,714,900 MBtu
5,774,800 kgal
81,641,400 kWh
55,100 MBtu
8,500 man-hr
2. 00 /MBtu
0.12 /kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
3,429,800
693,000
2,367,600
(110,200)
2,177,600
144,500
9,296,100
10,104,400
18.28
3.69
12.62
(0.59)
11.61
0.77
49.54
53.85
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
4,006,900
5,888,900
1,458,000
59,400
306,000
11,719,200
21,823,600
21.36
31.38
7.77
0.32
1.63
62.46
116.31
Byproduct Sales Revenue
100% sulfuric acid 114,000 tons
Sodium sulfate 9,110 tons
Net average annual revenue requirements
25.00/ton
100% H2S04
23.00/ton
(2,850,000)
(209,500j
18,764,100
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
5.36
12.51
0.60
474
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, 39,620 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,371,000; total depreciable investment, $66,781,000; and total
capital investment, $68,475,000.
All tons shown are 2,000 Ib.
209
-------
TABLE A-57
WELLMAN-LORD/ SULFURIC ACID PROCESS VARIATION FROM BASE CASE: 90* S REMCVAL. RE6ULATEO CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 68475000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HP/
START KW
1
2
3
4
5
7000
7000
7000
7000
7000
6 7000
7 7000
8 7000
9 7000
1.0. JOHO
11
12
13
. 14
IS
16
17
18
19
?ft
21
22
23
24
?^
26
27
28
29
39
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TOT 127bOO
LIFETIME
PROCESS COST
LEVELIZED
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
MEAT FUEL POLLUTION
REQUIREMENT. CONSUMPTION. CONTROL
MILLION BTU TONS COAL PROCESS.
/YEAR /YEAR TONS/YEAR
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31501)000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500000 1500000
31500(109 1500000
22500000 1071400
22500000 1071400
22500000 1071400
22500000 1071400
225000QD 1Q71400
15750000 750000
15750000 750000
15750000 750000
15750000 750000
15750000 750.QOO
6750000 321400
6750000 321400
6750000 321400
6750000 321400
6750001) 321400
6750000 321400
6750000 321400
6750000 321400
6750000 321400
6750000 32140Q
34600
39600
J9600
39600
396 OD
39600
39600
39600
39600
39600
28300
28300
2B300
28300
2830J)
19800
19800
19800
19800
19801)
8500
8500
8500
8500
850J1
8500
8500
8500
8500
8501)
8Y-HRODUCT
RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04 NA2S04
114000
114000
114000
114000
U4Q40
114000
114000
114000
114000
1J4MO
81400
8140Q
81400
81400
8141)0 _
57000
57000
57000
57000
5.7000
24400
24400
24400
24400
24400
24400
24400
24400
24400
24400
9100
9100
9100
9100
9JOO
9100
9100
9100
9100
9100
6500
6500
6500
6500
6,500
4600
4600
4600
4600
4600
2000
2000
2000
2000
2000
2000
2000
2000
2000
2000
573750000 27321000 721500 2076000 166500
AVERAGE INCREASE (DECREASE) IN UNIT OPtRATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR RtMOVED
DISCOUNTED AT 11.6% TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100% COMPANY,
H2S04 NA2S04 S/YEAR
22.50
22.50
22.50
22.50
- 22.54
22.50
22.50
22.50
22.50
-_2i«iS_
22.50
22.50
22.50
22.50
_12j5_g_
22.50
22.50
22.50
22.50
2?t5(J
22.50
22.50
22.50
22.50
_£2_i5J2
22.50
22.50
22.50
22.50
22.50
20.70
20.70
20.70
20.70
__ 20. 74
20.70
20.70
20.70
20.70
_2JUZ2-
20.70
20.70
20.70
20.70
20.75
20.70
20.70
20.70
20.70
20.7Q
20.70
20.70
20.70
20.70
20. 7fl
20.70
20.70
20.70
20.70
20.70
27406500
27023600
26640800
26257900
25875004
25492100
25109300
24726400
24343500
23960700
20717700
20334800
19951900
19569100
19,l£6i5JL
16571200
16188300
15B05500
15422600
15039701)
11450200
11067300
10684400
10301500
991870D
9535800
9152900
8770100
8387200
8004301)
TOTAL
NET
SALES
REVENUE,
S/YEAR
2753400
2753400
2753400
2753400
2753400
2753400
2753400
2753400
2753400
2753400
1966100
1966100
1966100
1966100
1966100
1377700
1377700
1377700
1377700
1377700
590400
590400
590400
590400
590400
590400
590400
590400
590400
590400
532895200 50157000
19.50 1.83
8.36 0.79
92.88 8.74
738.59 69.51
191409700 19548600
DISCOUNTED PROCESS COST OVER LIFE OF
17.97 1.83
7.70 0.78
85.59 8.74
680.69 69.52
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
24653100
24270200
23887400
23504500
23 I 2i 655
22738700
22355900
21973000
21590100
2120735P
18751600
18368700
17985800
17603000
1722Q15Q
15193500
14810600
14427800
14044900
136^2.0J)0.
10859800
10476900
10094000
9711100
__212&3_ap.
8945400
8562500
8179700
7796800
7413900
482738200
17.67
7.57
84.14
669.08
171861100
POWER UNIT
16.14
6.92
76.85
611.17
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
24653100
48923300
72810700
96315200
1J94J68DO
142175500
164531400
186504400
208094500
2293gj(JUO
24H053400
266422100
284407900
302010900
3J 9231500
334424500
349235100
363662900
377707800
39.13£2a_QO
402229600
412706500
422800500
432511600
44J.S3..29_0.0
450785300
459347800
467527500
475324300
48.27J8_2J10
-------
TABLE A-58. WELLMAN-LORD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four direct oil-fired reheaters)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfurie acid production)
Acid storage (storage and shipping facilities for 30-day production
of sulfurie 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
311,000
3,908,000
4,213,000
1,063,000
1,577,000
4,603,000
3,158,000
534,000
19,367,000
1,162,000
20,529,000
1,868,000
467,000
3,070,000
954,000
6,359,000
5,378,000
32,266,000
3,227,000
3,872,000
39,365,000
27,000
987,000
40,379,000
1.5
19.0
20.5
5.2
7.7
22.4
15.4
2.6
94.3
5.7
100.0
9.1
2.3
15.0
4.6
31.0
26.2
157.2
15.7
18.9
191.8
0.1
4.8
196.7
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.
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.
211
-------
TABLE A-59. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
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
2,780 tons 103.00/ton
790 liters 2.50/liter
2,740 tons 15.00/ton
31 tons 189.00/ton
45,440 man-hr 12.50/man-hr
286,300
2,000
41,100
5,900
335,300
568,000
2.39
0.02
0.34
0.05
2.80
4.74
2
2
53
,467
501
,322
,159
21
8
,400
,300
,000
,700
,300
,130
gal
MBtu
kgal
kWh
MBtu
man— hr
0
2.
0
0
2,
17
.40/gal
. 00/MBtu
.12/kgal
.029/kWh
.00/MBtu
.00 /man-hr
1
1
1
5
6
987,
,002,
278,
,541,
(42,
,231,
138,
,705,
,040,
000
600
700
600
600)
700
200
200
500
8.
8,
2.
12,
(0.
10.
1.
47,
50,
.23
.36
.32
.85
.35)
.27
.15
.57
.37
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
2,519,400
3,472,600
969,000
56,800
118,400
7,136,200
13,176,700
21.01
28.95
8.08
0.47
0.99
59.50
109.87
Byproduct Sales Revenue
100% sulfuric acid
Sodium sulfate
Net average annual revenue requirements
44,100 tons 25.00/ton (1,102,500) (9.19)
100% H2S04
3,530 tons 23.00/ton (81,200) (0.68)
11,993,000 100.00
Equivalent unit revenue requirements (net)
$/bbl oil $/MBtu heat $/ton
Mills/kWh burned input S removed
3.43
2.24
0.37
782
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, 15,330 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $20,529,000; total depreciable investment, $39,365,000; and total
capital investment, $40,379,000.
All tons shown are 2,000 Ib.
212
-------
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213
-------
TABLE A-61. WELLMAN-LOSD/SULFURIC ACID PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: wet-scrubbing fly ash removal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
SC>2 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Fly ash removal (four scrubbers and entrainment separators,
tanks, agitators, and pumps)
ESP credit
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
SC>2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
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 excluding pond
Pond
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
458,000
4,642,000
4,352,000
1,136,000
5,296,000
(4,713,000)
2,641,000
8,161,000
5,600,000
895,000
28,468,000
1,708,000
30,176,000
154,000
30,330,000
2,233,000
555 ,000
4,255,000
1.284,000
8,327,000
7,731,000
46,388,000
4,623,000
5,567,000
56,578,000
42,000
1,558,000
58,178,000
1.5
15.3
14.3
3.7
17.5
(15.5)
8.7
26.9
18.5
3.0
93.9
5.6
99.5
0.5
100.0
7.4
1.8
14.0
4.2
27.4
25.5
152.9
15.2
18.4
186.5
0.1
5.2
191.8
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.
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.
214
-------
TABLE A-62. WELLMAN-LORD/SULFURIC ACID PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: wet-scrubbing fly ash removal)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
ESP electricity credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
6,300 tons 103.00/ton
1,800 liters 2.50/liter
3,240 tons 15.00/ton
70 tons 189.00/ton
47,500 man-hr 12.50/man-hr
648,900
4,500
48,600
13,200
715,200
593,800
3.75
0.02
0.28
0.08
4.13
3.43
1,556,600 MBtu
5,092,500 kgal
113,923,900 kWh
48,400 MBtu
7,114,900 kWh
8,500 man-hr
2. 00 /MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
0.029/kWh
17.00/man-hr
3,113,200
611,100
3,303,800
(96,800)
(206,300)
1,815,200
144.500
9,278,500
9,993,700
17.98
3.53
19.09
(0.56)
(1.19)
10.49
0.83
53.60
57.73
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
3,394,700
5,003,300
1,276,800
59,400
268,700
10,002,900
19,996,600
19.61
28.91
7.38
0.34
1.55
57.79
115.52
Byproduct Sales Revenue
100% sulfuric acid 100,100 tons
Sodium sulfate 8,000 tons
Net average annual revenue requirements
25.00/ton
100% H2S04
23.00/ton
(2,502,500)
(184.000)
17,310,100
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.95
11.54
0.55
498
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $30,330,000; total depreciable investment, $56,578,000; and total
capital investment, $58,178,000.
All tons shown are 2,000 Ib.
215
-------
TABLE A-63
WELLMAN-LORD/ SULFURIC ACID PROCESS VARIATION FROM BASE CASEl WET SCRUBBING F-LV ASH REMOVAL* REGULATED CO, ECONOMICS
TOTAL CAPITAL INVtSTMENT JHIMOOO
to
YEARS ANNUAL POWER UNIT
AFTER OPERA- HEAT
POWER TIQN, REQUIREMENT/
UNIT KW-HR/ MILLION BTU
START KW /YEAR
1 7000 31500000
2 7000 31500000
3 7000 31500000
4 7000 31500000
_ 5 _ 2000 aiSQQQOQ...
6 7000 31500000
7 7000 31500000
8 7000 31500000
9 7000 31500000
10 20QQ 315QQQQO
11 5000 22500000
12 5000 22500000
13 5000 22500000
1* 5000 22500000
IS 5000 225QOQQQ _.
16 3SOO 15750000
17 3SOO 15750000
18 3500 15750000
19 3500 15750000
20 3500 _15250QQQ
21 1500 6750000
22 1SOO 6750000
23 1900 6750000
24 1300 6750000
«1SOQ 6250000
26 1500 6750000
27 1500 6750000
28 1500 6750000
29 1500 6750000
_30 1900 67.300.00—.
TOTAL
SULUJR BY-PRODUCT DP. COST
REMOVED RATE* INCLLOING NET ANNUAL CUMULATIVE
POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TUNS/YEAR */TON RCI FCR NET (DECREASE) (DECREASE)
CONSUMPTION, CONTROL POWER SALES IN COST OF IN COST OF
TUNS COAL PROCESS, 100* 100» CCMPAhY, REVENUE/ POWER, POWER/
/YEAR TONS/YEAR H2S04 NA2SO* H250* NA2SO* */YEAR $/YEAR t *
1500000 34800 100100 8000 22.50 20.70 2*731300 2*17900 22313*00 22313*00
1500000 3*800 100100 8000 22.50 20,70 2**06900 2*17900 21989000 **302*00
1500000 3*800 100100 8000 22.50 20,70 2*082600 2*17900 2166*700 65967100
1500000 3*800 100100 aOOO 22.50 20.70 23758200 2*17900 213*0300 87307*00
- --15QQQQQ 348QQ_-_JLOQlaO dQOO— 22»5fl__-2Q»20— 23433BQ0...2412SQQ 21Qi52QQ 1QS3233QO
1500000 3*800 100100 8000 22.50 20.70 23109*00 2*17900 20691500 12901*800
1500000 3*600 100100 8000 22.50 20.70 22785100 2*17900 20367200 1*9382000
1500000 3*800 100100 8000 22.50 20,70 22*60700 2*17900 200*2800 169*2*800
1500000 3*800 100100 8000 22,50 20.70 22136300 2*17900 19718*00 1891*3200
1JQQQQQ .34800— 1QQ10Q aQQa__-22»5Q___2a»20— 218U2QQ___24122QQ 123240QQ 20flS32200
1071*00 2*800 71500 5700 22,50 20.70 1865*900 1726800 16928100 225*65300
1071*00 2*800 71500 5700 22.50 20.70 18330500 1726800 16603700 2*2069000
1071*00 2*800 71500 5700 22,50 20.70 18006100 1726800 16279300 2583*8300
1071*00 2*800 71500 5700 22.50 20.70 176B1700 1726800 1595*900 27*303200
- --1Q214.QQ 24BQO 215QQ 3200— 22*50— 20*20—12352400. __lZ26flOQ 1563Q6.QQ 289.93380.0
750000 17*00 50100 *000 22.50 20.70 1*832600 1210100 13622500 303556300
750000 17*00 50100 *000 22.50 20.70 1*508200 1210100 13298100 316854*00
750000 17*00 50100 *000 22.50 20.70 1*183800 1210100 12973700 329828100
750000 17*00 50100 *000 22.50 20,70 13859500 1210100 126*9*00 3*2*77500
- _— 250QQU 124QQ 5Q1QQ 4QOQ_._Zi*aa._. 20*20— 13533100— .121QIQQ 12325QQQ 354802800
321*00 7500 21500 1700 22,50 20.70 10075200 519000 9556200 36*358700
321*00 7500 21500 1700 22,50 20.70 9750800 519000 9231800 373590500
321*00 7500 21500 1700 22.50 20.70 9*26500 519000 8907500 382*98000
321*00 7500 21500 1700 22.30 20.70 9102100 519000 8583100 391081100
3214QQ 2500 215QQ 1IQQ 22*50. _ 20»2Q- ..82222QQ 512QOQ 8258200 32S339800
321*00 7500 21500 1700 22.50 20.70 6*53300 519000 7934300 40727*100
321*00 7500 21500 1700 22,50 20.70 8129000 519000 7610000 *1*884100
321*00 7500 21500 1700 22.50 20.70 780*600 519000 7285600 422169700
321*00 7500 21500 1700 22.50 20.70 7*80200 519000 6961200 *29130900
- . 32i4QO 25QQ 215QQ 120Q— 22.50.. 2U.2Q 21558QQ 5i200Q 6636800 4352622QO
TOT 127500 573750000 27321000 63*000 182*000 1*5500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTJ HEAT INPUT
DOLLARS PER TON UF SJLFUK REMOVED
PROCESS Ct T DISCOUNTED AT 11.6X TO INITIAL YEAR/ DOLLARS
LEVELIZL INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
MILLS PER KILDWATT-H3UR
CENTS PER MILLION BTJ HEAT INPUT
OOLIARS PER TON UF SULFUR REMOVED
479821200 **053500 *35767700
7,53 0.69 6.8*
83,63 7,68 75.95
756,82 69,*9 687.33
172986*00 17167600 155818800
DISCOUNTED PROCESS CCSI OVER LIFE OF POWER UNIT
6,96 0.69 6.27
77,35 7,68 69.67
700,35 69,50 630.85
IHN215I CONVERT - ILLEGAL DECIMAL CHARACTER S
SODIUM CARBONATE 6300TONS 103,00/TUN 1.0
TRACEBACK ROUTINE CALLED FROM ISN REG, 14 REC. 15 REG, 0 KEU. 1
IBCOM OOOBF910 OOOCB1EL OOQOOOOF OOObFuf*
-------
TABLE A-64. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW existing)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (two absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
305,000
1,952,000
1,902,000
504,000
2,153,000
1,534,000
4,544,000
4,024,000
377,000
17,295,000
1,038,000
18,333,000
31,000
18,364,000
1,590,000
397,000
2,803,000
877,000
5,667,000
4,806,000
28,837,000
2,881,000
3,460,000
35,178,000
16,000
925,000
36,119,000
1.7
10.6
10.4
2.7
11.7
8.4
24.7
21.9
2.1
94.2
5.6
99.8
0.2
100.0
8.6
2.2
15.2
4.8
30.8
26.2
157.0
15.7
18.9
191.6
0.1
5.0
196.7
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.
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.
217
-------
TABLE A-65. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE. REQUIREMENTS
(Variation from base case: 200 MW existing)
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
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
2,660 tons 103.OO/ton
1,370 tons 15.00/ton
30 tons 189.00/ton
14,010 tons 60.00/ton
30,040 man-hr 12.50/man-hr
274,000
20, 600
5,700
840.600
1,140,900
375,500
2.46
0.18
0.05
7.55
10.24
3.37
335,100 gal
662,600 MBtu
1,699,100 kgal
32,658,000 kWh
78,400 MBtu
4,480 man-hr
0.40/gal
2. 00 /MBtu
0.12 /kgal
0.031/kWh
2. 00 /MBtu
17.00/man-hr
134,000
1,325,200
203,900
1,012,400
(156,800)
1,284,200
76,200
4,254,600
5,395,500
1.20
11.90
1.83
9.09
(1.41)
11.53
0.68
38.19
48.43
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
Sulfur 13,800 tons
Sodium sulfate 3,380 tons
Spent anthracite 7,200 tons
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
2,462,500
3,106,200
868,000
37,600
81,000
6,555,300
11,950,800
40.00/ton (552,000)
23.00/ton (77,700)
25.00/toti (180,000)
11,141,100
$/ton coal $/MBtu heat
Mills/kWh burned input
7.96 17.59 0.84
22.10
27.88
7.79
0.34
0.73
58.84
107.27
(4.95)
(0.70)
(1.62)
100.00
$/ton
S removed
759
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, 14,680 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $18,364,000; total depreciable investment, $35,178,000; and total
capital investment, $36,119,000.
All tons shown are 2,000 Ib.
218
-------
TABLE A-66
VO
WELL 'A.i-LORD/RESnx PROCESS VARIATION FKJM BASE CASE: 200 MW EXISTING, REGULATED co, ECONOMICS
TOTAL CAPITAL INVESTMENT
36119000
YEARS ANNUAL
AFTErt JPERA-
PDW£P TIUN,
UNIT KW-HR/
START M
1
2
3
4
6
7
8
9
11 5000
12 SuOO
13 Soon
14 Soon
16 3300
17 3500
IB 3500
19 3500
.20 aaoo...
21 1500
22 1530
23 1300
.25 15QQ-.
26 1300
27 1500
2b 1100
29 1JOO
.3u 1203..
POl'ER UNIT
HEAT
REQUIRE lEI-iT,
HILLIUJ 3TU
/YEAR
9500000
9500000
9500030
25QCQQO .
6650000
6650000
6650000
665JOOO
ZH5UOOO
2850000
2850000
2850000
2S5,iJQQQ
2d5000p
2350000
235 JOOO
TOTAL
SULFUR BY-PRODUCT DP, COST
REMOVED RATE, INCLUDING NET ANNUAL CUMULATIVE
PCMER 'JNIT BY EQUIVALENT NET RfiVfcNUE, REGULATED TOTAL INCREASE NET INCREASE
FUEL PPLLUTIUN TONS/YEAR */TQN ROI FOR NET (DECREASE) (DECREASE)
CONSUMPTION, CONTROL POWER SALES IN COST OF IN COST OF
TCMS ClUL PkQCESS, HA2S04 t HA2S04 £ COMPANY, REVENUE, POWER, POWER,
/YtAk mjs/YHAR SULFUR SP, ANT, SULFUR SP, ANT, WYEAR $/YEAR $ *
452*30
452*00
452*00
452*00
316700
3167QO
316700
316700
3167.QQ
135700
1357.JO
135700
135700
. .-1357.20.
135700
135701)
135700
135700
10500 9900 7600 36,00 21,93 14039000 523100 13515900 13515900
10500 9900 7600 36,00 21,93 13736400 523100 13213300 26729200
10500 9900 7600 36.00 21.93 13433900 523100 12910800 39640000
10500 9900 7600 36.00 21,93 13131400 523100 12608300 522483QO
laaQQ 23QQ 26012 36*00 21*33 128211800 5231QQ-.__123Q52QQ 64554000
7*00 6900 5300 36.00 21,93 11331400 364600 10966800 75520800
7300 6900 5300 36. 00 21,93 11028900 364600 10664300 86185100
7300 6900 5300 36,00 21,93 10726400 364600 10361800 96546900
7300 6900 5300 36, yO 21,93 10423800 364600 10059200 106606100
2300 6300 53QQ— .3&*QQ_-_21»S3--_101213QO 36460Q..___32562QQ 116362800
3100 3000 2300 30,00 21,93 8087200 158400 7928800 124291600
3100 3000 2300 36.00 21,93 7784600 158400 7626200 131917800
3100 3000 2300 36,00 21,93 7482100 158400 7323700 139241900
3100 3000 2300 36,00 21,93 7179600 158400 7Q21200 146262700
-31QQ 32QQ 2300 3Q»QQ 21*33 6822000 15B4QO 62186QQ 152961300
3100 3000 2300 36.00 21,93 6574500 158400 6416100 159397400
3100 30UO 2300 36,00 21,93 6272000 15840P 6113600 165511000
3100 3000 2300 36.00 21,93 5969400 158400 5811000 171322000
3100 3000 2300 30,00 21,93 5666900 158400 5508500 176830500
3100 3QUQ 23Qu 3t»»OQ.__21»33 5364400 15a4QQ_.._.52Q6QQQ 182036500
TOT 57300 1092*0000 5202300 121)000 114000 87503
AVERAGE IMCRtASF (TECRSASE) Is! UNIT OPERATING COST
C'CktASS PE< TO 4 DF C3AL BURNED
188Q59000 6022500 182036500
PROCESS COS
LtVCLIZE
36,15 1,16 34,99
16,35 0,52 15,83
CENTS PER MILLION BTJ HEAT INPUT 172.14 5.52 166,62
H'JLLARS PEK TO'I OF SJLFUK REMOVED 1567,16 50.19 1516,97
T TISCUUNTE) AT 11,b» TO INITIAL YEAR, DQLL4RS 85255200 2975000 82280200
D INCREAS£ (IifcCRFASt) IJ UNIT jPERATInG COST EQUIVALENT Tu DlbCUUnTED PROCESS COST OVER LIFE OF POWER UNIT
iJLLAKS PH3 T04 GF CJAL bJRNED 33,13 1.16 31,97
ULLS PfR KILDJ4TT.H3'JR 14.99 0.52 14,47
;t>iTi PER .IILLION BTJ HFAT I»PUT 157.77 5.50 152.27
PER TOJ UF SJuFUR RE'IOVEI) 1432,86 50.00 1382.86
-------
TABLE A-67. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW new)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, ' feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (two absorbers and entrainment separators, tanks,
pomps, filters, agitators, and heat exchangers)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
301,000
1,908,000
1,858,000
493,000
2,104,000
1,503,000
4,444,000
3,936,000
369,000
16,916,000
1,015,000
17,931,000
56,000
17,987,000
1,588,000
395,000
2,756,000
863,000
5,602,000
4,718,000
28,307,000
2,825,000
3,397,000
34,529,000
16,000
902,000
35,447,000
1.7
10.6
10.3
2.7
11.7
8.4
24.7
21.9
2.1
94.1
5.6
99.7
0.3
100.0
8.8
2.2
15.4
4.8
31.2
26.2
157.4
15.7
18.9
192.0
0.1
5.0
197.1
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.
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.
220
-------
TABLE A-68. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW new)
Annual Unit
quantity cost, $
Direct Costs
Raw materials
Sodium carbonate 2,580
Agricultural limestone 1,320
Filter aid 29
Anthracite coal 13,570
Total raw materials cost
Conversion costs
Operating labor and supervision 30,040
Utilities
Fuel oil 324,600
Steam 641,700
Process water 1,645,500
Electricity 31,649,000
Heat credit 76,000
Maintenance
Labor and material
Analyses 4,480
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
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
Sulfur 13,400
Sodium sulfate 3,270
Spent anthracite 7,000
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189. 00 /ton
tons 60.00/ton
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu
kgal 0.12/kgal
kWh 0.031/kWh
MBtu 2.00/MBtu
man-hr 17.00 /man-hr
tons 40.00/ton
tons 23.00/ton
tons 25.00/ton
$/ton
Total % of average
annual annual revenue
cost, $ requirements
265,700
19,800
5,500
814.200
1,105,200
375,500
129,800
1,283,400
197,500
981,100
(152,000)
1,256,800
76,200
4,148,300
5,253,500
2,071,700
3,048,400
854,200
37,600
78,600
6,090,500
11,344,000
(536,000)
(75,200)
(175,000)
10,557,800
coal $/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements (net)
7.54 17.
22 0.82
2.52
0.19
0.05
7.71
10.47
3.56
1.23
12.16
1.87
9.29
(1.44)
11.90
0.72
39.29
49.76
19.62
28.88
8.09
0.36
0.74
57.69
107.45
(5.08)
(0.71)
(1.66)
100 . 00
$/ton
S removed
742
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, 14,220 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $17,987,000; total depreciable investment, $34,529,000; and total
capital investment, $35,447,000.
All tons shown are 2,000 Ib. 991
-------
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-------
TABLE A-70. WELLMAN-LOED/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500 MW existing)
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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 , $
463,000
4,442,000
4,426,000
1,153,000
4,977,000
2,678,000
8,432,000
7,398,000
652,000
34,621,000
2,077,000
36,698,000
123,000
36,821,000
2,356,000
586,000
4,996,000
1,488,000
9,426,000
9,249,000
55,496,000
5,537,000
6,660,000
67,693,000
41,000
1,956,000
69,690,000
% of
total direct
investment
1.3
12.1
12.0
3.1
13.5
7.3
22.9
20.1
1.8
94.1
5.6
99.7
0.3
100.0
6.4
1.6
13.6
4.0
25.6
25.1
150.7
15.0
18.1
183.8
0.1
5.4
189.3
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.
223
-------
TABLE A-71. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500 MW existing)
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
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
j,440 tons 103.00/ton
3,310 tons 15.00/ton
72 tons 189.00/ton
33,920 tons 60.00/ton
47,500 man-hr 12.50/man-hr
663,300
49, 700
13,600
2,035,200
2,761,800
593,800
3.06
0.23
0.06
9.37
12.72
2.74
S^-,400 gal
1,604,200 MBtu
4,113,600 kgal
78,217,000 kWh
189,900 MBtu
8,500 man-hr
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
324,600
3,208,400
493,600
2,268,300
(379,800)
2,205,600
144,500
8,859,000
11,620,800
1.50
14.78
2.27
10.45
(1.75)
10.16
0.66
40.81
53.53
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
Sulfur 33,500 tons
Sodium sulfate 8,180 tons
Spent anthracite 17,500 tons
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
4,332,400
5,993,300
1,472,000
59,400
196,600
12,053,700
23,674,500
40.00/ton (1,340,000)
23.00/ton (188,100)
25.00/ton (437,500)
21,708,900
$/ton coal $/MBtu heat
Mills/kWh burned input
6.20 14.16 0.67
19.96
27.61
6.78
0.27
0.90
55.52
109.05
(6.17)
(0.87)
(2.01)
100.00
$/ton
S removed
611
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, 35,550 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,821,000; total depreciable investment, $67,693,000; and total
capital investment, $69,690,000.
All tons shown are 2,000 Ib.
224
-------
Ln
TABLE A-72
WELL.iAx-LfJRD/ RFSOX PPJttii VARIATION f*QV SASfc tASF.I 500 t «J EXISTING* REGULATED CO, ECONOMICS
TOTAL CAPITAL INVESTMENT 69690000
SULFUR PY-PRIJOUCT
REMOVED RATE,
YEARS ANNUAL PU^ER uc IT PCMER >JMIT SSY EQUIVALENT
AFTEU cjPi.:RA- HEAT FUEL POLLUTIIJN TUNS/YEAR
POv-E* Tjjii, RECUI"F,h'Lr T, CONSUMPTION* CruTRCL
UNIT KW-HR/ MILlini, MTU THNS COAL PROCESS* NA2S04 £
START KR /YEA.< /YEAH TONS/YEAR SULFUR SP, ANT.
i
2
3
ii
__a_- ____. ... . . -_ _ _
6 7000 32200000 1533300 35600 33500 25700
7 7000 3220000C 1533300 35600 33500 25700
8 7000 32200000 1533 H'O 35600 333no 25701
9 7oOO 32200000 15333CO 35600 335uO 25700
_1Q 2UQQ -222CUQQQ _1522iaQ 35600- 3.35UQ 25200
11 5'JOO 7.3000000 1095200 25400 23900 1&300
12 5000 23000000 1095200 25400 239^0 18300
13 5v,oo 23000000 1095200 25400 23900 18300
14 5'JOo 23000000 1095200 25400 23900 18300
.15 5JOO 23UOUQOO 122520Q 25aQi_ -2320Q 1S3QO
16 3500 16100000 766700 17800 16800 12800
17 35yo 1610JOOO 766700 17800 16BoO 12800
lb 350U 16100000 766700 17800 16800 12300
19 35-jfi i6tOT030 7667JO 17600 168OO 12800
-2U - -3aUQ - -1S12U030 - - ZaiJJQ 1Z&QQ 16.SQQ '282Q
21 UOO 6900030 323600 /6QO 7200 550T
22 I5')0 6900000 320600 7600 72uO 5500
23 ISO.) 6900000 32(1600 7600 72uO 5500
24 15QO 690)000 32fli)0 7600 72oO 5500
.25 150Q &2QUQOQ 223iaQ 2600- 22UQ _ 55L1U
26 1SOO 6900000 328600 7600 7200 5500
27 1300 6903000 328630 7600 7200 5500
2b liOO D900QOO 326oOO 7600 7200 5500
29 1500 6900000 32iiooo 7600 72oO 5500
_3Q 1520 __&12C-uJC . __22aaflO_- ...__2SiOiJ---__22JU -5502—
TOT 92300 *23aOOOOO 232o2 000 47nnoO 4't30oO 339003
LIFETIME AVERAGE INCPKASF (DECREASE) rt UNIT OPEKATMG CCST
OOLL«"S PER TON OF CJAL oURNED
| ILLS PER KILOWATT. HJUR
CtNTS MfcR MILL UJU BTU H£i\T IdPUT
uil.'LLARS PER TON OF SJLFIJH REMOVED
PRC/CfSS COST OISCQWiTFO AT 11,6% TQ I'lirjAL vfAK* Ori|,LrtRS
LtVFLlZED INCKEASi. 1,,'fcCREASE) IN UNIT J4PEKATI'"G COST EQUIVALENT TO
liULLoRS PER TUN OF CJAL liJRfiED
:1ILL5 PLR K!LnuATT-H3UR
CbhTS PFR MILLI1N BTJ HFAT INPUT
U'JLL«''S PER TON OF SJLFU" REMOVED
TOTAL
OP. CCST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE* REGULATED TOTAL INCREASE NET INCREASE
*/TDM RCI FOR NET (OECREASE) (DECREASE}
POUER SALES IN COST OF IN COST OF
i
-------
TABLE A-73. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2.0% sulfur)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
SC-2 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystalllzer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
SC-2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
318,000
4,376,000
4,352,000
1,136,000
4,894,000
1,619,000
4,826,000
4,264,000
397,000
26,182,000
1,571,000
27,753,000
154,000
27,907,000
2,140,000
532,000
3,971,000
1,205,000
7,848,000
7,151,000
42,906,000
4,275,000
5,149,000
52,330,000
44,000
1,253,000
53,627,000
1.2
15.7
15.6
4.1
17.5
5.8
17.2
15.3
1.4
93.8
5.6
99.4
0.6
100.0
7.7
1.9
14.2
4.3
28.1
25.6
153.7
15.4
18.4
187.5
0.2
4.5
192.2
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.
226
-------
TABLE A-74. WELLMAN-LORD/RESOX 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
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
Total raw materials cost
2,900 tons 103.00/ton
3,240 tons 15.00/ton
32 tons 189.00/ton
15,270 tons 60.00/ton
298,700
48,600
6,000
916,200
1,269,500
1.91
0.31
0.04
5.86
8.12
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
42,550 man-hr 12.50/man-hr
531,900
365,200 gal
946,900 MBtu
1,954,300 kgal
60,417,000 kWh
85,500 MBtu
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
7,610 man-hr 17.00/man-hr
3.40
0.94
12.12
1.50
11.21
(1.09)
10.68
0.83
39.59
47.71
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
3,139,800
4,611,900
1,165,600
53,200
88,600
9,059,100
16,515,200
20.09
29.51
7.46
0.34
0.56
57.96
105.67
Byproduct Sales Revenue
Sulfur 15,100 tons
Sodium sulfate 3,680 tons
Spent anthracite 7,900 tons
Net average annual revenue requirements
40.00/ton
23.00/ton
25.00/ton
(604,000)
(84,600)
(197,500)
15,629,100
3.87
0.54
1.26
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.47
10.42
0.50
977
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, 16,000 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $27,907,000; total depreciable investment, $52,330,000; and total
capital investment, $53,627,000.
All tons shown are 2,000 Ib.
227
-------
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I
-------
TABLE A-76. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
SO- regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit" for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
458,000
4,376,000
4,352,000
1,136,000
4,894,000
2,641,000
8,307,000
7,289,000
643,000
34,096,000
2,046,000
36,142,000
154,000
36,296,000
2,352,000
585,000
4,938,000
1,472,000
9,347,000
9,129,000
54,772,000
5,462,000
6,573,000
66,807,000
44,000
1,920,000
68,771,000
1.3
12.0
12.0
3.1
13.5
7.3
22.9
20.1
1.8
94.0
5.6
99.6
0.4
100.0
6.5
1.6
13.6
4.1
25.8
25.1
150.9
15.1
18.1
184.1
0.1
5.3
189.5
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.
229
-------
TABLE A-77. WELLMAN-LOBD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
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
6,300 tons
3,240 tons
70 tons
33,180 tons
103.00/ton
15.00/ton
189.00/ton
60.00/ton
47,500 man-hr 12.50/man-hr
793,800 gal
1,569,400 MBtu
4,024,300 kgal
76,531,800 kWh
185,800 MBtu
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
8,500 man-hr 17.00/man-hr
648,900
48,600
13,200
1,990,800
2,701,500
593,800
317,500
3,138,800
482,900
2,219,400
(371,600)
2,173,100
144,500
8,698,400
11,399,900
3.08
0.23
0.06
9.43
12.80
2.81
1.50
14.87
2.29
10.52
(1.76)
10.30
0.68
41.21
54.01
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
4,008,400
5,914,300
1,455,700
59,400
192,400
11,630,200
23,030,100
28.02
6.90
0.28
0.91
55.10
109.11
Byproduct Sales Revenue
Sulfur
Sodium sulfate
Spent anthracite
32,800 tons
8,000 tons
17,100 tons
Net average annual revenue requirements
40.00/ton
23.00/ton
25.00/ton
(1,312,000)
(184,000)
(427,500)
21,106,600
(6.22)
(0.87)
(2.02)
100.00
$/ton coal $/MBtu heat $/ton
Milla/kWh burned input S removed
Equivalent unit revenue requirements (net)
6.03
14.07
0.67
607
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,296,000; total depreciable investment, $66,807,000; and total
capital investment, $68,771,000.
All tons shown are 2,000 Ib.
230
-------
TABLE A-78
ro
WETLNAi-1-LO.RD/ RFSUX PROCESS BASE CASE! 500 K4 3.5K Si REGULATED CO. ECONOMICS
THTAL CAPITAL INVESTMENT 68771000
YEARS ANNUAL PO»ER UNIT
AFTER UPERA- HEAT
POWER TION, REQUIREMENT,
UNIT KW-HR/ MILLION BTO
START KW /YEAR
1 7000 31500000
2 7000 31500000
3 7000 31500001
4 7000 31500000
5 2JQQ 3.15QQQQQ__.
6 7000 31500000
7 7000 31500000
8 7000 31500000
9 7000 31500000
_1G ZQQQ 3.1500000...
11 5.100 2250000C
12 5000 22500000
13 5000 22500000
1* 5000 2Z500000
.15 5£QQ _ ..2250U2QO
16 3500 15750000
17 3500 15750000
1« 35dO 15750000
19 3500 15750000
_2U 35UQ 15251)000...
21 1500 6750000
22 1500 6750000
23 1500 6750000
24 1500 6753000
.25 1SOQ &Z2U02Q
26 1500 67500DO
27 1500 675000C
28 15QO 6750000
29 1500 6750000
.30 liQQ 6.2522QQ...
TOTAL
SULFJR BY-PRODUCT OP, COST
REMOVED RATE/ INCLUDING NET ANNUAL CUMULATIVE
P'.IHER UNIT BY EQUIVALENT NET RtVgNUE, REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TONS/YEAR S/TQN RCI FOR NET (DECREASE) (DECREASE)
CONSUMPTION, CONTROL POWER SALES IN COST OF IN COST OF
T'INS CHAL PROCESS, NA2SO* £ NA2SQ* £ COMPANY, REVENUE, POWER, POWIR,
/YEAR TUNS/YEAR SULFUR SP. ANT. SULFUK SP, ANT, */YEAR $/YEAR $ *
isooooo 3*iioo izaoo 25100 55, oo 21, 51 21752260 1731206 27021660 27621600
1500000 3*800 32BOO 25100 36, 00 21,93 28369200 1731200 26638000 536S9000
1500000 34BOO 32800 25100 36.00 21,93 27986200 1731200 26255000 7991*000
1500000 34800 32800 25100 36,00 21,93 27603100 1731200 25871900 105785900
15QQOOQ 24200 32BUQ. 1251QQ __3&»OQ._ 21*33 22220100 1221200 . 2S&3&SQQ 13122&BQQ
1500000 3*800 32800 25100 36,00 21,93 26837100 1731200 251059QO 156380700
1500000 34800 32800 25100 36,00 21,93 2645*100 1731200 24722900 181103600
1500000 34300 32800 25100 36,00 21,93 26071000 1731200 24339800 205**3*00
1500000 34800 32800 25100 36,00 21,93 25688000 1731200 23956800 229400200
15000QQ 24.200 32800 l2510.fi _3&»QO;_ 21*23 2S3Q5QQQ 1Z312QQ . 235Z3&QQ 252224000
1071-iQO 248QO 23400 17900 36,00 21,93 21691800 12349QO 20456900 27343Q900
1071400 24800 23400 17900 36.00 21,93 213C8800 1234900 20073900 29350*800
1071400 24800 23400 17900 36,00 21,93 20925800 1234900 1969Q900 313195700
1071'ino Z*BOO 23400 17900 36.00 21,93 20542800 123*900 193079QO 332503600
. .1021400 KtiiUQ 23.4.QQ '1220Q 3b*QQ 21*93 2C152200 1234200 1BS2&&QQ 351428*00
750000 17400 16400 12600 36,00 21,93 " 17266900~~~ 866700 16*00200 367828600
750100 17400 16400 12600 36,00 21,93 16883900 866700 16017200 383845800
750000 17400 16400 12600 36,00 21,93 16500900 866700 15634200 399480000
750000 17400 16400 12600 36,00 21,93 16117800 866700 15251100 41*731100
252QQQ 12400. .16400 °12&UQ _36»QO_. 21*33 15Z3.4BQQ B6.62QQ . 14B.&S1QO 4235SS200
321400 7500 7000 5400 36.00 21,93 11775700 370*00 11*05300 **100*SOO
321400 7500 7000 5400 36,00 21,93 11392600 370*00 11022200 *52026700
321400 7500 7000 5*00 36.00 21,93 11009600 370*00 10639200 *6266590C
321400 7500 7000 5400 30.00 21,93 10626600 370400 10256200 472922100
321iQO 25UO 2Qi2Q_ 1.54Q2 36*23 21*33. 1Q243&QQ 22Q4QO . 2B232QQ 4fl22SS3Qt
321-tOO 7500 7000 5*00 36.00 21,93 9860500 370*00 9*90100 *92285*00
321430 7500 70UO 5400 36.00 21,93 9*77500 370*00 9107100 501392500
321'00 7500 7000 5*00 3o.OO 21,93 909*500 370*00 872*100 510116600
321400 7500 7000 5400 36,00 21,93 8711500 370*00 83*110.0 518457700
22142Q 2SOQ 2QUQ__l_a4QC__-36*OQ.__21*23. _ 8326400. _ 320400— _2i5BQQQ_ 526419ZOO
TOT 127500 573751000 27321000 63*000 597000 457500
LIFETIME AVERAGE IMCMASF (i)FCREiSE) H UNIT OPERATING CHST
DOLLARS PER TUl) OF C3AL SiED
"ILLS PFR KILOWATT-HJUR
CENTS PER MILLION BTJ HEAT JilPUT
UHLLAKS PEK ron ur SJLFUR REMOVED
PROCESS CF3ST OISCQUI'TED AT 11.68 TO INITIAL YEAR, DOLLARS
557939700 3152*000 526*15700
20,42
8,75
97,24
880,03
201015300
1.15
0.49
5,49
49,72
12289*00
LtVELlZFO INCktASE (PFCREASE) IN UNIT 3PCRATIf,G COST EQUIVALENT TO DliCGU'iTfcD PROCESS COS'TOVER LIFE C1F
iHLLAFS PFR THN OF C3AL »URM6U 18,88 1,16
".ILLS PFk KILt'WATT.HDUR 8.09 0.5P
CINTi PEK MILLION BTJ HEAT INPUT 89,88 5,49
''t'LLARS PEP TDM OF SULFUr RFt.OVEn 813,83 49,76
19,27
8,26
91,75
H30.31
188725900
POWER UNIT
17,72
7,59
8*. 39
764,07
-------
TABLE A-79. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5.0% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
and pumps)
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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 01,UUU
4,376,000
4,352,000
1,136,000
4,894,000
3,465,000
11,231,000
9,811,000
840,000
40,666,000
2,440,000
43,106,000
154,000
43,260,000
2,528,000
629,000
5,711,000
1,682,000
10,550,000
10,762,000
64,572,000
6,442,000
7,749,000
78,763,000
44,000
2,564,000
81,371,000
1. 3
10.1
10.1
2.6
11.3
8.0
26.0
22.7
1.9
94.0
5.6
99.6
0.9
100.0
5.8
1.5
13.2
3.9
24.4
24.9
149.3
14.9
17.9
182.1
0.1
5.9
188.1
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.
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.
232
-------
TABLE A-80. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 9,690
Agricultural limestone 3,240
Filter aid 110
Anthracite coal 51,030
Total raw materials cost
Conversion costs
Operating labor and supervision 51,020
Utilities
Fuel oil 1,220,900
Steam 2,189,700
Process water 6,087,400
Electricity 92,593,000
Heat credit 285,700
Maintenance
Labor and material
Analyses 9,130
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 8.6%
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
Sulfur 50,400
Sodium sulfate 12,300
Spent anthracite 26,300
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189. 00 /ton
tons 60.00/ton _3_
4
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu 4
kgal 0.12/kgal
kWh 0.029/kWh 2
MBtu 2.00/MBtu
2
man-hr 17.00/man-hr
11
15
4
6
1
13
29
tons 40.00/ton (2
tons 23.00/ton
tons 25.00/ton
26
998,100
48,600
20,800
.061,800
,129,300
637,800
488,400
,379,400
730,500
,685,200
(571,400)
,591,000
155,200
,096,100
,225,400
,725,800
,997,900
,692,000
63,800
295,600
,775,100
,000,500
,016,000)
(282,900)
(657,500)
,044,100
$/ton coal $/MBtu heat
Equivalent unit revenue requirements (net)
Mills/kWh burned
7.44 17.36
input
0.83
3.83
0.19
0.08
11.76
15.86
2.45
1.87
16.81
2.80
10.31
(2.19)
9.95
0.60
42.60
58.46
18.15
26.87
6.50
0.24
1.13
52.89
111.35
(7.74)
(1.09)
(2.52)
100.00
$/ton
S removed
487
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, 53,500 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $43,260,000; total depreciable investment, $78,763,000; and total
capital investment, $81,371,000.
All tons shown are 2,000 Ib. 233
-------
TABLE A-81
WELL<>HN-LORO/ RESQX PROCESS VARIATION FROM BASE CASEl 5,0% St REGULATED CD, ECONOMICS
TOTAL CAPITAL INVESTMENT
N>
YEARS ANHUAL POWER UNIT
AFTE« OPERA- HEAT
POWER TION, REQUIREMENT,
UNIT KW-HR/ MILLION BTU
START KW /YEAR
1 7000 31500000
2 7uOO 31500000
3 7oOO 31500000
* 7JOO 31500000
it 22QQ .315QQQQQ— .
6 7000 3150000?
7 7000 31500000
8 7UOO 31500000
9 7000 31500000
1Q 2uQQ .315QQQQQ— .
11 5000 22500000
1Z 5UOO 22500000
13 5000 22500000
1* 5000 2250UOOO
15 SUQQ 2250UQOO _.
16 3500 15750000
17 3500 15750000
18 3500 15750000
19 3500 15750000
2Ci 3500 1525QQJQ
21 1500 6750000
22 1500 6750000
23 1500 6750000
24 1500 6750000
25 1500 6.25UQQQ— .
26 1500 6750000
27 1SOO 67500OO
28 1500 6750000
29 1500 675UOOO
.30 _ _15DO 62SQCQD...
TOTAL
SULFUR BY-PRODUCT OP, COST
REMOVED RATE/ INCLUDING NET ANNUAL CUMULATIVE
POrtFR UNIT 9Y EQUIVALENT NET RfcVfcNUE* REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TONS/YEAR i/TOM RC1 FOR NET (DECREASE) (DECREASE)
CONSUMPTION* CONTROL POWER SALES IN COST OF IN COST OF
TONS COAL PROCESS* NA2SO* £ NAzSO* t CCMPANY, REVENUF., POWER, POWER,
/YEAR TONS/YEAR SULFUR SP, ANT, SULFUR SP, ANT, I/YEAR */YEAR * »
1500000 53500 50*00 38600 36.00 21,93 35703000 2660900 330*2T5o 330*IlOO
1500000 53500 50*00 38600 36,00 21,93 35251400 2660'OP 325905QO 65632600
1500000 535QO 50*00 38600 36,00 21,93 3*799900 266Q900 32139000 97771630
1500000 53500 50*00 38600 36,00 21,93 3*3*8300 2&60900 316«7*00 129*59000
15QUQUQ —53500 5Q4flQ_.;aa6aQ_—36»UQ— 21*23 33a2&200.__2&6Q9QC 312359QQ lfiQfi24flQO
1500000 53500 50*00 38600 36,00 21,93 J»3**5200 2660900 307^*300 191*79100
1500000 53500 50*00 386QQ 36,00 21,93 32993600 2660900 30332700 221811800
1500000 53500 50*00 38600 36,00 21,93 325*2000 266090" 29891100 251692900
1500000 53500 50*00 33600 30,00 21,93 32090500 2660900 29*29600 281122SOO
15QQJQQ S350Q 504QQ__.l3a&Qa— 36.aa._.2U23 3163B2QQ 26&Q2QQ 2S22SQQQ 310120300
1071*00 38200 36000 Z760Q 36,00 21,93 26868900 190L3QO 2*967600 335068100
1071400 38200 36000 27600 36.00 21,93 26*17*00 1901300 2*516100 35958*200
1071400 38200 36000 27600 36,00 21,93 25965800 1901300 2*06*500 3836*8700
1071
-------
TABLE A-82. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
i-and
Working capital
Total capital investment
634,000
7,010,000
7,525,000
1,846,000
8,232,000
4,088,000
13,499,000
11,757,000
988,000
55,579,000
3,335,000
58,914,000
127,000
59,041,000
2,892,000
720,000
7,389,000
2,130,000
13,131,000
14,434,000
86,606,000
8,648,000
10,393,000
105,647,000
69,000
3,450,000
109,166,000
1.1
11.9
12.7
3.1
13.9
6.9
22.9
19.9
1.7
94.1
5.7
99.8
0.2
100.0
4.9
1.2
12.5
3.6
22.2
24.5
146.7
14.6
17.6
178.9
0.1
5.9
184.9
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.
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.
235
-------
TABLE A-83. WELLMAN-LOKD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW existing)
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
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
12,600 tons 103.00/ton
6,480 tons 15.00/ton
140 tons 189.00/ton
66,360 tons 60.00/ton
67,180 tnan-hr 12.50/man-hr
1,297,800
97,200
26,500
3.981,600
5,403,100
839,800
3.64
0.27
0.08
11.18
15.17
2.36
1,587,600 gal
3,318,700 MBtu
8,048,600 kgal
152,464,000 kWh
371,500 MBtu
13,810 man-hr
0.40/gal
2.00/MBtu
0.12/kgal
0.028/kWh
2.00/MBtu
17. 00 /man-hr
635,000
6,277,400
965,800
4,269,000
(743,000)
2,949,500
234,800
15,428,300
20,831,400
1.78
17.63
2.71
11.99
(2.09)
8.28
0.66
43.32
58.49
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
Sulfur 65,600 tons
Sodium sulfate 16,000 tons
Spent anthracite 34,200 tons
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
6,761,400
9,388,300
2,012,000
84,000
384,700
18,630,400
39,461,800
40.00/ton (2,624,000)
23.00/ton (368,000)
25.00/ton (855,000)
35,614,800
$/ton coal $/MBtu heat
Mills/kWh burned input
5.09 11.87 0.57
18.98
26.36
5.65
0.24
1.08
52.31
110.80
(7.37)
(1.03)
(2.40)
100.00
$/ton
S removed
512
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, 69,560 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $59,041,000; total depreciable investment, $105,647,000; and total
capital investment, $109,166,000.
All tons shown are 2,000 Ib.
236
-------
TABLE A-84
WELL'>Ai.-LOKu/ REjUX i-.'.lftSS VARIATION F^3^ «ASE CASH 1300 MM EXISTING/ REGULATED CQ, ECONOMICS
TUTAL CAPITAL Ifll/ESTME JT 109166000
00
YEARS ANNUAL POWER UNIT
AFTE* ilPERA- HEAT
PQUE" riilN, REdUIREMENTi
UNIT KW-HR/ MIUIOu BTU
START KVI /YEAR
TOTAL
SULFUR BY-PRODUCT OP, COST
RMOVFD RATE, INCLUDING NET ANNUAL CUMULATIVE
PIWER U'JIT BY EQUIVALENT NfcT REVENUE, REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TUNS/YEAR $/TUN RC I FOR NET (DECREASE) (DECREASE)
CONSUMPTION, CONTROL POWER SALES IN COST OF IN COST OF
TDNS CMAL PRJCESS, NA2SO* S .MA2SO* 6 CCMPANY, REVENUE, POWER, PQttER,
/YEAR TOMS/Yfc4R 3ULFUK SP, ANT, bULFUH SP, ANT, S/YEAR $/YEAR * *
1
2
3
4
6 7000 63000000
7 7uOO r,300"000
8 70UO 63000000
9 7000 63000000
-10 2JCO 6.3QDI3QQQ
11 5oOO 45000000
12 5000 45000000
13 5000 45000000
14 5000 45000000
.15. 5.UUQ .^SGOQOQQ _
16 3500 31500000
17 S-'iOO 31500000
IB 3500 31500000
19 3500 31500000
.20 352U 3.1SOQQQC
21 1500 13500000
22 1500 13500000
23 15i)0 13500000
24 1500 iSSOOOOn
25 15.UQ 1350I20QQ
26 1300 13500HOO
27 1500 13500000
28 1500 1350x1000
29 lioo 1350000P
3000000
3000000
3000000
JOOOOOO
- -3.CUQOQQ
2142900
21429QO
2142900
- __21422dQ
1500000
1500000
1500000
1500000
642900
642900
642-510
6a22ao
6liO
69600 65600 50200 36,0'J 21,93 i,9l7C200 3*62500 45707700 45707700
6«600 h5600 50200 36.00 21,93 484*3300 3*62500 4*980800 90688500
69ooO 65600 50200 36.00 21,93 47716400 3*62500 **253900 13*9*2*00
69600 65600 50200 36,00 21,93 46989600 3*62500 *3527100 178*69500
&26UU 656QO__l502Qa— 36.0C— 21»23-__4&26220Q—_34625QQ 42200200 221268200
49700 46900 35900 36.00 21,93 39616300 2*75700 37140600 258410300
49700 46900 35900 36.00 21.93 38889400 2*75700 36413700 29*82*000
49700 »6900 35900 36,00 21,93 33162600 2*75700 356C69QO " 330510900
4*700 46900 35900 36.00 21,93 37*35700 2*75700 3*960000 365*70900
.42200 4&2QQ 35200— 36.Qfl_-.21.23-.-3fi2082QQ...2425200 34233200 3222Q41QO
3*»OC 32800 25100 36.00 21,93 31*22900 1731200 29691700 *29395800
34«00 32800 25100 36.00 21.93 30696000 1731200 2896*800 *583606QO
34bOO 32800 25100 3o,00 21.93 29969200 1731200 28238000 *86598600
34600 32800 25100 36,00 21,93 292*2300 1731200 27511100 51*109700
34&QQ 32auQ___251QQ— 3&»UU_._21*23.__2851S5QQ—_12312QQ 26284300 340824000
1*900 14100 10800 36,00 21,93 21394500 7*4*00 20650100 56l5**100
14900 14100 IOBOO 36.00 21,93 20667700 7***OP 19923300 581*67*00
14900 14100 10SOU 36,00 21,93 1994C800 74*400 19196*00 600663800
14900 1*100 10800 30,00 21,93 1921*000 7***00 18*69600 619133*00
14200 laiQiJ—lluaoa.— 36*Oa..-21.23...ia4821QQ 244400 12242200 636826100
1*900 14100 loBOO 36.00 21,93 17760300 74**00 17015900 653392000
1*900 14100 10800 3o,00 21,93 17033400 7*4*00 16219000 670181000
1*900 14100 10800 36, Oy 21.93 16306500 7***00 15562100 6857*3100
1*900 14100 IOBOO 36.00 21,93 15579700 7*4*00 1*835300 700578*00
_ _„ laauQ laiUQ— laaQO_~3B»QQ_-_21»23-_-l4852aOQ 244400... .14108400 214686800
TOT 1'25UO 83250-'>OOP 3"6*3'iOO Vl'fSOO H675t>0 O64000
LIFETIME AVERAGE lUCf-tASF (HECREASE) I ft U"IT JPf-RftT 11,1. COST
OOLLARb PER T1JN DF CJAL bUR'lED
ULLS PfcR KILCHJATT-HJUR
TR itiLi iw BTJ HEAT I.IPUT
PEK TO!) UF SJLFUK Rtl.QVEP
PRtlCfcSi CUST DISCOU!;TED AT u.6t- ''- IU1TJAL YEA'<, l^ULLARS
LEVELlZFD INCREASE (tiECREASE) IN UNIT 3PfkATI'
-------
TABLE A-85. WELLMAlf-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW new)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
624,000
6,853,000
7,324,000
1,802,000
8,026,000
4,001,000
13,175,000
11,487,000
968,000
54,260,000
3,256,000
57,516,000
159,000
57,675,000
2,876,000
716,000
7,249,000
2,092,000
12,933,000
14,122,000
84,730,000
8,457,000
10,168,000
103,355,000
72,000
3,349,000
106,776,000
1.1
11.9
12.7
3.1
13.9
7.0
22.8
19.9
1.7
94.1
5.6
99.7
0.3
100.0
5.0
1.2
12.6
3.6
22.4
24.5
146.9
14.7
17.6
179.2
0.1
5.8
185.1
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.
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.
238
-------
TABLE A-86. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW new)
Annual
quantity
Unit
coat, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
Total raw materials cost
12,200 tons
6,260 tons
135 tons
64,150 tons
103.00/ton
15.00/ton
189.00/ton
60.00/ton
1,256,600
93,900
25,500
3,849,000
5,225,000
3.66
0.27
0.08
11.22
15.23
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
67,180 man-hr 12.50/man-hr
839,800
2.45
1,534,700 gal
3,034,000 MBtu
7,780,200 kgal
147,399,000 kWh
359,100 MBtu
13,810 man-hr
0.40/gal
2. 00 /MBtu
0.12/kgal
0.028/kWh
2.00/MBtu
17.00/man-hr
613,900
6,068,000
933,600
4,127,200
(718,200)
2,880,600
234,800
14,979,700
20,204,700
1.79
17.69
2.72
12.03
(2.09)
8.40
0.68
43.67
58.90
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
6,201,300
9,182,700
1,977,600
84,000
371,900
17,817,500
38,022,200
18.08
26.77
5.77
0.24
1.08
51.94
110.84
Byproduct Sales Revenue
Sulfur
Sodium sulfate
Spent anthracite
63,400 tons
15,470 tons
33,100 tons
Net average annual revenue requirements
40.00/ton
23.00/ton
25.00/ton
(2,536,000)
(355,800)
(827,500)
34,302,900
(7.39)
(1.04)
(2.41)
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.90
11.83
0.56
510
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, 67,240 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $57,565,000; total depreciable investment, $103,355,000; and total
capital investment, $106,776,000.
All tons shown are 2,000 Ib.
239
-------
TABLE A-87
«ELLi''A!J_LQRD/ RESUX PROCESS VARIATION ROM BASE CASE! 1000 BW, REGULATED CL. ECONOMICS
TOTAL CAPITAL INVESTMENT 106776000
YEARS ANHUAL POWER UNIT
AFTE& fJPeRA- MEAT
POWER TIONj REQUIREMENT
UNIT Krf-HR/ MILLION BTU
START M /YEAR
1 7000 t>o90»M500
2 7000 6090UOOO
3 7000 60900000
4 7000 60900000
£ ZuQQ _6,Q2QQQ.QQ_
6 7JOO 60900000
7 7000 60900000
8 7000 60900000
500UO
24 1500 13050000
2i laQO _1305UGQQ_
26 1300 13050000
27 1300 13050000
26 1300 13Q50000
29 1500 13050000
3u liGQ __l205iaOQ_
TOTAL
SULFUR BY-PRODUCT DP. CGST
REMOVED RATE/ INCLINING NFT ANNUAL CUMULATIVE
POWER UNIT BY EQUIVALENT NET HEVHNUE* REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TUNS/YEAR */TW RCI FOR NET (DECREASE) (DECREASE)
, CONSUMPTION, CONTROL P0WER SALES IN COST OF IN CUST OF
TONS COAL PROCESS* NA2S04 £, NA2SO* £ CCMPANY, REVENUE* POWER, POWER,
/YEAR TUNS/YEAR SULFUR SP, ANT. SULFUK SP, ANT. t/YEAR */YEAR * *
1900000 67200 63400 486(10 3<>7oO 2l793 4*833500 1348200 ~~*3*S5300 4348S300
2900000 67200 63400 48600 3ft 00 21,93 *62*0900 3348200 42892700 86378000
2900000 67200 63400 48600 36.00 21,93 45648300 334820" 42300100 128678100
2900000 67200 63400 4B60P 36.00 21,93 43055700 3348200 41707500 170385600
22QQ JQQ — -.62200 634QQ-__4a6UC— 36»aa... 21*23__-444632QQ_-- 324820Q 4111SQOQ ZilSOfiftQO
2900000 67ZOO 63400 48600 36.00 21,93 43870600 3348200 40522400 252023000
2900000 67200 63400 48600 36.00 21.93 43278000 3348200 39929800 291952800
2900000 67200 63400 48600 3b.OQ 21,93 42685500 3348200 39337300 331290100
2900000 67200 63400 48600 36.00 21,93 42092900 3348200 38744700 37003*800
2200000 . . 6229.0 63iOO-.lfta&Oi}...a&*QQ.— 2i*23..-aiSOB2Q0...334B2QD 3&1S21QQ 40818680.0
2071400 48000 45300 34700 36.00 21,93 35166400 23918QO 32774600 440961SOO
2071400 4BOOO 45300 34700 36.00 21,93 3*573900 2391800 32182100 4731*3600
2071400 4BOOO 45300 34700 36.00 21,93 33981300 2391800 31589500 50*733100
7071400 48000 45300 34700 36.00 21,93 33388700 23918QO 30996900 535730000
20214QQ SBQQO 45300— l3ft2QQ 36.22 21.23 322S61QO 2321BOD ""43QD i"««g°
1450000 33600 31700 24300 36,00 21,93 27780400 167410P 26106300 592240600
1450000 33600 31700 24300 36.00 21,93 27187800 1674100 25513700 61775*300
1*50000 33600 31700 24300 30.00 21,93 2*595200 1674100 2*921100 642675*00
!450000 33600 31700 24300 36.00 21.93 2*002600 1674100 2*328500 667003900
1450000 33600 312aQ__l243Qa_— 3fe*UO— 21»22.._2541Q1QQ_— 1624100 23236QQQ 620238800
" 621*00 14400 13600 104QO 36.00 21,93 186C9900 717700 17892200 70B632JOO
6214QO 14400 13600 10400 J&.OO 21,93 18017300 717700 17299600 725931700
621'»00 14400 13600 10400 36.00 21,93 H424700 717700 16707000 7*2638700
621-.00 144QO 13600 10*00 36.03 21,93 16832200 717700 1611*500 7587S3200
62iaao 14400 13600—110402— 36.00— 21.23...1623S6QO 212200 15521200 22422S100
671400 1*400 13600 10400 SiS.OO 21.93 15647000 717700 14929300 78920*400
6214JO 14400 13600 10401 36,00 21,93 15054400 717700 1*336700 8035*1100
621400 1*400 13600 10400 36.00 21,93 1*461900 717700 13744200 817285300
621400 1*400 13600 10400 36.00 21,93 13869300 7177QO 13151600 830436900
621400 14400 1360Q-_:i0402— 36»ua._. 21.23...132262QO 21220Q 1255SQOQ 842285800
TOT 127JQ1 111)9250000 52821000 1224000 1155000 88500C
LIFETIME % TO INITIAL YEAR, DOLLARS
IMCRfcASr tr»bCRFAS*> 1U UNIT JPE'K'ATIHG COST EQUIVALENT Ti)
HOLLARS PER TON UF C3AL BURNED
• •ILLS PER KILOUATT-HJUR
CENTS PFR MILLI3N BT'J HEAT INPUT
UflLLARS PER TON UF SJLFUR REMOVED
9039B44QO 60988500 842995900
17.11 1.15 15,96
7,09 0,4» 6,61
81,50 5,50 76,00
738,55 49,83 688,72
327446000 23771700 303674300
PROCESS COST OVER LIFE OF P1WER UNIT
15.90 1.1! 1*,75
6,59
75.73
686.33
0.4B
5.50
49.83
6.11
70,23
636,50
-------
TABLE A-88. WELLMAN-LORD/RESOX PROCESS
SUMMARY OP ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% S02 removal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services,, utilities, and miscellaneous
Total excluding pond
Pond
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
487,000
4,376,000
4,352,000
1,136,000
4,894,000
2,868,000
9,104,000
7,974,000
697,000
35,888,000
2,153,000
38,041,000
154,000
38,195,000
2,399,000
597,000
5,151,000
1,530,000
9,677,000
9,574,000
57,446,000
5,729,000
6,894,000
70,069,000
44,000
2,085,000
72,198,000
1.3
11.5
11.4
3.0
12.8
7.5
23.8
20.9
1.8
94.0
5.6
99.6
0.4
100.0
6.2
1.6
13.5
4.0
25.3
25.1
150.4
15.0
18.0
183.4
0.1
5.5
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.
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.
241
-------
TABLE A-89. WELLMAN-LOBD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% SO, removal)
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Anthracite coal
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
7,180 tons 103.00/ton
3,240 tons 15.00/ton
80 tons 189.00/ton
37,800 tons 60.00/ton
47,500 man-hr 12.50/man-hr
739,500
48,600
15,100
2,268,000
3,071,200
593,800
3.30
0.22
0.06
10.13
13.71
2.65
904,300 gal
1,729,800 MBtu
4,558,000 kgal
80,687,000 kWh
211,600 MBtu
8,500 man-hr
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
361,700
3,459,600
547,000
2,339,900
(423,200)
2,287,100
144,500
9,310,400
12,381,600
1.62
15.45
2.44
10.45
(1.89)
10.21
0.65
41.58
55.29
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
Sulfur 37,400 tons
Sodium sulfate 9,110 tons
Spent anthracite 19,500 tons
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
4,204,100
6,209,000
1,512,700
59,400
219,300
12,204,500
24,586,100
40.00/ton (1,496,000)
23.00/ton (209,500)
25.00/ton (487,500)
22,393,100
$/ton coal $/MBtu heat
Mills/kWh burned input
6.40 14.93 0.71
18.77
27.73
6.76
0.26
0.98
54.50
109.79
(6.68)
(0.93)
(2.18)
100.00
$/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, 1,500,100 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Sulfur removed, 39,620 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $38,195,000; total depreciable investment, $70,069,000; and total
capital investment, $72,198,000.
All tons shown are 2,000 Ib.
242
-------
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243
-------
TABLE A-91. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four direct oil-fired reheaters)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
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
311,000
3,908,000
4,213,000
1,063,000
1,577,000
4,685,000
4,140,000
387,000
20,284,000
1,217,000
21,501,000
1,937,000
484,000
3,191,000
988,000
6,600,000
5,620,000
33,721,000
3,372,000
4,047,000
41,140,000
28,000
1,156,000
42,324,000
1.5
18.2
19.6
4.9
7.3
21.8
19.2
1.8
94.3
5.7
100.0
9.0
2.3
14.8
4.6
30.7
26.1
156.8
15.7
18.8
191.3
0.1
5.4
196.8
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.
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.
244
-------
TABLE A-92. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 2,780
Agricultural limestone 2,740
Filter aid 31
Anthracite coal 14,630
Total raw materials cost
Conversion costs
Operating labor and supervision 45,440
Utilities
Fuel oil 2,799,400
Steam 508,200
Process water 1,851,200
Electricity 52,790,000
Heat credit 81,900
Maintenance
Labor and material
Analyses 8,130
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 14,400
Sodium sulfate 3,530
Spent anthracite 7,500
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 60.00/ton _
1
man-hr 12.50/man-hr
gal 0.40/gal 1
MBtu 2.00/MBtu 1
kgal 0.12/kgal
kWh 0.029/kWh 1
MBtu 2.00/MBtu
1
man-hr 17. 00 /man-hr _
5
6
2
3
7
14
tons 40.00/ton
tons 23.00/ton
tons 25.00/ton
13
$/bbl oil
Milla/kWh burned
3.86 2.52
286,300
41,100
5,900
877.800
,211,100
568,000
,119,800
,016,400
222,100
,530,900
(163,800)
,290,100
138.200
,721,700
,932,800
,633,000
,639,900
998,200
56,800
84,500
,412,400
,345,200
(576,000)
(81,200)
(187,500)
,500,500
$/MBtu heat
input
0.42
2.12
0.31
0.04
6.50
8.97
4.21
8.29
7.53
1.64
11.34
(1.21)
9.56
1.02
42.38
51.35
19.50
26.96
7.40
0.42
0.63
54.91
106.26
(4.27)
(0.60)
(1.39)
100.00
$/ton
S removed
881
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, 15,330 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $21,501,000; total depreciable investment, $41,140,000; and total
capital investment, $42,324,000.
All tons shown are 2,000 Ib.
245
-------
TABLE A-93
WELL'IAU-LORD/ RESOX PROCESS VARIATION FR3M BASE CASEI UIL FIRED EXISnui, Kfc(,ULATED CO, ECONOMICS
TOTAL CAPITAL INVESTMENT 4232*000
YEARS ANNUAL
AFTER QPERA-
POWE* TIHN,
UNIT KW-HR/
START KW
POWER UNIT
HEAT
REQUIREMENT,
MILLION BTU
/YEAR
POWER UNIT
FUEL,
CONSUMPTION,
BARRELS OIL
/YEAR
SULFUR
REMOVED
8Y
POLLUTION
CONTRfJL
PROCESS,
TONS/YEAR
TOTAL
BY-PRODUCT OP, COST
RATE, INCLUDING NET ANNUAL CUMULATIVE
EaUIVALENT N6T RgVtNUE, REGULATED TOTAL INCREASE NET INCREASE
TUNS/YEAR I./TI.I-: ROI FOR NET (DECREASE) (DECREASE)
PUWER SALES IN crm OF IN COST OF
NA2SO* & NA2S04 £ COMPANY, REVENUE, POWER, POhER,
SP, ANT, SOLFUn SP, ANT, WYEAR t/YEAR t *
SULFUR
1
2
3
4
—5.
6
7
8
9
.10-
12
13
-15.
16
17
18
19
-20-
21
22
23
24
.25-
26
27
28
29
-30-
7000
7000
7000
7000
.200.0.
5000
5UOO
SOOO
SOQO.
3500
3500
3500
3500
3500.
1500
1500
1500
1500
1500.
1500
1500
1300
1500
.1200.
32200000
32200000
32200000
32200000
.322QQQQQ.
23000000
23000000
23000000
23000000
_23flQi)OQQ.
1610JOOO
16100000
16100000
16100000
6900000
6900000
6900000
6900000
6200000.
6900000
6900000
6900000
6900000
62QDQQQ.
532*100
532*100
5324100
532*100
52241QO.
3*02900
3802100
3802'JOO
3802900
3&Q22QQ.
2662500
2662000
2662000
2662000
26620.00-
1140000
1140'JOO
ll'VO'JOO
114Q20Q.
11*0''00
11*0^00
11*0900
11*0900
11402DQ-
15300
15300
15300
15300
-152QQ--.
UOOO
11000
11000
11000
-11QOQ—
7700
7700
7700
7700
.-2200—
3300
3300
3300
3300
—3300—
3300
3300
3300
3300
„ 3300 —
14*00
1*400
1**00
14400
.144UQ-.
10300
10300
10300
10300
.122UQ-.
72JO
7200
7200
7200
-22UQ-.
3100
3100
3130
3100
-31DQ —
3100
3100
3100
3100
11000
11003
liooo
liooo
7900
7900
7900
1.28QQ
5500
5500
5500
5500
1_55Q2_
2400
2400
2400
2400
L.24QQ
2400
2400
2400
2400
30.00
36. UO
36.03
3».CO
.3
-------
TABLE A-94. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: alternate conversion in sulfur production unit)
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur),
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
458,000
4,376,000
4,352,000
1,136,000
4,894,000
2,641,000
8,976,000
7,906,000
643,000
35,382,000
2,123,000
37,505,000
154,000
37,659,000
2,395,000
595,000
5,091,000
1,513,000
9,594,000
9,451,000
56,704,000
5,655,000
6,8X14,000
69,163,000
44,000
2,033,000
71,240,000
1.2
11.6
11,6
3.0
13.0
7.0
23.9
21.0
1.7
94.0
5.6
99.6
0.4
100.0
6.4
1.6
13.5
4.0
25.5
25.1
150.6
15.0
18.1
183.7
0.1
5.4
189.2
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.
247
-------
TABLE A-95. WELLMAN-LORD/RE SOX PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: alternate conversion in sulfur production unit)
Annual Unit
quantity cost , $
Direct Costs
Raw materials
Sodium carbonate 6,300
Agricultural limestone 3,240
Filter aid 70
Anthracite coal 37,330
Total raw materials cost
Conversion costs
Operating labor and supervision 47,500
Utilities
Fuel oil 893,000
Steam 1,676,900
Process water 4,472,900
Electricity 79,757,100
Heat credit 209,000
Maintenance
Labor and material
Analyses 8,500
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 8.6%
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
Sulfur 32,800
Sodium sulfate 8,000
Spent anthracite 19,200
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 60.00/ton
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu
kgal 0.12/kgal
kWh 0.029/kWh
MBtu 2.00/MBtu
man-hr 17 .00/man-hr
tons 40.00/ton
tons 23.00/ton
tons 25.00/ton
$/ton
Total % of average
annual annual revenue
cost , $ requirements
648,900
48,600
13,200
2,239,800
2,950,500
593,800
357,200
3,353,800
536,700
2,313,000
(418,000)
2,254,900
144,500
9,135,900
12,086,400
4,149,800
6,126,600
1,496,600
59,400
197,600
12,030,000
24,116,400
(1,312,000)
(184,000)
(480,000)
22,140,400
coal $/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements (net)
6.33 14.
76 0.70
2.93
0.22
0.06
10.12
13.33
2.68
1.61
15.15
2.42
10.45
(1.89)
10.19
0.65
41.26
54-.S9
18.74
27.67
6.76
0.27
0.89
54.33
108.92
5.92
0.83
2.17
100.00
$/ton
S removed
637
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $37,659,000; total depreciable investment, $69,163,000; and total
capital investment, $71,240,000.
All tons shown are 2,000 Ib.
248
-------
TABLE A- 96
vo
WELLMAN-LORD/ RESOX PROCESS VARIATION FROM BASE CASE: LOW CONVERSION. RFCiULATEO CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 71240000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER bMT bY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION BTU TOMS COAL PROCESS,
START KW /YEAR /YEAR TONS/YEAR
1 7000 31500000
'e. 7000 31500000
3 7000 31500000
4 7000 31500000
_S /.MIL JliftUULQ
6 7000 31500000
7 7000 31500000
B 7000 31500000
9 7000 31500000
11 5000 22500000
12 5000 22500000
lJ 5000 22500000
14 5000 22bOOOOO
_ii> SUfiU Z25..fi.afi..fl.O,
16 3500 15750000
17 3500 15750000
la 3500 15750000
19 3500 15750000
20 3Spp 1575J1000
21 1500
2c 1500
23 IbOO
24 1500
2i> J5p8
26 1500
i'l 1500
2o IbOO
29 IbOP
^y . 1&9Q ,
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
1500000
1500000
1500000
1500000
1500000
1500000
1500000
1500000
1071400
1071400
1071400
1071400
750000
750000
750000
750000
321400
321400
321400
321400
321400
321400
321400
321400
34800
34800
34800
34800
34BOO~"
3480U
34800
34800
BY-PRODUCT
RATE,
EUUIVALENT
TONS/YEAR
NA2S04 6.
SULFUR bP. ANT.
32800
32800
32800
32800
32800
J2800
32BOO
32800
328.00
27200
27200
27200
27200
77200
27200
27200
27200
27200
24800 23400 19400
24800 23400 1940'0
24800 23400 19400
24800 23400 19400
_£ ±& H JU £24.2.0. 1 9400
17400 16400 13600
17400 16400 13600
17400 16400 13600
17400 16400 13600
/500
7bOO
?bOO
7500
75JJJ!
7500
7500
7500
7500
7000
7000
7000
7000
7000
7000
7uOO
7000
TOTAL
OP. COST
INCLUDING
NET REVENUE, RFfiULATEU
t/fON ROI FOR
POWER
NA2S04 i, COMPANY,
SULFUR SP. ANT. t/YEAR
36.00
36.00
36.00
36.00
_36jOJ_
36.00
36.00
36.00
36.00
36.00
21.97
21.97
21.97
21.97
__£Lt£Z
21.97
21.97
21.97
21.97
21.97
36.00 21.97
36.00 21.97
36.00 21.97
36.00 21.97
_J6_.00 2.U2J
36.00 21.97
36.00 21.97
36.00 21.97
36.00 21.97
36.00 21.97
5800 36.00 21.97
5800 36.00 21.97
5800 3ft. 00 21.97
5800 36.00 21.97
5&2.Q 3*. 00 _21.97
b800 36.00 21.97
5800 jfc.UO 21. 97
5800 36.00 tl.97
5800 3*. 00 21.97
58.JJO 3fc.OO _2.1_i97
30H45700
29649200
29252600
28856100
"2806^000
27666500
27270000
26873400
22655000
2??5S500
21P61900
21465400
"180TT700
17617200
17220700
16824200
12^49800
11853300
11060200
106637.20
10267200
9670600
9474100
9077600
NET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE)
SALES IN COST OF IN COST OF
REVENUE, POWER, POWER,
S/YEAR $ t
1778400
1778400
1778400
1778400
1778400
1778400
1778400
1773400
126P600
1268600
1268600
1268600
Ig&S&Ofl.
889200
889200
889200
889200
83920.2.
379400
379400
379400
379400
379400
379400
379400
379400
379400
379400
28267300
27870800
27474200
27077700
26284600
25888100
25491600
25095000
_246Sa5_2JJ
28267300
56138100
83612300
110690000
.JL3JT^71iSO
163655800
189543900
215035500
240130500
264829000
21386400 286215400
20989900 307205300
20593300 327798600
20196800 347995400
ISMOJIU! 361 79§7_o. o
17124500 384920200
16728000 401648200
16331500 417979700
15935000 433914700
. _155J8400 449453140
11870400
11473900
11077300
10680800
X&2. 84.3J! 0__ .
9887800
9491200
9094700
8698200
8301600
461323500
472797400
483874700
494555500
514727600
524218800
533313500
542011700
T01 127500 573750000 27321000 634000 b97000 49bOOO
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON 0^ COAL BURNED
MILLS PER KILOwflTT-HOUR
CFNTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
COST DISCOUNTED AT 11.6* TO INITIAL YEAR, DOLLARS
582680300 32367000 550313300
21.33
9.14
101.b6
919.05
2100KblOO
1.19
0.51
5.64
51.05
12623100
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO D ISCOtjK'l ED pHOCtbS COST OVER LIFE OF
DOLLARS PER TON OF COAL HURNED 19.73 1.19
MILLS PER KILOWATT-HOUR P.45 0.50
CENTS PER MILLION HTU HEAT INPUT 43.94 5.65
DOLLARS PER TON UF SULFUR REMOVtD fl?0.5S 51.11
20.14
8.63
95.92
868.00
197462000
POWER UNIT
18.54
7.95
88.29
799.44
-------
TABLE A-97. WELLMAN-LORD/RESOX PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: wet-scrubbing fly ash removal)
% of
total direct
Investment, $ investment.
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Fly ash removal (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
ESP credit
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
458,000
4,642,000
4,352,000
1,136,000
5,296,000
(4,713,000)
2,641,000
8,307,000
7,289,000
643,000
30,051,000
1,803,000
31,854,000
154,000
32,008,000
2,352,000
585,000
4,449,000
1,337.000
8,723,000
8,146,000
48,877,000
4,872,000
5,865,000
59,614,000
44,000
1,983,000
61,641,000
1.4
14.5
13.6
3.5
16.5
(14.7)
8.3
26.0
22.8
2.0
93.9
5.6
99.5
0.5
100.0
7.3
1.8
13.9
4.2
27.2
25.5
152.7
15.2
18.3
186.2
0.1
6.2
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.
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.
250
-------
(Variation from
TABLE A-98. WELLMAN-LORD/RESOX PROCESS
ANNUAL REVENUE REQUIREMENTS
base case: wet-scrubbing fly ash removal)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 6,300
Agricultural limestone 3,240
Filter aid 70
Anthracite coal 33,180
Total raw materials cost
Conversion costs
Operating labor and supervision 47,500
Utilities
Fuel oil 793,800
Steam 1,569,400
Process water 4,024,300
Electricity 113,085,800
Heat credit 185,800
ESP electricity credit 7,114,900
Maintenance
Labor and material
Analyses 8,500
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 8.6%
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
Sulfur 32,800
Sodium sulfate 8,000
Spent anthracite 17,100
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 60.00/ton 1_
2
man-hr 12.50/man-hr
gal 0.40 /gal
MBtu 2.00/MBtu 3
kgal 0.12/kgal
kWh 0.029/kWh 3
MBtu 2.00/MBtu
kWh 0.029/kWh
1
man-hr 17.00/man-hr
9
11
3
5
1
10
22
tons 40.00/ton (1
tons 23.00/ton
tons 25.00/ton
20
648,900
48,600
13,200
,990,800
,701,500
593,800
317,500
,138,800
482,900
,279,500
(371,600)
(206,300)
,915,900
144,500
,295,000
,996,500
,576,800
,301,100
,327,100
59,400
192,400
,456,800
,453,300
,312,000)
(184,000)
(427,500)
,529,800
$/ton coal $/MBtu heat
Equivalent unit revenue requirements (net)
Mills/kWh burned
5.87 13.69
input
0.65
3.16
0.24
0.06
9.70
13.16
2.89
1.55
15.29
2.35
15.97
(1.81)
(1.00)
9.33
0.70
45.27
58.43
17.42
25.82
6.47
0.29
0.94
50.94
109.37
(6.39)
(0:90)
(2.08)
100.00
$/ton
S removed
590
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $32,008,000; total depreciable investment, $59,614,000; and total
capital investment, $61,641,000.
All tons shown are 2,000 Ib.
251
-------
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-
-------
TABLE A-100. WELLMAN-LOSD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (two absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
305,000
1,952,000
1,902,000
504,000
2,153,000
1,534,000
4,455,000
5,062,000
374,000
18,241,000
1,094,000
19,335,000
96,000
19,431,000
1,671,000
415,000
2,940,000
915,000
5,941,000
5,074,000
30,446,000
3,035,000
3,654,000
37,135,000
15,000
844,000
37,994,000
1.6
10.0
9.8
2.6
11.1
7.9
22.9
26.1
1.9
93.9
5.6
99.5
0.5
100.0
8.6
2.2
15.1
4.7
30.6
26.1
156.7
15.6
18.8
191.1
0.1
4.3
195.5
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.
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.
253
-------
TABLE A-101. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW existing)
Annual Unit
quantity coat, $
Direct Costs
Raw materials
Sodium carbonate 2,660
Catalyst
Agricultural limestone 1,370
Filter aid 30
Coal 12,300
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 30,040
Utilities
Fuel oil 180,300
Steam 663,200
Process water 1,800,400
Electricity 33,096,000
Heat credit 24,800
Maintenance
Labor and material
Analyses 4,480
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 7.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 13,100
Sodium sulfate 3,380
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 25.00/ton
tons 7.50/ton
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu
kgal 0.12/kgal
kWh 0.031/kWh
MBtu 2.00/MBtu
man-hr 17.00/man-hr
tons 40.00/ton
tons 23.00/ton
$/ton
Total % of average
annual annual revenue
cost, $ requirements
274,000
1,700
20,600
5,700
307,500
1,400
610,900
375,500
72,100
1,326,400
216,000
1,026,000
(49,600)
1,356,300
76,200
4,398,900
5,009,800
2,599,500
3,267,500
904,000
37,600
60,200
6,868,800
11,878,600
(524,000)
(77,700)
11,276,900
coal $/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements (net)
8.05 17.
80 0.85
2.43
0.02
0.18
0.05
2.73
0.01
5.42
3.33
0.64
11.76
1.91
9.10
(0.44)
12.03
0.68
39.01
44.43
23.05
28.98
8.02
0.33
0.53
60.91
105.34
(4.65)
(0.69)
100.00
$/ton
S removed
768
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, 14,680 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $19,431,000; total depreciable investment, $37,135,000; and total
capital investment, $37,994,000.
All tons shown are 2,000 Ib.
254
-------
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255
-------
TABLE A-103. WELLMAS-LORD/ALLIED CHEMICAL COAL/SO, REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 200 MW new)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (two absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (two indirect steam reheaters)
Chloride purge (two chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
Tot-al depreciable investment
Land
Working capital
Total capital investment
301,000
1,908,000
1,858,000
493,000
2,104,000
1,503,000
4,357,000
4,972,000
367,000
17,863,000
1,072,000
18,935,000
175,000
19,110,000
1,673,000
415,000
2,902,000
904,000
5,894,000
5,001,000
30,005,000
2,983,000
3,601,000
36,589,000
15,000
824,000
37,428,000
1.6
10.0
9.7
2.6
11.0
7.9
22.8
26.0
1.9
93.5
5.6
99.1
0.9
100.0
8.7
2.2
15.2
4.7
30.8
26.2
157.0
15.6
18.9
191.5
0.1
4.3
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.
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.
256
-------
TABLE A-104. WELLMAN-LORD/ALLIED CHEMICAL COAL/SO- REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 200 MW new)
Annual
quantity
Direct Costs
Raw materials
Sodium carbonate 2,580 tons
Catalyst
Agricultural limestone 1,320 tons
Filter aid 29 tons
Coal 11,900 tons
Sand 180 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 30,040 man-hr
Utilities
Fuel oil 174,600 gal
Steam 642,300 MBtu
Process water 1,743,600 kgal
Electricity 32,072,400 kWh
Heat credit 24,000 MBtu
Maintenance
Labor and material
Analyses 4,480 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 8.6%
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
Sulfur 12,700 tons
Sodium sulfate 3,270 tons
Net average annual revenue requirements
Total
Unit annual
cost, $ cost, $
103.00/ton 265,700
1,600
15.00/ton 19,800
189.00/ton 5,500
25.00/ton 297,500
7.50/ton 1,400
591,500
12.50/man-hr 375,500
0.40/gal 69,800
2. 00 /MBtu 1,284,600
0.12 /kgal 209,200
0.031/kWh 994,200
2.00/MBtu (48,000)
1,330,700
17.00/man-hr 76,200
4,292,200
4,883,700
2,195,300
3,218,800
891,200
37,600
58,300
6,401,200
11,284,900
40.00/ton (508,000)
23.00/ton (75,200)
10,701,700
% of average
annual revenue
requirements
2.48
0.02
0.19
0.05
2.78
0.01
5.53
3.51
0.65
12.00
1.96
9.29
(0.45)
12.44
0.71
40.11
45.64
20.51
30.08
8.33
0.35
0.55
59.82
105.46
(4.75)
(0.71)
100.00
S/ton coal $/MBtu heat $/ton
Mills/kWh burned input
Equivalent unit revenue requirements (net)
7.64 17.45 0.83
S removed
753
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, 14,220 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded
Total direct investment, $19,110,000; total depreciable investment, $36,589 000- and total
capital investment, $37,428,000. '
All tons shown are 2,000 Ib.
257
-------
TABLE A-105
ALLIED CHEMICAL PROCESS VARIATION FROM HASE CASEI 2-10 rtw, kgC.ULATED CQ, fcCOMDMICS
TOTAL CAPITAL INVESTMENT
37428000
bo
Ui
00
TOTAL
SULFUR HY-PROOUCT OP, COST
REMOVED KATE, INCLUDING
YEARS ANNUAL PLMER JMT PUWFR NNIT BY EQUIVALENT NtT RrVfiUE, REGULATED
AFTE"- uPERA- HEAT FUEu POLLUTION TONS/YEAR »/TllN RCI FOR
PQWEP TIIJN, REQUIREMENT, CONSUMPTION, CONTROL POWER
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS, ELEMENTAL SQoIU" ELEMENTAL SQrjIUM COMPANY,
START K<>i /YEA;< /YEAR TONS/YEAR SULFUK SULFATE SULFUR SJLFATE VYEAR
1 7000
2 7'JOO
3 7 JOO
4 7uOO
— 5 2uQU.
6 7''/00
7 7uOO
b 7JOO
9 7000
.10 2SQQ..
11 5000
12 5u()0
13 5000
14 5oOO
"l6 35oo"
17 3300
18 3500
19 3500
.20 3500.
21 1500
22 IJOO
23 1SOO
24 1500
.25 1500.
26 1500
27 150P
28 1500
29 1500
30 _ laoo
TOT 127500
LIFETIME
PROCESS CPST
12880000 613300 14200 12700 3300 36. C
12880000 613100 14200 12700 3300 36, C
1288,'. 000 6131JO 14200 12700 3300 3o,c
12880000 613.100 14200 12700 3300 36, C
!2s!S2aQQ $.12220 Ii202 12200 1.330U 3&*C
12880000 613300 14200 12700 3300 36, c
12880000 6133:10 14200 12700 3300 36, C
12SBOOOO 613300 14200 12700 3300 36. C
123BOOOO 613)00 14200 12700 3300 30.C
_123£2Q2Q ..£12322 14.200 122JQ 1.3300 22*5
9200000 438100 10200 9100 2300 So.ij
9200000 4381'JO 10200 9100 2300 36,0
9200000 438UJO 10200 9100 2300 36,0
9200000 438100 10200 9100 2300 30.0
_ . 2202020 4.23100 10200 21uQ 1.2302 3a»U
6440000 306700 7100 6300 1600 36,0
6440000 306700 7100 6300 1600 36.0
6*40000 3D67QO 7100 6300 1600 3o.O
6440000 306700 7100 6300 1600 36,0
6&&UGOO _ _ 306200 21QQ 63Q2- 1.1600 3tuU
2760000 1314QO 3000 2700 700 36.0
2760000 131400 3000 2700 700 36,0
2760000 131400 3000 2700 700 36,0
2760000 131400 3000 2700 700 36.0
2262Q2Q _ _ 131420 . 3000 2200 1 200 3tuU
2760000 131400 3000 2700 700 36,0
2760000 131400 3000 2700 700 36.0
2760000 131400 3POO 2700 703 3o,0
276000" 131400 3000 27CO 700 30.0
. 22620,30 131400 3000 2200 . 202 36.2
234600000 11171000 258500 231000 59500
AVERAGE If.CRF.ASE (DECREASE) H UNIT OPERATING COST
DOLLARS PER TUJ HF CJAL BURNED
''ILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
'"JuLARS PER TON OF SJLFUR REMOVED
UlStUUNTt-O AT 11,6% M INITIAL YEAR, DOLLARS
INCREASE IPECREASEI n UNIT OPERATING COST EQUIVALENT TO oiiCu
iJULLARS PER TON OF C3AL BURrlED
•ULLS PFR KILO-JATT-H'JUR
CHNTS PER .1ILLIQN BTU HEAT INPUT
:iDLLAkS PER TON QF SJLFUR REMUVet)
IC 20,70 14445500
10 20,70 142357QO
11 20,70 14026000
10 HO, 70 13816200
l3.-.20*2U-_-l2fr.Qfr.4.QO._.
10 20,70 13396700
10 20,70 13186900
iO 20,70 12977100
in 20,70 127673QO
iU...2Q*2Q-_-l225.26.QQ...
iO 20,70 10971100
ifl 20,70 10761300
K> 20,70 10551600
iO 20,70 10341800
!2..-2Q*2Q-_-lfil22QQQ._.
'0 20,70 8836000
iO 20,70 8626300
'0 20,70 8416500
'0 20,70 8206700
:fl— 20*20 2222000...
0 20,70 6196900
0 20,70 5987100
0 20,70 5777300
0 20,70 5567600
0_._20»2Q 52528QQ—
0 20,70 5148000
0 20,70 4938300
o 20,70 4728500
0 20,70 4518700
2_-.2Q*2Q 1302000.-.
282384900
25.23
11,07
120.37
1092.40
100914900
Ji TlrO PROCESS COST OVER
23,18
10,15
110.36
1001.14
TOTAL
NET
SALES
REVENUE,
*/YEAR
525500
525500
5255QO
5255QO
.-S255QO.
525500
525500
5255QO
525500
._2541QQ_,
375200
375200
375200
375200
.-225.2QO-,
259900
259900
2599QP
259900
,-252200..
111700
111700
111700
111700
1112QD
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
PO^ER, POWER,
$ $
I392o65o 13920000
13710200 2763Q200
13500500 4113Q700
1329Q700 54421400
...12030200 fr.25.Q23.QO
12871200 80373500
12661400 93034900
12451600 105486500
12241800 117728300
— 12223.502 12222lflQO
10595900 140527700
10336100 150913800
10176400 161090200
9966600 171056800
2256222 182313400
8576100 189389700
8366400 197756100
8156600 205912700
7946800 213859500
22321QQ 2215S66.00
6085200 227681600
5875400 233557200
5665600 239222800
5455900 244678700
524610O 24S924800
Ill7on 5036300 254961100
111700 4826600 259787700
111700 4616800 264404500
111700 4407000 268811500
-111200 &12230Q 213008800
9376100 273008800
0,84 24,44
0,36 10,71
4, OP 116,37
36.27 1056,13
3671000 97243900
LIFE OF POWER UNIT
0.85 22,33
0,37 9,78
4,02 106,34
36,42 964.72
-------
TABLE A-106. WELLMAN-LORD/ALLIED CHEMICAL COAL/S(>2 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 500 MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
463,000
4,442,000
4,426,000
1,153,000
4,977,000
2,678,000
8,266,000
8,236,000
648,000
35,289,000
2,117,000
37,406,000
357,000
37,763,000
2,434,000
603,000
5,107,000
1,516,000
9,660,000
9,485,000
56,908,000
5,655,000
6,829,000
69,392,000
39,000
1,736,000
71,167,000
1.2
11.8
11.7
3.1
13.2
7.1
21.9
21.8
1.7
93.5
5.6
99.1
0.9
100.0
6.5
1.6
13.5
4.0
25.6
25.1
150.7
15.0
18.1
183.8
0.1
4.6
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.
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.
259
-------
TABLE A-107. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 500 MW existing)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Coal
Sand
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,
6,440 tons 103.00/ton
3,310 tons
72 tons
29,790 tons
180 tons
15.00/ton
189.OO/ton
25.00/ton
7.50/ton
47,500 man-hr 12.50/man-hr
663,300
4,100
49,700
13,600
744,800
1,400
1,476,900
593,800
3.10
0.02
0.23
0.06
3.49
0.01
6.91
2.78
436,600 gal
1,605,800 MBtu
4,358,900 kgal
79,277,100 kWh
60,000 MBtu
8,500 man-hr
0.40/gal
2.00/MBtu
0.12 /kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
174,600
3,211,600
523,100
2,299,000
(120,000)
2,255,100
144,500
9,081,700
10,558,600
0.82
15.03
2.45
10.76
(0.56)
10.55
0.68
42.51
49.42
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
4,441,100
6,120,400
1,496,700
59,400
145,600
12,263,200
22,821,800
20.79
28.65
7.00
0.28
0.68
57.40
106.82
Byproduct Sales Revenue
Sulfur
Sodium sulfate
Net average annual revenue requirements
31,700 tons 40.00/ton
8,180 tons 23.00/ton
(1,268,000)
(188,100)
21,365,700
(5.94)
(0.88)
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
13.93
0.66
601
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, 35,550 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $37,763,000; total depreciable investment, $69,392,000; and total
capital investment, $71,167,000.
All tons shown are 2,000 Ib.
260
-------
TABLE A-108
WELLMAN-LORD/ ALLIED CHEMICAL PROCESS VARIATION FROM BASE CASEI 500 MW EXISTING* REGULATED CD.ECONOMICS
TOTAL CAPITAL INVESTMENT 7ii&7ooo
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT* CONSUMPTION,
MILLION BTU TONS COAL
/YEAR /YEAR
SULFUh
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
i!Y-PRQDUCT
RATE/
EQUIVALENT
TONS/YEAR
ELEMENTAL SODIUM
SULFUR SULFATE
TOTAL
DP. COST
INCLUDING NET ANNUAL CUMULATIVE
NtT REVENUE* REGULATED TOTAL INCREASE NET INCREASE
$/TflN RCI FDR NET (DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
ELEMENTAL SODIUM COMPANY, REVENUE* POWER, POWER*
SULFUR SULFATE $/YEAR */YEAR $ $
9
.10.
11
12
13
14
-13.
16
17
18
19
.20.
21
22
23
24
-29.
26
27
28
29
.30.
7000
7000
7000
7000
2000.
5000
5000
5000
5000
...5000.
3500
3500
3500
3500
—3900.
1500
1500
1500
1500
.—1500.
1500
1500
1500
1500
...1900.
32200000
32200000
32200000
32200000
—.322000.00.
23000000
23000000
23000000
23000000
...23000000.
16100000
16100000
16100000
16100000
___161QQQQO_
6900000
6900000
6900000
6900000
6900000.
6900000
6900000
6900000
6900000
6200000.
1533300
1533300
1533300
1533300
-15J330Q.
1095200
1095200
1095200
1095200
-10S520Q-
766700
766700
766700
766700
..766ZQQ.
328600
326600
328600
328600
..32B6QQ.
328600
328600
328600
328600
-328600.
35600
35600
35600
35600
.33600...
25400
25400
25400
25400
-25400.-.
17800
17800
17800
17800
.izaoo—
7600
7600
7600
7600
—Z6.QO—
7600
7600
7600
7600
.-2600—
31700
31700
31700
31700
.31200...
22600
22600
22600
22600
.22600
15900
15900
15900
15900
.15200...
6800
6800
6800
6800
..6BQQ
6800
6800
6800
6800
..6800...
8200
8200
8200
8200
.B2UQ-.
5800
5800
5800
5800
.5flOQ_.
4100
4100
4100
4100
.61QQ-.
1800
1800
1800
1800
.1BOQ-.
1800
1800
1800
1800
.1BQQ-.
36.00
36.00
36.00
36.00
.-22»iQ_
36.00
36.00
36.00
36,00
.-36.UQ.
36,00
36.00
36.00
36.00
.-36*00.
36,00
36,00
36.00
36.00
.-36.QQ.
36.00
36.00
36.00
36.00
-36*00.
20,70
20.70
20.70
20.70
.20*20.
20.70
20,70
20,70
20,70
.20*20.
20.70
20.70
20,70
20,70
-20*20-
20,70
20.70
20,70
20.70
-20*20-,
20.70
20.70
20.70
20.70
.20*20-,
29259400
28782000
28304600
27827200
.-2234SZQO.
23883200
23405800
22928400
22451000
.-21923500.
19165000
1B687600
18210200
17732800
.-12255300.
13433200
12955800
12478400
12001000
.-11523500.
11046100
10568700
10091300
9613900
...3136400.
1310900
1310900
1310900
1310900
..-BB300Q.
933700
933700
933700
933700
—233200-
657300
657300
657300
657300
—652300.
282100
282100
282100
282100
...2821QQ.
282100
282100
282100
282100
—28.2100.
27948500
27471100
26993700
26516300
--.264467.00-
22949500
22472100
21994700
21517300
...2103SBQQ.
18507700
18030300
17552900
17075500
...16S3BQQO.
13151100
12673700
12196300
11718900
.--11241400.
10764000
10286600
9809200
9331800
8854300-
27948500
55419600
82413300
108929600
...135386300
158349800
180817900
202812600
224329900
...245363200
263877400
281907700
299460600
316536100
.--333134100
3462BJ200
358958900
371155200
362874100
...394115500
404879500
415166100
424975300
434307100
.--443161400
TOT 92900 425500000 20262000 470000 419000 108500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON UF C3AL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SJLFUR REMOVED
PROCESS COST DISCOUNTED AT 11,6% TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF C3AL BURNED
MILLS PER KILOWATT-HDUR
CENTS PER MILLION BTJ HEAT INPUT
DDHARS PER TON OF SJLFUR REMOVED
46C064000 16902600 443161400
22,71 0.84 21.87
9,95 0.37 9.5S
108,12 3.97 104.15
978,86 35.96 942.90
187087100 7600200 179486900
PROCESS COST OVER LIFE OF POWER UNIT
20.38 0.83 19.55
8,93 0.37 8.56
97,03 3.94 93.09
877,93 35.66 842.27
-------
TABLE A-109. WELLMAN-LORD/ALLIED CHEMICAL COAL/SC>2 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 2.0% sulfur)
Investment, $
% of
total direct
investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S0£ regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
318,000
4,376,000
4,352,000
1,136,000
4,894,000
1,619,000
4,732,000
5,306,000
395,000
27,128,000
1,628,000
28,756,000
280,000
29,036,000
2,224,000
551,000
4,107,000
1.242.000
8,124,000
7.432.000
44,592,000
4,431,000
5,351,000
54,374,000
42,000
1,162,000
55,578,000
1.1
15.1
15.0
3.9
16.8
5.5
16.3
18.3
1.4
93.4
5.6
99.0
1.0
100.0
7.7
1.9
14.1
4.3
28.0
25.6
153.6
15.3
18.4
187.3
0.1
4.0
191.4
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.
262
-------
TABLE A-110. WELLMAN-LOKD/ALLIED CHEMICAL COAL/S(>2 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 2.0% sulfur)
Total 7. of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 2,900
Catalyst
Agricultural limestone 3,240
Filter aid 32
Coal 13,410
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 42,550
Utilities
Fuel oil 196,500
Steam 946,600
Process water 2,064,700
Electricity 60,894,000
Heat credit 27,000
Maintenance
Labor and material
Analyses 7,610
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 8.6%
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
Sulfur 14,300
Sodium sulfate 3,680
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 25.00/ton
tons 7.50/ton
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu I
kgal 0.12/kgal
kWh 0.029/kWh 1
MBtu 2.00/MBtu
1
man-hr 17.00/man-hr _
6
7
3
4
1
9
16
tons 40.00/ton
tons 23.00/ton
15
$/ton coal
Mills/kWh burned
4.49 10.48
298,700
1,800
48,600
6,000
335,300
1,400
691,800
531,900
78,600
,893,200
247,800
,765,900
(54,000)
,733,800
129,400
,326,600
,018,400
,262,400
,779,700
,197,600
53,200
65,700
,358,600
,377,000
(572,000)
(84,600)
,720,400
$/MBtu heat
input
0.50
1.90
0.01
0.31
0.04
2.13
0.01
4.40
3.38
0.50
12.04
1.58
11.24
(0.34)
11.03
0.82
40.25
44.65
20.75
30.40
7.62
0.34
0.42
59.53
104.18
(3.64)
(0.54)
100.00
$/ton
S removed
982
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, 16,000 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $29,036,000; total depreciable investment, $54,374,000; and total
capital investment, $55,578,000.
All tons shown are 2,000 Ib.
263
-------
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-------
TABLE A-112. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Base case: 500 MW, 3.5% sulfur)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
4
4
1
4
2
8
8
34
2
36
37
2
5
1
9
9
56
5
6
68
1
70
458
,376
,352
,136
,894
,641
,144
,138
639
,778
,087
,865
425
,290
,432
602
,055
,502
,591
,376
,257
,583
,751
,591
42
,705
,338
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
1
11
11
3
13
7
21
21
1
93
5
98
1
100
6
1
13
4
25
25
150
15
18
183
0
4
188
.3
.7
.7
.1
.1
.1
.8
.8
.7
.3
.6
.9
.1
.0
.5
.6
.6
.0
.7
.1
.8
.0
.1
.9
.1
.6
.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.
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.
265
-------
TABLE A-113. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Base case: 500 MW, 3.5% sulfur)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 6,300
Catalyst
Agricultural limestone 3,240
Filter aid 70
Coal 29,140
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 47 500
Utilities
Fuel oil 427,100
Steam 1,570,900
Process water 4,264,200
Electricity 77,568,400
Heat credit 58,700
Maintenance
Labor and material
Analyses 8,500
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 8.6%
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
Sulfur 31,000
Sodium sulfate 8,000
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103. OO/ ton 648,900
4,000
tons 15.00/ton 48,600
tons 189.00/ton 13,200
tons 25.00/ton 728,500
tons 7.50/ton 1,400
1,444,600
man-hr 12.50/man-hr 593,800
gal 0.40/gal 170,800
MBtu 2.00/MBtu 3,141,800
kgal 0.12/kgal 511,700
kWh 0.029/kWh 2,249,500
MBtu 2.00/MBtu (117,400)
2,224,600
man-hr 17. 00 /man-hr • 144,500
8,919,300
10,363,900
4,115,500
6,049,100
1,481,400
59,400
142,400
11,847,800
22,211,700
tons 40.00/ton (1,240,000)
tons 23.00/ton (184,000)
20,787,700
$/ton coal $/MBtu heat
Mills/kWh burned input
5.94 13.86 0.66
3.12
0.02
0.23
0.06
3.51
0.01
6.95
2.86
0.82
15.11
2.46
10.82
(0.56)
10.70
0.70
42.91
49.86
19.80
29.10
7.13
0.28
0.68
56.99
106.85
(5.96)
(0.89)
100.00
$/ton
S removed
598
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $37,290,000; total depreciable investment, $68,591,000- and total
capital investment, $70,338,000.
All tons shown are 2,000 Ib.
-------
TABLE A-114
ALLIED CHEMICAL PROCESS BASE CASE 500 M* 3.5X S, REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT 70338000
NJ
YEARS ANNUAL POWER UNIT
AFTER OPERA- "EAT
POWER TION, REQUIREMENT,
UNIT KW-HR/ MILLION BTU
START KW /YEAR
1 7000 31500000
2 7000 31500000
3 7000 31500000
4 7000 31500000
5 2UOO 31500000...
6 7000 31500000
7 7uOO 31500000
8 7000 3150COOO
9 7000 31500000
.10 _ -20QQ .31500000...
11 5000 22500000
12 5000 22500000
13 5000 22500000
14 5000 22500000
-IS _ SUQO .225QQQQ.Q .
16 3500 15750000
17 35QO 15750000
IB 35QO 15750000
19 3500 15750000
_2U 3500 15250000...
21 1500 6750000
22 1500 6750000
23 1500 6750000
24 15QO 6750000
.25 1520. 625QQQC...
26 1500 6750000
27 1500 6750000
28 1500 6750000
29 15QO 675UOOO
.30 15QQ 6250000...
TOTAL
SULFUR BY-PRODUCT pP . COST
REMOVED RATE* INCLUDING NET ANNUAL. CUMULATIVE
POKER UNIT BY EQUIVALENT NET KfcVfNUE, REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TJNS/YEAR »/THN RCI FOR NET (DECREASE! (DECREASE)
CONSUMPTION, CONTROL PQUER SALES IN COST OF IN COST OF
TONS CtlAL PROCESS, ELEMENTAL SQOIUM ELEMENTAL SOOlUM CCMPANY, REVENUE, POwER, POWER,
/YEAR TONS/YEAR SULFUR SULFATE bULFU'1 SULFATE S/YEAR S/YEAR * *
1500000 34800 31000 8000 36.05 20,70 2S118700 1281600 26837100 26837100
1500000 348QO 31000 8000 36.00 20.70 27725500 1281600 26443900 53281000
1500000 34800 31000 800O 36,00 20,70 27332200 12816QO 26050600 793316QO
1500000 34800 31000 8000 36.00 20,70 2*939000 12816QO 25657400 104989000
1500000 . 34SQQ 31QQO l.BQQB _.3fuQQ 20..20- 26541300 12H16QQ-. 25264100- .130259100
1500000 34800 31000 3000 36.00 20,70 2*152400 1281600 24870800 153123900
1500000 34800 31000 8000 36,00 20,70 25759200 1281600 24477600 1796QISOO
1500000 34800 31000 8000 36.00 20,70 21365500 1281600 24084300 203689800
1500000 34800 3101)0 8000 36,00 20,70 2*972600 1281600 23691000 227376800
. -15.QQQQQ . 34BQQ 31000. __8UQC — 22*52 20*20- 24522400 8621QQ 22216200. 251QS31QO
10714QO 24800 22100 5700 36.00 20,70 21252400 913600 20338800 271431900
1071*00 24800 22100 5700 36,00 20,70 20859200 913600 19945600 291377SOO
1071400 24800 22100 5700 36,00 20,70 2C465900 913600 19552300 310929800
1071400 24800 22100 5700 36.00 20,70 2007260C 913600 19159000 330088800
. .1021420 . 248QQ .221QQ- 1.52QQ 3&»UQ__ 20*20- 1262240C 213600,. 18265800. -.348954600
750000 17400 15500 4000 36,00 20,70 16997200 64080C 16356400 369211000
750000 17400 15500 4000 36,00 20,70 16604000 640800 15963200 381174200
750000 17400 15500 4000 36.00 20,70 16210700 640800 15569900 396744100
750000 17400 15500 400v 36.00 20,70 15817400 64Q800 15176600 411920700
250QQQ 124QQ 155UQ—1.4QQQ_._3b»ua 20*20 154242QQ 640600 14133400 426IQ41QO
321400 7500 6600 1700 36,00 20,70 11745100 272800 11472300 438176400
321400 7500 6600 1700 36.00 20,70 1135J900 272800 11079100 449255SOO
321100 7500 6600 170(1 36,00 20,70 10958600 272800 10685800 459941300
3214QO 7500 66UO 1700 36,00 20,70 10565300 272800 10292500 470233800
3214UQ 2500 66flfl-.1.12Qa— 36»Uii.._2Q»20._.lQ1221flC 2228.QO 2828300 480133100
321400 7500 6600 1700 36.00 20,70 9778800 27280C1 9506000 489639100
321400 7500 6600 1700 36.00 20,70 9385600 272800 9112800 49875HOO
321400 7500 6600 1700 36, uO 20,70 8992300 272800 8719500 507471400
321<-00 75>00 6600 1700 36.00 20,70 S59900C 2728QO 8326200 515797600
321400 2500 660Q._1.1200— 36*Uii— 2d*2Q 8205600 222800 2223000 523230600
TQT 127500 57375UOOO 27321000 634000 564000 145500
LlF-fcTJME AVERAGE INCREASE (DECREASE) IN UIIJT OPERATING COST
DOLLARS PtR TOM OF C3AL BURNED
''ILLS PER KILOUATT-H3UR
CENTS PFR MILLION BTU HEAT INPUT
LiRLLAPS PER TON UF SJLFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6% TU INITIAL YEAR, DOLLARS
LSVELIZED INCREASE (DECREASE) II! UNIT OPERATING COST EQUIVALENT Til DliCUU'.
DOLLARS PKR TON OF CDAL BURNED
KILLS Pfci< KILOWATT-H3UR
CEBITS PER MILLION BTJ HEAT INPUT
ODLLARS PER TON UF SJLFUR REMOVED
546628100 22897500 523730600
20.01 0,84 19,17
8.57 0.35 8.22
95,27 3,99 91,28
862.19 36.12 826,07
196363000 8956000 187407000
TED PROCESS COST EVER LIFE PF POUER UNIT
18.44 0,84 17.60
7,90 0.36 7,54
87.BO 4.00 *3,80
794,99 36.26 758.73
-------
TABLE A-115. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 5.0% sulfur)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
f f. If, y\
Subtotal
Se vi u ill ies nd iscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Total indirect investment
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Total depreciable investment
Land
Working capital
Total capital investment
561,000
4,376,000
4,352,000
1,136,000
4,894,000
3,465,000
11,011,000
10,311,000
835,000
40,941,000
2,456,000
43,397,000
590,000
43,987,000
2,595,000
641,000
5,799,000
1,703,000
10,738,000
10,945,000
65,670,000
6,508,000
7,880,000
80,058,000
42,000
2,223,000
82,323,000
1.3
9.9
9.9
2.6
11.2
7.9
25.0
23.4
1.9
93.1
5.6
98.7
1.3
100.0
5.9
1.4
13.2
3.9
24.4
24.9
149.3
14.8
17.9
182.0
0.1
5.1
187.2
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.
268
-------
TABLE A-116. WELLMAN-LOKD/ALLIED CHEMICAL COAL/SO^ REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 5.0% sulfur)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 9,690
Catalyst
Agricultural limestone 3,240
Filter aid 108
Coal 44,820
Sand 18°
Conversion costs
Operating labor and supervision 51,020
Utilities
Fuel oil 656,900
Steam 2,193,100
Process water 6,456,400
Electricity 94,187,200
Heat credit 90,300
Maintenance
Labor and material
Analyses 9,130
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 8.6%
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
Sulfur 47,700
Sodium sulfate 12,300
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 25.00/ton 1
tons 7.50/ton _
2
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu 4
kgal 0.12/kgal
kWh 0.029/kWh 2
MBtu 2.00/MBtu
2
man-hr 17.00/man-hr
11
13
-
4
7
1
13
27
tons 40.00/ton (1
tons 23.00/ton
25
998,100
6,200
48,600
20,400
,120,500
1,400
,195,200
637,800
262,800
,386,200
774,800
,731,400
(180,600)
,621,500
155,200
,389,100
,584,300
,803,500
,079,800
,707,200
63,800
219,100
,873,400
,457,700
,908,000)
(282,900)
,266,800
S/ton coal $/MBtu heat
Equivalent unit revenue requirements (net)
Mills/kWh burned
7.22 16.84
input
0.80
3.95
0.02
0.19
0.08
4.44
0.01
8.69
2.52
1.04
17.36
3.07
10.81
(0.71)
10.37
0.61
45.07
53.76
19.01
28.02
6.76
0.25
0.87
54.91
108.67
(7.55)
(1.12)
100.00
$/ton
S removed
472
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, 53,500 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $43,987,000; total depreciable investment, $80,058,000; and total
capital investment, $82,323,000.
All tons shown are 2,000 Ib.
269
-------
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-------
TABLE A-118. WELLMAN-LOED/ALLIED CHEMICAL COAL/SO- REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW existing)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
SC»2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
634,000
7,010,000
7,525,000
1,846,000
8,232,000
4,088,000
13,234,000
11,914,000
982,000
55,465,000
3,328,000
58,793,000
543,000
59,336,000
2,934,000
726,000
7,432,000
2,138,000
13,230,000
14,513,000
87,079,000
8,654,000
10,449,000
106,182,000
66,000
2,999,000
109,247,000
1.1
11.8
12.7
3.0
13.9
6.9
22.3
20.1
1.7
93.5
5.6
99.1
0.9
100.0
4.9
1.2
12.6
3.6
22.3
24.5
146.8
14.6
17.6
179.0
0.1
5.0
184.1
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.
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.
271
-------
TABLE A-119. WELLMAN-LOED/ALLIED CHEMICAL CQAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW existing)
Annual Unit
quantity cost, $
Direct Costs
Raw materials
Sodium carbonate 12,600
Catalyst
Agricultural limestone 6,480
Filter aid 140
Coal 58,280
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 67,180
Utilities
Fuel oil 854,200
Steam 3,141,800
Process water 8,528,400
Electricity 154,536,700
Heat credit 117,400
Maintenance
Labor and material
Analyses 13,810
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
Marketing, 10% of byproduct sales revenue
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 62,000
Sodium sulfate 16,000
Net average annual revenue requirements
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 25.00/ton
tons 7.50/ton
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu
kgal 0.12/kgal
kWh 0.028/kWh
MBtu 2.00/MBtu
man-hr 1 7 . 00 /man-hr
tons 40. 00 /ton
tons 23.00/ton
$/ton
Total % of average
annual annual revenue
cost , $ requirements
1,297,800
8,000
97,200
26,500
1,457,000
1,400
2,887,900
839,800
341,700
6,283,600
1,023,400
4,327,000
(234,800)
2,955,900
234,800
15,771,400
18,659,300
6,795,600
9,395,200
2,015,200
84,000
284,800
18 574 800
37,234,100
(2,480,000)
(368,000)
34,386,100
coal $/MBtu heat
Mills/kWh burned input
Equivalent unit revenue requirements (net)
4.91 11.46 0.55
3.77
0.02
0.28
0.08
4.24
0.01
8.40
2.44
0.99
18.27
2.98
12.58
(0.68)
8.60
0.68
45.86
54.26
19.76
27.32
5.86
0.25
0.83
54 .02
108.28
(7.21)
(1.07)
100.00
$/ton
S removed
494
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, 69,560 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $59,336,000; total depreciable investment, $106,182,000; and total
capital investment, $109,247,000.
All tons shown are 2,000 Ib.
272
-------
TABLE A-120
WELLHAN-LDRD/ ALLIED CHEMICAL process VARIATION FROM BASE CASEI 1000 M* EXISTING, REGULATED cr. ECONOMICS
TOTAL CAPITAL INVESTMENT 109247000
YEARS
AFTER
UNIT
START
ANIIUAL
DPERA-
TIUU,
KW-HR/
KW
PQUER UNIT
HEAT
REQUIREMENT/
MILLION BTU
/YEAR
PCHER UNIT
FUEL
CONSUMPTION/
TONS COAL
/YEAR
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
ELEMENTAL SODIUM
SULFUK SLILFATE
NfeT ReVfcNUE/
ELEMENTAL
SULFUR
i\l
SODIUM
SULFATE
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
PUHER
COMPANY/
I/YIAR
TOTAL
NET
SALES
REVENUF,
$/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER/
*
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST QF
POWER,
*
9
.10.
11
12
13
1*
.15.
16
17
18
1*
.2(1.
21
22
23
24
.25.
2t>
27
28
2V
.30.
N3
7000
7000
7000
7(.'00
-7.aoQ_
5000
5000
5>>00
5000
-5UQQ_
3500
3500
3500
3500
6300JOOO
63000000
63000000
63QOOOOO
1500
1300
1500
1500
45000000
45000000
45000000
45000000
.iSQQQQQQ.
31500000
31500000
31500000
31500000
.3i50aOQQ_
13500000
13500000
13500000
13500000
3000000
3000000
3000000
3000000
38BQJQQ-
2142900
2142900
21429QO
2142900
21*2220-
1500000
1500000
1500000
1500000
1500
1500
1500
1500
_150Q.
13500000
13500000
13500000
13500000
.135QUQQO.
6*2900
642900
642'JOO
642900
&4.22BO-
642900
642900
642900
642900
64.2200.
69600
696QO
69600
696QO
.62600...
49700
49700
49700
49700
_*.2200-__
34800
34800
34800
34800
.34.800-..
1*900
14900
14900
14900
-142QC...
14900
14900
14900
14900
-U2UU--.
62000
62000
62000
62000
.6.2QUQ-
44300
44300
44300
44300
16000
16000
16000
16000
llaooQ.
11400
11400
11400
11400
31000
31000
31000
31000
.31QQQ
13300
13300
13300
13300
.1330. Q-
13300
13300
13300
13300
.133UU
8000
8000
aooo
8000
1.SQQQ-
3400
3400
3400
3400
3400
3400
3400
3400
1.34DC-
36,00
36,00
36,00
36.00
.22*52.
36,00
36,00
36.00
36,00
_2!l»Ua.
36.00
36,00
36,00
36,00
.36*03
36,00
36.00
36,00
36,00
.36*aa.
36,00
36,00
36.00
36,00
.ab.au.
20,70
20,70
20,70
20,70
.2Q*2Q.
20,70
20,70
20,70
20,70
.2Q*2Q_
20,70
20.70
20,70
20,70
.20*28-
20,70
20,70
20,70
20,70
.20*20-
20,70
20,70
20,70
20,70
.20.2Q.
47053000
46322400
45591900
448614QO
-&&13CSQQ.
38101300
37370800
36640200
359C9700
-3S1232QQ.
30354800
29624300
Z8893800
28163200
-2Z&322QQ.
20928000
20197400
19466900
18736300
2563200
2563200
25632QO
2563200
-1Z262QQ.
1830800
1830800
1830800
1830800
44489800
43759200
43028700
42296200
-*.2&Q*.6.QQ_
36270500
35540000
34809400
34Q78900 .
12B1600
1281600
1281600
1281600
17275300
16544700
15814200
15083700
-14353100.
549200
549200
549200
549200
—54220Q-
549200
549200
5*9200
549200
..
29073200
283*2700
27612200
26881600
. 261511QQ-
20378800
19648200
18917700
18187100
_l245fi&OQ-
16726100
15995500
15265000
14534500
.13803300.
444H9BOO
88249QOO
131277700
173575900
.2152fiQ5ao
252291000
287791000
322600400
356679300
390022200
419100900
447443600
475055800
501937400
548467300
56B1155QO
587033200
605220300
-6.22626.9QO
639403000
655398500
670663500
685198000
.fcssouiaao
TOT 92500 632500000 ^9643500 919500 819500 211000
LIFETIME AVERAGE INCREASE (DECREASE) IM UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TDM UF SULFUR REMOVED
PROCtSS COST DISCOUNTED AT 11.6% TQ INITIAL YEAR/ DOLLARS
LFVELIZED INCREASE (DECREASE) IN UNIT OPEKATING COST EQUIVALENT TQ DISCOUNTED
UOLLARS PER TON OF C3AL BURNED
"(ILLS PER KILOWATT-HOUR
CENTS PFR MILLION BTJ HEAT IMPUT
HOLLARS PER TD'J OF SULFUR REMOVED
732034900 33033000 699001900
18.47 0,84 17,63
7,91 0.35 7,56
87,93 3.97 83.96
796,12 35,92 760,20
299515300 14864100 284651200
PROCESS CCST CVER LIFE OF PHWER UNIT
16,67 0,82 15,85
7,15 0,36 6,79
79,40 3.94 75,46
718.78 35.67 683,11
-------
TABLE A-121. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 1,000 MW new)
% of
total direct
Investment^ j> investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S(>2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
624,000
6,853,000
7,324,000
1,802,000
8,026,000
4,001,000
12,916,000
11,694,000
962,000
54,202,000
3,252,000
57,454,000
680,000
58,134,000
2,927,000
723,000
7,308,000
2,105,000
13,063,000
14,239,000
85,436,000
8,476,000
10,252,000
104,164,000
69,000
2,915,000
107,148,000
1.1
11.8
12.6
3.1
13.8
6.9
22.2
20.0
1.7
93.2
5.6
98.8
1.2
100.0
5.0
1.2
12.7
3.6
22.5
24.5
147.0
14.6
17.6
179.2
0.1
5.0
184.3
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.
274
-------
TABLE A-122. WELLMAN-LORD/ALLIED CHEMICAL COAL/S(>2 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 1,000 MW new)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 12,200
Catalyst
Agricultural limestone 6,260
Filter aid 135
Coal 56,340
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 67,180
Utilities
Fuel oil 825,700
Steam 3,037,000
Process water 8,244,000
Electricity 149,402,900
Heat credit 113,500
Maintenance
Labor and material
Analyses 13,810
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 8.6%
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
Sulfur 59,900
Sodium sulfate 15,470
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton 1
tons 15.00/ton
tons 189.00/ton
tons 25.00/ton 1
tons 7.50/ton _
2
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu 6
kgal 0.12/kgal
kWh 0.028/kWh 4
MBtu 2.00/MBtu
2
man-hr 17.00/man-hr
15
18
6
9
1
17
35
tons 40.00/ton (2
tons 23.00/ton
33
$/ton coal
Mills/kWh burned
4.74 11.44
,256,600
7,700
93,900
25,500
,408,500
1,400
,793,600
839,800
330,300
,074,000
989,300
,183,300
(227,000)
,893,100
234,800
,317,600
,111,200
,249,800
,214,700
,983,800
84,000
275,200
,807,500
,918,700
,396,000)
(355,800)
,166,900
$/MBtu heat
input
0.54
3.79
0.02
0.28
0.08
4.25
0.01
8.43
2.53
1.00
18.31
2.98
12.61
(0.68)
8.71
0.71
46.18
54.61
18.85
27.78
5.98
0.25
0.83
53.69
108.30
(7.22)
(1.08)
100.00
$/ton
S removed
493
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, 67,240 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $58,134,000; total depreciable investment, $104,164,000; and total
capital investment, $107,148,000.
All tons shown are 2,000 Ib.
275
-------
TABLE A-123
WELL IAJ-L3RD/ ALLIED CHEMICAL PROCESS VARIATION FRPM BASE CASEI IOOCMW, REFLATED CQ, ECCNCMICS
TOTAL CAPITAL INVESTMENT 1071*9000
NJ
YEARS ANNUAL
AFTEH LlPErtA-
PQWEH TIDNj
UNIT KW-HR/
START KW
puvigR UNIT POKIER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION,
MILLION STU TONS CJAL
/YEAK
/YEAR
SULFUR
REMOVED
8V
POLLUTION
CONTROL
PROCESS,
BY-PRODUCT
RATE,
EQUIVALENT
TQNS/YEAR
ELEMENTAL SODIUM
TONS/YEAR SULFUR SULFATE
TOTAL
DP. COST
INCLUDING
REGULATED
RCI FOR
POWER
ELEMENTAL. SODIUM COMPANY,
SULFATE $/YEAR
NfcT RtVE.NUE,
t/TON
1 7000
2 7000
3 7000
4 7000
.-5 2JJQ— .
6 700O
7 7aoo
a 7ooo
9 7000
-la— 2uQQ— .
11 5000
12 5001
13 5000
14 5000
.15 5JOQ— .
16 3500
17 3500
18 35uo
19 3500
.20-— 3503.-.
21 li>00
22 1500
23 1500
24 1500
.25 1500.-.
26 1500
27 I5oo
2« 1500
29 1500
.30 15JQ___
60900000 2900300
00900000 2900000
6<)9o 1000 29Q0300
60900000 2900000
—.ca2oaoQQ 22ooaao.,
60900000 2900000
00900000 2900000
60903000 2900000
60900000 29QOOOO
.— 602a2aaQ 2900200 .
43500000
43500000
43500000
43500000
. — 435QUQQQ
30450000
30450000
30450000
30450000
. 30450000
1305UOOO
13050010
13050000
.13050000
1305UOOO
I3o5"000
13050000
13050000
. — 13050000
2071400
2071400
2071400
2071400
2021400..
1450300
1450000
1450300
1450300
.1450000
621400
621400
621400
621400
621400 .
621400
621400
621400
621400
6214UQ-.
67200
67200
67200
67200
.-62200.
67ZOO
67200
67200
67200
..62200
4SOOO
4aooo
49000
49000
.-4SOQQ
33600
33600
33600
33600
..23630.
1*400
144QO
14400
14400
59900
59900
59900
59900
—522UQ-
59900
59900
59900
59900
..52200.
42800
42800
42800
42300
.-42300-
29900
29900
29900
29900
.-222UQ.
12800
12600
12800
12800
14400
14400
14400
14400
-1440Q__
12800
12BUO
12800
12800
-12300-,
15500
15500
15500
15500
—15500..
15500
15500
15500
15500
-11500-.
11100
11100
11100
11100
.-Liuoa..
7700
7700
7700
7700
.:.22aa—
3300
3300
3300
3300
.1-3303—
3300
3300
3300
3300
.—33QU—
36.00
36.00
36,00
30.00
.aa»oo.
36.00
36.00
36.00
36.00
_2i»50_
30.00
36,00
30.00
36.00
_aa»oc_
36,00
36.00
36.00
30,00
3e»oa.
36.00
36.00
36,00
36,JO
atuaa.
36.00
36,00
36,00
36,00
aa.ua.
20,70
20,70
20,70
20,70
-.20*20..
20.70
20,70
20,70
20,70
-20*20-.
20,70
20,70
20,70
20,70
-20*20-.
20,70
20,70
20,70
20,70
.-20*20-.
20,70
20,70
20,70
20,70
.-20*20-.
20,70
20,70
20,70
20,70
,-2Q*2Q—
^4858800
4*261600
43664400
43Q67200
.42220000.
41672800
412755QO
40678300
40081100
.
337*3600
33146400
32549200
3195ZOOO
2*782700
2*185500
25588300
24991100
24323200,
181859QO
17586700
16991500
16394300
l52S2lOQ_
15199900
14602700
1*005500
13408300
TOTAL
NET
SALES
REVENUE,
S/YEAR
"2477300""
2477300
2477300
247730P
.-2S7220Q...
2477300
2477300
2477300
2477300
-1S6SZQQ...
1770600
177Q6QO
1770600
1770600
-1220600--.
1235800
1235800
1235800
1235800
-1235800...
529100
529100
529100
529100
—52S1CO—.
529100
529100
529100
529100
— 522100 — .
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
"42381500"
41784300
4U87100
40589900
.32222200-
39395500
38798200
38201000
376038QO
..
31973000
31375800
30778600
30181400
22524200..
255469QO
24949700
24352500
23755300
22153100-
17656800
17059600
16462400
15865200
15266000...
14670800
14073600
13476400
12879200
12222000..
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
*
42381556"
841656QO
125352*00
165942800
. — 202235500
245331000
284129200
322330200
359934000
...222252200
429722200
461098000
491876600
522058000
,—551642200
S77189100
602138600
6264913QO
650246600
—B234Q4200
691061500
70812UOO
7245635QO
740448700
—255216200
770367JOO
784461100
797937SOO
610816700
..£23038200
TOT 127500 110925JOOO 52821000 1224000 1090500 2R2000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TOvl OF COAL BUR'JED
'''ILLS PFR KILOJATT-H3UR
CENTS PER MILLION BTJ HEAT INPUT
t'DLLARS PE< TON OF SJLFUR REMOVED
PRUCrSi COST DISCOUNTED AT ll,6« T3 INITIAL YEAR, DOLLARS
L:VtLlZ£3 Ii-ICRtASE (OeCrtEAiE) IN UNIT OPERATING COST HQUIVAUENT TO
DQtLARS PE-! TON OF C3AL BURNED
ULLS PER KILOWATT-HOUR
CENTS PtR MILLI3N BTJ HEAT INPUT
COLLARS PES TO'J OF SJLFUR REMOVED
867386100 442874QO 923098700
16,42
6,80
78.20
708,65
313281POO
0,84
0,34
4.00
36, 1«
17316600
15,58
6,46
74.20
672.47
295964400
DISCUUNTfcO PROCESS CCST OVER LIFE OF POWER UNIT
15,22 0.85 14,37
6,30 0.34 5.96
72,46 4.01 68,45
656,64 36.30 620,34
-------
TABLE A-124. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: 90% S0_ removal)
7, of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge; bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
4
4
1
4
2
8
8
36
2
38
39
2
5
1
9
9
58
5
7
71
1
73
487
,376
,352
,136
,894
,868
,926
,740
693
,472
,188
,660
480
,140
,478
613
,263
,558
,912
,810
,862
,838
,063
,763
42
,838
,643
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
1.
11.
11.
2.
12.
7.
22.
22.
1.
93.
5.
98.
1.
100.
6.
1.
13.
4.
25.
25.
150.
14.
18.
183.
0.
4.
188.
3
2
1
9
5
3
8
3
8
2
6
8
2
0
3
6
4
0
3
1
4
9
0
3
1
7
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.
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.
277
-------
TABLE A-125. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: 90% S02 removal)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 7,180
Catalyst
Agricultural limestone 3,240
Filter aid 80
Coal 33,200
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 47,500
Utilities
Fuel oil 486,600
Steam 1,731,900
Process water 4,831,300
Electricity 81,867,400
Heat credit 66,900
Maintenance
Labor and material
Analyses 8,500
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 8.6%
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
Sulfur 35,300
Sodium sulfate 9,110
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton 739,500
4,600
tons 15.00/ton 48,600
tons 189.00/ton 15,100
tons 25.00/ton 830,000
tons 7.50/ton 1,400
1,639,200
man-hr 12.50/man-hr 593,800
gal 0.40/gal 194,600
MBtu 2.00/MBru 3,463,800
kgal 0.12/kgal 579,800
kWh 0.029/kWh 2,374,200
MBtu 2. 00 /MBtu (133,800)
2,334,000
man-hr 17.00/man-hr 144,500
9,550,900
11,190,100
4,305,800
6,333,300
1,536,200
59,400
162,100
12,396,800
23,586,900
tons 40.00/ton (1,412,000)
tons 23.00/ton (209,500)
21,965,400
$/ton coal $/MBtu heat
Mills/kWh burned input
6.28 14.64 0.70
3.36
0.02
0.22
0.07
3.78
0.01
7.46
2.70
0.89
15.77
2.64
10.81
(0.61)
10.62
0.66
43.48
50.94
19.60
28.83
7.00
0.27
0.74
56.44
107.38
(6.43)
(1.95)
100.00
$/ton
S removed
554
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, 39,620 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $39,140,000; total depreciable investment, $71,763,000; and total
capital investment, $73,643,000.
All tons shown are 2,000 Ib. ?7R
-------
TABLE A-126
WELLMAN-LORD/ ALLIED CHEMICAL PROCESS VARIATION FROMBASE CASE I 90K S REMOVAL* REGULATED CD. ECONOMICS
TOTAL CAPITAL INVESTMENT 73643000
YEARS ANNUAL POWER UNIT
AFTER JPERA- HEAT
POWER TIPNj REQUIREMENT/
UNIT KH-HR/ MILLION 8TU
START K«I /YEAR
1 7000 31500000
2 7(JQO 31500000
3 7000 31500000
4 7000 31500000
5 _2QQfi 315QQQQQ...
6 7000 31500000
7 7000 31500000
8 7000 31500000
9 7000 31500000
.10 '2000 _ .31500000...
11 5000 22500000
12 5000 22500000
13 5000 22500000
14 5000 22500000
.15 _ 5000 - .22502000--.
16 3500 15750000
17 35QO 15750000
18 3500 15750000
19 3500 15750000
2Q _ 3500 15Z5QQOQ _.
21 1500 6750000
22 1500 6750000
23 15QO 6750000
24 15QO 6750000
25 ' 15QQ 6Z5QOQQ ,
26 1500 6750000
27 1500 6750000
28 1500 6750000
29 1500 6750000
_3Q___ll500 6250000.-,
TOTAL
SULFUR BY-PRODUCT OP. CDST
REMOVED RATE/ INCLLOING NET ANNUAL CUMULATIVE
POWER UNIT BY EOUIVALENT NET AVENUE* REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TONS/YEAR */TC!N RC I FGR NET (DECREASE) (DECREASE)
CONSUMPTION, CONTROL POfcER SALES IN COST OF IN COST OF
TONS C3AL PROCESS* ELEMENTAL SODIUM ELEMENTAL SODIUM COMPANY, REVENUE* POWER, POWER*
/YEAR TONS/YEAR SULFUR SULFATE SULFUR SULFATE S/YEAR »/YEAR * *
1500000 39600 35300 9100 36.00 20,70 29759300 1459200 28299100 28299100
1500000 39600 35300 9100 36.00 20,70 29346900 1459200 27887700 56186800
1500000 39600 35300 9100 36.00 20,70 38935400 1459200 27476200 83663000
1500000 39600 35300 9100 36,00 20,70 28524000 1459200 27064800 110727800
— .-15QQOQQ — 326.00 35aoQ_.:.210Q— 36.00—20.20 2£1125ao.__l4522QC 2&6533Q& 122261100
1500000 39600 35300 9100 30.0" 20,70 27701100 1459200 26241900 163623000
1500000 39600 35300 9100 36,00 20,70 272896QO 1459200 25830400 189453400
1500000 39600 35300 9100 30.00 20,70 26878200 1459200 25419000 214872400
1500000 39600 35300 9100 36,00 20,70 26466800 1459200 25007600 239880000
ISQOQflQ 32600 3530Q__1_21QQ 22*50--. 20*20—26055300 2827.00 22.07.26.00 244252600
107HOO 28300 25200 6500 36.00 20,70 22*75200 1041800 2U33400 286386000
1071400 28300 25200 6500 30, uO 20,70 22063700 1041800 21021900 307407900
1071400 28300 25200 6500 30.00 20,70 21652300 1041800 20610500 328018400
1071400 28300 25200 6500 3o,oO 20,70 21240900 10418QO 20199100 348217SOO
1Q7.14QQ 20.300 252QQ .&5Qfl._-36»tt2— 20*2Q. --20222400— .1041800-,- .12232600 368005100
750000 19800 17700 4600 3D. 00 20,70 17950000 732400 17217600 385222700
750300 19830 17700 4600 36.00 20,70 17538500 732400 16806100 402028800
750000 19800 17700 4600 36.00 20,70 17127100 732400 16394700 41b423500
750000 19800 17700 4600 36.00 20,70 16715700 732400 15983300 434406800
. ..25Q2QQ 12800 12200— 1-4600— 36.UO— 20*20— 16304200 23240Q 15521800 442228600
321400 BSOO 7600 2000 36,00 20.70 12356900 315000 12043900 462022500
321400 8500 7600 2000 36.00 20,70 11947400 315000 11632400 473654900
321400 8500 7600 2000 36.00 20,70 11536000 315000 11221000 484875900
321400 8500 7600 2000 36,00 20,70 11124500 315000 10819500 495685400
. — 2214DQ 8500 26UQ— .2000— 36»02-..2C»2Q— 1C2131QD 315QQC 10328100 5060113500
321400 8500 7600 2000 36.03 20,70 1C3C1700 315000 99^6700 516070200
321400 8500 7600 2000 36, OJ 20,70 9890200 315000 9575200 525645400
321tOO 8500 7600 2000 36.00 20,70 9478800 315000 9163800 534809200
321400 8500 7600 2000 3o.0o 20,70 9067300 315000 8752300 543561500
221420 aSQQ 26QQ-.:.2QQQ— 36.0Q-..2Q*2Q £655200 215QQQ S34Q20Q 5512024QO
TOT 127500 573750000 27321000 721500 643500 166500
LIFETIME AVERAGE INCREASE H UNIT OPERATING COST
DOLLARS PER TO •> OF C3AL BURNED
MILLS PER KILQ>VATT-H3UR
CtiNTS PER MILLION BTJ HEAT INPUT
HOLLARS PER TON OF SJLFUR REMOVED
PROCESS COST DISCOUNTED AT 11,6% TO INITIAL YEAR* DOLLARS
LEVELlZED INCREASE (DECREASE) I.J UNIT OPERATING COST EQUIVALENT TU DI5CIX
DOLLARS PJR TON OF C3AL BURNED
MILLS PER KILP'J4TT-H3iJR
CENTS PER MKLI3U BTJ HEAT INPUT
DOLLARS PER TON Or SJLFUR REMOVED
578038900 26136500 551902400
21.16 0.96 20,20
9.07 0.41 B.66
100.75 4.56 96,19
801,16 36.22 764,94
207846100 10203800 197642300
PROCESS CDST CVER LIFE PF POWER UNIT
19,52 0,96 18,56
8,36 0.41 7,95
92.94 4,57 98,37
739,14 36.29 702,85
-------
TABLE A-127. WELLMAS-LOKD/ALLIED CHEMICAL COAL/SO2 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: oil-fired, existing)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four direct oil-fired reheaters)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S(>2 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
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
311,000
3,908,000
4,213,000
1,063,000
1,577,000
4,593,000
5,184,000
385,000
21,234,000
1,274,000
22,508,000
2,010,000
502,000
3,314,000
1,023,000
6,849,000
5,871,000
35,228,000
3,523,000
4,227,000
42,978,000 '
27,000
1,069,000
44,074,000
1.4
17.4
18.7
4.7
7.0
20.4
23.0
1.7
94.3
5.7
100.0
8.9
2.2
14.7
4.6
30.4
26.1
156.5
15.6
18.8
190.9
0.1
5.0
196.0
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.
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.
280
-------
TABLE A-128. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: oil-fired, existing)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 2 , 780
Catalyst
Agricultural limestone 2,740
Filter aid 31
Coal 12,840
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 45,440
Utilities
Fuel oil 2,626,800
Steam 509,700
Process water 1,956,900
Electricity 53,247,000
Heat credit 25,900
Maintenance
Labor and material
Analyses 8,130
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.4% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 13,700
Sodium sulfate 3,530
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton 286,300
1,800
tons 15.00/ton 41,100
tons 189.00/ton 5,900
tons 25.00/ton 321,000
tons 7.50/ton 1,400
657,500
man-hr 12.50/man-hr 568,000
gal 0.40/gal 1,050,700
MBtu 2.00/MBtu 1,019,400
kgal 0.12/kgal 234,800
kWh 0.029/kWh 1,544,200
MBtu 2.00/MBtu (51,800)
1,350,500
man-hr 17 .00/man-hr 138,200
5,854,000
6,511,500
2,750,600
3,790,400
1,028,400
56,800
62,900
7,689,100
14,200,600
tons 40.00/ton (548,000)
tons 23.00/ton (81,200)
13,571,400
$/bbl oil $/MBtu heat
Mills /kWh burned input
3.88 2.54 0.42
2.11
0.01
0.30
0.04
2.37
0.01
4.84
4.19
7.74
7.51
1.73
11.38
(0.38)
9.95
1.02
43.14
47.98
20.27
27.93
7.58
0.42
0.46
56.66
104.64
(4.04)
(0.60)
100.00
$/ton
S removed
885
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, 15,330 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,508,000; total depreciable investment, $42,978,000; and total
capital investment, $44,074,000.
All tons shown are 2,000 Ib.
281
-------
TABLE A-129
WELL'WJ-LQRD/ ALLIED CHEMICAL PROCESS VARIATION FROH BASE CASEl OIL FIKEO fcXISTING REGLLATED CO, ECONOMICS
TOTAL CAPITAL INVESTMENT 44074000
ro
oo
YEARS ANNUAL
AFTER QPERA-
PQWEK TIQNj
UNIT KW-HR/
START KW
1
2
4
5
6 7000
7 7000
8 7000
9 7000
.10 2QQQ—
11 5000
12 5000
13 5000
14 5000
.15 5QQO--
16 3500
17 3500
18 3500
19 3500
.20— —350.0—
21 1300
22 15QO
23 1500
24 15QO
.25 15QQ._
26 1500
27 1500
28 1500
29 1500
.30 1500—
POWER U'MIT
HfcAT
REQUIREMENT,
MILLION BTU
/YEAK
32200000
32200000
32200000
32200000
222QUO.QQ
PQs-IER U-UT
FUEL
CONSUMPTION,
PARRELS OIL
/YEAR
5324100
5324100
5324100
5324100
5324100
23000000 3802900
23000000 380?.qOO
23000000 3802900
23000000 3802900
— 23QQUQQQ 2202200—
16100000 2662000
16100000 2662000
16100000 2662000
16100000 2662000
161QQOQQ 2662UQQ _
6901QOO
6900000
6900000
6900000
1140''00
1 140^*00
1 140^00
SULFUR
REMOVED
BY
POLLUTION
CUNTRUL
PROCESS,
TONS/YEAR
BY-PROOUCT
RATE,
EQUIVALENT McT 4f-VgfiU£,
TONS/YEAR »/TON
ELEMENTAL SODIUM ELEMENTAL SODIUM
SULFUR SULFATE bULFUh SULFATE
15300 13700 3500
15300 13700 3500
15300 13700 3500
15300 13700 3500
152QQ 132QC— 1.3500— .
11000 9800 2500
11000 9800 2500
11000 9800 2500
11000 9800 2500
11QQQ 2fiQQ_.:.25QQ—
7700 6800 1800
7700 6800 1800
7700 6800 1300
7700 6800 1800
2200 6800— .1300— -
3300 2900 800
3300 2900 800
3300 2900 300
3300 2900 800
3300 22uo ' aac _
69QOOOO 1140°00 3300 2900 POO
690000Q ll^Q^QO 3300 2900 800
690QOOO 1140Q00 3300 2900 800
6900000 1140Q00 3300 2900 800
62QQQQO 1140200 3300 220Q.___.6QO—
36
36
3b
36
36
36
36
36
3e
36
30
36
30
36
36
.00
.0')
.00
.00
.on
.00
.00
.00
,OJ
.00
.0x1
.00
,cc
• 00
JhUQ
.00
.00
TOTAL
DP. CCST
INCLUDING
REGULATED
RCI FOR
CCMPANY,
VYEAR
20,70 18214600
20,70 17918900
20,70 17623300
20.70 17327600
—2Q.2Q 12Q2120Q.
20,70 14893000
20,70 14597300
?0,70 14301600
20,70 1*005900
20*20 132103QC.
20.70 11971400
20,70 11675700
20.70 11380000
20,70 11084300
20*20 1C28.&6.QQ.
20.70 84C6300
20,70 8110600
20,70 7814900
20,70 7519200
20*20 222350Q.
20,70 6927800
20,70 6632100
20.70 6336500
2o,70 6040800
...20*20 5245100.
TOTAL
NET
SALES
REVENUE,
*/YEAR
565700
565700
565700
565700
3.SQ8.QQ..
404600
40*600
4Q4fiQQ_,
282100
28210"
262100
282100
2EE100-.
1ZIOOO
121000
12100P
121000
121QQO-.
121000
121000
12100f
121000
121QOQ-.
NET ANNUAL
INCREASE
IPECREASE)
IN COST OF
POWER,
$
17648900
17353200
17057600
16761900
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER*
t
17648900
39002100
52059700
66821600
SZ4222QO
1*488400 99961100
1*192700 11*153800
13897000 128050800
13601300 14165ZIOO
— 122QS2QQ 154252800
11689300 166647100
11393600 178040700
11097900 189138600
10802200 199940800
.— 10506.500 2104*2300
8235300 Z1873J600
7989600 226722200
7693900 23*416100
7398200 241814300
2102500 248316800
6806800 255723600
6511100 262234700
6215500 266450200
5919800 274370000
5624100 22S2241QO
TOT 92500 425500000 70354000 203000 180500 47000
LIFETIME AVERAGE INCREASE (DECRhASE! IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
'ULLS pEK KILOUATT-HJUR
CtiJTS PER MILLION BTJ HEAT INPUT
DOLLARS PFR TON OF SJLFUK REMOVED
PROCESS COST DISCOUNTED AT 11.6% TJ INITIAL YEAR, DOLLARS
LEVELlZcD INCREASE (DECREASE) lit UNIT OPEKATIMG COST FOUlVALE^T TO
DULLARS PER BARREL OF OIL BURNED
MILLS PER KILQWATT-H3UR
CENTS PER MILLION BTJ HEAT iiiPUT
DOLLARS PFR TON OF SULFUR REMOVED
287281200 72B7100 279994100
4,08 0.10 3,98
6,21 0,1* 6,05
67,52 1,72 65,80
1415,18 35.90 1379,23
116641600 3280400 113361200
PROCESS CCST EVER LIFE tip PHWER UNIT
3.66 0.10 3,56
5.57 0.16 5,41
6C.50 1.70 58,80
1270,61 35.7* 1234,87
-------
TABLE A-130. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: alternate conversion in sulfur production unit)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
S02 absorption (four absorbers and entrainment separators, tanks,
pumps, filter^, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment separators,
tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
458,000
4,376,000
4,352,000
1,136,000
4,894,000
2,641,000
8,805,000
8,653,000
639,000
35,954,000
2,157,000
38,111,000
475,000
38,586,000
2,469,000
611,000
5,201,000
1,542,000
9,823,000
9,682,000
58,091,000
5,762,000
6,971,000
70,824,000
42,000
1,789,000
72,655,000
1.3
11.3
11.2
2.9
12.6
.7.3
22.6
22.3
1.7
93.2
5.6
98.8
1.2
100.0
6.3
1.6
13.5
4.0
25.4
25.1
150.5
14.9
18.1
183.5
0.1
4.7
188.3
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.
283
-------
TABLE A-131. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: alternate conversion in sulfur production unit)
Total % of average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
Direct Costs
Raw materials
Sodium carbonate 6,300
Catalyst
Agricultural limestone 3,240
Filter aid 32
Coal 32,580
Sand 180
Total raw materials cost
Conversion costs
Operating labor and supervision 47,500
Utilities
Fuel oil 477,500
Steam 1,689,400
Process water 4,712,400
Electricity 80,926,900
Heat credit 65,600
Maintenance
Labor and material
Analyses 8,500
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 8.6%
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
Sulfur 31,000
Sodium sulfate 8,000
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
tons 103.00/ton
tons 15.00/ton
tons 189.00/ton
tons 25.00/ton
tons 7.50/ton
1
man-hr 12.50/man-hr
gal 0.40/gal
MBtu 2.00/MBtu 3
kgal 0.12 /kgal
kWh 0.029/kWh 2
MBtu 2.00/MBtu
2
man-hr 17.00/man-hr
9
10
4
6
1
12
23
tons 40.00/ton (1
tons 23.00/ton
21
$/ton coal
Milla/kWh burned
6.20 14.47
648,900
4,000
48,600
6,000
814,500
1,400
,523,400
593,800
191,000
,378,800
565,500
,346,900
(131,200)
,300,900
144,500
,390,200
,913,600
,249,400
,248,300
,519,600
59,400
142,400
,219,100
,132,700
,240,000)
(184,000)
,708,700
$/MBtu heat
input
0.69
2.99
0.02
0.22
0.03
3.75
0.01
7.02
2.74
0.88
15.56
2.60
10.81
(0.60)
10.60
0.66
43.25
50.27
19.58
28.78
7.00
0.27
0.66
56.29
106.56
(5.71)
(0.85)
100.00
$/ton
S removed
624
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $38,586,000; total depreciable investment, $70,824,000; and total
capital investment, $72,655,000.
All tons shown are 2,000 Ib.
284
-------
TABLE A-132
WELLHAU-LORO SCRUBBING/ALLIED PROCLSS VARIATION FROM EASE CASE! LOW CUiWtRilCN, REGULATED CD, ECONOMICS
TOTAL CAPITAL INVESTMENT 7i65>5000
oo
Ul
YEARS ANNUAL PPKFP UNIT
AFTER OPERA- HtAT
POWER TION, REQUIREMENT,
UNIT KW-HR/ MILLION RTU
START KM /YEAR
1
2
3
4
6
7
8
9
.10
11
12
13
14
~16
17
18
19
.20
21
22
23
24
.25
26
27
28
29
.30
7000 31SOOOOO
7000 31500000
7000 31500000
7000 3150000P
_2&QO. 315QQQQQ
7000 31500000
7000 31500000
7000 31500000
7000 31500000
- 2UOQ 315QQQQQ _
5000 22500000
,5000 2250'~>000
5000 22500000
5000 22500000
5.0.0.6. 225.QUQO.Q .
3500 15750000
3500 15750000
35QO 15750000
3500 15750000
3500 15250.000
1500 6750000
1500 6750000
1500 6750000
1500 6750000
15QQ _ _^fi25l)QQQ._.
1500 67SOOOO
1500 6750000
15QO 6750000
1500 6750000
1500 625aCQO_--
TOTAL
SULFUR BY-PRODUCT UP. COST
REMOVED RATE, INCLUDING NFT ANNUAL CUMULATIVE
POhER UNIT BY EQUIVALENT NtT RtVtNUE, REGULATED TOTAL INCREASE NET INCREASE
FUEL POLLUTION TONS/YEAR WTL..'< RCI FCR NET (DECREASE) (DECREASE)
CONSUMPTION, CONTROL PQhfcP SALES IN COST OF IN COST OF
TONS CUAL PROCESS, ELEMENTAL SODIUM ELtMtr-.TAL SODIUM COMPANY, REVENUF, POWER, POWER,
/YEAR TONS/YEAR SULFUR SULFATE SULhUl* SULFATE */YEAR t/YEAR * *
ISOOOO'O 3*800 31000 BOOU 30,00 20,70 29239000 1281600 27957*00 27957400
1500000 3*800 31000 UQOfi 3S.OO 20,70 2^832900 1281600 27551300 55508700
1500000 3*800 31000 3000 36,00 20,70 26*26800 128160" 271*5200 82653900
1500000 3*800 31000 8000 36. CO 20,70 2&02060C 12E16QO 26739200 105393100
15.0.0000 34800 31QQQ ..flQOO. 3tt»U2 2LU2Q 22&1*.2QC 1281600 26233100 132226200
1500000 3*800 31000 8000 36. 00 20,70 27208700 1281600 25927100 161653300
1500000 3*800 31000 8000 39,00 20,70 2&802600 1281600 25521000 18717*300
1500000 3*300 31000 8000 36. CO 20,70 26396600 1281600 25115000 212289300
1500HOO 3*800 31000 8000 So. DC 20,70 25990500 1281600 2*7n89QO 236998200
-15.QQQ.QQ 34800 31QQQ 1.2000. 22»5U 2U»2Q 255844.0.0 863100 24221300 2612185QO
1071*00 24800 22100 5700 36.00 20,70 2208S500 9136QP 2117*900 28289*400
1071400 2*800 22100 5700 36, on 20,70 21682*00 913600 20768800 303663200
10710QO 24BQO 22100 5700 36,00 20,70 21276*00 91360" 20362800 324026000
1071400 2*800 22100 5700 36,00 20,70 JC870300 913600 19956700 3*3982700
1Q2140G . _ 2480Q. _221QQ__1.52QO 3tuOU 2Q*2Q- _2ti4fi63QQ. 2136QC.. 1255Q2QQ 3635334QO
750000 17*00 15500 4000 36.00 20,70 17649900 6408QO 17009100 380542500
750000 17400 15500 *"00 36, oo 20,70 17243800 64080" 16603000 397145500
750000 17400 15500 4000 36.00 20,70 16837800 640800 16197000 4133*2500
750000 17400 15500 4000 Sfr.lO 20,70 16431700 640800 15790900 429133*00
25&QQQ 12400 155QQ-_1.40QQ_-_ 3&*Uu... 2Q»2B__-lfiQ222QC 640800— -.15324200 44451830.0
321400 7500 6600 170C 36.00 20,70 12168600 272800 11895800 456*1*100
321«»00 7500 6600 1700 3t>,00 20,70 11762600 272800 11*'<9800 467903900
321*00 7500 6600 1700 36. oO 20,70 1135650C 27280P 11083700 478987600
321400 7500 6600 1700 36.00 20.70 1C95C40C 272800 10677600 489665200
221400 25QC. .fi6flQ-...12QB— 3t».bi-..2U»2a.__lC54S4DO. 222BQC...-1Q2216QQ 42S236800
321400 7500 6600 170" So.uO 20,70 1C138300 27280P 9865500 S09802300
321400 7500 6600 1700 36. <>•) 20,70 973230C 2728QO 9459500 519261800
321400 7500 6600 170C 36. oO 20,70 9326200 272800 9053400 52B315200
321400 7500 6600 1700 36.00 20,70 892MCO 2728QO 8647300 536962500
321*00 2500 66UQ___.12QQ 3fc»li£_._20»2Q £514100 222BQC 8241300 545203800
TOT 127500 573750000 27321000 634000 564000 145500
LIFETIME AVERAGE IN-CRtASE (DECREASE) IN UNIT OPERATING COST
HOLLARS PER TOI1 OF COAL BURNED
MLIS PtR KILOV'ATT-HDUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TOM QF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 11.6% TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DliCUUi
DOLLARS PER TUN OF COAL BURNED
'•'ILLS PER KILOWATT-HOUR
CENTS PER MILLION PTJ HEAT INPUT
DOLLARS PER TDII OF SULFUR REMOVED
5681C1300 2289750P 5*5203800
20,79 0.83 19,96
8.91 0.3A 8,55
99,C2 4.00 <»5.02
896.C6 36.12 B59.94
204203500 895600H 1952*7500
Tin PROCESS COST CVFR LIFE PF PDi^ER UNIT
19.17 0,8* 18,33
8,22 0.36 7,86
91,31 *,01 87.30
626,73 36.25 790,4S
-------
TABLE A-133. WELLMAN-LORD/ALLIED CHEMICAL COAL/S(>2 REDUCTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(Variation from base case: wet-scrubbing fly ash removal)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker, tanks,
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, gas ducts from chloride
scrubber to absorber)
SC>2 absorption (four absorbers and entrainment separators, tanks,
pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Fly ash removal (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
ESP credit
Sulfate crystallization (evaporator-crystallizer, heat exchanger,
pumps, agitator, tank, dryer, conveyors, centrifuge, bin, silo,
and feeder)
S02 regeneration (evaporators, heat exchangers, strippers, tanks,
agitators, pumps, blower, and condensers)
Sulfur production (complete unit for sulfur production)
Sulfur storage (storage and shipping facilities for 30-day production
of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
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
458,000
4,642,000
4,352,000
1,136,000
5,296,000
(4,713,000)
2,641,000
8,144,000
8,138,000
639,000
30,733,000
1,844,000
32,577,000
425,000
33,002,000
2,432,000
602,000
4,569,000
1,369,000
8,972,000
8,395,000
50,369,000
4,994,000
6,044,000
61,407,000
42,000
1,768,000
63,217,000
1.4
14.1
13.2
3.4
16.0
(14.3)
8.0
24.7
24.7
1.9
93.1
5.6
98.7
1.3
100.0
7.4
1.8
13.8
4.2
27.2
25.4
152.6
15.1
18.3
186.1
0.1
5.4
191.6
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.
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.
286
-------
TABLE A-134. WELLMAN-LORD/ALLIED CHEMICAL COAL/S02 REDUCTION PROCESS
ANNUAL REVENUE REQUIREMENTS
(Variation from base case: wet-scrubbing fly ash removal)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Coal
Sand
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
ESP electricity credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, ?
Total
annual
cost, $
% of average
annual revenue
requirements
6,300 tons 103.00/ton
3,240 tons
70 tons
29,140 tons
180 tons
15.00/ton
189.00/ton
25.00/ton
7.50/ton
47,500 man-hr 12.50/man-hr
648,900
4,000
48,600
13,200
728,500
1,400
1,444,600
593,800
3.21
0.02
0.24
0.07
3.60
0.01
7.15
2.94
427,100 gal
1,570,900 MBtu
4,264,200 kgal
114,122,400 kWh
58,700 MBtu
7,114,900 kWh
8,500 man-hr
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
0.029/kWh
17.000/man-hr
170,800
3,141,800
511,700
3,309,500
(117,400)
(206,300)
1,967,400
144,500
9,515,800
10,960,400
0.85
15.54
2.53
16.37
(0.58)
(1.02)
9.73
0.72
47.08
54.23
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
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Sulfur 31,000 tons
Sodium sulfate 8,000 tons
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
3,684,400
5,436,700
1,352,900
59,400
142,400
10,675,800
21,636,200
40.00/ton (1,240,000)
23.00/ton (184,000)
20,212,200
$/ton coal $/MBtu heat
Mills/kWh burned input
5.77 13.47 0.64
18.23
26.90
6.69
0.29
0.71
52.82
107.05
(6.14)
(0.91)
100.00
$/ton
S removed
581
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, 34,780 short tons/yr.
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $33,002,000; total depreciable investment, $61,407,000; and total
capital investment, $63,217,000.
All tons shown are 2,000 Ib.
287
-------
TABLE A-135
WFLI MAN-I OP(V ALLIED CHEMICAL PROCESS VARIATION FPO" BASF CASE: WFT <;c°i,=iRING FLY ASK RF"OVAL. REGULATED CO. ECONOMICS
TOTAL CAPITAL INVESTMENT
63217000
NJ
CO
CO
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
YEA"S ANNUAL POWFP. UNIT POWER UNIT RY EQUIVALENT NET REVENUE. RFRULATED
AFTER OPERA- HEAT FUFL POLLUTION TONS/YEAR t/TON ROI FOR
PO*»ER TION, RFOUIVEMENT. CONSUMPTION. CONTROL . PQWFR
UNIT KW-HP/ MILLION eTii TONS COAL PROCESS. FLFMEMT/SL SODIUM ELF^NTAL SODIUM COMPLY,
STAOT KW
1
2
3
4
_ 5
" 6
7
8
y
li)
11
12
13
1*
1C,
16
17
If-
19
2£
'21
22
23
24
25
2fe
27
28
2<>
TOT
7(ipn
7POO
7000
7000
JPfiO
7000
7000
7POO
7000
7QD.O.
5000
5POO
5000
5POO
5000
3500
3500
3500
3500
35fio
1500
1500
1500
1*00
1521!
1500
1500
1500
1*20
\275flO *
/YEAR
3150000"
31500000
31500000
31500000
.3.15..0..0J.O.O
31500000
31500000
31500000
.31500000
.31 5..0..0..0..Q 0
22500000
22500000
22500000
22500000
p?50j) 0.0, 0
15750000
15750000
15750000
15750"00
/YEAR TONS/YFAR SULFUP bULFATE
1500000 34POO 3100(1
1500000 34900 31000
1500000 34800 3100(1
1500000 34800 31000
ROOO
8000
8000
8000
15JJOJJJJJ! J48.0..0. 3.1000 _ 80.0.0 _
1500000 34800 31000
1500000 34800 31000
1500000 34800 31001)
1500000 34800 31000
1500000 34800 31000
1071400 24*011 22100
1071400 24800 22100
1071400 24800 22100
1071400 24800 22100
107J4jQ^ 248.QO 22.1^0
750000 17400 15500
750000 17400 15500
750000 17400 15500
750000 17400 15500
8000
8000
8000
8000
80.Q 0
S700
5700
5700
5700
57^ 0
4000
4000
4000
4000
SUI
36.
36.
36.
36.
Fliw
no
00
00
00
SULFATE */YF4°
20.70
20.70
20.70
20.70
26930600
26*78600
26226500
25S74400
J6_.00 20.70__ 25c?24fl£__
?f- B
36.
36.
36.
^6 .
'36.
36.
36.
36.
^6 .
36 .
36.
36.
36.
00
00
00
00
0 0
no
oo
00
00
00
00
00
00
OP
J5.J.5.PJJJJ1 750J)J)J) 1J4.0.P. 15500 40£0 36^00
6750000
6750POO
6750000
6750POO
675J]PJ)0
6750POO
6750000
6750000
6750000
675£PJ)0
73750000
LIFFTIMF AVFRARF Ir>.C&FASF
DOLLARS P
WILLS PFP
CENTS PER
321400 7500 6600
321400 7500 6,600
321400 7500 6600
321400 7500 6600
->2J400 75..QO 6600
321400 7500 6600
321400 7500 6600
321400 7500 6600
321400 7500 6600
IglMJO 7500 _ 66.00
27321000 634000 564000
(DECREASE) IN UNIT OfFBATIMfi COST
FP TON OF COAL TWNED
KILOrtATT-HOUP
MILLION 8TU HI-ST INPUT
1700
1700
1700
1700
1700
1700
1700
1700
1700
1700
145500
36.
3
3
3 .
"> .
-3
3
3 .
- .
-3
00
00
00
00
00
00
00
00
00
00
20.70
20.70
20.70
20.70
.20.70,
20.70
20. 70
20.70
20.70
2 0 . 70
20.70
20.70
20.70
20.70
25170300
24B18200
24466200
241 14100
2376 2 jj jl 0
20302900
19450800
19*93700
19246700
1 P8946JJO
16131600
15779600
15427500
15075400
NET ANNUAL
TOTAL INCREASE
NET (DECREASE)
SALES IN COST OF
REVENUE. POWER.
S/YEAR
1281600
1281600
1281600
1281600
*
25649000
25297000
24944900
24592800
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
$
25649000
50946000
75890900
100483700
128J6_oj! 24J4D8M • _ 12»T«+S50
1281600
1281600
1281600
1281600
1 29 1600
913600
913600
913600
913600
91360.fi
640800
640800
640800
640800
23888700
23536600
23184600
22832500
22^80^9J2
19389300
19037200
18685100
18333100
j 79P'} OHO
15490800
15138800
14786700
14434600
14R613200
172149800
195334400
218166900
1 "34^6*4^^0.0
"260036600
279073800
297758900
316092000
^ *" 3.349V49.00
349563800
364702600
379489300
393923900
20j70_ 14723400_ _64fi8_OJ) l*88.26flj> ' ;_'SJ)>B*l99fiO
20. rn~
20.70
20.70
20.70
20_j70
20.70
20.70
20. 70
20.70
20.70
HOLLOAS PFR ION OF SULFUR ^h«OVEO
PROCESS COST DISCOUNTED AT 1
LFVFLI7FD INC
1.6* TO INITIAL YFAW. DOLLOPS
P^AiE (OfCRMSI-) IN UNIT nofaecrlNr- ro
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-81-099
2.
3. RECIPIENT'S ACCESSION NO.
«. TITLE AND SUBTITLE Definitive SOx Control Process Eval-
uations: Aqueous Carbonate and Wellman-Lord (Acid,
Allied Chemical, and Resox) FGD Technologies
5. REPORT DATE
June 1981
B. PERFORMING ORGANIZATION CODE
7. AUTHORIS)
J.R. Byrd, K.D.Anderson, S. V.Tomlinson, and
R. L. Torstrick
B. PERFORMING ORGANIZATION REPORT NO.
TVA-EDT-121
3. PERFORMING ORGANIZATION NAME AND ADDRESS
TVA, Division of Energy Demonstrations and
Technology, Office of Power
Muscle Shoals, Alabama 35660
10. PROGRAM ELEMENT NO.
1NE827
11. CONTRACT/GRANT NO.
IAG-D9-E721-BI
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: 4/78 - 4/81
14. SPONSORING AGENCY CODE
EPA/600/13
,s.SUPPLEMENTARY NOTES IERL_RTP project officer is Michael A. Maxwell, Mail Drop 61,
919/541-2578.
16. ABSTRACT
repOrt gives results of economic evaluations of two processes: the
Rockwell International aqueous carbonate process (ACP) and the Wellman-Lord pro-
cess, the latter applied to a sulfuric acid plant, the Foster Wheeler Resox process ,
and the Allied Chemical coal reduction process , all for sulfur production. The ACP
uses a spray dryer flue gas desulfurization (FGD) system and molten salt reduction
with coal to make sulfur. For a 500-MW power plant burning 3. 5% sulfur coal, capi-
tal investments for the ACP and the Wellman-Lord (acid, Resox, and Allied) pro-
cesses are #119, #131, #138, and #141/kW, respectively. Annual revenue requirements
are 4. 81, 5.11, 6.03, and 5.94 mills /kWh, respectively. The ACP has a major cost
advantage because it incorporates final fly ash and chloride removal as process
functions. Fly ash removal credits and Wellman-Lord chloride control costs essen-
tially determine the capital investment relationships of the processes. The ACP has
a major advantage in annual revenue requirements because it does not need process
or reheat steam. Wellman-Lord process costs are the same for all three applica-
ions. The cost difference results from end plant costs to produce acid or sulfur. The
cost relationship could be affected by further development. The ACP, Resox, and
Allied processes have not been operated as commercial FGD systems.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Sulfur Oxides
Flue Gases
Desulfurization
Sulfuric Acid
Sulfur
Coal
Fly Ash
Chlorides
Pollution Control
Stationary Sources
Aqueous Carbonate
Wellman-Lord
Allied Chemical
Resox
Coal Reduction
13B
07B
21B
07A,07D
08G
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
319
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (fl-73)
289
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