EPA
TVA
United States Industrial Environmental Research
Environmental Protection Laboratory
Agency Research Triangle Park. NC 27711
EPA-600/7-85-006
February 1985
Tennessee Valley
Authority
Power and Engineering
Energy Demonstrations
and Technology
Muscle Shoals, AL 35660
TVA/OP/EDT-84/13
Economics of Nitrogen Oxides,
Sulfur Oxides,
and Ash Control Systems
for Coal-Fired
Utility Power Plants
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-85-006
TVA/OP/EDT-84/13
February 1985
Economics of Nitrogen Oxides,
Sulfur Oxides,
and Ash Control Systems for
Coal-Fired Utility Power Plants
by
J.D. Maxwell and L.R. Humphries
TVA, Power and Engineering
Division of Energy Demonstrations and Technology
Muscle Shoals, Alabama 35660
EPA Interagency Agreement No. 79-D-X0511
EPA Project Officer: J. David Mobley
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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DISCLAIMER
This report was prepared by the Tennessee Valley Authority and has been
reviewed by the Office of Energy, Minerals, and Industry, U.S. 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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ACKNOWLEDGMENTS
Technical and economic information from the suppliers of the type
processes evaluated was furnished by the following individuals whose coopera-
tion is greatly appreciated.
SCR Systems
John Cvicker
FW Energy Applications, Inc.
Bruce Bley,
D. J. Frey, and
Bernie Minor
Combustion Engineering, Inc. - C-E Power Systems
SCR - Spray Dryer - Baghouse Systems
James Clark
Joy Manufacturing
Air Heater Systems
Francis 0'Conner and
Henry Osborne
Combustion Engineering, Inc. - C-E Air Preheater
iii
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±v
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ABSTRACT
A U.S. Environmental Protection Agency (EPA)-sponsored economic evalua-
tion was made of three process combinations to reduce NOX, S02, and ash
emissions from coal-fired utility power plants. One case is based on a 3.5$
eastern bituminous coal; the other two are based on 0.7$ western subbituminous
coal. NOX control is based on an 80$ reduction from current new source
performance standards (NSPS); SC^ and fly ash control are based on meeting
the current NSPS. Selective catalytic reduction (SCR) is used for NOX
control in all three cases. Limestone scrubbing and a cold-side electrostatic
precipitator (ESP) are used in the 3.5$ sulfur coal case. Lime spray dryer
flue gas desulfurization (FGD) and a baghouse for particulate collection are
used in one 0.7$ sulfur coal case; limestone scrubbing and a hot-side ESP are
used in the other. The economics consist of detailed breakdowns of the
capital investments and annual revenue requirements. For systems based on a
500-MW power plant, capital investments range from $167 to $187 million (333
to 373 $/kW) and first-year annual revenue requirements from $54 to $60
million (29 to 33 mills/kWh). The 3-5$ sulfur coal case is highest because of
the higher S02 control costs. The case with the spray dryer and baghouse is
marginally lower in cost than the case with limestone scrubbing and hot-side
ESP. Costs for NOX control range from one-fourth to one-half of the total
costs, largely because of the high cost of the catalyst. The costs of the
overall systems and the relationships of the component costs are complexly
interrelated because of the interactions of the three processes.
v
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vi
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CONTENTS
Abstract v
Figures ix
Tables xi
Abbreviations and Conversion Factors xiii
Executive Summary S-1
Introduction 1
Background 5
Boiler Design and Operation 5
Fly Ash 9
Bottom Ash 9
Ash Handling 9
Bottom Ash 10
Fly Ash 10
Control of Nitrogen Oxide Emissions 11
Selective Catalytic Reduction 13
Electrostatic Precipitators 18
Fabric Filters 22
Spray Dryer FGD 24
Wet-Limestone Flue Gas Desulfurization 30
Chemistry 31
Forced Oxidation 32
Premises 35
Design Premises 35
Coal Premises 35
Power Plant 35
Flue Gas Compositions 37
Environmental Standards 37
NOx Control Process 41
FGD Process 42
Particulate Control Process 43
Solids Disposal 44
Raw Materials 44
Economic Premises 47
Schedule and Cost Factors 47
Capital Cost Estimates 49
Annual Revenue Requirements 51
Accuracy of Estimates 54
vii
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"57
Systems Estimated ^o
Case 1 I8
NOX Control ^°
S02 Control ^
Particulate Control ^
Case 2 °°
NOx Control °°
S02 Control ]1^
•Particulate Control 11^
Case 3 116
NOx Control 116
S02 Control 139
Reheat 1l*1
Particulate Control 1^1
Results 1^3
Base Case Comparisons 1^5
Capital Investment 1^8
Annual Revenue Requirements 153
Energy Requirements 158
Case Variations 158
Power Unit Size Case Variation 158
Two-Year Catalyst Life Case Variation 161
Ninety Percent Nitrogen Oxide Reduction Case Variations 163
Ammonia Price Case Variation 163
Conclusions 167
References 169
Appendix A A-1
viii
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FIGURES
Number Page
1 Typical pulverized-coal-fired boiler configuration 7
2 Landfill plan and construction details 45
3 Case 1 flow diagram 59
4 Case 2 flow diagram 89
5 Case 3 flow diagram 117
6 Base case capital investment (PC = process capital, C =
initial catalyst, 0 = other) 150
7 Base case annual revenue requirements (CC = capital charges,
C = conversion costs, RM = raw materials) 155
8 Variation of capital investment with power unit size .... 159
9 Variation of annual revenue requirements with power unit
size 162
10 Annual revenue requirements for 80 and 90 percent NOx reduc-
tion (CC = capital charges, C = conversion costs, RM =
raw materials) 164
ix
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TABLES
Number Page
S-1 Major Design Conditions S-3
S-2 Summary of Capital Investments in M$ S-5
S-3 Summary of Capital Investments in $/kW S-6
S-4 Summary of Annual Revenue Requirements in M$ S-7
S-5 Summary of Annual Revenue Requirements in mills/kWh S-8
S-6 Base Case Capital Investment Comparison S-9
S-7 Annual Revenue Requirement Element Analysis for Base
Cases S-12
S-8 Cost Per Ton of Pollutant Removed for Base Cases S-13
S-9 Comparison of Base Case Energy Requirements S-15
1 SCR Units for Coal-Fired Utility Boilers in Japan 17
2 Coal Compositions 36
3 Power Unit Operating Time and Heat Rate 37
4 Flue Gas Composition for 3-5? Sulfur Eastern Bituminous
Coal 38
5 Flue Gas Composition for 0.7? Sulfur Western Subbituminous
Coal 39
6 1979 Revised NSPS Emission Standards 40
7 SC-2 Emission Control Requirements 40
8 Particulate Matter Emission Control Requirements 41
9 Number of FGD Trains 42
10 Solid Waste Percent Moisture and Density 46
11 Raw Material Characteristics 47
12 Cost Indexes and Projections 49
13 Cost Factors 48
14 Indirect Capital Cost Factors 50
15 Contingency and Allowance for Startup and Modification Cost
Factors 50
16 Case 1 Material Balance 60
17 Case 1 Equipment List 63
18 Steam Sootblowing and Water Washing Requirements for Air
Heaters of Case 1 84
19 Case 2 Material Balance 90
20 Case 2 Equipment List 92
21 Steam Sootblowing and Water Washing Requirements for Air
Heaters of Case 2 113
22 Case 3 Material Balance 118
23 Case 3 Equipment List 121
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TABLES (Continued)
Number Page
24 Steam Sootblowing and Water Washing Requirements for Air
Heaters of Case 3 140
25 Summary of Capital Investments in M$ 144
26 Summary of Capital Investments in $/kW 145
27 Summary of Annual Revenue Requirements in M$ 146
28 Summary of Annual Revenue Requirements in mills/kWh 147
29 Base Case Capital Investment Comparison 149
30 Annual Revenue Requirement Element Analysis for Base
Cases 154
31 Cost Per Ton of Pollutant Removed for Base Cases 156
32 Additional Air Heater Operation and Catalyst Disposal Costs
from NOx Control 157
33 Comparison of Base Case Energy Requirements 160
34 The Effect of Catalyst Life on Annual Revenue Requirements
for NOX Control 161
35 Sensitivity of NOx Control to Ammonia Price 165
xii
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ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
aft3/min actual cubic feet per
minute
Btu British thermal unit
OF degrees Fahrenheit
dia diameter
FGD flue gas desulfurization
ft feet
ft2 square feet
ft3 cubic feet
gal gallon
gpm gallons per minute
gr grain
hp horsepower
hr hour
in. inch
k thousand
kW kilowatt
kWh kilowatthour
Ib pound
L/G liquid-to-gas ratio in
gallons per thousand
actual cubic feet of gas
at outlet conditions
M million
mi mile
mo month
MW megawatt
ppm parts per million
psig pounds per square inch
(gauge)
rpm revolutions per minute
SCA specific collection area
sec second
sft3/min standard cubic feet per
minute (60OF)
SS stainless steel
yr year
xiii
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CONVERSION FACTORS
EPA policy is to express all measurements in Agency documents in metric units. Values in this
report are given in British units for the convenience of engineers and other scientists accustomed to
using the British systems. The following conversion factors may be used to provide metric equivalents.
To convert British
Multiply bv
To obtain Metric
ac acre 0.405
Btu British thermal unit 0.252
°F degrees Fahrenheit minus 32 0.5556
ft feet 30.48
ft2 square feet 0.0929
ft3 cubic feet 0.02832
ft/min feet per minute 0.508
ft3/min cubic feet per minute 0.000472
gal gallons (U.S.) 3-785
gpm gallons per minute 0.06308
gr grains 0.0648
gr/ft3 grains per cubic foot 2.288
nP horsepower 0.746
in. inches 2.54
lb pounds 0.4536
Ib/ft3 pounds per cubic foot 16.02
Ib/hr pounds per hour 0.126
Psi pounds per square inch 6895
"i miles 1609
rpm revolutions per minute 0.1047
sfWmin standard cubic feet per 1.6077
minute (60°F)
ton tons (short) 0.9072
ton/hr tons per hour 0.252
hectare
kilocalories
degrees Celsius
centimeters
square meters
cubic 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
meters
radians per second
normal cubic meters per
hour (0°C)
metric tons
kilograms per second
ha
kcal
°C
cm
m2
m3
cm/s
m3/s
L
L/s
g
g/m3
kW
cm
kg
kg/m3
g/s
meter) Pa (N/m2)
m
rad/s
m3/hr (0°C)
tonne
kg/s
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ECONOMICS OF NITROGEN OXIDES, SULFUR OXIDES, AND ASH CONTROL SYSTEMS
FOR COAL-FIRED UTILITY POWER PLANTS
EXECUTIVE SUMMARY
This is a summary of a U.S. Environmental Protection Agency (EPA)-
sponsored evaluation in which the economics of three combinations of emission
control processes for coal-fired power plants are examined. Each combination
provides for the control of NOX, S02, and fly ash and bottom ash. They
represent typical adaptations of current emission control technology as
influenced by the types of coal used by utilities, particularly the low-
sulfur, predominately western subbituminous coals that have influenced the
types of processes used for S02 and fly ash control. The first combination,
case 1, is based on a high-sulfur eastern bituminous coal. Cases 2 and 3 are
based on a low-sulfur western subbituminous coal. The emission control
requirements are based on the assumption that a higher degree of NOX control
than now required is necessary; the S02 and fly ash control requirements are
based on meeting the current 1979 new source performance standards (NSPS).
INTRODUCTION
Most NOX emission control requirements now in force are being met by
modifications to the boiler combustion process. Combustion modifications now
being commercially used usually involve reducing the flame temperatures and
limiting the amount of oxygen available in the flame zone. These modifica-
tions include techniques such as staged combustion (bias firing, burners out
of service, and overfire air), flue gas recirculation, low excess air, and
dual-register burner designs. Advanced burner and furnace designs now under
development have the potential to provide significantly lower NOX emissions
than today's standards. These new combustion systems include fuel-staging and
after-burning approaches. However, these new designs are still several years
from commercial availability. If stricter regulations were adopted in the
near future, these combustion modification methods would not—at least for
several years—be adequate and flue gas treatment would be necessary. The
most highly developed method of flue gas treatment for NOX control is selec-
tive catalytic reduction (SCR) in which the flue gas is treated with ammonia
and passed over a solid catalyst to reduce the NOX to molecular nitrogen.
The need for flue gas treatment to meet NOX emission limits would probably
-------
be met by the use of SCR processes, several variants of which are offered
commercially. A generic SCR process, derived from these commercial processes,
is therefore used in all three cases.
Limestone scrubbing remains the predominant method of flue gas desulfuri-
zation (FGD), increasingly with provisions to produce gypsum by forced or
natural oxidation to reduce waste disposal problems. The use of low-sulfur
coal has, however, led to the rapid adoption of spray dryer FGD in which the
flue gas is contacted with a fine spray of absorbent that evaporates to solid
particles in the spray dryer and can be collected as a solid. More than a
dozen spray dryer FGD systems have been selected by utilities for low- and
medium-sulfur coal applications in the last five years. This trend is
represented by the use of a lime-based spray dryer system in case 2, one of
the low-sulfur coal cases. For case 1, the high-sulfur coal case, and case 3,
the other low-sulfur coal case, conventional limestone FGD systems producing
gypsum are used.
The use of low-sulfur coal has also led to the adoption of new methods of
fly ash control because the ash is difficult to collect in conventional cold-
side (after the boiler air heater) electrostatic precipitators (ESPs) that
have served as the industry standard for many years. In many such cases, hot-
side (before the air heater) ESPs have been used because the higher ash
temperature improves the electrical properties of the ash that affect the
efficiency of collection. In both cases, however, strict fly ash emission
regulations such as the 1979 NSPS strained the capabilities of then-existing
ESP technology, leading to the rapid adoption of fabric filter baghouses for
fly ash control. Baghouses, which are proving quite effective, have also been
the predominant choice for use with spray dryer FGD in which the fly ash and
FGD wastes are collected together. These uses are represented by a conven-
tional cold-side ESP in case 1, a baghouse in case 2, and a hot-side ESP in
case 3•
PROCESS DESCRIPTIONS
The base case designs are applied to a new, 500-MW boiler fired with
pulverized coal that operates 5,500 hr/yr for 30 years. The boiler meets the
1979 NSPS NOX emission requirements by combustion modification techniques.
The emission control systems are designed for an 80% reduction in these NOX
emissions and for reduction of S02 and fly ash emissions to the 1979 NSPS
levels. The designs upon which the costs are based include all equipment
involved in the collection and disposal of wastes, including a common onsite
landfill, and all boiler modifications—air heater modifications and larger
induced-draft (ID) fans—made necessary by the presence of the emission
control systems. Major conditions are shown in Table S-1.
The SCR systems consist of two trains of insulated reactors with ash
hopper bottoms (except in case 3 with an upstream ESP) and provisions for
changing catalyst beds. The beds are composed of 0.15- by 0.15- by 1-meter
S-2
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honeycomb blocks in metal modules. Flue gas is ducted from the economizer (or
hot-side ESP) outlet and returned to the air heater. Modifications to the air
heater to accommodate ammonia salt buildup are included. An ammonia storage
and handling system to inject an ammonia-air mixture in the inlet duct is
provided. An economizer bypass to maintain the reactor temperature during
low-load operation is included. The catalyst life is assumed to be one year,
with changes during scheduled boiler outages.
TABLE S-1. MAJOR DESIGN CONDITIONS
Case 1
Case 2
Case
Coal and boiler conditions
Coal East. bit.
Coal sulfur, % as fired 3.36
Coal ash, % as fired 15.1
Btu/lb, as fired 11,700
Sulfur emitted, % of total 92
Fly ash, % of total ash 80
NOx emitted, Ib/MBtu 0.6
Boiler sizea, MW 500
Heat rate, Btu/kWh 9,500
West, subbit.
0.48
6.3
8,200
85
80
0.5
500
10,500
West, subbit.
0.48
6.3
8,200
85
80
0.5
500
10,500
Emission control
NOx control
NOx reduction, %
S02 control
Absorber trainsb
Bypassed flue gas, %
S02 removal, overall %
S02 removal, absorber %
Fly ash control
Fly ash removal, %Q
SCR
80
Limestone FGD
5
0
89
89
Cold-side ESP
99.7
SCR
80
Lime spray dryer
4
12
65
73
Baghouse
99.9
SCR
80
Limestone FGD
5
28
65
90
Hot-side ESP
99.6
a. Based on coal consumption and heat rate.
b. Including one spare train.
c. In collection device, excluding upstream fallout,
The limestone FGD systems consist of multiple trains of spray tower
absorbers connected to a common inlet plenum and discharging to the stack
plenum. Each train consists of a presaturator, the absorber with a hold tank
and the associated absorbent recirculation system (and an oxidation tank in
S-3
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case 1), and a booster fan. A steam reheater is included in case 1 to provide
a stack temperature of 175°F. Flue gas is bypassed in the low-sulfur coal
case to eliminate reheating costs (in this case, a less expensive alternative
than full scrubbing at the low removal efficiency required). A single slurry
preparation area supplies the system. The gypsum waste is dewatered in a
thickener and rotary vacuum filters and trucked one mile to the landfill. A
spare absorber train and emergency bypasses for one-half of the scrubbed flue
gas are provided in all cases. A similar arrangement is used for the spray
dryer system in case 2 except that the baghouse booster fans also serve for
the spray dryer system. The spray dryers are cylindrical vessels with conical
bottoms with single rotary atomizers. The absorbent slurry consists of slaked
lime and recycled solids from the baghouse.
The ash control systems consist of the ESPs or baghouses (two parallel
identical units), hoppers, conveying systems, a bottom ash dewatering system,
storage silos for fly ash, and the equipment for trucking the waste to the
landfill. The bottom ash is collected in a conventional hopper and sluiced to
the dewatering system. Fly ash is conveyed to silos with a vacuum-pneumatic
system. The mixed fly ash and FGD waste in case 2 are conveyed with a
pressure-vacuum pneumatic system.
ECONOMIC PROCEDURES
The economics consist of the capital investment in 1982 dollars and the
first-year and levelized annual revenue requirements in 1984 dollars. The
annual revenue requirements consist of operating and maintenance costs plus
capital charges. The capital charges are levelized in both the first-year and
levelized annual revenue requirements; whereas, the operating and maintenance
costs are also levelized in the latter. The levelizing factor in all cases is
1.886, which represents a 6% annual inflation and a 10$ discount rate over the
30-year life of the project.
The costs include all costs associated with the construction and opera-
tion of the systems, including modifications to the boiler air heater and the
incremental increase in the boiler ID fans to account for the pressure drop
in the emission control equipment that is not compensated for by separate
booster fans. The construction and operating costs of the landfill are also
included.
The costs are divided into three sections representing costs for NOX,
S02, and ash control and are further divided into categories representing
particular unit operations within the processes. In cases in which equipment
or operations serve more than one process (incremental increases in boiler ID
fans and the common landfill, for example), the costs are prorated using the
appropriate factors (pressure drops or waste volume, for example). Baghouse
costs are not prorated, however, because of the effect of flue gas volume on
baghouse costs.
S-4
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RESULTS
The capital investments and annual revenue requirements are summarized in
Tables S-2 through S-5. With the choice of processes determined, at least in
part, by the type of coal, and the costs of the individual processes influ-
enced by other processes in the system, economic comparisons on a process-by-
process basis must be Interpreted with care, as seen in the detailed breakdown
of the base case costs.
TABLE S-2. SUMMARY OF CAPITAL INVESTMENTS IN M$a,b
Capital investment, mid-1982
NOx
S02 Particulate Total
Base case, 500 MM, 80$ NOx
removal
Case 1
Case 2
Case 3
Case variation, 200 MW, 80%
NOx removal
Case 1
Case 2
Case 3
Case variation, 1,000 MW, 80$
NOx removal
Case 1
Case 2
Case 3
Case variation, 500 MW, 90$
NOx removal
Case 1
Case 2
Case 3
41.9
50.1
48.1
20.6
24.2
24.3
77.7
94.8
91.2
48.2
55.5
53.9
101.8
54.0
69.4
58.2
31.7
41.4
175.7
97.4
121.1
101.9
54.0
69.4
42.9
62.6
53.5
22.6
31.4
27.8
73.3
110.7
94.6
42.9
62.7
53.5
186.6
166.7
171.0
101.5
87.3
93-5
326.6
302.9
306.9
193.0
172.2
176.8
a. Table S-1 lists the major design conditions for each case.
b. All values have been rounded; therefore, totals do not necessarily
correspond to the sum of the individual values indicated.
S-5
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TABLE S-3. SUMMARY OF CAPITAL INVESTMENTS IN $/KWa'b
investment,, mid-1 Q82 &
NOx
S02
Particulate
Total
Base case, 500 MW, 80$ NOx
removal
Case 1 83.7 203-7
Case 2 100.2 108.0
Case 3 96.1 138.7
Case variation, 200 MW, 80$
NOx removal
Case 1 103.1 291.0
Case 2 121.0 158.3
Case 3 121.6 206.9
Case variation, 1,000 MW, 80$
NOx removal
Case 1 77.7 175.7
Case 2 94.8 97.4
Case 3 91.2 121.1
Case variation, 500 MW, 90$
NOx removal
Case 1 96.4 203.8
Case 2 111 .0 108.0
Case 3 107.8 138.8
85.8
125.3
107.1
113.2
157-2
139.0
73-3
110.7
94.6
85.8
125.4
-107.1
373-2
333.4
342.0
507.3
436.6
467.5
326.6
302.9
306.9
386.0
344.3
353.6
a. Table S-1 lists the major design conditions for each case.
b. All values have been rounded; therefore, totals do not necessarily
correspond to the sum of the individual values indicated.
Base Case Capital Investments
Breakdowns of the base case capital investments are shown in Table S-6.
The case 1 (3*5$ sulfur coal, SCR, limestone FGD, and cold-side ESP) capital
investment is $187 million (373 $/kW), of which NOX control accounts for 22$
of the total; S02 control, 55$; and particulate control, 22$. The case 2
(0.7$ sulfur coal, SCR, spray dryer FGD, and baghouse) capital investment is
$167 million (333 $/kW) and the breakdown is 30$, 32$, and 38$. The case 3
(0.7$ sulfur coal, hot-side ESP, SCR, and limestone FGD) capital investment is
$171 million (342 $/kW) and the breakdown is 28$, 40$, and 32$. The low
percentage for S02 control in case 2 with the spray dryer results from the
S-6
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TABLE S-4. SUMMARY OF ANNUAL REVENUE REQUIREMENTS IN M$
a,b
Annual revenue requirements. 1984 &
First year
NOX S02 Partlculate Total
Levellzed
NOx S02 Partioulate Total
Base case, 500 MW, 80$ NOX
removal
Case 1
Case 2
Case 3
Case variation, 200 MW, 80$ NOX
removal
Case 1
Case 2
Case 3
Case variation, 1,000 MW, 80$
NOx removal
Case 1
Case 2
Case 3
Case variation, 500 MW, 90$ NOX
removal
* Case 1
Case 2
Case 3
21.9
26.5
24.7
9.7
11.6
11.1
51.2
47.9
26.1
30.1
28.6
28.8
12.7
18.0
16.3
7.6
11.0
48.8
22.2
30.3
28.8
12.7
18.0
9.8
14.4
12.1
5.2
7.7
6.6
16.1
24.5
20.5
9.8
14.4
12.1
60.4
53.6
54.8
31.2
26.8
28.7
106.4
97.9
98.7
64.6
57.2
58.6
35.8
43.5
40.4
15.6
18.7
17.8
68.1
84.2
78.4
42.9
49.5
46.8
41.0
16.9
24.9
23.1
10.1
15.3
69.2
29.2
41.4
41.0
16.9
24.9
12.8
19.0
15.8
6.9
10.4
8.8
20.9
31.8
26.4
12.8
19.0
15.8
89.7
79.4
81.0
45.6
39-2
41.9
158.2
145.1
146.3
96.7
85-4
87.5
a. Table S-l lists the major design conditions for each case.
b. All values have been rounded; therefore, totals do not necessarily correspond to the sum of the
individual values indicated.
-------
TABLE S-5. SUMMARY OF ANNUAL REVENUE REQUIREMENTS IN MILLS/KWRa'b
I
00
Annual revenue
reauirements. 1Q84 4
First vear
Levelized
Mills/kWh
NOX
Base case, 500 MW, 80$ NOX
removal
Case 1
Case 2
Case 3
Case variation, 200 MW,
removal
Case 1
Case 2
Case 3
Case variation, 1,000 MW
NOx removal
Case 1
Case 2
Case 3
Case variation, 500 MW,
removal
Case 1
Case 2
Case 3
a. Table S-1 lists the
6
9
9
80$ NOX
8
10
10
, 80?
7
9
8
90? NOX
9
10
10
major design
.0
.6
.0
.8
.6
.1
.5
.3
.7
.5
.9
.4
S02 Particulate
10.5
4.6
6.5
14.8
6.9
1C.O
8.9
4.0
5.5
10.5
4.6
6.5
conditions for
b. All values have been rounded; therefore
, totals
3
5
4
4
7
6
2
4
3
3
5
4
.5
.2
.4
.7
.0
.0
.9
.5
.7
.5
.2
.4
Total
22.0
19.5
19.9
28.4
24.4
26.1
19-3
17.8
18.0
23.5
20.8
21.3
NOX
13.0
15.8
14.7
14.2
17.0
16.2
12.4
15.3
14.3
15.6
18.0
17.0
S02
14.9
6.2
9-0
21.0
9.2
13-9
12.6
5.3
7.5
14.9
6.2
9.0
Particulate Total
4.
6.
5.
6.
9.
8,
3
5
4
4
6
5
7
9
7
.3
.4
.0
.8
.8
.8
.7
.9
.7
32.6
28.9
29.5
41.5
35.7
38.1
28.8
26.4
26.6
35.2
31.1
31.8
each case.
do
not neces
isarily co
rrespond
to the
sum of
the
individual
values indicated.
-------
TABLE S-6. BASE CASE CAPITAL INVESTMENT COMPARISON3
Case 1 . k*
Process capital
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Materials handling
Feed preparation
S02 absorption
Oxidation
Reheat
Solids separation
Lime parti culate recycle
Particulate removal and
m storage
I Particulate transfer
vo
Total process capital,
k$
Other Capital Investment
Waste disposal direct
investment
Land
Catalyst
Royalty
Other t>
Total
*
Total, $/kW°
NOx
1,311
7,829
3,813
819
13,805
19
10
12,028
163
15,530
11,855
83-7
S02
11,313
2,528
1,717
20,111
2,677
3,653
3,681
19,010
1,011
158
18,360
101,839
203-7
Particulate Total
1,311
10,509
5,636
17,156
3,311
377
21,710
12,887
85.8
1,311
7,829
16,197
819
2,528
4,717
20,111
2,677
3,653
3,681
10,509
5,636
80,271
7,371
815
12,028
463
85,600
186,581
373-2
NOX
1,328
9,278
1,513
1,220
16,369
31
15
11,678
563
18,431
50,090
100.2
Case
2. k$
Case ^. k$
S02 Particulate Total
7,374
1,132
1,258
12,992
2,140
24,896
527
75
28,478
53,976
108.0
4(961
15,446
6,779
27 , 1 86
2,719
326
32,388
62,619
125.3
1,328
9,278
16,878
1,220
1,132
1,258
12,992
2,110
15,116
6,779
68,151
3,310
116
14,678
563
79,297
166,715
333.1
NOX
1,297
8,453
5,386
861
15,997
30
15
13,155
563
18,001
18,061
96.1
SC-2 Particulate Total
11,175
1,266
2,363
18,070
2,265
35,139
817
113
33,272
69,371
138.7
1,290
11,351
1,378
23,022
2,628
313
27,583
53,516
107.1
1,297
8,153
20,851
861
1,266
2,363
18,070
2,265
11,351
1,378
71,158
3,505
111
13,155
563
78,856
170,978
312.0
a. Table S-1 lists the major design conditions for each case.
b. Consists of costs for "services, utilities, and miscellaneous"; all six items of "indirect investment"; "allowance for startup and
modifications"; "interest during construction"; and "working capital" as listed in the appendix tables.
c. All values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
-------
participate collection costs for FGD waste being combined with the fly ash
collection costs and assigned to particulate control costs.
Nitrogen Oxides Control—
For NOX control, the most important capital cost is the initial cata-
lyst charge, which is almost one-third of the total capital investment. Most
of the remaining capital costs are for the reactor and the associated internal
and external catalyst supports and handling system, and for the incremental
fan 'cost and flue gas ductwork associated with flue gas handling. The remain-
ing capital costs—ammonia storage and injection system, air heater modifica-
tion, waste disposal (of spent catalyst), land, and royalties—are relatively
minor. Incremental fan costs are minor; 90$ of the flue gas-handling costs is
for ductwork.
Most of the capital costs are directly related to the flue gas volume,
particularly for the major cost areas. As a result, the total capital invest-
ment for NOX control in case 1 is lowest because of lower flue gas volume
with the high-Btu coal. Case 3 is slightly lower than case 2 because of the
absence of fly ash.
Air heater modification costs are associated with the increase in size,
the more tightly packed elements, and the use of thicker and more corrosion-
resistant elements.
The ammonia storage and injection costs are almost the same for all three
cases. The only cost differences result from differences in the injection
grid, which vary with the flue gas duct size and design.
Sulfur Dioxide Control—
The capital investments for SC-2 control are highest for case 1 and
lowest for case 2, but the capital investment for case 2 does not contain the
costs for FGD waste collection. In all three cases, most of the costs are
associated with the S02 absorption area (the absorbers and the absorbent
liquid system or the spray dryers) and the flue gas-handling area (fans and
ductwork). These two areas account for 65$ of the process equipment costs in
case 1 and about 80$ of the process equipment costs in cases 2 and 3.
The higher capital investment for case 1 as compared with case 3 is
almost entirely related to the larger quantities of 862 removed. The
materials-handling (limestone), feed preparation, and solids separation area
costs are roughly two times higher and waste disposal costs are almost five
times higher for case 1 than for case 3- In addition, the S02 removal
requirements in case 1 require both full scrubbing—necessitating steam reheat
of the flue gas—and forced oxidation, neither of which is necessary in
case 3 •
SOX control in case 2 is the least expensive, primarily because of
lower costs in the S(>2 absorption area (because there is no liquid recircu-
lation system) and in the flue gas-handling areas (because of the lower
pressure drop in the spray dryers and the economy of scale with fan costs
S-10
-------
prorated between SC>2 and particulate control). An accurate comparison of
S02 control capital investment in cases 2 and 3» however, must include the
costs of particulate collection, which is discussed in the following section.
Particulate Control—
The capital investments for particulate control are $43 million for
case 1, $63 million for case 2, and $54 million for case 3. In all three
cases, the particulate removal and storage area accounts for about 60? of the
total particulate control process equipment costs, with the ESPs or baghouses
and their hoppers accounting for most of the area cost. The cold-side ESPs of
case 1 have an installed cost of $5.9 million and the hot-side ESPs of case 3
have an installed cost of $9.8 million. Most of this difference is a result
of the larger flue gas volume in case 3—both in an absolute sense and because
the ESPs in case 3 operate at a higher temperature. (An SCA of 500 ft2/
kaft3/min was used for case 1 after determining SCA values ranging from
about 450 to over 650 ft2/kaft3/min from several references. Some
reviewers state that an SCA range of 200 to 250 ft2/kaft3/min is adequate
to meet the ash removal required by the ESP in case 1. If an ESP designed
with an SCA of 250 was used, the investment and revenue requirements for
particulate control would be reduced about 15$.) The baghouses have an
installed cost of $7.4 million. Much of the cost difference between cases 2
and 3 is a result of the larger size of the baghouses and the corresponding
larger and more complex hoppers required.
Particulate transfer process equipment costs are $5.6 million for case 1,
$6.8 million for case 2, and $4.4 million for case 3. Case 2 has a more
complicated pressure-vacuum conveying system, which accounts for most of the
cost difference between cases 2 and 3.
Flue gas-handling costs are $1.3 million for case 1, $5.0 million for
case 2, and $4.4 million for case 3. The lower costs for case 1 result from
the smaller absolute volume and lower temperature of the flue gas. In addi-
tion, the costs for cases 1 and 3 are almost totally composed of the cost of
ductwork since the incremental fan costs are negligible. In the case of the
baghouses, however, fan costs are significant, about equal to ductwork costs,
because of the large pressure drop through the baghouses.
Base Case Comparisons - Annual Revenue Requirements
The base case annual revenue requirements are shown in Table S-7. The
first-year annual revenue requirements for case 1 (3.5% sulfur coal, SCR,
limestone FGD, and cold-side ESP) are $60 million (22 mills/kWh) with 36%
associated with NOX control, 48? with SC>2 control, and 16? with particu-
late control. For case 2 (0.7? sulfur coal, SCR, spray dryer FGD, and bag-
house), the first-year annual revenue requirements are $54 million (19.5
mills/kWh) with 49? associated with NOX control, 24? with S02 control, and
27? with particulate control. For case 3 (0.7? sulfur coal, hot-side ESP,
SCR, and limestone FGD), the first-year annual revenue requirements are $55
million (19-9 mills/kWh) with 45? associated with NOX control, 33? with
S02 control, and 22? with particulate control.
The levelized annual revenue requirements are $90 million (33 mills/kWh),
$79 million (29 mills/kWh), and $81 million (30 mills/kWh) for cases 1, 2, and
S-ll
-------
TABLE S-7. ANNUAL REVENUE REQUIREMENT ELEMENT ANALYSIS FOR BASE CASES
500-MW UNIT WITH 80% NO REMOVAL'
x
Direct costs
Ammonia
Catalyst
Lime/ limestone
Operating labor and
supervision
Process
Landfill
Steam
Electricity
Fuel
Maintenance
Analysis
Other
Total direct costs, k$
Indirect costs
Overheads
Capital charges
Total first-year annual
revenue requirements
k$
Mills/kWh"
Level ized annual
revenue requirements
k$
Mills/kWhb
NO
364
13,899
66
3
51
278
1
586
46
13
15,307
421
6,153
21,881
8.0
35,816
13.0
S02
1,216
658
523
1,369
2,146
162
4,276
104
27
10,481
3,337
14,970
28,788
10.5
41,031
14.9
Case 1
Particulate
230
436
581
135
1,025
6
19
2,432
1,018
6,304
9,754
3.5
12,811
4.7
Total
364
13,889
1,216
954
962
1,420
3,005
298
5,887
156
59
28,220
4,776
27,427"
60,423
22.0
89,658
32.6
NOX
336
16,962
66
5
65
492
1
695
46
17
18,685
487
7,363
26,535
9.6
43,521
15.8
S02
708
263
83
780
18
1,599
88
16
3,555
1,220
7,934
12,709
4.6
16,940
6.2
Case 2
Particulate
296
435
966
95
1,811
6
36
3,645
1,529
9,209
14,383
5.2
18,967
6.9
Total
336
16,962
708
625
523
65
2,238
114
4,105
140
69
25,885
3,236
24,506
53,627
19.5
79,428
28.9
NOX
336
15,549
66
4
63
391
1
679
46
41
17,176
477
7,065
24,718
9.0
40,359
14.7
(
SO 2
186
594
127
1,477
28
3,005
69
19
5,505
2,277
10,198
17,980
6.5
24,875
9.0
3ase 3
Particulate
230
393
993
87
1,299
6
36
3,044
1,157
7,871
12,072
4.4
15,794
5.7
Total
336
15,549
186
890
524
63
2,861
116
4,983
121
96
25,725
3,911
25,134
54,770
19.9
81,028
29.5
a. Table S-1 lists the major design conditions for each case.
b. All values have been rounded; therefore, totals do not necesarily correspond to the sum of the individual values indicated.
-------
3, respectively. For cases 1, 2, and 3, respectively, 40?, 55?, and 50? of
the total levelized annual revenue requirements are associated with NOX
control; 46?, 21$, and 31? with S02 control; and 14?, 24?, and 19? with
particulate control.
The cost per ton of pollutant removed is presented for the base cases in
Table S-8 based on each of first-year and levelized annual revenue require-
ments. A comparison on this basis indicates that NOX control is signifi-
cantly less cost effective than SC>2 and particulate control. For example,
with first-year annual revenue requirements, the costs in Table S-8 range from
about 31500 $/ton to 4,600 $/ton for NOX control, from about 500 $/ton to
over 1,900 $/ton for S02 control, and from 60 $/ton to 130 $/ton for
particulate control.
TABLE S-8. COST PER TON OF POLLUTANT REMOVED FOR BASE CASES
500-MW UNIT WITH 80? NOX REMOVAL
Case 1
Case 2
Case 3
NOx
3,490
4,600
4,280
First
S02
470
1,370
1,930
$/tonT
vear
Particulate
60
130
110
1984 $
Levelized
NOX
5,710
7,540
6,990
S02
670
1,820
2,680
Particulate
80
170
140
Nitrogen Oxides Control—
The first-year annual revenue requirements for the NOX control
processes in cases 1, 2, and 3, respectively, are $22 million (8 mills/kWh),
$27 million (10 mills/kWh), and $25 million (9 mills/kWh). In all cases, the
catalyst replacement costs are the overwhelmingly dominant cost elements:
over 90? of the direct costs and two-thirds of the total annual revenue
requirements are for the yearly replacement of catalyst. Except for this
cost, the annual revenue requirements are modest, appreciably less than the
costs for similar cost categories for S02 and particulate control.
Sulfur Dioxide Control—
The first-year annual revenue requirements for the S02 control proces-
ses are $29 million (11 mills/kWh), $13 million (5 mills/kWh), and $18 million
(7 mills/kWh) for cases 1, 2, and 3, respectively. Again, case 2 with the
spray dryer does not include costs associated with operation of the baghouse.
Excluding capital charges (which are proportional to capital investment) and
overheads (which are proportional to the direct costs), the direct costs of
the annual revenue requirements reflect appreciably wider differences in
S-13
-------
operating costs. The direct costs are $10.5 million, $3.6 million, and $5.5
million for cases 1, 2, and 3, respectively. Maintenance costs are the
highest element of direct costs in all three cases, followed again in all
three cases by electricity costs. Steam for reheating the flue gas is the
third largest direct cost (13$ of the total) in case 1, a cost not incurred by
cases 2 and 3, which have bypass reheat. These costs and the remaining direct
costs are all higher for case 1 than the corresponding costs for cases 2 and
3, a result of the large quantity of S02 removed for case 1. With the
exception of lime costs, which are 20? of the total direct costs, cass 2 has
lower direct costs in every category as compared with case 3-
Particulate Control—
The first-year annual revenue requirements for particulate control are
$10 million (4 mills/kWh), $14 million (5 mills/kWh), and $12 million
(4 mills/kWh) for cases 1, 2, and 3, respectively. The annual revenue
requirements for case 2, however, also include the collection of the spray
dryer FGD solids. Among the direct costs, maintenance costs are the highest
direct cost in all three cases, followed by electricity costs and labor costs.
Maintenance costs are highest for case 2, which are about 7555 higher than
case 1 and 40$ higher than case 3. Electricity costs are lowest for case 1
and highest for case 3, while case 2 has only slightly lower electricity costs
than case 3. Labor costs do not differ appreciably, although process labor in
case 2 is about 25$ higher than in cases 1 and 3.
Energy Requirements
The energy consumptions of the base cases, expressed in Btu equivalents,
are shown in Table S-9- The total energy requirements range from 4.89$ of the
boiler capacity for case 1 to 2.31$ of the boiler capacity for case 2. The
NOX control energy requirements are the lowest in all three cases and most
are for the incremental electricity consumption of the boiler ID fan that
compensates for the relatively small pressure loss in the reactors. For SOX
control, cases 1 and 3 have large electricity requirements because of the FGD
booster fans and the pumping requirements for the absorbent liquid recircula-
tion systems. These are similar in both cases. The electricity requirements
for the spray dryer in case 2 are lower because there is no liquid recircula-
tion system. Particulate control energy requirements in cases 1 and 3 are
mostly for ESP electricity, which is substantially lower for the cold-side
ESP. In case 2, most of the electricity is for the booster ID fans that
compensate for the relatively high pressure drop in the baghouse.
Power Unit Size Case Variation
The capital investments and annual revenue requirements of systems for
200-MW, 500-MW, and 1,000-MW systems are shown in Tables S-2 through S-5.
Compared with the 200-MW systems, the 500-MW systems are 83$ to 91$ higher and
the 1,000-MW systems are 222$ to 247$ higher in capital investment. In terms
of $/kW, the 1,000-MW systems are about one-third less expensive, however,
because of the economy of scale. The general relationships of the three cases
remain the same at all three power unit sizes. The rate of capital investment
increase is greatest for the NOX control processes (an increase of 275$ to
292$ between the 200-MW and 1,000-MW sizes, as compared with 193$ to 207$ for
the S02 control processes and 224$ to 253$ for the particulate control
S-14
-------
processes) and it is also higher for the spray dryer FGD process and the
baghouse than for the limestone FGD process and ESPs. As a result, the rate
of capital investment increase with size is greatest for case 2.
TABLE S-9. COMPARISON OF BASE CASE ENERGY REQUIREMENTS
Case
Steam,
MBtu/hr
Electricity,
MBtu/hr
Diesel fuel,
MBtu/hr
Percent of
power unit,
incut energy
Case ia
NOx
SOx
Particulate
Total
Case 2*>
NOx
SQx
Particulate
Total
Case 3b
NOx
SOx
Particulate
Total
3.15
83.79
0.00
86.94
4.00
0.00
0.00
4.00
3.88
0.00
0.00
3.88
12.97
100.20
27.14
140.31
25.40
40.26
49.85
115.51
20.18
76.20
51.22
147.60
0.01
2.65
2.20
4.86
0.02
0.30
1.55
1.87
0.02
0.46
1.41
1.89
0.34
3.93
0.62
4.89
0.56
0.77
0.98
2.31
0.46
1.46
1.00
2.92
Note: Does not include energy requirement represented by raw materials.
a. Based on a 500-MW boiler, a gross heat rate of 9,500 Btu/kWh for
generation of electricity, and a boiler efficiency of 90$ for
generation of steam.
b. Based on a 500-MW boiler, a gross heat rate of 10,500 Btu/kWh for
generation of electricity, and a boiler efficiency of 90$ for
generation of steam.
Compared with the 200-MW systems, the annual revenue requirements of 500-
MW systems are 91$ to 100$ higher, the 1,000-MW systems are 241$ to 265$
higher, and there is approximately a one-third reduction in costs in terms of
$/kWh. As with capital investment, the annual revenue requirements retain the
same general relationships at the three power unit sizes and the rates of
S-15
-------
increase for the NOX control processes are higher (328$ to 341$ between the
200-MW and the 1,000-MW sizes, compared with 175$ to 199$ for the S02
control processes and 210$ to 218$ for the particulate control processes) and
the rates for the spray dryer FGD and baghouse are higher than those of the
limestone FGD systems and ESPs.
Two-Year Catalyst Life Case Variation
To illustrate the effect of catalyst life on annual revenue requirements,
the annual revenue requirements for the three 500-MW base cases were also
determined for a 2-year catalyst life. The only change in NOX control
annual revenue requirements is a reduction in the catalyst cost by 50$—$7.0
million, $8.5 million, and $7.8 million for cases 1, 2, and 3, respectively.
The longer catalyst life reduces the annual revenue requirements of NOX
control by one-third. The annual revenue requirements of the overall systems
are reduced by 12$ to 16$.
Ninety Percent Nitrogen Oxide Reduction Case Variation
To evaluate the economic effects of a 90$ reduction in NOX, as compared
with the 80$ used in the other evaluations, the economics of the three 500-MW
cases were determined with 90$ NOX reduction. The primary differences from
the base case conditions are an NHgrNOjj ratio of 0.91:1.0 instead of
0.81:1.0, a 12$ increase, and an increase in catalyst (based on vendor recom-
mendations) of 22.5$ for case 1, 15.0$ for case 2, and 18.0$ for case 3. The
capital investments of the NOX control processes are increased 11$ to 15$
and the total for the three systems by 3$ to 4$, all of which is a result of
the increase in NOX reduction. The first-year annual revenue requirements
for the NOX process are increased 19$, 14$, and 16$ for cases 1, 2, and 3,
respectively. The effect on the annual revenue requirements of the overall
system of increasing the NOX from 80$ to 90$ is an increase of 7$ in all
three cases.
Ammonia Price Case Variation
Changes in the price of ammonia would have little effect on the overall
cost of the NOX control process. The annual revenue requirements for the
NOX control processes (in the 500-MW base case) increase only 1.5$ to 1.9$
as the ammonia price is doubled from the base case value of 155 $/ton to 310
$/ton.
CONCLUSIONS
The total costs for case 1, based on 3-5$ sulfur coal, and cases 2 and 3,
based on 0.7$ sulfur coal, differ less than 15$ in capital investment and
annual revenue requirements in spite of the differing control processes. This
is a result in part of offsetting differences—the much higher S02 control
costs for case 1 are offset by lower fly ash control costs and a smaller flue
gas volume. The costs for the two low-sulfur coal cases, one with a spray
S-16
-------
dryer FGD system and baghouse and the other with limestone FGD and a hot-side
ESP, differ only marginally in cost. In the two low-sulfur coal cases, the
low spray dryer FGD costs and the advantage of combined particulate collection
are offset by the higher NOX control costs and higher baghouse costs. When
only the SC>2 and fly ash control costs are compared, the spray dryer-
baghouse case is 5% lower in capital investment and 12? lower in annual
revenue requirements than the hot-side ESP and limestone FGD case.
The combined emission control processes increase the power plant capital
investment by about 35$ on the average, of which the NOX portion is about
one-third. Based on levelized annual revenue requirements, the average
increase in the cost of power is about 45?, of which the NOX portion is
about one-half.
The energy requirements of 2% to 5% of the boiler input energy are mostly
for SC>2 and particulate control. For the cases with limestone FGD, S02
control has the highest energy requirements.
The use of flue gas treatment for NOX control, such as the SCR process
in this study, would add significantly to emission control costs. An SCR
process for a 500-MW power plant would have a capital investment of 80 to 100
$/kW and annual revenue requirements of 8 to 9 mills/kWh. The high cost is
largely associated with the catalyst replacement cost, which accounts for 90?
of the direct costs in annual revenue requirements. A 2-year catalyst life
reduces the annual revenue requirements by over one-third, however, so the
costs for NOX control in this study, which are based on a 1-year life, could
be substantially reduced if extended catalyst lives are attained.
Other than catalyst life, the main factor affecting NOX control costs
is the flue gas volume which determines the fan and ductwork costs and the
catalyst volume. Increasing the NOx reduction efficiency from 80? to 90?
increases the costs by 10? to 20?, again because of the larger catalyst volume
needed. Ammonia costs have almost no effect on costs; doubling the price of
ammonia increases the annual revenue requirements by about 2?.
Although the costs of NOX control are in the same general range as
those for S02 and fly ash control, if the processes are compared on the
basis of the pounds of pollutants reduced, the costs for NOX control are 2
to 10 times greater than for SC>2 control and 40 to 60 times greater than for
ash control.
In S02 control, the major costs are associated with the absorption area
and flue gas handling (ductwork and fans). These costs do not differ greatly
among the three cases because of offsetting differences—a larger cost for
liquid circulation in the high-sulfur coal case but a larger flue gas volume
in the low-sulfur coal cases, which requires larger equipment and has larger
fan costs. The higher costs for the high-sulfur coal case are in large part
the result of the much larger quantity of sulfur removed: the materials-
handling, waste-handling, and disposal costs are two to five times higher for
the high-sulfur coal case than for the low-sulfur coal case with limestone
FGD.
S-17
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S-18
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INTRODUCTION
This report describes a U.S. Environmental Protection Agency (EPA)-
sponsored economic evaluation of three combinations of flue gas emission
control processes, each of which provides for the control of nitrogen oxides
(NOX), for flue gas desulfurization (FGD), and for fly ash removal. The
process designs are based on electric utility boilers fired with pulverized
coal, using a 500-MW boiler as the base case. The NOX emission level used
as the design basis is substantially lower than the present allowable limits
in most areas, representing possible regulatory changes that could result from
concerns about the effects of NOX on large-scale atmospheric phenomena such
as haze and acid rain (1). The S02 and fly ash emission levels are based on
the limits imposed by the 1979 new source performance standards (NSPS) (2).
The processes in each of the three cases represent some of the current
trends in emission control technology that are the product of changing
patterns of coal use by utilities, responses to existing or anticipated emis-
sion control requirements, and of developments that have produced more eco-
nomical and environmentally acceptable emission control processes. All three
cases include selective catalytic reduction (SCR) flue gas treatment for NOX
control. The first case (case 1) is based on the use of a high-sulfur eastern
bituminous coal; it includes a forced-oxidation limestone FGD process and a
conventional cold-side electrostatic precipitator (ESP) in addition to the SCR
process. The other two cases are based on the use of a low-sulfur western
subbituminous coal. One (case 2) includes a spray dryer FGD system with a
fabric filter baghouse that serves to collect both FGD waste and fly ash. The
other (case 3) includes a limestone FGD system (with natural oxidation to
gypsum) and a hot-side ESP.
Except for a few areas in the United States, the reductions in NOX
emissions required thus far for utility boilers have been met by modifications
to the combustion process that reduce the formation of NOX in the furnace.
These present commercial methods do not appear capable of providing substan-
tially higher levels of NOX reduction. New burner and furnace designs now
under development have the potential to provide significantly lower NOX
emissions than today's standards. However, these promising new combustion
modification designs are still several years from commercial availability (3).
Flue gas treatment would probably be necessary to meet near-term regulations
requiring reductions substantially below the existing 1979 NSPS limits.
Numerous flue gas treatment processes to control NOX emissions have been
brought to various stages of development and use, primarily in Japan where
large reductions in NOX emissions are required (4). Among these processes,
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SCR processes have proven popular because of their simplicity and effective-
ness; they have also been evaluated on a prototype scale in the United States
(5,6,7,8). SCR processes appear the most likely candidates for widespread use
if further large reductions in NOX emissions become necessary in the near
future. Because of this, an SCR process is used in each of the three cases
evaluated in this study.
The FGD and particulate control processes represent trends in emission
control that have been accelerated during the past few years by the increasing
use of low-rank western coals, which are growing in importance as a fuel for
electricity generation in the United States (9). Low-rank western coals--
typified in quantity of reserves and extent of use by the subbituminous coals
of the northern Great Plains and Rocky Mountains (10)—are characterized, as
compared with eastern coals, by a low heating value, a low sulfur and ash
content, a high moisture content, and a different ash chemical composition.
Many of the deposits can be efficiently and economically mined in large
volumes (11). Along with efficient coal transportation systems, this has made
them economically competitive over a wide area of the central and east-central
United States. They have been a source of low-sulfur coal to meet SC>2
emission requirements for some time and are also coming into increasing use in
situations that require FGD. This use has been accelerated by the increasing
use of coal to generate electricity in the trans-Mississippi west, as well as
the attractiveness of these coals as a reliable and economical source of coal
east of the Mississippi River (12).
The low-sulfur content of western coals has encouraged the development of
alternate methods of FGD that do not involve wet scrubbing. One result of
these efforts has been the development and rapid adoption of spray dryer FGD,
which is used in one of the three cases in this study. Wet limestone FGD,
used in the other two cases, remains widely used in high-sulfur coal applica-
tions and is also common in low-sulfur coal applications. The forced-
oxidation version used for the high-sulfur coal case in this study represents
an increasing use of this process innovation to reduce waste dewatering and
disposal problems.
The high-sulfur coal case has a conventional cold-side ESP, a type tradi-
tionally used in this type of application and one which has long provided
reliable and economic fly ash removals in the high 90$ range. The use of low-
sulfur coals, however, created collection problems (the removal efficiency of
cold-side ESPs depends in large part on the presence of conditioners such as
SOg in the flue gas) that led to the widespread use of hot-side ESPs, and
more recently, to fabric filter baghouses. Both types of ESPs remain in wide-
spread use in new construction but the difficulties of attaining the very high
removal efficiencies necessary for some emission regulations—exacerbated to
some degree by the use of western coals, which not only have a low-sulfur
content but an ash composition inimical to collection by electrostatic
methods—have led to an increasing use of fabric filter baghouses. The
frequent use of fabric filters with spray dryer FGD has also increased the
acceptance of baghouses.
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The processes used in this study represent several aspects of emission
control technology: The SCR process is a promising method of meeting low
limits of NOX emissions unattainable with the methods now in use; it is,
however, unlikely to replace these methods to meet existing emission limits on
its own merits. Hot-side ESPs and fabric filter baghouses are responses to
the problems encountered with some coals in attaining low fly ash emission
limits with conventional cold-side ESPs. Spray dryer FGD, on the other hand,
is an attractive alternative to conventional wet scrubbing and is replacing
wet scrubbing in some applications. Finally, the use of forced oxidation in
the limestone FGD process is a response not related to emission control, but
to problems of waste handling and disposal.
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BACKGROUND
All of the processes used in this study have been extensively discussed
in the technical literature. The following discussion is primarily a per-
spective of this literature with emphasis on details that have a direct
bearing on the processes in relation to the coals used and their interactions
in various combinations that have economic effects. Some of the processes—
notably the SCR process and the hot-side ESP—also intrude on boiler functions
in ways that directly affect the boiler operation.
The SCR process (13)f the limestone FGD process (14), and spray dryer FGD
(15) have been evaluated in previous Tennessee Valley Authority (TVA) economic
studies for EPA. Ash-handling and disposal economics—excluding the actual
collection of the ash—have also been evaluated in a similar study (16).
These evaluations focused on the economic comparison of individual processes
over a range of conditions.
The type of boiler also has an effect on the economics of some of the
processes. In terms of number and generating capacity, a dry-bottom boiler
fired with pulverized coal is most typical of utility boilers. About three-
fourths of the coal used by electric utilities is burned in this type of
boiler (17) and the type also predominates in new construction (18). In this
type of boiler, the coal is reduced to a fine powder and blown into the
furnace as a suspension in part of the combustion air. The term dry bottom is
applied to designs in which the ash solidifies as small particles while
suspended in the combustion gases, a part of which falls from the bottom of
the furnace as "dry" bottom ash. Similar wet-bottom furnaces are designed so
that the ash collects as molten slag on the furnace walls and drains from the
furnace in molten form. Wet-bottom designs are usually used only when problem
fuels make a dry-bottom design impractical. The other types of coal-fired
boilers used by utilities are stoker fired (which, although numerous, are
small and consume only about "[% of the coal used by utilities) and cyclone
fired [which are important producers of electricity but which have essentially
vanished from new construction (18)]. Dry-bottom boilers produce more fly ash
in proportion to bottom ash than the other types. Pulverized-coal-fired
boilers are also more adaptable to combustion modifications to reduce NOX
emissions.
BOILER DESIGN AND OPERATION
Modern dry-bottom boilers fired with pulverized coal generally have a
generating capacity of a few hundred to several hundred megawatts (MW), with a
representative average of 500 to 600 MW (18). The design of these boilers and
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other types is discussed in detail in manuals published by boiler manufac-
turers (19,20). In side view, the boiler somewhat resembles a compact
inverted U, as shown in Figure 1. The furnace for a typical (500 to 600 MW)
utility boiler is a rectangular vessel 40 to 50 feet on a side and up to 200
feet high (boilers designed to burn low-rank coals are usually larger for a
given capacity than those designed to burn high-rank coals). At the top is a
horizontal pass that contains superheater and reheater tubes and at the rear
is a vertical pass that contains additional superheater and reheater tubes and
an economizer that heats the boiler feedwater. The furnace and most or all of
the horizontal and vertical passes are lined with tubing that serves as part
of the boiler water-steam system. After passing through the economizer, the
flue gas-is passed through an air heater that heats the combustion air. The
flow of combustion air is controlled by forced-draft (FD) fans and the flow of
flue gas is controlled by induced-draft (ID) fans, generally situated down-
stream from the fly ash collection equipment if possible.
Air heaters recover heat from the flue gas by heating the combustion air.
This also improves the combustion performance and provides the heated air
necessary to dry the coal in the pulverizers. Air heaters can be either
recuperative—which are essentially large shell-and-tube heat exchangers—or
regenerative, in which a heat absorbing surface is exposed alternately to flue
gas and combustion air. The Ljungstrom air heater is typical of regenerative
air heaters (20). It consists of a large horizontal rotor with steel sheets
to provide a large surface. The rotor turns slowly in a housing with
elaborate seals to provide parallel paths for flue gas and combustion air so
that sections are exposed alternately to flue gas and combustion air. Air
heaters are exposed to flue gas near the acid dewpoint and cool combustion air
and are subject to corrosion and plugging. Processes that affect the flue gas
properties upstream from the air heater may make modifications to the air
heater necessary.
The coal is reduced to a fine powder—typically about 100 micrometers in
size—and dried in pulverizers—typically consisting of rollers that ride on a
rotating bowl-shaped grinding table (21). A portion of the heated combustion
air—called primary air—is passed through the pulverizer to dry the coal and
transport it to the furnace burners. The burners, up to a few dozen in
number, are arranged in various arrays in the front, front and back, or
corners of the furnace. The coal-bearing primary air is injected through a
central nozzle in the burner and all or some of the remaining combustion air,
called secondary air, is injected through a larger orifice surrounding this
nozzle. Burner design philosophy has undergone a revolution as the result of
NOX emission regulations stemming from the Clean Air Act Amendments of 1970
(Public Law 91-604). Before these regulations, burner design had concentrated
on the production of a hot, compact flame; conditions that increased carbon
burnout; improved flame stability; and minimized operating problems such as
slagging, but which also increased the formation of NOX. In the 1970s, the
objective became the development of burners that decreased the maximum flame
temperature and minimized the concentration of oxygen present at the higher
temperatures.
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Economizer
Horizontal and
vertical passes
with superheaters
and reheaters
To hot-side
emission control
systems
Air heater
To cold-
side
emission
' control
system
Induced-draft fan
Forced-draft fan
^ Combustion air
Ash sluice pump
Figure 1. Typical pulverized-coal-fired boiler configuration.
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The coal particles suspended in the combustion air burn in less than a
second. A small part of the nitrogen in the coal and air is converted to
NOX during this time. Sulfur is oxidized to S02 and a small percentage is
further oxidized to 803. The NOX and the sulfur oxides, except for a
small percentage trapped in the ash particles, remain as gases in flue gas.
Some of the mineral matter in the coal such as carbonates and some minor
elements are decomposed to gaseous oxides. Other mineral matter such as
alkali metals and some trace elements vaporize and, subsequently, condense as
submicrometer particles or on the surfaces of other particles. Most of the
mineral matter is wholly or partly fused and solidifies as small particles
that are typically spherical and porous or hollow. The larger particles and
agglomerates of particles, along with slag dislodged from the furnace, fall
through a throat in the bottom of the furnace as bottom ash; the rest, usually
about 80% of the total, is carried out of the furnace as fly ash in the flue
gas.
The flue gas typically enters the horizontal pass at about 2,000°F and
the economizer at about 800°F. It usually enters the air heater at about
700°F where it is cooled to about 300°F. The temperature of the flue gas
leaving the air heater is usually determined by the need to avoid the corro-
sive effects of sulfuric acid condensation. The acid dewpoint is usually in
this range, depending on the sulfur content of the coal and the fraction
converted to SOg.
The water content of the flue gas under ideal conditions is determined by
the inherent moisture (that contained in the coal as mined) and surface
moisture contents of the coal, the water content of the combustion air, and
the water formed during combustion. This usually produces a water dewpoint of
roughly 120°F to 130°F in the flue gas, lower for bituminous coals with
low inherent moistures and higher for subbituminous coals with high inherent
moistures. Several factors can contribute to higher flue gas water contents,
however, often in ways that produce wide unpredictable variations. Among
these are variations in the surface moisture on the coal and humidity of the
air caused by precipitation, sootblowing and sootblower malfunctions, and
steam leaks. Normally the flue gas leaving the boiler is well above the water
saturation temperature; the variations can, however, have important effects on
the design concepts and operation of spray dryer FGD systems.
The bottom ash that falls through the throat at the bottom of the furnace
is collected in a bottom ash hopper. Other systems are used but it is
typically a water-filled multiple-vee-bottom hopper that is periodically
emptied by sluicing the ash through clinker grinders into a pump that trans-
ports the ash as a water slurry to a pond or dewatering system.
Most of the fly ash remains entrained in the flue gas and is removed in
the fly ash collection equipment—ESPs or baghouses. Some, however, settles
in the boiler or post-boiler equipment where it is necessary to place hoppers
and handling equipment to remove it. Usually hoppers are installed at the
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base of the vertical pass containing the economizer and on the air heater.
SCR reactors have usually been equipped, as they are in this study (except for
the case with a hot-side ESP preceding the SCR reactor), with a hopper bottom
to collect ash.
Flv Ash
In appearance, fly ash is a light powdery material ranging in color from
earthy brown to black with somewhat the texture of a gritty silt. The geo-
metric mean diameter is usually between 10 and 20 micrometers, with 1$ to 10$
below 1 micrometer and about 90$ below 100 micrometers (22), a size distribu-
tion that encompasses clay through fine sand. Most fly ash particles consist
of vitreous spheres that are frequently hollow (23). Others consist of frag-
ments of spheres, irregular porous fragments, agglomerates, and char. The
major chemical constituents are silicon, aluminum, and iron, which occur
primarily as a variety of vitreous and crystalline silicates and oxides (24).
The calcium, magnesium, and sodium contents seldom exceed 2% each in eastern
bituminous coals; in western subbituminous coals and lignites, however, the
calcium content usually exceeds that of iron and is usually in the 10$ to 20$
range. The magnesium and sodium contents of western coals are also usually
higher than those of eastern coals. The carbon contents, which depend on the
boiler operating conditions, are often less than 1$ but may temporarily exceed
20$.
Fly ash is rich in minor and trace elements, a result of the process of
coal formation in which 25 to 40 elements are abnormally concentrated (25).
Many of these elements, among them those with potential harmful effects such
as antimony, selenium, arsenic, and lead, are concentrated in the fly ash
portion of the ash during combustion. There is also a variation of chemical
composition with particle size and, in some cases, between the surface and
interior of the ash particles.
Bottom Ash
Bottom ash is a relatively innocuous material similar in physical prop-
erties to a sandy gravel (26). Most of the particles range from 0.2 to 10 mm
(less than 1/100 to about 3/8 inch) in size and range in texture from dense
pieces of slag through rounded and angular vesicular particles to porous
sintered aggregates. It has the same bulk chemical composition as fly ash but
is depleted in the more volatile elements and is less reactive.
ASH HANDLING
The ash-handling systems consist of the hoppers associated with the
boiler and emission control equipment, hydraulic and pneumatic transporting
systems, and dewatering and storage equipment. Several methods and numerous
variations of methods adapted to particular requirements are used. There has
been, however, a trend toward methods that reduce or eliminate the use of
water sluicing, the traditional method of transporting ash to the disposal
site. There has also been at least the beginnings of a trend to incorporate
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improved technology in the form of improved hopper designs, transporting
systems, and continuous ash removal systems into utility ash-handling systems.
These and conventional ash-handling systems are discussed in detail in manu-
facturers' publications (20,27)-
The equipment associated with the slurry-handling and transport systems
is subject to severely abrasive conditions. Hard steels and iron are used for
pumps and lines, often with wear plates or ceramic inserts at points of
extreme wear such as nozzles and bends. Sometimes pipes lined with abrasion-
resistant materials such as basalt are used. Corrosion and scaling can also
be a problem in closed-loop water systems, necessitating water softening
treatment and pH control.
Bottom Ash
Bottom ash hoppers are equipped with clinker grinders (two opposed steel-
toothed rollers) through which the ash is periodically sluiced into a trans-
portation pump by jets of water. The pump may be either a water ejector or a
centrifugal pump. Water ejectors are simpler, less prone to plugging and air
locks but centrifugal pumps produce higher heads and can be staged to provide
higher pressures if necessary. The ash is transported as a 1$ to 6$ solid
slurry at velocities up to about 700 ft/min, either to a temporary or
permanent disposal pond or to a dewatering system.
Bottom ash dewatering systems (27) consist of dewatering bins into which
the ash is pumped from the boiler hopper. Water drains from the ash into a
settling tank to remove fines and then drains to a storage tank for treatment
and reuse. The ash in the dewatering bin is dumped to a truck for removal to
the storage or disposal area. Often the water must be treated to control
scaling and adjust extreme pH levels.
A different type of bottom ash system called a submerged scraper conveyor
or submerged drag bar chain conveyor, widely used in Europe, is now offered by
several U.S. vendors and is coming into use in the United States (20). The
boiler ash hopper is a water-filled low-profile hopper containing a continuous
drag bar conveyor in the bottom. The drag bar conveyor (essentially two
chains at each side of the hopper bearing transverse bars) operates continu-
ously, drawing the ash to the end of- the hopper and up an inclined dewatering
screen. The ash can be passed through a clinker grinder and removed by
conveyor or by trucking.
Flv Ash
Fly ash removal is frequently complicated by difficulties in removing the
ash from the collection hoppers. Fly ash is usually somewhat hygroscopic and
may pack and cake if it is allowed to approach the acid or water dewpoint
temperature. Western coals also frequently produce ash with cement!tious
properties that add to the caking problems. The hoppers must be carefully
designed and the system carefully operated to ensure efficient operation. The
hopper bottoms generally slope at 55 degrees or more from the horizontal to a
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center outlet a foot or more across. The hoppers must also be heavily
insulated and may be equipped with heaters, vibrators, and heated-air
fluidizers. Economizer ash hoppers may be designed for continuous removal,
for collection of the ash in water, or for isolation of the ash from the hot
flue gas because of the tendency of economizer ash to form agglomerates—or to
burn if it is rich in carbon.
Fly ash is usually removed from the hoppers intermittently through air
lock valves by a vacuum or pressure pneumatic system. Usually the system is
cycled so that one or a group of hoppers are emptied at a time. Vacuum
systems allow the use of simple air lock valves and supplement the action of
gravity with suction to remove ash from the hoppers. They are, however,
limited in the distance that the ash can be transported and they are less
efficient at higher altitudes. Pressure systems (which usually operate below
15 psig) require more complex air lock valves but they have higher capacities.
Vacuum systems and most pressure systems operate in an overall "dilute phase"
in which the ratio of fly ash to air is 20 to 1 or less and the velocities are
1,500 ft/min or more. "Dense phase" pressure systems with much higher ash-to-
air ratios and lower velocities are coming into use, however (28).
In large complicated hopper systems, such as those associated with large
baghouses, a vacuum-pressure system may be used. This allows the use of
simplified air lock valve systems. The ash is conveyed by the vacuum system
to a nearby separator mounted on a surge tank, from which it is conveyed to
storage silos by the pressure system.
The vacuum in vacuum systems can be supplied by a mechanical pump or by
steam or water eductors. If water eductors are used, the ash can be drawn
directly into the eductor and mixed with the water- The slurry of a few
percent solids is discharged to a deaerator tank and flows by gravity to a
disposal pond. The ash can also be removed in cyclone-baghouse collectors and
stored in a surge tank, from which it is removed, slurried, and pumped to a
pond. Since the fly ash cannot be readily dewatered, once slurried for trans-
portation by sluicing, some form of temporary or permanent pond disposal is
inevitable. Because of the practical and environmental problems associated
with ponding, this once almost universal method of fly ash disposal is giving
way to dry collection and disposal methods. Increasing use of fly ash has
also encouraged dry collection methods.
In dry disposal, the ash is removed from the conveying air using the same
cyclone-baghouse collection system and stored in metal or concrete silos. The
silos are usually elevated to permit direct loading into trucks or railcars,
often through a moisture-mixer to reduce dusting problems.
CONTROL OF NITROGEN OXIDE EMISSIONS
The formation of nitrogen oxides is not an invariant function of the fuel
characteristics but depends in part on the nature of the combustion process.
NOX (consisting of about 90$ to 95$ NO and 10$ to 5% N02) is formed by the
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temperature-promoted reaction of oxygen with nitrogen in the combustion air
(called thermal NOX) and nitrogen in the fuel (fuel NOX). The quantity
formed depends on the time-temperature relationship of the combustion process,
the amount of oxygen available at the higher flame temperatures, the quantity
of fuel nitrogen in the coal, and the nature of the release of fuel nitrogen
during combustion (29). Consequently, the emission of NOX can be controlled
to some extent by modifying the combustion process. This approach to NOX
emission control--"combustion modifications"—has proven widely successful in
meeting many NOX emission control requirements. Flue gas treatment, how-
ever, is technically capable of providing larger reductions in NOX emissions
and is thus a potential alternative means of attaining low emission levels.
Combustion modification techniques consist of physical modifications to
the fuel burners (this is most feasible in pulverized-coal-fired boilers) and
the furnace to reduce the flame temperatures and the duration of higher
temperatures and to limit the amount of oxygen available during the higher
temperatures. In general, the burners are designed to produce a low-
turbulence flame with "staged combustion" to maintain an oxygen-deficient
atmosphere during the combustion phases most favorable for NOX formation.
To reduce the availability of oxygen, the lowest practical excess air level is
used and some of the combustion air may be admitted through air ports around
or above (overfired air) the burners, or burners that are not supplied with
coal may be used to admit air ("burners out of service"). The area of the
furnace occupied by the burners may also be increased to reduce the flame
intensity and the heat-absorbing area of the furnace may be increased to
induce a rapid initial cooling of the combustion products.
Several successful low-NOx burners and furnace designs are now offered
commercially (30). They have become standard equipment, along with the
associated furnace modifications, for new construction to meet most NOX
emission control requirements. Such burners combined with the injection of
pulverized limestone for SC>2 control—for example, the limestone injection
multiple burner or LIMB process—are also being developed (31). Combustion
modifications are not, however, without problems associated with an oxygen-
deficient atmosphere such as slagging and tube corrosion. The present NOX
emission limits are, in part, a balance between the possible reductions
attainable and the severity of operating problems associated with combustion
modification techniques (32).
'x
Several general types of flue gas treatment processes to control NOA
emissions have advanced to various stages of development and use, including
wet-scrubbing and dry adsorption processes that frequently also incorporate
S02 removal. Wet processes have been essentially abandoned because of their
complexity and expense (33); the development of dry adsorption processes is
continuing, however (34). The most highly developed processes involve injec-
tion of NHg into the flue gas to reduce the NOX to molecular nitrogen.
These appear to be the most economical methods of flue gas treatment and do
not produce a waste product. Processes of this type are in commercial use in
Japan, although limited information is available on their use on coal-fired
boilers (35). They are called selective reduction processes because the
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reaction of NH3 with NOX rather than other flue gas components is favored
(other troublesome reactions such as the formation of ammonium-sulfur
compounds occur, however). Adequate uncatalyzed reaction rates occur in a
narrow temperature range at about 1,700°F to 1,800°F which has led to the
development of processes in which the NHg is injected into the furnace above
the burner zone. These processes—called selective noncatalytic processes
(SNR)—are actively being developed (36). Most of the processes, including
those in commerical use, involve a catalyzed reaction at a lower temperature
and are called SCR processes. The catalyzed reaction occurs in a temperature
range between about 600°F to 750°F, allowing treatment of the flue gas
after it has passed through all of the boiler components except the air
heater. The flue gas from the boiler economizer is treated with M$ and
ducted to a reactor containing beds of catalyst and is returned to the boiler
air heater. Usually it is necessary to modify the air heater because of
reaction byproducts and unreacted NHg in the treated gas.
Selective Catalytic Reduction
A typical SCR system consists of one or more trains of vertical reactor
vessels connected by ducts to the economizer outlet. The ammonia is injected
into this duct as a dilute mixture in air. The flue gas containing the
ammonia flows downward through the reactor, passing through multiple layers of
catalyst, which is in the form of honeycomb-like blocks or bundles of tubes.
The flue gas is ducted from the reactor to the air heater- If not preceded
by an ESP, the reactor has a hopper bottom to remove fly ash that settles in
the reactor. An economizer bypass to supply hot flue gas to the reactor inlet
is often provided to maintain the necessary reactor temperature at low loads.
The flue gas flow rate and temperature, the reactor pressure drop, the
inlet NOX and oxygen contents, and the outlet NOX and ammonia contents are
monitored to serve as a basis of control for the economizer bypass, ammonia
injection, and sootblower operations. Based on experience with commercial
operations in Japan, there are unresolved problems in process control because
there are no fully reliable methods of continuously monitoring low levels of
ammonia in flue gas that contain NOX, S02, and fly ash. A chemilumines-
cence method in which the ammonia is reduced or oxidized to nitrogen or NO and
determined by difference is most commonly used. An ultraviolet absorption
method has also been evaluated. All methods used so far, however, have
suffered from interference from other components and incomplete conversion of
ammonia (37)•
The NHo is stored as an anhydrous liquid. It is vaporized and diluted
with a gas—usually air—and injected into the flue gas upstream from the
reactor through an injection grid that consists of an array of pipes with
nozzles across the cross section of the duct. The dilution reduces the
possibility of explosions and increases the volume of the injected gas to
improve mixing with the flue gas. A mixing grid, downstream from the injec-
tion grid, consisting of a matrix of pipes, ensures complete mixing.
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Chemical Reactions— -
The catalyst promotes the direct reaction of NH3 with NOX to form
molecular nitrogen and water.
4NH3 + 6NO + 5N2 + 6H20
8NH3 + 6N02 -* 7N2 + 12H20
(1)
(2)
If oxygen is present, however, it also enters into the reaction.
4NH3 + UNO + 02 + 4N2 + 6H20
4NH3 + 2N02 + 02 •* 3N2 + 6H20
(3)
(4)
About 1$ oxygen in the flue gas is sufficient to favor the reactions shown in
reactions 3 and 4, which are also favored by higher temperatures. From a
practical point of view, since flue gas normally contains at least several
percent oxygen and since NO constitutes 90? or more of the NOX, reaction 3
is the most significant. However, there has been limited data from commercial
operations in Japan indicating the importance of reaction 1 occurring, in
addition to reaction 3, since 80$ NOX reduction has been obtained at one
commercial facility with an NHo:NOx mol ratio slightly less than 0.8
(37).
NHg also reacts directly with oxygen at a rate increasing with
temperature.
4NH3 + 302 -»• 2N2 + 6H20
4NH3 + 702 -> 4N02 + 6H20
(5)
(6)
The catalyst also promotes the oxidation of S02 to SO^ (based on vendor
information, the percent S02 oxidized to SO^ ranges from 0.5$ to 2.0$)
which, added to the few percent S02 normally oxidized in the boiler,
increases the acid dewpoint of the flue gas and promotes formation of ammonium
sulfate and bisulfate (38,39,40).
+ 303 + H20
NH3 + 303 + H20
(NHl|)2SOli
NHltHSOlj
(7)
(8)
These salts exist as solids at temperatures of about 350°F or higher,
depending on the concentrations of NH^ and SOg. The NHijHSOo can form
14
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in the reactor at temperatures up to about 600°F where it forms a coating
on the catalyst. To avoid this, vendors recommend a minimum operating tem-
perature somewhat above 600°F to be maintained by hot flue gas bypass
under low-load conditions (37). Formation of these salts in downstream
equipment as the flue gas is cooled to 350°F or below is essentially
unavoidable, though it can be reduced by minimizing the formation of SCb and
the amount of unreacted NHg — the NH3 "slip" or "breakthrough"~in the flue
gas. Ammonium sulfate salts typically form in the air heater as sticky
corrosive deposits that usually necessitate modification of the air heater to
reduce corrosion and plugging (41,
In addition to the certain effects of ammonium sulfates/bisulfates upon
air heaters, there are potential effects of unreacted ammonia and ammonia
salts upon downstream equipment such as ESPs, baghouses, FGD processes, and
waste disposal which are not well defined and require further study (43,W.
For example, ammonia may improve ESP collection performance but aggravates
plate cleaning and discharging of ash from hoppers. Ammonium salts may blind
the filter media in baghouses, requiring more frequent bag cleaning and bag
replacement. Ammonia slip may benefit FGD systems by increasing SC>2 removal
and reducing absorbent stoichiometry.
In addition to the effects above, there is concern for the effect of
ammonia and ammonium salts on utilization of fly ash. Fly ash from the
Shimonoseki unit in Japan, where ammonia slip has been maintained at very low
levels, however, has been used in cement with no quality problems (37) .
Catalyst —
The catalyst itself is actually a surface coating on — or component of —
rigid metal or ceramic boxwork structures that are usually manufactured in
elements of a standard size, usually a fraction of a meter in width and length
and a meter in depth (the direction of flow). These elements, which are
themselves called the catalyst, are assembled in metal frames called modules
that are in turn placed on supports in the reactor to provide the desired
surface area of catalyst. (Somewhat confusingly, the quantity of catalyst is
frequently reported in terms of "space velocity," which is the volume of flue
gas divided by the volume of catalyst. This relates directly to an area only
for a particular catalyst design.) In some cases, the modules may be formed
of individual pipe-like elements. The number of layers of modules is
determined by the surface area of catalyst needed. The reactor is designed
with removable sections, framework, and hoisting equipment to facilitate
replacement of the modules. Sootblowers are also installed above and below
each layer to clean the catalyst.
The catalyst is one of the most important features of SCR processes, as
well as the primary distinguishing characteristic of the processes offered by
different manufacturers. The initial catalyst cost is an important element of
capital investment and catalyst replacement costs are — or are believed to be —
by far the largest operating cost (45). The manufacturers have pursued active
15
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catalyst development programs that have produced unique physical configura-
tions and, presumably, compositions. These designs are closely guarded
proprietary information, which makes quantitative comparisons difficult,
however.
Application of SCR processes to coal-fired boilers places severe demands
on the catalyst because of the fly ash (which both erodes and coats the
catalyst and can plug the reactor), the higher levels of flue gas components
that can cause the catalyst to deteriorate, and the generally higher levels of
SC>2. SCR processes were developed for clean flue gas using beds of catalyst
balls. The rigid honeycomb catalyst was developed for dirty flue gas to
reduce erosion and plugging and to permit cleaning with sootblowers. The
catalyst modules are designed to provide a flue gas velocity that minimizes
the pressure drop and erosion but which is high enough to prevent the fly ash
from coating or plugging the catalyst. The dimensions of the passages in the
catalyst (the pitch) range from about 5 to 20 mm, depending on the fly ash
content of the flue gas and the design philosophies of the manufacturers.
The active components of the catalysts are usually based on vanadium and
titanium oxides (46) but the actual compositions are proprietary. The cata-
lyst can either be applied as a surface coating or may be incorporated into
the support material, based on the assumption that erosion exposes fresh
catalyst (47). In addition to erosion, the catalyst effectiveness deterio-
rates because of poisoning by alkali metals and some heavy metals, prolonged
overtemperatures, and blinding or chemical masking, which can be wholly or
partially reversible by sootblowing operations or washing. Inevitably, how-
ever, the catalyst must eventually be replaced. Vendors generally guarantee a
1-year catalyst life and lives of two years or more have been attained in some
coal-fired applications in Japan (37) (the economic evaluations showing the
large catalyst replacement cost are normally based on a 1-year life). It is
uncertain whether the entire catalyst charge deteriorates uniformly or whether
a partial replacement is satisfactory (48).
Some of the major objectives of the ongoing catalyst development efforts
are to increase the resistance of the catalyst to fly ash abrasion, to reduce
chemical deterioration caused by flue gas components such as alkali metals, to
(improve the specificity to) reduce the formation of undesirable side products
such as SO^, and to reduce the pressure drop and tendency of fly ash to
blind the surface or physically to plug the catalyst.
Another potential environmental effect of SCR applications is catalyst
disposal. At the time of this study, both catalyst disposal and reclamation
procedures were under review by the process vendors (38,39,40). Although most
vendors indicated willingness to participate in spent catalyst disposal
studies, no definite procedures have been established, primarily because none
of the commercial SCR units have required a catalyst change (37) .
Commercial Systems in Japan—
The commercial SCR systems operating (or soon to be operating) on coal-
fired boilers in Japan are listed in Table 1. The Shimonoseki and Shin-Ube
16
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systems treat flue gas with a full fly ash loading. The Tomato-Atsuma and
Takehara systems treat flue gas from which the fly ash is removed by hot-side
ESPs upstream from the SCR system. All of the other systems treat flue gas
from which the fly ash is removed downstream from the SCR system.
TABLE 1. SCR UNITS FOR COAL-FIRED UTILITY BOILERS IN JAPAN
Owner Plant site No.
EPDC Takehara 1
2
Chugoku Shimonoseki 1
Electric Shin-Ube 1
2
3
Mizushima 1
2
Hokkaido Tomato- 1
Electric Atsuma
Kyushu Omura 2
Electric Minato 1
Joban Nakoso 8
Joint 9
Tohoku Sendai 2
Electric
Tokyo Yokosukag 1
Electric 2
Source: Reference 37
a. New or retrofit.
b. Babcock Hitachi K.K.
c. Kawasaki Heavy Industries.
d. Mitsubishi Heavy Industries.
e. Subjecting one-fourth of the
Boiler
MW
250
700
175
75
75
156
125
156
3506
156
156
600
600
175
265
265
gas to
N/Ra
R
N
R
R
R
R
R
R
N
R
R
N
N
R
R
R
SCR.
f. Ishikawajima-Harima Heavy Industries.
g. Currently uses oil and will
use coal-oil
Constructor
BHKb, KHIC,
BHK
MHld
MHI
MHI
MHI
BHK
BHK
BHK
MHI
MHI
MHI
IHlf
BHK
MHI
MHI
mixture from 1 984 .
Completion
1980
1983
1980
1982
1982
1982
1983
1983
1980
1982
1983
1983
1983
1983
1984
1984
17
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The Shimonoseki system is designed for 50$ NOX reduction in a flue gas
containing about 55 ppm NOX. The system has operated without trouble and
has produced NOX reductions of 50$ and 55$ at NH3:NOX mol ratios of
0.51:1.0 and 0.56:1.0. The system was designed for an ammonia breakthrough of
10 ppm or less; during the initial operation, the breakthrough was 1 ppm or
less but later increased to 2 to 3 ppm without affecting the NOX reduction.
The catalyst has shown little change during the first two years of operation.
It was initially expected to have a life of three or more years.
The Takehara system consists of two units in parallel on a 250-MW boiler.
The system was designed for 80$ NOX reduction in flue gas containing 400 ppm
NOX with an ammonia breakthrough below 5 ppm. The system was started up in
April of 1981 for tests and produced the 80$ NOX reduction at an NH^zNOx
mol ratio of slightly less than 0.8:1.0. The system was placed in commercial
operation in August 1982.
The Tomato-Atsuma system was designed for 90$ NOX reduction but has
been operated to obtain 80$ reduction. With NH3:NOX mol ratios of 0.85
and 0.95, NOX reduction efficiencies of 81$ and 92$ were obtained, with
ammonia breakthroughs of less than 2 ppm. The system treats one-fourth of the
flue gas, which contains 200 ppm NOX. The gas is combined with the
remaining flue gas to produce an ammonia concentration of less than 1 ppm.
The SCR system was the first designed by Babcock Hitachi for a coal-fired
boiler and was designed with sufficient safety factors to ensure that it would
not interfere with the operation of the boiler. The catalyst effectiveness
had not changed after one year of operation.
The Shin-Ube system was started up in the spring of 1982 as part of a
combined NOx-SC^ control system. The system is operated to obtain a 65$
NOX reduction, treating flue gas containing 400 ppm NOX. It has a honey-
comb catalyst with a space velocity of 4,000 hr~1 and an NHo:NOx mol
ratio of 0.66. The ammonia breakthrough has been less than 1 ppm. The
catalyst has a pitch of 7 mm, which is more efficient than the 10-mm pitch
used at the Shimonoseki system.
ELECTROSTATIC PRECIPITATORS
ESPs consist of arrays of vertical collection plates several inches
apart, interspaced with wire-like electrodes in a housing with a hopper
bottom. The flue gas flows through the array parallel to the plates at
velocities of a few feet per second, normally at a pressure drop of 1 to 2
inches H20. A voltage sufficient to create a corona discharge is placed on
the electrodes, which, by a complex ionization process (16,49), produces a
flow of charged particles to the grounded collection plates. Particles in the
flue gas acquire a similar charge and migrate to the collection plates and
adhere to them. The accumulating layer of particles is periodically dislodged
by rapping the plates and falls into the collection hoppers at the bottom of
the housing. The size of ESPs is expressed in terms of plate area per unit of
flue gas volume—called the specific collection area (SCA)—in ft2/1,000
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aft3/min. For normal applications in the past, SCAs of 300 to 500 have been
typical of high-efficiency ESPs.
Since they were first used in the 1920s, ESPs have proven to be a highly
satisfactory means of meeting most of the particulate emission control
requirements of utilities (50). The removal efficiencies imposed by the
particulate emission and opacity regulations of the past decade and the
problems associated with some coals coming into increasing use have, however,
placed rigorous demands on ESP technology (51). Emission regulations such as
the 1979 NSPS require removal efficiencies well in excess of 99$; plume
opacity restrictions have increased the importance of submicrometer particle
collection, for which ESPs are less effective than for larger particles. At
the same time, increasing use of low-sulfur coal and western coal often
creates conditions that make the collection of fly ash in ESPs more difficult.
It is generally most desirable, operationally and economically, to locate
ESPs downstream from the boiler air heater where the flue gas is coolest and
contains no recoverable heat: the ESP can be smaller and does not have to be
designed for the rigors of high operating temperatures and large temperature
changes, no useful heat is lost, and the boiler design and ducting are unaf-
fected. In some cases, however, these "cold-side" ESPs are impractical
because of the ash electrical resistivities in this temperature range. In
these cases, a "hot-side" ESP, which treats the flue gas from the boiler
economizer before it passes through the air heater, may be more practical.
Although more expensive and not without difficulties, hot-side ESPs have been
used with increasing frequency to collect high-resistivity ash (52).
The effectiveness with which an ESP collects particles is determined by
the potential of the electrodes, which determines the current density and
field strength between the electrode corona and the plates and the potential
on the charged particles. There are, however, factors that limit the maximum
practical potential, among which the properties of the particles themselves
and the temperature and composition of the flue gas are pivotal. All of these
affect the electrical resistivity of the particles, which determines the rate
at which the charge on the particles dissipates. Resistivities of about 1 x
10? ohm-cm are regarded as most suitable for collection in an ESP (50).
Resistivities regarded as high may range upward to about 10^3 ohm-cm. If
the resistivity is too low—which is rare in utility applications—the
particles on the plate lose their charge and become reentrained. More common,
and encountered with increasing frequency, are situations in which the
resistivity is too high. In this case, the ash adheres so firmly to the
plates that it cannot be effectively dislodged. High resistivity also creates
a high potential across the layer of particles on the collection plates that
induces an electrical breakdown called back corona. The potential across the
layer exceeds the dielectric strength of the gases in the layer, causing them
to ionize and essentially destroy the capacity of the affected plate area to
collect particles (53). To avoid these problems, it is necessary to operate
at a lower voltage—which requires a larger SCA to attain the desired removal
efficiency—or to operate at conditions that produce a lower resistivity.
19
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The resistivity of the ash is a function of the mobility of the charge on
the particle. At low temperatures, it is a surface phenomenon in which the
charge is conducted by a surface film formed on the ash particles by condensed
or adsorbed gases. As the temperature increases, the effectiveness of this
mechanism decreases but conduction through the particle itself becomes
increasingly effective. As a result, ash resistivities usually increase
rapidly with temperature as surface resistivity increases, reaching a maximum
between 250°F to 350°F, then rapidly decrease as volume resistivity
decreases. Plotted with temperature as the abscissa, log resistivities
resemble an inverted U with a peak near 300°F.
Sulfur trioxide is effective in forming a conducting film on the fly ash
particles in the temperature range at which surface conductance is an effec-
tive charge transfer mechanism. Usually coals with moderate to high sulfur
contents—over about 2% (SO)--produce flue gas with sufficient S03 to allow
efficient collection of fly ash in a cold-side ESP. Alkali metals, particu-
larly sodium, are believed to be the primary charge carriers in volume conduc-
tance (54) and probably surface conductance (55). Other components of the ash
are also believed to affect conductance: calcium, for example, increases the
resistance and iron decreases it (56).
Eastern bituminous coals typically have a high-sulfur content, a low
calcium-to-iron ratio, and a moderate sodium content (57). They produce a
flue gas and fly ash that usually allow effective fly ash collection with an
ESP at temperatures at which either surface or volume resistivity is the
controlling factor. Western coals typically have a low-sulfur content, a high
calcium-to-iron ratio, and a sodium content that may be a small fraction of a
percent to several percent, depending on the coal (58). Generally, the fly
ash from western coals has a high surface resistivity because of the low 863
content of the flue gas. The volume resistivity may be high or low, depending
on the sodium content of the ash. In most cases, however, the volume resis-
tivity is suitable for collection in an ESP operating at 600°F to 800°F.
In the United States, the evolution of ESP technology was largely based
on the collection of ash from eastern high-sulfur bituminous coals which
produces ash and flue gas conditions particularly favorable for collection in
an ESP. In addition, removal requirements were seldom as stringent as many
now required. These conditions were readily met by cold-side ESPs situated
after the boiler air heater where the flue gas temperature is about 300°F.
They economically and reliably provided removal efficiencies in the high 90$
range. In a highly competitive market, design emphasis was placed on reduc-
tion of capital costs by minimizing the size and structural complexity of the
ESP, a practice that came to be called "American design" philosophy (50). In
contrast, ESPs constructed in other countries, often to collect ash less
easily collected in an ESP than ash from high-sulfur U.S. coals, followed a
"European design" philosophy that placed greater emphasis on efficiency,
reliability, and structural competence.
When low-sulfur coals came into wide use in the 1960s, the performance of
these cold-side American design ESPs sometimes proved disappointing because of
20
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the high resistivity of the ash, which reduced the collection efficiency and
required rapping so vigorous that the ESPs were physically damaged. To
improve the efficiency, hot-side ESPs, several hundred of which are now in use
by utilities (16), were developed. Hot-side ESPs treat flue gas from the
boiler economizer before it passes through the air heater where the higher
600°F to 800°F temperature provides a low volume resistivity independent
of the flue gas S03 content.
Unexpected problems have also occurred with hot-side ESPs, however. Some
have been mechanical problems caused by the higher operating temperatures and
larger temperature changes but high resistivities have also been encountered
at the higher flue gas temperatures (59). Usually these are associated with
low-sodium coals in which there are insufficient alkali metal ions to serve as
charge carriers. There have also been instances in which the performance of
the ESPs deteriorated with time. This is believed to be caused by a gradual
depletion of sodium in an ash layer on the collection plates that is not
dislodged when the plates are rapped. The permanent layer gradually becomes
depleted in sodium, causing an increase in the apparent resistivity of the ash
(60).
Very high removal efficiencies, the continuous nature of many emission
regulations, and the more severe operating conditions also place severe
demands on the design and operation of ESPs (61). The American design
philosophy was criticized (62) because it sometimes did not provide the neces-
sary reliability and continued high level of efficiency to meet these require-
ments. Gas flow characteristics also became more important since it became
necessary to reduce the amount of flue gas that bypasses the collection area
(sneakage) and ash that evades collection or becomes reentrained because of
velocity variations and turbulence (63).
Flue gas conditioners have frequently been used to imprave the perform-
ance of ESPs (50). Usually this has been done to increase the efficiency of
an existing ESP that did not meet the design performance or to increase the
efficiency to meet new emission regulations; conditioners have seldom been a
factor in design considerations (61). For cold-side ESPs, SOg is a common
conditioner, although ammonia and a number of similar substances have been
used. Numerous proprietary materials are also available, although many do not
affect the ash resistivity itself but alter the physical characteristics of
the ash to reduce disintegration of the ash layer during rapping or to make it
easier to dislodge (64). Conditioners can also be used with hot-side ESPs.
In this case, however, a sodium compound is injected into the boiler or flue
gas to increase the volume conductance of the ash (65)•
The problems encountered with ESPs required to meet strict emission
limits, particularly with low-sulfur coals, have created a pessimistic outlook
for the future use of ESPs in utility applications (51). The difficulties
have evoked a spate of research and development efforts in ESP technology, a
field formerly left largely to the manufacturers of ESPs. EPA, the Electric
Power Research Institute (EPRI), and others have sponsored symposiums intended
to disseminate information on ESP technology (66) and both, along with private
organizations, are actively conducting studies of ESP technology. These
21
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studies Involve both the improvement of existing ESP designs and the develop-
ment of advanced designs. Among the latter are pulse energization and 2-stage
ESPs. Pulse energization, which is commercially available technology (67),
consists of applying a high-frequency voltage pulse to the energizing voltage,
which increases the efficiency of the ESP without corresponding increases in
sparking and back corona. In 2-stage ESPs, the particle charging zone is
separate from the collection zone (68).
FABRIC FILTERS
The fabric filters used by utilities usually consist of bags about 1 foot
in diameter and 30 to 40 feet long suspended vertically by the closed end in
compartments of 100 to 300 bags. The open, bottom ends are attached to a tube
sheet, also called a thimble sheet, that divides the compartment into an upper
section containing the bags and a lower section with a hopper bottom. Flue
gas is admitted to the lower section and flows upward through the bags into
the upper section, from which it is ducted to the stack. A baghouse for a
large utility boiler typically consists of up to several dozen compartments to
provide an "air-to-cloth" ratio (aft3/min of flue gas per ft2 of filter
area) of about 2, with provisions for compartments that are out of service for
cleaning and maintenance (69). The material and fabric construction is a
subject of great importance because of its bearing on bag durability. Several
temperature-resistant materials and numerous fabric constructions are poten-
tially useful but the technology in this area is still evolving (70). In
commercial installations, woven glass fabrics with a Teflon or silicon
coating, are usually used.
To clean the bags, each compartment has provisions for circulating
reverse air: The flue gas is diverted to other compartments and clean air or
gas is circulated through the bags in the opposite direction of the flue gas
flow. The bags collapse, dislodging the accumulated cake, which falls into
the hopper in the bottom of the compartment. A bag shaker is sometimes used
to supplement the reverse airflow and in a few cases, shakers alone are used.
This type of baghouse is referred to as a "conventional" or "low-ratio"
(air-to-cloth) design. A few utilities have installed high-ratio designs (71)
in which the fly ash is collected on the outside of the bags. These designs
have air-to-cloth ratios of 6 or more and about the same pressure drop as low-
ratio designs. The bags, usually felted instead of woven, are suspended from
a tube sheet at the top of the baghouse compartment and are supported inter-
nally by a metal frame or cage. The bags are cleaned while in service by
directing a pulse of high-pressure air into the open top of the bags which
causes a bulge to travel down the length of the bag.
In comparison with ESPs, baghouses have higher pressure drops—design
pressure drops are usually about 6 inches H20 compared with about 2 to 3
inches H20 for an ESP—an important consideration since each 1-inch H20
increase in pressure drop is estimated to cost $2 million in operating costs
22
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°VeLth® life of a 1,000-MW plant (72). Baghouses are, however, relatively
unaffected by changes in flue gas volume and by ash and flue gas properties
such as those caused by load changes and coal variations that affect ESP
removal efficiencies, and they are somewhat better collectors of the sub-
micrometer particles that cause opacity problems and which are attracting
attention because of their physiological effects (73).
Fabric filters were first investigated for utility use in the 1960s in
conjunction with injection of dry alkalis into the flue gas to remove S02
(7*0 . A cautious interest in fabric filters for fly ash control by utilities
developed in the 1970s, with the advent of stricter limitations on particulate
emission and opacity, as scaled-up and redesigned ESPs to meet these limita-
tions became much more expensive and sometimes failed to meet the design
specifications (61). Recently, this interest has grown as generally favorable
experience with baghouses has accumulated (75).
The reluctance to adopt baghouses was not due to doubts of their effi-
ciency—fabric filters almost inevitably remove in excess of 99% of the
particulate matter in flue gas passed through them—but of their operability
and durability: the effect of wet particulates on the pressure drop when
operating below the water dewpoint, corrosion when operating below the acid
dewpoint, and particularly the effect of bag life on operating costs. Bag
life is a critical factor in the practicality of baghouses. A subbituminous
coal-fired, 500-MW power plant, for example, requires a baghouse containing in
excess of 10,000 bags for fly ash control (about 2 million aft3/min of flue
gas and an air-to-fabric ratio of 2). A short bag life would have enormous
effects on the operating costs of a baghouse.
The first baghouse installations at utility power plants were started up
in 1973 at the Nulca Station of the Colorado Ute Electric Cooperative, and at
the Sunbury Station of the Pennsylvania Power and Light Company (16). Neither
were particularly typical of utility power plants—the Nulca installation
consisted of three baghouses on three 12-MW stoker-fired boilers and the
Sunbury installation of four baghouses on four 38-MW boilers that burned a
blend of anthracite, bituminous coal, and petroleum coke—but the operation of
the baghouses was followed with considerable interest (16,76).
Both installations provided reliable removal efficiency well in excess of
99$ and an essentially clear stack (near 0$ opacity) over a range of boiler
operating conditions. Bag life at the Nulca Station was initially low but was
improved by mechanical improvements. By 1976, several other utilities were
operating or installing baghouses (77). By early 1983, 8M baghouses with a
total capacity of about 11,000 MW were in operation on utility boilers and an
additional 32 with a total capacity of 10,000 MW had been contracted,
including some high-ratio, pulse-jet designs (69).
A considerable amount of published information on baghouses in utility
use has accumulated. Both EPA and EPRI have published proceedings (78) of
symposiums that dealt with utility fabric filter technology. EPRI has
published an evaluation of a large baghouse in operation at the Kramer Station
23
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of the Nebraska Public Power District (79), economic studies (80), and evalua-
tion of design aspects (72). EPRI also conducted evaluations at a 10-MW test
facility at the Arapahoe Station of the Public Service Company of Colorado
(81).
SPRAY DRYER FGD
Spray dryer FGD—also called dry scrubbing—appeared in the late 1970s
and quickly gained acceptance among utilities for control of S02 emissions
from power units burning low-sulfur coal. From 1977f when the first commer-
cial utility system was contracted, through early 1983, 15 commercial utility
systems were contracted and 3 full-scale demonstration systems were operated
(82). During this period, 12 vendors developed and placed spray dryer FGD
systems on the market (83). The total capacity of the commercial systems is
about 6,200 MW, about 10% of the total operating and contracted FGD capacity
in the United States.
The application of spray dryer techniques to FGD is a readily appreciable
solution to many of the problems and economic penalties of wet scrubbing. In
basic concept, it is identical to standard and widely used spray dryer tech-
nology (84). An atomized slurry or solution of absorbent is dispersed in the
flue gas under conditions that result in evaporation of sufficient liquid to
form solid particles while the droplets are suspended in the gas. S02
reacts with the alkali in the absorbent to form calcium sulfur salts, contin-
uing to do so at a diminishing rate as long as the particles are in contact
with the flue gas and residual moisture remains in the particles. Some or all
of the particles, consisting of calcium salts and unreacted alkali, remain
entrained in the gas and are collected in a fabric filter baghouse or ESP as a
dry granular waste. The only liquid system involved is that needed to prepare
and meter the absorbent liquid to the absorber. The many problems associated
with the liquid systems in wet-scrubbing processes—corrosion, erosion,
plugging, and scale formation—are reduced or eliminated, as are the costs for
these systems. In addition, the flue gas is not cooled to the saturation
temperature and reheating costs are reduced or eliminated. Since particulate
collection is an intrinsic part of the process, fly ash collection can be
combined with collection of the FGD waste, using a single particulate collec-
tion system and producing a single dry waste that can be disposed of in a
landfill without further processing (85).
Balanced against these manifest advantages, however, are some limitations.
The contact time of the flue gas with the liquid phase is a period of a few
seconds and a reactive absorbent, often at high stoichiometries, is essential.
As a result, absorbent costs are high, particularly for high-sulfur coal
applications. This, perhaps more than intrinsic limitations on removal effi-
ciencies, has focused interest in spray dryer FGD on low-sulfur coal
applications.
The rapid ascension of spray dryer FGD to a prominent position in S02
emission control is due in part to the nature of the process—which is essen-
tially a combination of spray drying and particulate collection technologies,
24
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both of which are mature and widely used industrial technologies. Adoption of
these technologies to FGD, however, required the development of processes
quite dissimilar to industrial applications in some respects, particularly in
size and control requirements. Typically, but not exclusively, the vendors of
spray dryer FGD systems are manufacturers of particulate collection equipment
who developed the necessary spray dryer technology or formed accordances of
various natures with spray dryer manufacturers. The rapidity with which spray
dryer FGD evolved is illustrated by the fact that most vendors did not begin
development work until the late 1970s (the first pilot plants were operated at
power plant sites in 1977); in some cases, commercialization proceeded almost
simultaneously with development.
The development of spray dryer FGD was also aided by the lengthy efforts
to develop dry-injection FGD. A major impetus was the dry-injection pilot
plant at the Basin Electric Power Cooperative's Leland Olds Station, which was
used to develop an FGD system for the Coyote Station being built in
North Dakota by a consortium of power companies (86). The most practical, if
not the only practical, absorbent proved to be nahcolite, a natural sodium
bicarbonate mineral, which appeared likely to be unavailable in the necessary
quantities. Evaluations of other absorbents led, in 1977, to the use of a
spray dryer to improve the reactivity of the absorbent. The Rockwell Interna-
tional Corporation (RI), which had been evaluating a spray dryer as part of a
sulfur-producing recovery process, provided the spray dryer and the
Wheelabrator-Frye, Inc., baghouse, previously used for the dry-injection
tests, as the collection device. This led to a joint venture—since
dissolved— by RI and Wheelabrator-Frye to market spray dryer FGD systems and
to a contract for a commercial system for unit 1 at the Coyote Station.
Shortly thereafter, three other companies, all of whom are now spray dryer FGD
vendors, operated pilot plants at Basin Electric or Otter Tail Power Company
power plants—a joint venture of the Joy Manufacturing Company and Niro
Atomizer, Inc. (Joy/Niro); the Babcock & Wilcox Company (B&W); and the
Carborundum Company (now Carborundum Environmental Systems)—in competition
for commercial systems at Basin Electric's Antelope Valley Station unit 1 and
Laramie River Station unit 3. These tests resulted in contracts for three
systems with a total capacity of 1,500 MW.
For processes that have gained such widespread commercial acceptance,
there is relatively little comprehensive design information available, in part
a result of their rapid development, which has allowed little time for such
information to accumulate and, in part, a result of the lack of long-term
institutionally sponsored studies with published results. Most of the pilot-
scale studies have been conducted by the vendors who are dedicated to
particular design concepts or who regard some of their results as proprietary
information. Commercial or large demonstration systems have not yet provided
comprehensive data; only the startup phase of the Coyote Station soda-ash
system (87), the operation of demonstration systems at the Northern States
Power Company's Riverside Station (88), and the City of Colorado Springs'
Martin Drake Station (89) have been reported. EPA has sponsored pilot-plant
studies and published summaries (90) of spray dryer FGD applications. EPRI
25
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has published a status review (83) and initiated a 1-year pilot-plant study in
1982 (91). The Department of Energy (DOE) also conducted a pilot-plant study
(92).
Overall, however, comprehensive design and comparative performance data
on spray dryer FGD are scarce and the relative merits, if any, of particular
design philosophies adopted by vendors are difficult to assess. In most
cases, only summary descriptions of the various vendors' designs have been
published.
Although the main thrust of spray dryer FGD has been directed toward low-
sulfur coal applications, there has been interest in high-sulfur coal applica-
tions. There have been tests in which satisfactory removal rates were
attained with high-sulfur coals (88) and some vendors are willing to guarantee
high removal rates at coal sulfur levels in the range of 3% to 4$ (83). There
is, however, a practical limit at which the quantity of absorbent liquid
necessary to supply the absorbent required produces a saturated flue gas, a
limit that may be reached at a coal sulfur content of about H% (83).
The economics may also be a limiting factor because of the large quan-
tities of absorbent required in high-sulfur coal applications. In a TVA
economic study (15), for example, the absorbent costs for a lime spray dryer
FGD system for a power unit fired with 0.7% sulfur lignite were $1.7 million
per year, while the absorbent costs for a power unit with the same capacity
fired with 3-5% coal were $8.4 million per year—50% of the total operating
costs.
The spray dryer FGD process consists of the absorber (spray dryer); a
baghouse or ESP to collect the solids, which also serves to collect the fly
ash; and ancillary feed preparation and waste-handling systems. The absorbent
liquid is introduced into the absorber through either a rotary atomizer or
2-fluid nozzle atomizer as very fine droplets that evaporate to solid
particles in a few seconds at most (the design residence time in the spray
dryer is 6 to 10 seconds). S02 is absorbed by the droplets and reacts with
the absorbent to form the same sulfur salt wastes as are produced in wet
scrubbing. The nominally dry particles, which consist of unreacted absorbent
and sulfur salts, continue to react with SO;?, although at a much slower rate
while they are in contact with the flue gas. If a baghouse is used, this
contact is an important mechanism of S02 removal; from 5% to 20$ of the
total S02 removal is attributed to reactions that occur as the flue gas
passes through the collected absorbent on the bags (83). For ESPs where there
is less intimate contact between the waste and the flue gas, additional
removal is significantly less. Because of this and other reasons (some
vendors manufacture only baghouses), baghouses have been preferred over ESPs—
only two of the commercial utility systems have ESPs.
Most vendor designs follow typical spray dryer configurations in which
the gas flows downward through a cylindrical vessel with a conical bottom,
with the atomizer or atomizers mounted at the top, and leaves through a duct
in the bottom or side. The side configuration (with the opening centered in
26
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the vessel, facing down) permits collection of some of the particulate matter
in the bottom of the absorber. The cylindrical design is the most practical
when rotary atomizers are used and is also suited to 2-fluid nozzle atomizers.
The 2-fluid nozzles are equally suited to other configurations, however. In
contrast to the cylindrical design now favored by other vendors, the B&W
design, which uses 2-fluid nozzles, is a horizontal vessel with a rectangular
cross section.
Partial flue gas bypass may be used, either for reheat or as a safety
factor to ensure dry operation of the particulate collection equipment. In
some cases, "warm gas" from the air heater outlet is used; in other cases,
"hot gas" from the economizer outlet is used. Vendors appear to differ on the
value of flue gas bypass—about one-half of them provide it and the rest
provide it "if necessary" (83).
The individual absorbers of the commercial systems range up to 192 MW in
size, the largest being the horizontal rectangular chamber installed by
B&W on unit 3 of the Basin Electric Company's Laramie River Station. The
largest cylindrical absorber is 51 feet in diameter (158 MW) and the smallest
is 46 feet in diameter (110 MW). The use of a single rotary atomizer places
limits on the practical size of the absorbers because of the flow rates and
spray pattern attainable. This has led to special gas flow arrangements in
large single-atomizer designs and the unusual (for spray dryer technology) use
of multiple rotary atomizers. The 2-fluid nozzles, which have low capacities,
can be used in any number and arrangement and place no particular restrictions
on the size or shape of the absorber. This is discussed more fully below.
It is essential to the effective operation of a spray dryer
that the absorbent liquid be broken into very fine droplets—probably no
larger than a few hundred micrometers in size—and uniformly dispersed in the
flue gas. Either rotary or 2-fluid nozzle atomizers, both standard equipment
in conventional spray drying, are used. Each has arguable advantages and
disadvantages (83) and it is possible that either may be most suitable,
depending on the particular system (93)- Thus far, vendors have favored
rotary atomizers: seven use rotary atomizers and five use nozzles, though one
vendor whose initial design included nozzles has contracted for a commercial
system with rotary atomizers (94). Only two of the commercial systems and one
of the two full-scale demonstration systems have nozzles but these figures
also reflect the preponderance of commercial systems supplied by the Joy/Niro
consortium, whose design has a rotary atomizer.
Rotary atomizers consist of a rotor—called a wheel—that is mounted on a
vertical shaft driven by a motor-gearbox system. In FGD applications, typical
wheels are 8 to 16 inches in diameter and rotate at 10,000 to 20,000 rpm,
producing tip speeds of 35,000 to 50,000 ft/sec (93). Absorbent liquid is
introduced through an opening in the top of the wheel around the shaft and
flows through interior cavities to orifices in the periphery, where it is
sheared into droplets as it is expelled. In conventional spray dryers, one
27
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atomizer is mounted on the vertical axis at the top of a cylindrical vessel
and the gas flows downward around it through the spray. This arrangement
places severe demands on the rotary atomizers because of the large flue gas
volumes and absorbent flow rates of typical full-scale absorber trains. Very
large atomizers, with flow rates well over 100 gal/min in some cases, are
required and the flue gas flow has to be modified to achieve effective
dispersion of the droplets in the flue gas. The aerodynamic properties of the
droplets make them lose velocity very rapidly, forming a cloche-like spray
pattern that has at most a diameter of 20 to 30 feet, making it impossible to
span the width of full-sized absorbers with a single atomizer and conventional
downward gas flow. Some vendors who use rotary atomizers have resorted to
installing three or four in each absorber. Others use a single atomizer and
introduce a portion of the flue gas below the atomizer, directed upward, to
achieve satisfactory mixing. The RI design, for example, has three 300-hp
atomizers with wheels less than a foot in diameter and the flue gas is ducted
downward around each atomizer (87). The Joy/Niro design, typified by the
demonstration system at the Northern States Power Company's Riverside Station
(88), has a single 700-hp atomizer with a wheel over a foot in diameter and
the flue gas is directed both downward around the atomizer and upward toward
the spray. Both have operated successfully and the relative merits of the
designs, if any, are not resolved.
The 2-fluid nozzle atomizers have much smaller capacities and consume
more power than rotary atomizers, but they are arguably simpler mechanically
and more flexible in design and use. The absorbent liquid is combined with
air in a chamber in the nozzle and ejected from the nozzle at a high
velocity, forming a long narrow plume of turbulent gas and suspended droplets.
They commonly have a liquid capacity of about 5 gal/min and operate at gas
pressures up to about 100 Ib/in^ (93). Because of the small capacity, at
least several must be used in each absorber so the absorber configuration is
less important. The B&W system at the Laramie River Station has 15 nozzles in
each absorber (83) and the Flakt, Inc., demonstration system at the Pacific
Power and Light Company's Jim Bridger Station (83), which has a cylindrical
absorber, has 10 nozzles.
Except for the soda ash system at the Coyote Station (which is a direct
descendent of RI's sulfur-producing process, based on soda ash), lime has been
used exclusively as the absorbent for commercial utility systems. Lime is
widely available and with some exceptions in specific areas, it is the least
expensive material that is sufficiently reactive for spray dryer FGD. In
addition, it produces the now-familiar and relatively insoluble calcium salt
waste in dry form that is produced as a slurry in wet-limestone and lime FGD
processes. Other absorbents such as magnesium oxide have been evaluated in
pilot plants (93).
Unlike many materials that are dried in a spray dryer—in which the
drying mechanism tends to produce a porous expanded or hollow particle—the
dried particles of lime tend to be dense and have hard surfaces that inhibit
reaction of S02 with lime in the core (15). This places emphasis on the
fineness of the lime particles and has led to more extensive feed preparation
28
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techniques than are common in wet FGD processes. Ball mill slakers are used
in eight of the commercial utility systems, apparently because tests by some
vendors have convinced them of their value. Ordinary paste and detention
slakers are also used, however. In addition to producing a very fine particle
size, it is also necessary to remove grit and lumps that tend to plug the
atomizers.
The presence of fly ash in the absorbent slurry has been found to
increase the reactivity of the lime, presumably by providing a large surface
area upon which the lime particles can deposit and remain available to S02
(95). The effect occurs with acidic fly ash typical of eastern coals and is
independent of the effects of increased alkalinity from the fly ash (92). For
this reason, and to take advantage of unreacted lime and the alkalinity of the
fly ash itself, most vendors recycle a portion of the waste to the spray dryer
(83).
The absorbent slurry composed of fresh lime and reslurried waste is
normally maintained at a constant solids content and the addition rate is
varied to provide the desired S02 removal efficiency. Normally, L/G ratios
of 0.2 to 0.3 gal/kft3 are used. Additional water is added to the atomizer
to control the outlet flue gas temperature. The maximum slurry solids with
fly ash is apparently about 35$» somewhat lower for slurries composed wholly
of fresh lime, above which the slurry becomes too viscous and abrasive to
pump.
Stoichiometries are generally expressed in mols of absorbent per mol of
inlet SC>2 rather than mols of S02 removed, as is common in wet FGD
processes. Furthermore, fly ash alkalinity is regarded as an important factor
in subbituminous coal and lignite applications; S02 removals of 65$ have
been reported using alkaline fly ash alone (96). Stoichiometry alone is thus
not a reliable indication of S02 removal efficiency or absorbent utilization
(that is, the percentage that actually reacts with the S02). Reported
design Stoichiometries (83) for lime-based commercial systems range from 0.88
to 1.5 mol Ca(OH)2/mol S02 inlet, with little relationship to design
S02 removal. The 0.88 Stoichiometry corresponds to an S02 removal of 85$,
for example, while the 1.5 Stoichiometry corresponds to an S02 removal of
86$. In general, the Stoichiometries are higher for higher-sulfur coal
applications.
The most important operating condition is the temperature change in the
flue gas caused by evaporation of the absorbent water. Normally, flue gas
from the boiler air heater has a temperature of about 300°F and a water
saturation temperature of roughly 125°F. The spray dryer must operate
within this range to avoid producing moist particulates which can deposit in
the spray dryer and ducts (a "wet bottom" condition) or clog the baghouse.
The approach to saturation—which for a constant absorbent rate is determin&d
by the solids content of the absorbent—is important because S02 removal
efficiency increases rapidly as the temperature of the flue gas leaving the
spray dryer approaches its saturation temperature, allowing a longer effective
liquid phase to exist in the absorbent droplets.
29
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Commercial system design thus far allows for a 15°F to 40°F approach
to saturation, with about 20°F most common. A close approach to saturation
increases absorbent utilization while increasing control problems and the
possibility of upsets. It is most important for high-sulfur coals requiring
high S02 removal efficiencies—and for which absorbent costs are a critical
factor. A close approach in these cases may also be necessary to introduce
sufficient absorbent si'nce the solids content of the absorbent liquid is
limited by absorbent solubility or slurry viscosity.
WET-LIMESTONE FLUE GAS DESULFURIZATION
Since it was first used by U.S. utilities over 15 years ago, wet-
limestone scrubbing has become the standard method of utility FGD in the
United States. In 1981, 39 systems, H2% of all utility FGD systems in opera-
tion, were limestone systems and among those being constructed or in the
planning stage, 46? were limestone systems (97). After a long and sometimes
difficult evolution, limestone FGD has become a mature and reliable technology
(98). This evolution has produced a spectrum of processes differing apprecia-
bly in design and operating philosophies. All, however, share the restric-
tions placed on them by the use of this cheapest of available absorbents:
large liquid circulation rates of an abrasive slurry, restriction to a narrow
range of operating conditions to avoid scaling and plugging, and the produc-
tion of an intractable waste.
The process used in this study represents two current trends in limestone
FGD: the use of a simplified absorber design and the use of forced oxidation
to improve the waste-handling properties. The process is one of several
variants that were extensively evaluated during tests sponsored by EPA at the
Shawnee test facility operated at TVA's Shawnee Steam Plant (99)-
Most limestone FGD systems have absorbent liquids that contain between 5%
and 15$ solids that consist of unreacted limestone, calcium sulfite, calcium
sulfate, and sometimes fly ash. The relatively insoluble limestone (the
solubility constant is about 10~9f several orders of magnitude lower than
other FGD absorbents) makes the use of a stoichiometric excess of limestone
necessary. Normally, the stoichiometric ratios lie in the range of 1.1 to 1.6
mol CaCOg/mol S02 removed. The operating pHs usually range from 5 to 6
at the absorber inlet to 4.5 to 5.5 at the absorber outlet, depending in large
part on the stoichiometry. Because of the slow dissolution rate of the lime-
stone, limestone processes require a large hold tank with a hold time of at
least several minutes to allow time for a portion of the dissolution and
precipitation reactions to occur outside the absorber itself (100).
Regardless of the operating conditions, S02 gas-liquid mass transfer
rates are low compared with most FGD processes and intimate gas-liquid contact
is necessary. This requires either multistage absorbers, absorbers with
complex internals, or very large L/G ratios. All of these are widely used,
typified by venturi-spray tower combinations, mobile-bed absorbers, and spray
towers with high L/G ratios (98). In recent years, with the maturation of
30
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limestone FGD technology, there has been a trend toward simple absorbers such
as spray towers (101), motivated apparently by the lower capital costs and
maintenance requirements. There is relatively little difference in operating
costs among the different approaches because fan costs for high-pressure drop
designs tend to be offset by pumping costs for high L/G designs (U).
Chemistry
The chemistry of limestone FGD—which is surprisingly complex, with many
interrelated factors that differ in importance depending on the operating
conditions—has been discussed at length (102). The primary alkaline species
that react with dissolved 862 to form SOg'2 and HS03~ are C0o~2
and HCO^" from limestone dissolution and SO^'2 from calcium sulfite
dissolution. These, along with several minor species, are referred to as the
total dissolved alkalinity (103). The level of dissolved alkalinity can be
increased somewhat by the addition of cations that form more soluble salts
than calcium, such as magnesium (103), or by the use of a buffer, such as
adipic acid (104). The forms of all the sulfite and carbonate species are pH
dependent and the pH of the absorbent is vitally important because of its
effects on S02 removal efficiency and the precipitation of solids. The
relative importance of the many reactions involved is thus dependent on the
operating conditions—limestone stoichiometry, 862 absorption rate, L/G
ratio, hold times, and others.
Within limits, a high pH is desirable because of the higher SC>2 absorp-
tion rate. At pHs above about 6, however, the formation of carbonate scale
may cause operating problems (99)• Some decrease in pH, as the absorbent
liquid passes through the absorber, is also desirable because it causes the
absorbed 862 to exist as the soluble HSO^' rather than to precipitate as
calcium sulfite, which can form muddy accumulations that plug the absorber.
Too large a decrease, however, may cause an inert coating to form on the
limestone particles that prevents their dissolution. A low pH leaving the
absorber may also be desirable if forced oxidation is incorporated in the
process. A low pH may also affect the formation of sulfate scale: low pHs
favor the dissolution of calcium sulfite rather than limestone as the source
of dissolved alkalinity. This produces twice as many mols of calcium ions
per mol of 862 absorbed as limestone dissolution, which under some condi-
tions, can produce high levels of gypsum CaSOi}-2H20 supersaturation.
There are, however, other methods of dealing with sulfate scale.
The absorbent liquid leaving the absorber consists of a disequilibrium
mixture of dissolved sulfite and sulfate species, supersaturated in respect to
calcium sulfite and gypsum, and solid limestone, calcium sulfite, and gypsum.
The limestone continues to dissociate and the calcium salts precipitate as the
pH slowly rises. Addition of fresh limestone slurry accelerates the precipi-
tation reactions which, after several minutes or more, have progressed suf-
ficiently for the regenerated absorbent to be reused in the absorber.
Because of the intimate gas-liquid contact necessary for S02 absorp-
tion, oxygen absorption is also high in limestone FGD and the proportion of
31
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the S02 absorbed that is oxidized to gypsum is correspondingly high compared
with most FGD processes. For high-sulfur coals, oxidation rates vary widely,
with oxidation of about one-third of the total S02 absorbed being represen-
tative. For low-sulfur coal applications, oxidation rates in excess of 90$
are possible. These increase the problems caused by gypsum scaling that are
common to calcium-based systems but which have now largely been controlled.
The common gypsum scaling, which is a problem in many industrial water
systems as well as calcium-based FGD systems, is a result of the tendency of
gypsum to form supersaturated solutions from which rapid precipitation can
occur when a critical concentration is reached. Under some conditions, this
precipitation can form rock-like deposits on the surfaces of the equipment.
Because of the solubility relationships of calcium sulfite and gypsum, it is
impractical to operate limestone FGD systems below gypsum saturation; most, in
fact, operate up to about 1.3 times gypsum saturation, a level below which
experience has shown gypsum scaling to be minimized. Among the methods of
controlling the gypsum saturation level are the provision of abundant seed
crystals, providing sufficient reaction time outside the absorber for lime-
stone dissolution and gypsum precipitation, reducing the quantity of S02
absorbed per volume of absorbent liquid (the "make per pass"), and operating
in a pH and stoichiometry range that does not create large increases in the
calcium ion concentration in the absorber.
Forced Oxidation
The ease with which sulfites in solution are oxidized by dissolved oxygen
creates scaling problems but it also affords a means of reducing one of the
major problems in limestone FGD: handling and disposing of the intractable
high-sulfite waste. High-sulfite wastes cannot be dewatered sufficiently to
form a stable solid; they must either be impounded or treated with stabilizing
material. Chemically precipitated gypsum, in contrast, is a sand-like
material that can easily be dewatered to a stable solid that can be disposed
of in a landfill without further treatment (105). There is also the prospect,
at least technically feasible, of disposing of gypsum as a byproduct to
replace natural gypsum in industrial uses (106).
Forced oxidation has been widely adopted in Japan as a means of improving
waste properties and of producing a byproduct (107). The complex 2-stage
processes used there, however, did not prove attractive to U.S. utilities. In
the United States, institutional and industrial studies of forced oxidation in
conventional limestone processes were begun in the mid-1970s. The most fully
documented are the pilot-plant tests begun by EPA in 1975 and continued at the
Shawnee test facility from 1976 through 1979 (99). During the same period,
forced-oxidation versions of limestone FGD processes were developed by several
vendors of FGD systems (108). In 1983, there were about a dozen full-scale
utility systems in operation or under construction (108).
The forced-oxidation method consists of sparging air into the absorbent
liquid so that sufficient oxygen is absorbed to oxidize the sulfites in the
32
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liquid to sulfate, which reacts with the calcium already present to precipi-
tate gypsum. Normally, this is done in the absorber liquid loop, in one of
the absorber hold tanks, or in an additional tank in the loop. Forced oxida-
tion of a bleedstream is also used (109) but this requires the presence of an
additive such as magnesium or adipic acid to increase the concentration of
dissolved sulfites because the pH increases as oxidation progresses reduce
the oxidation rate below practical levels (99). Usually a simple perforated
piping system and a low-pressure air supply serves as the sparging system.
The tank is agitated to provide sufficient air-liquid content and keep the
solids in suspension (other methods using air ejectors and agitation by air
injection are also used less frequently). The air rate, expressed in atomic
equivalents of oxygen per mol of 50^ absorbed, can be as low as 1.5 lb
atoms 0/lb mol 862 but 2 to 5 is more common. The essential requirements
are a pH of about 5.5 or less to ensure that the sulfite is in solution as
HSOj' rather than in solid form as calcium sulfite and that there is
adequate air-liquid contact time.
Forced oxidation does not decrease the S02 absorption efficiency
because of the depletion of dissolved alkalinity provided by SO^2",
probably because the absence of sulfite species improves the gas-liquid mass
transfer rate (110). It has been known for some time (111) that forced oxida-
tion decreases the gypsum supersaturation level and the scaling potential,
rather than increasing it as might be supposed. The precipitation of gypsum
at moderate supersaturation levels is enhanced because of the abundant seed
crystals in the liquid. The high degree of agitation normally used may also
enhance nucleation of new crystals (112).
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34
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PREMISES
The premises used in this study were developed by TVA to evaluate the
economics of coal-fired power plant emission control processes. The design
premises quantify SOX, NOx, and particulate emissions from a typical
modern coal-fired power unit and establish representative design and operating
conditions required to determine emission control economics. The economic
premises define the procedures for determining the capital investment and
annual revenue requirements based on regulated utility economics. The
premises are based on projects with a 1981 to 1983 construction period and a
1984 startup. Capital investment is based on mid-1982 costs and annual
revenue requirements are based on mid-1984 costs.
DESIGN PREMISES
Coal
The coals used are an eastern bituminous coal containing 3.5$ sulfur and
a western subbituminous coal containing 0.7% sulfur, both on a dry basis. The
properties of these coals are based on composites of samples representing
major coal production areas (113,114,115). The eastern bituminous coal has a
heating value of 11,700 Btu/lb and an ash content of 15.1$ as fired. The
heating value and ash content of the western subbituminous coal are 8,200
Btu/lb and 6.3$ as fired. The compositions of the coals are shown in Table 2.
Ash compositions are considered to be typical of the coals used. The
compositions are not qualified in terms of physical and chemical behavior,
with the exception of calcium content. Both ashes are assumed identical in
handling properties until wetted. The eastern coal ash is assumed to have no
cemetitious properties affecting handling and disposal site emplacement. The
western coal ash is assumed to have self -hardening characteristics that affect
handling and emplacement within a few hours after being wetted (16).
Power Plant
The power plant site is in the north-central region (Illinois, Indiana,
Ohio, Michigan, and Wisconsin) . The location represents an area in which
coal-fired power plants burning coals of diverse type and source are situated
(12,116). The design is based on standard design practices (19,20) and
current trends in utility boiler construction (18). The base case power unit
is a new," single 500-MW, balanced-draft, pulverized-coal-fired, dry-bottom
boiler. Heat rates are based on power unit size as shown in Table 3. To
provide equitable comparisons, the power units are not derated for energy
35
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LO
OS
TABLE 2. COAL COMPOSITIONS
CoaJL
Heat
Sulfur, Ash, Moisture , content, .
t I « Btu/lb C.S H.S O.I N.I Cl.%
Ultimate analysis
(As-Fired Basis)
Eastern bituminous 3-36 15.14 4.0
Western subbituminous 0.48 6.30 29.3
11,700 66.7 3.8 5.6 1.3 0.1
8,200 49.0 3-5 10.7 0.7 0.02
(Moisture-Free Basis)
Eastern bituminous
Western subbituminous
3.50
0.68
15.7
8.9
69.5 4.0 5.8
69.3 5.0 15.1
1.4 0.1
1.0 0.02
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consumption by the emission control systems evaluated. Instead, the energy
requirements are charged as independently purchased commodities. Cost
estimates are based on a single power unit independent of other units at the
site. Power unit size case variations consist of similar 200- and 1,000-MW
units. The emission control systems are assumed to be installed during
construction of the power plant and are assumed to have a 30-year life and to
operate at full load for 5,500 hours a year- This operating schedule is
equivalent to a total lifetime operation of 165,000 hours.
TABLE 3- POWER UNIT OPERATING TIME AND HEAT RATE
Power unit size. MW:
Remaining life, yr
Full load, hr/yr
Heat rate, Btu/kWh
Bituminous coal
Subbituminous coal
200
30
5,500
9,700
10,700
•500
30
5,500
9,500
10,500
1.000
30
5,500
9,200
10,200
Flue Gas Compositions
Flue gas compositions are based on combustion of pulverized coal, assum-
ing a total air rate equivalent to 139$ of the stoichiometric requirement (the
air required for combustion of carbon, hydrogen, and sulfur). This includes
20% excess air to the boiler and 19$ additional air leakage to the flue gas in
the air heater. It is assumed that 80$ of the ash present in each coal is
emitted as fly ash and the remaining 20$ as bottom ash, with no adjustments
for pulverizer rejects or slagging and fouling losses. For the bituminous
coal, 92$ of the sulfur is emitted as SC^, while 85$ of the sulfur is
emitted as SOX for the western subbituminous coal. The remaining sulfur is
removed in the bottom ash and fly ash. No loss of sulfur in the pulverizers
is assumed. Three percent of the sulfur emitted as SOx is SOg and the
remainder is SC^. The base case flue gas compositions and flow rates based
on combustion of each of the coals assumed for the study are shown in Tables 4
and 5.
Environmental Standards
The NSPS established by EPA in 1979 governing emissions from new coal-
fired utility plants specify a maximum emission for particulate matter, S02,
and NOX emissions based on heat input. These emission standards are shown
in Table 6.
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TABLE 4. FLUE GAS COMPOSITION
FOR 3.5? SULFUR EASTERN BITUMINOUS COAL
Component
Vol.
Lb-mol/hr
Lb/hr
N2
02
C02
S02
so3
NO
N02
HC1
H20
Fly ash
Total
74.85
3.27
14.22
0.24
0.01
0.04
0.00
0.01
7.36
100.00
118,700
5,178
22,550
380
12
59
3
12
11.660
158,600
3,326,000
165,700
992,300
24,320
940
1,766
142
418
210.200
4,722,000
50.050
4,772,000
Sft3/mln (60QF) = 1,003•000
Aft3/min (705°F) = 2,247,000
Flv ash loading
Wet
Dry
Gr/sft3
5.82
6.28
Basis: 500-MW boiler, flue gas conditions
after economizer at 705<>F.
In this study, the particulate matter and S02 removal efficiencies for
all cases are designed to meet these NSPS. The S02 and particulate matter
removal efficiencies are tabulated in Tables 7 and 8. The boilers being
constructed now are capable of meeting the current NSPS for NOX emissions
without flue gas treatment. The SCR processes are capable of achieving 80$ to
90$ NOX reduction efficiencies. Therefore, in this study, the NOX emis-
sion level from the boiler for most cases is assumed to be equal to the exist-
ing NSPS limitations and the NOX reduction efficiency with SCR is an addi-
tional 80$. This produces a stack NOX emission of 0.12 Ib/MBtu for the
38
-------
bituminous coal and 0.10 Ib/MBtu for the subbituminous coal. A case variation
of 90$ NOX reduction efficiency is examined to illustrate the effects of
varying NOx reduction efficiency on the economics of the systems evaluated.
TABLE 5. FLUE GAS COMPOSITION
FOR 0.7$ SULFUR WESTERN SUBBITUMINOUS COAL
Component Vol. 1
Lb-mol/hr
Lb/hr
N2
02
C02
S02
S03
NO
N02
HC1
H20
Fly ash
Total
70.22
3.07
13-59
0.04
0.00
.03
.00
0.00
13.05
0,
0,
100.00
134,900
5,894
26,120
79
2
54
3
4
25.070
192,100
3,780,000
188,600
1,150,000
5,063
196
1,627
131
132
451.700
5,577,000
32.640
5,610,000
Sft3/min (600F) = 1,216,000
Aft3/min (780QF) = 2,900,000
Fly ash loading
Wet
Dry
Gr/sft3
3.13
3.60
Basis: 500-MW boiler, flue gas conditions
after economizer at 780°F.
Waste disposal sites are assumed to be governed by nonhazardous solid
waste regulations. Landfill disposal is used for the ash, FGD waste, and
NOX catalyst.
39
-------
TABLE 6. 1979 REVISED NSPS EMISSION STANDARDS
S02
70$ S02 removal (minimum) to a maximum S02
emission of 0.6 Ib S02/MBtu
0.6 Ib S02/MBtu maximum emission up to 90$ S02
removal
90$ S02 removal (minimum) to a maximum S02
emission of 1.2 Ib S02/MBtu
1.2 Ib S02/MBtu maximum emission
NOX
Bituminous coal - 0.6 equivalent Ib N02/MBtu
Subbituminous coal - 0.5 equivalent Ib N02/MBtu
Lignite - 0.6 equivalent Ib N02/MBtu
Particulate
0.03 MBtu
TABLE 7 . S02 EMISSION CONTROL REQUIREMENTS
Equivalent
Equivalent Overall S02 removal Controlled
S02 content equivalent S02 required outlet
Case of coal, removal in FGD emission,
Coal No. Ib S02/MBtu efficiency. $ system. $a Ib S02/MBtu
Eastern bit. ,
3.5$ S 1 5.74 89.6
Western subbit.,
0.7$ S 2,3 1.17 70.0
88.7 0.60
64.7 0.35
a. Based on FGD as the only S02 control device and the previously defined
sulfur retention in the ash.
40
-------
TABLE 8. PARTICULATE MATTER EMISSION CONTROL REQUIREMENTS
Fly asha Fly asha Fly ash
content of removal controlled
flue gas entering required in outlet
Case ESP or baghouse, ESP or baghouse emission,
Coal No. Ib/MBtu process, % Ib/MBtu
Eastern bit.,
3.5$ S 1 10.54 99.7 0.03
Western subbit.,
0.7% S 2 21.433 99.9 0.03
Western subbit.,
0.7$ S 3 6.87 99.6 0.03
a. Particulate matter in case 2 flue gas is a combination of fly ash and
lime spray dryer solids.
NOx Control Process
The SCR NOX control process is a generic design based on information
from several vendors. Two reactor trains are used for the 200-MW and 500-MW
boilers and four trains are used for the 1,000-MW boiler. Catalyst replace-
ment is assumed to take place during scheduled boiler outages and no spare
reactor trains are provided. Spare ammonia vaporization equipment is pro-
vided. The catalyst is assumed to have a 1-year life. The spent catalyst is
assumed to be a nonhazardous waste that can be disposed of in the facility
landfill.
The costs for an economizer bypass are also included in the costs. This
is used at low boiler loads (less than 60$ of capacity) to maintain a suffi-
ciently high flue gas temperature in the reactors. Air heater modifications
to minimize the effects of ammonia salts on the air heaters are also included.
These consist of an increase in the size of the air heaters, use of a thicker
gauge corrosion-resistant alloy for the elements, and provisions for addi-
tional sootblowers and water washing. The additional costs—compared with
the costs of conventional air heaters—are included in the NOX process
costs. A bypass duct around the SCR reactor is included for maximum system
flexibility.
Separate booster fans are not used. Instead, the boiler ID fans are
increased in size to compensate for the pressure drop in the NOX control
system and the incremental costs of this increase are included in the NOX
41
-------
process costs. (It is possible in some cases that boiler modifications would
be necessary to reduce the possibility of implosions caused by the higher
overall pressure drops. These are not included because they are highly
variable and site specific.)
Several other possible effects of the NOX process that have economic
implications are not included because they are undefined. These include the
effects of ammonia and ammonia salts on downstream equipment other than the
air heater and the possible need of additional waste water processing and
waste disposal requirements because of the presence of soluble nitrogen
compounds.
FGD Process
The limestone and spray dryer FGD processes are generic designs. The
limestone process is based on data developed at the Shawnee test facility
(99i117), industry information, and vendor information. The spray dryer
process is based on vendor information and published data. Both represent
current trends in industry practice.
The FGD systems consist of multiple absorber trains supplied by a common
plenum into which the boiler ID fans (or cold-side ESPs) discharge. Spare
trains are provided in all cases to permit the use of an emergency bypass, as
specified in the 1979 NSPS (32). The number of trains for each of the cases
and power unit sizes evaluated is shown in Table 9. The emergency bypass
consists of two ducts, each sized for 25% of the flue gas scrubbed, that
connect the ends of the inlet plenum with the stack plenum. If partial scrub-
bing is used and some flue gas is normally bypassed, the size of these ducts
is increased proportionally and they are also used for the normal bypass.
TABLE 9. NUMBER OF FGD TRAINS
Pnit
1
size. MW
200
500
,000
Case
Ooeratine
2
4
8
1
Spare
1
1
2
Case 2
Operatinc
2
3
6
Spare
1
1
2
Case
Ooeratinc
2
3
6
^
Spare
1
1
2
For the limestone FGD processes, each train is equipped with an ID
booster fan to compensate for the pressure drop in the FGD system. For the
-------
spray dryer FGD process, ID booster fans downstream from the baghouses serve
to compensate for the pressure drop in both the spray dryer system and the
baghouse.
For low-sulfur coal applications, the absorbers are designed for the
highest practical removal efficiency (90% for limestone FGD and 73$ for spray
dryer FGD) and a portion of the flue gas is bypassed to reduce reheating
requirements. This is more economical than processing all of the flue gas at
lower S02 removal efficiencies. For the 0.7$ sulfur coal using limestone
FGD, 28$ of the flue gas is bypassed; for the same coal using spray dryer FGD,
12$ is bypassed.
The limestone FGD process has spray tower absorbers constructed of
rubber-lined carbon steel. They rre equipped with a presaturator section at
the inlet in which the flue gas is sprayed with absorbent liquid to cool it to
127°F. Each absorber has a horizontal mist eliminator with fiberglass
chevron vanes that reduces the entrained moisture to 0.1$ by weight of the
flue gas.
For the limestone FGD processes, indirect steam reheat of the scrubbed
gas is provided as necessary to provide a flue gas temperature of 175°F in
the stack. The size of the reheater is based on a scrubbed gas temperature of
125°F and a bypassed gas temperature of 300°F- The heat of compression in
the ID booster fans is also included in the determination of reheater size.
The reheater tubes are Inconel 625 at flue gas temperatures below 150°F and
Cor-Ten steel above 150°F. It is designed for a flue gas velocity of 25
ft/sec.
The spray dryer process has cylindrical absorbers with conical bottoms
that are equipped with single rotary atomizers. They are constructed of
unlined carbon steel. The spray dryers are enclosed in a prefabricated metal
building to reduce seasonal temperature variations.
Square or rectangular insulated ductwork is used. At temperatures below
150°F, it is constructed of stainless steel. At temperatures above 150°F,
it is constructed of Cor-Ten steel. All ducts are designed for a flue gas
velocity of 50 ft/sec.
Particulate Control Process
The particulate control process consists of the ESPs or baghouses, all
hoppers associated with ash collection on the boiler (bottom ash, economizer
ash, and air heater ash) and emission control equipment (NOX process
reactors and the ESPs or baghouses), a pneumatic conveying system and storage
system for the dry particulates, a hydraulic conveying system, and dewatering
system for the bottom ash. All designs are based on standard industry
practice and commercially available equipment.
The ESPs and baghouses are standard designs based on current industry
practice and vendor information. Two ESPs in parallel are used for the 200-MW
-------
and 500-MW boiler sizes and four trains in parallel are used for the 1,000-MW
boiler. All dry particulate hoppers are a double-vee bottom design with 55-
degree slopes and are insulated and electrically heated. Hoppers are provided
on all boiler and emission control equipment upstream of the ESPs or
baghouses. The bottom ash system is a standard utility design with a double-
vee, water-filled hopper; ejector and centrifugal pumps; and a bin-type
dewatering system. Vacuum fly ash conveying systems are used for systems with
ESPs. Vacuum-pressure systems are used with systems with baghouses because of
the larger volumes and larger number of hoppers involved.
All hoppers are designed for a 12-hour capacity to allow intermittent
removal of solids. Storage facilities (bottom ash bins and fly ash silos) are
designed for a 3-day capacity to permit waste transportation operations on a
5-day week.
Solids Disposal
The solids generated by the emission control processes (FGD solids, fly
ash, bottom ash, and spent catalyst) are disposed of in a common landfill one
mile from the facility. Sufficient land is provided for disposal for the 30-
year life of the facility. The disposal site is assumed to be an area of low
relief with sufficient soil for landfill preparation and reclamation.
Square area-type landfills with a 20-foot-high perimeter and a 6-degree
cap are used, as shown in Figure 2. After topsoil removal, the landfill area
is lined with 12 inches of clay (assumed available onsite). A French drain
system (perforated pipe surrounded by gravel) and 24 inches of bottom ash are
added on top of the clay. The bottom ash layer and French drain system allow
the seepage to be collected separately from runoff and treated for pH
adjustment.
Land requirements include the landfill, catchment basin, equipment
storage area, topsoil storage area, and a 50-foot perimeter of undisturbed
land. Costs for access roads, a 6-foot security fence around the total
landfill area, security lighting, topsoil stripping and replacement, and
revegetation are included. One upstream and three downstream groundwater
monitoring wells are also included.
All mobile equipment involved in loading and transporting the solid
wastes from the in-process storage area, as well as working the landfill, is
included in the landfill equipment. Mobile equipment and landfill
requirements are based on the quantity, moisture content, and bulk density of
the solid wastes. The dry bulk densities and water contents for each solid
waste are shown in Table 10.
Raw Materials
Raw materials capacity is normally 30 days unless process or industry
practice differs. Standard raw material characteristics are shown in
Table 11.
44
-------
-p-
Ul
Topsoil-i Equipment-, Office-, /-Drain
Storage \ Storage \ / / Sump
*
\
|
i-
••
— i »
\ f" r~\ ~~^
u-'M
Access Road 4-« x| |
"V
\ ' '/
Landfill
Area
/ \
i
r^
"** — i
/
>
3
Catchment
aaln
50' Perimeter
Dirt
6' F"H Dit°cmh
1
t
, Ditch-' L6i pence
-1 — 24'
•-401 6°\
I 0' Bench
I' 6" Topsoll
24' Ditch
6" Clay
\-
Clay
2' Bottom Ash
With Drains
-20'
Figure 2. Landfill plan and construction details.
-------
TABLE 10. SOLID WASTE PERCENT MOISTURE AND DENSITY
Drv bulk density. Ib/ft3
Type of
solid waste
Bottom ash
Fly ash
FGD
Fly ash/FGD
NOx catalyst
% moisture
Case 1
10
10
15
-
0
Case 2
10
-
-
0
0
Case ?
10
0
15
-
0
Truck transport
Case 1
45
55
55
_
48
Case 2
51
-
-
62
48
Case 3
51
62
55
_
48
Case 1
75
85
85
—
48
Landfill
Case 2
85
-
_
95
48
Case 3
85
95
85
—
48
-------
TABLE 11. RAW MATERIAL CHARACTERISTICS
Size as received
Ground size
Analysis
Bulk
density. Ib/ft
Limestone 0 x 1-1/2 in.
90% to pass 95$
325 mesh 0.15$ MgO
4.85$ inerts
5 lb H20/100 Ib
dry limestone
95
Lime
(pebble)
Fineness of grind
index factor =5.7
Hardness of work
index factor = 10
3/4 x 1-1/4 in.
Sulfuric acid
Caustic soda
Ammonia
95$ CaOa
0.15$ MgO
4.85$ inerts
5 lb H20/100 lb
dry lime
98$ H2S04
50$ NaOH
199.5$ NH3
82.2$ N
55
a. Limestone and lime analysis on a dry basis. FfeO is based on pounds of
dry limestone or lime.
ECONOMIC PREMISES
Schedule and Cost Factors
A 3-year construction period, from early 1981 to late 1983, is used.
Mid-1982 costs are used for capital investment and mid-1984 costs are used for
annual revenue requirements. These costs represent the midpoint of
construction expenditures in 1982 and the midpoint of the first year of
operation in 1984. Costs are projected from Chemical Engineering magazine
cost indexes, as shown in Table 12, using standard estimating techniques
(118,119). Frequently used costs are shown in Table 13. In some instances,
cost-scaling factors based on gas and product rates are used to calculate
values at conditions other than the base case.
47
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TABLE 13. COST FACTORS
Project Timing
Start
End
Midpoint
First-year operation
January 1981
December 1983
Mid-1982
1984
1Q.8U Utility Costs
Electricity
Steam
Diesel fueia
Filtered river water
$0.037/kWh
$2.50/klb, $3-30/MBtu
$1.60/gal
$O.U/kgal
1Q84 Labor Costs
Process operating labor
Waste disposal labor
Analyses labor
$15.00/man-hr
$21.00/man-hr
$21.00/man-hr
Raw Material Costs
Limestone
Lime
Catalyst
Ammonia
Sodium hydroxide
Sulfuric acid
$8.50/ton (95% CaCO^, dry basis)
$75/ton (pebble, 95$ CaO, dry basis)
$23,558/ton ($5687ft3)
$155/ton
$300/ton
$65/ton
1382 Land Cost $5,000/acre
These cost factors are based on a north-central plant location.
a. Cost is based on wholesale price of barge-load quantities. Road
taxes are not included.
48
-------
Year:
Plant
Materialb
Laborc
TABLE
1978
218.8
240.6
185.9
12. COST INDEXES AND PROJECTIONS
1979
238.7
264.4
194.9
19803
257.8
288.2
210.5
19813
277.1
311.2
227.3
1Q82a
297.9
336.1
245.5
1Q8^a
320.2
363.0
265.2
1984a
342.6
388.4
283.7
a. TVA projections.
b. Same as "equipment, machinery, supports" Chemical Engineering
index.
c. Same as "construction labor" Chemical Engineering index.
Capital Cost Estimates
The capital investment estimates are divided into three major sections:
direct investment, indirect investment, and other capital investment. The sum
of direct and indirect investments is the fixed Investment.
Direct Investment—
Direct investment consists of the installed costs of all process
equipment, including provisions for services, utilities, and miscellaneous;
and waste disposal investment. Installation costs are estimated by major
processing area and include charges for all piping, foundations, excavation,
structural steel, electrical equipment, Instruments, ductwork (all flue gas
ductwork is included in the gas-handling area), paint, buildings, taxes,
freight, and a premium for 7% overtime construction labor.
Service facilities such as maintenance shops, stores, communications,
security, offices, and road and railroad facilities are estimated or allocated
on the basis of process requirements. Included in the utilities costs are
necessary electrical substations and facilities for process water, fire and
service water, instrument air, chilled water, inert gas, and compressed air.
Services, utilities, and miscellaneous are 6$ of the total process capital.
All equipment and direct construction costs associated with the landfill
are Included in waste disposal costs. All mobile equipment involved in
loading and transporting the waste from the in-process storage area, as well
as working the landfill, is included in landfill equipment. The solid wastes
from all control processes are disposed of in a common landfill. The landfill
costs are prorated to each of the individual processes based on the volume of
solid waste from each process. The sum of total process capital, services,
utilities, and the waste disposal cost is the total direct investment.
Indirect Investment—
Indirect capital costs cover fees for engineering design and supervision,
architect and engineering contractor, construction expense, contractor fees,
and contingency. Listed in Tables 14 and 15 are the percentages used to
calculate these costs.
49
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TABLE 14. INDIRECT CAPITAL COST FACTORS
Indirect investment
Processa
Engineering design and
supervision
Architectural and
engineering
Construction expense
Contractor fees
1.000 MW
6
1
14
JL
25
500 MW
7
2
16
-a
30
200 MW
8
3
18
_£.
35
Landfillb
1,000 MW
2
1
7
JL
14
500 MW 200 MW
2 2
1 1
8 9
-5. JL
16 18
a. Percentage of process direct investments, excluding landfill.
b. Percentage of landfill equipment and construction.
TABLE 15. CONTINGENCY AND ALLOWANCE FOR STARTUP AND
MODIFICATION COST FACTORS
Contingency, % of
direct and indirect
Process tvoea
Allowance for startup
and modification, % of
NOx-SCR
SOx-limestone slurry
SOx-lime spray dryer
Particulate-ESP/baghouse
Waste disposalb
Landfill
20
10
20
20
20
10
8
10
10
0
a. Percentage of only process costs.
b. Percentage of only landfill costs.
50
-------
Other Capital Investment—
The allowance for startup and modifications is applied as a percentage of
the total fixed investment. Since the startup and modification costs for the
waste disposal area are assumed to be negligible, this allowance is calculated
using only the process fixed investment. The percentages used to calculate
these costs are listed in Tables 14 and 15.
The cost of borrowed funds (interest) during construction is 15.6$ of the
fixed investment (both process and waste disposal). This factor is based on
an assumed 3-year construction schedule and is calculated with a 10$ weighted
cost of capital, with 25$ of the construction expenditures in the first year,
50$ in the second year, and 25$ in the third year of the project. Expendi-
tures in a given year are assumed uniform over that year. Startup costs are
assumed to occur late in the project schedule so that there are no charges for
the use of money to pay startup costs. No royalty charges are included for
the limestone or lime FGD processes and for particulate control by either ESP
or baghouse. Royalty charges are included for the SCR processes and are based
on vendor information.
Land—
All land associated with the process and waste disposal area is charged
to the process. The cost of land is 5,000 $/acre.
Working Capital—
Working capital is the total amount of money invested in raw materials,
supplies, finished products, accounts receivable, and money on deposit for
payment of operating expenses. Working capital is the equivalent cost of 1
month's raw material cost, 1.5 months' conversion cost, 1.5 months' plant and
administrative overhead costs (all of the above are shown on the annual
revenue requirements sheet), and 3$ of the total direct capital investment.
One month is defined as 1/12 of annual costs. For the SCR processes, catalyst
replacement cost is excluded in calculating the working capital.
Annual Revenue Requirements
Annual revenue requirements account for recovery of various direct and
indirect operating and maintenance costs and capital charges. Annual revenue
requirements normally vary from year to year as operating and maintenance
costs change and capital charges decline. Thus, no single year is necessarily
representative of the lifetime costs, and single-year undistorted comparisons
cannot be made among processes with different ratios of operating costs to
capital charges. In addition, it is necessary to take into account the effect
of time on the value of money (i.e., for inflation, the future earning power
of money spent, and other factors).
Frequently these factors are accounted for by levelizing (120). Leveli-
zation converts all the varying annual revenue requirements to a constant
annual value, such that the sum of the present worths of the levelized annual
revenue requirements equals the sum of the present worths of the actual annual
revenue requirements. The levelized value is calculated by multiplying the
revenue requirements for each year by the appropriate present worth factor and
51
-------
summing the present worth values. Then the single present worth value is
converted to equal annual values by multiplying the result by the capital
recovery factor.
In this study, the operating and maintenance costs are levelized by
multiplying the first-year operating and maintenance cost by a levelizing
factor. The levelized capital charges are determined by levelizing the
percentage of capital investment applied yearly as capital charges. The
levelizing factor includes a discount factor reflecting the time value of
money and an inflation factor reflecting the effects of inflation during the
operating life of the system. The annual discount rate used is 10? and the
annual inflation rate used is 6$.
Operating and Maintenance Costs—
Operating and maintenance costs consist of direct costs for raw materials
and conversion and indirect costs for overheads. Conversion costs consist of
operating labor and supervision, utilities, maintenance, and analysis costs.
Raw materials include consumables required for their chemical or physical
properties, other than fuel for the production of heat. In this evaluation,
the raw materials consist of limestone, lime, ammonia, catalyst, sulfuric
acid, and sodium hydroxide. Raw material costs are determined from vendor
quotations or published sources. All costs are delivered costs.
Operating labor and supervision consists of all labor requirements for
operation of the equipment and waste disposal facility. The allocation of
operating labor and supervision man-hours for the N0x-S02~particulate
control system depends on the process complexity, number of process areas,
labor intensity of the process, and operating experience. Waste disposal
operating labor and supervision depends on the number of equipment operators
required to operate the landfill.
Services such as steam, electricity, process water, and diesel fuel are
charged under the utilities heading. Costs for steam and electricity are
based on the assumption that the required energy is purchased from another
source. This simplifying assumption eliminates the need to derate the utility
plant. Process water requirements are defined as any water used by the
process being evaluated and are determined from the material balance. Steam
requirements are for stack gas reheat and sootblowing. Electrical power
requirements are determined from the installed horsepower of operating
electrical equipment (excluding the horsepower of spared equipment). Each
motor in operation is assumed to be operating at rated capacity although this
results in higher power consumptions than would actually occur. Electrical
requirements are obtained from the equipment list where the motor horsepower
is identified, plus an additional amount for functions such as lighting.
Diesel fuel is calculated based on the equipment required for the landfill.
Process maintenance costs are calculated as a percentage of direct
process investment which varies with the process complexity, process equip-
ment, materials handled, and the power unit size. Waste disposal maintenance
52
-------
costs are 3% of the waste disposal direct investment. The maintenance
percentages used for specific processes are shown below. Analysis costs are
based on process complexity and are listed as a single entry.
Maintenance, % of direct
investment
Process tvoe (orocess onlv)
NOx-SCR
S02-limestone slurry
S02-lime spray dryer
Particulate-ESP
Parti culate-baghouse
Landfill (disposal only)
1.000 MW
3
7
5
4
5
3
500 MW
4
8
6
5
6
3
200 MW
5
9
7
6
7
3
Plant and administrative overheads include plant services, general
engineering (excluding maintenance), and the expenses connected with manage-
ment activities. Plant and administrative overheads are 60$ of the conversion
costs less utilities.
Capital Charges—
Capital charges are those costs incurred by construction of the facility
that must be recovered during its life. They consist of returns on equity and
debt (discount rate), depreciation, income taxes, and other costs such as
insurance and local taxes. In keeping with common practice for investor-owned
utilities, the weighted cost of capital is used as the discount rate (121).
Depreciation is stated as a sinking fund factor to simplify calculations. An
allowance for interim replacement is included. Credits are also included for
tax preference allowances. The capital charges are shown below.
% of total
capital investment
Weighted cost of capital
Depreciation (sinking fund factor)
Annual interim replacement
Levelized accelerated tax depreciation
Levelized Investment tax credit
Levelized income tax
Insurance and property taxes
Levelized annual capital charge
10.00
0.61
0.56
-1.36
-1.93
1.31
2.50
53
-------
The capital charges are applied as a percentage of the total capital
investment.
The capital structure is assumed to be 35% common stock, 15$ preferred
stock, and 50$ long-term debt. The cost of capital is assumed to be 11.4$ for
common stock, 10.0$ for preferred stock, and 9.0$ for long-term debt. The
weighted cost of capital is 10.0$. The discount rate is equal to the weighted
cost of capital. Other economic factors used in financial calculations are a
10$ investment tax credit rate, 50$ State plus Federal income taxes, 2.5$
property tax and insurance, and an annual inflation rate of 6$. Salvage value
is assumed to be less than 10$ and equal to removal cost.
The sinking fund factor method of depreciation is used since it is
equivalent to straight-line depreciation levelized for the economic life of
the facility using the weighted cost of capital. The use of the sinking fund
factor does not suggest that regulated utilities commonly use sinking fund
depreciation. An annual interim replacement (retirement dispersion) allowance
(122) is also included as an adjustment to the depreciation account to ensure
that the initial investment will be recovered within the actual rather than
the forecasted life of the facility. Tax preference allowances are incentives
designed to encourage investment as a stimulus to the overall economy. The
basic accounting method used is the flow-through method which passes the tax
advantages to revenue requirements as soon as they occur -
Levelized Operating and Maintenance Costs—
Assuming a constant inflation rate, the levelized operating and mainte-
nance costs are determined by multiplying the first-year operating and mainte-
nance costs by an appropriate levelizing factor, Lf. The levelizing factor
is calculated as follows:
Lf = CRFe (K + K2 + K3 + + KN)
= CRFe [K(1 - KN)]/(1 - K)
where: CRFe = capital recovery factor for the economic life
K = (1 + i)/(1 + r); present worth of an inflationary value
i = inflation rate
r = discount rate
N = book life in years
An inflation rate of 6$ (i = 0.06) and a discount rate of 10$ (r = 0.10) are
used for new units. The first-year operating and maintenance costs are
multiplied by the levelizing factor to obtain the levelized operating and
maintenance costs.
ACCURACY OF ESTIMATES
The accuracy of the capital estimates used in this evaluation is -15$,
+30$. It represents the potential variation in costs for an actual installa-
tion in comparison to the estimated costs, expressed as a percent of the
estimated cost. The accuracy assigned to a cost estimate is empirical and not
related to variabilities in a statistical sense. Rather, it depends on both
54
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the quantity and the quality of the technical data available. Accuracy ranges
also reflect the numerous uncertainties surrounding estimates made using
simplifying assumptions. However, when comparing the costs for processes
evaluated using the same methodology, many of the same simplifying assumptions
are made for each of the processes. Therefore, the comparability is greater
than the overall accuracy of the estimates. When directly comparing estimates
of the same grade, the uncertainty ranges associated with the compared costs
are estimated to be less than ±10$.
55
-------
56
-------
SYSTEMS ESTIMATED
The base case systems for the three cases are described in this section.
Each of the three processes for NC^, S02, and particulate control in each
case is defined by a flow diagram, a material balance, and a major equipment
list (the costs shown in the equipment list are the installed costs exclusive
of ancillary equipment and facilities such as foundations, structures, piping,
electrical equipment, and control systems). The three processes are treated
separately and are further divided into processing areas to facilitate cost
comparisons.
NOx Control
Ammonia storage and injection
Reactor
Flue gas handling
Air heater modification
Haste disposal
S02 Control
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Reheat
Oxidation
Lime particulate recycle
Solids separation
Waste disposal
Particulate Control
Case 1
Case 2
Case
Area 1
Area 2
Area 3
Area 4
Area 5
Area 1
Area 2
Area 3
Area 4
Area 5
Area 1
Area 2
Area 3
Area 4
Area 5
Area 6
Area 7
Area 8
Area 9
Area 10
Area 11
None
Area 12
Area 13
Area 6
Area 7
Area 8
Area 9
None
None
Area 10
None
Area 11
Area 6
Area 7
Area 8
Area 9
None
None
None
Area 10
Area 11
Particulate removal and storage
Particulate transfer
Flue gas handling
Waste disposal
Area 14
Area 15
Area 16
Area 17
Area 12
Area 13
Area 14
Area 15
Area 12
Area 13
Area U
Area 15
All of the cases are based on 500-MW power units and include, in addition
to the three emission control processes, the costs for bottom ash collection,
dewatering, and disposal. In most cases in which identical or similar func-
tions such as flue gas handling and landfill are shared by two or three
processes, the costs are prorated to each process.
57
-------
CASE 1
Case 1 is based on 3.5$ eastern bituminous coal. It consists of an SCR
NOX control process, a limestone FGD process with forced oxidation, and
cold-side ESPs. The flow diagram is shown in Figure 3» the material balance
is shown in Table 16, and the equipment list is shown in Table 17. Each of
the processing areas is described below.
NOX Control
Processing areas 1 through 5 describe the NOX control process.
Area 1 - Ammonia Storage and Injection—
A 30-day supply of liquid ammonia is stored in 250-psig storage tanks. A
compressor is provided to unload the ammonia from truck or rail transporters
(a spare is also provided). The tanks are equipped with water sprays to
prevent overpressurization in hot weather and a water spray absorber system
for purging and emergency discharge.
Electric heaters at the storage tanks heat the ammonia which discharges
into an accumulator tank. The accumulator supplies two ammonia metering
systems, one for each reactor train. The ammonia is metered at an NHgiNOx
mol ratio of 0.81 into an ammonia-air mixer where it is mixed with preheated
250°F air at a ratio of 1 part ammonia to 29 parts air. This dilutes the
ammonia to a concentration outside the flammability range (15$ to 27$) and
improves the flow and mixing characteristics. The ammonia-air mixture is
conveyed to the injection grids in insulated ducts.
The injection grid consists of a Cor-Ten pipe array in the reactor inlet
duct. A Cor-Ten mixing grid downstream from the injection grid ensures
uniform mixing of the ammonia-air mixture with the flue gas.
Area 2 - Reactor—
Two reactor trains are used. Each reactor consists of a carbon steel
vessel 46 feet by 37 feet in size and 43 feet high, supported 40 feet above
the level of the power plant floor- The reactors are equipped with ash hopper
bottoms (costed in area 15) and are insulated with 6 inches of mineral wool.
The flue gas enters at the top of the reactor and leaves at the bottom through
a side duct above the ash hopper. The reactors are equipped with access doors
and internal supports and structures for catalyst handling and support.
The catalyst is a honeycomb type supplied in blocks 150-mm square and
1 meter in length (the direction of flow). The blocks are mounted in metal
baskets to form modules and placed in the reactor to form vertically separated
beds. The catalyst volume is 24,400 ft3, which provides a space velocity of
2,350 hr~1. The catalyst modules are loaded into and removed from the
58
-------
1
Figure 3. Case 1 flow diagram.
-------
TABLE 16. CASE 1 MATERIAL BALANCE
Description
1
2
1
4
5
6
7
R
9
10_
Total stream, Ib/hr
SftJ/min (60°F)
Temperature, °F
Pressure, psig
1
Coal to boiler
406,000
2
Combustion
air to air
heater
5,071,700
1,120,700
80
3
Combustion air
to boiler
4,378,400
967,500
4
Gas to
economizer
4,771,900
1,003,100
5
Gas to
ammonia
injection
grid
4,771,900
1,003,100
705
1
2
3
4
5
6
7
8
9
10
Description
Total stream. Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure, psie
6
Gas with
ammonia to SCR
reactor
4,814,400
1,012,600
701
7
Gas to
air heater
4,814,400
1,012,600
705
8
Gas to
ESP
5,507,700
1,165,800
300
9
Gas to
spray
tower
5,457,900
1,165,800
300
10
Gas from
spray
tower
5,687,200
1,249,200
125
Stream No.
Description
1
1
J
4
b
b
7
8
9
10
Total stream, Ib/hr
SftJ/min (60°F)
Temperature, °F
Pressure, psig
11
Gas to
stack
5,687,200
1,249,200
175
12
Steam to
dilution air
heater
2,200
298
50
13
Dilution air
to mixer
14
Ammonia to
mixer
41,645 I 855
J
9,200 ' 300
250
15
Ammonia-air
mixture to
injection grid
42,500
9,500
Stream No.
J
2
3
k
5
6
7
8
9
10
Description
Total stream. Ib/hr
Sft3/min (60°F)
Temperature. °F
Pressure, psie
6
Fly ash to
storage silo
49,800
300
17
Steam to
reheater
99,500
470
18
Bottom ash
from boiler
74,900
19
Bottom ash
sluice water to
settling tank
92,700
— '—20 ' ""
Dewatered
bottom ash
to disposal
13,900
!
(Continued)
60
-------
TABLE 16. (Continued)
Stream No.
Description
I
2
3
4
5
6
7
8
9
10
Total stream. Ib/hr
SftJ/min (60°F)
Temperature. °F
Pressure, psia
21
Settling tank
overflow to
surge tank
64.400
11 I 23 t 24
^
Settling tank
solids return
to devatering
bin
28.300
Reagent to
surge tank
Makeup
water
100 ' 1.300
25
Water to
bottom ash
sluice
62,400
1
2
3
it
5
6
7
8
9
10
Stream No.
Description
Total stream. Ib/hr
Sft3/min (60°Fl
Pressure, psig
26
Surge tank
underflow to
dewatering bins
3,400
27
Mositurizer
water
5.500
28
Fly ash to
landfill
55.300
29
Recycle
slurry to
presaturator
2.946.200
30
Makeup water
to spray
tower
288.300
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure, psiK
31
Recycle
slurry
to spray
tower
77,935,300
32
Air to
oxidation
tank
116,400
25,700
80
33
Clear
liquid to
oxidation
tank
801,100
34
Clear
liquid
return
833,300
t
35
Thickener
overflow
return
732,700
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, °F
Pressure, psig
36
Thickener
evaporation
27,400
37
Slurry to
thickener
950,300
38 | 39
Clear liquid
to wet ball
mills
32,200
Thickener
bottoms
to filter
196,560
40
Limestone
to wet
ball mills
54,400
t
(Continued)
61
-------
TABLE 16. (Continued)
S^rfam No.
Description
1
3
4
5
fi
7
8
q
in
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, UF
Pressure, psig
41
Limestone
slurry to
recirculation
tank
86,600
42
Filtrate
return
100,600
Filter cake
to landfill
89,600
...
1
1
2
3
4
5
6
7
8
9
1ft
Stream No.
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, °F
Pressure, psig
Stream No .
i
2
j
4
b
b
/
8
^
10
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature, UF
Pressure, psig
1
I
!
J
2
3
'»
5
6
7
8
9
JO
Description
Sft^/min (60°F)
Temperature, °F
Pressure, psig
62
-------
TABLE 17. CASE 1 EQUIPMENT LIST
Material Labor
Item - Description ___ cost, 1982$ cost, 1982$
Area 1— Ammonia Storage and Injection
1. Compressor, NH^ unloading (2); 14.6 ft3/min 8,600 2,100
capable of 250 psig suction max., 5-hp motor,
cast iron body, insulated (1 operating, 1 spare)
2. Tank. NH^ storage (5): Horizontal, 9-ft 169,500 3,900
diameter x 66 ft long, 30,000 gal, 250 psig,
carbon steel
3. Vaporizer, NH^ (55): Electric resistance 32,000 900
heater, carbon steel shell, 15-kW rated,
11 per ammonia storage tank
4. Tank, ammopi? accumulator (1): 293 ft3, 5,200 5,200
5.5-ft diameter x 10.5 ft long, carbon
steel, insulated (3 in.), +2.75-ft
hemispherical end, 15 psig design pressure,
180°F design temperature
5. Anaemia absorber (1): 4 ft high x 1.1-ft 400 1,900
diameter, 1 .5-ft support, with vent, water
supply, 1/4-in. Cor-Ten
6- Blower, air (3): 4,800 aft3/min, 20 in. H20, 13,100 1,400
25 hp, carbon steel, insulated (2 operating,
1 spare)
7. Heater, dilution air (2): Fin tube steam 27,500 800
heater, 540-ft2 surface area, aluminum
tubes, galvanized cabinet
8. Mixer, ammonia and dilution air (2): 32-in. 12,400 7,800
diameter x 10 ft long, carbon steel
9. Injection grid. NH^ and air (2): 25 ft wide, 77,300 79,300
19 ft high, Cor-Ten pipe and supports
10. Mixing, grid; NH^t air, and flue gas (2): 9,500 24,600
26 ft wide, 15 ft high, Cor-Ten pipe
Total, Area 1 355,500 127,900
(Continued)
63
-------
TABLE 17. (Continued)
Item - Description
Material Labor
cost. 1Q82& post.
Area 2—Reactor
1. Reactor (2): 46 ft wide x 37 ft
long x 43 ft high, 6-in. mineral wool
insulation; carbon steel housing,
internals, and supports; elevated
40 ft
2. Sootblower. steam (20): 46 ft, retractable,
40-lb/min steam at 86 psig, 1 hp
3. Reactor crane and hoist (2): Electric 2-
speed hoist, 2-ton capacity, 80-ft lift,
grade to access door, 3 hp
4. Reactor hoist (4): Electric single-speed
hoist, 2-ton capacity, access door to
inside reactor, 3 hp
Total, Area 2
2,191,200 2,327,700
520,000
21,200
28,200
33,100
600
1,700
2,760,600 2,363,100
Area 3—Flue Gas Handling Modifications
1. Fan, flue gas (2): Induced draft, 862,243
aft3/min, AP = 22 in. H20, carbon steel,
4,000 hp, fluid drive, double width,
double inlet
73,100
300
Total, Area 3
73,100
300
Area 4—Air Heater Modification^
1. Air heater (2): Vertical inverted, size 31,
Ljungstrom type,
Hot elements: DN type, 22 gauge, low alloy
corrosion resistant, 16
in. deep, 84,900-ft2 area
575,000
10,300
(Continued)
64
-------
TABLE 17. (Continued)
Material Labor
Item - Description cost, 1982$ cost, 1982$
Cold elements: NF type, 3.5-mm spacing,
22 gauge, low alloy corrosion
resistant, 42 in. deep,
274,500-ft2 area
2. Sootblower. steam (2): Retractable, 127-lb/min 15,200 900
steam at 200 psig
3. Pump, wash water booster (3): Centrifugal, 3t550
2,020 gpm, 210-ft head, 200 hp, carbon steel,
(2 operating, 1 spare)
Total, Area 4 625,700 14,200
Area 5—Waste Disposal0
1. Landfill site development and construction 12,900 1,200
(1): 161-acre landfill site, 2,256-ft square
landfill, 10,144,000 yd3 volume, 30-yr life,
139 ft high at center, 9,171-ft perimeter
ditch to 141,000-ydS catchment basin
2. Wheel loader (2): 7.0-yd3 bucket, diesel 1,900
engine
3. Dozer (2): Track type with straight blade, 700
137-hp diesel engine
4. Compactor (2): Vibratory sheepsfoot 1,000
compactor, self-propelled
5. Wheel loader (1): 3-5-yd3 bucket, diesel 300
engine
6. Water truck (1): Tandem-axle, 4-rear-wheel- 100
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
(Continued)
65
-------
TABLE 17- (Continued)
Material Labor
Item - Description cost, 1992$ cost.
7. Service truck (1): Wrecker rig with 500-gal 100
cargo tank for diesel fuel and cargo space
for lubricants and other field service
items, including tools
8. Onsite trailer for sanitary facilities and 100
break room (1): 12-ft-wide x 30-ft-long mobile
home restructured into 2 offices, 1 break room,
1 lavatory; propane gas stove and heater;
self-contained portable toilet, potable water
supply, and 120-volt electric supply
9. Onsite water supply and discharge treatment 100 100
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
10. Truck (4); Tandem-axle, 4-rear-wheel-drive 500
dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (3 operating, 1 spare), 0.2$ of total
truck costs in this area
Total, Area 5 17,700 1,300
a. Costs shown are additional costs of boiler I.D. fan due to NOX reactor
pressure loss.
b. Costs shown are for modifications and additional equipment made necessary
by NOx removal.
c. Except as noted, 0.3$ of total waste disposal costs is charged to
removal.
(Continued)
66
-------
TABLE 17. (Continued)
Material Labor
Item - Description oostf 1982$ cost, 1982$
Area 6—Materials Handling
1. Car shaker and crane (1): Top mounting 71f900 13,000
with crane, 20-hp shaker, 7-1/2-hp hoist
2. Car puller (1): 25-hp puller, 5-hp return 63»000 19f600
3. Hopper, limestone unloading (1): 16-ft 15,500 5,900
diameter x 10-ft straight side, 2,650 ft3,
carbon steel, 50-degree cone bottom,
includes 6-in. square grating
4. Feeder, limestone unloading (1): Vibrating 5,500 500
pan, 30 in. wide x 60 in. long, 3.5 hp, 250
ton/hr, carbon steel
5. Conveyor, limestone unloading (1); Belt 11,400 1,400
36 in. wide x 20 ft long, 5 hp, 250 ton/hr,
165 ft/min
6. Conveyor, limestone unloading (incline) (1); 85,300 4,800
Belt, 36 in. wide x 310 ft long, 50 hp,
15-degree incline, 250 ton/hr, 165 ft/min
7. Dust collector, limestone unloading pit (1): t1,200 5,200
Bag filter, polypropylene bag, 2,200 aft3/min,
7-1/2 hp, reverse jet cleaning, includes
5 dust hoods
8. Pumpf limestone sump Pit (1): Duplex, 60 gpm, 2,400 800
70-ft head, 5 hp, carbon steel, neoprene lined
9. Conveyorf storage (1): Belt, 36 in. wide x 73>100 3f900
200 ft long, 5 hp, 250 ton/hr, 165 ft/min
10. Tripper, storage conveyor (1): 1 hp, 30 ft/min 27,200 9|100
11. Mobile, equipment (1): Scraper tractor, 3«0-yd3 141,900 0
bucket, 170-hp diesel engine
12. Hopper, reclaim (2): 7-ft square x 4-1/4 ft 2,400 1,600
deep x 2-ft-wide bottom, 75 ft3, carbon steel,
60-degree cone bottom
(Continued)
67
-------
TABLE 17- (Continued)
Item - Description
Material Labor
post. 1Q.82& cost, I9flp.fr
13. Feederf reclaim (2): Vibrating pan, 3.5 hp,
100 ton/hr
14. Dust collector, limestone reclaim pit (1): Bag
filter, polypropylene bag, 2,200 aftS/min,
7-1/2 hp, reverse jet cleaning, 4 hoods
15. Pump, reclaim sump pit (1): Duplex, 60 gpm,
70-ft head, 5 hp, carbon steel, neoprene lined
16. Conveyor, limestone reclaim (1): Belt, 30 in.
wide x 200 ft long, 5 hp, 100 ton/hr, 105
ft/min
17. Conveyor, limestone reclaim (incline) (1):
Belt, 30 in. wide x 193 ft long, HO hp,
15-degree incline, 50-ft lift, 100 ton/hr,
105 ft/min
18. Elevator, live limestone feed (1): Continuous
bucket, 14 in. x 8 in. x 11-3/4 in., 75 hp,
90-ft lift, 100 ton/hr
19. Conveyor, live limestone feed (1): Belt,
30 in. wide x 60 ft long, 7-1/2 hp, 100
ton/hr, 105 ft/min
20. Tripper, live limestone feed conveyor (1):
1 hp, 30 ft/min
21. Bin, crusher feed (3): 13-ft diameter x 21-
ft straight side height, 3,100 ft3, covered,
50-degree cone, carbon steel
Total, Area 6
10,900
7,800
2,400
40,900
60,300
57,800
20,500
1,100
2,600
800
2,900
3,700
6,700
1,400
27,200 9,100
43,300 24,100
781,900
118,200
Area 7—Feed Preparation
1. Feeder, crusher (3): Weigh belt, 14 ft
long, 2 hp
(Continued)
49,600
2,300
68
-------
TABLE 17. (Continued)
Item - Description
Material Labor
cost. 1982& cost. 1982$
2. Crusher (3): Gyratory, 75 hp
3. Ball
4.
5.
, wet (3): Wet, open system,
9-ft diameter x 19 ft long, 741 hp,
13-0 ton/hr (2 operating, 1 spare)
Dust collector , ball mill (3): Bag filter,
polypropylene bag, 2,200 aft3/minf 7.5 hp,
reverse jet cleaning
Tank, mills product (3): 10-ft diameter x
10 ft high, 5,500 gal, open top, four 10-in.
baffles, agitator supports, carbon steel,
glass-filled polyester lining
6. Agitator t mills product tank (3): 40-in.
diameter, 10 hp, neoprene coated
7. Pvro.Pi
product tank (3): Centrifugal
.
55 gpm, 60- ft head, 2 hp, carbon steel,
neoprene lined (2 operating, 1 spare)
8. Tank, slurry feed (1): 21 -ft diameter x
21 ft high, 57,800 gal, open top, four
20-in. baffles, agitator supports, carbon
steel, glass-filled polyester lining
9. Agitator, slurry feed (1): 82-in. diameter,
50 hp, neoprene coated
10. Pump, slurry feed (8): Centrifugal, 27 gpm,
60-ft head, 1 hp, carbon steel, neoprene
lined (4 operating, 4 spares)
297,100 6,500
1,721,900 122,000
23,300
13,700
22,900
8,500
19,900
43,000
21,600
7,800
11,000
5,500
2,700
16,400
3,500
7,300
Total, Area 7
(Continued)
2,221,500
185,000
69
-------
TABLE 17. (Continued)
Item - Description
Material Labor
cost. 1Q82& cost.
Area 8—Flue Gas Handling
1.
Fansf flue gas (5): Induced draft, 380,800
aft3/min, AP = 7.8 in. HgO, 669 hp, fluid
drive, double width, double inlet, Inconel
625
3,420,100
59,600
Total, Area 8
3,^20,100
59,600
Area 9—S02 Absorption
1. S02 absorber (5): Spray tower, 40 ft
high x 34 ft wide x 17 ft deep, 1/4-in.
carbon steel, neoprene lining, 316
stainless steel grids, FRP chevron
vane entrainment separator, slurry header
and nozzles
2. Tank, recirculation (5): 38-ft diameter x
38 ft high, 326,000 gal, open top, four
38-in.-wide baffles, agitator supports,
carbon steel, glass-filled polyester lining
3. Agitator, recirculation tank (5): 158-in.
diameter, 67 hp, neoprene coated
4. Pump, oresaturator (10): Centrifugal,
1,401 gpm, 100-ft head, 62 hp, carbon
steel, neoprene lined (4 operating, 6
spares)
5. Pump, recirculation (15): Centrifugal,
18,525 gpm, 100-ft head, 819 hp, carbon
steel, neoprene lined (8 operating,
7 spares)
6' Pump, makeup water (2): Centrifugal,
3,501 gpm, 200-ft head, 295 hp, carbon
steel (1 operating, 1 spare)
5,560,300
360,500
1,697,900
33,400
452,500
291,200
445,400 182,700
103,500 32,400
150,200
3,800
(Continued)
70
-------
TABLE 17. (Continued)
Item - Description
Material Labor
cost. 1982& oost. 1982$
7. Sootblowera (40): Air-fixed
112,000
104,000
Total, Area 9
8,313,000 1,216,800
Area 10—Reheat
1. Reheater (5): Steam, tube type, 2,750
ft2, one-half of tubes made of Inconel
625 and one-half made of Cor-Ten
2. Sootblower (20); Air-retractable
2,656,900
183,000
168,800
78,200
Total, Area 10
2,839,900
247,000
Area 11—Oxidation
1. Tank, oxidation (5): 30.2-ft diameter x
38.1 ft high, 203,800 gal, open top,
four 30-in.-wide baffles, agitator
supports, carbon steel, glass-filled
polyester lining, includes air sparger
2. Agitator, oxidation tank (5): 110-in.
diameter, 59 hp, neoprene coated
3. Pump, oxidation bleed (8): Centrifugal,
452 gpm, 60-ft head, 12 hp, carbon steel,
neoprene lined (4 operating, 4 spares)
4. Blowerf oxidation air (6): 3,300 sft3/min,
323 hp (4 operating, 2 spares)
5. Oxidation sparger (5): 19.1-ft-diameter ring
274,600
319,500
37,700
208,600
93,800
222,000
131,000
15,800
4,700
41,600
Total, Area 11
(Continued)
934,200
415,100
71
-------
TABLE 17. (Continued)
Material Labor
Item - Description cost, 1992$—cost.
Area 12—Solids Separation
1. Tank, thickener feed (1): 19.1-ft 28,700 23,700
'diameter x 38.1 ft high, 81,400 gal,
open top, four 20-in.-wide baffles,
agitator supports, carbon steel,
glass-filled polyester lining
2. Agitator, thickener feed tank (1): 80-in. 31,500 2,600
diameter, 42 hp, neoprene coated
3. Pump, thickener feed (2): Centrifugal, 19,200 7,200
1,807 gpm, 60-ft head, 48 hp, carbon
steel, neoprene lined (1 operating,
1 spare)
4. Thickener (1): 48-ft diameter x 5.4 ft 85,500 59,300
high, carbon steel sides, concrete basin,
includes 1-hp rake motor and mechanism,
1,780-ft2 area
5. Tank, thickener overflow (1): 27.5-ft 6,600 4,500
diameter x 5.4 ft high, 24,200 gal,
open top, carbon steel
6. Pump, thickener overflow tank (2): Centrifugal, 12,900 1,500
1,466 gpm, 75-ft head, 46 hp, carbon steel,
neoprene lined (1 operating, 1 spare)
7. Pumpf thickener underflow (2): Centrifugal, 7,800 3,200
287 gpm, 9.3-ft head, 1 hp, carbon steel,
neoprene lined (1 operating, 1 spare)
8. Tank, filter feed (1): 9.3-ft diameter x 3,700 3,100
9.3 ft high, 4,730 gal, open top, four
9-in.-wide baffles, agitator supports,
carbon steel, glass-filled polyester lining
9. Agitator, filter feed tank (1): 36-in. 5,600 500
diameter, 7 hp, neoprene coated
(Continued)
72
-------
TABLE 17. (Continued)
Item - Description
Material Labor
cost. 1982& cost. 1982$
10. Pump, filter feed tank (3): Centrifugal,
143 gpm, 50-ft head, 4 hp, carbon steel,
neoprene lined (2 operating, 1 spare)
11. Filter (3): Rotary vacuum, 8-ft diameter x
14-ft face, 48 hp, includes auxiliary equip-
ment, 380-ft2 area (2 operating, 1 spare)
12. Pump, filtrate (4): Centrifugal, 101 gpm,
20-ft head, 1 hp, carbon steel, neoprene
lined (2 operating, 2 spares)
13. Tank, filtrate surge (1): 8.3-ft diameter x
8.3 ft high, 3,300 gal, open top, carbon
steel
14. Pump, filtrate surge tank (2): Centrifugal,
201 gpm, 85-ft head, 7 hp, carbon steel,
neoprene lined (1 operating, 1 spare)
15. Conveyorf filtrate cake (1): Belt, 30 in.
wide, 75-ft-lbng horizontal, 1-1/2 hp, 50
ton/hr, 100-ft incline
11,900
381,100
17,300
1,700
9,300
37,100
3,600
68,600
1,900
1,200
1,000
3,500
Total, Area 12
659,900
185,400
Area 13—Waste Disposal5
1. Landfill site development and construction
(1): 161-acre landfill site, 2,256-ft square
landfill, 10,144,000-ydS volume, 30-yr life,
139 ft high at center, 9,171 ft perimeter
ditch to I41,000-yd3 catchment basin
2. Wheel loader (2): 7.0-yd3 bucket, diesel
engine
3. Dozers (2): Track type with straight blade,
137-hp diesel engine
(Continued)
2,616,300
384,000
138,200
243,800
73
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TABLE 17. (Continued)
Material Labor
Item - Description cost. 1982& oostT
4. Compactor (2): Vibratory sheepsfoot
compactor, self-propelled
5. Wheel loader (1): 3.5-yd3 bucket, diesel 69,000
engine
6. Water truck (1): Tandem-axle, ^-rear-wheel- 17,700
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal 45,100
cargo tank for diesel fuel and cargo space
for lubricants and other field service items,
including tools
8. Onsite trailer for sanitary facilities and 3,700
break room (1): 12-ft-wide x 30-ft-long
mobile home restructured into 2 offices, 1
break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply, and 120-volt electric
supply
9. Onsite water supply and discharge treatment 27,500 22,500
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
10. Trucks (4); Tandem-axle, Wear- wheel -drive 143,200
dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (3 operating, 1 spare), 54.0$ of total
truck costs in this area
Total, Area 13 3,648,600 266,300
a. Except as noted, 54.4$ of total waste disposal costs is charged to S02
removal.
(Continued)
74
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TABLE 17. (Continued)
Material Labor
Item - Description cost, 1Q82& cost, 1982$
Area 14—Particulate Removal and Storage
1. Electrostatic precipitator. cold side (2); 2,646,400 2,384,800
849,850 aft3/min, 424,925-ft2 collection
area, 1.0-in. pressure drop, 99.72$
removal efficiency, 500-ft2/kaft3/min SCA,
48.5 ft deep x 71.8 ft wide x 38.8 ft high,
(inside dimensions)
2. Hopper. economizer ash (8): Inverted pyramid- 146,500 92,200
type double-V hopper, 15 ft long x 7.5 ft wide
x 7.2 ft deep, thermally isolated design,
constructed of 3/8-in. Cor-Ten plate, 55-
degree valley angle, each hopper has 2
outlets, 2l6-ft3 volume and 244-ft2 area per
hopper
3. Hopper, air heater ash (8): Inverted pyramid- 77,600 45,100
type double-V hopper, 15 ft long x 7.5 ft wide
x 7.2 ft deep, constructed of 3/8-in. Cor-Ten
plate, heat traced and insulated, 55-degree
valley angle, each hopper has 2 outlets,
216-ft3 volume and 244-ft2 area per hopper,
6-kW heater
4. Hopper, ESP ash (20); Inverted pyramid-type 556,700 311|800
double-V hopper, 24.3 ft long x 14.4 ft wide
x 13.8 ft deep, constructed of 3/8-in. Cor-Ten
plate, heat traced and insulated, each hopper
has 2 outlets, 55-degree valley angle, 1,430-ft3
volume and 802-ft2 area per hopper, 10-kW heater
5. Hopper, NOx reactor ash (12): Inverted pyramid- 264,500 149,400
type double-V hopper, 23 ft long x 12.3 ft wide
x 11.8 ft deep, constructed of 3/8-in. Cor-Ten
plate, insulated, 55-degree valley angle,
each hopper has 2 outlets, 949-ft3 volume and
634-ft2 area per hopper, 10-kW heater
(Continued)
75
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TABLE 17. (Continued)
Material Labor
Item - Description cost, 19$2$—post. 1Qfip.fr
6. Hopper, bottom ash (1): 51 ft long x 352,000 202,600
9 ft wide x 22 ft high (inside dimensions),
double-V hopper, center discharge with
3,320-ft3 capacity for 12-hr ash containment,
supported independently of furnace-boiler,
3/8-in. carbon steel plate, refractory
lined, 4 hydraulically operated exit doors
emptying to 4 double-roll clinker grinders,
10-in. diameter x 2-ft-long manganese steel
rolls, 60 hp
Total, Area 14 4,043,700 3,185,900
Area 15—Particulate Transfer
1. Pressure pneumatic transfer system for fly
ash (1):
a. Conveying lines, pressure pneumatic for 59,800 32,000
fly ashes (1): Pipelines and pipe fittings
for pressure pneumatic conveyance of ash,
50-ton/hr conveying capacity with 1,320-ft
equivalent length system, 10-in. I.D.
branch lines and 12-in. I.D. main lines,
nickel-chromium cast iron pipe with Ni-Hard
or equivalent pipe fittings
b. Pressure feeders, ash and air (96): 768,000 437,200
Materials-handling valve, electrically
actuated, air operated, 10-in. I.D. ash
inlet, 10-in. I.D. ash outlet, cast iron
body, stainless steel slide gate; each
assembly includes two spring-loaded, air-
inlet check valves with cast iron bodies
c- Valves, line secret^ ft pg (12): Segregating 28,800 16,600
slide valve, electrically actuated, air
operated for on-off control of each branch
conveying line, 12-in. I.D. port, cast iron
body, stainless steel slide gate
(Continued)
76
-------
TABLE 17. (Continued)
Material Labor
Item - Description cost, 1982$ cost. 1982$
d. System control unit (1): Automatic sequence 96,000 54,600
control unit to control the programmed
operation of materials-handling valves, line
segregating valves, and blowers; includes
gauges for manual reading and override
switches for manual operation
e. Filtersf silo bag (2): Automatic cycling vent 40,000 23,200
filter, 1,440-ft2 bag area, 12 ft x 5.3 ft
x 11 ft overall dimensions
f. Fans, bag filter vent (2): 8,000 aft3/min, 16,000 9,000
AP = 6 in. H20, 20 hp
g. Compressor, pressure pneumatic transfer system 108,000 9,300
(3): 4,525 aft3/min, 13.75 psig, 500 hp,
carbon steel, with silencers (2 operating,
1 spare)
h. Silo, flv ash storage (2): 30-ft diameter x 584,000 332,800
55 ft high, 35,300-ft volume, with bin air
fluidizing system, elevated construction
for 11-1/2-ft truck clearance, rotary star
feeders and moisturizers, carbon steel
plate, 20 hp
2. Bottom ash sluice transfer system (1):
a. Pumpsf bottom ash water supply (3): Centrifu- 10,400 1,800
gal, 255 gpm, 90-ft head, carbon steel, 10 hp
(2 operating, 1 spare)
b. Pumps, bottom ash water supply (3): Centrifu- 25,900 4,000
gal, 1,860 gpm, 115-ft head, carbon steel, 75 hp
(2 operating, 1 spare)
c. Pumpsf bottom ash water supply (3): Centrifu- 40,600 5,200
gal, 587 gpm, 577-ft head, carbon steel, 150 hp
(2 operating, 1 spare)
(Continued)
77
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TABLE 17. (Continued)
Material Labor
Item - Description __ cost. 1982$ cost.
d. Tank, overflow (1): 18-ft diameter x 8 f t high, 11,400 11,000
11,400 gal, flat bottom, open top, with an
overflow weir 2 ft below top of tank, 3/8- in.
carbon steel, epoxide-coated interior
e. Pump, bottom ash hopper overflow bin 17,400 2,700
(3): Centrifugal, 550 gpm, 175-ft
head, carbon steel, 40 hp (2 operating,
1 spare)
f. Jet pump, bottom ash conveyance (4): 4,000 1,600
Jet ejector nozzle assembly and adapter
to bottom ash hopper, 360 gpm, 692-ft
head supply water, Ni-Hard nozzle
and throat construction (2 operating,
2 spares)
g. Sumo pit, sluice (1): Concrete pit, 2,900 6,300
5 ft wide x 5 ft long x 8 ft deep
with two agitator nozzles located in
bottom of bin to prevent settling
h. Pumps, bottom ash sluice (3): Centrifugal, 108,100 6,200
slurry pumps, 2,550 gpm, 230-ft head,
Ni-Hard liner and impeller, 250 hp
(2 operating, 1 spare)
i. Valves, shutoff and crossover (17): Air- 30,400 17,400
operated gate valve, 8-in. I.D. port,
Ni-Hard
j- Slurry Pipeline, one-quarter mile 82,000 29,500
basalt-lined to dewatering bins, normal
use (1): Pipeline comprising 74, 18-ft-
long sections of flanged, basalt-lined
steel pipe, 8-in. I.D. and 4 basalt-
lined elbows or bends, 8-in. I.D.
(Continued)
78
-------
TABLE 17. (Continued)
Material Labor
Item - Description cost. 1982$ cost, 1982$
k. Slurry pipeline, spare line to 31,200 11,000
dewatering bins and return waterline
(2): Pipeline comprising 34, 40-ft-
long sections of flanged steel pipe,
8-in. I.D., schedule 80 carbon steel,
and 4 hardened elbows or bends, 8-in.
I.D.
1. Binf bottom ash dewatering (2): Conical- 240,000 111,800
bottom dewatering bin, 35-ft diameter x
64 ft high, with 18-1/2-ft cylindrical
section, 26-ft-high cone, 17,l60-ft3
volume, stainless steel floating decanter
and movable drainpipe, stationary decanter
in conical section, erected for 16-1/2-ft
truck clearance, carbon steel with stainless
steel decanter drums, 400-ton capacity
m. Settling tank, bottom ash return water (1): 82,400 38,900
50-ft diameter x 15 ft deep, 220,700 gal,
carbon steel, epoxide-coated interior,
open top
n. Surge tank, bottom ash return water (1): 62,400 29,000
Water reservoir, 40-ft diameter x 16 ft
deep, 154,100 gal, carbon steel,
epoxide-coated interior, open top
o. Pump, underflow solids recycle (3); Centrifu- 11,300 2,300
gal, 250 gpm, 100-ft head, Ni-Hard steel body
and impeller, 15 hp (2 operating, 1 spare)
p. Pump, dewatering bin sump pit (3): Duplex, 7,200 2,500
60 gpm, 70-ft head, 5 hp, carbon steel,
neoprene lined (2 operating, 1 spare)
3. Water treatment system for recycle water
alkalinity control (1):
(Continued)
79
-------
TABLE 17. (Continued)
Material Labor
Item - Description _ cost. 1Q82& coat.
a. Storage tank, sulfuric acid for pH control 1»900 300
of water (1): Cylindrical steel tank,
5-ft, 7-in. diameter x 5 ft, 7 in. high,
1,000 gal, flat bottom and closed flat
top, carbon steel, all-weather housing
b. Metering pump, sulfuric acid (2): 1,900 600
Positive displacement metering pump,
0.01 to 1 gpm, 0 psig, with flow
rate controlled by a pH controller,
Carpenter 20 or alloy of similar corrosion
resistance to 93% sulfuric acid, 0.25 hp
(1 operating, 1 spare)
c. Agitator, treated water (1): Agitator 2,900 400
with 24-in. -diameter nickel-chromium
blade, 5 hp
Total, Area 15 2,474,900 1,197,200
Area 16—Flue Gas-Handling Modificationsa
1. Fan, flue gas (2): Induced draft, 20,900 100
862,243 aft3/min, AP = 22 in. H20,
carbon steel, 4,000-hp motor,
fluid drive, double width, double inlet
Total, Area 16 20,900 100
Area 17—Waste Disposalb
1- Undfill site development and construction 2,179,700 203,100
(1): 161-acre landfill site, 2,256-ft square
landfill, 10,144,000-yd3 volume, 30-yr life,
139 ft high at center, 9,171-ft perimeter
ditch to 141,000-ydS catchment basin
(Continued)
80
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TABLE 17. (Continued)
Item - Description
Material Labor
cost. 1982$ cost. 1982$
2. Wheel loader (2):
engine
7.0-yd3 bucket, diesel
3. Dozers (2): Track type with straight blade,
137-hp diesel engine
4. Compactor (2): Vibratory sheepsfoot
compactor, self-propelled
5. Wheel loader (1): 3.5-yd3 bucket, diesel
engine
6. Water truck (1): Tandem-axle, 4-rear-wheel-
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal
cargo tank for diesel fuel and cargo space
for lubricants and other field service
items, including tools
8. Onsite trailer for sanitary facilities and
break room (1): 12-ft-wide x 30-ft-long
mobile home restructured into 2 offices,
1 break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply, and 120-volt electric
supply
9. Qnsite water supply and discharge treatment
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
(Continued)
319,900
115,200
169,900
57,500
14,700
37,600
3,100
22,900
18,800
81
-------
TABLE 17. (Continued)
Material Labor
Item - Description cost. 1Q82& costf
10. Trucks (4): Tandem-axle, 4-rear-wheel- 121,300
drive dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (3 operating, 1 spare), 45.8? of total
truck costs in this area
Total, Area 17 3,041,800 221,900
a. Costs shown as additional costs of boiler I.D. fan due to ESP pressure loss.
b. Except as noted, 45.3$ of total waste disposal costs is charged to ash
removal.
82
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reactor with two hoists; one lifts the modules from ground level and the other
moves the modules in the reactor on a monorail system. Retractable steam
sootblowers are provided between each catalyst bed to remove ash and ammonia
salt deposits.
Area 3 - Flue Gas Handling—
This area includes the incremental increase in the capacity of the two
boiler ID fans to compensate for the 7-inch HgO pressure drop in the
reactors and the ductwork associated with the NOX control system. The
ductwork consists of the economizer bypass, reactor bypass, ducts from the
boiler to the reactors and from the reactors to the air heater, and the addi-
tional ductwork needed to connect the air heater to the downstream equipment
(made necessary to accommodate the NOX control system). Included in the
cost of the ductwork are the costs of insulation, flanges, dampers, and
expansion joints.
Area 4 - Air Heater Modifications—
Modifications to two air heaters to reduce the adverse effects of ammonia
salt deposition and corrosion are provided. Only the incremental costs for
these modifications, as compared with a standard air heater, are included.
The hot- and cold-end elements are increased in thickness (from 24 to 22 gauge
and 22 to 18 gauge, respectively) and a low-alloy corrosion-resistant metal is
used for the hot-end element. The hot-end element depth is decreased and the
cold-end element depth is increased, with a net increase in overall depth.
The cold-end element spacing is reduced from 6 mm to 3.5 mm and the diameter
of the rotor is increased. The overall result of these changes is an increase
in heat transfer area of 50%, compared with a standard air heater.
Two additional steam sootblowers are provided for each air heater to
clean the hot-end elements. The frequency of water washing and the quantity
of water used are also increased, with a corresponding increase in the size of
pipes and pumps in the water washing system. The increase in the quantities
of steam and water used as a result of these changes is shown in Table 18.
Area 5 - Waste Disposal—
The only disposal costs involved in NOx control are for spent catalyst
disposal. The catalyst is assumed to be a nonhazardous waste that is trucked
to and disposed of in the landfill. The disposal costs are prorated from the
total waste disposal costs based on volume.
S02 Control
Processing areas 6 through 13 describe the limestone FGD process.
Area 6 - Materials Handling—
The materials-handling area comprises the equipment to unload, store, and
transfer the limestone used in the FGD system. The 0- x 1-1/2-inch limestone
is dumped from trucks or railcars to an unloading hopper and transported by
83
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00
TABLE 18. STEAM SOOTBLOWING AND WATER WASHING REQUIREMENTS
FOR AIR HEATERS OF CASE 1
Case
Standard with-
out SCR
Modified with
SCR
Case
Number of
blowers
2
4
Cycles/ vr
Cycles/day/
blower
3
3
Hr/ cycle
Steam
Min/ cycle
17
sootblowine
Lb
steam/ min
127
18 127
Water washinc
Gal/
min/ heater
Psic
Lb
steam/ Yr
2,968,625
6,286,500
Gal/yr
Additional
Ib
3,317,875
Additional
gal/yr
Standard with-
out SCR
Modified with
SCR
1,320
2,020
75 1,267,200
150 3,878,400 2,611,200
-------
belt conveyors to a 30-day capacity storage pile over two reclaim hoppers.
The unloading system has a capacity of 250 ton/hr. The limestone is reclaimed
and transported to the feed preparation area with a belt conveyor system with
a capacity of 100 ton/hr. The system is operated intermittently to meet the
FGD limestone requirements of 27 ton/hr.
Area 7 - Feed Preparation—
The feed preparation area consists of equipment to prepare limestone
slurry for the FGD system. It includes two operating and one spare train,
each consisting of a crusher, a wet ball mill, and an agitated product tank,
with ancillary equipment such as a dust collection system and pumps. The
limestone is first crushed to 0 x 3M inch and then wet ground to a 60$ slurry
with a particle size of 90$ minus 325 mesh. The slurry from each ball mill is
collected in the mill product tank of the ball mill, then stored in an 8-hour
capacity feed tank that supplies the FGD system.
Area 8 - Flue Gas Handling—
This area consists of the inlet plenum that supplies the absorber trains,
the absorber train ductwork, two emergency bypass ducts from each end of the
feed plenum to the stack plenum for bypass of 50$ of the scrubbed gas, and one
ID booster fan for each of the five absorber trains to compensate for the 7.8-
inch H20 pressure drop in the FGD system.
The emergency bypass ducts and the ductwork upstream from the absorbers
and downstream from the reheaters are constructed of Cor-Ten steel. The
ductwork from the absorbers to the reheaters is constructed of 316 stainless
steel. The ID booster fans are constructed of Inconel 625. The flue gas
velocity is 50 ft/sec. All ducts are insulated with 2 inches of glass wool.
Area 9 - S02 Absorption—
The area consists of the four operating and one spare spray tower
absorbers and related equipment. The absorbers are equipped with presaturator
systems in the inlet duct that spray the flue gas with 4 gal/kaft3 of scrub-
bing liquid, cooling it from 300°F to 127°F as it enters the absorber.
The spray towers are rectangular neoprene-lined carbon steel vessels 3^ by 17
feet, 40 feet high with three layers of stainless steel grids to control the
gas distribution. Each absorber contains four banks of spray headers, one
above each grid spraying downward and one below the bottom grid spraying
upward. The absorbers are equipped with horizontal open-vane, three-pass,
fiberglass chevron mist eliminators to reduce the entrained moisture content
of the flue gas to 0.1$ by weight. The mist eliminators are continuously
washed on the underside and intermittently on the top side with makeup water.
The presaturators and absorbers are equipped with air sootblowers to remove
deposits.
Absorbent liquid drains from the absorber into an oxidation tank (which
is included in area 11) and overflows by gravity into a recirculation tank to
which the makeup slurry is added. The absorbent liquid is recirculated from
this tank to the presaturator and absorber spray headers.
85
-------
The absorber is designed for a superficial gas velocity of 10 ft/sec and
an S02 removal efficiency of 89$ (in addition, 50% of the S03 and 100$ of
the HC1 are removed). The L/G ratio is 106 gal/kaft3 and the limestone
stoichiometry is 1.4 mols CaC03/mol SC>2 plus 2HC1 removed.
Area 10 - Reheat--
The reheaters are tubular steam heat exchangers designed to provide a
flue gas temperature of 175°F at the stack plenum. They are situated in the
ducts between the absorber and ID booster fan. The gas velocity is 25 ft/sec.
The temperature increase required is approximately 47°F, from 125°F to
172°F, with the remaining increase provided by compression in the ID booster
fans. The reheater tubes in contact with flue gas below 150°F are Inconel
625 and the remainder are Cor-Ten steel. The reheaters are equipped with air
sootblowers to clean the tubes.
Area 11 - Oxidation—
The oxidation area for the FGD system consists of an agitated tank
beneath each absorber that contains a sparging ring (a circular pipe manifold
with holes in the periphery) to introduce oxidizing air and low-pressure
compressors that supply air at a rate of 2.5-gm atoms 0/gm mol S02
absorbed. The system is designed to produce a minimum oxidation level of 95$.
A bleedstream containing 8$ solids is withdrawn from the tank and pumped to
the solids separation area; the remaining slurry overflows to the absorber
recirculation tank.
Area 12 - Solids Separation—
In this area, the bleedstreams from the absorbers are dewatered and
stored for removal to the disposal area. The 8$ solids bleedstreams from the
four absorber trains are combined in a thickener feed tank and dewatered to
40$ solids in a 48-foot-diameter thickener. The thickener underflow is
dewatered to 85$ solids in two rotary vacuum filters (a spare filter is
provided) and conveyed to a concrete storage pad. The filters are 8 feet in
diameter and 14 feet long. The thickener overflow and the filtrate are
returned to the feed preparation and absorber areas.
Area 13 - Waste Disposal—
The operations in this area consist of trucking the FGD waste to the
common landfill and operation of the landfill. The waste is loaded into 26-
yd3 dump trucks with a front loader and hauled one mile to the landfill.
The landfill and its operation are described in the premise section. The FGD
waste disposal costs associated with the operation of the landfill are pro-
rated on the basis of volume.
Particulate Control
Processing areas 14 through 17 describe the bottom ash and fly ash
control processes.
Area 14 - Particulate Removal and Storage—
This area consists of two cold-side ESPs and all hoppers associated with
bottom ash and fly ash collection. The ESPs are operated in parallel. Each
86
-------
is 49 feet long, 72 feet wide, and 39 feet high, with an SCA of 500
ft2/aft3/min and a pressure drop of 1.0 inch I^O. The removal
efficiency is 99.7?. (Some reviewers state that an SCA range of 200 to 250
ft2/kaft3/min is adequate to meet the ash removal required by the ESP in
case 1 . An SCA of 500 ft2/kaft3/min was used for case 1 after determining
SCA values ranging from about 450 to over 650 ft2/kaft3/min from several
references.)
There are 48 double-vee fly ash hoppers, each with 2 outlets, 8 on the
economizer, 4 on each air heater, 10 on each ESP, and 6 on each SCR reactor.
All are inverted-pyramid type with 55-degree slopes and are constructed of
Cor-Ten steel. They are equipped with electric heaters and are insulated.
The economizer hoppers are equipped with isolation chutes to prevent ash
fusion and combustion of residual carbon. The bottom ash hopper has a double-
vee bottom and a refractory lining. It is equipped with flushing jets and
water lances and has four discharge doors, each with a 2-roll clinker grinder.
All hoppers have a 12-hour capacity.
Area 15 - Particulate Transfer—
This area consists of a pneumatic system that removes the fly ash from
the hoppers and silos where it is stored for transport to the landfill, and a
bottom ash hydraulic transporting and dewatering system.
The fly ash pneumatic system operates at an air pressure of about 13
psig. Fly ash is removed from each of the 96 hopper outlets through air lock
valves to 10-inch branch lines in an automatically controlled sequence. The
branch lines connect to 12-inch main lines that transport the ash to two
carbon steel storage silos, each 30 feet in diameter and 55 feet high,
elevated for direct loading to trucks. The silos are equipped with fabric
filter dust collectors, air fluidizing systems, and moisturizers to moisten
the ash as it is discharged.
The bottom ash system consists of a hydraulic sluicing system to trans-
port the ash to dewatering bins. The ash is periodically sluiced through the
clinker grinders on the hopper to high-pressure water ejector pumps that
sluice it to a sump from which it is sluiced one-fourth of a mile to the
dewatering system by centrifugal pumps (the ejector pumps are self-priming and
nonplugging while the centrifugal pumps are more efficient for long-distance
pumping). All pipes are basalt lined and the pumps and fittings are con-
structed of abrasion-resistant metal alloy. The ash is sluiced to one of two
dewatering bins. The bins have conical bottoms and are elevated for discharge
of the ash to trucks. The bins have a capacity of 72 hours and operate on a
24-hour cycle to allow intermittent operation. The ash is allowed to drain to
a 10$ water content. The water drains first to a settling tank to remove
fines and then to a surge tank. The water is returned to the sluicing system
after pH adjustment and is also recirculated continuously through the bottom
ash hopper as necessary to maintain a maximum 175°F water temperature in the
hopper.
Area 16 - Flue Gas Handling—
This area includes the incremental increase in the boiler ID fan neces-
sary to compensate for the 2-inch 1^0 pressure drop in the ESP and related
87
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ductwork and the ductwork connecting the ESP to the air heaters and the FGD
inlet plenum.
Area 17 - Waste Disposal —
This area consists of the equipment and operations involved in trucking
the bottom ash and fly ash to the landfill and the portion of the landfill
operation prorated to ash disposal.
CASE 2
Case 2 is based on 0.7$ sulfur western subbituminous coal. It consists
of an SCR NOx control process, a lime spray dryer FGD process, and a
baghouse for combined FGD and fly ash collection. The flow diagram is shown
in Figure 4, the material balance is shown in Table 19, and the equipment list
is shown in Table 20. Each of the process areas is described below with the
exception of those for which the verbal description is similar to those for
the same areas previously described in case 1 .
Control
The 2-train SCR reactor system is essentially the same as the system in
case 1 . The major differences result from size differences related to the
lower concentration of NOx in tne flue Sas» the larger volume of flue gas,
and slight differences in equipment layout resulting from these differences.
Process areas 1 through 5 describe the NOX control process.
Area 1 - Ammonia Storage and Handling —
The description of this area is the same as the description for area 1 in
case 1. The ammonia storage system is identical. The ammonia vaporization
and air heating and mixing system is slightly smaller because of the lesser
quantity of ammonia required and the injection and mixing grids are slightly
larger because of the larger volume of flue gas.
Area 2 - Reactor —
The equipment in this area is essentially the same as the equipment
description for area 2 in case 1 . The reactors are proportionally larger
because of the larger flue gas volume (53 by 37 feet in cross section,
compared with 46 by 37 feet in case 1) and the catalyst volume is 29,862
ft3, providing a space velocity of 2,320 hr~1 (as compared with a catalyst
volume of 24,400 ft3 and a space velocity of 2,350 hr~1 in case 1).
Area 3 - Flue Gas Handling—
The pressure drop is 7 inches H20, as it is in case 1 , and the ductwork
design is the same but the equipment is proportionally larger because of the
larger flue gas volume.
Area 4 - Air Heater Modifications—
The same air heater modifications described in case 1 are included. In
this case, the air heater is more than double the size of that of a compara-
tive air heater for service without NOX control. The additional sootblowing
and water washing requirements are shown in Table 21 .
88
-------
00
Figure 4. Case 2 flow diagram.
-------
TABLE 19. CASE 2 MATERIAL BALANCE
Stream No.
Description
1
1
5
6
-i
R
1
in
Total <*t-rpam. Ib/hr
Sft3/min (60°F)
Tpmplratlire. «;
Pressure, psle
1
Coal to boiler
640.200
Combustion
air to air
heater
5.765.200
1,273,900
80
Combustion air
to boiler
4
Gas to
economizer
A. 977. 200 • 5.609.200
1,099,800 • 1,215,300
'
5
Gas to
ammonia
injection
grid
5.609.200
1,215,300
750
Description
1
2
3
4
5
6
7
«
9
19
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure, psig
6
Gas with
ammonia to SCR
reactor
5,648,400
1,224,100
747
7
Gas to air
heater
5,648,400
1,224,200
8
Gas to
inlet
plenum
6,436,400
9
Spray
dryer
bypass gas
742,200
1,398,300 161,200
750 ! 300 300
;
10
Gas to
spray
dryer
5,694,200
1,237,100
300
1
A
3
4
b
6
/
8
9
lu
Stream No.
Description
Total stream, Ib/hr
Sft^/min (60UF)
Temperature, °F
Pressure, psig
11
Gas from
spray dryer
5,933,300
1,297,700
154
12
Combined
gas to
baghouse
6,675,500
1,458,900
170
13 14
Steam to
Gas to dilution
stack air heater
6,573,800 2,000
1,458,900
170 298
50
I
15
Dilution air
to mixer
38,412
8,500
250
1
2
3
^
5
6
7
8
9
10
Stream No.
Description
Total stream, Ib/hr
SftJ/min (60°F)
Temoerature, °F
Pressure. DSie
16
Ammonia to
mixer
788
300
17
Ammonia-air
mixture to
injection grid
39,200
8,800
1,250
18
Bottom ash
from boiler
48,900
19
Bottom ash
sluice water to
settling tank
60,500
20
Dewatered
bottom ash
to disposal
9,100
(Continued)
90
-------
TABLE 19. (Continued)
1
2
3
4
5
6
7
8
9
10
S tream No
Description
Total stream. Ib/hr
Sft3/min (60°F)
Temperature . °F
Pressure, psia
21
Settling tank
surge tank
42.000
22
Settling tank
solids return
bin
18,500
23
surge tank
200
-24
water
700
25
Water to
sluice
40.700
i
2
3
4
b
6
7
8
9
1ft
Stream No.
Description
Total stream, Ib/hr
Sft3/min (60°F)
Temperature , °F
Pressure, psia
26
Surge tank
underflow to
dewatering bins
2,200
27
Baghouse
solids to
disposal
40,300
28
Baghouse
solids to
transfer
station
101,700
29
Solids to
solids
recycle
silo
61,400
30
Feed slurry
to spray
dryer
273,300
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
Total stream, Ib/hr
Sft3/min (60°F)
Temperature. °F
Pressure. psiE
31
Makeup water
to combined
feed tank
20,000
32 j 33 34
Recycle Makeup
Lime slurry slurry water to
to combined to combined reslurry
feed tank feed tank tank
14,500 i 238,800 51,200
1
1
;
',
35
Reslurried
solids to
recycle
tank
85,400
J
2
3
/,
3
6
7
8
9
JO
Stream No.
Description
Total stream, Ib/hr
Sft^/min (60°F)
Temperature. °F
Pressure, psig
36
Lime feed
to wet ball
mills
3,435
37
Makeup water
to wet ball
mills
11,065
" ""
38 [
1
Makeup water •
to recycle ;
slurry tank
92,200
.
!
,
1
I
91
-------
TABLE 20. CASE 2 EQUIPMENT LIST
Material Labor
Item - Description ___ cost. 1Q82& oast,
Area 1— Ammonia Storage and Injection
1. Compressor. NH^ unloading (2); 14.6 ft3/min, 8,600 2,100
capable of 250 psig suction max. , 5-hp motor,
cast iron body, insulated (1 operating, 1 spare)
2. Tank. NIfo storage (5): Horizontal, 9-ft 169,500 3,900
diameter x 66 ft long, 30,000 gal, 250 psig,
carbon steel
3. Vaporizer, NH^ (50): Electric resistance 29,800 800
heaters, carbon steel shell, 15-kW rated,
10 per ammonia storage tank
accumulator (1): 281 ft3, 5,100 5,100
5.5-ft diameter x 10 ft long, carbon steel,
insulated (3 in.), +2.75-ft hemispherical
end, 15 psig design pressure, 180°F design
temperature
5. Ammonia absorber (1): if ft high x 1.1-ft 400 1,900
diameter, 1 .5-ft support, with vent, water
supply, 1/4-in. Cor-Ten
6. Blower, air (3): 4,400 aft3/min, 20 in. H20, 12,500 1,400
20 hp, carbon steel, insulated (2 operating,
1 spare)
7. Heater, dilution air (2): Fin tube steam 26,200 800
heater, 500-ft2 surface area, aluminum
tubes, galvanized cabinet
8. Mixer, ammonia and dilution air (2): 30-in. 11,600 7,200
diameter x 9.5 ft long, carbon steel
9- Injection grid, NH^ and air (2): 32 ft wide, 90,700 96,600
19 ft high, Cor-Ten pipe and supports
10. Mixing grid, NH^, air, and flue gas (2): 33 ft 14,000 27,600
wide, 15 ft high, Cor-Ten pipe
Total, Area 1 368,400 147,400
(Continued)
92
-------
TABLE 20. (Continued)
Item - Description
Material Labor
cost. 1Q-82& cost. 1Q82&
Area 2—Reactor
1. Reactor (2): 53 ft wide x 37 ft
long x 43 ft high, 6-in. mineral wool
insulation; carbon steel housing,
internals, and supports; elevated 40 ft
2. Sootblower. steam (20): 53 ft, retractable,
40-lb/min steam at 86 psig, 1 hp
3- Reactor crane and hoist (2): Electric 2-
speed hoist, 2-ton capacity, 80-ft lift,
grade to access door, 3 hp
4. Reactor hoist (4): Electric single-speed
hoist, 2-ton capacity, access door to inside
reactor, 3 hp
2,649,600 2,798,600
686,400
21,200
28,200
33,100
600
1,700
Total, Area 2
3,385,400 2,834,000
Area 3—Flue Gas—Handling Modifications**
1. Fan, flue gas (2): Induced draft,
1,031,915 aft3/min, AP = 20 in. H20,
carbon steel, 5,000 hp, fluid drive,
double width, double inlet
128,000
1,800
Total, Area 3
128,000
1,800
Area 4—Air Heater Modifications^
1. Air heater (2): Vertical inverted, size
33» Ljungstrom type,
Hot elements: DL type, 22 gauge, low alloy
corrosion resistant, 26 in.
deep, 206,700-ft2 area
(Continued)
1,026,000
23,900
93
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost, 1982$—oost.
Cold elements: NF type, 3.5-mm spacing, 22
gauge, low alloy corrosion
resistant, 42 in. deep,
391,UOO-ft2 area
2. Sootblower, steam (2): Retractable, 175 15,200 900
Ib/min steam at 200 psig
3. Pump, wash water booster (3): Centrifugal, 3»900 900
2,970 gpm, 210-ft head, 300 hp, carbon
steel (2 operating, 1 spare)
Total, Area 4 1,045,100 25,700
Area 5—Waste Disposals
1. Landfill site development and construction 22,300 2,900
(1): 75-acre landfill site, 1,475-ft square
landfill, 3,213,000-yd3 volume, 30-yr life,
98 ft high at center, 6,046-ft perimeter
ditch to 6l,000-yd3 catchment basin
2. Wheel loader (1): 5.3-yd3 bucket, diesel 2,200
engine
3. Dozer (1): Track type with straight blade, 1,000
103-hp diesel engine
4. Compactor (1): Vibratory sheepsfoot 1,300
compactor, self-propelled
5. Wheel loader (1): 2.6-yd3 bucket, diesel 1,000
engine
6. Water truck (1): Tandem-axle, 4-rear-wheel- 300
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
(Continued)
94
-------
TABLE 20. (Continued)
Material Labor
Item - Description costr 1982* cost. 1Q82&
7. Service truck (1): Wrecker rig with 500-gal 400
cargo tank for diesel fuel and cargo space
for lubricants and other field service items,
including tools
8. Onsite trailer for sanitary facilities and 100
break room (1): 12-ft-wide x 30-ft-long
mobile home restructured into 2 offices,
1 break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply, and 120-volt electric
supply
9. Onsite water supply and discharge treatment 300 200
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
10. Truck (2): Tandem-axle, 4-rear-wheel- 900
drive dump truck with ash-haul body,
26-yd3 capacity, 56,000-lb suspension,
9 forward speeds, manual transmission,
290-hp diesek engine (1 operating,
1 spare), 0.7% of total truck costs in
this area
Total, Area 5 29,800 3,100
a. Costs shown are additional costs of boiler I.D. fan due to NOx reactor
pressure loss.
b. Costs shown are for modifications and additional equipment made necessary
by NOx removal.
c. Except as noted, 1.0? of total waste disposal costs is charged to NOx
removal.
(Continued)
95
-------
TABLE 20. (Continued)
Item - Description
Material Labor
cost. 1Q82& coat,
Area 6—Materials Handling
1. Car shaker and crane (1): Top mounted
with crane, 20-hp shaker, 7-1/2-hp hoist
2. Car puller (1): 25-hp puller, 5-hp return
3. Hopper, unloading (1): 16-ft diameter,
10-ft straight side, includes 6-in.
square grating
4. Feeder, unloading (1): Vibrating, hopper
mounted, 3-1/2-hp motor
5. Conveyor, lime unloading (1): Belt, 100
ton/hr, 20-ft horizontal, 5-hp motor
6. Dust collector, lime unloading pit (1): Bag
filter, polypropylene bag, includes dust
hoods, reverse jet cleaning
7. Elevator, lime storage silo (1): 100 ton/hr,
100 ft high, 50-hp motor
8. Concrete silo, lime storage (1): 44,960 ft3,
33.7-ft diameter, 50.5-ft straight side
storage height, 30-day storage
9. Hopper bottom, lime storage silo (1): 60-degree
cone, carbon steel
10. Feeder, lime storage silo reclaim (1): Hopper
mounted, 3-1/2 hp, vibrating type
11. Conveyor, lime reclaim (1): Belt, 109-ft
horizontal, 5-hp motor
12. Elevator, lime feed bin (1): 50 ft high,
50-hp motor
(Continued)
71,900
63,000
15,500
3,800
11,400
11,200
51,700
82,500
10,700
3,800
23,900
47,700
13,000
19,600
5,900
300
1,400
5,200
3,700
172,100
7,300
400
3,100
2,200
96
-------
TABLE 20. (Continued)
Item - Description
Material Labor
cost. 19824 cost. 1982$
13. Bin, lime feed (2): 10-ft diameter,
15-ft straight side height, covered,
carbon steel, vent filter
9,700
6,700
Total, Area 6
406,800
240,900
Area 7—Feed Preparation
1. Feedert lime bin unloading (2): Vibrating,
24 in. wide x 48 in. long, 16 ton/hr,
5 hp, carbon steel
2. Feeder, lime feed (2): Screw, 6-in. diameter
x 12 ft long, 1 hp, 2 ton/hr
3. Slaker (2): Ball mill type, spiral classifier,
mild steel, 2-ton/hr system, 4-ft inside
diameter x 4-ft-long ball mill, 25 hp for
mill, 14$ manganese steel shell (1 operating,
1 spare)
4. Pump, lime slaker water supply (1); Centrifugal,
23 gpm, 100-ft head, 1 hp
5. Tank, slaker product (1): 6-ft diameter, 7 ft
high, 1,450 gal, open top, four 6-in.
baffles, agitator supports, carbon steel,
neoprene lined
6. Agitator, slaker product tank (1): 2 turbines,
24-in. diameter, 2.5 hp, neoprene coated
7. Pump, slaker product tank (3): Centrifugal,
70 gpm, 150-ft head, 3 hp, carbon steel,
neoprene lined (2 operating, 1 spare)
8. Tank, combined feed (1): 40-ft diameter x
20 ft high, 182,700 gal, open top, four
40-in. baffles, agitator supports, carbon
steel, neoprene lined
(Continued)
8,300
4,000
107,100
1,000
2,000
8,000
10,000
46,300
600
3,400
14,000
600
1,700
900
2,300
37,600
97
-------
TABLE 20. (Continued)
Item - Description
Material Labor
cost. 1982$ cost,
9. Agitatorf combined feed tank (1): 160-in. 60,900 4,600
diameter, 50 hp, neoprene coated
10. fumpf combined feed tank (12): Centrifugal, 53,300 23,300
142 gpm, 100-ft head, 10 hp, carbon steel,
neoprene lined (6 operating, 6 spares)
11. gumo, makeup water and dilution water for 4,800 800
temperature control (1): Centrifugal, 60 gpm,
250-ft head, 15 hp, carbon steel
12. gump, emergency flue gas quench (4): Centrifugal, 28,500 3,800
525 gpm, 200-ft head, 50 hp, carbon steel
(3 operating, 1 spare)
13. Tank, overflow feed (4): 30 gal, 1.1-ft 500 800
diameter x 4 ft high, neoprene lined
14. Dust collecting system (1): Bag filter, poly- 7,800 2,700
propylene bag, 2,200 aft3/min, 7-1/2 hp,
3 hoods
Total, Area 7 342,500 97,100
Area 8—Flue Gas Handlinga
1. Fan, flue gas (4): Induced draft, 455,000
aft3/min, AP = 12 in. H20, Inconel 625,
1,250 hp, fluid drive
1,199,100
19,700
Total, Area 8
(Continued)
1,199,100
19,700
98
-------
TABLE 20. (Continued)
Material Labor
Item - Description ooat. 1Q82& cost. 1Q82$
Area 9—SC-2 Absorption
1. Sorav drver (4): 46-ft diameter x 41 ft 7,846,300 1,011,200
high, straight side, carbon steel, 60-degree
cone bottom, 40 ft long, 7-ft penthouse, total
height 87 ft, one rotary atomizer per spray
dryer, 700-hp motor on atomizer, (3 operating
1 spare)
Total, Area 9 7,846,300 1,011,200
Area 10—Lime Particulate Recycle
1. Silo, solids recycle (2): 25-ft diameter 333,600 197,000
x 37-ft straight side, 18,000 ft3, covered,
carbon steel, porous stone air slide bin
activator system
2. Vibrator (2): Bin actuator, 10-ft diameter, 28,900 4,800
5 hp
3. Pneumatic pressure transfer system (1): 12 in.,
25 ton/hr, 1,000 ft long
a. Conveying lines, pressure pneumatic for 25,300 13,600
soray drver solids (1): Pipelines and
pipe fittings for pressure pneumatic
conveyance of ash, 25-ton/hr conveying
capacity with 1,000-ft equivalent
length system, 10-in. I.D. branch lines
and 12-in. I.D. main lines, nickel-
chromium cast iron pipe with Ni-Hard
or equivalent pipe fittings
b. Pressure feeders, ash and air (4): Materials- 32,000 18,200
handling valve, electrically actuated, air
operated, 10-in. I.D. ash inlet, 10-in. I.D.
ash outlet, cast iron body, stainless steel
slide gate; each assembly includes two
spring-loaded, air-inlet check valves with
cast iron bodies
(Continued)
99
-------
TABLE 20. (Continued)
Material Labor
Item - Description __ post. 1Q.82& costr
c. Valves, line segregating (2): Segregating 4,800 2,800
slide valve, electrically actuated, air
operated for on-off control of each branch
conveying line, 12-in. I.D. port,
cast iron body, stainless steel slide
gate
d. System control unit (1): Automatic 29,100 16,800
sequence control unit to control the
programmed operation of materials-
handling valves, line segregating
valves, and blowers; includes gauges
for manual reading and override
switches for manual operation
e. Filters, silo bag (2): Automatic 27,700 15,900
cycling vent filter located on storage
silo to remove residual ash from
silo air discharge, 720-ft2 bag area,
6 ft x 5.3 ft x 11 ft overall dimensions
f. Fans, bag filter vent (2): 2,364 aft3/min, 12,700 7,200
0.2 psig, 5-hp motor
4. Feeder, recycle slurry tank (2): Screw, 14,900 3,600
20-in. diameter x 17 ft long, 5 hp, 100
ton/hr
5. Tank, recycle slurry (1): 30-ft diameter x 44,300 35,400
31 ft high, 162,600 gal, open top, four
30-in. baffles, agitator support, carbon
steel, neoprene lined
6« Agitator, recycle alurrv tank (1): 120-in. 78,700 5,900
diameter, 75 hp, neoprene coated
7- PUMP, recycle slurry tai^k (3): Centrifugal, 15,200 6,200
308 gpm, 100-ft head, 25 hp, carbon steel,
neoprene lined, 1 train of 3 pumps in series
(2 operating, 1 spare)
(Continued)
100
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost, 1982$ cost, 1982$
8. Pump, makeup water (2): Centrifugal, 286 gpm, 10,400 1,600
150-ft head, 20 hp, carbon steel, (1 operating,
1 spare)
9. Conveyor, dragline (incline) (4): 50 ft/min, 120,000 3,300
24 in. wide x 15 ft long, 2 hp
10. Compressorsf pneumatic pressure transfer 34,700 3i100
system (1): 3»200 aft3/min, 15 psig,
carbon steel, with silencers, 500-hp motor
11. Tankf reslurrv (1): 15-ft diameter x 10 ft 7,300 5,800
high, 11,900 gal, carbon steel, neoprene
lined
12. Agitator, reslurrv tank (1): 60-in. diameter, 25,600 1,900
15 hp, neoprene coated
13. Pumpr reslurrv tank (2); Centrifugal, 8,500 1,900
160 gpm, 100-ft head, 15 hp, carbon
steel, neoprene lined
14. Conveyorf reslurrv tank and re.lect stack 100,300 13,400
feed (2): Belt, 285 ft long x 24 in. wide,
17 ton/hr, 2 hp
Total, Area 10 954,000 358,400
Area 11—Waste Disposal*)
1. Landfill site development and construction 345,200 44,500
(1): 75-acre landfill site, 1,475-ft square
landfill, 3,213,00-yd3 volume, 30-yr life,
98 ft high at center, 6,046-ft perimeter
ditch to 6l,000-yd3 catchment basin
2. Wheel loader (1): 5.3-yd3 bucket, diesel 33,700
engine
(Continued)
101
-------
TABLE 20. (Continued)
Material Labor
Item - Description post, 1992$ cost.
3. Dozers (1): Track type with straight blade, 15,000
103-hp diesel engine
4-. Compactor (1): Vibratory sheepsfoot 20,700
compactor, self-propelled
5. Wheel loader (1): 2.6-yd3 bucket, diesel 15,600
engine
6. Water truck (1); Tandem-axle, 4-rear-wheel- 5,200
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal 5,400
cargo tank for diesel fuel and cargo space
for lubricants and other field service
items, including tools
8. Onsite trailer for sanitary facilities and 1,100
break room (1): 12-ft-wide x 30-ft-long mobile
home restructured into 2 offices, 1 break room,
1 lavatory; propane gas stove and heater;
self-contained portable toilet, potable water
supply, and 120-volt electric supply
9. Onsite water supply and discharge treatment 4,000 3,300
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
(Continued)
102
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost, 1982$ cost, 1982$
10. Trucks (2): Tandem-axle, U-rear-wheel-drive 20,900
dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (1 operating, 1 spare), 15.7$ of total
truck costs in this area
Total, Area 11 466,800 47,800
a. These fans serve both SOx and particulate removal cases. 33$ of total fan
costs is charged to SOx removal for spray dryer pressure loss.
b. Except as noted, 15.9$ of total waste disposal costs is charged to S02
removal.
(Continued)
103
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost, 1982$ cost.
Area 12—Partioulate Removal and Storage
1. Baghouae. flue gas participate removal (2): 2,502,000 2,218,800
880,200 aft3/min, automatic fabric filters,
1.76 gross air-to-cloth ratio, 500,115-ft2
gross bag area, based on 80$ availability,
2.2 net air-to-cloth ratio, 5-in. pressure
drop, 28 compartments with 375 bags/compartment,
99.88$ removal, 14 compartments/baghouse,
each train 204 ft deep x 58 ft wide x 70 ft
high (inside dimensions)
2. Hopper, economizer ash (10); Inverted 188,200 118,200
pyramid-type double-V hopper, 15 ft x
7.7 ft wide x 7-4 ft deep, thermally
isolated design, constructed of 3/8-in.
Cor-Ten plate, 55-degree valley angle,
each hopper has 2 outlets, 232-ft3 volume
and 252-ft2 area per hopper
3. Hopper, air heater ash (10): Inverted pyramid- 99,500 57,900
type double-V hopper, 15 ft long x 7.7 ft wide
x 7.4 ft deep, constructed of 3/8-in. Cor-Ten
plate, heat traced and insulated, 55-degree
valley angle, each hopper has 2 outlets,
232-ft3 volume and 252-ft2 area per hopper,
6-kW heater
4. Hopper, baghouse particulates (56): Inverted 1,748,500 976,700
pyramid-type double-V hopper, 29 ft long x
14.6 ft wide x 14 ft deep, constructed of
3/8-in. Cor-Ten plate, heat traced and
insulated, each hopper has 2 outlets, 55-
degree valley angle, 1,585-ft3 volume and
917-ft2 area per hopper, 10-kW heater
5. Hopper. NOx reactor ash (20): Inverted 323,700 184,500
pyramid-type double-V hopper, 18.5 ft long
x 10.6 ft wide x 10.2 ft deep, constructed
of 3/8-in. Cor-Ten plate, insulated, 55-degree
valley angle, each hopper has 2 outlets,
586-ft3 volume and 448-ft2 area per hopper,
10-kW heater
(Continued)
10A
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost. 1Q82* cost. 1Q82&
6. Hopper, bottom ash (1): 51 ft long x 10 ft 285,000 164,700
wide x 9-1/2 ft high (inside dimensions),
double-V hopper, center discharge with
2,170-ft3 capacity for 12-hr ash containment,
supported independently of furnace-boiler,
3/8-in. carbon steel plate, refractory lined,
4 hydraulically operated exit doors emptying
to 4 double-roll clinker grinders, 10-in.
diameter x 2-ft-long manganese steel rolls,
60 hp
Total, Area 12 5,146,900 3,720,800
Area 13—Particulate Transfer
1. Vacuum/pressure pneumatic fly ash and
baghouse ash transfer system consisting
QL (1):
a. Conveying lines, vacuum/pressure pneumatic 215,000 103,700
for fly ashes and spray dryer solids (4):
Pipelines and pipe fittings for vacuum
pressure conveyance of ash from point of
collection to transfer stations, 25-ton/hr
conveying capacity with 1,320-ft equivalent
length, 10-in. I.D. branch lines and 12-in.
I.D. main lines, nickel-chromium cast
iron pipe with Ni-Hard or equivalent pipe
fittings
b. Valves, ash and air inlet (192): Materials- 614,400 357,700
handling valve, electrically actuated,
air operated, 10-in. I.D. ash inlet, 10-in.
I.D. ash outlet cast iron body, stainless
steel slide gate; each assembly includes two
spring-loaded, air-inlet check valves with
cast iron bodies
c. Valves, line segregating (24): Segregating 86,400 6,900
slide valve, electrically actuated, air
operated for on-off control of each branch
conveying line, 12-in. I.D. port, cast iron
body, stainless steel slide gate
(Continued)
105
-------
TABLE 20. (Continued)
Material Labor
Item - Description _ oost. 1Q82& cost,
d. Ash separation system comprising of (2): 96,000 66,600
Primary air-ash separator ( 2) : Primary
centrifugal separator with tangential
air-ash inlet, cyclone-type vortex finding
sleeve, and top vertical outlet; two-gate,
three-chamber ash removal and air-lock
provision cycled for continuous vacuum
operation; 5-ft diameter x 17 ft high;
40-ton/hr capacity, carbon steel shell,
Ni-Hard in high-velocity compartment
Secondary air-ash separator (2): Secondary
centrifugal separator similar to primary unit
except 3. 5-ft diameter x 12 ft high for
6.9-ton/hr capacity
Air-ash bag filter (2): Bag filter for air-ash
service at 15QOF, 19-in. Hg vacuum, 1,200-ft2
cloth area, cycled bag shaker and air-lock
delivery to storage bin, 1 .4-ton/hr capacity
e. Mechanical exhausters for supplying vacuum 240,000 62,100
(6): Two-impeller, straight-lobe type,
2,000 aft3/min at 18-in. Hg vacuum and 150OF,
8-in. I.D. inlet connected to a common
vacuum plenum, equipped with silencer, noise
insulation, and inline prefilter, 200 hp
(4 operating, 2 spares)
f. Transfer stations (U) : Vacuum/pressure ash 320,000 182,100
transfer units to convert from vacuum
conveying medium to pressure conveying
medium, 25 ton/hr/station, each station
contains a primary and secondary cyclone,
a filter, and the vacuum/pressure air-lock
feeder, Ni-Hard or equivalent hardness wear
surfaces, 5 hp (1-hr retention time)
g. Compressors (6): 2,000 aft3/min, 11 psig, 240,000 18,600
200 hp, intake filters, carbon steel body,
silencers and noise insulation for body
portion (4 operating, 2 spares)
(Continued)
106
-------
TABLE 20. (Continued)
Material Labor
Item - Description oost. 1Q82& oost. 1Q82&
h. Silo, solids storage (2): 30-ft diameter x 455,000 257,700
40 ft high, 28,300-ft3 volume, with bin
air fluidizing system, elevated construc-
tion for 11-1/2-ft truck clearance,
rotary star feeders, carbon steel plate,
2 hp
i. Filter, silo bag (2):. Automatic cycling 44,000 25,700
vent filter, 2,436-ft2 bag area, 20 ft x
5.3 ft x 11 ft overall dimensions
j. Fansf bag filter vent (2): 8,000 aft3/min, 16,000 9,100
AP = 6 in. H20, 20-hp motor
k. System control unit (1): Automatic sequence 160,000 91,100
controller for the vacuum inlets and
pressure stations, controls hopper levels,
valve sequencing, alarms, blower operation,
and other system monitoring; includes gauges
for manual readings and override switches
for manual operation
2. Bottom ash sluice transfer system (1);
a. Pump, bottom ash water supply (3): 10,400 1,800
Centrifugal, 255 gpm, 90-ft head,
carbon steel, 10 hp (2 operating,
1 spare)
b. Pump, bottom ash water supply (3); 25,900 4,000
Centrifugal, 1,860 gpm, 115-ft head,
carbon steel, 75 hp (2 operating,
1 spare)
c. Pump, bottom ash water supply (3): 40,600 5,200
Centrifugal, 587 gpm, 577-ft head,
carbqn steel, 150 hp (2 operating,
1 spare)
(Continued)
107
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost. 19.82$ cost, ^ftpj
d. Tank, overflow (1): 18-ft diameter x 11,400 11,000
8 ft high, 11,400 gal, flat bottom,
open top, with an overflow weir 2 ft
below top of tank, 3/8-in. carbon
steel, epoxide-coated interior
e. Pump, bottom ash hopper overflow bin (3): 17,400 2,600
Centrifugal, 550 gpm, 175-ft head, carbon
steel, 40 hp (2 operating, 1 spare)
f. Jet pumpT bottom ash conveyance (4): 4,000 1,600
Jet ejector nozzle assembly and adapter
to bottom ash hopper, 360 gpm, 692-ft
head supply water, Ni-Hard nozzle and
throat construction (2 operating,
2 spares)
g. Sumo pit, sluice (1): Concrete pit 5 ft 2,900 6,300
wide x 5 ft long x 8 ft deep with two
agitator nozzles located in bottom of
bin to prevent settling
h. Pump, bottom ash sluice (3): Centrifugal 108,100 6,200
slurry pumps, 2,550 gpm, 230-ft head,
Ni-Hard liner and impeller, 250 hp (2
operating, 1 spare)
i. Valves, shutoff and crossover (17): Air- 30,400 17,400
operated gate valve, 8-in. I.D. port,
Ni-Hard
J- Slurry pipeline, one-quarter nyl,!? 82,000 29,500
basalt-lined to dewaterine bins, normal
use (1): Pipeline comprising 74, 18-ft-
long sections of flanged, basalt-lined
steel pipe, 8-in. I.D. and 4 basalt-lined
elbows or bends, 8-in. I.D.
(Continued)
108
-------
TABLE 20. (Continued)
Item - Description
Material Labor
cost. 1Q82& cost. 1Q82ife
k. Slurry Pipeline, spare line to
dewatering bins and return waterline
(2): Pipeline comprising 34, 40-ft-
long sections of flanged steel pipe,
8-in. I.D., schedule 80 carbon steel
and 4 hardened elbows or bends, 8-in.
I.D.
1. Bin, bottom ash dewatering (2): Conical-
bottom dewatering bin, 25-ft diameter x
62 ft high, with 24-ft cylindrical section,
18-1/2-ft-high cone, 11,190-ft3 volume,
stainless steel floating decanter and movable
drainpipe, stationary decanter in conical
section, erected for 16-172-ft truck
clearance, carbon steel with stainless
steel decanter drums, 250-ton capacity
m. Settling tank, bottom ash return water
(1): 45-ft diameter x 13 ft deep,
154,800 gal, carbon steel, epoxide-
coated interior, open top
n. Surge tank, bottom ash return water (1):
Water reservoir, 35-ft diameter x 14 ft
deep, 110,000 gal, carbon steel, epoxide-
coated interior, open top
o. Pump, underflow solids recycle (3): Cen-
trifugal, 250 gpm, 100-ft head, Ni-Hard
steel body and impeller, 15 hp (2 operating,
1 spare)
p. Pumpf dewatering bin sump pit (3)« Duplex,
60 gpm, 70-ft head, 5 hp, carbon steel,
neoprene lined (2 operating, 1 spare)
3. Water treatment system for recycle water
alkalinity control (1):
(Continued)
31,200
11,000
200,000
93,600
68,000
48,000
11,300
38,900
27,300
2,300
7,200
2,500
109
-------
TABLE 20. (Continued)
Item -
Description
Material Labor
COSt. 1Q82* fiost., ^fln*
a. Sulfuric acid storage tank for oH 1,900 300
control of water (1): Cylindrical steel
tank, 5-ft, 7-in. diameter x 5 ft, 7 in.
high, 1,000 gal, flat bottom and closed
flat top, carbon steel; all-weather housing
b. Metering pump for sulfuric acid (2): 1f900 600
Positive displacement metering pump,
0.01 to 1 gpm, 0 psig, with flow rate
controlled by a pH controller,
Carpenter 20 alloy or similar corrosion
resistance to 93? sulfuric acid; 0.25 hp
(1 operating, 1 spare)
c. Agitator, treated water (1): Agitator 2,900 400
with 24-in. diameter, nickel-chromium
blade, 5 hp
Total, Area 13 3,192,300 1,143,800
Area 11—Flue Gas Handlinga
1. Fan, flue gas (4): Induced draft, 2,398,200 39,300
455,000 aft3/min, AP = 12 in.
Inconel 625, 1,250-hp motor,
fluid drive
Total, Area 14 2,398,200 39,300
Area 15—Waste Disposalb
1- Landfill site development and construction 1,799,500 231,600
(1): 75-acre landfill site, 1,475-ft square
landfill, 3,213,000-yd3 volume, 30-yr life,
98 ft high at center, 6,046-ft perimeter
ditch to 61,000-ydS catchment basin
(Continued)
110
-------
TABLE 20. (Continued)
Item - Description
2. Wheel loader (1): 5.3-yd3 bucket, diesel
engine
3. Dozer (1): Track type with straight blade,
103-hp diesel engine
4. Compactor (1): Vibratory sheepsfoot
compactor, self-propelled
5. Wheel loader (1): 2.6-yd3 bucket, diesel
engine
6. Water truck (1); Tandem-axle, H-rear-wheel-
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal
cargo tank for diesel fuel and cargo space
for lubricants and other field service
items, including tools
8. Onsite trailer for sanitary facilities and
break room (1): 12-ft-wide x 30-ft-long
mobile home restructured into 2 offices, 1
break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply, and 120-volt electric
supply
9. Onsite water supply and discharge treatment
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
(Continued)
Material Labor
cost. 1Q82J5 cost. 1982$
175,700
78,200
108,000
81,500
27,000
28,200
5,600
21,000
17,200
111
-------
TABLE 20. (Continued)
Material Labor
Item - Description cost. 1Q82& oostr
10. Truck (2); Tandem-axle, 4-rear-wheel-drive 111,000
dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (1 operating, 1 spare), 83.6$ of total
truck costs in this area
Total, Area 15 2,435,700 248,800
a. These fans serve both SOx and particulate removal areas. 67% of total fan
costs is charged to particulate removal for baghouse pressure loss.
b. Except as noted, 83.1$ of total waste disposal costs is charged to ash
disposal.
112
-------
TABLE 21. STEAM SOOTBLOWING AND WATER WASHING REQUIREMENTS
FOR AIR HEATERS OF CASE 2
Case
Standard with-
out SCR
Modified with
SCR
Case
Number of
blowers
2
4
Cycles/ vr
Cycles/day/
blower
3
3
Hr/pyple
Steam
Min/cvcle
20
sootblowlne
Lb Lb
steam/min steam/vr
127 3,492,500
22 175 10,587,500
Water washinc
Gal/
Bin/ heater
Psi* Gal/vr
Additional
Ib
7,095,000
Additional
sral/vr
Standard with-
out SCR
Modified with
SCR
2,440
2,970
150 2,342,400
150 5,702,400 3,360,000
-------
Area 5 - Waste Disposal—
The waste disposal area description is identical to that of case 1. The
spent catalyst volume is slightly larger because of the larger volume of
catalyst used in case 2.
S02 Control
Processing areas 6 through 11 describe the spray dryer FGD process.
Notice that there is no processing area for particulate collection in the
S02 control process. Differentiation of costs and functions of fabric
filter particulate control between SC>2 particulate collection and fly ash
collection is impractical; therefore, all baghouse costs are included in the
particulate control section.
Area 6 - Materials Handling--
The materials-handling area consists of the equipment to unload pebble
quicklime from trucks or railcars, transfer it to concrete storage silos at
the FGD system, and transfer it from the silos to the feed preparation area.
The unloading and conveying system is designed for 100 ton/hr and the silos
have a 30-day capacity. The lime is transferred by closed conveyor and loaded
into the silos and feed bin by bucket elevator.
Area 7 - Feed Preparation—
The feed preparation area consists- of equipment to slake the lime and
prepare and meter the absorbent slurry to the spray dryers, along with other
auxiliary equipment. The lime is metered to two parallel trains of ball mill
slakers equipped with spiral classifiers and oversized particle recycle. The
slaked lime slurry from both slakers is combined in an agitated slaker
receiver tank as a 20$ solids slurry. This slurry is combined with the 40?
solids slurry from the lime particulate recycle area (area 10) in an 8-hour
capacity combined feed tank, from which the combined slurry is metered to the
spray dryer atomizers. The feed preparation area also meters dilution water
to the atomizers for feed concentration control and emergency quench pumps to
protect the baghouse in case of interruptions to the feed slurry addition.
Area 8 - Flue Gas Handling—
The flue gas-handling area contains the same general equipment and has
the same function as the flue gas handling area of case 1. It consists of the
incremental increase in the size of the boiler ID fan to compensate for the Cl-
inch H20 pressure drop in the FGD system (the remaining incremental increase
is prorated to processing area 14) and the FGD system ductwork. The ductwork
consists of the spray dryer inlet plenum, the ducts connecting the spray
dryers to the inlet plenum and to the baghouse plenum, the individual spray
dryer bypass ducts, and the two emergency bypass ducts with a combined
capacity of 50$ of the scrubbed flue gas that connect the inlet plenum with
the stack plenum.
Area 9 - S02 Absorption—
This area consists of the four spray dryers and their atomizer systems.
Each spray dryer is a 46-foot-diameter carbon steel vessel with a total height
of 87 feet, including a 60-degree conical bottom section. A single 700-hp
114
-------
rotary atomizer is mounted at the top of each spray dryer. The flue gas
enters through a gas distribution manifold around the atomizer that imparts a
swirling moment to the gas. The flue gas leaves the spray dryer through a
downward-opening horizontal duct in the conical bottom. Larger particles
collect in the conical bottom and are removed through an air lock. The spray
dryers are designed for an overall excess S02 removal capacity of 33$ so
that three can meet the 862 removal requirements; normally, however, all
four are operated to reduce the overall pressure drop.
The spray dryers are designed for an S02 removal efficiency of 73% at a
stoichiometry of 0.79 mol Ca(OH)2/mol S02 entering, a 10-second resi-
dence time, and an 1 8°F approach to saturation. At an entering flue gas
temperature of 300°F, this produces an outlet temperature of 154°F. A
bypass for 12$ of the flue gas is provided for each spray dryer to ensure dry
operation of the baghouse. The gas entering the baghouse, which consists of
the treated and bypassed gas, has a temperature of 170°F.
Area 10 - Lime Particulate Recycle—
This area consists of equipment to convey, store, and reslurry particu-
late matter from the bottom of the spray dryers and some of the particulate
matter collected in the baghouse. Each spray dryer hopper has an air lock and
a drag chain conveyor that carries the solids to a common belt conveyor. The
conveyor carries the solids to the reslurry tank at 34,100 Ib/hr. A portion
of the solids from the baghouse is pneumatic-pressure conveyed to the solids
recycle silos and metered at a rate of 61,400 Ib/hr to the recycle slurry
tank. The total recycle rate is 95,500 Ib/hr of solids as a 40$ solids
slurry. This corresponds to a 1 to 27.8 ratio of fresh lime to recycle
solids.
Area 11 - Waste Disposal—
The FGD waste, collected commingled with the fly ash in the baghouse, is
transported and disposed of in the common landfill as described in the
particulate control section. Costs are prorated from the total transportation
and disposal costs on the basis of volume.
Particulate Control
Processing areas 12 through 15 describe the bottom ash, fly ash, and fly
ash - FGD solids control processes.
Area 12 - Particulate Removal and Storage—
The baghouse; all bottom ash, fly ash, and baghouse hoppers; the bottom
ash transport and dewatering system; the pneumatic particulate transfer
system; and the particulate storage silos are included in this area. Two
baghouses in parallel are used, each 204 feet long, 58 feet wide, and 70 feet
high (inside dimensions). Each baghouse is designed for a flow rate of
440,100 aft3/min and has a gross air-to-cloth ratio of 1.76 aft3/min/ft2
and a net air-to-cloth ratio of 2.2 at a pressure drop of 5 inches H20.
Each baghouse has 14 compartments with 375 bags per compartment. The design
removal efficiency is 99.88$.
115
-------
There are 96 individual double-vee hoppers in which dry partioulate
matter is collected: 56 on the baghouse, 10 on the economizer, 10 on the air
heaters, and 20 on the SCR reactors. The description is the same as the
description in case 1 (area 13).
Area 13 - Particulate Transfer —
The vacuum-pressure pneumatic system to remove the fly ash and fly ash -
FGD, solids from the hoppers and transfer it to storage silos and the bottom
ash transfer and dewatering system are included in this area. The bottom ash
system is identical in function to that of case 1 (area 15), differing only in
size because of the smaller quantity of ash. The fly ash and fly ash - FGD
particulates are transported with a combined vacuum-pressure pneumatic system
because of the large number of hoppers involved and the resulting longer
transport distances. The particulates are collected from the 192 hopper
outlets with a vacuum system and transported to 4 transfer stations. From the
transfer stations, they are transported by a pressure pneumatic system to two
elevated carbon steel storage silos 30 feet in diameter and 40 feet high.
Area 14 - Flue Gas Handling —
This area consists of the plenum that distributes flue gas to the bag-
houses, the four ducts connecting the baghouses to the stack, and four ID
booster fans to compensate for the 12-inch I^O pressure drop through the FGD
system and the baghouses (costs are prorated between the two systems based on
an 8-inch 1^0 pressure drop for the baghouses and their associated
ductwork) .
Area 15 - Waste Disposal —
Trucking of the combined fly ash - FGD waste and bottom ash to the land-
fill and landfill operations are included in this area. The costs are pro-
rated based on the volume of spent SCR process catalyst, FGD waste, and ash.
CASE 3
Case 3 is based on 0.7$ sulfur western subbituminous coal. It consists
of a hot-side ESP, an SCR NOx control process, and a limestone FGD process
in which natural oxidation produces a 95$ gypsum waste. The flow diagram is
shown in Figure 5, the material balance is shown in Table 22, and the equip-
ment list is shown in Table 23. Each process area is described below with the
exception of those in which the verbal description is similar to those for the
same areas previously described in cases 1 and 2.
Control
The 2-train SCR reactor system is essentially the same as the system in
case 2 except for the differences that result from upstream fly ash removal:
a different equipment layout to accommodate the hot-side ESP, a smaller
catalyst volume because of reduced fly ash fouling, and elimination of fly ash
hoppers on the reactors. Areas 1 through 5 describe the NOX control
process.
116
-------
Figure 5. Case 3 flow diagram.
-------
TABLE 22, CASE 3 MATERIAL BALANCE
1
1
1
4
6
7
8
9
12.
Stream No.
Description
Total stream, Ib/hr
Sft-Vmin (60°F)
Temperature, °F
Pressure, psig
1
Coal to boiler
640,200
2
Combustion
heater
5,765,200
1,273,900
80
3
to boiler
4, 977, 200
1,099,800
i
4
economizer
5,609,200
1,215,300
5
ESP
5,609,200
1,214,300
750
Stream No.
Description
1
2
3
4
5
6
7
8
9
10
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure. psiE
6
Gas to
ammonia
injection
grid
5,576,800
1,215,300
750
Gas with
ammonia to
SCR reactor
5,616,000
1,224,100
747
8 9
Gas to
Gas to inlet
air heater plenum
5,616,000 6,404,000
1,224,200 1,398,300
750 300
1
Spray tower
bypass gas
1,800,200
393,100
300
Stream No.
Description
J Total stream. Ib/hr
2
3 sfrS/m-in rsooFi
4 Temperature, °F
5 Pressure, psig
d
7
8
9
10
11
Gas to
spray tower
4.603.800
1.005.200
300
12
Gas from
spray tower
4,798,000
1.074.000
135
13
Gas to
stack
6,598,200
1.467.100
14
Steam to
dilution
air heater
2,000
298
50
15
Dilution air
to mixer
38,412
8.500
250
J
2
3
't
3
6
7
8
9
10
Stream No.
Description
Total stream, Ib/hr
SftJ/min (60°F)
Temperature, °F
Pressure, psig
16
Ammonia to
mixer
788
300
17
Ammonia-air
mixture to
injection grid
39,200
8,800
18
Fly ash
to storage
silo
32,400
19
Bottom ash
from boiler
48,900
20
Bottom ash
sluice water
to settling
tank
60,500
i
(Continued)
118
-------
TABLE 22. (Continued)
1
2
3
4
5
6
7
8
9
10
Stream No.
Description
Total stream. Ib/hr
Sft^/min (60°F)
Temperature. °F
Pressure, osie
21
Dewatered
to landfill
9.100
22 '23 1 24
s Settling tank ,
Settling tank J solids return i Reagent
surge tank ! bin : tank
42,000 ' 18.500 200
i
|
i
i
i
\
25
water
700
i
2
i
i,
b
6
7
8
9
10
^Stream No.
Description
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, °F
Pressure, psig
26
Water to
bottom ash
sluice
40,700
27 1 28 i 29
! j
Surge tank 1 Recycle
underflow to Fly ash to slurry to
dewatering bins landfill presaturator
2,200 i 32,400 2,580,000
'
30
Makeup water
to spray
tower
205,600
1
2
1
4
5
6
7
8
9
10
Stream No.
Description
Total stream. Ib/hr
Sft-3/m-In r60°Fl
Temperature
Pressure, psig
31
Recycle
slurry
to spray
tower
74,288,800
32 33 34
Clear
liquid to • Clear Thickener
recirculation ' liquid overflow
tank | return return
121,000 ' 126,300 110,800
i
;
'
!
i i
35
Thickener
evaporation
5,600
1
2
3
4
j
6
;
8
9
10
Stream No.
Description
SftJ/min (60°F)
Temperature. °F
Pressure, psia
36
Slurry to
thickener
145 r 700
37 | 38 | 39
1 j
1 |
Clear liquid | Thickener ; Limestone
to wet ball • bottoms to wet ball
mills j to filter mills
5,300 j 29.300 8.000
j |
1 j
;
1
j ;
i t
i
1
I
40
Limestone
slurry to
recirculation
tank
13.300
(Continued)
119
-------
TABLE 22. (Continued)
Description
1
2
1
^
5
f,
7
8
9
1°.
Total stream, Ib/hr
Sft3/min (bO°F)
41
Filtrate
return
15,500
42 ' !
Filter cake
to landfill
13,800
i
;
I
1
2
3
4
5
6
7
a
9
10
1
2
3
4
b
b
/
8
9
10
Description
Total stream, Ib/hr
Sft3/min (60°F)
Temperature, "F
Pressure, psig
Stream No.
Description
Total stream, Ib/hr
SftJ/min (60°F)
Temperature, F
Pressure, psiE
i
I
.
1
J
2
'j
4
3
b
'
9
iu
Stream No.
Description
Total stream, Ib/hr
Sft^/min (60"F)
Temperature, °F
Pressure, psig
1
!
120
-------
TABLE 23. CASE 3 EQUIPMENT LIST
Material Labor
Item - Description _____ coat. 1Q82& cost. 1982&
Area 1 — Ammonia Storage and Injection
1. Compressor. NH^ unloading (2): 14.6 ft3/minf 8,600 2,100
capable of 250 psig suction max. , 5-hp motor,
cast iron body, insulated (1 operating, 1 spare)
2. Tank, NH^ storage (5); Horizontal, 9-ft 169,500 3,900
diameter x 66 ft long, 30,000 gal, 250 psig,
carbon steel
3. Vaporizer. NH^ (50): Carbon steel, 15 kW, 29,800 800
electric resistance heater, 10 per ammonia
storage tank
4. Tapir, aphonia accumulator (1): 281 ft3, 5.5-ft 5,100 5,100
diameter x 10 ft long, carbon steel, insulated
(3 in.), +2.75-ft hemispherical end, 15 psig
design pressure, 180°F design temperature
5. Ammonia absorber (1): 4 ft high x 1.1-ft 400 1,900
diameter, 1.5-ft support, with vent, water
supply, 1/4-in. Cor-Ten
6. Blower, air (3): 4,400 aft3/min, 20 in. H20, 12,500 1,400
20 hp, carbon steel, insulated (2 operating,
1 spare)
7. Heater, dilution air (2): Fin tube steam 26,200 800
heater, 500-ft2 surface area, aluminum
tubes, galvanized cabinet
8. M^or, annonia and dilution air (2): 30-in. 11,600 7,200
diameter x 9.5 ft long, carbon steel
9. Injection grid, NH^ and air (2): 21 ft wide, 63,400 82,600
26 ft high, Cor-Ten pipe and supports
10. Mixing grid. NH^. air, and flue gas (2): 22 ft 13,800 27,000
wide, 22 ft high, Cor-Ten pipe
Total, Area 1 340,900 132,800
(Continued)
121
-------
TABLE 23. (Continued)
Item - Description
Material Labor
cost. 1982& coat, Tqfi
Area 2—Reactor
1. Reactor (2): 49 ft wide x 40 ft
long x 42 ft high, 6-in. mineral wool
insulation; carbon steel housing,
internals, and supports; elevated 20 ft
2. Sootblower, steam (20): 49 ft, retractable,
35-lb/min steam at 86 psig, 1 hp
3. Reactor crane and hoist (2): Electric 2-
speed hoist, 2-ton capacity, 60-ft lift,
grade to access door, 3 hp
4. Reactor hoist (4): Electric single-speed
hoist, 2-ton capacity, access door to inside
reactor, 3 hp
Total, Area 2
2,437,200 2,580,900
540,000 33,100
17,800 600
28,200
1,700
3,023,200 2,616,300
Area 3—Flue Gas-Handling Modificationsa
1. Fan, flue gas (2): Induced draft,
1,031,915 aft3/min, AP = 22 in. H20,
carbon steel, 5,000 hp, fluid drive,
double width, double inlet
107,300
1,300
Total, Area 3
107,300
1,300
Area 4—Air Heater Modificattonab
1. Air heater (2): Vertical inverted, size
32.5, Ljungstrom type,
Hot elements: DN type, 22 gauge, low alloy
corrosion resistant, 26 in.
deep, 186,100-ft2 area
(Continued)
747,000
9,600
122
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost. 1Q82& cost, 1982$
Cold elements: NF type, 3.5-mm spacing, 22
gauge, low alloy corrosion
resistant, 42 in. deep,
359,500-ft2 area
2. Sootblower, steam (2): Retractable, 127- 15,200 900
Ib/min steam at 200 psig
Total, Area M 762,200 10,500
Area 5—Waste Disposal^
1. Landfill site development and construction 20,000 2,500
(1): 80-acre landfill site, 1,533-ft square
landfill, 3,559,000-yd3 volume, 30-yr life,
101 ft high at center, 6,277-ft perimeter
ditch to 66,000-yd3 catchment basin
2. Wheel loader (1): 5.3-yd3 bucket, diesel 1,800
engine
3. Dozer (1): Track type with straight blade, 900
109-hp diesel engine
H. Compactor (1): Vibratory sheepsfoot 1,200
compactor, self-propelled
5. Wheel loader (1): 2.6-yd3 bucket, diesel 800
engine
6. Water truck (1): Tandem-axle, M-rear-wheel- 300
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal 300
cargo tank for diesel fuel and cargo space
for lubricants and other field service items,
including tools
(Continued)
123
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost. 1Q.82& cost, -|9j
8. Onsite trailer for sanitary facilities and 100
break room (1): 12-ft-wide x 30-ft-long
mobile home restructured into 2 offices,
1 break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply, and 120-volt electric
supply
9. Onsite water supply and discharge treatment
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
10. Truck (2): Tandem-axle, 4 rear-wheel- 700
drive dump truck with ash-haul body,
26-yd3 capacity, 56,000-lb suspension,
9 forward speeds, manual transmission,
290-hp diesel engine (1 operating,
1 spare), 0.6? of total truck costs
in this area
Total, Area 5 26,300 2,700
a. Costs shown are additional costs of boiler I.D. fan due to NOx reactor
pressure loss.
b. Costs shown are for modifications and additional equipment necessary for NOx
removal.
c. Except as noted, 0.9? of total waste disposal costs is charged to NOx
removal.
(Continued)
124
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost. 1Q82& cost. 1Q82&
Area 6—Materials Handling
1. Mobile equipment (1): Bucket tractor, 75,900 0
2-1/2-yd3 bucket, storage pile is 52,300
ft3
2. Hopper, reclaim (1): 7-ft diameter x 4-1/4 1,200 800
ft deep x 2-ft bottom, 75 ft3, carbon steel,
60-degree cone bottom
3. Feeder, reclaim (1): Vibrating pan, 3-1/2 hp, 5,500 500
100 ton/hr
4. Dust collectorf limestone reclaim pit (1): 7,800 2,600
Bag filter, polypropylene bag, 2,200 aft3/min,
7.5 hp, reverse jet cleaning, includes
dust hoods
5. Pump, reclaim sump Pit (1): Duplex, 60 gpm, 2,400 800
70-ft head, 5 hp, carbon steel, neoprene
lined
6. Conveyor, limestone reclaim (1): Belt, 30 in. 22,900 1,400
wide x 100 ft long, 2 hp, 100 ton/hr, 105
ft/min
7. Conveyorf limestone reclaim (inclined (1): 60,300 3,700
Belt, 30 in wide x 193 ft long, 40 hp, 15-
degree incline, 50-ft lift, 100 ton/hr,
105 ft/min
8. Elevator, live limestone feed (1): Continuous 57,800 6,700
bucket, 14 in. x 8 in. x 11-3/4 in., 75 hp,
90-ft lift, 100 ton/hr
9. Conveyor, feed (1): Belt, 30 in. wide x 60 ft 20,500 1,400
long, 7.5 hp, 100 ton/hr, 105 ft/min
10. Tripper, feed conveyor (1): 30 ft/min, 1 hp 27,200 9,100
(Continued)
125
-------
TABLE 23- (Continued)
Material Labor
Item - Description cost. 19g2$ oostf iqfc|
11. Btnr crusher feed (3); 13-ft diameter x 21-ft 43,300 24,100
straight side height, 3,100 ft3, covered,
50-degree cone, carbon steel
Total, Area 6 324,800 51,100
Area 7—Feed Preparation
1. Feeder, crusher (3): Weigh belt, 49,600 2,300
14 ft long, 2 hp
2. Crusher (3): Gyratory, 75 hp 297,100 6,500
3. Ball mill, wet (3): Wet, open system, 503,200 61,600
7-ft diameter x 10-1/2 ft long, 113 hp,
2.0 ton/hr (2 operating, 1 spare)
4. Dust collector, ball mill M): Bag filter, 23,300 7,800
polypropylene bag, 2,200 aft3/min, 7.5 hp,
reverse jet cleaning, 2 hoods
5. Tank, mills product (3): 10-ft diameter x 13,700 11,000
10 ft high, 5,500 gal, open top, four 10-in.
baffles, agitator supports, carbon steel,
glass-filled polyester lining
6. Agitator, mills product tank (3): 40-in. 22,900 5,500
diameter, 10 hp, neoprene coated
7. Pump, mills product tank (3): Centrifugal 7,600 2,700
8 gpm, 60-ft head, 1 hp, carbon steel,
neoprene lined (2 operating, 1 spare)
8. Tank, slurry feed (1): 11.5-ft diameter x 5,700 4,700
11.5 ft high, 8,800 gal, open top, four
12-in. baffles, agitator supports, carbon
steel, glass-filled polyester lining
(Continued)
126
-------
TABLE 23- (Continued)
Item - Description
Material Labor
costr 1Q82& cost. 19823
9. Agitator, slurry feed (1): 44-in. diameter,
14 hp, neoprene coated
10. Pump, slurry feed (6): Centrifugal, 6 gpm,
60-ft head, 1/4 hp, carbon steel, neoprene
lined (3 operating, 3 spares)
11,400
14,900
900
5,500
Total, Area 7
949,400
108,500
Area 8—Flue Gas Handling
1. Fan, flue gas (4): Induced draft, 409,800
aft3/min, AP = 7.2 in. H20, 663 hp, fluid
drive, double width, double inlet, Inconel
625
Total, Area 8
2,775,400
2,775,400
48,900
48,900
Area 9—S02 Absorption
1. S02 absorber (4): Spray tower, 40 ft x
37 ft wide x 18-1/2 ft deep, 1/4-in.
carbon steel, neoprene lining,
316 stainless steel grids, FRP chevron
vane entrainment separator, slurry header
and nozzles
2. Tank, recirculation (4): 41.3-ft diameter
x 41.3 ft high, 413,100 gal, open top,
four 41-in.-wide baffles, agitator supports,
carbon steel, glass-filled polyester lining
3. Agitator, recirculation tank (4): 156-in.
diameter, 78 hp, neoprene coated
(Continued)
5,087,500
337,600
421,300
402,300
272,800
138,200
127
-------
TABLE 23. (Continued)
Item - Description
Material Labor
post. 1Q82& cost, J9«
4. Pump, presaturator (8): Centrifugal, 87,200 27,700
1,636 gpm, 100-ft head, 72 hp, carbon
steel, neoprene lined (3 operating, 5 spares)
5. Pump, recirculation (16): Centrifugal, 15,600 1,647,200 148,800
gpm, 100-ft head, 692 hp, carbon steel, neoprene
lined (9 operating, 7 spares)
6. Pump, makeup water (2): Centrifugal, 3,068 30,400 3,400
gpm, 200-ft head, 258 hp, carbon steel
(1 operating, 1 spare)
7. Sootblower (32): Air, fixed 89,500 83,400
Total, Area 9
7,700,700 1,076,600
Area 10—Solids Separation
1. Tank, thickener feed (1): 20.6-ft diameter
x 41.3 ft high, 103,200 gal, open top, four
20-in.-wide baffles, agitator supports,
carbon steel, glass-filled polyester lining
2. Agitator, thickener feed tank (1): 78-in.
diameter, 49 hp, neoprene coated
3. Pumpf thickener feed (2): Centrifugal, 276
gpm, 60-ft head, 7 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
4. Thickener (1): 19-ft diameter x 4.6 ft high,
carbon steel sides, concrete basin, includes
1/4-hp rake motor and mechanism, 272-ft2 area
5. Tank, thickener overfloyf (i\- 11.7-ft diameter
x 4.6 ft high, 3,655 gal, open top, carbon
steel
(Continued)
33,600
33,600
1,700
27,800
37,300 3,100
8,700 3,200
23,600
1,200
128
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost. 1Q.82& oost. 1982$
6. Pump, thickener overflow tank (2): Centrifugal, 9,300 1,000
222 gpm, 75-ft head, 7 hp, carbon steel, neoprene
lined (1 operating, 1 spare)
7. Pump, thickener underflow (2): Centrifugal, 4,800 1,800
44 gpm, 5-ft head, 1/4 hp, carbon steel,
neoprene lined (1 operating, 1 spare)
8. Tank, filter feed (1): 5-ft diameter x 5 ft 1,100 900
high, 723 gal, open top, four 5-in.-wide
baffles, agitator supports, carbon steel,
glass-filled polyester lining
9. Agitator, filter feed tank (1): 19-in. diameter, 900 100
2 hp, neoprene coated
10. PumpT filter feed tank ("3); Centrifugal, 22 gpm, 7.800 2,700
50-ft head, 1 hp, carbon steel, neoprene
lined (2 operating, 1 spare)
11. Filter (3): Rotary vacuum, 3-ft diameter x 163,300 47,600
6-ft face, 7 hp, includes auxiliary equipment,
58-ft2 filtration area (2 operating, 1 spare)
12. Pump, filtrate (4): Centrifugal, 15 gpm, 16,500 1,900
20-ft'head, 1/4 hp, carbon steel, neoprene
lined (2 operating, 2 spares)
13. Tank, filtrate surge (1): 4.4-ft diameter x 500 300
4.4 ft high, 508 gal, open top, carbon steel
14. Pump, filtrate surge tank (2): Centrifugal, 8,400 1,000
31 gpm, 85-ft head, 1 hp, carbon steel,
neoprene lined (1 operating, 1 spare)
15. Convevorf filtrate cake (1): Belt, 30 in. 37,100 3,500
wide x 75-ft-long horizontal, 1-1/2 hp,
7-1/2 ton/hr, 100-ft incline
Total, Area 10 364,600 119,700
(Continued)
129
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost, 1982$ cost. 19
Area 11—Waste Disposals
1. Landfill site development and construction 562,500 69,400
(1): 80-acre landfill site, 1,533-ft square
landfill, 3,559,000-yd3 volume, 30-yr life,
101 ft high at center, 6,277-ft perimeter
ditch to 66,000-yd3 catchment basin
2. Wheel loader (1): 5-3-yd3 bucket, diesel 51,200
engine
3. Dozer (1): Track type with straight blade, 24,200
109-hp diesel engine
H. Compactor (1): Vibratory sheepsfoot 33f700
compactor, self-propelled
5. Wheel loader (1): 2.6-yd3 bucket, diesel 23,700
engine
6. Water truck (1): Tandem-axle, 4-rear-wheel- 7,900
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal 8,900
cargo tank for diesel fuel and cargo space
for lubricants and other field service items,
including tools
8. Onsite trailer for sanitary facilities and 1,600
break room (1): 12-ft-wide x 30-ft-long
mobile home restructured into 2 offices, 1
break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply; and 12-volt electric
supply
(Continued)
130
-------
TABLE 23. (Continued)
Item - Description
Material Labor
cost. 19824 cost. 1982$
19. Onsite water supply and discharge treatment
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
10. Truck (2): Tandem-axle, 4-rear-wheel-drive
dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (1 operating, 1 spare), 24.1$ of
total truck costs in this area
Total, Area 11
6,500
5,300
32,000
752,200
74,700
a. Except as noted, 24.2$ of total waste disposal costs is charged to S02
removal.
(Continued)
131
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost, 1992$ cost. iQftp
Area 12—Partioulate Removal and Storage
1. Electrostatic precipitator. hot side (2): 4,694,500 3,856,500
1,447,150 aft3/min, 651,2l8-ft2 collection area,
1-in. pressure drop, 99-52$ removal efficiency,
450-ft2/kaft3/min SCA, 57.8 ft deep x 85.7 ft
wide x 46.3 ft high (inside dimensions)
2. Hopper, economizer ash (10): Inverted pyramid- 188,200 118,200
type double-V hopper, 15 ft long x 7.7 ft wide
x 7.4 ft deep, thermally isolated design,
constructed of 3/8-in. Cor-Ten plate, 55-
degree valley angle, each hopper has 2 outlets,
232-ft3 volume and 252-ft2 area per hopper
3. Hopper. ESP ash (24): Inverted pyramid-type 738,100 412,300
double-V hopper, 28.6 ft long x 14.5 ft wide
x 13.9 ft deep, constructed of 3/8-in. Cor-Ten
plate, heat traced and insulated, each hopper
has 2 outlets, 55-degree valley angle, 1,545-ft3
volume and 899-ft2 area per hopper, 10-kW
heater
4. Hopper, bottom ash (1): 51 ft long x 10 ft 285,000 164,700
wide x 9-1/2 ft high (inside dimensions),
double-V hopper, center discharge with 2,170-
ft3 capacity for 12-hr ash containment, supported
independently of furnace-boiler, 3/8-in. carbon
steel plate, refractory lined, 4 hydraulically
operated exit doors emptying to 4 double-roll
clinker grinders, 10-in. diameter x 2-ft-long
manganese steel rolls, 60 hp
Total, Area 12 5,905,800 4,551,700
Area 13—Particulate Transfer
1. Pressure pneumattp transfer system fpr fj,y
(1):
(Continued)
132
-------
TABLE 23. (Continued)
Material Labor
Item - Description post. 1Q82& oostf 1982&
a. Conveying linef pressure pneumatic for 53,200 28,800
fIv ashes (1): Pipelines and pipe fittings
for pressure pneumatic conveyance of ash,
35-ton/hr conveying capacity with 1,320-ft
equivalent length system, 8-in. I.D. branch
lines and 10-in. I.D. main lines, nickel-
chromium cast iron pipe with Ni-Hard or
equivalent pipe fittings
b. Pressure feeder, ash and air (68): Materials- 544,000 309,700
handling valve, electrically actuated, air
operated, 10-in. I.D. ash inlet, 10-in. I.D.
ash outlet, cast iron body, stainless steel
slide gate; each assembly includes two
spring-loaded, air-inlet check valves with
cast iron bodies
c. Valve, line segregating (9): Segregating 20,000 11,600
slide valve, electrically actuated, air
operated for on-off control of each branch
conveying line, 10-in. I.D. port, cast
iron body, stainless steel slide gate
d. System control unit (1): Automatic sequence 80,000 45,500
control unit to control the programmed
operation of materials-handling valves, line t
segregating valves, and blowers; includes
gauges for manual reading and override
switches for manual operation
e. Filter, silo bag (2): Automatic cycling vent 36,000 20,600
filter, 1,120-ft2 bag area, 9.3 ft x 5.3 ft x
11 ft overall dimensions
f. Fan, bag filter vent (2): 3f224 aft3/min, 12,800 7,500
.20 psig, 5 hp
g. Compressor, pressure pneumatic transfer system 104,000 9,300
(3): 3,200 aft3/min, 15 psig, 500-hp
motor, carbon steel, with silencers (2
operating, 1 spare)
(Continued)
133
-------
TABLE 23. (Continued)
Material Labor
Item - Description _ cost. 1982& coat,
h. Silof flv ash storage (2): 30-ft diameter x 375,000 212,200
32 ft high, 22,600-ft3 volume, with bin
air fluidizing system, elevated construction
for 11-1/2-ft truck clearance, rotary star
feeders, carbon steel plate, 2 hp
2. Bottom ash sluice transfer system (1):
a. Pump, bottom ash water supply (3): Centrifugal, 10,400 1,800
255 gpm, 90-ft head, carbon steel, 10 hp
(2 operating, 1 spare)
b. Pump, bottom ash water supply (3); Centrifugal, 25,900 4,000
1,860 gpm, 115-ft head, carbon steel, 75 hp
(2 operating, 1 spare)
c. Pump, bottom ash water supply (3): Centrifugal, 40,600 5,200
587 gpm, 577-ft head, carbon steel, 150 hp
(2 operating, 1 spare)
d. Tank, overflow (1): 18-ft diameter x 8 f t 11,400 11,000
high, 11,400 gal flat bottom, open top,
with an overflow weir 2 ft below top of
tank, 3/8-in. carbon steel, epoxide-
coated interior
e. Pump, bottom ash hopper overflow bin (3): 17,400 2,600
Centrifugal, 550 gpm, 175-ft head, carbon
steel, 40 hp (2 operating, 1 spare)
f' Jet pump, bottom ash conveyance (4): Jet 4,000 1,600
ejector nozzle assembly and adapter to
bottom ash hopper, 360 gpm, 692-ft head
supply water, Ni-Hard nozzle and throat
construction (2 operating, 2 spares)
«• Sump pit, sluice (1): Concrete pit, 5 ft wide 2,900 6,300
x 5 ft long x 8 ft deep with two agitator
nozzles located in bottom of bin to prevent
settling
(Continued)
134
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost. 1Q82* cost. 1Q824
h. Pump, bottom ash sluice fj): Centrifugal 108,100 6,200
slurry pumps, 2,550 gpm, 230-ft head,
Ni-Hard liner and impeller, 250 hp (2
operating, 1 spare)
i. Valve, shutoff and crossover (17): Air- 30,400 17,400
operated gate valve, 8-in. I.D. port,
Ni-Hard
j. Slurry Pipeline, one-quarter mile basalt- 82,000 29,500
lined to dewatering binsr normal use (1):
Pipeline comprising 74, 18-ft-long sections
of flanged, basalt-lined steel pipe, 8-in.
I.D. and 4 basalt-lined elbows or bends,
8-in. I.D.
k. Pipelinef spare slurry line to dewatering 31,200 11,000
bins and return waterline (1): Pipeline
comprising 34, 40-ft-long sections of
flanged steel pipe, 8-in. I.D., schedule 80
carbon steel and 4 hardened elbows or bends,
8-in. I.D.
1. Binf bottom ash dewatering (2): Conical- 200,000 93,600
bottom dewatering bin, 25-ft diameter x
62 ft high, with 2-ft cylindrical section,
18-1/2-ft-high cone* 11,190-ft3 volume, .
stainless steel floating decanter and
movable drainpipe, stationary decanter in
conical section, erected for 16-1/2-ft
truck clearance, carbon steel with stainless
steel decanter drums, 250-ton capacity
m. Settling tank, bottom ash return water (1): 68,000 38,900
45-ft diameter x 13 ft deep, 154,800 gal,
carbon steel, epoxide-coated interior,
open top
(Continued)
135
-------
TABLE 23. (Continued)
Item - Description
Material Labor
post. 1Q82& cost,
n. Surge tank, bottom ash return water (1):
Water reservoir, 35-ft diameter x 14 ft
deep, 110,000 gal, carbon steel, epoxlde-
coated interior, open top
o. Pump, underflow solids recycle (3):
Centrifugal, 250 gpm, 100-ft head, Ni-Hard
steel body and impeller, 15 hp (2 operating,
1 spare)
p. Pump, dewatering bin sump pit (3)-
Duplex, 60 gpm, 70-ft head, 5 hp,
carbon steel, neoprene lined
(2 operating, 1 spare)
3. Water treatment system for recycle water
alkalinity control (1):
a. Storage tank, sulfuric acid, for pH control
of water (1): Cylindrical steel tank, 5-ft,
7-in. diameter x 5 ft, 7 in. high, 1,000 gal,
flat bottom and closed flat top, carbon
steel; all-weather housing
b. Metering pump, sulfuric acid (2):
Positive displacement metering pump, 0.01
to 1 gpm, 0 psig, with flow rate controlled
by a pH controller, Carpenter 20 alloy or
similar corrosion resistance to 93%
sulfuric acid, 0.25 hp (1 operating, 1 spare)
c. Agitator, treated water (1): Agitator
with 24-in. diameter nickel-chromium
blade, 5 hp
48,000
11,300
7,200
1,900
1,900
2,900
Total, Area 13
1,930,500
27,300
2,300
2,500
300
600
400
907,700
(Continued)
136
-------
TABLE 23. (Continued)
Jtem - Description
Material Labor
post. 1Q82& cost. 1Q82&
Area 14—Flue Gas-Handling Modlfloatlonaa
1. Fan, flue gas (2): Induced draft, 1,031,915
aft3/min, AP = 22 in. H20, carbon steel,
5iOOO-hp motor, fluid drive, double width,
double inlet
30,700
400
Total, Area
30,700
400
Area 15—Waste Disoosalb
1. Landfill site development and construction
(1): 80-acre landfill site, 1,533-ft square
landfill, 3,559,000-yd3 volume, 30-yr life,
101 ft high at center, 6,277-ft perimeter
ditch to 66,000-yd3 catchment basin
2. Wheel loader (1): 5.3-yd3 bucket, diesel
engine
3. Dozer (1): Track type with straight blade,
109-hp diesel engine
4. Compactor (1): Vibratory sheepsfoot
compactor, self-propelled
5. Wheel loader (1): 2.6-yd3 bucket, diesel
engine
6. Water truck (1): Tandem-axle, 4-rear-wheel-
drive tank truck with spray nozzle boom
attachment, and pumping system, 1,500-gal
fiberglass tank, 130-hp diesel engine
7. Service truck (1): Wrecker rig with 500-gal
cargo tank for diesel fuel and cargo space
for lubricants and other field service
items, including tools
(Continued)
1,743,400
215,200
158,600
75,100
104,400
73,600
24,400
27,600
137
-------
TABLE 23. (Continued)
Material Labor
Item - Description cost. 1982$ cost,
8. Onsite trailer for sanitary facilities and 5,100
break room (1): 12r-ft-wide x 30-ft-long
mobile home restructured into 2 offices, 1
break room, 1 lavatory; propane gas stove
and heater; self-contained portable toilet,
potable water supply, and 120-volt electric
supply
9. Onsite water supply and discharge treatment 20,200 16,500
system (1): Catchment basin pumps, chemical
addition tanks and pumps, water supply well,
tank, and pumps
10. Truck (2); Tandem-axle, 4-rear-wheel-drive 100,100
dump truck with ash-haul body, 26-yd3
capacity, 56,000-lb suspension, 9 forward
speeds, manual transmission, 290-hp diesel
engine (1 operating, 1 spare), 75.3? of
total truck costs in this area
Total, Area 15 2,332,500 231,700
a. Costs shown are additional costs of boiler I.D. fan due to ESP pressure loss.
b. Except as noted, 7^.9$ of total waste disposal costs is charged to ash
removal.
138
-------
Area 1 - Ammonia Storage and Handling—
This area includes the equipment to receive, store, and inject the
ammonia-air mixture into the flue gas. It is identical in design and size to
the system in area 1 of case 2 except for the injection and mixing grid
configurations which conform to a different inlet duct configuration.
Area 2 - Reactor—
The two reactors are similar in design to the reactors in case 2 but are
49 by 40 feet in cross section (compared with 53 by 37 feet in case 2) and 42
feet high (compared with 43 feet in case 2). The catalyst volume is 27,486
ft3 and the space velocity is 2,520 hr"1, an 8% smaller catalyst volume
and a 7$ larger space velocity than case 2 made possible by the absence of fly
ash from the flue gas. The only other difference is that the reactors in
case 3 do not require ash hopper bottoms.
Area 3 - Flue Gas Handling—
This area consists of the ductwork associated with the NOX control
process, as described in area 3 for case 1, and the incremental increase in
the boiler ID fan size to compensate for the 7-inch H20 pressure drop in the
reactors and ducts.
Area 4 - Air Heater Modifications—
The same air heater modifications described in area 4 of cases 1 and 2
are made, but the absence of fly ash allows a lesser increase in element area.
Also, water washing frequency is increased since there is no fly ash to aid
removal of ammonia salt deposits (through a scouring action). The additional
sootblowing and water washing requirements are shown in Table 24.
Area 5 - Waste Disposal—
The waste disposal area description is identical to that of case 1. The
spent catalyst volume is smaller because of the smaller volume of catalyst
used in case 3•
S02 Control
Processing areas 6 through 11 describe the limestone FGD process. In
most areas, the process is similar to the description of the FGD process in
case 1. The primary differences are in size—related to the different flue
gas volumes and S02 content—and in the absence of forced oxidation.
Area 6 - Materials Handling—
The equipment necessary to store, retrieve, and supply limestone to the
FGD feed preparation area is included in this area. In contrast to the high-
sulfur coal case in case 1, which requires 27 ton/hr of limestone feed, this
case requires only 4 ton/hr. Because of this, all deliveries are assumed to
be by truck, and railcar unloading facilities are not included. The trucks
are assumed to dump directly to the storage pile over the reclaim hopper. The
reclaim system and the conveying system that transport the limestone to the
feed preparation area are the same as those for case 1 except that only one
reclaim hopper is used rather than two.
139
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TABLE 24. STEAM SOOTBLOWING AND WATER WASHING REQUIREMENTS
FOR AIR HEATERS OF CASE 3
Case
Standard with-
out SCR
Modified with
SCR
Case
Number of
blowers
2
4
Cvcles/vr
Cycles/day/
blower
3
3
Hr/cvcle
Steam
Min/cvcle
20
sootblowins:
Lb
steam/ min
127
21 175
Water washing
Gal/
min/heater
Psic
Lb
steam/ vr
3,492,500
10,106,250
Gal/vr
Additional
Ib
steam/ vr
6,613,750
Additional
eal/vr
Standard with-
out SCR
Modified with
SCR
2,440
2,680
150
2,342,400
150 10,291,200 7,948,800
-------
Area 7 - Feed Preparation—
The limestone is crushed and wet ball milled to a 40$ solids slurry with
a particle size of 90$ minus 325 mesh in this area. The same equipment as
used in area 7 of case 1 is used—including two operating trains and one spare
train of crushers and ball mills—but the equipment size is smaller.
Area 8 - Flue Gas Handling—
The flue gas-handling area consists of the inlet plenum that supplies the
individual absorber trains, the ductwork of the trains themselves, ID booster
fans in each train, and two bypass ducts that serve both for the normal 28$
operating bypass and for emergency bypass of 50$ of the scrubbed flue gas.
The description is the same as the description of area 8 in case 1.
Area 9 - S02 Absorption—
This area consists of four trains of spray tower absorbers, one of which
is a spare, each 37 by 18.5 feet in plan view and 40 feet high. Except that
there is no forced oxidation—the absorbers drain directly to the recircula-
tion tanks—the description is the same as that of area 9 in case 1. The
absorbers are designed to scrub 72$ of the flue gas at a 90$ removal effi-
ciency using three trains (the remaining flue gas is bypassed). The pre-
saturator L/G ratio is 4 gal/kaft3 and the absorber L/G ratio is 115
gal/kaft3, the superficial gas velocity is 10 ft/sec, and the stoichiometry
is 1.4 mols CaCOg/mol S02 + 2HC1 absorbed.
Reheat
Because 28$ of the flue gas bypasses the absorbers and is recombined with
the flue gas in the stack plenum, producing a stack temperature of 175°F, no
reheat is required.
Area 10 - Solids Separation—
In this area, the bleedstreams from the absorbers—consisting of an 8$
solid slurry, 95$ of which is gypsum—are thickened to 40$ solids and filtered
to 85$ solids. Except for the size of the equipment (the thickener is 19 feet
in diameter instead of 41 and the filters are 3 feet in diameter and 6 feet
long instead of 8 feet and 14 feet, for example), the description of this area
is the same as that of area 12 in case 1.
Area 11 - Waste Disposal—
The waste is trucked to the common landfill. Except for the reduction in
equipment size and number because of the smaller volume of waste, the descrip-
tion is the same as that for area 13 in case 1.
Particulate Control
Areas 12 to 15 describe the particulate control processes.
Area 12 - Particulate Removal and Storage—
This area consists of the hot-side ESPs and all hoppers associated with
ash collection. Two parallel ESPs are used, each 58 feet long, 86 feet wide,
and 46 feet high with an SCR of 450 ft2/kaft3/min and a removal efficiency
141
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of 99.5?. There are 34 double-vee ash hoppers, 10 on the economizer and 24 on
the ESPs (there are no ash hoppers on the SCR reactors or air heaters). The
description of these hoppers and of the bottom ash hopper is the same as that
for area 14 of case 1.
Area 13 - Particulate Transfer—
This area consists of the equipment to remove the ash from the hoppers,
dewater the bottom ash, and store the fly ash. The bottom ash system descrip-
tion is the same as that for area 15 of case 1. A pressure pneumatic system
similar to that described for area 15 of case 1 is used except that there are
fewer hoppers, and thus fewer transfer lines, and the ash storage silos are
smaller.
Area 14 - Flue Gas Handling—
This area includes the incremental increase in the boiler ID fan to
compensate for the 2-inch 1^0 pressure drop in the ESPs and related ductwork
and the ductwork connecting the ESPs to the boiler and NOX control system.
Area 15 - Waste Disposal—
The ash is trucked to the common landfill as described in area 17 of
case 1.
142
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RESULTS
Three cases, each composed of processes providing a system for NOX,
and particulate matter (including bottom ash) control, serve as the
basis of the economic evaluation:
Case 1: 3.5$ sulfur coal - SCR reactor - cold-side ESP - limestone FGD
Case 2: 0.7$ sulfur coal - SCR reactor - spray dryer FGD - baghouse
Case 3: 0.7$ sulfur coal - hot-side ESP - SCR reactor - limestone FGD
Capital investments in 1984 dollars and first-year and levelized annual
revenue requirements in 1984 dollars were determined for each process. Both
annual revenue requirements contain levelized capital charges; levelized
annual revenue requirements also contain levelized operating and maintenance
costs. The levelizing factor consists of an annual 10$ discount rate and an
annual 6$ inflation rate. In situations in which the same equipment or func-
tion serves more than one process (as in waste disposal and flue gas handling,
for example), the costs are prorated between the processes when possible.
The base cases are systems for 500-MW power units, which are described in
the systems estimated section. Case variations of these systems were also
evaluated to illustrate the effects of different catalyst lives, NOX reduc-
tion levels, and ammonia prices on the cost of NOX control. In addition,
the economics of 200-MW and 1,000-MW systems were determined. These differ
from the systems described in the systems estimated section primarily in size
and in the number of trains.
It is essential in assessing and comparing the costs of the three systems
as a whole, the three processes that compose them, and the component costs of
the processes to consider both the type of coal and the interactions created
by the particular combinations of processes, both of which have important
economic effects. The subbituminous coal contains 80$ less sulfur than the
bituminous coal and requires removal of 85$ less S02 to meet the 1979 NSPS.
In addition, for the same power output, it produces 17$ more flue gas and
about 35$ less fly ash and bottom ash than the bituminous coal.
These differences in coal properties bear strongly on the types of
processes used for S02 and particulate control. Up to this time at least,
hot-side ESPs and spray dryer FGD would be atypical of high-sulfur coal
applications and cold-side ESPs, perhaps less so of low-sulfur coal applica-
tions. The combination of individual processes in one emission control system
also creates interactions that have important economic effects—the use of
143
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spray dryer FGD, for example, combines 803 and fly ash control in a way that
makes an assessment of some of the separate functions impossible. With the
choice of process determined, at least in part, by the type of coal, and the
costs associated with individual processes influenced by other processes in
the system, economic comparisons on a process-by-process basis must be
interpreted with care.
The capital investments and annual revenue requirements for each of the
processes and for each of the systems evaluated are shown in the appendix.
The same results are summarized in Tables 25 through 28. Detailed cost break-
downs of the three base cases, the case variations, and the energy require-
ments of the base cases are discussed below.
TABLE 25. SUMMARY OF CAPITAL INVESTMENTS IN M$a
Capital investment, mid-1Q82 i
NOX
S02
Particulate
Total
Base case, 500 MW, 80$ NOX
removal
Case 1 41.9 101.8
Case 2 50.1 54.0
Case 3 48.1 69.4
Case variation, 200 MW, 80$
NOx removal
Case 1 20.6 58.2
Case 2 24.2 31.7
Case 3 24.3 41.4
Case variation, 1,000 MW, 80$
NOx removal
Case 1 77.7 175.7
Case 2 94.8 97.4
Case 3 91.2 121.1
Case variation, 500 MW, 90$
NOx removal
Case 1 48.2 101.9
Case 2 55.5 54.0
Case 3 53-9 69.4
42.9
62.6
53.5
22.6
31.4
27.8
73-3
110.7
94.6
42.9
62.7
53.5
186.6
166.7
171.0
101.5
87-3
93.5
326.6
302.9
306.9
193.0
172.2
176.8
a.
All values have been rounded; therefore, totals do not necessarily
correspond to the sum of the individual values indicated.
144
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TABLE 26. SUMMARY OF CAPITAL INVESTMENTS IN $/kWa
Capital investment, mid-1 Q82 &
$/kW
NOX
SC-2
Partioulate Total
Base case, 500 MW, 80$ NOX
removal
Case 1 83.7 203.7
Case 2 100.2 108.0
Case 3 96.1 138.7
Case variation, 200 MW, 80$
NOx removal
Case 1 103-1 291.0
Case 2 121.0 158.3
Case 3 121.6 206.9
Case variation, 1,000 MW, 80$
NOx removal
Case 1 77.7 175.7
Case 2 94.8 97.4
Case 3 91.2 121.1
Case variation, 500 MW, 90$
NOx removal
85.8
125.3
107.1
113.2
157.2
139.0
73.3
110.7
94.6
373.2
333.4
342.0
507.3
436.6
467.5
326.6
302.9
306.9
Case 1
Case 2
Case 3
96.4
111.0
107.8
203.8
108.0
138.8
85.8
125.4
107.1
386.0
344.3
353.6
a. All values have been rounded; therefore, totals do not necessarily
correspond to the sum of the individual values indicated.
BASE CASE COMPARISONS
A breakdown of the capital investment and annual revenue requirements for
the base cases illustrates the relative economic importance of each of the
processes and the importance of the different cost elements in each of the
processes. When equipment or a function serves more than one process, the
costs are prorated between the processes if a definable relationship exists:
fan capital investment and operating costs are prorated on the basis of the
pressure loss in each process; waste disposal costs and waste disposal area
land costs are prorated on the basis of waste volume. The baghouse costs are
not prorated because the size is largely determined by the flue gas rate.
145
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TABLE 27. SUMMARY OF ANNUAL REVENUE REQUIREMENTS IN M$'
Annual revenue reauirements
First vear
Base case, 500 MW, 80$ NOX
removal
Case 1
Case 2
Case 3
Case variation, 200 MW, 80$ NOX
removal
Case 1
Case 2
Case 3
Case variation, 1,000 MW, 80$
NOx removal
Case 1
Case 2
Case 3
Case variation, 500 MW, 90$ NOx
removal
Case 1
Case 2
Case 3
NOX
21 .9
26.5
21.7
9.7
11.6
11.1
11.5
51.2
17.9
26.1
30.1
28.6
S02
28.8
12.7
18.0
16.3
7.6
11.0
18.8
22.2
30.3
28.8
12.7
18.0
Mi
Particulate
9.8
11.1
12.1
5.2
7.7
6.6
16.1
21.5
20.5
9.8
11.1
12.1
Total
60.1
53-6
51.8
31.2
26.8
28.7
106.1
97.9
98.7
61.6
57.2
58.6
NOx
35.8
13.5
10.1
15.6
18.7
17.8
68.1
81.2
78.1
12.9
19.5
16.8
. 1Q81 i
Levelized
S02
11.0
16.9
21.9
23.1
10.1
15.3
69.2
29.2
11.1
11.0
16.9
21.9
Mi
Particulate
12.8
19.0
15.8
6.9
10.1
8.8
20.9
31.8
26.1
12.8
19.0
15.8
Total
89.7
79.1
81.0
15.6
39.2
11.9
158.2
115.1
116.3
96.7
85.1
87.5
a. All values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual
values indicated.
-------
TABLE 28. SUMMARY OF ANNUAL REVENUE REQUIREMENTS IN MILLS/KWHa
Annual revenue reauirements. 1Q84 $
Mills/kWh
Base case, 500 MW, 80$ NOX
removal
Case 1
Case 2
Case 3
Case variation, 200 MW, 80$ NOx
removal
Case 1
Case 2
Case 3
Case variation, 1,000 MW, 80$
NOx removal
Case 1
Case 2
Case 3
Case variation, 500 MW, 90$ NOX
removal
Case 1
Case 2
Case 3
NOX
8.0
9.6
9.0
8.8
10.6
10.1
7.5
9.3
8.7
9.5
10.9
10.4
S02
10.5
4.6
6.5
14.8
6.9
10.0
8.9
4.0
5.5
10.5
4.6
6.5
First vear
Particulate
3.5
5.2
4.4
4.7
7.0
6.0
2.9
4.5
3.7
3.5
5.2
4.4
Levelized
Total
22.0
19.5
19.9
28.4
24.4
26.1
19.3
17.8
18.0
23.5
20.8
21.3
NOx
13.0
15.8
14.7
14.2
17.0
16.2
12.4
15.3
14.3
15.6
18.0
17.0
S02
14.9
6.2
9.0
21.0
9.2
13.9
12.6
5.3
7.5
14.9
6.2
9.0
Particulate
4.7
6.9
5.7
6.3
9.4
8.0
3.8
5.8
4.8
4.7
6.9
5.7
Total
32.6
28.9
29-5
41.5
35.7
38.1
28.8
26.4
26.6
35.2
31.1
31.8
a. All values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual
values indicated.
-------
Capital Investment
The base case capital investments by area are shown in Table 29 and are
summarized in Figure 6. Those components of indirect capital investment and
other capital investment that are determined indirectly, as functions of the
total process capital, for example, are listed as a sum identified as "other."
For case 1 (3.5$ sulfur coal, SCR, limestone FGD, and cold-side ESP), the
total capital investment is $187 million, of which NOX and particulate
control accounts for about 22$ each and S02 control accounts for about 55%.
For case 2 (0.7$ sulfur coal, SCR, spray dryer FGD, and baghouse), the total
capital investment is $167 million with NOX control accounting for 30$;
S02 control, 32$; and particulate control, 38$. In this case, however,
S02 particulate collection is included in the total particulate collection
costs rather than S02 control costs. For case 3 (0.7$ sulfur coal, hot-side
ESP, SCR, and limestone FGD), the total capital investment is $171 million
with NOX control accounting for 28$; S02 control, 40$; and particulate
control, 32$.
Nitrogen Oxides Control—
For NOX control, the most important capital cost is the initial
catalyst charge, which is almost one-third of the total capital investment.
Most of the remaining capital costs are for the reactor and the associated
internal and external catalyst supports and handling system and for the incre-
mental fan cost and flue gas ductwork associated with flue gas handling. The
ammonia storage and injection system constitutes the fourth largest capital
cost. The remaining capital costs—air heater modification, waste disposal
(of spent catalyst), land, and royalties—are relatively minor. Since the
same NOX control process is used in all three cases, the relationship of the
cost elements remains the same in each case.
Most of the capital costs are directly related to the flue gas volume and
to a lesser extent, the presence of fly ash. This is particularly true of the
major cost areas: catalyst, reactor, and flue gas handling. As a result, the
total capital investment for NOX control in case 1 is $42 million, while for
case 2, it is $50 million and for case 3 it is $48 million because of the
larger flue gas volume in cases 2 and 3 and the absence of fly ash in case 3-
If, however, the costs are expressed in terms of flue gas volume, the capital
investments for cases 1, 2, and 3 are 18.6, 17-3, and 16.6 $/aft3/min,
respectively, making the case 1 process the most expensive on this basis.
Because of the low pressure drop in the system, incremental ID fan costs
are minor. About 90$ of the flue gas-handling costs is for ductwork. The
ductwork costs are particularly high in case 3 because of the presence of the
hot-side ESP.
Air heater modifications to deal with salt deposits caused by ammonia
breakthrough are a minor cost element. Most are associated with the increase
in size, the more tightly packed elements, and the use of thicker and more
corrosion-resistant elements. Since air heaters are manufactured in incre-
mental sizes, the costs are not directly proportional to the flue gas volumes.
148
-------
TABLE 29. BASE CASE CAPITAL INVESTMENT COMPARISON
Case 1 . ki
Process capital
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Materials handling
Feed preparation
S02 absorption
Oxidation
Reheat
Solids separation
Lime particulate recycle
Particulate removal and
storage
Particulate transfer
Total process capital,
k$
Other Capital Investment
Waste disposal direct
investment
Land
Catalyst
Royalty
Othera
Total
Total, $/kWb
NOX
1,314
7,829
3,843
819
13,805
19
10
12,028
463
15,530
41,855
83-7
S02
11,343
2,528
4,717
20,411
2,677
3,653
3,681
49,010
4,011
458
48,360
101,839
203.7
Particulate
1,311
10,509
5,636
17,456
3,344
377
21,710
42,887
85.8
Total
1,314
7,829
16,497
819
2,528
4,717
20,411
2,677
3,653
3,681
10,509
5,636
80,271
7,374
845
12,028
463
85,600
4
186,581
373.2
NOX
1,328
9,278
4,543
1,220
16,369
34
15
14,678
563
18,431
50,090
100.2
Case 2. ki
S02
7,374
1,132
1,258
12,992
2,140
24,896
527
75
28,478
53,976
108.0
Particulate
4,961
15,446
6,779
27,186
2,749
326
32,388
62,649
125.3
Total
1,328
9,278
16,878
1,220
1,132
1,258
12,992
2,140
15,446
6,779
68,451
3,310
416
14,678
563
79,297
166,715
333.4
NOX
1,297
8,453
5,386
861
15,997
30
15
13,455
563
18,001
48,061
96.1
Case 3. ki
S02
11,175
1,266
2,363
18,070
2,265
35,139
847
113
33,272
69,371
138.7
Particulate
4,290
14,354
4,378
23,022
2,628
313
27,583
53,546
107.1
Total
1,297
8,453
20,851
861
1,266
2,363
18,070
2,265
14,354
4,378
74,158
3,505
441
13,455
563
78,856
170,978
342.0
a. Consists of costs for "services, utilities, and miscellaneous"; all six items of "indirect investment"; "allowance for startup and
modifications"; "interest during construction"; and "working capital"; as listed in the appendix tables.
b. All values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
-------
I >
0
1 — 1
c
CO
•co-
H
!3 O
H
W
M
Cn H O
0 H -3-
^
O
0
CSJ
-
0
c
PC
0
PC
0
PC
PC
PC
PC
PC
PC
PC
NO,
SOz Particulate NOX 502 Particulate NOX 502 Particulate
Case 1
Case 2
Case 3
Figure 6. Base case capital investment (PC = process capital, C = initial catalyst, 0 = other)
-------
The air heater modification costs for case 2 are about 50? higher than for
case 1, while the same costs for case 3, with the same flue gas volume as case
2 but with no fly ash, are only slightly higher than case 1.
The ammonia storage and injection costs are almost the same for all three
cases. The largest cost is for ammonia storage, which is identical for all
cases. The only cost differences result from differences in the injection
grid, which vary with the flue gas duct size and design.
The costs for process control are included in the processing areas with
which they are associated. The total costs for all three cases are about
$650,000, about three-fourths in the reactor area (to monitor oxygen, ammonia,
and NOX) and the remainder in the ammonia storage and injection area.
Sulfur Dioxide Control—
The capital investments for S02 control are $102 million for case 1,
$54 million for case 2, and $69 million for case 3- The capital investment
for case 2, however, does not contain the costs for particulate collection,
which is an essential function of 862 control. Proration of particulate
collection cost is not particularly meaningful because the baghouse size is
largely determined by the required air-to-cloth ratio—that is, by the flue
gas volume rather than the solids rate.
In all three cases, most of the costs are associated with the 862
absorption area (the absorbers and the absorbent liquid system or the spray
dryers) and the flue gas-handling area (fans and ductwork). These two areas
account for 65$ of the process equipment costs in case 1 and about 80$ of the
process equipment costs in cases 2 and 3. The 802 absorption area process
equipment costs for cases 1 and 3—both of which have limestone scrubbers—do
not differ greatly, although case 1 has five trains while case 3 has four
trains. The absorbers in case 3 are larger and the L/G ratio is higher, which
accounts for the absence of a larger cost difference. In case 2, the cost of
the spray dryers themselves is higher than the cost of the absorbers in case 3
($7.8 million versus $5.1 million) but the spray dryers have no liquid recir-
culatlon system while the absorbers in case 3 have about $5 million in tanks,
pumps, and piping associated with them.
The flue gas-handling costs for cases 1 and 3 are similar in spite of the
additional train in case 1 because of the larger flue gas volume in case 3-
The flue gas-handling area costs in case 2 are lower than case 3, largely
because of the lower pressure drop in the spray dryers, which reduces the fan
costs. Also, the fans in case 2 serve as the booster fans for the baghouse,
with the costs prorated between 802 control and particulate control, which
provides some economy of scale.
The nearly 50$ higher capital investment for case 1 as compared with case
3 is almost entirely related to the larger quantities of S02 removed. The
materials-handling (limestone), feed preparation, and solids separation area
costs are roughly two times higher and waste disposal costs are almost five
times higher for case 1 than for case 3. In addition, the S02 removal
151
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requirements in case 1 require full scrubbing; this necessitates steam reheat
of the flue gas, which accounts for nearly 8? of the process capital costs.
Case 1 also requires forced oxidation; this, however, accounts for only 5% of
the process capital cost.
In addition to the lower costs of case 2 in the 863 absorption and flue
gas-handling areas, it has no solids separation (dewatering) area and lower
feed preparation area costs because lime is used, which requires only slaking
while the limestone used in case 3 must be crushed and ball milled. Case 2,
however, has costs associated with waste recycle that are equivalent to the
solids separation area costs of case 3. An accurate comparison of S02
control capital investment in cases 2 and 3, however, must include the costs
of particulate collection, which is discussed in the following section.
Particulate Control—
The capital investments for particulate control are $43 million for case
1, $63 million for case 2, and $54 million for case 3- The process equipment
costs are subdivided into three processing areas: particulate removal and
storage, which consists of the ESPs or baghouses (each of the three base cases
has two identical units); the hoppers that form their bottoms plus all other
ash hoppers on the boiler and SCR reactors; particulate transfer, which
consists of the bottom ash sluicing and dewatering system and the fly ash
pneumatic conveying system and storage silos; and flue gas handling, which
consists of the incremental fan costs and ductwork. Land costs and disposal
site development, both prorated from total waste disposal costs, are also
included in the total capital investment.
In all three cases, the particulate removal and storage area accounts for
about 60% of the total process equipment costs, with the ESPs or baghouses and
their hoppers accounting for most of the area cost. The cold-side ESPs of
case 1 have an installed cost of $5.9 million and the hot-side ESPs of case 3
have an installed cost of $9.8 million. Most of this difference is a result
of the larger flue gas volume in case 3—both in an absolute sense and because
the ESPs in case 3 operate at a higher temperature. The ESPs in case 1 have
an SCA of 500 but process a flue gas volume of 850,000 aft3/min. (An SCA of
500 ft2/kaft3/min was used for case 1 after determining SCA values ranging
from about 450 to over 650 ft2/kaft3/min from several references. Some
reviewers state that an SCA range of 200 to 250 ft2/kaft3/min is adequate
to meet the ash removal required by the ESP in case 1. If an ESP designed
with an SCA of 250 was used, the investment and revenue requirements for
particulate control would be reduced about 15$.) The ESPs in case 3 have an
SCA of 450 but process a flue gas volume of 1,447,000 aft3/min. In addi-
tion, the hot-side ESPs of case 3 are constructed to operate at the more
rigorous conditions created by the higher temperature. The baghouses have an
installed cost of $7.4 million. Much of this cost difference, in comparison
to the ESPs, is due to the large size of the baghouses and the corresponding
larger and more complex hoppers required. The total volume of the baghouses
is 1,656,000 ft3, compared with 276,000 and 458,000 ft3 for the cold-side
and hot-side ESPs.
Particulate transfer process equipment costs are $5.6 million for case 1,
$6.8 million for case 2, and $4.4 million for case 3. Cases 1 and 3 have
152
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similar vacuum pneumatic conveying systems and the cost differences are a
result of the different quantities of ash. Case 2 has a more complicated
pressure-vacuum conveying system, which accounts for most of the cost dif-
ference. These costs do not include transportation of the waste to the
landfill.
Flue gas-handling costs are $1.3 million for case 1, $5.0 million for
case 2, and $4.4 million for case 3- The lower costs for case 1 result from
the smaller absolute volume and lower temperature of the flue gas. In addi-
tion, the costs are higher for case 3 because of the more complicated and
longer duct lengths required for the hot-side ESP. The pressure drops are low
for both ESPs and the incremental fan costs are negligible—$21,000 and
$31,000. In the case of the baghouse, however, fan costs are a major cost
element because of the large pressure drop through the baghouse. For case 2,
the incremental fan costs are $2.4 million, almost one-half of the total flue
gas-handling costs.
Annual Revenue Requirements
The base case annual revenue requirements are shown in Table 30 and
summarized in Figure 7. The first-year annual revenue requirements for case 1
(3.5% sulfur coal, SCR, limestone FGD, and cold-side ESP) are $60 million (22
mills/kWh) with 36$ associated with NOX control, 48$ with S02 control, and
16$ with particulate control. For case 2 (0.7$ sulfur coal, SCR, spray dryer
FGD, and baghouse), the first-year annual revenue requirements are $54 million
(19.5 mills/kWh) with 49$ associated with NOX control, 24$ with S02
control, and 27$ with particulate control. For case 3 (0.7$ sulfur coal, hot-
side ESP, SCR, and limestone FGD), the first-year annual revenue requirements
are $55 million (19.9 mills/kWh) with 45$ associated with NOX control, 33$
with S02 control, and 22$ with particulate control.
The levelized annual revenue requirements are $90 million, $79 million,
and $81 million for cases 1,2, and 3, respectively. For cases 1, 2, and 3,
respectively, 40$, 55$, and 50$ of the total levelized annual revenue require-
ments are associated with NOX control; 46$, 21$, and 31$ with S02 control;
and 14$, 24$, and 19$ with particulate control. The percentage of the total
associated with NOX control is higher because of the higher ratio of
operating and maintenance costs to capital charges for the SCR process (since
the capital charges are levelized in both types of annual revenue require-
ments, levelizing involves only adjustment of the operating and maintenance
costs).
The cost per ton of pollutant removed is presented for the base cases in
Table 31 based on each of first-year and levelized annual revenue require-
ments. A comparison on this basis indicates that NOX control is signifi-
cantly less cost effective than S02 and particulate control. For example,
with first-year annual revenue requirements, the costs in Table 31 range from
about 3,500 $/ton to 4,600 $/ton for NOX control, from about 500 $/ton to
over 1,900 $/ton for S02 control, and from 60 $/ton to 130 $/ton for
particulate control.
153
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TABLE 30. ANNUAL REVENUE REQUIREMENT ELEMENT ANALYSIS FOR BASE CASES
500-MW UNIT WITH 80% NO REMOVAL
x
Direct costs
Ammonia
Catalyst
Lime/limestone
Operating labor and
supervision
Process
Landfill
Steam
Electricity
Fuel
Maintenance
Analysis
Other
Total direct costs, k$
Indirect costs
Overheads
Capital charges
Total first-year annual
revenue requirements
k$
Mills/kWha
Levelized annual
revenue requirements
k$
Mills/kWha
NOx
361
13,899
66
3
51
278
1
586
46
13
15,307
421
6,153
21,881
8.0
35,816
13.0
S02
1,216
658
523
1,369
2,116
162
4,276
101
21
10,181
3,337
11,970
28,788
10.5
41,031
11.9
Case 1
Particulate
230
136
581
135
1,025
6
19
2,132
1 ,018
6,301
9,754
3.5
12,811
4.7
Total
364
13,889
1,216
954
962
1,120
3,005
298
5,887
156
59
28,220
1,776
27,127
60,423
22.0
89,658
32.6
NOX
336
16,962
66
5
65
192
1
695
16
17
18,685
487
7,363
26,535
9.6
43,521
15.8
S02
708
263
83
780
18
1,599
88
16
3,555
1,220
7,934
12,709
4.6
16,940
6.2
Case 2
Particulate
296
435
966
95
1,811
6
36
3,645
1,529
9,209
14,383
5.2
18,967
6.9
—
Total
336
16,962
708
625
523
65
2,238
114
4,105
140
69
25,885
3,236
24,506
53,627
19-5
79,428
28.9
NOX
336
15,549
66
4
63
391
1
679
46
41
17,176
477
7,065
24,718
9.0
40,359
14.7
I
SO 2
186
594
127
1,477
28
3,005
69
19
5,505
2,277
10,198
17,980
6.5
24,875
9.0
lase 3
Particulate
230
393
993
87
1,299
6
36
3,044
1,157
7,871
12,072
4.4
15,794
5-7
— — — —
Total
336
15,549
186
890
524
63
2,861
116
1,983
121
96
25,725
3,911
25,131
54,770
19.9
81 ,028
29-5
a. All values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
-------
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§ *""*
,
|3
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RM
RM
_
u
en
i — i
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cd
C
CC
c
CC
RM
c
CC
4-1
w
>,
iH
ca
4-1
Cfl
t_)
C
CC
RM
RM
CC
r
CC
4-1
tn
^
4J
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O
c
CC
^^^^S^S^S
C
CC
RM
C
CC
NOX S02 Particulate
Case 1
NOX S02 Particulate
Case 2
NOX S02 Particulate
Case 3
Figure 7. Base case annual revenue requirements (CC = capital charges, C = conversion costs,
RM = raw materials).
-------
TABLE 31. COST PER TON OF POLLUTANT REMOVED FOR BASE CASES
500-MW UNIT WITH 80% NOX REMOVAL
Case 1
Case 2
Case 3
NOX
3,^90
4,600
4,280
First
S02
470
1,370
1,930
4/ton.
vear
Particulate
60
130
110
1Q84 4
Levelized
NOX
5,710
7,540
6,990
S02
670
1,820
2,680
Particulate
80
170
140
Nitrogen Oxides Control—
The first-year annual revenue requirements for the NOX control
processes in cases 1, 2, and 3, respectively, are $22 million, $27 million,
and $25 million. In all cases, the catalyst replacement costs are the over-
whelmingly dominant cost elements: over 90$ of the direct costs and two-
thirds of the total annual revenue requirements are for the yearly replacement
of catalyst. Except for this cost, the annual revenue requirements are
modest, appreciably less than the costs for similar cost categories for S02
and particulate control. Maintenance costs are the largest direct cost,
followed by ammonia costs and electricity, but the total of these constitute
less than 10/6 of the total direct costs.
Other costs, such as additional steam for air heater sootblowing and
catalyst disposal, are negligible. Operating costs for the effects of the
process on the air heater operation are for the extra quantities of steam and
electricity used in sootblowing, the extra wash water required, the addi-
tional chemicals required for wash water treatment, and the extra maintenance
(calculated as a percentage of the process capital for air heater modifica-
tions) . Catalyst disposal operating costs are primarily landfill manpower
requirements and maintenance fuel. The sums of these costs as first-year
direct operating costs are shown in Table 32 for all three cases evaluated.
As can be seen, these operating costs are a very insignificant part of the
total annual revenue requirements.
Sulfur Dioxide Control—
The first-year annual revenue requirements for the S02 control
processes are $29 million, $13 million, and $18 million for cases 1, 2, and 3,
respectively. Again, case 2 with the spray dryer does not include costs
associated with operation of the baghouse. Excluding capital charges (which
156
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are proportional to capital investment) and overheads (which are proportional
to the direct costs), the direct costs of the annual revenue requirements
reflect appreciably wider differences in operating costs. The direct costs
are $10.5 million, $3.6 million, and $5.5 million for cases 1, 2, and 3,
respectively. Maintenance costs are the highest element of direct costs in
all three cases, followed again in all three cases, by electricity costs.
Steam for reheating the flue gas is the third largest direct cost (13% of the
total) in case 1, a cost not incurred by cases 2 and 3, which have bypass
reheat. Limestone costs are the fourth largest direct cost for case 1, a
result of the large quantity of sulfur removed. These costs and the remaining
direct costs are all higher than the corresponding costs for cases 2 and 3, a
result of the large quantity of SC>2 removed (as opposed to the removal
efficiency in the absorber itself). This necessitates full scrubbing, and the
accompanying penalty of flue gas reheat requires a large liquid volume and
produces a large volume of waste. In contrast, the low-sulfur applications in
cases 2 and 3 have much lower direct costs. This is particularly true of the
spray dryer process of case 2; with the exception of lime costs, which are 20?
of the total direct costs, it has lower direct costs in every category as
compared with case 3•
TABLE 32. ADDITIONAL AIR HEATER OPERATION AND CATALYST DISPOSAL
COSTS FROM NOX CONTROL
Additional
air heater Catalyst disposal
Case number
1
2
3
©Deration costsa, k$
61
98
105
costs.
5
7
6
k$
a. First-year direct costs, base case conditions.
Particulate Control—
The first-year annual revenue requirements for particulate control are
$10 million, $1*1 million, and $12 million for cases 1, 2, and 3, respectively.
The annual revenue requirements for case 2, however, also include the collec-
tion of the spray dryer FGD solids. Among the direct costs, maintenance costs
are the highest direct cost in all three cases, followed by electricity costs
and labor costs. Maintenance costs are highest for case 2, which are about
15% higher than case 1 and HQ% higher than case 3. Electricity costs are
lowest for case 1 and highest for case 3, while case 2 has only slightly lower
157
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electricity costs than case 3. In cases 1 and 3, the electricity costs are
primarily for operation of the ESPs; in case 2, the electricity costs are
primarily associated with operation of the booster fans. Labor costs do not
differ appreciably, although process labor in case 2 is about 25% higher than
in cases 1 and 3.
ENERGY REQUIREMENTS
The energy consumptions of the base cases, expressed in Btu equivalents,
are shown in Table 33. Almost all of the energy requirements are for elec-
tricity to operate the larger boiler ID fans, booster ID fans, the ESPs and
absorbent liquid pumps in cases 1 and 3, and the particulate transfer systems.
Except in case 1, which has substantial steam requirements for flue gas
reheat, steam requirements are minimal, as are the diesel fuel requirements
for waste disposal. The total energy requirements range from 4.89? of the
boiler capacity for case 1 to 2.31$ of the boiler capacity for case 2. The
NOX control energy requirements are the lowest in all three cases. Most are
for the incremental electricity consumption of the boiler ID fan that compen-
sates for the relatively small pressure loss in the reactors. For SOX
control, cases 1 and 3 have large electricity requirements because of the FGD
booster fans and pumping requirements for the absorbent liquid recirculation
systems. These are similar in both cases. Case 1 has higher electricity
requirements largely because of the larger feed preparation and waste-handling
requirements. The electricity requirements for the spray dryer in case 2 are
lower because there is no liquid recirculation system. Particulate control
energy requirements in cases 1 and 3 are mostly for ESP electricity, which is
substantially lower for the cold-side ESP. In case 2, most of the electricity
is for the booster ID fans that compensate for the relatively high pressure
drop in the baghouse.
CASE VARIATIONS
Case variations were made to evaluate the effects of power unit size, SCR
catalyst life, NOX reduction level, and ammonia costs.
Power Unit Size Case Variation
The capital investments for 200-MW, 500-MW, and 1,000-MW systems shown in
Table 25 are summarized in Figure 8. Compared with the 200-MW systems, the
500-MW systems are 83$ to 91$ higher and the 1,000-MW systems are 222$ to 247$
higher in capital investment. In terms of $/kW, the 1,000-MW systems are
about one-third less expensive, however, because of the economy of scale. The
general relationships of the three cases remain the same at all three power
unit sizes. The rate of capital investment increases with increasing power
unit size and the rate differs slightly, depending on the processes. The rate
of increase is greatest for the NOX control processes (an increase of 275$
to 292$ between the 200-MW and 1,000-MW sizes, as compared with 193$ to 207$
for the S02 control processes and 224$ to 253$ for the particulate control
158
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H
W
>—i
rl
H
i—i
Q-i
U
O
c
PI
O
O
CM
O
O
Case 1
Case 2
J_
_L
_L
_L
Total
FGD
NOX
Particulate
Case 3>
_L
200
600
1,000 200 600
POWER UNIT SIZE, MW
1,000 200
600
1,000
Figure 8. Variation of capital investment with power unit size.
-------
processes) and it is also higher for the spray dryer FGD process and the
baghouse than for the limestone FGD process and ESPs. As a result, the rate
of capital investment increase with size is greatest for case 2. The rate is,
in general, more rapid for costs that depend primarily on the flue gas volume,
for which there is less economy of scale; this is most evident in the NOX
control processes in which the flue gas volume is the primary determinant of
costs.
TABLE 33. COMPARISON OF BASE CASE ENERGY REQUIREMENTS
Percent of
Steam, Electricity, Diesel fuel, power unit,
Case MBtu/hr MBtu/hr MBtu/hr input energy
Case la
NOx
SOx
Particulate
Total
Case 2b
NOx
SOx
Particulate
Total
Case 3b
NOx
SOx
Particulate
Total
3.15
83.79
0.00
86.94
4.00
0.00
0.00
4.00
3.88
0.00
0.00
3.88
12.97
100.20
27.14
140.31
25.40
40.26
49.85
115.51
20.18
76.20
51.22
147.60
0.01
2.65
2.20
4.86
0.02
0.30
1.55
1.87
0.02
0.46
1.41
1.89
0.34
3.93
0.62
4.89
0.56
0.77
0.98
2.31
0.46
1.46
1.00
2.92
Note: Does not include energy requirement represented by raw materials.
a. Based on a 500-MW boiler, a gross heat rate of 9,500 Btu/kWh for
generation of electricity, and a boiler efficiency of 90$ for
generation of steam.
b. Based on a 500-MW boiler, a gross heat rate of 10,500 Btu/kWh for
generation of electricity, and a boiler efficiency of 90? for
generation of steam.
160
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The annual revenue requirements for the same units shown in Table 27 are
summarized in Figure 9. Compared with the 200-MW systems, the 500-MW systems
are 91$ to 100$ higher and the 1,000-MW systems are 241? to 265$ higher, and
there is an approximately one-third reduction in costs in terms of $/kWh. As
with capital investment, the annual revenue requirements retain the same
general relationships at the three power unit sizes and the rates of increase
for the NOX control processes are higher (328$ to 341$ between the 200-MW
and the 1,000-MW sizes, compared with 175$ to 199$ for the S02 control
processes and 210$ to 218$ for the particulate control processes) and the
rates for the spray dryer FGD and baghouse are higher than those of the
limestone FGD systems and ESPs.
•gwo-Year Catalyst Life Case Variation
In the preceding discussions, it has been apparent that the initial and
replacement costs of the catalyst are the dominant cost element of both the
capital investment and annual revenue requirements for NOX control and that
the annual revenue requirements would be greatly affected by a variation from
the assumed 1-year catalyst life. The 1-year life is based on the normal
vendor guarantees at the time this project was initiated. Since then, the
growing body of experience with SCR processes in coal-fired applications
suggests that a longer life—two years or more—is possible. To illustrate
the effect of catalyst life on annual revenue requirements, the annual revenue
requirements for the three 500-MW base cases were determined for a 2-year
catalyst life. The HQ^ control capital investment remains unchanged, as do
the costs for the S02 and particulate control. The only change in NOx
control annual revenue requirements is a reduction in the catalyst cost by
50$— $7.0 million, $8.5 million, and $7.8 million for cases 1, 2, and 3,
respectively. The longer catalyst life reduces the annual revenue require-
ments of NOX control by one-third, as shown in Table 34. The annual revenue
requirements of the overall systems are reduced by 12$ to 16$.
Case 1
Case 2
Case 3
TABLE 3^. THE EFFECT OF CATALYST LIFE ON
ANNUAL REVENUE REQUIREMENTS FOR NOX CONTROL
Annual catalyst
replacement cost. M$
1 -year 2-year
catalyst catalyst
life life
First-year
revenue
reauirements . M$
1-year 2- year
catalyst catalyst
life life
Levelized annual
revenue
requirements . M$
1 -year 2-year
catalyst catalyst
life life
13.9
17.0
15.5
7.0
8.5
7.8
21.9
26.5
24.7
14.9
18.0
16.9
35.8
43.5
40.4
22.7
27.5
25.7
161
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en
H
w
Pi
3
o
w
Csl
w
>
w
o
o
Case 1
Case 2
Total
FGD
NOX
Particulate
Case 3.
200
600
1,000 200 600 1,000 200
POWER UNIT SIZE, MW
600
1,000
Figure 9. Variation of annual revenue requirements with power unit size.
-------
Ninety Percent M?fcr0gen Oxide Reduotion Case Variation
The SCR processes are capable of very high reduction efficiencies of 90$
or greater. However, the reduction rate is dependent on the ammonia addition
rate and the catalyst must be increased disproportionately to prevent exces-
sive breakthrough of ammonia, as well as to obtain the higher reduction effi-
ciency. To evaluate the economic effects of a 90$ reduction in NOX, as
compared with the 80$ used in the other evaluations, the economics of the
three 500-MW cases were determined with 90$ NOX reduction. The results are
summarized in Tables 25 and 27 and the annual revenue requirements for 80$ and
90$ reduction are compared in Figure 10.
The primary differences from the base case conditions are an NHgtNOx
ratio of 0.91:1.0 instead of 0.81:1.0, a 12$ increase, and an increase in
catalyst (based on vendor recommendations) of 22.5$ for case 1, 15.0$ for
case 2, and 18.0$ for case 3. There are also slight increases in the flue gas
volume because of the additional ammonia and air, which have slight effects on
the S(>2 and parti cul ate control processes.
The capital investments of the NOX control processes are increased 11$
to 15$ and the total for the three systems by 3$ to 4$, all of which is a
result of the increase in NOX reduction. Most of the increase in NOX
control capital investment is a result of the increase in the reactor size;
the increase is proportional to the increase in catalyst and the increase in
reactor costs is also proportional to this increase. These account for most
of the capital investment increases.
The first-year annual revenue requirements for the NOX process are
increased 19$, 14$, and 16$ for cases 1, 2, and 3, respectively. Most of the
increase is the result of the additional catalyst replacement cost and the
increase in capital charges. The ammonia costs are increased 12$, which has
little effect on the total annual revenue requirements. The annual revenue
requirements of the other processes are affected little. The effect on the
annual revenue requirements of the overall system of increasing the NOX
reduction from 80$ to 90$ is an increase of 7$ in all three cases.
Price Case Variation
The possibility of increases in the prices of high-priced raw materials
is an economic concern in some emission control processes. The SCR NOX
control process uses such a raw material — ammonia, for which a price of
155 $/ton is used in this study. In this case, however, the costs associated
with the ammonia are a minor element of the annual revenue requirements — less
than 2$ of the total in the 500-MW base cases. Under these conditions,
changes in the price of ammonia would have little effect on the overall cost
of the process, as shown in Table 35, which shows the annual revenue require-
ments for the NOX control processes at an ammonia price of 310 $/ton. The
annual revenue requirements are increased 1.5$ to 1.9$.
163
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o
ro
JUIREMENTS, M$
20 25
«— '
w
p> u~l
S ^
FIRST-YEAR ANNUAL
5 10
o
-
RM
80%
4-1
03
g__j
cd
cd
u
C
CC
90%
4J
CO
i— 1
cd
4J
cd
u
C
CC
RM
90%
80%
Catalyst
C
CC
Catalyst
C
CC
RM
80%
RM
Catalyst
C
CC
9u/£
Catalyst
C
CC
RM
Case 1
Case 2
Case 3
Figure 10. Annual revenue requirements for 80% and 90% NOX reduction (CC = capital charges,
C = conversion costs, RM = raw materials).
-------
TABLE 35. SENSITIVITY OF NOx
CONTROL TO AMMONIA PRICE
Percent change
Levelized annual revenue requirements in revenue
NH3 at $155/ton NH^ at 310 $/ton requirement due
Case number M$/yr Mills/kWh M$/yr Mills/kWh to increased NH^ costs
1 35,816 13.0 36,507 13.3 1.9
2 43,521 15.8 44,159 16.1 1.5
3 40,359 14.7 40,997 14.9 1.6
165
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166
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CONCLUSIONS
The total costs for case 1, based on 3.5% sulfur coal, and cases 2 and 3,
based on 0.7$ sulfur coal, differ less than 15$ in capital investment and
annual revenue requirements in spite of the differing coals and control
processes. This is a result in part of offsetting differences — the much
higher S02 control costs for case 1 are offset by lower fly ash control
costs and a smaller flue gas volume. The costs for the two low-sulfur coal
cases, one with a spray dryer FGD system and baghouse and the other with
limestone FGD and a hot-side ESP, differ only marginally in cost. In the two
low-sulfur coal cases, the low spray dryer FGD costs and the advantage of
combined particulate collection are offset by the higher NOX control costs
and higher baghouse costs. When only the S02 and fly ash control costs are
compared, the spray dryer-baghouse case is 5% lower in capital investment and
12$ lower in annual revenue requirements than the hot-side ESP limestone FGD
case.
The combined emission control processes increase the power plant capital
investment by about 35$ on the average, of which the NOX portion is about
one- third. Based on levelized annual revenue requirements, the average
increase in the cost of power is about 45$, of which the NOX portion is
about one- half.
The energy requirements of 2$ to 5$ of the boiler input_energy are mostly
for S02 and particulate control. For the cases with limestone FGD, S02
control has the highest energy requirements.
The use of flue gas treatment for NOX control, such as the SCR process
in this study, would add significantly to emission control costs. An SCR
process for a 500-MW power plant would have a capital investment of 80 to 100
$/kW and annual revenue requirements of 8 to 9 mills/kWh. The high cost is
largely associated with the catalyst replacement cost, which accounts for 90$
of the direct costs in annual revenue requirements. A 2-year catalyst life
reduces the annual revenue requirements by over one- third, however, so the
costs for NOX control in this study, which are based on a 1-year life, could
be substantially reduced if extended catalyst lives are attained.
Other than catalyst life, the main factor affecting NOx control costs
is the flue gas volume which determines the fan and ductwork costs and the
catalyst volume. Increasing the NOX reduction efficiency from 80$ to 90$
increases the costs by 10$ to 20$, again because of the larger catalyst volume
needed. Ammonia costs have almost no effect on overall costs; doubling the
price of ammonia increases the annual revenue requirements by about 2$.
167
-------
Although the costs of NOg control are in the same general range as
those for S02 and fly ash control, if the processes are compared on the
basis of the pounds of pollutants reduced, the costs for NOX control are 2
to 10 times greater than for SC>2 control and 40 to 60 times greater than for
ash control.
In S(>2 control, the major costs are associated with the absorption area
and flue gas handling (ductwork and fans). These costs do not differ greatly
among the three cases because of offsetting differences—a larger cost for
liquid circulation in the high-sulfur coal case but a larger flue gas volume
in the low-sulfur coal cases, which requires larger equipment and has larger
fan costs. The higher costs for the high-sulfur coal case are in large part
the result of the much larger quantity of sulfur removed: the materials-
handling, waste-handling, and disposal costs are two to five times higher for
the high-sulfur coal case than for the low-sulfur coal case with limestone
FGD.
168
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Washington, D.C.
115. J. D. Ruby and H. Huettenhain, 1981, Western Subbituminous Coals and
Lignite, EPRI CS-1768, Electric Power Research Institute, Palo Alto,
California
116. National Electric Reliability Council, 1980, 1980 Summary of Projected
Peak Demand, Generating Capability, and Fossil Fuel Requirements,
National Electric Reliability Council, Princeton, New Jersey
117. W. L. Anders and R. L. Torstrick, 1981, Computerized Shawnee Lime/
Limestone Scrubbing Model Users Manualf EPA-600/8-81-008, U.S.
Environmental Protection Agency, Washington, D.C.
118. V. W. Uhl, 1979, A Standard Procedure for Cost Analysis of Pollution
Control Operations. Volumes I and II, EPA-600/8-79-0I8a and EPA-600/8-
79-018b, U.S. Environmental Protection Agency, Washington, D.C.
119. The Richardson Rapid System, Process Plant Estimation Standards,
Volumes I, III, and IV, 1978-1979 Edition, Richardson Engineering
Services, Inc., Solano Beach, California
120. EPRI, 1978, Technical Assessment Guidef EPRI PS-866-SR, Special
Report, June 1978, Electric Power Research Institute, Palo Alto,
California
179
-------
121. E. L. Grant and W. G. Ireson, 1970, Principles of Engineering Economy,
Ronald Press, New York
122. P. H. Jeynes, 1968, Profitability and Economic Choicef First Edition,
The Iowa State University Press, Ames, Iowa
180
-------
APPENDIX A
A-l
-------
TABLE A-l. CASE 1, 200-MW, NO REMOVAL CAPITAL INVESTMENT
X
Capital
Investment. k$
Direct Investment
NH3 storage and injection 745
Reactor 3.373
Flue gas handling 2,441
Air heater
Total process capital 7,037
Services, utilities, and miscellaneous 422
Total direct investment excluding waste disposal 7,459
Waste disposal 10
Total direct investment 7, 469
Indirect Investment
Engineering design and supervision 597
Architect and engineering contractor 224
Construction expense 1,343
Contractor fees 448
Contingency 2,014
Waste disposal indirect investment _ j)
Total fixed investment 12,099
Other Capital Investment
Allowance for startup and modifications 1,209
Interest during construction 1,887
Royalties 192
Land 5
Working capital 3113
Catalyst 4.893
Total capital investment 20,628
103.1
Basis: 3.5% sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-2
-------
TABLE A-2. CASE 1, 200-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit Total annual
quantity cost. $ cost. k&
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
/
Total direct costs
Indirect Costs - First Year
959 tons
240 tons
16 tons
8 tons
2,190 man-hr
77 man-hr
6,358 MBtu
1,074 kgal
3,068,548 kWh
201 gal
1,752 man-hr
155
23,558
300
65
15.00
21.00
3-30
0.14
0.037
1.60
21.00
149
5,654
5
5,809
33
2
21
0
114
0
373
580
6,389
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
9.7
15.6
Mills/kWh
8.8
14.2
267
6,656
3,032
9,688
12,553
3,032
15,585
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-3
-------
TABLE A-3. CASE 1, 200-MW, S02 REMOVAL CAPITAL INVESTMENT
Capital
investment. k&
Direct Investment
Materials handling
Feed preparation
Flue gas handling i«oo
S02 absorption 10,880
Oxidation ].|JO
Reheat 1't}^
Solids separation 2,781
Total process capital
Services, utilities, and miscellaneous 1 »629
Total direct investment excluding waste disposal 28,773
Waste disposal 2,0. 6.9
Total direct investment 30,842
Indirect Investment
Engineering design and supervision 2,302
Architect and engineering contractor 863
Construction expense 5,179
Contractor fees 1f726
Contingency 3i884
Waste disposal indirect investment - 756
Total fixed investment 45,552
Other Capital Investment
Allowance for startup and modifications 3>m&
Interest during construction 7f106
Land 256
Working capital 1 . 87.1
Total capital investment 58,203
$/kW 291.0
Basis: 3.5$ sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, B0% SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-4
-------
TABLE A-4. CASE 1, 200-MW, S02 REMOVAL ANNUAL REVENUE REQUIREMENTS
Direct Cost - First Year
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Annual
auantitv
58,400 tons
33,470 man-hr
15,825 man-hr
169,394 MBtu
79,170 kgal
24,564,866 kWh
41,073 gal
3,300 man-hr
Unit
cost, $
8.50
15.00
21.00
3-30
0.14
0.037
1.60
21.00
Total annual
cost, k$
4Q6
496
502
332
559
11
909
66
2,652
63.
5.100
5,596
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs 7,729
Levelized capital charges (14.7$ of total
capital investment) 8.556
Total first-year annual revenue requirements 16,285
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 14,577
Levelized capital charges (14.7$ of total capital
investment) 8,556
Total levelized annual revenue requirements 23,133
MS Mills/kWh
First-year annual revenue requirements 16.3 14.8
Levelized annual revenue requirements 23.1 21.0
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-5
-------
TABLE A-5. CASE 1, 200-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
Direct Investment
Particulate removal and storage
Particulate transfer
Flue gas handling
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
Capital
investment. k$
4, 679
3,356
833
8,868
9,^00
1.730
11,130
752
282
1,692
564
2,538
17,589
Basis: 3-5% sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
-------
TABLE A-6. CASE 1, 200-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Direct Cost - First Year
H2SOH (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and
Annual Unit
quantity cost. &
112 tons 65
6,570 man-hr 15.00
13,218 man-hr 21.00
3,083 kgal 0.14
6,435,402 kWh 0.037
34,308 gal 1.60
200 man-hr 21 .00
maintenance costs
Total annual
cost. kit
1
7
99
278
0
238
55
616
tt
1,2QO
1,297
5Q8
1,895
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements 5,222
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 3,574
Levelized capital charges (14.7? of total capital
investment) 3.327
Total levelized annual revenue requirements 6,901
Mi_ Mills/kWh
First-year annual revenue requirements 5.2 4.7
Levelized annual revenue requirements 6.9 6.3
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-7
-------
TABLE A-7, CASE 1, 200-MW, TOTAL CAPITAL INVESTMENT
Total capital investment
$/kW
Capital
investment.
Direot Investment
NOx removal areas
S02 removal areas
Partioulate removal areas
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
7.037
27 . 1 44
8.868
43,049
2.583
45,632
3r8QQ
49,441
3,651
1,369
8,214
2,738
8,436
75,240
6,150
11,737
192
2,784
101,464
507.3
Basis: 3.5% sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-8
-------
TABLE A-8. CASE 1, 200-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Dlreot Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Annual
quantity
959 tons
240 tons
16 tons
120 tons
58,l»00 tons
42,230 man-hr
29,120 man-hr
175,752 MBtu
83,326 kgal
,068,816 kWh
75,582 gal
Unit
cost.
Total annual
cost. k$
155
23,558
300
65
8.50
15.00
21.00
3.30
0.14
0.037
1.60
5,252 man-hr 21.00
119
5,651
5
8
496
6,312
631
612
580
11
1,261
121
3,641
110
6.970
13,282
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
M$
First-year annual revenue requirements 31-2
Levelized annual revenue requirements 45.6
Mills/kWh
28.4
41.5
2,998
16,280
14.915
31,195
30,704
14.915
45,619
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-9
-------
TABLE A-9. CASE 1, 500-MW, NO REMOVAL CAPITAL INVESTMENT
X
Capital
Investment. k&
Direct Investment
NH3 storage and injection 1.314
Reactor 7>829
Flue gas handling 3»843
Air heater 219.
Total process capital 13»805
Services, utilities, and miscellaneous 828
Total direct investment excluding waste disposal 14,633
Waste disposal 19
Total direct investment 14,652
Indirect Investment
Engineering design and supervision 1,024
Architect and engineering contractor 293
Construction expense 2,341
Contractor fees 732
Contingency 3,805
Waste disposal indirect investment 7
Total fixed investment 22,854
Other Capital Investment
Allowance for startup and modifications 2,283
Interest during construction 3,565
Royalties 463
Land 10
Working capital 652
Catalyst 12f028
Total capital investment 41,855
$/kW 83.7
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-10
-------
TABLE A-10. CASE 1, 500-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
X
Direct Cost - First Year
Annual
quantity
Unit
cost.
Total annual
cost. k$
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,350 tons
590 tons
39 tons
20 tons
1,380 man-hr
122 man-hr
15,572 MBtu
2,629 kgal
7,508,752 kWh
498 gal
2,190 man-hr
155
23,558
300
65
15.00
21.00
3-30
0.14
0.037
1.60
21.00
364
13,899
12
14,276
66
3
51
0
278
1
586
Mi
1,031
15,307
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
M$
First-year annual revenue requirements 21.9
Levelized annual revenue requirements 35.8
Mills/kWh
8.0
13.0
421
15,728
35,816
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-ll
-------
TABLE A-ll. CASE 1, 500-MW, SC>2 REMOVAL CAPITAL INVESTMENT
Capital
investment. k&
Direct Investment
Materials handling 2,528
Feed preparation 1,717
Flue gas handling 11,313
S02 absorption 20,111
Oxidation 2,677
Reheat 3,653
Solids separation 3i68l
Total process capital 49,010
Services, utilities, and miscellaneous 2rQ11
Total direct investment excluding waste disposal 51,951
Waste disposal 1,011
Total direct investment 55,962
Indirect Investment
Engineering design and supervision 3,637
Architect and engineering contractor 1,039
Construction expense 8,312
Contractor fees 2,598
Contingency 6,751
Waste disposal indirect investment 1 f 355
Total fixed investment 79,657
Other Capital Investment
Allowance for startup and modifications 5,913
Interest during construction 12,126
Land 158
Working capital
Total capital investment 101,839
$/kW 203.7
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, &0% SCR NOx
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-12
-------
TABLE A-12. CASE 1, 500-MW, SC>2 REMOVAL ANNUAL REVENUE REQUIREMENTS
Direct Cost - First Year
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Annual
quantity
143,030 tons
43,860 man-hr
24,896 man-hr
414,758 MBtu
193,864 kgal
58,011,017 kWh
101,256 gal
4,940 man-hr
Unit
cost, $
8.50
15.00
21.00
3-30
0.14
0.037
1.60
21.00
Total annual
cost . k$
1,216
1,216
658
523
1,369
27
2,146
162
4,276
104
9,265
10,481
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion- costs less utilities)
Total first-year operating and maintenance costs 13,818
Levelized capital charges (14.7$ of total
capital investment) 14.970
Total first-year annual revenue requirements 28,788
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 26,061
Levelized capital charges (14.7$ of total capital
investment) 14,970
Total levelized annual revenue requirements 41,031
Ht Mills/kWh
First-year annual revenue requirements 28.8 10.5
Levelized annual revenue requirements 41.0 14.9
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-13
-------
TABLE A-13. CASE 1, 500-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
Total capital investment
$/kW
Capital
investment.
10,509
5,636
17,456
1.047
18,503
Direct Investment
Particulate removal and storage
Panticulate transfer
Flue gas handling
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
21,847
1,295
370
2,960
925
4,811
1.120
33,337
2,886
5,201
377
1.086
42,887
85.8
Basis:
3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80* SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-14
-------
TABLE A-14. CASE 1, 500-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
auantltv cost, $
Direct Cost - first Xgaj"
H2S04 (100$ equivalent) 275 tons 65
Total raw material cost
Conversion costs
Operating labor and supervision
Process 15(330 man-hr 15.00
Landfill 20,742 man-hr 21.00
Utilities
Process water 7,549 kgal 0.14
Electricity 15,715,143 kWh 0.037
Diesel fuel 84,360 gal 1.60
Maintenance
Labor and material
Analysis 300 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60% of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment )
Total levelized annual revenue requirements
Total annual
cost. k&
USL
18
230
436
1
581
135
1,025
2.414
2,432
1,018
3,450
6.304
9,754
6,507
6.304
12,811
First-year annual revenue requirements
Levelized annual revenue requirements
9.8
12.8
Mills/kWh
3.5
4.7
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-15
-------
TABLE A-15. CASE 1, 500-MW, TOTAL CAPITAL INVESTMENT
—— Capital
____ - investment. k&
Direct Investment
NOx removal areas 13,805
S02 removal areas 49,010
Particulate removal areas 17.456
Total process capital 80,271
Services, utilities, and miscellaneous 4,816
Total direct investment excluding waste disposal 85,087
Waste disposal 7r374
Total direct investment 92,461
Indirect Investment
Engineering design and supervision 5,956
Architect and engineering contractor 1,702
Construction expense 13,613
Contractor fees 4,255
Contingency 15,370
Waste disposal indirect investment 2r491
Total fixed investment 135,848
Other Capital Investment
Allowance for startup and modifications 11,112
Interest during construction 21,192
Royalties 463
Land 845
Working capital 5,093
Catalyst 12,028
Total capital investment 186,581
$/kW 373.2
Basis: 3.5$ sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-16
-------
TABLE A-16. CASE 1, 500-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
Unit
cost. $
2,350 tons
590 tons
39 tons
295 tons
143,030 tons
63,570 man-hr
45,760 man-hr
430,330 MBtu
204,042 kgal
81,234,912 kWh
186,114 gal
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
155
23,558
300
65
8.50
First-year annual revenue requirements
Levelized annual revenue requirements
60.4
89.7
Mills/kWh
22.0
32.6
15.00
21.00
3-30
0.14
0.037
1.60
7,430 man-hr 21.00
Total annual
cost. k&
364
13,899
12
19
1.216
15,510
954
962
1,420
28
3,005
298
5,887
12.710
28,220
4.776
32,996
27.427
60,423
62,231
27,427
89,658
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-17
-------
TABLE A-17. CASE 1, 500-MW, NO REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment, kft
1,414
9,469
3,845
81Q
15,54?
16,504
1,154
330
2,637
824
4,285
25,742
2,571
4,016
463
13
728
14.678
48,211
96.4
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-lead operation, 90? SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-18
-------
TABLE A-18. CASE 1, 500-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS,
X
90% NO REMOVAL
x
Direct Cost - First Year
Annual
quantity
Unit
cost. &
Total annual
cost. k$
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,610 tons
720 tons
39 tons
20 tons
4,380 man-hr
149 man-hr
16,941 MBtu
2,635 kgal
7,654,216 kWh
606 gal
155
23,558
300
65
15.00
21.00
3.30
0.14
0.037
1.60
2,190 man-hr 21.00
409
16,962
12
J
17,384
66
3
56
0
283
1
660
JLfi.
1,115
18,499
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
_M4_
First-year annual revenue requirements 26.1
Levelized annual revenue requirements 42.9
Milla/kWh
9.5
15.6
46S
18,964
7,087
26,051
35,766
7.087
42,853
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-19
-------
TABLE A-19. CASE 1, 500-MW, S02 REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
X
Capital
investment. k$
Direct Investment
Materials handling 2,528
Feed preparation 4,717
Flue gas handling 11,354
S02 absorption 20,413
Oxidation 2,689
Reheat 3,653
Solids separation 3i68l
Total process capital 49,035
Services, utilities, and miscellaneous 2.942
Total direct investment excluding waste disposal 51,977
Waste disposal 4,011
Total direct investment 55,988
Indirect Investment
Engineering design and supervision 3|638
Architect and engineering contractor 1,040
Construction expense 8,316
Contractor fees 2,599
Conti ngency 6 , 7 57
Waste disposal indirect investment 1 f 355
Total fixed investment 79,693
Other Capital Investment
Allowance for startup and modifications 5,946
Interest during construction 12,432
Land 458
Working capital
Total capital investment 101,886
$/kW 203.8
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90? SCR NOx
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-20
-------
TABLE A-20. CASE 1, 500-MW, SC>2 REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Direct Cost - First Year
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Annual
auantitv
143,058 tons
43,860 man-hr
24,896 man-hr
415,182 MBtu
194,024 kgal
58,055,993 kWh
101,256 gal
4,940 man-hr
Unit
cost . $
8.50
15.00
21.00
3-30
0.14
0.037
1.60
21.00
Total annual
cost, k$
1,216
1,216
658
523
1,370
27
2,148
162
4,278
104
Q,270
10,486
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
M$
First-year annual revenue requirements 28.8
Levelized annual revenue requirements 41.0
Mills/kWh
10.5
14.9
13,824
14.977
28,801
26,072
14.977
41,049
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-21
-------
TABLE A-21. CASE 1, 500-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Capital
Investment,
Direct Investment
Particulate removal and storage 10,519
Particulate transfer 5,636
Flue gas handling 1.312
Total process capital 17,467
Services, utilities, and miscellaneous 1.048
Total direct investment excluding waste disposal 18,515
Waste disposal 3,344
Total direct investment 21,859
Indirect Investment
Engineering design and supervision 1,296
Architect and engineering contractor 370
Construction expense 2,962
Contractor fees 926
Contingency 4,814
Waste disposal indirect investment 1.120.
Total fixed investment 33i356
Other Capital Investment
Allowance for startup and modifications 2,888
Interest during construction 5,204
Land 377
Working capital 1.087
Total capital investment 42,912
$/kW 85.8
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90? SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-22
-------
TABLE A-22. CASE 1, 500-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Annual Unit Total annual
quantity cost. $ cost. k$
Direct Cost - First Year
H2SOl| (100? equivalent) 275 tons 65 18.
Total raw material cost 18
Conversion costs
Operating labor and supervision
Process 15,330 man-hr 15.00 230
Landfill 20,742 man-hr 21.00 436
Utilities
Process water 7,549 kgal 0.14 1
Electricity 15,733,157 kWh 0.037 582
Diesel fuel 84,360 gal 1.60 135
Maintenance
Labor and material 1,026
Analysis 300 man-hr 21.00 1
Total conversion costs 2r416
Total direct costs 2,434
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities) 1fQ19
Total first-year operating and maintenance costs 3,453
Levelized capital charges (14.7? of total
capital investment) 6.308
Total first-year annual revenue requirements 9,761
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 6,512
Levelized capital charges (14.7? of total capital
investment) 6,3.08
Total levelized annual revenue requirements 12,820
M$ Mills/kWh
First-year annual revenue requirements 9.8 3.5
Levelized annual revenue requirements 12.8 4.7
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-2 3
-------
TABLE A-23. CASE 1, 500-MW, TOTAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Capital
investment f
Direct Investment
NOx removal areas 15,54?
S02 removal areas 49,035
Particulate removal areas 17.467
Total process capital 82,049
Services, utilities, and miscellaneous 4,923
Total direct investment excluding waste disposal 86,972
Waste disposal 7,379
Total direct investment 94,351
Indirect Investment
Engineering design and supervision 6,088
Architect and engineering contractor 1,740
Construction expense 13,915
Contractor fees 4,349
Contingency 15,856
Waste disposal indirect investment 2f492
Total fixed investment 138,791
Other Capital Investment
Allowance for startup and modifications 11,405
Interest during construction 21,652
Royalties 463
Land 848
Working capital 5,172
Catalyst 14t678
Total capital investment 193,009
$/kW 386.0
Basis: 3.5$ sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90$ SCR NOx
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-24
-------
TABLE A-24. CASE 1, 500-MW, TOTAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
2,640 tons
720 tons
39 tons
295 tons
143,058 tons
63(570 man-hr
45,787 man-hr
432,123 MBtu
204,208 kgal
81,443,366 kWh
186,222 gal
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 .times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
M&
Annual
quantity
Unit
cost.
155
23,558
300
65
8.50
First-year annual revenue requirements 64.6
Levelized annual revenue requirements 96.7
Mills/kWh
23.5
35.2
15.00
21.00
3-30
0.14
0.037
1.60
7,430 man-hr 21.00
Total annual
cost. k&
409
16,962
12
19
1,216
18,618
954
962
1,426
28
3,013
298
5,964
15&
12.801
31,419
4,822
36,241
28,372
64,613
68,350
28.372
96,722
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-25
-------
TABLE A-25. CASE 1, 1,000-MW, NO REMOVAL CAPITAL INVESTMENT
X
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment. k$
1,997
14,937
7,561
1.606
27,700
1,660
277
3,873
1,107
6,917
1,150
6,481
902
16
1,170
23.444
77,707
77.7
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80* SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-26
-------
TABLE A-26. CASE 1, 1,000-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
X
Annual Unit Total annual
quantity cost. $ cost. k&
Direct Cost - First Year
Ammonia l(,551 tons 155 705
Catalyst 1,150 tons 23,558 27,092
Sodium hydroxide 76 tons 300 23
H2S01 (100? equivalent) 38 tons 65 2
Total raw material cost 27,822
Conversion costs
Operating labor and supervision
Process 6,570 man-hr 15.00 99
Landfill 180 man-hr 21.00 1
Utilities
Steam 30,162 MBtu 3.30 100
Process water 5,092 kgal 0.11 1
Electricity 11,513,122 kWh 0.037 538
Diesel fuel 953 gal 1.60 2
Maintenance
Labor and material 831
Analysis 2,628 man-hr 21.00 5JL
Total conversion costs 1.630
Total direct costs 29,152
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities) 593
Total first-year operating and maintenance costs 30,015
Levelized capital charges (11.7? of total
capital investment) 11.123
Total first-year annual revenue requirements 11,168
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 56,665
Levelized capital charges (11.7$ of total capital
investment) 11.123
Total levelized annual revenue requirements 68,088
MS Mills/kWh
First-year annual revenue requirements 11.5 7-5
Levelized annual revenue requirements 68.1 12.1
Basis: One year of operation at the conditions described on the capital investment
table, mid-1981 costs.
A-27
-------
TABLE A-27. CASE 1, 1,000-MW, S02 REMOVAL CAPITAL INVESTMENT
pirect Investment
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Oxidation
Reheat
Solids separation
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
Capital
investment,
2,916
6,042
21,830
HO ,107
5,556
7,153
88,321
5. 299
93,620
6,620
100,240
5,617
936
13,107
3,745
11,703
2,076
137,424
10,298
21,438
708
5,781
175,651
175.7
Basis: 3.5? sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-28
-------
TABLE A-28. CASE 1, 1,000-MW, S02 REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
quantitv cost, &
Direct Cost - First Year
Limestone 276,930 tons 8.50
Total raw material cost
Conversion costs
Operating labor and supervision
Process 55,130 man-hr 15.00
Landfill 36,162 man-hr 21.00
Utilities
Steam 803,333 MBtu 3.30
Process water 375,460 kgal 0.14
Electricity 109,941 ,621 kWh 0.037
Diesel fuel 190,989 gal 1.60
Maintenance
Labor and material
Analysis 6,590 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost. k&
2,^54
2,354
827
759
2,651
53
4,068
306
6,752
131
15,554
17,908
5r086
22,994
25.821
48,815
43,367
25.821
69,188
First-year annual revenue requirements
Levelized annual revenue requirements
48.8
69.2
Mills/kWh
8.9
12.6
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-29
-------
TABLE A-29. CASE 1, 1,000-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
____Capital
investment,
Total capital investment
$/kW
20,417
8,264
2. 580
31,261
1.876
33,137
Direct Investment
Particulate removal and storage
Particulate transfer
Flue gas handling
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
38,673
1,988
331
4,639
1,325
8,284
56,975
4,970
8,888
588
1.82Q
73,250
73.3
Basis: 3.5$ sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-30
-------
TABLE A-30. CASE 1, 1,000-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
Unit
cost. $
21,900 man-hr
30,218 man-hr
14,621 kgal
30,395,983 kWh
159,597 gal
Mrect Cost - First Year
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (11.7? of total capital
investment)
Total levelized annual revenue requirements
MS
533 tons
400 man-hr
First-year annual revenue requirements
Levelized annual revenue requirements
16.1
20.9
Mills/kWh
2.9
3.8
65
15.00
21.00
0.14
0.037
1.60
21.00
Total annual
cost. k&
35
329
635
2
1,125
255
1,492
3.846
3,881
1.478
5,359
10.768
16,127
10,107
10.768
20,875
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-31
-------
TABLE A-31. CASE 1, 1,000-MW, TOTAL CAPITAL INVESTMENT
""Capital
investment, k-fr
Direct Investment
NOx removal areas
S02 removal areas
Particulate removal areas
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
26,101
88,321
31.261
145,683
8.741
154,424
12.18Q
166,613
9,265
1,544
21,619
6,177
26,904
3.821
235,943
19,418
36,807
902
1,312
8,782
23,444
326,608
326.6
Basis: 3.5% sulfur bituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOx
reduction from 1979 NSPS level, forced-oxidation limestone FGD and
cold-side ESP to meet 1979 NSPS, mid-1982 costs.
A-32
-------
TABLE A-32. CASE 1, 1,000-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
1,551 tons
1,150 tons
76 tons
571 tons
276,930 tons
833, ^95 MBtu
395,173 kgal
154,881,026 kWh
351 ,539 gal
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (11.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
m
Annual
quantity
Unit
cost.
83,600 man-hr
66,560 man-hr
155
23,558
300
65
8.50
First-year annual revenue requirements 106.4
Levelized annual revenue requirements 158.2
Mills/kWh
19.3
28.8
15.00
21.00
3-30
0.14
0.037
1.60
9,618 man-hr 21.00
Total annual
cost. k&
705
27,092
23
37
2.354
30,211
1,255
1,398
2,751
56
5,731
563
9,075
201
21,030
51,241
7.157
58,398
48.012
106,410
110,139
48.012
158,151
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-33
-------
TABLE A-33. CASE 2, 200-MW, NO REMOVAL CAPITAL INVESTMENT
Capital
investment.
Direct Investment
NH3 storage and injection 838
Reactor 3,743
Flue gas handling 2,876
Air heater —Hi
Total process capital 8,170
Services, utilities, and miscellaneous 4QQ
Total direct investment excluding waste disposal 8,660
Waste disposal 19
Total direct investment 8,679
Indirect Investment
Engineering design and supervision 693
Architect and engineering contractor 260
Construction expense 1,559
Contractor fees 520
Contingency 2,338
Waste disposal indirect investment 1
Total fixed investment 14,056
Other Capital Investment
Allowance for startup and modifications 1,403
Interest during construction 2,193
Royalties 231
Land 8
Working capital 406
Catalyst 5fQ12
Total capital investment 24,209
$/kW 121.0
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power uhit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-34
-------
TABLE A-34. CASE 2, 200-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
X
Annual
quantity
Unit
cost. &
Total annual
cost. k&
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2SOH (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
1,059 tons
290 tons
21 tons
10 tons
2,190 man-hr
256 man-hr
8,914 MBtu
1,380 kgal
5,511,653 kWh
425 gal
155
23,558
300
65
15.00
21,00
3.30
0.14
0.037
1.60
1,752 man-hr 21.00
164
6,832
6
7,003
33
5
29
0
204
1
434
_32.
74?
7,746
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
MS
First-year annual revenue requirements 11.6
Levelized annual revenue requirements 18.7
Mills/kWh
10.6
17-0
^05
8,051
3.55Q
11,610
15,184
3,559
18,743
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-35
-------
TABLE A-35. CASE 2, 200-MW, SC>2 REMOVAL CAPITAL INVESTMENT
Capital
Investment f
Direct Investment
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Lime particulate recycle
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital Investment
$/kW
694
790
3,956
7,476
14,069
8Uii
14,913
2QQ
15,212
1,193
447
2,684
895
4,026
107
24,564
2,416
3,832
41
806
31,659
158.3
Basis: 0.7% sulfur subbltuminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOx
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-36
-------
TABLE A-36. CASE 2, 200-MW, SO- REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit Total annual
quantity cost, $ cost. k$
Direct Cost - First Year
Lime 3,845 tons 75
Total raw material cost 288
Conversion costs
Operating labor and supervision
Process 13,140 man-hr 15.00 197
Landfill 3,970 man-hr 21.00 83
Utilities
Process water 47,065 kgal 0.14 7
Electricity 8,576,199 kWh 0.037 317
Diesel fuel 6,577 gal 1.60 11
Maintenance
Labor and material 1,053
Analysis 4,191 man-hr 21.00 88
Total conversion costs 1.756
Total direct costs 2,044
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities) 85^
Total first-year operating and maintenance costs 2,897
Levelized capital charges (14.7? of total
capital investment) 4f654
Total first-year annual revenue requirements 7,551
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 5,464
Levelized capital charges (14.7? of total capital
investment) 4.654
Total levelized annual revenue requirements 10,118
M$ Mills/kWh
First-year annual revenue requirements 7.6 6.9
Levelized annual revenue requirements 10.1 9.2
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-37
-------
TABLE A-37. CASE 2, 200-MW, PARTICIPATE REMOVAL CAPITAL INVESTMENT
Capital
Investment,
Direct Investment
Particulate removal and storage
Particulate transfer
Flue gas handling
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
7,078
3,704
2.185
12,967
778
13,745
1.563
15,308
1,100
2,474
825
3,711
561
24,391
2,227
3,805
181
83Q
31,443
157.2
Basis: O.J% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-38
-------
TABLE A-38. CASE 2, 200-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual
Quantity
Direct Cost - First Year
H2SOl| (100? equivalent) 224 tons
Total raw material cost
Conversion costs
Operating labor and supervision
Process 10,950 man-hr
Landfill 20,734 man-hr
Utilities
Process water 950 kgal
Electricity 10,676,617 kWh
Diesel fuel 34,348 gal
Maintenance
Labor and material
Analysis 200 man-hr
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
Unit Total annual
cost. $ cost. k$
65 15.
15
15.00 164
21.00 435
0.14 0
0.037 395
1.60 55
1,009
21.00 4_
2,062
2,077
967
3,044
4.622
7,666
5,741
4.622
10,363
M$ Mllls/kHh
First-year annual revenue requirements 7.7 7.0
Levelized annual revenue requirements 10.4 9-4
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-39
-------
TABLE A-39. CASE 2, 200-MW, TOTAL CAPITAL INVESTMENT
~~~~ Capital
investment, fr
Direct Investment
NOx removal areas 8,170
S02 removal areas 14,069
Particulate removal areas 12,967
Total process capital 35,206
Services, utilities, and miscellaneous 2.112
Total direct investment excluding waste disposal 37,318
Waste disposal 1.881
Total direct investment 39,199
Indirect Investment
Engineering design and supervision 2,986
Architect and engineering contractor 1«119
Construction expense 6,717
Contractor fees 2,240
Contingency 10,075
Waste disposal indirect investment 675
Total fixed investment 63,011
Other Capital Investment
Allowance for startup and modifications 6,046
Interest during construction 9,830
Royalties 231
Land 230
Working capital 2,051
Catalyst 5fQ12
Total capital investment 87,311
$/kW 436.6
Basis: 0.7/t sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOx
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-40
-------
TABLE A-40. CASE 2, 200-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
Unit
cost. $
Total annual
cost. k$
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Lime
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
1,059 tons
290 tons
21 tons
235 tons
3,845 tons
26,280 man-hr
21,960 man-hr
8,914 MBtu
49,395 kgal
24,764,469 kWh
41,350 gal
155
23,558
300
65
75
15.00
21.00
3.30
0.14
0.037
1.60
6,143 man-hr 21.00
164
6,832
6
16
288
7,306
394
523
29
7
916
67
2,496
129
4.561
1.1,867
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
26.8
39.2
Mills/kWh
24.4
35.7
2f125
13,992
12,835
26,827
26,389
12.835
39,224
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-41
-------
TABLE A-41. CASE 2, 500-MW, NO REMOVAL CAPITAL INVESTMENT
X
Total capital investment
$/kW
Capital
investment,
1,328
9,278
4,513
1.220
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
17,385
1,215
3*7
2,776
868
4,511
27,114
2,707
4,230
563
15
783
1U.678
50,090
100.2
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80* SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-42
-------
TABLE A-42. CASE 2, 500-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
X
Annual
quantity
Unit
Total annual
cost. k$
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,167 tons
720 tons
50 tons
25 tons
4,380 man-hr
257 man-hr
19,819 MBtu
3,382 kgal
13,305,600 kWh
738 gal
2,190 man-hr
155
23,558
300
65
15.00
21.00
3-30
0.14
0.037
1.60
21.00
17,315
66
5
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (1*1.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
M$
First-year annual revenue requirements
Levelized annual revenue requirements
26.5
43.5
Mills/kMh
9.6
15.8
487
19,172
43,521
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-43
-------
TABLE A-43. CASE 2, 500-MW, S02 REMOVAL CAPITAL INVESTMENT
Capital
investment,
Direct Investment
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Lime particulate recycle
Total process capital
Services, utilities, and miscellaneous
Total direct Investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal Indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
1,132
1,258
7,374
12,992
2.14.0.
24,896
1.4QH
26,390
527
26,917
1,847
528
4,222
1,320
6,861
41,876
4,117
6,533
75
53,976
108.0
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOx
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-44
-------
TABLE A-44. CASE 2, 500-MW, SC>2 REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
auantitv cost. $
Direct Cost - First Year
Lime 9,446 tons 75
Total raw material cost
Conversion costs
Operating labor and supervision
Process 17,520 man-hr 15.00
Landfill 3,976 man-hr 21.00
Utilities
Process water 115,303 kgal 0.14
Electricity 21,088,330 kWh 0.037
Diesel fuel 11,380 gal 1.60
Maintenance
Labor and material
Analysis 4,191 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost. k$
708
708
263
83
16
780
18
1,599
81
2.847
3,555
1,2,20
4,775
7.9^4
12,709
9,006
7.9^4
16,940
Mills/kWh
First-year annual revenue requirements 12.7
Levelized annual revenue requirements 16.9
4.6
6.2
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-45
-------
TABLE A-45. CASE 2, 500-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
_____ -— — Capital
investment, fc
Direct Investment
Particulate removal and storage 15,446
Particulate transfer 6,779
Flue gas handling 4.961
Total process capital 27,186
Services, utilities, and miscellaneous 1.631
Total direct investment excluding waste disposal 28,817
Waste disposal 2f74Q
Total direct investment 31,566
Indirect Investment
Engineering design and supervision 2,017
Architect and engineering contractor 576
Construction expense 4,611
Contractor fees 1,441
Contingency 7,492
Waste disposal indirect investment Q44
Total fixed investment 48,647
Other Capital Investment
Allowance for startup and modifications 4,495
Interest during construction 7,589
Land 326
Working capital 1?592
Total capital investment 62,649
$/kW 125.3
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1?79 NSPS level, lime spray dryer FGD^and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-46
-------
TABLE A-46. CASE 2, 500-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
Unit
cost. &
Total annual
cost. k&
19,710 man-hr
20,726 man-hr
2,330 kgal
26,111,655 kWh
59,320 gal
Direct Cost - First Year
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
_M$_
550 tons
First-year annual revenue requirements 14.4
Levelized annual revenue requirements 19.0
Mills/kWh
5.2
6.9
65
15.00
21.00
0.14
0.037
1.60
300 man-hr 21.00
36
296
135
0
966
95
1,811
3.609
3,645
1,52Q
5,174
14,383
9,758
9,209
18,967
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-47
-------
TABLE A-47 CASE 2, 500-MW, TOTAL CAPITAL INVESTMENT
Direct Investment,
Capital
investment. k$
NOx removal areas 16,369
S,02 removal areas 24,896
Particulate removal areas 271186.
Total process capital 68,451
Services, utilities, and miscellaneous 4.107
Total direct investment excluding waste disposal 72,558
Waste disposal 3,310
Total direct investment 75,868
Indirect Investment
Engineering design and supervision 5,079
Architect and engineering contractor 1,451
Construction expense 11,609
Contractor fees 3,629
Contingency 18,864
Waste disposal indirect investment 1.137
Total fixed investment 117,637
Other Capital Investment
Allowance for startup and modifications 11,319
Interest during construction 18,352
Royalties 563
Land 416
Working capital 3,750
Catalyst
Total capital investment 166,715
$/kW 333.4
Basis: G.7% sulfur subbitumlnous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80.? SCR NOX .
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-48
-------
TABLE A-48. CASE 2, 500-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
Unit
cost. $
Total annual
cost. k$
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Lime
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,16? tons
720 tons
50 tons
575 tons
9,446 tons
41,610 man-hr
24,959 man-hr
19,819 MBtu
121,015 kgal
60,505,585 kWh
71,438 gal
155
23,558
300
65
75
15.00
21.00
3-30
0.14
0.037
1.60
6,681 man-hr 21.00
336
16,962
15
38
708
18,059
625
523
65
16
2,238
114
4,105
140
7.826
25,885
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
53-6
79-4
Mills/kHh
19.5
28.9
3,236
29,121
24.506
53,627
54,922
24.506
79,428
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-49
-------
TABLE A-49. CASE 2, 500-MW, NO REMOVAL CAPITAL INVESTMENT,
X
90% NO REMOVAL
X
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment, k$
1,431
10,654
4,515
1.221
18,961
1,325
378
3,028
946
4,920
29,571
2,952
4,613
563
22
848
16.920
55,489
111.0
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90% SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-50
-------
TABLE A-50. CASE 2, 500-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Direct Cost - First Year
Annual
quantity
Unit
cost.
Total annual
cost. k$
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,432 tons
830 tons
50 tons
25 tons
4,380 man-hr
296 man-hr
21,083 MBtu
3,387 kgal
13,438,932 kWh
848 gal
155
23,558
300
65
15.00
21.00
3-30
0.14
0.037
1.60
2,190 man-hr 21.00
19,947
66
6
70
0
497
1
758
tti
1,444
21,391
Overheads
Plant and administrative (60$ of.
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
M&-
First-year annual revenue requirements
Levelized annual revenue requirements
30.1
49.5
Mills/kWh
10.9
18.0
21,917
8,157
30,074
41,335
8,157
49,492
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-51
-------
TABLE A-51. CASE 2, 500-MW, SC>2 REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Direct Investment
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Lime particulate recycle
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
Capital
investment. 14
1,132
1,258
7,377
12,997
2.112
26,927
1,818
5.28
1,221
1,320
6,861
,892
1,118
6,535
75
1.375
53,995
108.0
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90% SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-52
-------
TABLE A-52. CASE 2, 500-MW, SO REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Annual Unit
Quantity cost. 4
Direct Cost - First Year
Lime 9,446 tons 75
Total raw material cost
Conversion costs
Operating labor and supervision
Process 17,520 man-hr 15.00
Landfill 3,976 man-hr 21.00
Utilities
Process water 115,398 kgal 0.14
Electricity 21 ,104,983 kWh 0.037
Diesel fuel 11,380 gal 1.60
Maintenance
Labor and material
Analysis 4,191 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost. k$
708
708
263
83
16
781
18
1,600
S&
2. 849
3,557
1,220
4,777
7.937
12,714
9,009
7.937
16,946
M$
Mills/kWh
First-year annual revenue requirements 12.7
Levelized annual revenue requirements 16.9
4.6
6.2
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-53
-------
TABLE A-53. CASE 2, 500-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Direct Investment
Capital
investment, 14
Particulate removal and storage 15,457
Particulate transfer 6,779
Flue gas handling 1,961
Total process capital 27,200
Services, utilities, and miscellaneous -1_»£3£
Total direct investment excluding waste disposal 28,832
Waste disposal _2,J43
Total direct investment 31,581
Indirect Investment
Engineering design and supervision 2,018
Architect and engineering contractor 577
Construction expense 4,613
Contractor fees 1,442
Contingency 7,496
Waste disposal indirect investment 944
Total fixed investment 48,671
Other Capital Investment
Allowance for startup and modifications 4,498
Interest during construction 7,593
Land 326
Working capital i.59^
Total capital investment 62,681
$/kW 125.4
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90? SCP NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-54
-------
TABLE A-54. CASE 2, 500-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Annual Unit
auantitv cost. $
Direct Cost - First Year
H2S04 (100? equivalent) 550 tons 65
Total raw material cost
Conversion costs
Operating labor and supervision
Process 19i710 man-hr 15.00
Landfill 20,726 man-hr 21.00
Utilities
Process water 2,330 kgal 0.11
Electricity 26, 131, 704 kWh 0.037
Diesel fuel 59,320 gal 1.60
Maintenance
Labor and material
Analysis 300 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (1*1.7% of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (Hi. 7$ of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost. k$
36.
36
296
435
0
967
95
1,812
6
^.611
3,647
1,529
5,176
9.214
14,390
9,762
9,214
18,976
First-year annual revenue requirements 14.4
Levelized annual revenue requirements 19.0
Mills/kWh
5.2
6.9
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-55
-------
TABLE A-55. CASE 2, 500-MW, TOTAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Total capital investment
Capital
investmentr
17»851
24,906
27.200
69,957
4.1Q7
74,154
Direct Investment
NOx removal areas
S02 removal areas
Particulate removal areas
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
$/kW
77,469
5,191
1,483
11,865
3,708
19,280
1 r
120,134
11,568
18,741
563
1(23
3,816
16,Q20
172,165
344.3
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90$ SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-56
-------
TABLE A-56. CASE 2, 500-MW, TOTAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Direct Cost - First Year
Annual
quantity
Unit
cost. $
Total annual
cost. k$
Ammonia
Catalyst
Sodium hydroxide
H2SOl( (100$ equivalent)
Lime
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,432 tons
830 tons
50 tons
575 tons
9,446 tons
4 1,610 man-hr
24,998 man-hr
21,083 MBtu
121,115 kgal
60,678,619 kWh
71,548 gal
155
23,558
' 300
65
75
15.00
21.00
3-30
0.14
0.037
1.60
6,681 man-hr 21.00
377
19,553
15
38
708
20,691
625
524
70
16
2,245
114
4,170
140
7,904
28,595
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
57.2
85.4
Mills/kHh
20.8
31.1
3.275
31,870
25 f308
57,178
60,106
25.308
85,414
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-57
-------
TABLE A-57- CASE 2, 1,000-MW, NO REMOVAL CAPITAL INVESTMENT
X
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment, k$
2,290
17,988
8,960
2.UQQ
33,590
2,012
335
4,695
1,3*1
8,384
50,375
5,030
7,859
1,091
25
28,948
94,777
94.8
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-58
-------
TABLE A-58. CASE 2, 1,000-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
X
Direct Cost - First Year
Annual
quantity
Unit
post.
Total annual
cost. k&
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
5,016 tons
1,420 tons
98 tons
49 tons
6,570 man-hr
350 man-hr
42,480 MBtu
6,579 kgal
26,269,165 kWh
1,254 gal
155
23,558
300
65
15.00
21.00
3-30
0.14
0.037
1.60
2,628 man-hr 21.00
34,266
99
7
140
1
972
2
1,008
2,284
36,550
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (11.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (1*1.7? of total capital
investment)
Total levelized annual revenue requirements
701
37,251
51,183
70,255
84,187
Mills/kWh
First-year annual revenue requirements 51.2 9.3
Levelized annual revenue requirements 84.2 15-3
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-59
-------
TABLE A-59. CASE 2, 1,000-MW, SC>2 REMOVAL CAPITAL INVESTMENT
~~~ ~ Capital
. _ __ __ investment, k&
Direct ^investment
Materials handling 1|630
Feed preparation 1»780
Flue gas handling 14,524
S02 absorption 25,598
Lime particulate recycle
Total process capital 46, 8? 4
Services, utilities, and miscellaneous 2,812
Total direct investment excluding waste disposal 49>686
Waste disposal - 8.31
Total direct investment 50,517
Indirect Investment
Engineering design and supervision 2,981
Architect and engineering contractor 497
Construction expense 6,956
Contractor fees 1,987
Contingency 12,421
Waste disposal indirect investment 269
Total fixed investment 75,628
Other Capital Investment
Allowance for startup and modifications 7,453
Interest during construction 11,798
Land 1 1 9
Working capital 2f442
Total capital investment 97,
$/kW 97.
Basis: 0.7% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80* SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-60
-------
TABLE A-60. CASE 2, 1,000-MW, S02 REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
Quantity cost. 4
Pj.rect Cost - First Year
Lime 18,489 tons 75
Total raw material cost
Conversion costs
Operating labor and supervision
Process 21,900 man-hr 15.00
Landfill 5,332 man-hr 21.00
Utilities
Process water 224,300 kgal 0.14
Electricity 41 ,005,970 kWh 0.037
Diesel fuel 19,078 gal 1.60
Maintenance
Labor and material
Analysis 5,590 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost, k$
1,387
1,387
329
112
31
1,517
31
2,509
117
4.646
6,033
1,840
7,873
14,324
22,197
14,848
14.324
29,172
First-year annual revenue requirements
Levelized annual revenue requirements
Ml
22.2
29.2
Mills/kWh
4.0
5.3
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-61
-------
TABLE A-61. CASE 2, 1,000-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
Direct Investment
Particulate removal and storage
Particulate transfer
Flue gas handling
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Capital
investment, k*
30,145
10,609
9.752
50,506
3. 030
53,536
57,841
3,212
535
7,495
2,141
13,384
Total capital investment
$/kW
86,003
8,030
13,416
508
2.760
110,717
110.7
Basis: 0.7* sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80% SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-62
-------
TABLE A-62. CASE 2, 1,000-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
aua.ptitv cost. $
Direct Cost - First Year
H2S04 (100$ equivalent) 1,069 tons 65
Total raw material cost
Conversion costs
Operating labor and supervision
Process 28,1*70 man-hr 15.00
Landfill 27,597 man-hr 21.00
Utilities
Process water 4,526 kgal 0.14
Electricity 50,762,221 kWh 0.037
Diesel fuel 98,740 gal 1.60
Maintenance
Labor and material
Analysis 400 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost. kJ
63L
69
427
580
1
1,878
158
2,806
5,858
5,927
2 ,293
8,220
16.275
24,495
15,503
16.275
31,778
_M& Mills/kWh
First-year annual revenue requirements 24.5 4.5
Levelized annual revenue requirements 31.8 5.8
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-63
-------
TABLE A-63. CASE 2, 1,000-MW, TOTAL CAPITAL INVESTMENT
——Capital
investment, k*
Direct Investment
NOx removal areas 31»638
S02 removal areas 46,87 4
Particulate removal areas 5Qi506
Total process capital 129>018
Services, utilities, and miscellanepus —7«74Q
Total direct investment excluding waste disposal 136,758
Waste disposal 5,190
Total direct investment 141,948
Indirect Investment
Engineering design and supervision 8,205
Architect and engineering contractor 1,367
Construction expense 19»146
Contractor fees 5,469
Contingency 34,189
Waste disposal indirect investment 1.682
Total fixed investment 212,006
Other Capital Investment
Allowance for startup and modifications 20,513
Interest during construction 33,073
Royalties 1,091
Land 652
Working capital 6,651
Catalyst 28,,948
Total capital investment 302,934
$/kW 302.9
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, lime spray dryer FGD and baghouse to
meet 1979 NSPS, mid-1982 costs.
A-64
-------
TABLE A-64. CASE 2, 1,000-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Direct Cost - First Year
Annual
quantity
Unit
cost, $
Total annual
cost, kit
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Lime
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
5,046 tons
1,420 tons
98 tons
1,118 tons
18,489 tons
56,940 man-hr
33.279 man-hr
42,480 MBtu
235,405 kgal
118,037,356 kWh
119,072 gal
155
23,558
300
65
75
15.00
21.00
3-30
0.14
0.037
1.60
8,618 man-hr 21.00
782
33,452
29
72
1.387
35,722
855
699
140
33
4,367
191
6,323
180
12.788
48,510
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
JJ|_
First-year annual revenue requirements 97-9
Levelized annual revenue requirements 145.1
Mills/kWh
17.8
26.4
4.834
53,344
44.531
97,875
100,606
44,531
145,137
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-65
-------
TABLE A-65. CASE 3, 200-MW, NO REMOVAL CAPITAL INVESTMENT
X
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment, k$
830
3,656
3,420
50 T
8,409
501?
8.9U
8,931
713
26?
1,605
535
2,407
14,464
1,444
2,256
231
8
411
S.5Q4
24,318
121.6
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80% SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-66
-------
TABLE A-66. CASE 3, 200-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
3C
2,190 man-hr
214 man-hr
8,658 MBtu
3,252 kgal
4,396,004 kWh
356 gal
1,752 man-hr
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
Annual
quantity
Unit
coat,
1,059 tons
270 tons
49 tons
24 tons
155
23,558
300
65
First-year annual revenue requirements
Levellzed annual revenue requirements
11.1
17.8
Mllls/kWh
10.1
16.2
15.00
21.00
3.30
0.14
0.037
1.60
21.00
Total annual
Cost, k$
6,361
15
6,542
33
29
0
163
1
446
713
7,255
312
7,567
3.575
11,142
14,271
3.575
17,846
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-67
-------
TABLE A-67. CASE 3, 200-MW, S02 REMOVAL CAPITAL INVESTMENT
Total capital investment
$/kW
Capital
investment. k&
987
1,612
6,037
9,833
Direct Investment
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Solids separation
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
20,208
1.212
21,420
470
21,890
1,714
643
3,856
1,285
2,892
170
32,450
2,545
5,062
67
1.264
41,388
206.9
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOx
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-68
-------
TABLE A-68. CASE 3, 200-MW, SC>2 REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit Total annual
quantity cost. $ cost. k$
Direct Cost - First Year
Limestone 8,903 tons 8.50 16_
Total raw material cost 76
Conversion costs
Operating labor and supervision
Process 30,660 man-hr 15.00 460
Landfill 5,935 man-hr 21.00 125
Utilities
Process water 55,573 kgal 0.14 8
Electricity 16,924,291 kWh 0.037 626
Diesel fuel 9,886 gal 1.60 16
Maintenance
Labor and material 1,942
Analysis 3,300 man-hr 21.00 69
Total conversion costs 3,246
Total direct costs 3,322
Indirect Costs - First Year
Overheads
Plant and administrative (60% of
conversion costs less utilities) .1,558
Total first-year operating and maintenance costs 4,880
Levelized capital charges (14.7? of total
capital investment) 6.084
Total first-year annual revenue requirements 10,964
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 9,204
Levelized capital charges (14.7? of total capital
investment) 6.084
Total levelized annual revenue requirements 15,288
M$ Mllls/kWh
First-year annual revenue requirements 11.0 10.0
Levelized annual revenue requirements 15.3 13-9
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-69
-------
TABLE A-69. CASE 3, 200-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
Capital
_ _ ______ _ . __ investment. k$
Direct Investment
Particulate removal and storage 6,035
Particulate transfer 2,619
Flue gas handling 2.732
Total process capital 11,386
Services, utilities, and miscellaneous 683
Total direct investment excluding waste disposal 12,069
Waste disposal 1,490
Total direct investment 13,559
Indirect Investment
Engineering design and supervision 966
Architect and engineering contractor 362
Construction expense 2,172
Contractor fees 724
Contingency 3,259
Waste disposal indirect investment
Total fixed investment 21,579
Other Capital Investment
Allowance for startup and modifications 1,955
Interest during construction 3,366
Land 173
Working capital 718
Total capital investment 27,791
$/kW 139.0
Basis: 0.7% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5, 500-hr/ yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, natural -oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-70
-------
TABLE A-70. CASE 3, 200-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
6,570 man-hr
18,811 man-hr
950 kgal
10,969,^96 kWh
31,335 gal
200 man-hr
Direct Cost - First Year
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
M$
224 tons
Unit
cost.
First-year annual revenue requirements 6.6
Levelized annual revenue requirements 8.8
Mllls/kWh
6.0
8.0
65
15.00
21.00
0.11
0.037
1.60
21.00
Total annual
cost. k$
15.
15
99
395
0
406
50
769
4
1.723
1,738
760
2,498
4,085
6,583
4,711
4f085
8,796
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-71
-------
TABLE A-71. CASE 3, 200-MW, TOTAL CAPITAL INVESTMENT
Direct Investment
NOx removal areas
S02 removal areas
Particulate removal areas
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment.
8,109
20,208
11.386
1*0,003
2.400
1)2,403
1.Q77
44,380
3,393
1,272
7,633
8,558
?n
68,493
5,944
10,684
231
248
2,393
5.504
93,497
467.5
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone PGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-72
-------
TABLE A-72. CASE 3, 200-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Annual Unit Total annual
quantity cost. $ cost. k$
Direct Cost - First Year
Ammonia 1,059 tons 155 164
Catalyst 270 tons 23,558 6,361
Sodium hydroxide 49 tons 300 15
H2S04 (100$ equivalent) 249 tons 65 17
Limestone 8,903 tons 8.50 Z&
Total raw material cost 6,633
Conversion costs
Operating labor and supervision
Process 39,420 man-hr 15.00 592
Landfill 24,960 man-hr 21.00 524
Utilities
Steam 8,658 MBtu 3.30 29
Process water 59,775 kgal 0.14 8
Electricity 32,289,791 kWh 0.037 1,195
Diesel fuel 41,577 gal 1.60 67
Maintenance
Labor and material 3,157
Analysis 5,252 man-hr 21.00 110
Total conversion costs 5,682
Total direct costs 12,315
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities) 2.630
Total first-year operating and maintenance costs 14,945
Levelized capital charges (14.7$ of total
capital investment) 13,744
Total first-year annual revenue requirements 28,689
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 28,186
Levelized capital charges (14.7$ of total capital
investment) 13.744
Total levelized annual revenue requirements 41,930
M$ Mills/kWh
First-year annual revenue requirements 28.7 26.1
Levelized annual revenue requirements 41.9 38.1
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-73
-------
TABLE A-73. CASE 3, 500-MW, NO REMOVAL CAPITAL INVESTMENT
X
Total capital investment
Capital
investment. k&
1,297
8,453
5,386
861
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
16,987
1,187
339
2,713
848
4,409
26,493
2,645
4,133
563
15
757
$/kW
48,061
96.1
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-74
-------
TABLE A-74. CASE 3, 500-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
X
4,380 man-hr
214 man-hr
19,190 MBtu
7,969 kgal
10,572,460 kWh
620 gal
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
Annual
quantity
Unit
cost. &
2,165 tons
660 tons
119 tons
60 tons
155
23,558
300
65
First-year annual revenue requirements
Levelized annual revenue requirements
24.7
40.4
Mills/kWh
9.0
14.7
15.00
21.00
3-30
0.14
0.037
1.60
2,190 man-hr 21.00
Total annual
cost. k$
15,925
66
4
477
17,653
7.065
24,718
33,294
7,065
40,359
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-75
-------
TABLE A-75. CASE 3, 500-MW, SC>2 REMOVAL CAPITAL INVESTMENT
Direct Investment
Capital
investment.
Materials handling 1,266
Feed preparation 2,363
Flue gas handling 11,175
S02 absorption 18,070
Solids separation 2,265
Total process capital 35,139
Services, utilities, and miscellaneous 2,1P8
Total direct investment excluding waste disposal 37,247
Waste disposal 8JH
Total direct investment 38,094
Indirect Investment
Engineering design and supervision 2,607
Architect and engineering contractor 745
Construction expense 5,960
Contractor fees 1,862
Contingency 4,842
Waste disposal indirect investment 292
Total fixed investment 54,402
Other Capital Investment
Allowance for startup and modifications 4,261
Interest during construction 8,487
Land 113
Working capital 2.108
Total capital investment 69,371
$/kW 138.7
Basis: 0.7% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-76
-------
TABLE A-76, CASE 3, 500-MW, SC>2 REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
quantity costr 4
Direct Cost - First Year
Limestone 21,871 tons 8.50
Total raw material cost
Conversion costs
Operating labor and supervision
Process 39,610 man-hr 15.00
Landfill 6, 036 man-hr 21.00
Utilities
Process water 136,178 kgal 0.14
Electricity 39,91^,421 kWh 0.037
Diesel fuel 17, 462 gal 1.60
Maintenance
Labor and material
Analysis 3,300 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
Total annual
cost. k$
186
186
594
127
19
1,477
28
3,005
te.
5,319
5,505
2f277
7,782
10.198
17,980
14,677
10,198
24,875
M$ Mills/kWh
First-year annual revenue requirements 18.0 6.5
Levelized annual revenue requirements 24.9 9.0
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-77
-------
TABLE A-77. CASE 3, 500-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
— — Capital
__ investment. k&
Direct Investment
Particulate removal and storage 14,354
Particulate transfer 4,378
Flue gas handling 4.2QQ
Total process capital 23,022
Services, utilities, and miscellaneous 1 .381
Total direct investment excluding waste disposal 24,403
Waste disposal 2.628
Total direct investment 27,031
Indirect Investment
Engineering design and supervision 1,708
Architect and engineering contractor 488
Construction expense 3,904
Contractor fees 1,220
Contingency 6,345
Waste disposal indirect investment Q05
Total fixed investment 41,601
Other Capital Investment
Allowance for startup and modifications 3,807
Interest during construction 6,490
Land 3 1 3
Working capital 1 .
Total capital investment 53,546
107.1
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5, 500-hr/ yr full-load operation, 80% SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-78
-------
TABLE A-78. CASE 3, 500-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit Total annual
_ quantity cost, $ cost, k$
Direct Cost - First Year
H2SOij (100$ equivalent) 550 tons 65 Jjj.
Total raw material cost 36
Conversion costs
Operating labor and supervision
Process 15,330 man-hr 15.00 230
Landfill 18,710 man-hr 21.00 393
Utilities
Process water 2,330 kgal 0.14 0
Electricity 26,830,622 kWh 0.037 993
Diesel fuel 54,129 gal 1.60 87
Maintenance
Labor and material 1,299
Analysis 300 man-hr 21.00 6.
Total conversion costs 3,008
Total direct costs 3,044
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities) 1,157
Total first-year operating and maintenance costs 4,201
Levelized capital charges (14.7$ of total
capital investment) 7f87_1
Total first-year annual revenue requirements 12,072
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 7,923
Levelized capital charges (14.7$ of total capital
investment) 7|871
Total levelized annual revenue requirements 15,794
M$ Mills/kWh
First-year annual revenue requirements 12.1 4.4
Levelized annual revenue requirements 15.8 5.7
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs. -
A-79
-------
TABLE A-79. CASE 3, 500-MW, TOTAL CAPITAL INVESTMENT
Capital
investment. k$
Direct Investment
NOx removal areas 15,997
S02 removal areas 35,139
Particulate removal areas 23.022
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment 82,112
Indirect Investment
Engineering design and supervision 5,502
Architect and engineering contractor 1,572
Construction expense 12,577
Contractor fees 3,930
Contingency 15,596
Waste disposal indirect investment 1f207
Total fixed investment 122,496
Other Capital Investment
Allowance for startup and modifications 10,713
Interest during construction 19,110
Royalties 563
Land 1)41
Working capital 4,200
Catalyst 13.455
Total capital investment 170,978
342.0
Basis: 0.7% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-80
-------
TABLE A-80. CASE 3, 500-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Annual
quantity
Unit
cost, $
Direct Cost - First Year
Ammonia 2,165 tons
Catalyst 660 tons
Sodium hydroxide 119 tons
H2S04 (100$ equivalent) 610 tons
Limestone 21,871 tons
Total raw material cost
59,320 man-hr
24,960 man-hr
19,190 MBtu
146,477 kgal
77,317,503 kWh
72,211 gal
5,790 man-hr
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - 'First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
155
23,558
300
65
8.50
First-year annual revenue requirements 54.8
Levelized annual revenue requirements 81.0
Mllls/kWh
19.9
29.5
15.00
21.00
3.30
0.14
0.037
1.60
21.00
Total annual
costf k$
336
15,549
36
40
186
16,147
890
524
63
20
2,861
116
4,983
121
9.578
25,725
3.911
29,636
25,134
54,770
55,894
25,134
81,028
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-81
-------
TABLE A-81, CASE 3, 500-MW, NO REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Capi tal
investment. k$
Direct Investment
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
9,937
5,388
861
17,580
18,635
18,670
1,304
373
2,982
932
1,815
29,118
2,907
563
22
826
15.Q01
53,879
107.8
Basis: 0.7? sulfur subbitum.inous coal, new pulverized-coal-f j red power" unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90? SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FCD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-82
-------
TABLE A-82. CASE 3, 500-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
— . . .
•
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Annual
auantitv
2,1432 tons
780 tons
119 tons
60 tons
4,380 man-hr
253 man-hr
20,454 MBtu
7,978 kgal
10,703,620 kWh
731 gal
2,190 man-hr
Unit
cost. $
155
23,558
300
65
15.00
21.00
3-30
0.14
0.037
1.60
21.00
Total annual
cost. k$
377
18,375
36
4
18,792
66
5
68
1
396
1
746
kfi.
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
28.6
46.8
Mills/kWh
10.4
17.0
20,121
20,639
7.920
28,559
38,925
7.920
46,845
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-83
-------
TABLE A-83. CASE 3, 500-MW, SO REMOVAL CAPITAL IISTVESTMENT,
90% NO REMOVAL
x
Direct Investment
Materials handling
Feed preparation
Flue gas handling
S02 absorption
Solids separation
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
Capital
investment. k&
1,267
2,363
11,180
18,072
2.265
35,147
2f10Q
37,256
847
38,103
2,608
745
5,961
1,863
4,843
54,415
4,262
8,489
113
2.108
69,387
138.8
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90? SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-84
-------
TABLE A-84. CASE 3, 500-MW, SO REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Direct Cost - First Year
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Annual
quantity
21,871 tons
39,610 man-hr
6,036 man-hr
136,269 kgal
39,935,729 kWh
17,462 gal
3,300 man-hr
Unit
cost, $
8.50
15.00
21.00
0.14
0.037
1.60
21.00
Total annual
cost. k&
186
186
594
127
19
1,478
28
3,006
62
Total conversion costs
Total direct costs 5,507
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities) 2,278
Total first-year operating and maintenance costs 7,785
Levelized capital charges (14.7$ of total
capital investment) 1Q.2QQ
Total first-year annual revenue requirements 17,985
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M) 14,683
Levelized capital charges (14.7$ of total capital
investment) 1Qi20Q
Total levelized annual revenue requirements 24,883
M$ Mills/kWh
First-year annual revenue requirements 18.0 6.5
Levelized annual revenue requirements 24.9 9-0
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-85
-------
TABLE A-85. CASE 3, 500-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Capital
investment. k$
Direct Investment
Particulate removal and storage
Particulate transfer 4,378
Flue gas handling 4.290
Total process capital 23,022
Services, utilities, and miscellaneous 1.381
Total direct investment excluding waste disposal 24,403
Waste disposal 2,626
Total direct investment 27,031
Indirect Investment
Engineering design and supervision 1,708
Architect and engineering contractor 488
Construction expense 3,904
Contractor fees 1,220
Contingency 6,345
Waste disposal indirect investment 905
Total fixed investment 41,601
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Land
Working capital
Total capital investment
$/kW
Basis: 0.7% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90% SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-86
-------
TABLE A-86. CASE 3, 500-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
X
Annual
quantity
15,330 man-hr
18,710 man-hr
2,331 kgal
26,854,413 kWh
54, 129 gal
300 man-hr
Direct Cost - First Year
H2S04 (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60? of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
_HL-
550 tons
Unit
cost.
First-year annual revenue requirements 12.1
Levelized annual revenue requirements 15-8
Mills/kWh
4.4
5.7
65
15.00
21.00
0.14
0.037
1.60
21 .00
Total annual
cost. k$
36
230
393
0
994
87
1,299
3,009
3,045
1,157
4,202
7.871
12,073
7,925
7,871
15,796
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-87
-------
TABLE A-87. CASE 3, 500-MW, TOTAL CAPITAL INVESTMENT,
90% NO REMOVAL
x
Direct Investment
NOx removal areas
S02 removal areas
Particulate removal areas
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment. k$
17,580
35,14?
23.022
75,749
4.545
80,294
3.510
83,804
5,620
1,606
12,847
4,015
16,033
1.209
125,134
10,976
19,521
563
449
4,269
15.901
176,813
353.6
Basis: 0.7$ sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 90$ SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-88
-------
TABLE A-88. CASE 3, 500-MW, TOTAL ANNUAL REVENUE REQUIREMENTS,
90% NO REMOVAL
x
Direct Cost - First Year
Annual
quantity
Unit
cost. &
Total annual
cost. k&
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
2,432 tons
780 tons
119 tons
610 tons
21,871 tons
59,320 man-hr
24,999 man-hr
20,454 MBtu
146,578 kgal
77,493,762 kWh
72,322 gal
155
23,558
300
65
8.50
15.00
21.00
3.30
0.14
0.037
1.60
5,790 man-hr 21.00
377
18,375
36
40
186
19,014
890
525
68
20
2,868
116
5,051
121
9,659
28,673
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
58.6
87.5
Mills/kHh
21.3
31.8
32,626
25.991
58,617
61,533
25,991
87,524
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-89
-------
TABLE A-89. CASE 3, 1,000-MW, NO REMOVAL CAPITAL INVESTMENT
X
Direct Investment
i,
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency
Waste disposal indirect investment
Total fixed investment
Other Capital Investment
Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital
Catalyst
Total capital investment
$/kW
Capital
investment. k&
2,198
16,476
10,622
1.694
32,897
1,971
328
1,599
1,314
8,212
49,337
4,927
7,697
1,091
24
1,402
26.706
91,184
91.2
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-90
-------
TABLE A-90. CASE 3, 1,000-MW, NO REMOVAL ANNUAL REVENUE REQUIREMENTS
"
Direct Cost - First Year
Annual
quantity
Unit
cost.
Total annual
cost, k$
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100$ equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (11.7$ of total capital
investment)
Total levelized annual revenue requirements
M$
5,016 tons
1,310 tons
232 tons
116 tons
155
23,558
300
65
6,570 man-hr
292 man-hr
41 ,257 MBtu
15,502 kgal
20,951,980 kWh
1,064 gal
15.00
21.00
3.30
0.14
0.037
1.60
2,628 man-hr 21.00
First-year annual revenue requirements
Levelized annual revenue requirements
47-9
78.4
Mills/kWh
8.7
14.3
31,721
99
6
136
2
755
2
987
2,062
33,783
688
34,471
•R.4Q4
47,875
65,012
13,404
78,416
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-91
-------
TABLE A-91. CASE 3, 1,000-MW, S02 REMOVAL CAPITAL INVESTMENT
Capital
Investment, k$
Direct Investment
Materials handling 1,345
Feed preparation 2,828
Flue gas handling 21,686
S02 absorption 35,584
Solids separation
Total process capital
Services, utilities, and miscellaneous
Total direct investment excluding waste disposal
Waste disposal
Total direct investment
Indirect Investment
Engineering design and supervision 4,072
Architect and engineering contractor 679
Construction expense 9,501
Contractor fees 2,715
Contingency 8,483
Waste disposal indirect investment 424
Total fixed investment 95,043
Other Capital Investment
Allowance for startup and modifications 7,465
Interest during construction 14,827
Land 167
Working capital ^.627
Total capital investment 121,129
$/kW 121e1
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-92
-------
TABLE A-92. CASE 3, 1,000-MW, SC>2 REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual Unit
Quantity cost. $
Direct Cost - first Jfear
Limestone 42,1*33 tons 8.50
Total raw material cost
Conversion costs
Operating labor and supervision
Process 19,330 man-hr 15.00
Landfill 7,910 man-hr 21.00
Utilities
Process water 264,862 kgal 0.14
Electricity 75,892,554 kWh 0.037
Diesel fuel 28,828 gal 1.60
Maintenance
Labor and material
Analysis 4,940 man-hr 21.00
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (f>Q% of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment )
Total levelized annual revenue requirements
M&_ Mills/kWh
First-year annual revenue requirements 30.3 5.5
Levelized annual revenue requirements 41.4 7-5
Total annual
cost, k£
361
361
740
166
37
2,808
46
4,790
104
8,691
9,052
3.480
12,532
17.806
30,338
23,635
17.806
41,441
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-93
-------
TABLE A-93- CASE 3, 1,000-MW, PARTICULATE REMOVAL CAPITAL INVESTMENT
Capital
investment. k&
Direct Investment
Particulate removal and storage 27,916
Particulate transfer 6,403
Flue gas handling 8.456
Total process capital 42,775
Services, utilities, and miscellaneous 2.567
Total direct investment excluding waste disposal 45,342
Waste disposal 4,143
Total direct investment 49,485
Indirect Investment
Engineering design and supervision 2,721
Architect and engineering contractor 453
Construction expense 6,348
Contractor fees 1,814
Contingency 11,336
Waste disposal indirect investment 1T344
Total fixed investment 73,501
Other Capital Investment
Allowance for startup and modifications 6,801
Interest during construction 11,466
Land H90
Working capital 2,310
Total capital investment 94,568
$/kW 9H.6
Basis: 0.7% sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80$ SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-94
-------
TABLE A-94. CASE 3, 1,000-MW, PARTICULATE REMOVAL ANNUAL REVENUE REQUIREMENTS
Annual
Quantity
21,900 man-hr
25,078 man-hr
4,526 kgal
52,163,646 kWh
91,398 gal
400 man-hr
Direct Cost - First Year
H2S04 (100? equivalent)
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costa - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (14.7? of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7? of total capital
investment)
Total levelized annual revenue requirements
M$
1,068 tons
Unit
cost, $
First-year annual revenue requirements
Levelized annual revenue requirements
20.5
26.4
Mijlls/kWh
3-7
4.8
65
15.00
21.00
0.14
0.037
1.60
21.00
Total annual
cost. k$
69
329
527
1
1,930
146
1,938
4.879
4,948
1.681
6,629
13.901
20,530
12,502
13.901
26,403
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-95
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TABLE A-95. CASE 3, 1,000-MW, TOTAL CAPITAL INVESTMENT
Capital
investment. k&
Direct Investment
NOx removal areas 30,990
S02 removal areas 64,022
Particulate removal areas 42,775
Total process capital 137,787
Services, utilities, and miscellaneous 8.267
Total direct investment excluding waste disposal 146,054
Waste disposal 5,4Q7
Total direct investment 151,551
Indirect Investment
Engineering design and supervision 8,764
Architect and engineering contractor 1,460
Construction expense 20,448
Contractor fees 5,843
Contingency 28,031
Waste disposal indirect investment 1.784
Total fixed investment 217,881
Other Capital Investment
Allowance for startup and modifications 19,193
Interest during construction 33,990
Royalties 1,091
Land 681
Working capital 7,339
Catalyst 26.706
Total capital investment 306,881
306.9
Basis: 0.7? sulfur subbituminous coal, new pulverized-coal-fired power unit
with a 30-yr life at 5,500-hr/yr full-load operation, 80? SCR NOX
reduction from 1979 NSPS level, natural-oxidation limestone FGD and
hot-side ESP to meet 1979 NSPS, mid-1982 costs.
A-96
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TABLE A-96. CASE 3, 1,000-MW, TOTAL ANNUAL REVENUE REQUIREMENTS
Direct Cost - First Year
Ammonia
Catalyst
Sodium hydroxide
H2S04 (100? equivalent)
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
Process
Landfill
Utilities
Steam
Process water
Electricity
Diesel fuel
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative (60$ of
conversion costs less utilities)
Total first-year operating and maintenance costs
Levelized capital charges (11.7$ of total
capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
costs (1.886 times first-year O&M)
Levelized capital charges (14.7$ of total capital
investment)
Total levelized annual revenue requirements
M$
Annual Unit Total annual
quantity cost. A cost. k&
5,046 tons
1,310 tons
232 tons
1,185 tons
42,433 tons
155
23,558
300
65
8.50
77,800 man-hr
33,280 man-hr
41 ,257 MBtu
284,890 kgal
149,008,180 kWh
121,290 gal
15.00
21.00
3.30
0.14
0.037
1.60
7,968 man-hr 21.00
First-year annual revenue requirements 98.7
Levelized annual revenue requirements 146.3
Mills/kWh
18.0
26.6
32,151
1,168
699
136
40
5,513
194
7,715
Ifil
15,632
47,783
S.84Q
53,632
45.111
98,743
101,149
45.111
146,260
Basis: One year of operation at the conditions described on the capital investment
table, mid-1984 costs.
A-97
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TECHNICAL REPORT DATA
(Please read iHUructions on the reverse before completing)
1 . REPORT NO
EPA-600/7-85-006
4 TITLE AND SUBTITLE
Economics of Nitrogen Oxides, Sulfur Oxides, and Ash
Control Systems for Coal-fired Utility Power Plants
6. PERFORMING ORGANIZATION CODE
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
February 1985
7. AUTHOR(S)
J. D. Maxwell and L. R. Humphries
8. PERFORMING ORGANIZATION REPORT NO
9 PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
TVA, Office of Power
Division of Energy Demonstrations and Technology
Muscle Shoals, Alabama 35660
11. CONTRACT/GRANT NO.
EPA IAG-79-D-X0511
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 1/81 - 1/85
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES AEERL project officer is J. David Mobley, Mail Drop 61, 919/541-
2612.
is. ABSTRACT
report gives results of an EPA- sponsored economic evaluation of
three processes to reduce NOx, SO2, and ash emissions from coal-fired utility po-
wer plants: one based on 3. 5% sulfur eastern bituminous coal; and the other, on 0.7%
sulfur western subbituminous coal. NOx control is based on an 80% reduction from
current new source performance standards (NSPS); SO2 and fly ash control are based
on meeting the current NSPS. Selective catalytic reduction (SCR) is used for NOx
control with both coals. Limestone scrubbing and a cold- side electrostatic precipita-
tor (ESP) are used with the 3. 5% sulfur coal. Lime spray dryer flue gas desulfuriza-
tion (FGD) and a baghouse for particulate collection are used with one 0.7% sulfur
coal; and limestone scrubbing and a hot- side ESP, with the other. The economics
consist of detailed breakdowns of the capital investments and annual revenue require-
ments. For systems based on a 500- MW power plant, capital investments range
from $167 to $187 million (333 to 373 S/kW) and the first year annual revenue require-
ments from $54 to $60 million (29 to 33 mills /kWh). The 3. 5% sulfur coal case is
highest because of the higher SO2 control costs. The case with the spray dryer and
baghouse is marginally lower in cost than that with limestone scrubbing and hot- side
ESP. Costs for NOx control are 25 to 50% of the total costs.
17.
KEY WORDS AND DOCUMENT ANALYSIS
•DESCRIPTORS
Pollution
Economics
Coal
Combustion
Utilities
Nitrogen Oxides
Sulfur Dioxide
Fly Ash
Catalysis
Scrubbers
Electric Power Plants
l>. IDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Selective Catalytic Re-
duction
Baghouses
c. COSATl 1 icId.'Croup
13B
05C
21D
2 IB
10 B
07B
07A.13I
3. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
309
20 SECURITY CLASS (This pane)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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