&EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/5-79-003
January 1979
Air
Cost Analysis of
Lime-based Flue Gas
Desulfurization Systems
for New 500-MW Utility
Boilers
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EPA-450/5-79-003
Cost Analysis of Lime-based
Flue Gas Desulfurization Systems
for New 500-MW Utility Boilers
Prepared by:
PEDCo Environmental, Inc.
Chester Towers
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2842
Assignment No. 25
EPA Task Manager: J. Garrard Wright
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Strategies and Air Standards Division
Economic Analysis Branch
Research Triangle Park, North Carolina 27711
January 1979
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DISCLAIMER
This report was furnished to the U.S. Environmental Protection Agency (EPA) by
PEDCo Environmental, Inc., Cincinnati, in fulfillment of Assignment No. 25 of Contract No.
68-02-2842. The contents of this report are reproduced herein as received from the
contractor. The opinions, findings, and conclusions expressed are those of the author and not
necessarily those of the EPA.
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CONTENTS
Figures
Tables
Acknowledgment
1. Introduction 1-1
2. System Variables 2-1
2.1 FGD System Configuration 2-1
2.2 Plant Variables 2-3
2.3 Analysis Approach 2-4
3. Cost Components 3-1
3.1 Capital Costs 3-1
3.2 Annualized Costs 3-4
3.3 Computer Model for Costs 3-5
4. Results and Applications t 4-1
4.1 Results 4-1
4.2 Applications 4-22
111
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FIGURES
No. Page
2-1 Lime FGD system 2-2
2-2 Plant combinations for FGD cost analysis 2-6
4-1 Capital investment excluding cost of sludge pond and 4-4
land for a lime FGD system at a bituminous-coal-fired
500-MW plant
4-2 Capital cost of sludge pond and land for a lime FGD 4-5
system at a bituminous-coal-fired 500-MW plant
4-3 Operation and maintenance cost excluding electricity '4-6
and reheat for a lime FGD system at a bituminous-coal-
fired 500-MW plant
4-4 Fixed charges for a lime FGD system at a bituminous- 4-7
coal-fired 500-MW plant
4-5 Capacity penalty for a lime FGD system at a bitu- 4-8
minous-coal-fired 500-MW plant
4-6 Energy penalty for a lime FGD system at a bituminous- 4-9
coal-fired 500-MW plant
4-7 Capital investment excluding cost of sludge pond and 4-10
land for a lime FGD system at a subbituminous-coal-
fired 500-MW plant
4-8 Capital cost of sludge pond and land for a lime FGD 4-11
system at a subbituminous-coal-fired 500-MW plant
4-9 Operation and maintenance cost excluding electricity 4-12
and reheat for a lime FGD system at a subb i turn i nous-
coal-fired 500-MW plant
4-10 Fixed charges for a lime FGD system at a subbitu- 4-13
minous-coal-fired 500-MW plant
4-11 Capacity penalty for a lime FGD system at a subbitu- 4-14
minous-coal-fired 500-MW plant
IV
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FIGURES (CONTINUED)
No. Page
4-12 Energy penalty for a lime FGD system at a subbitu- 4-15
minous-coal-fired 500-MW plant
4-13 Capital investment excluding cost of sludge pond and 4-16
land for a lime FGD system at a lignite-fired 500-MW
plant
4-14 Capital cost of sludge pond and land for a lime FGD 4-17
system at a lignite-fired 500-MW plant
4-15 Operation and maintenance cost excluding electricity 4-18
and reheat for a lime FGD system at a lignite-fired
500-MW plant
4-16 Fixed charges for a lime FGD system at a lignite-fired 4-19
500-MW plant
4-17 Capacity penalty for a lime FGD system at a lignite- 4-20
fired 500-MW plant
4-18 Energy penalty for a lime FGD system at a lignite- 4-21
fired 500-MW plant
v
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TABLES
No. Paqe
2-1 Assumed Coal Characteristics 2-4
2-2 Selected Number of Scrubber Modules and Spare Capacity 2-8
2-3 Cost Bases and Rates 2-9
4-1 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-24
Plant Firing Bituminous Coal With 0.0 RSD in Long-
Term Sulfur Content
4-2 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-?5
Plant Firing Bituminous Coal With 1.3 RSD in Long-
Term Sulfur Content
4-3 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-26
Plant Firing Bituminous Coal With 3.0 RSD in Long-
Term Sulfur Content
4-4 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-27
Plant Firing Subbituminous Coal With 0.0 RSD in Long-
Term Sulfur Content
4-5 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-2F
Plant Firing Subbituminous Coal With 1.3 RSD in Long-
Term Sulfur Content
4-6 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-29
Plant Firing Subbituminous Coal With 3.0 RSD in Long-
Term Sulfur Content
4-7 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-30
Plant Firing Lignite With 0.0 RSD in Long-Term Sulfur
Content
4-8 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-31
Plant Firing Lignite With 1.3 RSD in Long-Term Sulfur
Content
4-9 Cost-Effectiveness of a Lime FGD System for a 500-MW 4-32
Plant Firing Lignite With 3.0 RSD in Long-Term Sulfur
Content
vi
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ACKNOWLEDGMENT
This report was furnished to the U.S. EPA by PEDCo Environ-
mental, Inc., Cincinnati. PEDCo Project Director was Mr. Donald
J. Henz, and Mr. Yatendra M. Shah was the PEDCo Task Manager.
Mr. J. Garrard Wright was the EPA Task Manager. PEDCo appre-
ciates the contributions made to this study by Mr. Wright and Mr.
Richard E. Jenkins, also of the EPA.
VII
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SECTION 1
INTRODUCTION
This report studies the effect of sulfur dioxide (SO_)
removal levels on the cost of lime-based flue gas desulfurization
(FGD) systems for total and partial scrubbing. The analysis is
performed for a 500-MW utility boiler firing three major types of
coal. The results are presented as graphs for six cost compon-
ents.
The three types of coal considered are bituminous, subbitu-
minous, and lignite. Because these coals differ from each other
in firing characteristics, boilers using different fuels have
different FGD costs for the same SO- removal levels.
The results of this analysis are to be used in studying the
effects of limitation levels and averaging times on SO- control
costs. The U.S. Environmental Protection Agency (EPA) has con-
tracted with PEDCo Environmental, Inc., to perform this analysis
in support of a program to review New Source Performance Stan-
dards for SO- emissions from coal-fired utility boilers.
Section 2 discusses the system variables for each kind of
coal, and Section 3 describes the cost components studied. The
results and applications of the analysis are presented in Section
4, which includes costs for model plants defined by the EPA.
1-1
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SECTION 2
SYSTEM VARIABLES
This report is intended for use with various combinations
of input parameters. To present a broad spectrum of cases, the
report follows these guidelines:
1. Cost components are evaluated for three types of coal
that are representative of the coals mined in the
United States.
2. To study the effect of partial scrubbing, the analysis
includes FGD cost curves for flue gas flows from 20
through 100 percent of the total boiler exhaust.
3. The analysis is applicable to SC>2 removal levels up to
3867 ng/J (9.0 lb/106 Btu).
The ranges of variables and FGD system assumptions are
discussed in this section.
2.1 FGD SYSTEM CONFIGURATION
The process diagram for a typical lime FGD system is shown
in Figure 2-1. The system does not include equipment for par-
ticulate removal. It is assumed that the particulate concentra-
tion of flue gas entering the absorber complies with the ap-
plicable particulate emission regulations.
The FGD system has three major process areas: (1) slurry
preparation, (2) SO2 scrubbing, and (3) sludge disposal. The
items of equipment included for each process area are as follows
2-1
-------
nut GAS
FROM BOILER
I
fo
CLEAN GAS
TO ATMOSPHERE
.COVERED
CONVEYOR
0 FIXATION
CHEMICAL
STORAGE
FIXATION
TANK
SLUDGE TO DISPOSAL POND
Figure 2-1. Lime FGD system.
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(1) Slurry preparation:
Conveyors
Slakers
Storage silos
Storage tanks
Pumps and motors
(2) SO2 scrubbing:
Absorbers
Fans and motors
Heat exchangers (reheaters)
Duct work and dampers
Slurry hold tanks
Recycle pumps
(3) Sludge disposal:
. Clarifiers
Chemical storage equipment
Mobile equipment
Hold tanks
Sludge pumps
The stack at the plant is not considered a part of the FGD
system. The sludge generated by the FGD is disposed of in an
onsite sludge pond. Sludge is assumed to be pumped 1.6 km (1
mile). Costs are for new applications only; retrofit applica-
tions are out of the scope of this report.
2.2 PLANT VARIABLES
FGD costs are estimated for single boiler plants, elch with
a total electrical capacity of 500 MW. Use of an FGD system,
however, causes plant generating capacity to be derated by the
amount of electricity needed to operate the system.
Costs are presented for plants firing three types of coal:
bituminous, subbituminous, and lignite. These coals have differ-
ent firing characteristics; those affecting the design of FGD
systems are listed in Table 2-1. Heating value and heat rate
determine the'quantity of coal fired per hour, and the SC>2 in
2-3
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boiler outlet gases is proportional to this quantity. Thus, FGD
costs vary for coals with different heat rates and heating values
TABLE 2-1. ASSUMED COAL CHARACTERISTICS
Coal type
Heating value
kJ/kg (Btu/lb)
Flue gas rate,a
m^/s (acfm)
Heat rate,
kj/kwh (Btu/kWh)
Bituminous
Subbituminous
Lignite
27,920 (12,000)
24,330 (10,500)
18,380 (7,900)
713 (1,510,000)
727 (1,540,000)
763 (1,616,000)
9500 (9000)
9560 (9050)
9720 (9200)
For 500-MW plant.
The size of handling equipment depends on total gas flow
through an FGD system. The amount of air required for complete
combustion varies for different coals and produces different
exhaust gas flow rates.
2.3 ANALYSIS APPROACH
To cover a broad range of cases, the report considers four
levels qf SO2 removal: 859 ng/J (2.0 lb/106 Btu) , 1718 ng/J (4.0
lb/106 Btu), 2578 ng/J (6.0 lb/106 Btu), and 3437 ng/J (8.0
lb/10 Btu) . Values of each cost component are calculated for
these levels and are plotted as points on graphs. Curves are
drawn through the points, and costs for intermediate S0~ re-
moval levels can be interpolated from the curves.
Separate curves are drawn for nine gas flow rates, ranging
from 20 to 100 percent of the exhaust gases at increments of 10
percent.
2-4
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Figure 2-2 shows the plant variables and total number of
plant combinations necessary for the analysis.
2.3.1 Module Selection
Items of gas handling equipment in an FGD system are gener-
ally referred to as scrubbing modules. Limitations on the
physical size of absorbers and ancillary devices force manu-
facturers of FGD equipment to limit maximum module size. The
number of modules selected depends on the reliability require-
ments and volume of gas to be treated. The cost of an FGD system
varies according to the number of modules it contains. The
availability of an FGD system is a direct function of number of
scrubbing modules. The more scrubbing modules there are, the
greater the availability of the system. A system with four
scrubbing modules, for example, loses 25 percent of capacity if
one module is down; but a system with only two scrubbing modules
loses 50 percent capacity if one module is down. Availability is
thus enhanced by a maximum number of functioning modules, as well
as by some spare scrubbing capacity.
Module selection for this analysis is based on reducing
system cost while providing for redundancy. The largest scrubber
size assumed is 218 m /s (462,000 acfm) of flue gas at 155°C
(310°F). This size is equivalent to 150 MW of electrical capac-
ity for subbituminous coal. Based on this size limitation, the
total costs for different numbers of modules are compared for
2-5
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4 SO, REMOVAL LEVELS
859 ng/J (2 lb/106 Btu)
1718 ng/J (4 lb/106 Btu)
2578 ng/J (6 lb/106 Btu)
3437 ng/J (8 lb/106 Btu)
9 GAS FLOW RATES
(percent of exhaust gas)
20, 30, 40, 50, 60, 70, 80, 90, and 100
TOTAL COMBINATIONS
(Number of coal types) x (Number of SOg removal levels) x (Number of gas flow rates)
3 x 4 x 9 = 108
Figure 2-2. Plant combinations for FGD cost analysis.
2-6
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each scrubbing case. Table 2-2 shows the number of modules
selected for the cases analyzed. Each case includes one spare
scrubbing module.
The cost bases and rate data used for the analysis are
presented in Table 2-3.
2-7
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TABLE 2-2.
SELECTED NUMBER OF SCRUBBER MODULES
AND SPARE CAPACITY
Gas flow
through FGD
system, % of
total exhaust
100
90
80
70
60
50
40
30
20
Bituminous coal
Total
number of
scrubber
modules
5
4
4
4
3
3
3
3
3
Spare
modules
1
1
1
1
1
1
1
1
J-
1
Spare
scrubbing
capacity,
%
25
33
33
33
50
50
50
50
50
Subbituminous coal
Total
number of
scrubber
modules
5
4
4
4
3
3
3
3
3
Spare
modules
1
1
1
1
1
1
1
1
1
Spare
scrubbing
capacity,
%
25
33
33
33
50
50 '
50
50
50
Lignite
Total
number of
scrubber
modules
5
5
4
4
4
3
3
3
3
Spare
modules
1
1
1
1
1
1
1
1
1
Spare
scrubbing
capacity,
%
25
25
33
33
33
50
50
50
50
N)
I
00
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TABLE 2-3. COST BASES AND RATES
Escalation factor for capital cost'
Electricity rate, mills/kWh
Reheat/steam rate, $/GJ ($/106Btu)
Labor rate, $/man-hour
Capital recovery factor for annualizing
capital investment, % of capital cost
Insurance, taxes, and general administrative
expenses, % of capital cost
2
Land rate, $/m ($/acre)
Lime rate, $/Mg ($/ton)
Fixation chemicals, $/Mg ($/ton)
1.156
25.00
1.18 (1.25)
10.00
11.70
4.30
0.49 (2000)
38.60 (35.00)
22.00 (20.00)
The base year for computer model costs is 1976; the
escalation factor is used to update the costs to 1978.
2-9
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SECTION 3
COST COMPONENTS
The cost of an FGD system is estimated as capital cost and
annualized cost. The capital cost represents the initial invest-
ment necessary to install and commission the. system. The annual-
ized cost represents the cost of operating and maintaining the
system and the charges needed to recover the capital investment,
which are referred to as fixed costs or fixed charges.
3.1 CAPITAL COSTS
Capital costs consist of direct and indirect costs incurred
up to the successful commissioning date of the facility. Direct
costs include the costs of various items of equipment and the
labor and material required for installing these items and inter-
connecting the system. Indirect costs are expenditures for the
overall facility that cannot be attributed to specific equipment;
they include such items as freight and spares.
3.1.1 Direct Costs
The "bought-out" cost of the equipment and the cost of in-
stalling it are considered direct costs. A bought-out cost of an
equipment item is the purchase price paid to the equipment
supplier on a free-on-board (f.o.b.) basis; this does not include
the freight charges. Installation costs cover the interconnection
3-1
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of the system, which involves piping, electrical, and the other
work needed to commission it. Also attributed to installation
are the costs of foundations, supporting structures, enclosures,
ducting, control panels, instrumentation, insulation, painting,
and similar items. Costs for interconnecting various items of
FGD equipment include site development, construction of access
roads and walkways, and the establishment of rail, barge, or
truck facilities. Finally, the cost of administrative facilities
is considered a direct cost.
Various procedures are available for estimating direct costs.
The PEDCo computer model uses the installation factor technique
to estimate total direct costs. The bought-out cost of each item
of equipment is multiplied by an individual installation factor
to obtain the installed cost. This installed cost includes a
proportional cost for interconnecting the equipment into the
system. The installation factors are based on the complexity of
the equipment and the cost of the material and labor required.
The installed costs of all the equipment are added together to
obtain the total direct cost of the facility.
3.1.2 Indirect Costs
The indirect costs of an FGD system include the following:
Interest: covers interest accrued on borrowed capital
during construction.
Engineering costs: include administrative, process, proj-
ect, and general costs; design and related functions for
specifications; bid analysis; special studies; cost anal-
ysis; accounting; reports; purchasing; procurement; travel
expenses; living expenses; expediting; inspection; safety;
3-2
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communications; modeling; pilot plant studies; royalty
payments during construction; training of plant personnel;
field engineering; safety engineering; and consultant serv-
ices .
Field overhead; includes the cost of securing permits and
right-of-way sections, and the cost of insurance for the
equipment and personnel on site.
Freight: includes delivery costs on FGD process and related
equipment shipped f.o.b. point of origin.
Offsite expenditures; include expenditures for powerhouse
modifications, interruption to power generation, and service
facilities added to the existing plant facilities.
Taxes: include sales, franchise, property, and excise
taxes.
Spare parts: represent costs of items stocked to permit 100
percent process availability; such items include pumps,
valves, controls, special piping and fittings, instruments,
spray nozzles, and similar equipment.
Shakedown; includes costs associated with system startup.
Contractor's fee and expenses; include costs for field
labor payroll, supervision field office, administrative
personnel, construction offices, temporary roadways, rail-
road trackage, maintenance and welding shops, parking lot,
communications, temporary piping, electrical, sanitary
facilities, rental equipment, unloading and storage of
materials, travel expenses, permits, licenses, taxes, in-
surance, overhead, legal liabilities, field testing of
equipment, and labor relations.
Con tingency cost s; include costs resulting from malfunc-
tions, equipment design alterations, and similar unforeseen
sources.
Land cost; includes only the cost of the land required for
sludge disposal. The cost of land for installing FGD equip-
ment is accounted for in the installation factors.
All indirect cost components, except land cost, are obtained
by multiplying the direct costs by an indirect cost factor. The
land cost is based on land rate and the disposal area required.
3-3
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3.2 ANNUALIZED COSTS
The annualized operating costs of an FGD system consist of
the following:
Raw materials: include costs of lime for the FGD system and
fixation chemicals.
Utilities: include costs of water for slurries, cooling,
and cleaning; electricity for pumps, fans, valves, lighting
controls, conveyors, and mixers; fuel for reheating flue
gases; and steam for processing.
Operating labor: includes costs of supervision and skilled
and unskilled labor to operate, monitor, and control the FGD
process.
Maintenance and repairs; include costs of manpower and
materials to keep the unit operating efficiently. The
function of maintenance is both preventive and corrective,
to keep outages to a minimum.
Overhead: represents business expenses that are not charged
directly to a particular part of a process, but are allo-
cated to it. Overhead costs include administrative, safety,
engineering, legal, and medical services; payroll; employee
benefits; recreation; and public relations.
The capital investment in an FGD system is generally trans-
lated into annual fixed charges. These charges, along with the
annual operating cost, represent the total revenue requirement or
annualized cost of a system. The annual fixed charges are cal-
culated under four cost components: depreciation, taxes, insur-
ance, and capital costs. The values for these components are
obtained as follows:
Depreciation; calculated by using a sinking-fund method
over the life period of the FGD system.
Taxes; calculated by multiplying the total capital cost by
the input tax rate. The tax rate varies for different
plants.
3-4
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Insurance; calculated by multiplying the total capital cost
by the insurance rate.
Capital charges; calculated by multiplying the total
capital cost by the input interest rate. Capital charges
represent the interest paid per year for the use of capital,
and they vary according to interest rates.
The total annual fixed charges are obtained by adding the
values of the above four components. The annualized cost or
total annual revenue required is the sum of the annual operating
costs and the total annual fixed charges. Table 2-3, presented
at the end of Section 2, shows the cost bases and rates used in
this analysis.
3.3 COMPUTER MODEL FOR COSTS
The costs for lime FGD systems were calculated using the
computer model developed by PEDCo. This model is structured to
provide capital and annualized costs for different FGD variables.
The input for the model consists of the rate data, coal data, gas
flow rates, rates of allowable S02, and other related data. The
base year for the model is 1976; a provision exists for adjusting
the capital costs by an escalation factor to the year of FGD
startup.
3-5
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SECTION 4
RESULTS AND APPLICATIONS
4.1 RESULTS
4.1.1 Cost Components
The coal fired in a utility boiler varies in sulfur content.
An FGD system designed for a long-term average sulfur content in
the coal would allow excessive emissions of S02 during short-term
peaks of sulfur content. To meet S0_ control regulations con-
sistently, an FGD system must be designed for these peaks and
thus be larger than would be required for a long averaging time.
To analyze the effect of averaging time, this report sub-
divides the FGD costs generated by the computer model into six
components. Of the six cost components, three are dependent on
averaging time: (1) capital cost of system equipment, (2) fixed
charges of total capital investment, and (3) capacity penalty.
The components independent of averaging time are: (1) capital
investment for sludge pond and land and (2) energy penalty. The
operation and maintenance costs are made up of components de-
pendent on averaging time and components independent of averaging
time. Costs of raw materials used by the FGD system are in-
dependefit of the averaging time, whereas maintenance costs, which
4-1
-------
are a function of capital investment, are dependent on it. TUB
importance of these components in cost analysis is explained
below.
4.1.1.1 Capital Cost of System Equipment--
The FGD system must be large enough to accommodate sulfur
content peaks in the coal. Such a system operates at a slightly
reduced load when sulfur content is lower than the peaks, and
brings a higher capital investment than a system designed for
long-term average sulfur content.
4.1.1.2 Fixed Charges—
The high capital investment for systems designed for short
averaging times also brings high annual capital charges, because
these charges are proportional to the capital investment.
4.1.1.3 Capacity Penalty—
The capacity penalty represents an instantaneous derating in
boiler capacity by the amount required to operate the FGD system.
The derating depends upon the maximum power to be reserved for
the system during sulfur peaks. This study treats the capacity
penalty as a percentage of total generating capacity.
4.1.1.4 Capital Investment for Sludge Pond and Land—
The total sludge generated by the FGD system depends on the
long-term sulfur content of coal and is independent of short-term
sulfur peaks. The capital investment for sludge pond and land
therefore always varies according to the long-term sulfur con-
tent of the coal.
4-2
-------
4.1.1.5 Operation and Maintenance Costs—
The cost components for operation and maintenance include
costs of lime, fixation chemicals, and labor. Reheat and elec-
tricity are not included. The operating costs are independent of
the averaging time, and maintenance costs are dependent on it.
4.1.1.6 Energy Penalty—
The energy penalty is represented as the percentage of
total generating capacity. The energy used by the FGD system
does not depend on averaging time.
4.1.2 Graphs for Cost Components
Graphs are presented for six cost components of lime FGD
systems at plants firing each of the three types of coal.
Figures 4-1 through 4-6 are for bituminous-coal-fired units;
Figures 4-7 through 4-12, for subbituminous-coal-fired ones; and
Figures 4-13 through 4-18, for lignite-fired ones. The six cost
components are:
(1) Capital investment excluding sludge pond and land.
(2) Capital cost of sludge pond and land.
(3) Operation and maintenance costs excluding electricity
and reheat.
(4) Fixed charges.
(5) Capacity penalty.
(6) Energy penalty.
The graphs for components 1 through 4 have x-axes showing the
amount of SO» removed. The graphs for components 5 and 6 have
4-3
-------
1.0
2.0 3.0
4.0
5.0 6.0 7.0 8.0 9.0
GAS FLOW THROUGH FGD =100%
20
10
9.0
S02 REMOVED, lb/10D Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-1. Capital investment excluding cost of sludge pc.nd
and land for a lime FGD system at a bituminous-coal-fired 500-MW plant
4-4
-------
1.0 2.0 3.0
4.0 5.0 6.0 7.0 8.0
10.0
9.0
GAS FLOW THROUGH FGD zlQO%3
• ; : . 1 't * T I • t • T i I - I . . i l^V ^
S02 REMOVED, lb/10 Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-2. Capital cost of sludge pond and land for a lime
FGD system at a bituminous-coal-fired 500-MW plant.
4-5
-------
1.0
9.0
5.0
4.5
5.0 6.0 7.0 8.
1.0
0.5
9.0
S02 REMOVED, lb/10 Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-3. Operation and maintenance cost excluding electricity
and reheat for a lime FGD system at a
bituminous-coal-fired 500-MW plant.
4-6
-------
9.0
S02 REMOVED, lb/10b Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-4. Fixed charges for a lime FGD system at a
bituminous-coal-fired 500-MW plant.
4-7
-------
3.0
10 20 30 40 50 60 70 80 90 100
2.5
2.0
1.5
3.0
2.5
2.0
1.5
i
1.0
1.0
a—F
0.5
0.5
10 20 30 40 50 60
GAS FLOW THROUGH FGD,
70 80 90 100
Figure 4-5. Capacity penalty for a lime FGD system at a
bituminous-coal-fired 500-MW plant.
4-8
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10 20 30 40
50
60 70
5.0
4.5
4.0
3.5
3.0
#2.5
i2.0
80 90 100
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
!! Ill' ! I
m
nun!
f i±a
1.5
1.0
0.5
LrfTi i
10 20 30 40 50 60
GAS FLOW THROUGH FGD,%
70
80 90 100
Figure 4-6. Energy penalty for a lime FGD system at a
bituminous-coal-fired 500-MW plant.
4-9
-------
1.0 2.0
3.0
9.0
20
10
5.0 6.0 7.0 8.0
9.0
S02 REMOVED, lb/10° Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-7. Capital investment excluding cost of sludge
pond and land for a lime FGD system at a
subbituminous-coal-fired 500-MW plant.
4-10
-------
io. o
9.0
8.0
7-°
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0
_" 5.0
1 GAS HOW
IHRUUIiH mi) - 1 00%
_:
::
'90%
i
=30% :
f
10.0
<) 0
8.0
7.0
6.0
5.0
4.0
3.0
2.0
1.0
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0
SO, REMOVED, lb/10 Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-8. Capital cost of sludge pond and land for a lime
FGD system at a subbituminous-coal-fired 500-MW plant.
4-11
-------
5.0
1.0
0.5
5.0 6.0 7.0 8.0 9.0
S02 REMOVED, lb/10b Btu
0 lb/106 Btu = 429.6 ng/J)
Figure 4-9.
Operation and maintenance cost excluding electricity
and reheat for a lime FGD system at a
subbituminous-coal-fired 500-MW plant.
4-12
-------
5.0
4.5 •
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.
0.5
0 9.0
S02 REMOVED, lb/106 Btu
(1 lb/106 Btu • 429.6 ng/0)
Figure 4-10. Fixed charges for a lime FGD system at a
subbituminous-coal-fired 500-MW plant.
4-13
-------
3.0
10 20 30 40 50 60 70 80 90 100
2.5
2.0
1.5
3.0
2.5
2.0
1.5
1.0
1 .0
0.?
0.5
10
20
30
40
GAS FLOW
50 60
THROUGH FGD,5£
70
80
90 100
Figure 4-11. Capacity penalty for a lime FGD system at a
subbituminous-coal-fired 500-MW plant.
4-14
-------
10 20
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
30 40 50 60 70 80 90 100
ill. 15.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
m
i
10 20 30 40 50 60
GAS FLOW THROUGH FGD, %
70 80 90 100
Figure 4-12. Energy penalty for a lime FGD system at a
subbituminous-coal-fired 500-MW plant.
4-15
-------
1.0 2.0
4.0 5.0 6.0 7.0 8.0 9.0
130
10
30
20
10
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0
S02 REMOVED, lb/106 Btu
(1 lb/106 Btu •= 429.6 ng/J)
Figure 4-13. Capital investment excluding cost of sludge pond
and land for a lime FGD system at a lignite-fired 500-MW plant.
4-16
-------
lO.O
g.O
8.0
7.0
6.0
. 5.0
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0
•> n
GAS FLOW THROUGH hGU
SI 10.0
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0
S02 REMOVED, lb/10 Btu
(1 lb/106 Btu •= 429.6 ng/J)
Figure 4-14. Capital cost of sludge pond and land for
a lime FGD system at a lignite-fired 500-MW plant.
4-17
-------
1.0 2.0
8.0 9.0
5.0
4.5
.5
5.0 6.0 7.0 8.0 9.0
S02 REMOVED, lb/10° Btu
(1 lb/106 Btu •= 429.6 ng/J)
Figure 4-15. Operation and maintenance cost
excluding electricity and reheat for a lime FGD system
at a lignite-fired 500-MW plant.
4-18
-------
5.0
0.5
1.0
0.5
4.0 5.0 6.0 7.0 8.0 9.0
S02 REMOVED, lb/10 Btu
(1 lb/106 Btu = 429.6 ng/J)
Figure 4-16. Fixed charges for a lime FGD system at a
lignite-fired 500-MW plant.
4-19
-------
10 20
30 40 :50 60
70 80
90 100
3.0
3.0
ffl-
2.5
2.5
2.0
2.0
3
1.5
1.5
1.0
1.0
; ; •
0.5
0.5
tottr
! ! I i i ! I i
10 20 30 40 50 60
GAS FLOW THROUGH FGD, *
70
80
90 100
Figure 4-17. Capacity penalty for a lime FGD
system at a lignite-fired 500-MW plant.
4-20
-------
10 20 30
40
50 ' 60 70 80 90 100
5.C
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
4.5
3.5
3.0
2.5
2.0
1.5
1.0
0.5
10 20 30
40 50 60
GAS FLOW THROUGH FGD, !
70 80 90 100
Figure 4-18. Energy penalty for a lime FGD system
at a lignite-fired 500-MW plant.
4-21
-------
x-axes showing the percentage of gas flow through the FGD system.
because the capacity and energy penalties are insensitive to .SO9
removal levels.
4.2 APPLICATIONS
Figures 4-1 through 4-18 were used to calculate the costs of
various model plant scenarios. In evaluating the effects of
averaging time on the scenarios, it was assumed that an averaging
time could be treated as a relative standard deviation (RSD) of
the long-term sulfur content of coal and that each RSD amounted
to an average increase in sulfur content of 15 percent. Model
plant costs are presented for three RSD values: 0.0, 1.3, and
3.0. The values for SO_ removal factor, percentage of gas flow
through the FGD system, and amount of SO- removed are obtained
with the following equations:
U - U*
(1) SO- removal factor = —^
R
TT ,long-term sulfur ~ ,, T-,<-^\ n t
U_ =[ Z 4. .c n x2x(l + nx RSD)]
R content of coal
U = Allowable S0~ emissions
(2) Percentage of gas flow through the FGD system
SO- removal factor
0785
x 100
*
In these equations, U and U should have the same units (either
ng/J or lb/10^ Btu).
n = number of RSD's (i.e., 0.0, 1.3, or 3.0); and RSD = 0.15
(15 percent).
4-22
-------
(3) Amount of SO0 removed by FGD system = U - U
^ ' K
The model plant scenarios are presented in Tables 4-1 through
4-9.
4-23
-------
TABLE 4-1. COST-EFFECTIVENESS OF A LIME FGD
SYSTEM FOR A 500-MW PLANT FIRING BITUMINOUS COAL
WITH 0.0 RSD IN LONG-TERM SULFUR CONTENT9
Controlled SO,, emission level
344 ng/J
(0.8 lb/106 Btu)
50% control
Capital cost of FGD sys-
tem, $/kW
Increment of capital cost
above cost of base
plant, %b
Annualized cost of FGD
system, mills/kwh
Increment of annualized
cost above the oper-
ating cost of the base
plant, %c
Annual SO2 emissions,
Mg/yr (tons/yr)
SO~ removal efficiency, %
Annualized cost of S02
removal, $/Mg ($/ton)
110.75
14.55
6.44
69.76
9.17
3.76
25.75
9,300 (10,250)
84.00
375.39 (340.55)
15.05
29,060 (32,030)
50.00
368.68 (334.47)
a Sulfur content of bituminous coal = 1074 ng/J (2.5 lb/106 Btu)
Base plant capital cost = $761/kW.
Base plant annualized operating cost = 25.0 mills/kWh.
4-24
-------
TABLE 4-2. COST-EFFECTIVENESS OF A LIME FGD SYSTEM FOR A
500-MW PLANT FIRING BITUMINOUS COAL WITH
1.3 RSD IN LONG-TERM SULFUR CONTENT3
Controlled S02 emission
level of 50%
Capital cost of FGD system, $/kW
Increment of capital cost above
cost of base plant, %^
Annualized cost of FGD system,
mills/KWh
Increment of annual cost above
the operating cost of the
base plant, %c
Annual SO2 emissions, Mg/yr (tons/yr)
S0~ removal efficiency, %
Annualized cost of SO2 removal,
$/Mg ($/ton)
70.10
9.21
3.77
15.09
29,060 (32,030)
50.00
369.61 (335.31)
a Sulfur content of bituminous coal = 1074 ng/J (2.5 lb/106 Btu)
Base plant capital cost = $761/kW.
0 Base plant annualized operating cost = 25.0 mills/kWh.
4-25
-------
TABLE 4-3. COST-EFFECTIVENESS OF A LIME FGD SYSTEM FOR A
500-MW PLANT FIRING BITUMINOUS COAL WITH
3.0 RSD IN LONG-TERM SULFUR CONTENT*1
Controlled SO2 emission
level of 50%
Capital cost of FGD system, $/kW
Increment of capital cost above
cost of base plant, %k
Annualized cost of FGD system,
mills/KWh
Increment of annual cost above
the operating cost of the
base plant, %c
Annual SO- emissions, Mg/yr (tons/yr)
SO2 removal efficiency, %
Annualized cost of S00 removal,
$/Mg ($/ton) 2
70.56
9.27
3.79
15.14
29,060 (32,030)
50.00
370.88 (336.46)
Sulfur content of bituminous coal = 1074 ng/J (2.5 lb/10 Btu)
Base plant capital cost = $761/kW.
Base plant annualized operating cost = 25.0 mills/kwh.
4-26
-------
TABLE 4-4. COST-EFFECTIVENESS OF A LIME FGD SYSTEM FOR A 500-MW PLANT
FIRING SUBBITUMINOUS COAL WITH 0.0 RSD IN LONG-TERM SULFUR CONTENT3
Controlled S02 emission level
215 ng/J
(0.5 lb/106 Btu)
344 ng/J
(0.8 lb/106 Btu)
50% control
Capital cost of FGD system, $/kW
Increment of capital cost above
cost of base plant, %"
Annualized cost of FGD system,
mills/kWh
Increment of annualized cost
above the operating cost of
the base plant, %c
Annual S02 emissions,
Mg/yr (tons/yr)
S0~ removal efficiency, %
Annualized cost of S02 removal,
$/Mg ($/ton)
88.34
10.79
4.68
18.71
5840 (6440)
69.88
982.30 (891.14)
69.79
8.52
3.61
14.44
9350 (10,310)
51.81
1022.86 (927.94)
68.29
8.34
3.49
13.98
9700 (10,690)
50.00
1025.44 (930.29)
a Sulfur content of subbituminous coal = 356 ng/J (0.83 lb/106 Btu).
Base plant capital cost = $819/kW.
^
Base plant annualized operating cost = 25.0 mills/kWh.
-------
TABLE 4-5. COST-EFFECTIVENESS OF A LIME FGD SYSTEM FOR A 500-MW PLANT
FIRING SUBBITUMINOUS COAL WITH 1.3 RSD IN LONG-TERM SULFUR CONTENT3
Controlled S02 emission level
215 ng/J
(0.5 lb/106 Btu)
344 ng/J
(0.8 lb/106 Btu)
50% control
I
NJ
00
Capital cost of FGD system, $/kW
Increment of capital cost above
cost of base plant, %b
Annualized cost of FGD system,
mills/kWh
Increment of annualized cost
above the operating cost of
the base plant, %c
Annual S02 emissions,
Mg/yr (tons/yr)
SO2 removal efficiency, %
Annualized cost of S02 removal,
$/Mg ($/ton)
94.95
11.59
4.88
19.51
5840 (6440)
69.88
1024.45 (929.38)
76.67
9.36
3.76
15.06
9350 (10,310)
51.81
1066.29 (967.34)
68.37
8.35
3.50
13.98
9700 (10,690)
50.00
1026.11 (930.89)
a Sulfur content of subbituminous coal = 356 ng/J (0.83 lb/10 Btu).
r_
Base plant capital cost = $819/kW.
r-i
Base plant annualized operating cost = 25.0 mills/kWh.
-------
TABLE 4-6. COST-EFFECTIVENESS OF A LIME FGD SYSTEM
FOR A 500-MW PLANT FIRING SUBBITUMINOUS COAL
WITH 3.0 RSD IN LONG-TERM SULFUR CONTENT3
Controlled SO« emission level
344 ng/J
(0.8 lb/106 Btu)
50% control
Capital cost of FGD sys-
tem, $/kW
Increment of capital cost
above cost of base
plant, %b
Annualized cost of FGD
system, mills/kwh
Increment of annualized
cost above the oper-
ating cost of the base
plant, %c
Annual SO2 emissions,
Mg/yr (tons/yr)
S02 removal efficiency, %
Annualized cost of SO2
removal, $/Mg ($/ton)
85.67
10.46
4.12
68.47
8.36
3.50
16.48
9350 (10,310)
51.81
1166.70 (1058.43)
14.00
9700 (10,690)
50.00
1026.94 (931.64)
Sulfur content of subbituminous coal = 356 ng/J (0.83 lb/10- Btu)
Base plant capital cost = $819/kW.
Base plant annualized operation cost = 25.0 mills/kWh.
4-29
-------
I
CO
o
TABLE 4-7. COST-EFFECTIVENESS OF A LIME FGD SYSTEM FOR A 500-MW
PLANT FIRING LIGNITE WITH 0.0 RSD IN LONG-TERM SULFUR CONTENT3
Capital cost of FGD system, S/kW
Increment of capital cost above
cost of base plant, %b
Annualized cost of FGD system,
raills/kWh
Increment of annualized cost
above the operating cost of
the base plant, %c
Annual SO2 emissions,
Mg/yr (tons/yr)
S02 removal efficiency, %
Annualized cost of SO2 removal,
$/Mg ($/ton)
Controlled SO. emission level
86 ng/J
(0.2 lb/106 Btu)
108.63
13.26
5.77
23.09
2380 (2620)
83.33
1383.23 (1254.87)
215 ng/J
(0.5 lb/106 Btu)
78.50
9.58
4.03
16.12
5940 (6550)
58.33
1379.43 (1251.42)
344 ng/J
(0.8 lb/106 Btu)
53.70
6.56
2.73
10.92
9500 (10,480)
33.33
1634.84 (1483.13)
50% control
69.72
8.51
3.57
14.29
7130 (7860)
50.00
1426.43 (1294.06)
Sulfur content of lignite = 258 ng/J (0.6 lb/106 Btu).
Base plant capital cost = $819/kW.
Base plant annualized operating cost = 25.0 mills/kwh.
-------
TABLE 4-8. COST-EFFECTIVENESS OF A LIME FGD SYSTEM FOR A 500-MW PLANT
FIRING LIGNITE WITH 1.3 RSD IN LONG-TERM SULFUR CONTENT3
Controlled S02 emission level
215 ng/J
(0.5 lb/106 Btu)
344 ng/J
(0.8 lb/106 Btu)
50% control
i
OJ
Capital cost of FGD system, $/kW
Increment of capital cost above
cost of base plant, %b
Annualized cost of FGD system,
mills/kWh
Increment of annualized cost
above the operating cost of
the base plant, %c
Annual S02 emissions,
Mg/yr (tons/yr)
S02 removal efficiency, %
Annualized cost of S02 removal,
$/Mg ($/ton)
85.60
10.45
4.29
17.17
5940 (6550)
58.33
1469.55 (1333.18)
68.89
8.41
3.36
13.42
9500 (10,480)
33.33
2010.36 (1823.80)
70.01
8.55
3.58
14.32
7130 (7860)
50.00
1429.70 (1297.02)
a Sulfur content of lignite = 258 ng/J (0.6 lb/106 Btu).
b Base plant capital cost = $819/kW.
£
Base plant annualized operating cost = 25.0 mills/kWh.
-------
TABLE 4-9. COST-EFFECTIVENESS OF A LIME FGD SYSTEM
FOR A 500-MW PLANT FIRING LIGNITE WITH
3.0 RSD IN LONG-TERM SULFUR CONTENT9
Controlled SO- emission level
344 ng/J
(0.8 lb/106 Btu)
50% control
Capital cost of FGD sys-
tem, $/kW
Increment of capital cost
above cost of base
plant, %"
Annualized cost of FGD
system, mills/kwh
Increment of annual!zed
cost above the oper-
ating cost of the base
plant, %c
Annual SO2 emissions,
Mg/yr (toris/yr)
S02 removal efficiency, %
Annualized cost of SO2
removal, $/Mg ($/ton)
73.09
8.92
3.53
70.21
8.57
3.59
14.14
9500 (10,480)
33.33
2117.00 (1920.55)
14.34
7130 (7860)
50.00
1431.93 (1299.05)
Sulfur content of lignite = 258 ng/J (0.6 lb/10 Btu).
Base plant capital cost = $819/kW.
Base plant annualized operating cost = 25.0 mills/kWh.
4-32
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/5-79-003
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Cost Analysis of Lime-Based Flue Gas Desulfurization
Systems for New 500-MW Utility Boilers
6. PERFORMING ORGANIZATION CODE
5. REPORT DATE
Issued 1/79
7. AUTHOR(S)
Yatendra M. Shah
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 4
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-2842
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Cost curves for the calculation of capital investment, operating and maintenance
cost, capacity, and energy penalties are presented. These curves apply only to
500-MW coal-fired utility boilers controlled by lime based flue gas desulfurization
systems. Costs can be determined for bituminous, sub-bituminous, and lignite coals
with sulfur contents ranging up to about 4.5%. The cost of FGD treatment of 20 -
100 percent of the gas flow in 10 percent increments and in a broad range of sulfur
removal efficiencies can also be calculated.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Air Pollution
Cost Comparison
Electric Utilities
Sulfur Oxides
Air Pollution Control
Stationary Sources
Coal-Fired Boilers
Emission Standards
13B
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
55
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
------- |