EPA-450/3-85-011
Industrial Boiler SO2
Cost Report
Prepared by-
Radian Corporation
Under Contract No. 68-02-3816
- v'-ro'i'.v .•*••! ^v,;-:ct:on Agency
fregjon V, LiUt-ry
230 South Dearborn Street
Chicago, Illinois 60604>;
Prepared for:
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Emission Standards and Engineering Division
Research Triangle Park, NC 27711
November 1984
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DISCLAIMER
This report has been reviewed by the Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, and approved for publication as received from the Radian Corporation. Approval does
not signify that the contents necessarily reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute endorsement or recommenda-
tion for use. Copies of this report are available from the National Technical Information Services, 5285 Port
Royal Road, Springfield, Virginia 221 61
U,S. Environmental Pretsctlon Agency.
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TABLE OF CONTENTS
Chapter Page
1.0 INTRODUCTION 1_1
2.0 COSTING METHODOLOGY 2-1
2.1 COSTING APPROACH 2-1
2.1.1 Capital Costs 2-2
2.1.2 Operation and Maintenance (O&M) Cost 2-6
2.1.3 Annualized Costs 2-10
2.2 BOILER AND CONTROL DEVICE SPECIFICATIONS 2-10
2.2.1 Uncontrolled Boiler Costs 2-13
2.2.2 Participate Matter (PM) Control Costs ..'.. 2-14
2.2.3 NO Control Costs 2-14
2.2.4 SO;; Control Costs ',,[', 2-19
2.3 OTHER COST CONSIDERATIONS 2-19
2.3.1 Continuous Emission Measurement Costs 2-22
2.3.2 FGO Malfunction Costs 2-22
2.3.3 Regional Cost Considerations 2-24
2.4 REFERENCES 2-28
3.0 COST OF S02 CONTROL ON COAL-FIRED MODEL BOILERS 3-1
3.1 REGION V COSTS 3.4
3.1.1 Capital Costs 3-4
3.1.2 Annual O&M Costs [','/, 3.5
3.1.3 Annual ized Costs 3_6
3.2 REGION VIII COSTS 3_15
3.2.1 Capital Costs 3_15
3.2.2 Annual O&M Costs [','.'/. 3-15
3.2.3 Annualized Costs 3_15
3.3 REFERENCES 3_2Q
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TABLE OF CONTENTS (Continued)
Chapter
4.0 COST OF S02 CONTROL ON RESIDUAL OIL-FIRED MODEL BOILERS 4-1
4.1 REGION V COSTS .
4.1.1 Capital Costs '.'[ l~t
4.1.2 Annual O&M Costs !!."!!.'!!! 43
4.1.3 Annualized Costs !!!!!!.*!!..* 4*3
4.2 REFERENCES 4_7
APPENDIX A - COST ALGORITHMS A_}
APPENDIX B - COST ESCALATION FACTORS... R ,
D-i
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LIST OF TABLES
Tab1e Page
2-1 CAPITAL COST COMPONENTS 2-3
2-2 CALCULATION OF INTEREST COSTS DURING CONSTRUCTION 2-4
2-3 CONSTRUCTION PERIODS AND INTEREST DURING
CONSTRUCTION FACTORS 2-5
2-4 WORKING CAPITAL CALCULATIONS FOR BOILERS AND CONTROL
DEVICES 2-7
2-5 OPERATING AND MAINTENANCE COST COMPONENTS 2-8
2-6 UNIT COSTS USED IN CALCULATIONS 2-9
2-7 CAPACITY UTILIZATION AND LABOR FACTORS USED FOR
MODEL BOILER COST CALCULATIONS 2-11
2-8 ANNUALIZED COST COMPONENTS 2-12
2-9 DIRECT O&M COST MULTIPLIERS TO ACCOUNT FOR ECONOMIES
ASSOCIATED WITH MULTIPLE BOILER INSTALLATIONS.'.....' 2-15
2-10 SPECIFICATIONS FOR COAL-FIRED MODEL BOILERS 2-16
2-11 SPECIFICATIONS FOR RESIDUAL OIL-FIRED MODEL BOILERS 2-17
2-12 GENERAL DESIGN SPECIFICATIONS FOR PM CONTROL SYSTEMS 2-18
2-13 NOY COMBUSTION MODIFICATION EQUIPMENT REQUIREMENTS
ORXMODIFICATIONS 2-20
2-14 GENERAL DESIGN SPECIFICATIONS FOR FGD SYSTEM FOR
S02 CONTROL 2-21
2-15 CONTINUOUS EMISSION MEASUREMENT COSTS 2-23
2-16 REGIONAL FUEL PRICES IN $106 BTU 2-25
3-1 SPECIFICATIONS FOR COAL DELIVERED TO REGION V AND
REGION VIII 3_2
3-2 PM/S02 CONTROL COSTS FOR A 44 MW (150 MILLION BTU/HR)
BOILER IN REGION V 3.3
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LIST OF TABLES (Continued)
Table
3-3 CAPITAL COST OF S02 CONTROL IN REGION V 3.5
3-4 O&M COSTS FOR A 29 MW (100 MILLION BTU/HR) MODEL
BOILER IN REGION V 3.7
3-5 O&M COSTS FOR A 44 MW (150 MILLION BTU/HR) MODEL
BOILER IN REGION V 3_8
3-6 O&M COSTS FOR A 73 MW (250 MILLION BTU/HR) MODEL
BOILER IN REGION V 3.9
3-7 O&M COSTS FOR A 117 MW (400 MILLION BTU/HR) MODEL
BOILER IN REGION V 3_10
3-8 ANNUALIZED COSTS OF SO, CONTROL FOR A 29 MW (100 MILLION
BTU/HR) MODEL BOILER IN REGION V 3_H
ANNUALIZED COSTS OF SO, CONTROL FOR A 44 MW (150 MILLION
BTU/HR) MODEL BOILER IN REGION V
3-9
- — -__-_ ._ . _. „ , , —-w.ir.iwta i \s i \ f i r~i i i»i \ ± *J \J (l^l^Lv^VJIf
f"» Tl I / l l r\ \ » j /M~s i—i n /^ v i *» **. ~r L-. n _• ^ . A . .
. 3-12
3-10 ANNUALIZED COSTS OF SO, CONTROL FOR A 117 MW (250 MILLION
BTU/HR) MODEL BOILER IN REGION V 3-13
3-11 ANNUALIZED COSTS OF SO, CONTROL FOR A 117 MW (400 MILLION
BTU/HR) MODEL BOILER IN REGION V 3-14
3-12 CAPITAL COST OF S02 CONTROL IN REGION VII 3-16
3-13 O&M COSTS IN REGION VIII 3_17
3-14 ANNUALIZED COSTS OF S02 CONTROL IN REGION VIII 3-18
4-1 SPECIFICATIONS FOR RESIDUAL OILS DELIVERED TO REGION V
AND REGION VIII 4_2
4-2 CAPITAL COSTS OF SO, CONTROL FOR RESIDUAL OIL-FIRED
MODEL BOILERS f 4.4
4-3 O&M COSTS OF S02 CONTROL FOR MODEL BOILERS IN REGION V.... 4-5
4-4 ANNUALIZED COSTS OF SO, CONTROL FOR RESIDUAL OIL-FIRED
MODEL BOILERS IN REGION V 4-6
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LIST OF FIGURES
Fl'9ure Page
2-1 FEDERAL REGIONS OF THE UNITED STATES 2-26
VI
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1.0 INTRODUCTION
This report presents a cost analysis of alternative sulfur dioxide
(S02) controls on coal- and residual oil-fired industrial boilers in EPA
Regions V (Midwest) and VIII (North Central). Alternative S02 controls
examined included the use of various low-sulfur fuels and flue gas
desulfurization (FGD) techniques. For each alternative control method, the
capital costs, operating and maintenance costs, and annualized costs are
presented.
Chapter 2 discusses the methodologies and cost bases for estimating
boiler and control costs. Chapter 3 presents the capital and annualized
costs for coal-fired model boilers, and Chapter 4 presents costs for
residual oil-fired model boilers.
Two appendices are also included for reference. Appendix A is a
listing of the cost algorithms used to estimate the boiler, PM control, S02
control, and N0x control costs. These algorithms are all based on mid-1978
dollars. The cost basis used in this report corresponds to January 1983
dollars. The factors used to convert algorithm costs to this later basis
are presented in Appendix B. Appendix B also provides factors for adjusting
report costs to other bases selected by the reader.
1-1
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2.0 COSTING METHODOLOGY
This chapter presents the methodologies and bases used to calculate the
costs of model boilers and S02 controls presented in Chapters 3 and 4 of
this report. Section 2.1 discusses the basic costing approach used in
calculating capital, operating and maintenance, and annualized costs for
boilers and control devices. The specific equipment specifications used to
calculate the model boiler and control device costs are presented in
Section 2.2. Lastly, Section 2.3 discusses other cost considerations such
as continuous emission measurement costs, FGD malfunction costs, and
regional cost differences.
2.1 COSTING APPROACH
In this report, the cost impacts of applying S02 controls to various
types and sizes of industrial boilers are assessed through an analysis of
"model boilers". These model boilers are selected to represent the
population of new industrial boilers expected to be built in the future, and
thus cover a range of boiler sizes, fuel types, and S02 control methods.
The costs of each model boiler can be broken down into three major cost
categories:
Capital Costs (total capital investment required to construct
and make operational a boiler and control systems),
Operation and Maintenance (O&M) costs (total annual cost
necessary to operate and maintain a boiler and control
systems), and
Annualized Costs (total O&M costs plus annualized capital-related
charges).
Each of these cost categories can be further subdivided into individual cost
components. Sections 2.1.1, 2.1.2, and 2.1.3 present the individual cost
2-1
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components and the methods used to develop the capital, O&M, and annualized
costs, respectively, for each of the model boilers.
2.1.1 Capital Costs
Table 2-1 presents the individual components of capital cost and the
general methodology used for calculating total capital costs. Direct
capital costs consist of the basic and auxiliary equipment costs in addition
to the labor and material required to install the equipment. Equipment and
installation costs for boilers and control systems are calculated using the
algorithms presented in Appendix A. Section 2.2 of this report discusses
the bases for each of these algorithms.
Other capital cost components are calculated using the factors shown in
Table 2-1. Indirect costs are those costs not attributable to specific
equipment items. Contingencies are included in capital costs to compensate
for unpredicted events and other unforeseen expenses. However, in some
cases, factors for indirect costs and contingencies different from those
shown in Table 2-1 may be used. For example, in the cases of dual alkali
and dry scrubbing FGD systems for boilers with heat inputs of 58 MW (200
million Btu/hr) or less, engineering costs are calculated as 10 percent of
the total direct costs for an FGD system applied to a 58 MW (200 million
Btu/hr) boiler. And for sodium scrubbing FGD systems, turnkey capital costs
are calculated directly, based on vendor and plant cost data.
The interest cost incurred during the period of construction of the
boiler and associated control equipment is also included in the boiler total
capital costs as a function of the turnkey capital cost. It is assumed that
payment terms for boilers and control equipment typically consist of a down
payment of approximately 20 percent of the turnkey capital cost with the
balance paid in equal progress payments over the period of construction and
startup. The interest cost is a function of turnkey cost, interest rate,
period of construction and total number of equal progress payments. The
equations used to calculate interest cost are shown in Table 2-2. Table 2-3
lists the construction period and the interest during construction factors
as a function of turnkey capital cost.
2-2
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TABLE 2-1. CAPITAL COST COMPONENTS3
(1) Direct Costs
Equipment
+ Installation
= Total Direct Costs
(2) Indirect Costs
Engineering (10 % of total direct costs)b
+ Construction and Field Expenses (10% of total direct costs)5
+ Construction Fees (10% of total direct costs):
+ Start Up Costs (2% of total direct costs)5
+ Performance Costs (1% Of total direct costs)0
= Total Indirect Costs
(3) Contingencies5 = 20% of (Total Indirect + Total Direct Costs)
(4) Total Turnkey Cost = Total Indirect Cost + Total Direct Cost +
Contingencies
(5) Interest During Construction
(6) Working Capital6
(7) Landf
(8) Total Capital Cost = Total Turnkey + Interest During Construction +
Working Capital + Land
Boiler and each control system costed separately; factors apply to cost of
boiler or control system considered; i.e., the engineering cost for the PM
control system is 10% of the direct cost of the PM control system.
Reference 1.
GReference 2.
dSee Tables 2-2 and 2-3.
eSee Table 2-4.
Land costs for boiler and control system are included in capital cost of
boiler.
2-3
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TABLE 2-2. CALCULATION OF INTEREST COSTS DURING CONSTRUCTION3
Assume: interest (i) = 10 percent effective annual rate
terms = 20 percent of total turnkey capital cost paid at
contract award and balance paid in equal monthly installments
over the period of construction.
Future value of the 20 percent down payment is found by using the compound
interest law or,
S = P (1 + i)n, where S = Future Value
P = Present Worth
n = Number of years
Future value of the equal monthly installments is calculated by the
following equation:
R(l + i/m)"1" - 1 R = Equal payment = P/np
(1 + i/m) - 1 m = No. of times corpounded per year = 1
n = No. of years (see Table 2-3)
P = No. of payments per year = 12
Combining the two equations yields,
p (I + i/m)" - 1
s = 0.2 P U .i )"* o.so-
Reference 3 and 4.
2-4
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TABLE 2-3. CONSTRUCTION PERIODS AND INTEREST-DURING-CONSTRUCTION FACTORS
Boiler or Control Equipment
Approximate
Construction
Period
(Months)3
Interest During
Construcjtion
Factor0
Boilers and NO Control:
For Packaged Oil and Gas-fired Boilers 12
For Field-erected Oil and Gas Boilers 18
For Coal-fired Boilers _<_ 150 MM Btu/hr 20
For Coal-fired Boilers > 150 MM Btu/hr 24
For PM Control:
For Q £ 150 MM Btu/hr 8
For Q > 150 MM Btu/hr 11
For SOp Control:
Sodium Scrubbing: all sizes 6.75
Dry Scrubbing: all sizes 27
Dual Alkali: all sizes 27
IDC = 0.056 * TKc'd
IDC = 0.087 * TK
IDC = 0.095 * TK
IDC = 0.120 * TK
IDC = 0.036 * TK
IDC = 0.051 * TK
IDC = 0.030 * TK
IDC = 0.137 * TK
IDC = 0.137 * TK
Reference 3.
All factors are based on 10% effective annual interest rate.
r
"IDC = interest costs during construction.
TK = turnkey capital cost.
2-5
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Costs of land for the boiler and control system are all included in
boiler capital costs. All model boilers except pulverized coal boilers are
assumed to require one acre of land and have land costs of $2,800. Pulver-
ized coal boilers are assumed to require two acres of land and have land
costs of SS./OO.1
The computation of working capital requirements for fuel and non-fuel
items differs slightly as shown in Table 2-4. These equations are based on
three months of direct annual non-fuel operating costs and one month of fuel
costs.
2.1.2 Operation and Maintenance (O&M) Costs
Table 2-5 lists the individual cost components and the general
methodologies used in calculating total O&M costs. Direct O&M costs include
operating, supervisory, and maintenance labor, fuel, utilities, replacement
parts, supplies, waste disposal and chemicals. Direct O&M costs for model
boilers and control systems are calculated using the algorithms presented in
Appendix A. Indirect operating costs include payroll and plant overhead and
are calculated based on a percentage of some key O&M cost components (e.g.
operating labor, supervisory labor, maintenance labor, and replacement
parts). •
Table 2-6 presents the unit costs for utilities, raw materials, waste
disposal, and labor used in calculating non-fuel O&M costs for the boilers
and control equipment. The largest O&M cost for boilers is fuel. Fuel
costs and specifications such as heating value, sulfur content, and ash
content for coals and residual oils used in this analysis are presented in
Chapters 3 and 4, respectively.
Operating and maintenance costs incurred are dependent upon the boiler
capacity utilization, defined as the actual annual fue1 consumption as a
percentage of the potential annual fuel consumption at maximum firing rate.
Fuel costs, raw material costs, utility costs, and waste disposal costs
decrease in direct proportion to the capacity utilization factor. However,
labor costs do not decrease in direct proportion due to shift manpower
requirements. In order to account for reduced labor costs for boilers
2-6
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TABLE 2-4. WORKING CAPITAL CALCULATIONS FOR BOILERS AND CONTROL DEVICES
Working Capital (WC)
Boilers - Assume three months of direct annual non-fuel operating costs
and one month of fuel costs
WC = 0.25 (Direct annual non-fuel operating costs) +
0.083 (Fuel costs)
Control Equipment - Assume three months of direct annual operating costs
WC = 0.25 (Direct annual operating costs)
Reference 5.
Reference 1.
2-7
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TABLE 2-5. OPERATING AND MAINTENANCE COST COMPONENTS
a
(1) Direct Operating Costs
Operating Labor
+ Supervision
+ Maintenance Labor, Replacement Parts and Supplies
+ Electricity
+ Water
+ Steam
+ Waste Disposal
Solids (Fly ash and bottom ash)
Sludge
Liquid
+ Chemicals
Total Non-Fuel O&M
+ Fuel
= Total Direct Operating Costs
(2) Indirect Operating Costs (Overhead)13
Payroll (30% Operating Labor)
+ Plant (26% of Operating Labor -t- Supervision + Maintenance Costs
+ Replacement Parts)
(3) Total Annual Operating and Maintenance Costs = Total Direct +
Total Indirect Costs
aBoilers and control systems are costed separately; factors apply to boiler
or control system being considered, (i.e., payroll overhead for FGD system
is 30°; of the labor requirement for the FGD system).
Factors recommended in Reference 6.
2-8
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TABLE 2-6 UNIT COSTS USED IN CALCULATIONS3'13
Utilities
Electricity
Water
Steam
Raw Materials
Na2C03
Lime
Limestone
Labor
S0.0390/Kwh
$0.06/m3 (SO.23/103 gal)
S4.55/GJ (S5.3/103 Ib)
$0.150/kg ($136/ton)
$0.059/kg ($53/ton)
$0.014/kg ($12/ton)
$18.15/man-hour
$23.60/man-hour
$22.09/man-hour
Direct Labor
Supervision
Maintenance Labor
Waste Disposal
Solids (Ash, Spray Dried Solids) $0.0251/kg ($23/ton)
Sludge $0.0251/kg (S23/ton)
Liquid
$0.88/m3 (SO.60/103 gal)
All costs in January 1983 S. Updated from 1978 using a multiplier 01
1.51 (see Appendix B).
Reference 7.
2-9
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operating at reduced capacity utilization, the algorithms also incorporate
labor factors. Table 2-7 presents the capacity utilization factors and
corresponding labor factors assumed for various model boilers.
2.1.3 Annualized Costs
Total annualized costs are the sum of the annual O&M costs and the
annualized capital charges. The annualized capital charges include the
payoff of the capital investment (capital recovery), interest on working
capital, general and administrative costs, taxes (real estate and local
taxes but not corporate taxes), and insurance.
Table 2-8 presents the methods used in this report to calculate the
individual annualized capital charge components. The capital recovery cost
is determined by multiplying the capital recovery factor, which is based on
the real interest rate and the equipment life, by the total turnkey costs
(see Table 2-8). For this analysis a 10 percent real interest rate and a
15 year equipment life are assumed for the boilers and control equipment.
This translates into a capital recovery factor of 13.15 percent. The real
interest rate of 10 percent was selected as a typical constant dollar rate
of return on investment to provide a basis for calculation of capital
recovery charges. This interest rate is the Veal" interest rate above and
beyond inflation.
Table 2-8 also presents the methods used to calculate other components
of the annualized capital charges. Interest on working capital is based on
a 10 percent interest rate. The remaining components (general and
administrative costs, taxes, and insurance) are estimated as 4 percent of
total turnkey costs.
2.2 BOILER AND CONTROL DEVICE SPECIFICATIONS
Direct capital and direct O&M costs for model boilers and PM, NO , and
A
S02 control techniques are estimated in this report by the use of cost
"algorithms". Each algorithm is an algebraic function which projects
capital and O&M costs for a particular system based on key process
2-10
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TABLE 2-7. CAPACITY UTILIZATION AND LABOR FACTORS USED
FOR MODEL BOILER COST CALCULATIONS3
Capacity
Boiler Type Utilization Factor (CF) Labor Factor (LF)
Coal-fired 0.60 0.75
(Spreader stoker,
pulverized coal)
Residual oil-fired 0.55 0.62
Labor Factor Equations
CF LF
>0.7 1
0-5 - 0.7 0.5 + 2.5 (CF - 0.5)
<0.5 0.5
References 5 and 8.
2-11
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TABLE 2-8. ANNUALIZED COST COMPONENTS
(1) Total Annualized Cost = Annual O&M Costs + Capital Charges
(2) Capital Charges = Capital recovery + interest on working capital +
miscellaneous (G&A, taxes and insurance)
(3) Calculation of Capital Charges Components
A. Capital Recovery = Capital Recovery Factor (CRF) x Total Turnkey
Cost
CRF-1 (1 + 1^
i = interest rate
n = number of years of useful life of boiler or control system
Item n i CRF
Boiler, control systems 15 10 0.1315
B. Interest on Working Capital = 10% of working capital3
C. G&A, taxes and insurance = 4" of total turnkey cost3
Reference 1.
2-12
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parameters (e.g., heat input to boiler, S02 removal efficiency, capacity
utilization factor, flue gas flow rate). The boiler and emission control
costing algorithms used in this report are provided in Appendix A. It
should be noted that the algorithms in Appendix A are given in 1978 dollars.
The cost factors used to update the 1978 estimates to January 1983 dollars
are presented in Appendix B. It should also be noted that all algorithms
are based on a Midwest (i.e., Region V) boiler location. However, these
algorithms can be used to predict costs in any other region of the U.S. (see
Section 2.3.3 for discussion of regional cost differences).
The battery limits of the boiler extend from the fuel-receiving
equipment to the ash disposal operation. Excluded are steam and condensate
piping beyond the boiler building. Costs of ducting and the stack are also
included in the battery limits of the boiler. Battery limits of the PM,
N0x, and S02 emission control systems include the control devices
themselves, auxiliaries, raw material handling, waste disposal, and any
additional ducting required. The specific equipment lists and assumptions
used to develop the various algorithms are discussed in the following
sections.
2.2.1 Uncontrolled Boiler Costs
This section presents the specific cost assumptions and methodologies
that were used to calculate the industrial boiler costs presented in
Chapters 3 and 4. References 8 and 9 detail the specific equipment lists
and assumptions used to develop the boiler algorithms presented in
Appendix A (Tables A-4 through A-7).
All of the coal-fired model boilers in this analysis are field-erected
units. In addition, all coal-fired boilers have the same heat transfer
configuration ir, that they are watertube units, although the firing
mechanism varies according to size. Model boilers with heat inputs of less
than 73 MW (250 million Btu/hr) are assumed to be spreader stokers and
larger model boilers are assumed to fire pulverized coal. All of the
residual oil-fired model boilers in this analysis are package watertube
units designed with the capability of firing residual oil or natural gas.
2-13
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All boiler costs are based on a new boiler constructed at a new plant
in the Midwest. It is assumed that new plants will operate multiple boilers
rather than one boiler where economically justified. Annual O&M costs such
as labor, utilities, chemicals, spare parts and ash disposal will be reduced
per boiler because of the economies of scale. To account for the O&M cost
reductions associated with multiple boiler installations, multipliers for
the annual O&M costs are incorporated into the algorithms presented in
Appendix A. These multipliers are presented in Table 2-9. These
multipliers are not included in the PM, NO. or S09 control algorithms,
X c.
however. It is assumed that a single PM and/or S02 control system will be
used at each facility regardless of the number of boilers used. And, the
major component of NOX control O&M costs is fuel cost (or savings), which
does not exhibit economies of scale.
The boiler specifications presented in Tables 2-10 and 2-11 have been
used to calculate the boiler capital costs presented in this report. It is
assumed that all boilers operate under low excess air firing conditions.
The flue gas flow rates for various model boilers are calculated using the
algorithms presented in Appendix A (Table A-15).
2.2.2 Particulate Matter (PM) Control Costs
The algorithm used to calculate capital and operating costs for PM
control on coal-fired boilers is presented in Appendix A (Table A-8). The
cost algorithm for reverse-air fabric filters for coal-fired boilers was
developed by PEDCo, Inc. Table 2-12 lists the general specifications for
a reverse-air fabric filter. It is assumed that no separate PM control is
required for residual oil-fired boilers; it is assumed that the small amount
of PM generally emitted by oil-fired boilers can be controlled through the
use of FGD systems for SO- control or through the use of low sulfur/low ash
oils.
2.2.3 NO,. Control Costs
A ^™™^—i «i
The algorithms used to calculate capital and operating costs for NO
A
control devices are presented in Appendix A (Tables A-12 through A-14). The
2-14
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TABLE 2-9. DIRECT O&M MULTIPLIERS TO ACCOUNT FOR ECONOMIES
ASSOCIATED WITH MULTIPLE BOILER INSTALLATIONS3
Coal-Fired Boilers:
Multiplier
Utilities, chemicals, and ash disposal 0.848
All labor, replacement parts, and overhead 0.767
Residual Oil-Fired Boilers:
Utilities and chemicals 0.845
All labor, replacement parts, and overhead 0.799
Reference 5.
2-15
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TABLE 2-10. SPECIFICATIONS FOR COAL-FIRED MODEL BOILERS
cr>
Thermal input, MW
(10° Btu/hr)
Fuel firing method
Excess air, %
Flu^ gas flow rate,d
m /s (acfm)
Load factor, %
Efficiency (%)
Steam quality
Pressure, kPa (psig)
Temperature, °k (°F)
29.0 (100) 44.0 (150) 73.0 (250) U7.2 (400)
Spreader stoker Spreader stoker Pulverized coal Pulverized coal
35 35 35 35
Dependent upon coal heatimj value.
60
80.0
3100 (450)
590 (600)
— ._
60
80.9
3100 (450)
590 (600)
— ' , .
60
82.0
5170 (750)
670 (750)
60
83.1
5170 (750)
670 (750)
See Table A-k, u, calculate flue gas flow rate for various coal types.
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TABLE 2-11. SPECIFICATIONS FOR RESIDUAL OIL-FIRED MODEL BOILERS
ro
i
t—•
-j
Thermal input, MW (106 Btu/hr)
Excess air, %
Flue gas flow rate, m3/s (acfni)a
Load factor, %
Efficiency (%)
Steam quality
Pressure, kPa (psig)
Temperature, °K (°F)
5170 (750)
670 (750)
5170 (750)
670 (750)
Based on a heating value of 43,000 kJ/kg (18,500 Btu/lb).
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r\>
i—*
oo
TABLE 2-12. GENERAL DESIGN SPECIFICATIONS FOR PM CONTROL SYSTEMS
Control Device Item
Specification
Fabric Filter Material of Construction Carbon steel (insulated)
(FF) for coal-fired boilers Cleaning method Reverse-air (multi-compartment)
Air to cloth ratio 2 ft/min
Bag material Teflon-coated fiberglass
Bag life 2 years
Pressure drop 6 in. H90 gauge
a
Pressure drop refers to gas-side pressure drop across entire control system.
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cost algorithms for low excess air (LEA) operation, and staged combustion
(SCA) were developed by Radian based on costs presented in the Individual
Technology Assessment Report (ITAR) for NO Combustion Modification.11
A
Table 2-13 presents the general specifications for LEA and SCA.
2.2.4 SOp Control Costs
The cost algorithms used to calculate capital and annual operating
costs for flue gas desulfurization units are also presented in Appendix A
(Tables A-9 through A-ll). The cost algorithms are based on information
presented in the FGO ITAR and Reference 12, but are not exact
representations of these costs. The ITAR costs were modified to reflect
revised installation factors for double alkali FGD systems and revised
fabric filter costs for spray drying FGD systems.13'14 A revised cost
algorithm for sodium scrubbing FGD systems was developed based on
information received from vendors and plants;15 this algorithm also includes
wastewater treatment costs.16'17
The cost algorithms used to estimate FGD capital costs are based on
shop-fabricated, or packaged, FGD units.13 These algorithms were developed
using techniques consistent with typical "budget-cost" estimates provided by
vendors to clients in the preliminary stages of project evaluation. These
estimates are considered accurate to within ±30 percent of the actual
installed costs of FGD systems.
Table 2-14 presents the general specifications for the FGD systems
analyzed in this report. These specifications are typical for FGD systems
currently in use.
2.3 OTHER COST CONSIDERATIONS
This section addresses additional cost considerations that may be
incurred by boiler operators and/or regulatory agencies that have not been
addressed in Section 2.2. Section 2.3.1 presents costs associated with
continuous emission measurement, Section 2.3.2 presents the costs of
2-19
-------
TABLE 2-13. N0v COMBUSTION MODIFICATION EQUIPMENT REQUIREMENTS OR MODIFICATIONS
A
Control Device
Low Excess Air (LEA)
Specification
Oxygen trim system - 0? analyzer, air flow
regulators
Wind box modifications (may be required for
multi-burner boilers)
Staged Combustion Air (SCA)
Pulverized coal-fired boilers:
Residual oil-fired builers:
Oxygen trim system - 0~ analyzer, air flow
regulators
Air ports
Wind box modifications
Larger forced draft fan power
Oxygen trim system - 0~ analyzer, air flow
regulators
Up to 30 percent larger boiler to accommodate
longer flame
-------
TABLE 2-14. GENERAL DESIGN SPECIFICATIONS FOR FGD SYSTEM FOR S02 CONTROL
Control Device
Item
Specification
Double Alkali FGD
(S09 removal only)
Scrubber type
Pressure drop3
L/G
Scrubber sludge
Sludge disposal
Tray tower
8 in. H90,
10 gal/foj acf
60% solids
Trucked to off-site landfill
Sodium Scrubbing FGD
(S09 removal only)
(SOD)
Scrubber type
Pressure drop3
L/G
Disposal method
Spray baffle
8 in. H90,
40 gal/TOJ acf
Oxidation and sewerage
Dry Scrubbing (spray
drying, SO^ and PM
removal)
(DS)
Material of construction
Reagent
Fabric filter
Pressure dropa
L/G
Solids disposal
Carbon steel spray dryer and fabric
filter (insulated)
Lime; with solids recycle at 2 kg
recycle solids/kg fresh lime feed
Pulse jeti air-to-cloth ratio of
4 acfm/ft
6 in. H20
0.3 gal/acf
Trucked to off-site landfill
All pressure drops refer to gas side pressure drop across entire control system.
-------
requiring S02 control during periods of FGD malfunction, and Section 2.3.3
discusses the impacts of regional cost differences.
2.3.1 Continuous Emission Measurement Costs
Table 2-15 presents estimates for continuous emission measurement costs
18
for opacity, NOX, and SO^. ° Costs are shown in January 1983 dollars. For
the purposes of this analysis, it is assumed that continuous NO monitors
are required on all coal- and residual oil-fired boilers with a heat input
capacity greater than 29 MW (100 million Btu/hour). Opacity monitors are
required for all boilers except those equipped with wet FGD systems. Units
with FGD are assumed to require continuous monitors for inlet and outlet S0?
and a diluent (CO^ or 02) monitor. Units without FGD are assumed to require
a single S02 monitor and a single diluent monitor at the outlet. An
automatic data reduction system is included as part of monitoring costs for
all model boilers. Continuous emission measurement costs shown in Table
2-15 are included in the total costs presented in subsequent chapters.
.2.3.2 FGD Malfunction Costs19
In order to maintain compliance with applicable emission requirements
during periods of FGD malfunction, several alternative methods of S02
control may be used. One alternative is to install a spare scrubbing unit
for operation during FGD malfunction. However, sparing is a capital
intensive alternative. Another alternative would be to fire low sulfur
fuels such as natural gas, low sulfur oil, or low sulfur coal during FGD
downtime. Nearly all new boilers will be designed for multi-fuel firing or
will be installed at facilities where spare natural gas or low sulfur
oil-fired boiler capacity is available. Therefore, there are essentially no
additional capital costs associated with the firing o^ natural gas or low
sulfur oil during malfunction.
Malfunction costs can vary as a function of boiler size, capacity
factor, type of FGD system, FGD system reliability and differential cost
between fuels fired during normal operation and during FGD malfunction. In
general, however, malfunction costs represent less than 3 percent of the
2-22
-------
TABLE 2-15. CONTINUOUS EMISSION MEASUREMENT COSTS (January 1983 $)a'b
Capital Cost
System ($1000)
Opacity
NO
X
S02 (outlet only)
S02 (inlet and outlet)
02/C02 (outlet only)
02/C02 (inlet and outlet)
57
57
44
64
9
18
0 & M Cost
($1000/yr)
8
36
36
72
8
15
Annual ized Cost
($1000/yr)
15
44
42
81
9
18
Reference 18.
See Section 2.3.1 for discussion of continuous emission measurement costs
assumed for each model boiler.
2-23
-------
total boiler annualized costs. In order to maintain consistency throughout
this report, it is assumed that FGD operators fire natural gas during
periods of malfunction. The FGD system reliability is assumed to be 95
20
percent. Malfunction costs are included in the total annualized costs in
subsequent chapters.
2.3.3 Regional Cost Considerations
Model boiler costs can vary on a regional basis due to differences in
fuel price, labor rates, utility rates, raw material costs, and waste
disposal costs. However, since fuel costs generally represent 50 to
75 percent of the total O&M costs for coal-fired boilers and 80 to
90 percent for residual oil-fired boilers, regional differences in fuel
price have a much greater impact on regional model boiler costs than do
non-fuel O&M components such as labor rates, etc.21 Table 2-16 shows how
fuel prices vary by Region and, for reference, Figure 2-1 depicts each
region geographically.
This report presents costs for coal-fired model boiler in Regions V and
VIII. As shown in Table 2-16, a large number of bituminous and
subbituminous coals are readily available in Region V. Generally, only low-
and medium-sulfur content bituminous and subbituminous coals are delivered
to Region VIII. Table 2-16 also shows that coal prices in Region V do not
differ significantly from prices in Regions I through VII. Coal prices in
Regions VIII, IX, and X are typically lower than in the other regions, with
Region VIII having the lowest prices anywhere in the U.S. Therefore,
Regions V and VIII were selected for analysis in this report - Region V
because it is representative of many other regions, and Region VIII because
it has significantly lower coal prices than any other region in the U.S.
Table 2-16 shows that regional variations in residual oil prices are not as
important as variations in coal prices. In addition, the premium price for
a low sulfur oil compared to high sulfur oil is essentially constant for all
regions. Therefore, this report presents costs for residual oil-fired model
boilers in Region V only. These costs should be representative of costs in
all regions.
2-24
-------
TABLE 2-16. REGIONAL FUEL PRICES IN $/106 BTU (JANUARY 1983 $)a>b>c
ro
i
ro
en
Sulfur Content .
Fuel Type (Ib S0?/10° Btu)a I
COAL
Bituminous
B 0.80 - 1.08
D 1.08 - 1.67
E 1.67 - 2.50
F 2.50 - 3.33
G 3.33 - 5.0
H >5.00
Subbi luminous
B 0.80 - 1.08
D 1.08-1.67
E 1.67-2.50
RESIDUAL OIL fi
0.8 Ib S02/10be 0.80
NATURAL GAS
aReference 22.
1990 level ized fuel prices in
cTo convert $/106 Btu to $/kJ,
To convert lb/10 Btu to ng/J
Subtract 10.70/106 Btu for 3.
0.37/10° Btu for 0.3 Ib S02
3.76
3.71
3.65
3.46
3.16
3.26
-
-
-
5.50
5.83
January 1983
multiply by
, multiply by
0 Ib S0,/106
/10° Btb oil.
II
3.52
3.45
3.30
3.13
2.82
2.85
-
-
-
5.49
5.79
dol lars
0.947.
430.
Btu oil;
III
3.14
2.94
2.85
2.75
2.42
2.39
-
-
-
5.49
5.73
subtract
IV
3.19
2.98
2.96
2.88
2.80
2.62
-
-
-
5.46
6.02
$0.38/ 106
REGION
V VI
3.32
3.18
3.08
2.93
2.67
2.50
3.38
3.34
3.30
5.63
5.88
Btu for
3.34
3.21
3.20
3.19
3.09
2.96
3.49
3.39
3.32
5.49
5.41
1.6 Ib
VII
3.14
3.08
3.04
2.92
2.62
2.47
2.74
2.69
2.72
5.60
5.45
S02/106 Btu
VIII IX
1.99 2.80
1.86 2.82
1.87 2.77
-
1.40 2.84
1.39 2.74
1.28 2.65
5.29 5.11
4.91 5.44
oil; add
X
3.18
2.97
2.84
-
2.66
2.60
2.09
5.07
5.57
-------
ro
i
ro
en
BostM
»
New Ywk City
Philadelphia
O.C.
f\f
-------
It was assumed that all costs other than fuel (capital charges,
non-fuel O&M costs) remain constant on a regional basis. Regional
variations in labor rates, utility rates, raw materials costs and waste
disposal costs can result in regional variations in absolute costs for any
given alternative. However, the purpose of this analysis is not to compare
the absolute costs of S02 control in various regions but rather to determine
the difference in cost between various alternatives within a given region.
In other words, the objective of this analysis is to determine the cost
difference between a given S02 control alternative and the baseline
alternative, and to determine whether that difference varies significantly
from region to region.
The incremental cost of one alternative as compared to another includes
differences in fuel prices and/or differences in the capital and operating
costs of FGD systems. The variation in FGD capital and operating costs from
region to region due to differences in labor rates, utility rates, raw
material costs, and waste disposal costs is small in comparison to
variations in regional fuel prices, and can therefore be neglected.21 For
this reason, the results presented here include only fuel price variations
and assume all other unit costs are equal on a regional basis.
2-27
-------
2.4 REFERENCES
1. Devitt, T., P. Spaite, and L. Gibbs. (PEDCo Environmental) Population
and Characteristics of Industrial/Commercial Boilers in the U.S.
(Prepared for U. S. Environmental Protection Agency.) Research
Triangle Park, N. C. EPA-600/7-79-78a. Cincinnati, Ohio
August 1979. 462 p.
2. Dickerman, J.C. and K.L. Johnson, (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Application: Flue Gas
Desulfurization. (Prepared for U. S. Environmental Protection Agency.)
Research Triangle Park, N. C. EPA-600/7-79-78c. November 1979
664 p.
3. Memo from Laughlin, J. H., and S. C. Margerum, E. F. Aul., Radian
Corporation, to C. B. Sedman, EPA/ISB. July 3, 1984. 6 p. Interest
during construction cost calculations.
4. Perry, R. H. Chemical Engineers' Handbook. Fifth ed. New York,
McGraw-Hill Book Company. 1973. p. 25-39.
5. Letter from Medine, E. S., Energy and Environmental Analysis, Inc. to
Short, R., EPA:EAB. September 14, 1981. 6 p. Comparison of IFCAM and
Radian Cost Algorithms for SCL and PM Control on Coal- and Oil-Fired
Industrial Boilers.
6. Reference 1, p. 117.
7. U. S. Environmental Protection Agency. Fossil Fuel Fired Industrial
Boilers - Background Information. Volume I. Research Triangle Park,
N. C. Publication No. 450/3-82-006a. March 1982. pp. 4-1 - 4-213.
8. PEDCo Environmental, Inc. Cost Equations for Industrial Boilers.
Final report. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. EPA Contract No. 68-02-3074.
January 1980. 22 p.
9. Reference 2, p. 118-122.
10. PEDCo Environmental, Inc. Capital and Operation Costs of Particulate
Controls on Coal- and Oil-Fired Industrial Boilers. (Prepared for
U.S. Environmental Protection Agency.) Research Triangle Park, N.C.
EPA-450/5-80-009. August 1980. 129 p.
11. Lim, K.J., et. al. (Acurex Corporation) Technology Assessment Report
for Industrial Boiler Applications: NO Combustion Modification.
(Prepared for U.S. Environmental Protection Aaency.) Research Triangle
Park, N.C. EPA-600/7-79-178f. December 1979!
2-28
-------
12. Gardner, R., R. Chang, and L. Broz. (Acurex Corporation.) Cost,
Energy and Environmental Algorithms for NO , SCL, and PM Controls for
Industrial Boilers. Final Report. (Prepared f6r U. S. Environmental
Protection Agency.) Cincinnati, Ohio. EPA Contract No. 68-03-2567
December 1979. p. 20-52.
13. Memo from Aul, E.F., M.A. Palazzolo, and R.S. Berry, Radian
Corporation, to C.B. Sedman, EPA/ISB, May 16, 1983. Revised Cost
Algorithms for Lime Spray Drying and Dual Alkali FGD Systems.
14. Letter from Berry, R.S. (Radian Corporation) to C.B. Sedman (EPA/ISB)
Changes to FGD Cost Algorithms. July 5, 1983.
15. Berry, R. S., and G. S. Shareef, Radian Corporation. Sodium Scrubbing
Cost Algorithm Development. February 7, 1984.
16. Berry, R. S., Radian Corporation. Update of the Sodium Scrubber
Wastewater Issue. January 24, 1984.
17. Berry, R. S., Radian Corporation. S0? Re-emissions from the Sodium
Scrubbing Wastewater Stream in Aerobic Environments. May 31, 1984.
18. Dicker-man, J.C. and M.E. Kelly. "Issue Paper: Compliance Monitoring
Costs." Radian Corporation. Durham, N.C. September 25, 1980. 20 p.
19. Memo from Margerum, S. C., Radian Corporation, April 6, 1984, to
Sedman, C. B., EPA/ISB. FGD System Malfunction Costs.
20. Radian Corporation. SO. Technology Update Report. Final. (Prepared
for U.S. Environmental Protection Agency). Research Triangle Park
N.C. EPA Contract No. 68-02-3816. July 21, 1984. p. 2-30.
21. Margerum, S. C. and J. A. Maddox. An Analysis of Regional Coal and
Residual Oil Model Boiler Costs. Radian Corporation. Durham, N C
January 6, 1984.
22. Projected Environmental, Cost and Energy Impacts of Alternative SO
NSPS for Industrial Fossil Fuel-fired Boilers. (Prepared for U. S~
Environmental Protection Agency). Energy and Environmental Analysis
Arlington, Virginia. July 27, 1984. pp. 9-10.
2-29
-------
3.0 COST OF S02 CONTROL ON COAL-FIRED MODEL BOILERS
This chapter presents the results of an analysis of S02 control costs
for coal-fired model boilers in Region V and in Region VIII. Capital and
annualized costs are examined for boilers with no S02 control (baseline) and
for boilers equipped with FGD systems achieving 50 percent, 70 percent, and
90 percent S02 removal. Costs are examined for several boiler sizes and for
numerous coal types. The boiler sizes selected for this analysis are 29,
44, 73 and 117 MW (100, 150, 250 and 400 million Btu/hr) heat input.
Specifications and prices of coals delivered to Region V and to Region
VIII are presented in Table 3-1. To maintain consistency with the
Industrial Fuel Choice Analysis Model (IFCAM), which is used to project the
national impacts of alternative S02 standards, the values in Table 3-1 are
projections for 1990 delivered fuel prices expressed in January 1983
dollars. The projections ignore the effects of inflation but assume that
fuel prices will escalate in real terms. In addition, the fuel prices have
been "levelized" over the life of the boiler (i.e., an equivalent constant
price has been calculated after allowing for escalation and the time value
of money).
The PM and N0x controls examined are the same under the baseline and
for each of the S02 control alternatives selected. All model boilers are
assumed to require a fabric filter for particulate matter control. Spreader
stoker boilers [boilers with heat inputs of less than 73 MW (250 million
Btu/hr)] are assumed to require the use of low-excess air (LEA) operation
for N0x control and pulverized coal boilers [boilers with heat inputs of 73
MW (250 million Btu/hr) or greater] are assumed to require staged combustion
air (SCA) operation in addition to LEA.
Several types of FGD systems are available for control of S0? from
industrial boilers, including double alkali, sodium scrubbing, and dry
scrubbing FGD. Table 3-2 presents the costs for a 44 MW (150 million
Btu/hr) boiler in Region V for each of the FGD systems above for two coal
types. The same relative relationships as those shown in Table 3-2 would
3-1
-------
TABLE 3-1. SPECIFICATIONS FOR COAL DELIVERED TO REGION V AMD REGION VIIIa
Coal
Type
Region V:
B-sub
D-sub
E-sub
B-bit
D-bit
E-bit
F-bit
G-bit
H-bit
Region VIII:
B-sub
D-sub
E-sub
B-bit
D-bit
E-bit
Uncontrolled SO,,
Ng/J (lb/10 BtO)
409 (0.95)
624 (1.45)
903 (2.10)
409 (0.95)
624 (1.45)
903 (2.10)
1,226 (2.85)
1,785 (4.15)
2,382 (5.54)
409 (0.95)
624 (1.45)
903 (2.10)
409 (0.95)
624 (1.45)
903 (2.10)
Fuel Price
$/kJ ($/lO° Btu)
3.20 (3.38)
3.16 (3.34)
3.13 (3.30)
3.14 (3.32)
3.01 (3.18)
2.92 (3.08)
2.77 (2.93)
2.53 (2.67)
2.37 (2.50)
1.33 (1.40)
1.32 (1.39)
1.22 (1.28)
1.88 (1.99)
1.76 (1.86)
1.77 (1.87)
Heating Value
kJ/kg (Btu/lb)
20,524 (8,825)
20,524 (8,825)
20,524 (8,825)
29,000 (12,500)
29,300 (12,600)
27,400 (11,800)
26,700 (11,500)
26,700 (11,500)
27,200 (11,700)
20,400 (8,770)
20,000 (8,620)
20,000 (8,620)
25,300 (10,900)
23,900 (10,300)
23,900 (10,300)
Sulfur
Content
Wt. %
0.42
0.64
0.93
0.60
0.91
1.24
1.64
2.38
3.23
0.42
0.63
0.91
0.52
0.75
1.08
Ash
Content
Wt. %
6.9
6.9
6.9
11.0
11.0
10.5
10.9
12.2
12.0
8.4
6.9
6.9
10.0
10.0
10.0
Reference 1.
b!990 levelized fuel price in 1983 $.
-------
CO
i
CO
TABLE 3-2. PM/SO? CONTROL COSTS FOR A 44 MW (150 MILLION BTU/HR) MODEL BOILER IN REGION Va'b
(JAN 1983 $)
Sodium Scrubbing0
Capital Cost ($1000):
High Sulfur Bituminous Coal6
Low Sulfur Subbituminous Coal
Annual ized Cost ($1000/yr):
High Sulfur Bituminous Coal6
Low Sulfur Subbituminous Coal
Fabric
Filter
1,549
1,607
419
440
FGD
919
698
919
458
Total
2,468
2,305
1,338
898
Dry Scrubbing
Total
3,102
2,617
1,504
1,095
Fabric
Filter
1,549
1,607
419
440
Double Al
FGD
2,403
1,894
1,171
811
kalic
Total
3,952
3,501
1,590
1,251
Includes applicable monitoring costs as shown in Table 2-15.
Includes FGD malfunction costs.
°Assumes 95 percent FGD reliability.
Assumes 90 percent FGD reliability.
6Heating value = 27,200 kJ/kg (11,700 Btu/lb); Sulfur content = 3.23 wt. %; Ash content 12.0 wt. '
Uncontrolled S02 = 2380 ng/J (5.54 lb/10 Btu).
Heating value = 20,500 kJ/kg (8,825 Btu/lb); Sulfur content = 0.42 wt. %; Ash Content 6.9 wt. %;
Uncontrolled S02 = 409 ng/J (0.95 lb/10 Btu).
-------
exist for other regions and other boiler sizes. Dry scrubbing FGD systems
are designed for combined control of S02 and particulate matter, whereas
sodium scrubbing and double alkali FGD systems are designed for SCL control
only. For this reason, Table 3-2 also shows the cost of a fabric filter for
particulate matter control for sodium scrubbing and double alkali FGD
systems. Table 3-2 shows that the capital and annualized costs of sodium
scrubbing are lowest for both high and low sulfur coals. Also the capital
and annualized costs of double alkali are highest for both coal types. In
general, dry scrubbing costs fall between the costs of sodium scrubbing and
dual alkali. In order to maintain consistency throughout this report, all
FGD costs are based on sodium scrubbing. Sodium scrubbing is currently the
most widely used FGD technology and its costs are considered representative
of FGD costs in general.
3.1 REGION V COSTS
3.1.1 Capital Costs
The capital costs presented in this report are based on the assumption
that industrial boilers will be designed specifically to fire either
bituminous or subbituminous coal. The FGD system capital costs reflect the
current practice of industrial boiler owners to design and install FGD
systems capable of achieving 90 percent SO^ removal on the highest sulfur
coal available in order to provide maximum fuel firing flexibility.
Table 3-3 presents the capital costs of S02 control for 29, 44, 73, and
117 MW (100, 150, 250, and 400 million Btu/hr) model boilers firing
bituminous and subbituminous coals. Capital costs for boilers at the
baseline firing subbituminous coals are higher than for those firing
bituminous coals due to the lower heating value of subbituminous coals
which, in turn, require larger boilers in order to achieve the same heat
input. Total capital costs for boilers equipped with FGD systems are also
higher for subbituminous coals than for bituminous coals.
3-4
-------
TABLE 3-3. CAPITAL COST OF SO- CONTROL IN REGION V ($1000) (JAN 1983 $)a
Boiler Size/
Coal Classification
29 MW (100 million Btu/hr)
Bituminous
Subbituminous
44 MW (150 million Btu/hr)
Bituminous
Subbituminous
73 MW (250 million Btu/hr)
Bituminous
Subbituminous
117 MW (400 million Btu/hr)
Bituminous
Subbituminous
Baseline
10,106
10,998
14,050
15,200
24,026
25,023
33,154
34,379
With FGDC
10,787
11,561
14,899
16,001
25,142
25,943
34,616
35,578
Includes applicable monitoring costs as shown in Table 2-15.
Baseline costs include PM/NO control costs.
A
Based on sodium scrubbing FGD.
3-5
-------
3.1.2 Annual O&M Costs
Tables 3-4 through 3-7 present the annual O&M costs of SCL control for
the various boiler sizes examined. These tables show that, at the baseline,
fuel costs represents 50 to 60 percent of the total O&M costs for a 29 MM
(100 million Btu/hr) boiler and 60 to 70 percent of the total for a 117 MW
(400 million Btu/hr). For the 90 percent S02 removal cases, fuel costs
represent about 45 to 55 percent of the total O&M costs for a 29 MW (100
million Btu/hr) boiler and about 55 to 65 percent of the total for a 117 MW
(400 million Btu/hr) boiler. As expected, these tables show that the annual
O&M costs at the baseline for bituminous coals increase with increasing fuel
price for all boiler sizes. The annual O&M costs at the baseline for
subbituminous coals are generally comparable to costs for medium sulfur
bituminous coals (Types D, E, and F coals). As expected, the annualized
cost of S02 control for boilers equipped with FGD systems increases with
increasing coal sulfur content. However, total O&M costs for boilers
equipped with FGD control generally track fuel price rather than sulfur
content, indicating the importance of fuel price in estimating SCL control
costs.
3.1.3 Annualized Costs
As discussed in Section 2.1.3, annualized costs are calculated as the
sum of annualized capital-related charges and annual O&M costs. Tables 3-8
through 3-11 present the annualized costs of SO- control for the various
boiler sizes and coal types examined.
These tables show that the difference in annualized costs of S0«
control for 50 percent, 70 percent, and 90 percent FGD for a particular coal
type is relatively small when compared to the total annualized costs of the
boiler. These tables further show that, as expected, the annualized cost of
SO- control increases with increasing coal sulfur content. However, the
total annualized costs generally track fuel price rather than sulfur
content, such that the total annualized costs of 90 percent FGD are lowest
for a Type H coal for all boiler sizes examined.
3-6
-------
TABLE 3-4. 0 & M COSTS FOR A 29 MW (100 MILLION BTU/HR) MODEL BOILER IN REGION Va
($1000/YR) (JAN 1983 $)
Coal Type
Type B -
Type D -
Type E -
Type F -
Type G -
-------
TABLE 3-5. 0 & M COSTS FOR A 44 MW (150 MILLION BTU/HR) MODEL BOILER IN REGION Vd
($1000/YR) (JAN 1983 $)
Coal Type
Type B - bit
Type 0 - bit
Type E - bit
Type F - bit
Type G - bit
Type H - bit
Type B - sub
Type D - sub
Type E - sub
Fuel
2,593
2,484
2,406
2,289
2,086
1,953
2,640
2,609
2,578
Baseline
Other
1,420
1,419
1,421
1,423
1,425
1,424
1,430
1,429
1,429
b
Total
4,013
3,903
3,827
3,712
3,511
3,377
4,070
4,038
4,007
Fuel
2,593
2,484
2,406
2,289
2,086
1,953
2,640
2,609
2,578
50% FGQC
Other
1,639
1,662
1,694
1,731
1,793
1,857
1,638
1,661
1,691
Total
4,232
4,146
4,100
4,020
3,879
3,810
4,278
4,270
4,269
Fuel
2,593
2,484
2,406
2,289
2,086
1,953
2,640
2,609
2,578
70% FGD
Other
1,657
1,689
1,733
1,784
1,871
2,960
1,655
1,688
1,730
c
Total
4,250
4,173
4,139
4,073
3,957
3,913
4,295
4,297
4,308
Fuel
2,593
2,484
2,406
2,289
2,086
1,953
2,640
2,609
2,578
90% FGDC
Other
1,674
1,716
1,772
1,837
1,948
2,063
1,673
1,715
1,769
Total
4,267
4,200
4,178
4.126
4,034
4,016
4,313
4,324
4,347
Includes applicable monitoring costs as shown in Table 2-15.
Baseline costs include PM/NO control costs.
Based on the use of sodium scrubbing FGD.
-------
TABLE 3-6. 0 & M COSTS FOR A 73 MW (250 MILLION BTU/HR) MODEL BOILER IN REGION Va
($1000/YR) (JAN 1983 $)
Coal Type
Type B - bit
Type D - bit
Type E - bit
Type F - bit
oo Type G - bit
10
Type H - bit
Type B - sub
Type D - sub
Type E - sub
Fuel
4,373
4,189
4,057
3,860
3,517
3,293
4,452
4,400
4,347
Baseline
Other
2,411
2,410
2,412
2,417
2,428
2,424
2,408
2,407
2,408
b
Total
6,784
6,599
6,469
6,277
5,945
5,717
6,860
6,807
6,755
Fuel
4,373
4,189
4,057
3,860
3,517
3,293
4,452
4,400
4,347
50% FGD
Other
2,696
2,734
2,787
2,850
2,961
3,065
2,679
2,717
2,768
c
Total
7,069
6,923
6,844
6,710
6,478
6,358
7,131
7,117
7,115
Fuel
4,373
4,189
4,057
3,860
3,517
3,293
4,452
4,400
4,347
70% FGD
Other
2,725
2,779
2,852
2,938
3,090
3,237
2,708
2,762
2.833
c
Total
7,098
6,968
6,909
6,798
6,607
6,530
7.160
7,162
7,180
Fuel
4,373
4,189
4,057
3,860
3,517
3,293
4,452
4,400
4,347
90% FGDC
Other
2,754
2,824
2,917
3,027
3,218
3,409
2,738
2,807
2,899
Total
7,127
7,013
6,974
6,887
6,735
6,702
7,190
7,207
7,246
alncludes applicable monitoring costs as shown in Table 2-15.
Baseline costs include PM/NO control costs.
cBased on the use of sodium scrubbing FGD.
-------
TABLE 3-7. 0 & M COSTS FOR A 117 MM (400 MILLION BTU/HR) MODEL BOILER IN REGION Va
($1000/YR) (JAN 1983 $)
Coal Type
Type B - bit
Type D - bit
Type E - bit
Type F - bit
Type G - bit
Type H - bit
Type B - sub
Type D - sub
Type E - sub
Fuel
6,997
6,702
6,492
6,175
5,627
5,269
7,124
7,040
6,955
Basel ine
Other
3,236
3,236
3,237
3,247
3,263
3,258
3,230
3,230
3,231
b
Total
10,233
9,938
9,729
9,422
8.890
8,527
10,354
10,270
10,186
Fuel
6,997
6,702
6,492
6,175
5,627
5,269
7,124
7,040
6,955
50% FGD
Other
3,614
3,677
3,759
3,862
4.039
4,206
3,592
3,654
3,736
c
Total
10,611
10,379
10,251
10,037
9,666
9,475
10,716
10,694
10,691
Fuel
6,997
6,702
6,492
6,175
5,627
5,269
7,124
7,040
6,955
70% FGD
Other
3,661
3,749
3,864
4,004
4,245
4,481
3,639
3,726
3,840
c
Total
10,658
10.451
10,356
10,179
9,872
9,750
10,763
10,766
10,795
Fuel
6,997
6,702
6,492
6,175
5,627
5,269
7,124
7,040
6,955
90% FGDC
Other
3,708
3.820
3.968
4,145
4,451
4,755
3.687
3,798
3.945
Total
10,705
10,522
10,460
10,320
10,078
10.024
10,811
10,838
10,900
alncludes applicable monitoring costs as shown in Table 2-15.
Baseline costs include PM/NO control costs.
cBased on the use of sodium scrubbing FGD.
-------
CO
TABLE 3-8. ANNUALIZED COSTS OF S02 CONTROL FOR A 29.MU (100 MILLION BTU/HR)
MODEL BOILER IN REGION V3)b
($1000/YR) (JAN 1983 $)
Coal
Type B
Type D
Type E
Type F
Type G
Type H
Type B
Type D
Type E
Type
- Bit
- Bit
- Bit
- Bit
- Bit
- Bit
- Sub
- Sub
- Sub
Baseline0
4,557
4,484
4,433
4,355
4,220
4,130
4,743
4,722
4,701
50
so2e
359
378
401
430
478
526
330
347
369
% FGDd
Total
4,916
4,862
4,834
4,785
4,698
4,656
5,073
5,069
5,070
o 70%
so2e
372
398
429
467
532
598
343
366
397
FGDd
Total
4,929
4,882
4,862
4,822
4,752
4,728
5,086
5,088
5,098
so2e
384
416
456
503
584
668
355
385
423
90% FGDd
Total
4,941
4,900
4,889
4,858
4,804
4,798
5,098
5,107
5,124
All costs include applicable monitoring costs as shown in Table 2-15.
All costs include FGD malfunction costs as discussed in Section 2.3.2.
Baseline costs include PM/NO control costs.
A
Based on the use of sodium scrubbing FGD.
p
Cost of S02 control is incremental cost above baseline cost.
-------
TABLE 3-9. ANNUAL I ZED COSTS OF S07 CONTROL FOR A 44 MW
(150 MILLION BTU/HR) MODEL BOItER IN REGION Va'b
($1000/YR) (JAN 1983 $)
Coal Type
Type B -
Type D -
Type E -
Type F -
Type G -
Type H -
Type B -
Type D -
Type E -
Bit
Bit
Bit
Bit
Bit
Bit
Sub
Sub
Sub
Bastline0
6
6
6
6
5
5
6
6
G
,344
,233
,156
,040
,838
,703
,607
,575
,544
50% FGDd
S02 Total
454
485
520
561
633
706
419
445
478
6
6
6
6
6
6
7
7
7
,798
,718
,676
,601
,471
,409
,026
,020
,022
70% FGDd
S02 Total
472
512
560
616
712
811
438
473
518
6
6
6
6
6
6
7
7
7
,816
,745
,716
,656
,550
,514
,045
,048
,062
90% FGDd
S02 Total
490
540
600
670
791
917
456
501
558
6,834
6,773
6,756
6,710
6,629
6,620
7,063
7,076
7,102
All costs include applicable monitoring costs as shown in Table 2-15.
All costs include FGD malfunction costs as discussed in Section 2.3.2.
°Baseline costs include PM/NO control costs.
X
Based on the use of sodium scrubbing FGD.
Q
Cost of SO 2 control is incremental cost above baseline cost.
-------
TABLE 3-10. ANNUALIZED COSTS
CO
I
I—'
t/J
ISTS OF S0? CONTROL FOR A 117 MW (250 MILLION BTU/HR)
MODEL BOItER IN REGION Va'D
($1000/YR) (JAN 1983 $)
Coal Type
Type B
Type D
Type E
Type F
Type G
Type H
Type B
Type D
Type E
- Bit
- Bit
- Bit
- Bit
- Bit
- Bit
- Sub
- Sub
- Sub
Baseline0
10
10
10
10
9
9
10
10
10
,751
,565
,433
,240
,905
,676
,987
,934
,881
50% FGDd
S02e Total
629
678
737
806
927
1,048
585
627
682
11
11
11
11
10
10
11
11
11
,380
,243
,170
,046
,832
,724
,572
,561
,563
70% FGDd
S02e Total
659
724
804
897
1,058
1,224
615
673
749
11
11
11
11
10
10
11
11
11
,410
,289
,237
,137
,963
,900
,602
,607
,630
90% FGDd
S02e Total
689
770
871
988
1,190
1,400
645
719
816
11,440
11,335
11,304
11,228
11,095
11,076
11,632
11,653
11,697
All costs include applicable monitoring costs as shown in Table 2-15.
All costs include FGD malfunction costs as discussed in Section 2.3.2.
cBaseline costs include PM/NO control costs.
X
Based on the use of sodium scrubbing FGD.
Cost of S02 control is incremental cost above baseline cost.
-------
TABLE 3-11. ANNUALIZED COSTS OF S0? CONTROL FOR A 117 MW (400 MILLION BTU/HR)
MODEL BOILER IN REGION V '
($1000/YR) (JAN 1983 $)
Coal Type
Type B -
Type D -
Type E -
Type F -
Type G -
Type H -
Type B -
Type D -
Type E -
Bit
Bit
Bit
Bit
Bit
Bit
Sub
Sub
Sub
Baseline0
15
15
15
14
14
13
16
15
15
,706
,409
,198
,889
,353
,986
,023
,938
,853
50%
so2e
875
954
1,048
1,159
1,351
1,546
818
88!)
973
FGDd
Total
16
16
16
16
15
15
16
16
16
,581
,363
,246
,048
,704
,532
,841
,823
,826
70% FGDd
S02e Total
923
1,027
1,155
1,304
1,562
1,827
866
959
1,080
16
16
16
16
15
15
16
16
16
,629
,436
,353
,193
,915
,813
,889
,897
,933
90% FGDd
S02e Total
971
1,101
1,262
1,449
1,773
2,109
914
1,033
1,187
16,677
16,510
16,460
16,338
16,126
16,095
16,937
16,971
17,040
All costs include applicable monitoring costs as shown in Table 2-15.
All costs include FGD malfunction costs as discussed in Section 2.3.2.
GBaseline costs include PM/NO control costs.
A
Based on the use; of sodium scrubbing FGD.
Cost of SO- control is incremental cost above baseline cost.
-------
3.2 REGION VIII COSTS
3.2.1 Capital Costs
Table 3-12 presents the capital costs of control at the baseline and
for the various S02 control alternatives for 29, 44, 73, and 117 MW (100,
150, 250, and 400 million Btu/hr) model boilers. A comparison of the costs
in Table 3-3 with those in Table 3-12 for Region VIII shows that the capital
costs for coal-fired boilers are about equal to those in Region V. Any
slight differences in capital costs between the two regions are attributable
to differences in fuel costs which, in turn, impact working capital
requirements.
3.2.2 Annual O&M Costs
Table 3-13 presents the annual O&M costs for each of the boiler sizes
examined. At the baseline level of control, fuel costs represent 35 to 45
percent of the total O&M costs for a 29 MW (100 million Btu/hr) model boiler
and 45 to 55 percent for a 117 MW (400 million Btu/hr) model boiler. For
the 90 percent S02 removal cases, fuel costs account for about 30 to
40 percent of the total O&M costs for a 29 MW (100 million Btu/hr) model
boiler and about 40 to 50 percent for a 117 MW (400 million Btu/hr) model
boiler. Fuel costs as a percentage of total O&M costs are lower in
Region VIII than in Region V (see Section 3.1.2). This is explained by the
significantly lower fuel prices in Region VIII as compared to Region V.
(Table 3-1 presented the fuel prices and specifications for coals in these
regions).
3.2.3 Annualized Costs
Table 3-14 presents the annualized costs of control at the baseline and
for each S02 control alternative for the various boiler sizes examined.
Annualized costs are calculated as the sum of the annualized capital charges
and annual O&M costs.
Table 3-14 shows that the differences in S02 control costs for 50, 70
and 90 percent FGD for a particular coal type are small relative to the
3-15
-------
TABLE 3-12. CAPITAL COST OF S02 CONTROL IN REGION VIII
($1000) (JAN 1983 $)a
Boiler Size/
Coal Classification
29
44
73
117
MW (100 million Btu/hr)
Bituminous
Subbituminous
MW (150 million Btu/hr)
Bituminous
Subbituminous
MW (250 million Btu/hr)
Bituminous
Subbituminous
MW (400 million Btu/hr)
Bituminous
Subbituminous
Baseline1"1
10,062
10,913
13,983
15,171
23,913
24,807
32,973
34,033
With FGDC
10,728
11,476
14,810
15,873
24,993
25,727
34,376
35,233
Includes applicable monitoring costs as shown in Table 2-15.
Baseline costs include PM/NO control costs.
A
GBased on sodium scrubbing FGD.
3-16
-------
TABLE 3-13. 0 & M COSTS IN REGION VIII ($1000/YR) (JAN 1983 $)a
CO
i
Baseline
Coal Type fuel Other
29 MW (100 x
Type B -
Type D -
Type E -
Type B -
Type D -
Type E -
44 MW (150 x
Type B -
Type D -
Type E -
Type B -
Type D -
Type E -
73 MW (250 x
Type B -
Type D -
Type E -
Type B -
Type D -
Type E -
117 MW (400 x
Type B -
Type D -
Type E -
Type B -
Type D -
Type E -
10 Btu/hr) model boiler
Bit 1,036 ,158
Bit 969 ,159
Bit 974 ,160
Sub 729 ,164
Sub 724 ,162
Sub 667 ,162
106 Btu/hr) model boiler
Bit 1,554 1,425
Bit 1,453 1,427
Bit 1,461 1,427
Sub 1,094 1,433
Sub 1,086 1,431
Sub 1,000 1,431
106 Btu/hr) model boiler
Bit 2,621 2,416
Bit 2,450 2,420
Bit 2,463 2,421
Sub 1,844 2,424
Sub 1,831 2,410
Sub 1,686 2,410
106 Btu/hr) model boiler
Bit 4,194 3,244
Bit 3,920 3,251
Bit 3,941 3,252
Sub 2,951 3,256
Sub 2,930 3,234
Sub 2,698 3,234
Includes applicable monitoring costs as
b
Total
2,194
2,128
2,134
1,893
1,886
1,829
2,979
2,880
2,888
2,527
2,517
2,431
5,037
4,870
4,884
4,268
4,241
4,096
7,438
7,171
7,193
6,207
6,164
5,932
shown in
50% FGDC
Fuel
1,036
96
-------
TABLE 3-14. ANNUALIZED COSTS OF SO,, CONTROL IN REGION VIII ($1000/yr) (JAN 1983 $)a>b
29
44
73
117
Coal
MW (100
Type B
Type 0
Type E
Type B
Type 0
Type E
MW (150
Type B
Type D
Type £
Type B
Type 0
Type E
MW (250
Type B
Type 0
Type E
Type B
Type 0
Type E
MW (400
Type B
Type 0
Type E
Type B
Type 0 •
Type E •
Type
x 106 Btu/hr)
- Bit
- Bit
- Bit
- Sub
- Sub
- Sub
x 106 Btu/hr)
- Bit
- Bit
- Bit
- Sub
- Sub
- Sub
x 106 Btu/hr)
- Bit
- Bit
- Bit
- Sub
- Sub
- Sub
x 106 Btu/hr)
- Bit
- Bit
- Bit
- Sub
- Sub
- Sub
Baseline0
model boiler
3,862
3,796
3,801
3,706
3,699
3,641
model boiler
5,301
5,201
5,209
5,051
5,041
4,954
model boiler
8,989
8,821
8,835
8,374
8,347
8,200
model boiler
12,888
12,619
12,641
11,841
11,798
11,564
50%
so2e
369
388
408
357
372
397
470
499
529
460
483
520
655
703
753
651
690
752
915
993
1,074
925
987
1,084
FGDd
Total
4,231
4,184
4,209
4,063
4,071
4,038
5,771
5,700
5,738
5,511
5,524
5,474
9,644
9.524
9,588
9,025
9,037
8,952
13,803
13,612
13,715
12,766
12,785
12,648
70%
SO/
382
407
436
370
392
425
490
528
571
480
513
562
685
749
820
681
736
819
964
1,066
1,181
973
1,060
1,191
FGDd
Total
4,244
4,203
4,237
4,076
4,091
4,066
5,791
5,729
5,780
5,531
5,554
5,516
9,674
9,570
9,655
9,055
9,083
9,019
13,852
13,685
13,822
12,814
12,858
12,755
so2
394
426
463
382
410
452
508
556
611
499
540
602
715
795
887
712
781
886
1,012
1,140
1,287
1,022
1,133
1,299
)% FGDd
Total
4,256
4,222
4,264
4,088
4,109
4,093
5,809
5,757
5,820
5,550
5,581
5,556
9,704
9,616
9,722
9,086
9,128
9,086
13,900
13,759
13,928
12,863
12,931
12,863
All costs include applicable monitoring costs as shown in Table 2-15.
All costs include malfunction costs as discussed in Section 2.3.2.
Baseline costs include PM/NO control costs.
Based on the use of sodium scrubbing FGD.
Cost of S02 control is incremental cost above Baseline Cost.
-------
total annualized cost of a boiler. Also, the total annualized cost of
control tracks the fuel price rather than the sulfur content. Therefore,
the least costly fuel has the lowest total annualized costs for each
alternative.
3-19
-------
3.3 REFERENCES
1. Projected Environmental, Cost and Energy Impacts of Alternative S00
NSPS for Industrial Fossil Fuel-Fired Boilers. (Prepared for U. S
Environmental Protection Agency). Energy and Environmental Analysis,
Arlington, Virginia. July 27, 1984. pp. 9-10.
3-20
-------
4.0 COST OF S02 CONTROL ON RESIDUAL OIL-FIRED MODEL BOILERS
This chapter presents the results of an analysis of S02 control costs
for residual oil-fired model boilers. Capital and annualized costs are
examined for boilers with no S02 control (baseline) and for boilers equipped
with FGD systems achieving 50 percent, 70 percent, and 90 percent S02
removal. Costs are examined for several boiler sizes and for several oil
sulfur contents. The boiler sizes selected for this analysis are 29, 44, 73
and 117 MW (100, 150, 250 and 400 million Btu/hr) heat input. The 117 MW
(400 million Btu/hr) model boiler is actually two 59 MW (200 million Btu/hr)
boilers sharing a common stack. This arrangement was selected because two
small packaged units are less costly than one large field-erected unit.
Specifications and prices of residual oil delivered to Region V are
presented in Table 4-1. To maintain consistency with the Industrial Fuel
Choice Analysis Model (IFCAM), which is used to project the national impacts
of alternative S02 standards, the values in Table 4-1 are projections for
1990 delivered fuel prices expressed in January 1983 dollars.1 The
projections ignore the effects of inflation but assume that fuel prices will
escalate in real terms. In addition, the fuel prices have been "levelized"
over the life of the boiler (i.e., an equivalent constant price has been
calculated after allowing for escalation and the time value of money.
In this analysis, it is assumed that all boilers require the use of low
excess air operation (LEA) for NOX control. Costs are also presented for a
model boiler using staged combustion air (SCA) operation in addition to LEA
when firing a high sulfur content oil since high sulfur oil may also contain
high nitrogen levels. It is also assumed that no add-on particulate matter
controls are required.
The basis of the FGD costs presented in this report for residual
oil-fired boilers is sodium scrubbing FGD. Sodium scrubbing FGD was
selected because it is the most widely used in residual oil applications and
it is generally the least costly method of control. Double alkali FGD is
more costly both on a capital and an annualized basis. And dry scrubbing
FGD is not considered applicable to residual oil-fired applications. Also
4-1
-------
TABLE 4-1. SPECIFICATIONS FOR RESIDUAL OILS DELIVERED TO REGION V AND REGION VIII3
I
IV)
Sulfur Content
Ib S02/10° Btu
Region V:
0.3
0.8
1.6
3.0
Region VIII:
0.3
0.8
1.6
3.0
Fuel Price
$/kJ ($/10D Btu)
5.69 (6.01)
5.33 (5.63)
4.97 (5.25)
4.68 (4.94)
5.37 (5.67)
5.01 (5.29)
4.67 (4.93)
4.36 (4.60)
Heating Value
U/kg (Btu/lb)
43,000 (18,500)
43,000 (18,500)
43,000 (18,500)
43,000 (18,500)
43,000 (18,500)
43,000 (18,500)
43,000 (18,500)
43,000 (18,500)
Ash
Content
Wt. %
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
Nitrogen
Content
Wt. %
0.04
0.12
0.23
0.44
0.04
0.12
0.23
0.44
Reference 1.
}1990 levelized fuel price in 1983 $.
-------
the FGD costs are based on an industrial boiler located in Region V. Unlike
coal all ten EPA regions have the same residual oils available. Thus the
only difference in FGD costs in Region V and any other region can be
attributed to fuel cost. Therefore, the cost impact of SCL control compared
to the regulatory baseline in Region V is representative of impacts
nationwide.
4.1 REGION V COSTS
4.1.1 Capital Costs
Table 4-2 presents the capital costs of S02 control for 29, 44, 73, and
117 MW (100, 150, 250 and 400 million Btu/hr) model boilers. The capital
costs of FGD for all oil types and percent removal requirements are designed
to achieve 90 percent S02 removal on a 3.0 Ib S02/106 Btu oil. In other
words, it is assumed that a boiler owner/operator will design an FGD for
maximum fuel-firing flexibility.
4.1.2 Annual O&M Costs
Table 4-3 presents the annual O&M costs of S02 control for residual
oil-fired model boilers in Region V. Table 4-3 shov-s that fuel costs
represent 80 to 90 percent of the total O&M costs at the baseline and for
each FGD alternative. In other words, a scrubbing requirement has little
impact on the total system costs since fuel costs represent such a large
percentage of the total costs.
4.1.3 Annualized Costs
Table 4-4 shows that, at the baseline and for each FGD alternative,
total annual ized costs decrease with increasing fuel sulf-jr content. Table
4-4 also shows that it is less costly to scrub a 3.0 Ib S02/106 Btu oil than
it is to fire a 0.3 Ib S02/106 Btu oil uncontrolled for all boiler sizes
examined. Furthermore, as boiler size increases, the premium price of a 0.3
Ib S02/10 Btu oil becomes even more important and scrubbing a 0.8 Ib
S02/10 Btu oil becomes less costly than firing a 0.3 Ib S02/106 Btu oil
uncontrolled.
4-3
-------
TABLE 4-2. CAPITAL COSTS OF S0? CONTROL FOR MODEL BOILERS IN REGION Va
($1000) (JAN 1983 $)
Boiler Size/
Coal Classification Basel ineb
29 MW
44 MW
73 MW
117 m
(100 Mill
(150 Mill
(250 Mill
f (400 Mil
ion Btu/hr) 2,545
ion Btu/hr) 3,278
ion Btu/hr) 4,579
lion Btu/hr) 7,732
With FGDC
3,104
3,973
5,500
8,998
Includes applicable monitoring costs as shown in Table 2-15.
Baseline costs include PM/NO control costs.
A
Based on sodium scrubbing FGD.
4-4
-------
TABLE 4-3. OPERATING AND MAINTENANCE COSTS OF S0? CONTROL FOR MODEL BOILERS IN REGION Va
($1000/YR) (JANUARY 1983 $)
Baseline5
Fuel Other
29
44
73
117
MW (100 x 106 Btu/hr
0.3 Ib S00/10° Btu
0.8 Ib S0,/10?. Btu
1.6 Ib S0,/10b Btu.
3.0 Ib SO;/10£ Btud
3.0 Ib S0£/10b Btue
MW (150 x 10b Btu/hr)
0.3 Ib S0y/10° Btu
0.8 Ib S0,/lo£ Btu
1.6 Ib SOy/lO? Btu.
3.0 Ib SO^/10?. Btud
3.0 Ib SOg/lO6 Btue
MW (250 x 10b Btu/hr)
0.3 Ib S0,/10° Btu
0.8 Ib S0;/10? Btu
1.6 Ib SOp/lO? Btu.
3.0 Ib S0,/10b Btud
3.0 Ib SO^/106 Btue
MW (400 x 10b Btu/hr)
0.3 Ib S0?/10° Btu
0.8 Ib SO^/IO? Btu
1.6 Ib S0;/10b Btu.
3.0 Ib S05/10* Btud
3.0 Ib S0£/10b Btue
2,847
2,667
2,487
2,340
2,386
4,241
4,000
3,730
3,510
3,579
7,118
6,667
6,217
5,850
5,965
11,388
10,668
9,948
9,360
9,544
521
521
521
521
541
652
623
623
622
651
816
817
817
817
862
1,368
1,368
1,368
1.370
1,442
Total
3,368
3,188
3,008
2,861
2,927
4,893
4,623
4,353
4,132
4.230
7,934
7,484
7,034
6,667
6,827
12,756
12,036
11,316
10,730
10,986
Fuel
2,847
2,667
2,487
2,340
2,386
4,241
4.000
3,730
3,510
3,579
7,118
6,667
6,217
5,850
5,965
11,388
10,668
9,948
9,360
9,544
50% FGDC
Other Total
677
693
717
760
780
801
825
861
926
954
1,035
1,075
1,136
1,243
1,288
1,635
1,696
1,794
1,967
2,040
3,524
3,360
3,204
3,100
3,166
5,072
4.825
4,591
4,436
4,533
8.153
7,742
7,353
7,093
7,253
13,023
12,364
11,742
11,328
11,584
Fuel
2,847
2,667
2,487
2,340
2,386
4,241
4,000
3,730
3,510
3,579
7,118
6,667
6,217
5,850
5,965
11,388
10,668
9,948
9,360
9,544
70% FGOC
Other Total
673
694
729
789
809
828
831
883
973
1,001
1.045
1,099
1,185
1,335
1,380
1,650
1,735
1,873
2,115
2,187
3,520
3,361
3,216
3,129
3,195
5,069
4,831
4,613
4,483
4,580
8,163
7,766
7,402
7,185
7,345
13,038
12,403
11,821
11,475
11,731
Fuel
2,847
2,667
2,487
2,340
2,386
4,241
4,000
3,730
3,510
3,579
7,118
6,667
6,217
5,850
5,965
11,388
10,668
9,948
9,360
9,544
90% FGDC
Other Total
677
704
748
826
846
834
846
912
1,028
1,056
1,054
1,124
1,234
1,427
1,472
1,664
1,775
1,951
2,263
2,335
3,524
3,371
3,235
3,166
3,232
5,075
4,846
4,642
4,538
4,635
8,172
7,791
7,451
7,277
7,437
13,052
12,443
11,899
11,623
11,879
a , , .... _______ ___
Baseline costs include NO control costs.
Based on the use of sodium scrubbing FGD.
N0x control = Low Excess Air
p
N0x control = Staged Combustion Air
-------
TABLE 4-4. ANNUAL1ZED COSTS OF S02 CONTROL FOR RESIDUAL OIL-FIRED MODEL BOILERS IN REGION Va>b
(SlOOO/YR) (JANUARY 1983 $)
I
cn
' ' — __
29
44
73
117
MW (100
0.3 Ib
0.8 Ib
1.6 Ib
3.0 Ib
3.0 Ib
x 106 Btu/hr)
SO,/ 10° Btu
SO,/ 10* Btu
SO,/ 10* Btu,
SO,/ 10* BtuT
SO^/106 Btu9
MW (150 x 106 Btu/hr)
0.3 Ib SO,/ 10? Btu
0.8 Ib S0l;/10° Btu
1.6 Ib SO,/ 10° Btu,
3.0 Ib SO,/ 10* Btuf
3.0 Ib SO^/IO0 Btu9
MW (250 x 106 Btu/hr)
0.3 Ib S0,/10^ Btu
0.8 Ib SO,/ 10* Btu
1.6 Ib S0£/ 10? Btu,
3.0 Ib SO,/ 10* Btuf
3.0 Ib SO^/106 Btu9
MW (400
0.3 Ib
0.8 Ib
1.6 Ib
3.0 Ib
3.0 Ib
x 106 Btu/hr)
S0?/10° Btu
SOp/10? Ctu
SO,/ 10° Btu,
SO,/ 10* BtuT
SO^/IO0 Btu9
Baseline0
3,767
. 3,585
3,404
3,256
3,354
5,408
5,136
4,864
4,642
4,782
8,671
8,217
7,763
7,393
7,619
13,994
13,268
12,542
11,950
12,316
50| FGDd
252
277
311
363
362
295
332
383
461
461
351
414
500
628
628
446
545
683
889
889
4
3
3
3
3
5
5
5
5
5
,019
,862
,715
,619
,716
,703
,468
,247
,103
,243
9,022
8,631
8,263
8,021
8,247
14,440
13,813
13,225
12,839
13,205
70% FGDd
SOZC Total
256
287
331
400
400
301
347
414
517
518
361
439
550
723
723
461
586
764
1,040
1,040
4,023
3,872
3,735
3,656
3,754
5,709
5,483
5,278
5,159
5,300
9,032
8,656
8,313
8,116
8,342
14,455
13,854
13,306
12,990
13,356
S02
260
297
351
438
438
307
362
444
574
574
370
464
601
817
817
477
626
804
1,191
1,191
FGDd
Total
4
3
3
3
3
5
5
5
5
5
,027
,882
,755
,694
,792
,715
,498
,308
,216
.356
9,041
8,681
8,364
8,210
8,436
14,
13,
13,
13,
13,
471
894
386
141
507
a, , . . , ~ — — — —
Includes FGD malfunction costs as discussed in Section 2.3.2.
Baseline costs include NO^ control costs.
Based on the use of sodium scrubbing FGD.
p
Cost of SO^ control is incremental over baseline cost.
N0x Control = Low Excess Air.
9NOx Control = Staged Combustion Air.
-------
4.3 REFERENCES
1.
Projected Environmental, Cost and Energy Impacts of Alternative SO,
NSPS for Industrial Fossil Fuel-Fired Boilers. (Prepared for U. S7
Environmental Protection Agency). Energy and Environmental Analysis,
Arlington, Virginia. July 27, 1984. pp. 9-10.
4-7
-------
APPENDIX A
A-l
-------
TABLE A-l. SUMMARY OF COSTING ALGORITHMS
Routine
Codea
SPRD
PLVR
RNG1
RNG2
FF
DA
SOD
DS
LEA
SCA
SCA
FLW
Algorithm Type
Boiler, spreader stoker, watertube,
field-erected
Boiler, pulverized coal, watertube,
field-erected
Boiler, residual/natural gas, watertube,
package
Boiler, residual/natural gas, watertube,
field-erected
Fabric filter applied to coal-fired boiler
Dual alkali FGD system without PM removal
Sodium scrubbing FGD system
Lime spray drying (dry scrubbing) FGD system
Low excess air applied to all fuel types
Staged combustion air applied to pulverized
coal-fired boiler
Staged combustion air applied to residual
oil-fired boiler
Calculates flue gas flowrates for all
fuel types
Boiler Size
Applicability
(10° Btu/hr)
60 - 200
^200
30 - 200
200 - 700
30 - 700
All sizes
All sizes
All sizes
All sizes
>150
30 - 250
All sizes
Table
A-4
A-5
A-6
A-7
A-8
A-9
A- 10
A-ll
A-12
A-13
A-14
A-15
A-2
-------
TABLE A-2. NOMENCLATURE USED IN COST ALGORITHMS
1. Capital Costs (1978 dollars)
EQUP = Equipment
INST = Installation
TD = Total Direct
IND = Indirect (Engineering, Field, Construction, Start-up,
and other miscellaneous costs)
TDI = Total Direct and Indirect
CONT = Contingencies
TK = Turnkey
LAND = Land
WC = Working Capital
TOTL = Total Capital
2. Operation and Maintenance Costs3 (1978 dollars/year)
DL = Direct Labor
SPRV = Supervision Labor
MANT = Maintenance Labor
SP = Spare Parts
ELEC = Electricity
UC = Utilities and Chemicals
WTR = Water
SW = Solid Waste Disposal
SLG = Sludge Waste Disposal
LW = Liquid Waste Disposal
SC = Sodium Carbonate
LMS = Limestone
LIME = Lime
FUEL = Fuel
TDOM = Total Direct Operation and Maintenance
OH = Overhead
TOTL = Total Operation and Maintenance
3. Annualized Costs (1978 dollars/year)
CR = Capital Recovery
WCC = Working Capital Charges
MISC = Miscellaneous (G & A, Taxes, Insurance)
TCC = Total Capital Charges
TOTL = Total Annualized Charges
A-3
-------
TABLE A-2. (Continued)
4. Boiler Specifications
Q = Thermal Input (106 Btu/hr) MW)b
FLW = Flue Gas Flowrate (acfm) (mVs)D
CF = Capacity Factor (-)
BCRF = Capital Recovery Factor for Boiler System
5. Fuel Specifications
FC = Fuel Cost (S/106 Btu) ($MJ)b .
H = Heating Value (Btu/lb) (KJ/kg)D
S = Sulfur Content (percent by weight)
A = Ash Content (percent by weight)
N = Fuel Nitrogen Content (percent by weight)
6. SO^ Control Specifications
UNCS02 = Uncontrolled S02 Emissions (lb/106 Btu) (ng/J)b
CTRS02 = Controlled S02 Emissions (lb/106 Btu) (ng/J)D
EFFS02 = S02 Removal Efficiency (percent)
CRFS02 = Capital Recovery Factor for S02 Contro"! System
7. PM Control Specifications
UNCPM = Uncontrolled PM Emissions (lb/106 Btu) (ng/J)b
CTRPM = Controlled PM Emissions (lb/105 Btu) (ng/J)D
EFFPM = PM Removal Efficiency (percent)
CRFPM = Capital Recovery Factor for PM Control System
8. Cost Rates
ELEC = Electricity Rate ($/kw-hr) . .
WTR = Water Rate ($/l(T gal) r$/nr)°
ALIME = Lime Rate ($/ton) ($/kg)°
ALS = Limestone Rate ($/ton) ($/kg)
SASH = Sodium Carbonate Rate (S/ton) ($/kg,)D
SLDG = Sludge Disposal Rate (S/ton) ($/kg)
— <_ i^ u ^ i ^ vi ^ \_ L-flopwOUI t\UUt \ •*> f \*\JU J '-J/f\UJ i
SWD = Solid Waste Disposal Rate ($/toni (S/kg)
LWD = Liquid Waste Disposal Rate (S/IQ-3 gal) ($/mJ)D
DLR = Direct Labor Rate ($/man-hr)
SLR = Supervision Labor Rate ($/man-hr)
AMLR = Maintenance Labor Rate (S/man-hr)
A-4
-------
10.
TABLE A-2. (Continued)
9. Miscellaneous
SI
S2
LF
= Heat Specific Sulfur Removal (kg S/1000 MJ)
= Time Specific Sulfur Removal (kg S/hr)
= Labor Factor (-)d
NO Control
Specifications
FFAC = F-Factor (dscf/106 Btu)
UNCEA = Uncontrolled Excess Air (%)
CTREA = Controlled Excess Air (%)
PRCT = Percent Flame Extension Due to Staging
DELT = Change in the flue gas exit temperature
elimination of the air preheater or a
in its effectiveness.
due to the
reduction
CRFNOx = Capital Recovery Factor for NO Control System
Cost categories are not mutually exclusive. For example, some costing
routines include electricity and waste cost in the utilities category
while other calculate these cost separately.
FGD algorithms use metric units.
(-) factor presented as fraction not as percent.
A-5
-------
TABLE A-3. CALCULATIONS COMMON TO COST ALGORITHMS
1. Capital Costs
EQUP + INST = TDa.
IND = 0.333 * TDD
TDI = TO + IND
CONT = 0.20 * TDI
LAND = $4000 pulverized coal boilers
= $2000 all other boilers
WC = 0.25 * (TDOM - Fuel) + 0.0833 (Fuel)d
TOTL = TK + LAND + WC
2. Operation and Maintenance Costs
FUEL = CF * Q * FC * 8760
TDOM = Sum of all O&M Costs other than OH
OH = 0.30 * DL + 0.26 * (DL + SPRV + MANT + SP)
TOTL = TDOM + OH
3. Annualized Costs
CR = CRF * TK
WCC = 0.10 * WC
MISC = 0.04 * TK
TCC = CR + WCC + MISC
TOTL = TCC + TOTL O&M Costs
4. Labor Factors
LF = 1 if CF > 0.7
LF = 0.5 + 2.5 * (CF - 0.5) if 0.5 < CF < 0.7
LF = 0.5 if CF < 0.5
FGD system cost algorithms compute TD without prior computation of EQUP and
INST
Some algorithms compute IND explicitly as a function of boiler and/or
control device specifications.
Only boilers have costs assumed for land.
For boilers, assume a 3-month supply of all working capital components
except fuel which will have a 1-month supply. For control devices, working
capital is 25% of total direct operating and maintenance costs.
A-6
-------
TABLE A-4. COST EQUATIONS FOR FIELD-ERECTED, WATERTUBE
SPREADER-STOKER BOILERS
(60-200 x 106 Btu/hr)1
Routine Code: SPRD
Capital Costs:
EQUP
INST
IND
Anmj_a1 Costs :a
DL
SPRV
MANT
SP
DC
SW
Q
-.35
7.5963 x 10"° Q + 4.7611 x 10
8.9174 x 10"8 Q + 5.5891 x 10"5
5 11,800
H
-.35
11,800
H -.35
1.2739 x 10"7 Q + 7.9845 x 10"5 11,800
LF (202,825 + 5.366 Q2) (0.767)
LF (136,900) (0.767)
LF (107,003 + 1.873 Q2) (0.767)
(50,000 + 1,000 Q) (0.767)
CF (29,303 + 719.8 Q) (0.848)
A Q 0.9754
0.38 CF (547,320 + 66,038 In H) ~150~ (0.848)
The multipliers used, 0.767 and 0.848, are included in determining annual
O&M costs. These factors reflect the economies of multiple boilers at a
facility (see Chapter 2).
A-7
-------
TABLE A-5. COST EQUATION FOR FIELD-ERECTED, WATERTUBE
PULVERIZED COAL-FIRED BOILERS
(>200 x 106 Btu/hr)1
Routine Code: PLVR
Capital Costs:
EQUP = (4,926,066 - 0.00337 H2)/_JM °'712
\~mrJ
INST
IND
Annual Costs:'
DL
SPRV
MANT
SP
UC
SW
1,547,622.7 + 6,740.026 Q - 0.0024133 H
1,257,434.72 + 6,271.316 Q - 0.00185721
LF (244,455 + 1,157 Q) (0.767)
LF (243,985 - 20'636'709\(0.767)
Q I
LF (-1,162,910 + 256,604 In Q) (0.767)
(180,429 + 405.4 Q) (0.767)
CF (189,430 + 1476.7 Q) (0.848)
0.38 CF (-641.08 + 70'679'828A^ / Q
H / ^ 200 /
1.001
(0.848)
The multipliers used, 0.767 and 0.848, are included in determining annual
O&M costs. These factors reflect the economies of multiple boilers at a
facility (see Chapter 2).
A-8
-------
TABLE A-6. COST EQUATIONS FOR PACKAGE, WATERTUBE DUAL-FIRED
BOILERS FIRING RESIDUAL OIL/NATURAL GAS
(30-200 x 106 Btu/hr)1
Routine Code: RNG1
Capital Costs
EQUP = 15,925 Q-775
INST = 54,833 Q°'364
IND = 16,561 Q-613
Annual Costs3
(0.799)
= LF \8,135 x 10'4 Q - 1.585 x 10"2
SPRV = LF (68,500) (0.799)
MANT - .cM,267,000\
f MT Lf\ g j + 77,190) (0.799)
SP = 7,185 Q°-4241 (0.799)
— (202 Q + 24,262) (0.845)
UC = .55
The multipliers used, 0.799 and 0.845, are included in determining annual
O&M costs. These factors reflect the economies of multiple boilers at a
facility (see Chapter 2).
A-9
-------
TABLE A-7. COST EQUATIONS FOR FIELD-ERECTED, WATERTUBE
RESIDUAL OIL/GAS-FIRED BOILERS
(200 - 700 x 106 Btu/hr)1
Routine Code: RNG2
Capital Costs:
EQUP = 1,024,258 + 8,458 Q
INST = 579,895 + 5,636 Q
IND = 515,189 + 4,524 0
Annual Costs:
a
DL = LF (173,197 + 734 Q) (0.799)
/ 30,940,QOO\
SPRV = LF (263,250 - QJ(0.799)
MANT = LF (32,029 + 320.4 Q)(0.799)
SP = (50,000 + 250 Q) (0.799)
UC = CF (43,671.7 + 479.6 Q) (0.845)
The multipliers used, 0.799 and 0.845 are included in determining annual
O&M costs. These factors reflect the economies of multiple boilers at a
facility (see Chapter 2).
A-10
-------
TABLE A-8. COST EQUATIONS FOR FABRIC FILTERS APPLIED TO
COAL-FIRED BOILERS
(30 - 700 x 106 Btu/hr)2
Routine Code: FF
Capital Costs:
EQUP = 8.340 (FLW)0-966
INST = -1,506,523 + 168,531 In (FLW)
IND = 24.990 (FLW)0'821
Annual Costs:
DL = LF (10,150 + 106 Q) if 30 < Q < 400
LF (52,600) if 400 < Q < 700
=0 if 30 , Q < 400
LF (17,000) if 400 < Q < 700
= LF (14,840 + 0.106 Q2) if 30 < Q < 400
LF (32,000) if 400 < Q < 700
SP = 0.278 (FLW)0-997
ELEC = (CF_} 0>74Q (FLW)0.953
SW = (§75-) 39.42 Q (UNCPM - CTRPM)
A-ll
-------
TABLE A-9. COST EQUATIONS FOR DUAL ALKALI
FGD SYSTEMS WITHOUT PM REMOVAL3
Routine Code: DA
Capital Costs:b>c
TD = 35,500 (FLW)0-61 + 83,118 (S2)°*39
TK = 1.48 TD + 93,600 if Q -<58.6
1.48 TD + 130,000 if Q >58.6
Annual Costs:b>c
DL = 8,760 * DLR * LF
SPRV = 1,314 * DLR * LF
MANT = 0.08 TD * LF
ELEC = 8,760 CF * ELEC [2.94 FLW (0.121 SI + 0.861)]
WTR = 8,760 CF *-WTR [0.197 FLW + 0.30]*
[0.977 + 0.119 In SI]
SW = 8,760 CF * SWD [7.73 S2 - 3.34]
SC = 8,760 CF * SASH [1.13 FLW - 2.06]*
[0.41 - 0.70 (0.24 - SI)1'74] if SI < 0.24
8,760 CF * SASH [1.13 FLW - 2.06]*
[0.70 (SI - 0.24)1'74 + 0.41] if SI > 0.24
LIME = 8,760 CF * ALIME [1.61 S2 - 0.85]
FGD algorithms use metric units as noted in Table A-2.
bSl = S * EFFS02 * 100/H.
CS2 = SI * Q * 3.6
A-12
-------
TABLE A-10. COST EQUATIONS FOR SODIUM SCRUBBING FGD SYSTEMS3
Routine Code: SODb'c
Capital Costs:d
TK,. = 39,900 (FLW)0'585 + 1,370 (S2)0'727
26,500
s
0.39
TK = TK + TK
s w
Annual Costs:
DL = 1,100*DLW
SPRV = 165*SPRV
MANT = 0.08*TK
ELECS= 8,760*CF*ELEC [3.61(FLW) - 2.15]
ELECw= 8760*CF*ELEC [0.23(S2) + 1.32]
ELEC = ElEC + ELEC
s w
WTR = 8760*CF*WTR [0.600(FLW) - 2.08] [0.527(31) + 0.364]
SC = 8760*CF*SASH [3.33(32) + 0.082]
LW = 8760*CF*LWD [0.0616(52) + 0.298]6
All FGD algorithms are in metric units as noted in Table A-2.
bSl = S*EFFS02*100/H
CS2 = S1*Q*3.6
The subscript "s" denotes scrubber costs and the subscript "w" denotes
wastewater costs.
a
This equation assumes that the wastewater stream has a total dissolved solids
concentration (TDS) of 5.7.
A-13
-------
TABLE A-ll. COST EQUATIONS FOR LIME SPRAY DRYING
FGD SYSTEMS WITH PM REMOVAL3
Routine Code: DS
Capital Costs:b'°
TD = Cl + C2 + C3 + C4
Cl = 55,600 (FLW)0'51
C2 = 32,900 (S2)°'4°
C3 = 18,400 + 8,260 (FLW) + 6,420 (FLW)0'50
C4 = 256,320 [Wl + W2]°'63
Wl = Q * S/H * [0.626 EFFS02 - 79.9 In (1-EFFS02/100) - 10.1]
W2 = 3.96 x 10"6Q (UNCPM - CTRPM)
TK = 1.48 TD + 110,400 if Q <_ 58.6
1.60 TD if Q > 58.6
Annual Costs, $/Year
DL = 8,760 * DLW * LF .
SPRV = 1,314 * SPRV * LF
MANT = [0.08 [55,600 (FLW)0'51 + 32,900(S2)°'40] + Ml + M2] * LF
Ml = 834 FLW
M2 = MANT * (4.04 FLW + 1,086)
ELEC = 8,760 CF * ELEC [6.14 (FLW)0'82]
WTR = 8,760 CF * WTR [0.144 FLW]
SW = 8,760 CF * SWD [W3 + W4]
W3 = (Q * S/H) * [569 EFFS02 - 72,700 In (1-EFFSQ2/10C) - 9,230]
W4 = 3.6 x 10"3Q (UNCPM - CTRPM)
LIME = 8,760 CF * ALIME * (-48,500) * Q * S/H * [In (1-EFFS02/100) +
0.127]
FGD algorithms use metric units as noted in Table A-2.
bSl = S * EFFS02 * 100/H.
cdS2 = SI * Q * 3.6.
A-14
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TABLE A-12. COST EQUATIONS FOR LOW EXCESS AIR
APPLIED TO INDUSTRIAL BOILERS
Routine Code: LEA
Capital Costs:
Coal: EQUIP = 46.22(Q) + 6496
INST and IND = 21.50(Q) + 1123
Oil and Gas: EQUIP = 31.38(Q) + 5185
INST and IND = 11.37(Q) + 1161
Annual Costs:
SPb = 0.05 (TK)
FUEL = -.00055(FC)(Q)(CF)(FFAC)(UNCEA - CTREA)
Algorithm assumes a flue gas temperature of 400°F and the ambient air
temperature to be 77°F.
Spare parts costs consist of the costs for spare parts, maintenance labor
and maintenance materials.
A-15
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TABLE A-13. COST EQUATIONS FOR STAGED COMBUSTION AIR
APPLIED TO PULVERIZED COAL-FIRED BOILERS
(>150 x 106 Btu/hr)
Routine Code: SCA
Capital Costs:
EQUIP = 65 (Q) + 13000
INST and IND = 60 (Q) + 2000
Annual Costs:
SPa = 0.05 (TK)
ELEC = 105 (Q)(CF)
FUEL = 21.9 (FC)(Q)(CF)
Spare parts costs consist of the costs for spare parts, maintenance labor,
and maintenance materials.
A-16
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TABLE A-14. COST EQUATIONS FOR STAGED COMBUSTION AIR APPLIED TO
RESIDUAL OIL-FIRED BOILERS (fuel N >0.23 wt. percent)
(30 - 250 x 106 Btu/hr)
Routine Code: SCA
Capital Costs:
TK = 1000 [(Q)(PRCT) 0.0536 + 2.56 (PRCT)]
where:
PRCT = 30; when N j>0.6
PRCT = 81.1(N) - 18.7 when 0.23
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TABLE A-15. FLUE GAS FLOWRATE ALGORITHMS3'b
Natural Gas
FLW = 8.14 x 106 Q/H (non-LEA)
FLW = 6.81 x 106 Q/H (LEA)
Distillate and/or Residual
FLW = 0.189 Q H°'77 (non-LEA)
FLW = 0.156 Q H°'77 (LEA)
Coal (Stoker)
FLW = EXP [8.14 x 10"5H] * 1.84 x 106 Q/H (non-LEA)
FLW = EXP [8.14 x 10'5H] * 1.66 x 106 Q/H (LEA)
Coal (Pulverized)
FLW = 1.62 x 105 * EXP [8.03 x 10"5 H] * Q/H (LEA)
FBC (Pulverized Coal)
FLW = 297.82Q
LEA and non-LEA conditions are defined as follows:
NG and oil: LEA - 15% excess air
Non-LEA - 40% excess air
Coal: LEA - 35% excess air for stokers and 30% excess air
pulverized coal.
Non-LEA - 50% excess air
Flue gas flowrate in acfm.
A-18
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APPENDIX 8
B-l
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TABLE B-l. COST ESCALATION FACTORS
Capital Costs
Capi tal
Operating and
0 & M Co:
Cost Escalation Factor
July 1978
Jan. 1979
July 1979
Jan. 1980
July 1980
Jan. 1981
July 1981
Jan. 1982
July 1982
Jan. 1983
Maintenance Costs
st Escalation Factor ~
July 1978
Jan. 1979
July 1979
Jan. 1980
July 1980
Jan. 1981
July 1981
Jan. 1982
July 1982
Jan. 1983
_ index for update year
index for July 1978
CE Plant Index3
219.2
229.8
239.3
247.5
263.6
276.6
303.1
311.8
314.2
315.5
index for update year
index for July 1978
Producer Price Index
210.1
220.0
237.5
260.6
276.2
291.5
306.2
311.8
312.8
313.9
B-2
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TABLE B-l COST ESCALATION FACTORS (Continued)
Economic Indicators. Chemical Engineering. 85 (23): 7, October 23, 1978;
85_ (11): 7, May 8, 1978; 86_ (24): 7, November 5, 1979; 86 (10): 7,
May 7, 1979; 87 (23): 7, November 17, 1980; 87 (9): 7, May 5, 1980;
88 (23): 7, November 16, 1984; 88 (10): 7, May 18, 1981; 89 (23): 7,
November 15, 1982; 89 (10): 7, May 17, 1982; 90 (24): 7, November 28,
1983; 90 (11): 7, May 30, 1983. ~
BLS Producer Price Index. All Industrial Commodities. File 176,
Dinlog Information Services, Inc. July 26, 1984 update.
B-3
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1.
4.
7.
9.
12
1b
Hm.*gO/3-85-011
TITLE AND SUBTITLE
Industrial Boiler S02 Cost Report
AUTHOR(S)
J.H. laughlin, III, J.A. Maddox, & S.C. Margerum
PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
3200 E. Chapel Hill Road/Mel son Highway
Research Triangle Park, North Carolina 27709
• SEONS.ORING AGENCY NAME AND ADDRESS
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
6. PERFORMING ^^ATIO^^DE
8. PERFORMING ORGANIZATION REPORT N
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3816
13. TYPE OF REPORT AND PERIOD COVERE
14. SPONSORING AGENCY CODE
EPA/200/04
SUPPLEMENTARY NOTES — ~~
Project Officer - Dale Pahl , OAQPS/ESED, MD-13
'
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
S02 Emissions
Coal Air Pollution
Industrial Boilers
Pollution Control Costs
Fuel Standards
Emission Standards
Flue Gas Desulfurization
Coal
Air Pollution Control
19. SECURITY CLASS (This Report)
21. NO. OF PAGES
Unlimited
20 SECURITY CLASS (This pagej
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDI TION i s OBSOLETE
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U.S. Environmental Protection Agency
Region V, Library
230 South Dearborn Street
Chicago, Illinois 60604
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