United States Office of Air Quality EPA-450/3-83-004
Environmental Protection Planning and Standards February 1983
Agency Research Triangle Park NC 27711
Air
Costs of Particulate
Matter Controls
for Nonfossil Fuel
Fired Boilers
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EPA-450/3-83-004
Costs of Particulate
Matter Controls for Nonfossil
Fuel Fired Boilers
Prepared by:
Keith W. Barnett
William D. Kwapil
Suzanne C. Margerum
Radian Corporation
3024 Pickett Road
Durham, North Carolina 27705
Contract No.: 68-02-3058
U.S. Environmental Protection Agency
Region V, Library ^-
230 South Dearborn Street^""
Chicago, Illinois 6060$'^ ...-^
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711 -^
•i '•
February 1983 |
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This report has been reviewed by the Emission Standards and Engineering Division of The Office of
Air Quality Planning and Standards, EPA, and approved for publication. Mention of trade names or
commercial products is not intended to constitute endorsement or recommendation for use. Copies of
this report are available through the Library Services Office (MD-35), U.S. Environmental Protection
Agency, Research Triangle Park, N.C. 27711, or from National Technical Information Services, 5285
Port Royal Road, Springfield, Virginia 22161.
0,S. Environmental Protection Agency
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TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1_1
1.1 ORGANIZATION 1_1
1.2 BOILER CASES EXAMINED 1-1
1.3 SELECTION OF EMISSION CONTROL SYSTEMS AND
EMISSION LIMITS 1_6
1.4 REFERENCES 1_8
2.0 METHODOLOGY FOR CALCULATING UNCONTROLLED BOILER AND
PM CONTROL SYSTEM COSTS 2-1
2.1 CAPITAL COSTS 2-1
2.2 ANNUALIZED COSTS ' 2-22
2.3 REFERENCES 2-32
3.0 COSTS OF PM CONTROL SYSTEMS AND UNCONTROLLED BOILERS 3-1
3.1 CAPITAL COSTS OF BOILERS AND CONTROLS 3-1
3.2 O&M AND TOTAL ANNUALIZED COSTS FOR BOILERS AND
PM CONTROLS 3-6
4.0 OTHER FUEL CASES 4_1
4.1 SALT-LADEN WOOD FIRED BOILERS 4-1
4.2 WOOD/FOSSIL FUEL MIXTURES 4.5
4.3 COSTS OF PM CONTROLS FOR RDF-FIRED BOILERS. . . 4-7
4.4 SOLID WASTE/FOSSIL FUEL MIXTURES 4-10
4.5 REFERENCES 4_H
APPENDIX A - DETAILED LINE BY LINE COSTS A-l
APPENDIX B - ESCALATION FACTORS B-l
m
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LIST OF TABLES
Table
Page
1-1 STANDARD BOILERS SELECTED FOR EVALUATION 1-2
1-2 REPRESENTATIVE STANDARD BOILER CAPACITIES 1-4
1-3 MODEL BOILERS 1-7
2.1-1 CAPITAL COST COMPONENTS 2-2
2.1-2 UNCONTROLLED MODEL BOILER DESIGN SPECIFICATIONS 2-4
2.1-3 ULTIMATE ANALYSES OF THE FUELS SELECTED FOR
MODEL BOILERS 2-9
2.1-4 EMISSION CONTROL SYSTEM DESIGN SPECIFICATIONS 2-10
2.1-5 CAPITAL COST CORRELATION FOR UNCONTROLLED NONFOSSIL
FUEL FIRED BOILERS 2-13
2.1-6 EQUIPMENT INSTALLATION COST FACTORS 2-14
2.1-7 MULTIPLE CYCLONE EQUIPMENT COSTS 2-15
2.1-8 ESTIMATION OF ESP TRANSITION DUCTING COSTS 2-21
2.1-9 SCREEN AREA, HORSEPOWER REQUIREMENT, AND EQUIPMENT COST
FOR FLY ASH REINJECTION SYSTEMS 2-23
2.2-1 ANNUALIZED COST COMPONENTS 2-25
2.2-2 UTILITY AND UNIT OPERATING COSTS 2-26
2.2-3 LABOR COSTS FOR UNCONTROLLED MODEL BOILERS 2-27
2.2-4 MAINTENANCE MATERIALS COSTS FOR UNCONTROLLED MODEL
BOILERS 2-28
2.2-5 OPERATION AND MAINTENANCE COSTS FOR PM CONTROL
SYSTEMS 2-29
2.2-6 AMOUNTS OF SOLID WASTE PRODUCED BY PARTICULATE EMISSION
CONTROLS 2-31
3-1 CAPITAL COSTS FOR MODEL BOILERS 3-2
IV
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LIST OF TABLES (CONTINUED)
3-2 COMPARISON OF WET SCRUBBER CAPITAL COSTS WITH AND
WITHOUT THICKENERS FOR A 150 x 10° Btu/HR WOOD-FIRED
BOILER 3-5
3-3 RELATIONSHIP BETWEEN PM EMISSION LEVELS AND WET SCRUBBER
PRESSURE DROP OR ELECTROSTATIC PRECIPITATOR SCA FOR
NONFOSSIL FUELS 3-12
3-4 ANNUAL O&M COSTS FOR MODEL BOILERS 3-14
3-5 TOTAL ANNUALIZED COSTS FOR MODEL BOILERS 3-17
3-6 COMPARISON OF MODEL BOILER ANNUALIZED COSTS WITHJ\ND
WITHOUT WET SCRUBBER THICKENERS FOR A 150 x 10° Btu/HR
WOOD-FIRED BOILER 3-21
4.1-1 UNCONTROLLED SLW-FIRED BOILER DESIGN SPECIFICATIONS. . . 4-2
4.1-2 EMISSION CONTROL SYSTEM DESIGN SPECIFICATIONS FOR
SLW-FIRED MODEL BOILER 4-3
4.1-3 COMPARISON OF THE PM CONTROL SYSTEM COSTS FOR SLW
VERSUS WOOD FOR A 44 MW BOILER SIZE 4-6
4.2-1 SCA'S REQUIRED TO ACHIEVE ESP OUTLET EMISSION LEVELS
OF 43 NG/J 4-8
4.2-2 CAPITAL AND ANNUALIZED PM CONTROL COSTS FOR 44 MW
WOOD/COAL FIRED BOILER 4-9
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LIST OF FIGURES
Page
Figure
3-1
3-2
3-3
3-4
3-5
3-6
3-7
3-8
3-9
3-10
3-11
Wood and Bagasse-Fired Boilers Capital Costs As A
Function of Boiler Sizes
MSW-Fired Boiler Capital Costs As A Function of
Boiler Size
Capital Costs of PM Controls Applied to Wood-Fired
Boilers As A Function of Boiler Size
PM Control Capital Costs for Bagasse-Fired Boilers As A
Function of Boiler Size
Capital Costs of ESPs Applied to MSW-Fired Boilers As A
Function of Boiler Size
Wet Scrubber Capital Costs Versus Pressure Drop for
Four Boiler Sizes
Wood-, Bagasse- and MSW-Fired Boiler Annualized Costs
As A Function of Boiler Size
Annualized Costs of PM Controls Applied To Wood-Fired
Boilers As A Function of Boiler Size
Annualized Costs of PM Controls Applied To Bagasse-Fired
Boilers As A Function of Boiler Size
Annualized Costs of ESPs Applied To MSW-Fired Boilers As
A Function of Boiler Size
Wet Scrubber Annualized Costs Versus Pressure Drop For
Four Boiler Sizes
3-7
3-8
3-9
3-10
3-11
3-13
3-22
3-23
3-24
3-25
3-26
VI
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1.0 INTRODUCTION
The purpose of this report is to provide supporting cost information
for a potential new source performance standard for nonfossil fuel-fired
boilers. This report presents a cost analysis of particulate matter (PM)
control technologies applied to wood-, bagasse-, and solid waste-fired
boilers. The emphasis is to quantify the individual boiler cost impacts
associated with various control strategies. Also shown are the data used
to calculate these costs. Both uncontrolled and controlled boiler costs are
examined. By comparing the costs of different control technologies, the
incremental cost impact of these technologies can be assessed.
1.1 ORGANIZATION
Chapter 2 presents the methodology used to develop model boiler costs.
Chapter 2 includes the data and references used to develop the design
specifications for the boilers and PM control systems, and to calculate the
costs of the specified systems. The cost results obtained using the cost
methodology in Chapter 2 are shown in Chapter 3. Chapter 4 presents some
individual cases that are not covered by the model boiler categories.
Appendices are included for reference. Appendix A provides the
detailed line-by-line costs for each of the boiler cases examined.
Appendix B gives escalation factors for updating costs. All costs in this
report are in mid-1978 dollars.
1.2 BOILER CASES EXAMINED
The first step in determining the cost cases to be examined is to
specify the standard boilers. A standard boiler represents an uncontrolled
boiler of a specific size and type. Standard boilers are selected to
represent the new NFFB population. Factors used in their selection include
fuels, firing methods, and boiler distribution by capacity. A summary of
the standard boilers selected for evaluation is presented in Table 1-1. The
rationale used to select the boiler fuels and capacities are discussed in
1-1
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TABLE 1-1. STANDARD BOILERS SELECTED FOR EVALUATION
Boiler Type
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Overfeed Stoker
Overfeed Stoker
Spreader Stoker
Fuel3
Wood
Wood
Wood
Wood
MSW
MSW
Bagasse
Heat,-
MW (10°
8.8
22
44
117
44
117
58.6
Input
Btu/hr)
(30)
(75)
(150)
(400)
(150)
(400)
(200)
Wood - hog fuel (wood/bark mixture).
MSW - municipal solid waste.
1-2
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Section 1.2.1. The selection of the boiler firing method is discussed in
Section 1.2.2. After standard uncontrolled boiler cases have been selected,
the control methods and emission levels are selected and combined with the
standard boilers. The combined standard boiler and emission control system
is called a "model" boiler. The selection of control methods and emission
levels is discussed in Section 1.3.
1.2.1 Selection Rationale
The boiler capacities, firing methods, and fuels reflected in the
standard boilers represent current and future designs based on the NFFB
population data. The principal NFFB fuels are wood and bark waste, solid
waste including municipal solid waste (MSW) and refuse derived fuel (RDF),
and bagasse. Boilers are selected to represent each of these basic fuel
types. Representative capacities for each fuel type are then selected
within the range of expected capacities for the new NFFB population.
Whenever practical, boiler capacities for the nonfossil fuel fired boilers
were selected to be the same as those selected in the cost report for fossil
fuel fired boilers. These selection criteria were applied to facilitate
direct comparisons between the fossil fuel fired boiler and nonfossil fuel
fired boiler studies, and to allow comparison of the economic, environ-
mental, and energy impacts resulting from alternative control technologies.
Capacities of NFFBs range from less than 2.9 MW (10 x 106 Btu/hr) to
greater than 117 MW (400 x 106 Btu/hr) of thermal input. However, the
bulk of NFFB capacity consists of watertube boilers larger than 7.3 MW
(25 x 10 Btu/hr). Many boilers at the lower end of the capacity range
are used for space heating, whereas the boilers at the upper end of the
capacity range are generally used to produce process steam, to drive
turbines, and in some cases, to generate electricity. In Table 1-2, the
NFFB capacity range is segmented into four size categories with appropriate
standard boilers chosen to represent each capacity interval.
The bulk of the wood-fired boiler capacity sold consists of watertube
boilers larger than 7.3 MW (25 x 106 Btu/hr) thermal input. Smaller
boilers are generally of the firetube design and are commonly used in the
furniture industry. Emission rates, while variable, are similar across the
entire capacity range.
1-3
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TABLE 1-2. REPRESENTATIVE STANDARD BOILER CAPACITIES
Capacity Range - Thermal Input
Fuel1
7.3-14,7 MW
(25-50 x 10° Btu/hr)
14.7-29.3 MW
(50-100 x 10° Btu/hr)
29.3-73.3 MW
(100-250 x 106 Btu/hr)
>73.3 MW
(>250 x 10° Btu/hr)
Wood
MSW
Bagasse
8.8,MW
(30 x 10° Btu/hr)
22.0,MW
(75 x 10° Btu/hr)
44.0,MW
(150 x 10° Btu/hr)
44.0,MW
(150 x 10° Btu/hr)
58.6.MW
(200 x 10° Btu/hr)
117,-MW
(400 x 10bBtu/hr)
117fiMW
(400 x 10DBtu/hr)
Wood - hog fuel (wood/bark mixture)
MSW - municipal solid waste.
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Four wood-fired boiler sizes of similar design were selected to show
the cost impacts on various size boilers. These sizes are 8.8, 22, 44, and
117 MW (30, 75, 150, and 400 x 106 Btu/hr) thermal input. The fuel
selected for these standard boiler sizes is a hog fuel representative of
wood fuels fired in most wood-fired boilers in the United States. Other
wood fuels, such as high ash bark (HAB), have similar costs of control to
2
hog fuel at similar emission levels. Costs for boilers firing mixtures
of wood and fossil fuels are discussed in Chapter 4.
Two MSW-fired boiler sizes were selected for evaluation, 44 and 117 MW
(150 and 400 x 10 Btu/hr) thermal input. These capacities are expected
to cover the range of sizes for most new large mass burn MSW-fired boilers.
The other type of solid waste-fired boiler, the "controlled" or "starved"
air boiler, is only produced in the smaller size ranges and is not included
in this report.
RDF may be fired alone or cofired with coal. However, the most recent
new boilers built to fire RDF have been designed to fire RDF alone. Little
emission data are currently available for RDF-fired boilers so no standard
boiler can be evaluated for this fuel. However, the estimated costs for
RDF-fired boiler PM emission controls are discussed in Chapter 4.
One standard boiler capacity, 58.6 MW (200 x 106 Btu/hr),
representing bagasse-fired boilers was selected. Most bagasse-fired boilers
sold had a thermal input capacity of about this size or larger. A smaller
bagasse-fired boiler was not included in the analysis because few if any
smaller boilers are anticipated to be built. A larger boiler was not
evaluated since economies of scale would be expected in both boiler and
emission control costs.
1.2.2 Characterization of Standard Boilers
The firing mechanisms for the majority of new wood-fired boilers are
similar across the capacity range. These units are primarily spreader or
overfeed stokers with the major differences being in the type of grate
selected. Some other firing methods used at times to fire wood include
Dutch ovens, fuel cells, and fluidized beds. However, Dutch ovens have been
phased out for new construction due to high costs, low efficiencies, and
1-5
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inability to follow load swings. Participate emission rates from the other
firing mechanisms are usually less than from spreader stokers. Because of
the prevalence of spreader stokers as a firing mechanism for wood-fired
boilers all of the wood-fired standard boilers were selected to be spreader
stokers.
The firing method for MSW-fired boilers is the overfeed stoker design.
This design is the only firing method used for large mass burn MSW-fired
boilers.
Bagasse-fired boilers use spreader stokers, fuel cells, and horseshoes
as firing methods. Horseshoes and fuel cells are pile burning designs
similar to the Dutch oven used to fire wood. They differ in the shape of
the furnace area but in other respects are similar in design and operation.
The basic design of the bagasse-fired spreader stoker is the same as that of
the wood-fired spreader stoker. Most new bagasse-fired boilers are expected
to use spreader stokers so this design was selected for the bagasse-fired
4
standard boiler.
1.3 SELECTION OF EMISSION CONTROL SYSTEMS AND EMISSION LIMITS
Costs for different control levels and types of emission controls are
calculated for each standard boiler case. This allows the cost impacts for
different control levels and control technologies to be compared. The
control technologies that were selected were the technologies that new NFFBs
would be expected to use in the absence of an NSPS, and the technologies
which form the basis of the NSPS. Each combination of a standard boiler,
emission level, and control technology is given a "model" boiler designa-
tion. Table 1-3 shows the emission levels and control technologies selected
for model boiler cost evaluations.
1-6
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TABLE 1-3. MODEL BOILERS0
Model Boiler
Number
WOOD-30-MC (0.60)
WOOD-30-DM (0.40)
WOOD-30-MC/WS (0.30)
WOOD-30-MC/WS (0.15)
WOOD-30-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-MC (0.40)
WOOO-75-MC/WS (0.30)
WOOD-75-MC/WS (0.15)
WOOD-75-MC/WS (0.05)
WOOD-150-MC (0.60)
WOOO-150-DM (0.40)
WOOD-150-MC/WS (0.30)
WOOD-150-MC/WS (0.15)
WOOD-150-MC/WS (0.05)
WOOD-400-MC (0.60)
WOOD-400-DM (0.40)
WOOD-400-MC/WS (0.30)
WOOD-400-MC/WS (0.15)
WOOD-400-MC/WS (0.05)
MSW-150-ESP 0.17)
MSW-150-ESP 0.10)
MSW-150-ESP 0.05)
MSW-400-ESP (0.17)
MSW-400-ESP (0.10)
MSW-400-ESP (0.05)
BAG-200-MC (0.62)
BAG-200-MC (0.30)
BAG-200-MC (0.20)
Fuel
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
Wood
MSW
MSW
MSW
MSW
MSW
MSW
Bagasse
Bagasse
Bagasse
Heat Input
Capacity
MW (10° Btu/hr)
8.8 (30)
8.8 (30)
8.8 (30)
8.8 (30)
8.8 (30)
22 (75)
22 75)
22 (75)
22 (75)
22 (75)
44 (150)
44 150)
44 150)
44 150)
44 (150)
117 (400)
117 (400)
117 (400)
117 (400)
117 (400)
44 (150)
44 (150)
44 (150)
117 (400)
117 (400)
117 (400)
58.6 200)
58.6 200)
58.6 200)
Uncontrolled
PM Emission,Level
ng/J (lb/10b Btu)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 4.88)
2100 4.88)
2100 4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
2100 (4.88)
1440 (3.36)
1440 (3.36)
1440 (3.36)
1440 (3.36)
1440 (3.36)
1440 (3.36)
2170 (5.05)
2170 (5.05)
2170 (5.05)
Controlled
PM Emission,Level
ng/J (lb/100 Btu)
258 (0.6)
172 (0.4)
129 (0.3)
64.5 (0.15)
21.5 (0.05)
258 (0.6)
172 (0.4)
129 (0.3)
64.5 (0.15)
21.5 (0.05)
258 (0.6)
172 (0.4)
129 (0.3)
64.5 (0.15)
21.5 (0.05)
258 (0.6)
172 (0.4)
129 (0.3)
64.5 (0.15)
21.5 (0.05)
73.1 (0.17)
43.0 (0.10)
21.5 (0.05)
73.1 (0.17)
43.0 (0.10)
21.5 (0.05)
267 (0.62)
129 (0.3)
86 (0.2)
Controlb
Device(s)
MC
DM
MC, WS
MC, WS
MC, WS
MC
DM
MC, WS
MC, WS
MC, WS
MC
DM
MC, WS
MC, WS
MC, WS
MC
DM
MC, WS
MC, WS
MC, WS
ESP
ESP
ESP
ESP
ESP
ESP
MC
WS
WS
Wood - hog fuel (wood/bark mixture).
MSW - municipal solid waste.
MC - mechanical collector.
DM - dual mechanical collector.
WS - wet scrubber.
ESP - electrostatic precipitator.
Control systems separated by a comma mean that both are used at the same time, not that either may
be used independently. Differences in emission levels for similar control systems are based on
differences in control system design (see Table 2.1-4).
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1.4 REFERENCES
1. Bowen, M.L. and M.S. Jennings. (Radian Corporation.) Costs of Sulfur
Dioxide, Particulate Matter, and Nitrogen Oxide Controls on Fossil Fuel
Fired Industrial Boilers. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. Publication No.
EPA-450/3-82-021. May 1982. p. 2-3.
2. U.S. Environmental Protection Agency. Nonfossil Fuel Fired Industrial
Boilers - Background Information. Research Triangle Park, N.C. EPA
Publication No. 450/3-82-007. March 1982. pp. 8-22 to 8-38.
3. Schwleger, B. Power from Wood. Power. 124:5.22 - S.23. February
1980.
4. Memo from Barnett, K., Radian Corporation, to file. January 27, 1982.
22 p. Projections of new nonfossil fuel fired boilers (NFFBs).
1-8
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2.0 METHODOLOGY FOR CALCULATING UNCONTROLLED BOILER
AND PM CONTROL SYSTEM COSTS
This chapter presents the bases used to calculate capital and
annualized costs for uncontrolled standard boilers and the particulate
matter (PM) emission control systems shown in Section 1.3. Section 2.1
discusses how capital costs were calculated, including boiler and control
equipment design specifications and the sources for the cost data.
Section 2.2 presents the bases used to calculate annualized costs.
2.1 CAPITAL COSTS
This section presents the information used to develop capital costs for
boilers and PM control systems.
2.1.1 Capital Cost Components
The capital cost is the total investment required to supply a complete
boiler/emission control system. Components of the capital costs, itemized
in Table 2.1-1, include total direct and indirect investment costs,
contingencies, land, and working capital.
The equipment costs are the basis of the other capital cost components
listed in Table 2.1-1. The cost of equipment installation, for example, is
estimated as a fraction of the equipment cost. Other cost components such
as engineering are then estimated as fractions of the sum of the equipment
and installation costs.
The boiler capital costs include the following boiler equipment items:
- fuel handling and storage systems;
- feedwater and condensate treatment systems;
- boiler and auxiliaries (feed pumps, chemical feed system,
soot blowers, instrumentation, and FD and ID fans); and
- bottom ash disposal systems.
Equipment included in the capital costs attributed to the emission control
system include:
- control equipment and auxiliaries;
2-1
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TABLE 2.1-1. CAPITAL COST COMPONENTS
1,2
(1) DIRECT INVESTMENT COSTS
Equipment
Installation
TOTAL DIRECT INVESTMENT COSTS (TDI)
(2) INDIRECT INVESTMENT COSTS
Engineering3 ,
Construction and Field Expense
Construction Fees
Start Up Costs ,
Performance Tests
TOTAL INDIRECT INVESTMENT COSTS (Til)
(3) CONTINGENCIES6
TOTAL TURNKEY COSTS (TTC)f
(4) LAND9
(5) WORKING CAPITAL11
TOTAL CAPITAL COSTS (Total Turnkey Costs + Land + Working Capital)
Estimated as 10% of Total Direct Investment Costs (TDI) for boiler and PM
control systems.
Estimated as 10% of TDI.
Estimated as 2% of TDI.
Estimated as greater of 1% of TDI or $3,000.
Estimated as 20% of the sum of TDI and Til.
Sum of TDI, Til, and Contingencies.
9EsJimated as: $1,000 for boilers with heat input capacities <22 MW (75 x
10g Btu/hr); $2,000 for boilers with heat input capacities >22 MW (75 x
10 Btu/hr); 0.084% of TTC for emission control systems.
Estimated as 25% of Total Direct Operating Costs.
2-2
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- ducting (from the boiler system to the emission control system
and stack);
- fans (increased fan capacity for overcoming control system
pressure drop);
- solids separation systems; and
- fly ash disposal systems.
In some model boilers, the bottom ash disposal system is combined with
the fly ash disposal system. In allocating the capital cost of the ash
disposal system, only the incremental cost of the combined system over the
cost of a bottom ash disposal system is allocated to the emission control
capital cost.
The control system capital costs were developed in terms of mid-1978
dollars and are generally accurate to ±30%. Boiler costs were developed
without detailed evaluation of equipment costs and are expected to be less
accurate than the control system costs.
2.1.2 Standard Boiler Specifications
The specifications for the standard boilers provide the basis for
calculating the costs of uncontrolled boilers. The primary specifications
used in this analysis are:
- Fuel type and quality
- Design capacity and load factor
- Flue gas characteristics
Each of these areas is discussed below. Table 2.1-2 presents design
specifications for the standard boilers.
2.1.2.1 Fuels. The fuel specifications have been chosen to represent
currently available choices for nonfossil fuels and are presented in
Table 2.1-3. The fuel characteristics, including heating value and chemical
analysis, are specified to determine the combustion-related characteristics
of the standard boilers.
All of the standard boilers firing wood use a wood fuel analysis
representative of a hog fuel, which is a mixture of wood and bark and is
representative of wood fuels fired in most wood-fired boilers in the United
2-3
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TABLE 2.1-2. UNCONTROLLED MODEL BOILER DESIGN SPECIFICATIONS
ro
i
Model Boiler Number
Thermal input, MW (106 Btu/hr)
Fuel3
Fuel rate, kq/s
(ton/hr)
Analysis
% sulfur
% ash
Heating value, kJ/kg
(Btu/lb)
WOOD-30
8.8 (30)
Wood
0.829
(3.29)
0.02
1.00
10,600
(4,560)
WOOD-75
22.0 (75)
Wood
2.07
(8.22)
0.02
1.00
10,600
(4,560)
WOOD-150
44.0 (150)
Wood
4.15
(16.4)
0.02
1.00
10,600
(4,560)
WOOD-400
117 (400)
Wood
11.1
(43.9)
0.02
1.00
10,600
(4,560)
Excess air, %
o
Flue gas flow rate, m /s (acfm)
Flue gas temperature, K (°F)
Load factor, %
Flue gas constituents, kg/hr (Ib/hr)
50
6.94(14,700)
478 (400)
60
50
17.3(36,700)
478 (400)
60
50
34.7(73,500)
478 (400)
60
50
92.5 (196,000)
478 (400)
60
Fly ash (before mechanical collector^
(after mechanical collector)
S0?
N0x
Ash from sand classifier, kg/hr (Ib/hr)
Bottom ash, kg/hr (Ib/hr)
Boiler Output, MW (106 Btu/hr)
Steam
Losses
Efficiency, %
Steam qualify
Pressure, kPa (psig)
Temperature, K (°F)
Steam production,6 kg/hr (Ib/hr)
66.2 (146)
13.3 (29.3)
3.40 (7.50)
29.2 (64.4)
20.1 (44.4)h
5.7 (19.5)
3.1 (10.5)
65
1,720 (250)
481 (406)
8,890
(19,600)
166 (366)
33.2 (73.2)
8.53 (18.8)
73.0 (161)
50.3 (lll)h
14.3 (48.7)
7.7 (26.3)
65
1,720 (250)
481 (406)
22,200
(49,000)
332 (732)
66.4 (146)
17.0 (37.5)
146 (322)
101 (222)h
28.6 (97.5)
15.4 (52.5)
65
1,720 (250)
481 (406)
44,500
(98,200)
885 (1950)
177 (390)
45.3 (100)
390 (859)
269 (592)h
76.1 (260)
41.0 (140)
65
5,170 (750)
672 (750)
101,000
(223,000)
See footnotes at end of table.
-------
TABLE 2.1-2. (CONTINUED)
i
en
Model Boiler Number
Thermal input, MW (106 Btu/hr)
Fuel3
Fuel rate, kg/s
(ton/hr)
Analysis
% sulfur
% ash
Heating value, kJ/kg
(Btu/lb)
Excess air, %
0
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K (°F)
Load factor, %
MSW-150
44.0 (150)
MSW
3.88
(15.4)
0.12
22.38
11,340
(4,875)
100
41.8 (88,500)
478 (400)
60
MSW-400
117 (400)
MSW
10.3
(41.0)
0.12
22.38
11,340
(4,875)
100
111 (236,000)
478 (400)
60
BAG-200
58.6 (200)
Bagasse
6.43
(25.5)
Trace
1.10
9,116
(3,920)
50
47.7 (101,000)
478 (400)
45
Flue gas constituents, kg/hr (Ib/hr)
Fly ash (before mechanical collector)0
(after mechanical collector)
S0?
NOX
Ash from sand classifier,9 kg/hr (Ib/hr)
Bottom ash, kg/hr (Ib/hr)
£•
Boiler Output, MW (10° Btu/hr)
Steam
Losses
Efficiency, %
Steam quality
Pressure, kPa (psig)
Temperature, °K (°F)
Steam production,6 kg/hr (Ib/hr)
\f*C* Tr^rti"ltr\'l~£lC 3 4" f\n A r\ -f " ~4- -» l-» 1 f\ " "~
229 (504)
33.5 (73.8)
21.0 (46.2)
-
3,490 (7,690)
30.8 (105)
13.2 (45)
70
3,100 (450)
589 (600)
43,600 (96,000)
608 (1,340)
89.3 (197)
56.0 (123)
_
9,310 (20,500)
81.9 (280)
35.1 (120)
70
5,170 (750)
672 (750)
109,000 (241,000)
458 (1,010)
18.1 (40.0)
—
145 (319)
35.2 (120)
23.4 (80)
60
1,720 (250)
533 (500)
51,700 (114,000)
-------
CT)
FOOTNOTES TO TABLE 2.1-2:
aWood - hog fuel (wood/bark mixture)
MSW - municipal solid waste
Uncontrolled emissions. .
cFly ash before mechanical collector means uncontrolled emissions prior to any control device
whether a mechanical collector is used or not.
dGuage pressure.
Assuming a saturated condensate return at 10 psig.
be the mass equivalent of an emission level of 258 ng/J (0.6 Ib/lU btu).
£.
WOOD-75-MC (0.60)! WOOD-150-MC (0.60), and WOOD-400-MC (0.60) respectively.
-------
States. The fuel moisture, sulfur, and nitrogen contents were selected as
representative values based on other literature data4 and on fuel analyses
from emission test reports.
The MSW composition was taken from a performance test conducted on
boilers at an operating facility. The analysis compares closely with
reported "typical" compositions for MSW6 except that the heating value of
the selected waste is somewhat higher. However, the heating value of MSW in
the United States has been increasing with time, and the heating value of
the selected waste falls well within the range of values predicted by
several studies for the 1985 - 1990 time frame.7
The bagasse composition was based on an average dry composition
reported in the "Cane Sugar Handbook". Sulfur and nitrogen concentrations
were based on values reported in various other sources. Fuel moisture was
set at an intermediate level based on values reported in "The Gilmore Sugar
Manual".9
2.1.2.2 Boiler capacities and load factors. The capacities of the
standard boilers selected are based on the maximum heat input to the boiler.
The heat input together with the heating value of the fuel determines the
fuel firing rate. To quantify the steam output, the thermal efficiency and
steam quality of the boiler must be specified. The thermal efficiency of
the boiler is the measure of the percentage of heat input which is
transferred to the steam cycle and is a function of the fuel properties,
firing method, flue gas characteristics, and boiler heat losses. Thermal
efficiencies shown in Table 2.1-2 are generally based on values reported in
the literature for wood,10 MSW,11'12 and bagasse-fired13 boilers.
The quality of the steam is specified in terms of temperature and
pressure. The steam quality varies with the intended steam use. The steam
temperatures and pressures specified for the standard boilers are those
commonly found in various applications for the selected boiler capacities.
Steam qualities were selected based on watertube boiler sales data14 for
wood and bagasse-fired boilers, and various literature references.15'16
The capacities of the standard boilers represent maximum firing rates.
Boilers, however, seldom operate at maximum capacity year-round. To analyze
2-7
-------
impacts on an annual operating basis, an appropriate measure of actual
boiler usage must be selected. The load factor (or capacity utilization
factor) is the actual annual fuel consumption as a percentage of the
potential annual fuel consumption at maximum firing rate. Load factors for
industrial boilers are estimated to range from 30 to 80 percent.17 Load
factors for MSW resource recovery plants installed by 1990 are forecasted to
1 Q
average 60-80 percent.
Low load factors generally represent "nonprocess" boilers or boilers
used in seasonal industries, such as bagasse-fired boilers. High load
factors generally represent process or utility boilers whose output is tied
directly to plant production. Load factors can vary considerably from plant
to plant and from industry to industry and are influenced by such items as
the economic climate of the country, the availability of nonfossil fuels,
the reliability of the boiler and fuel feeding equipment, and decisions to
buy oversized boilers to allow for plant expansions. Load factors for the
standard boilers were generally set at 60 percent for each boiler and fuel
combination. Bagasse-fired boilers were assigned a lower load factor of
45 percent due to the seasonal nature of the industry.
2.1.2.3 Flue gas characteristics. Temperature, composition, and
volumetric flow rate are the main flue gas characteristics upon which the
design of emission control systems are based. These characteristics are
mainly affected by fuel composition and boiler excess air. Fuel analyses
are presented in Table 2.1-3. A representative excess air value was
selected for each standard boiler and is included in Table 2.1-2. The
pollutant concentrations in the flue gas are calculated based on the excess
air rate, the chemical composition of the fuel, and the pollutant emission
factors developed in Chapter 3 of "Nonfossil Fuel Fired Industrial Boilers -
Background Information" for each standard boiler.
2.1.3 PM Control System Design Specifications
Emissions control system design specifications are detailed in
Table 2.1-4. These specifications are based on emission test data and
design data from existing NFFB facilities.
2O
"O
-------
TABLE 2.1-3. ULTIMATE ANALYSES OF THE FUELS SELECTED
FOR MODEL BOILERS
Composition, % by weight
Moisture
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Ash
Gross Heating
Value kJ/kg (Btu/lb)
Wood
50.0
26.95
2.85
0.08
19.10
0.02
1.00
10,600
(4,560)
FueJ
MSW"
27.14
26.73
3.60
0.17
19.74
0.12
22.38
11,340
(4,875)
Bagasse
52.00
22.60
3.10
0.10
21.10
Trace
1.10
9,116
(3,920)
Wood - hog fuel (wood/bark mixture); MSW - municipal solid waste.
Composition does not total 100 percent due to the presence of chlorine
which is not shown here.
2-9
-------
TABLE 2.1-4. EMISSION CONTROL SYSTEM DESIGN SPECIFICATIONS
Control System
Item
Specification
Multiple cyclone
Material of construction
Tube diameter
Pressure drop
Design PM removal efficiency
Carbon steel
23 cm (9 in.)
750 Pa (3 in. w.c.)
Model boilers WOOD-MC (0.60) and
BAG-200-MC (0.62): 88%
WOOD-DM (0.40) (upstream),
WOOD-MC/WS (0.30), WOOD-MC/WS (0.15), and
WOOD-MC/WS (0.05): 80%
WOOD-DM (0.40) (downstream): 60%
Wet Scrubbers
ro
i
Material of construction
Scrubber type
Liquid-to-gas ratio (L/G)
Liquid discharge pressure
Liquid pumping height
Length of piping
Sludge handling equipment/
characteristics
FRP-lined carbon steel
Model boilers WOOD-MC/WS (0.30): impingement
WOOD-MC/WS (0.15), WOOD-MC/WS (0.05),
BAG-200-WS (0.30), and BAG-200-WS (0.20):
variable throat venturi
o o
Impingement scrubbers: 0.4 dm liquid/m gas
(3 gal/1000 acf)
3 3
Venturi scrubbers: 0.4 dm liquid/m gas
(10 gal/1000 acf)
170 kPa (10 psig)
6 m (20 ft.)
30 m (100 ft.)
Clarifier; sludge comprises 30% solids
(except for BAG-200-WS (0.30) and
BAG-200-WS (0.20) where no clarifier
is used)
-------
TABLF 2.1-4. (CONTINUED)
Control System
Item
Specification
Wet Scrubbers
Electrostatic
Precipitator
Pressure drop (gas-phase) and
design PM removal efficiency
Venturi scrubber separator
pressure drop
Mist eliminator pressure drop
Model Boilers WOOD-MC/WS (0.30); IkPa
(4 in. w.c.j; 69%
WOOD-MC/WS (0.15); 2.2kPa
(9 in. w.c.); 84%
WOOD-MC/WS (0.05); 5kPa
(20 in. w.c.); 95%
BAG-200-WS (0.30); l.BkPa
(6 in. w.c.); 94%
BAG-200-WS (0.20); 2.5 kPa
(10 in. w.c.); 96%
750 Pa (3 in. w.c.)
250-500 Pa (1-2 in. w.c.) (Mist eliminators
are installed only on scrubbers with
gas-phase pressure drops exceeding
1.2 kPa or 5 in. w.c.)
Material of construction
Design specific collection area
Pressure drop
Power demand (average)
Carbon steel (insulated)
Model boilers MSW-ESP (0.17): 24 m2/(m3/s)
(160 flVlOOO acfml; 94.9%
MSW-ESP (0.10): 47 r//(ur/s)
(240 fr/1000 acfm); 97.0%
MSW-ESP (0.05): 93 (//(rrT/s)
(410 fr/1000 acfm); 98.5%
250 Pa (1 in. w.c.)
Model boilers MSW-15Q and MSW-400;
32 W/in plate area (3 W/ftZ)
Overall System
Pressure drop
Duct features
250-750 Pa (1-3 in. w.c.) plus pressure drops
from individual control equipment
Main duct length: 20-30 m (60-100 ft)
Expansion joints for duct connecting two
pieces of control equipment
Elbows
Transition ducting for ESPs
-------
2.1.4 Calculation of Capital Costs of Uncontrolled Model Boilers
Uncontrolled boiler costs were based on owner/vendor data and
?n
previously estimated costs for fossil fuel fired boilers. This study did
not attempt to develop boiler system costs by separately considering the
costs of individual boiler subsystems. Considering the boiler subsystems
separately would have required a more detailed analysis and design of boiler
systems than possible within the scope of this study.
The costs for uncontrolled boilers were developed as total turnkey
costs (TTC). Land and working capital costs were calculated using the
factors shown in Table 2.1-1. The generalized equation used to estimate TTC
was:
total turnkey costs ($1000) = axb
where x is the boiler heat input capacity in million Btu per hour.
The capacity exponent "b" was assumed to be 0.77 based on literature
21 7?
data and costs developed for coal-fired boilers. Cost data from boiler
owners, vendors, or literature was used to estimate the value of "a" for
each fuel. The resulting correlations for each fuel type are shown in
Table 2.1-5.
2.1.5 Calculation of capital costs of PM control systems
As discussed in Section 2.1.1, equipment costs are the basis of the
other capital cost components. Therefore, this section will mainly discuss
equipment costs. The factors used to estimate installation costs from
equipment costs are shown in Table 2.1-6. Factors used to estimate the
remaining components of the capital cost are shown in Table 2.1-1.
2.1.5.1 Multiple cyclone. Costs for 9" tube diameter multiple
cyclones are based on data from a vendor. These costs are presented in
Table 2.1-7.
2.1.5.2 Electrostatic precipitator (ESP). ESP costs are estimated
from cost algorithms presented in PEDCO's "Capital and Operating Costs of
24
Particulate Controls on Coal and Oil-fired Industrial Boilers. These
2
algorithms estimate the ESP equipment cost (in $/ft of collecting surface
area) as a function of the total ESP collection area. The total ESP
collection area (TPA) is simply estimated as:
2-12
-------
TABLE 2.1.5. CAPITAL COST CORRELATION FOR
UNCONTROLLED NOMFOSSIL FUEL FIRED BOILERS
Fuel Cost Correlation9
Wood TTC = 127.3x°'77
Bagasse TTC = 93.385x°'77
Municipal Solid Waste TTC = 343.82x°'77
a
TTC
- total turnkey cost ($1000). fi
x - boiler heat input capacity (10 Btu/hr).
2-13
-------
TABLE 2.1-6. EQUIPMENT INSTALLATION COST FACTORS
Equipment Item
I.
II.
III.
IV.
V.
VI.
VII.
dThe
Emission Control Equipment
A. Multiple cyclone
B. Electrostatic precipitator
C. Wet scrubber
Scrubber Auxiliaries
A. Circulation pumps
B. Pipingb
C. Circulation tank
Fan
Solids Separation
Ducting
Ash removal
A. Oumpster
B. Pneumatic conveying system/silo
Screen for Sand Classification
installation cost is equal to the ratio
Cost of Equipment Instal
Equipment Cost
Items included in the installation cost are
(1) freight and taxes
(2) foundations and supports
(3) erection and handling
(4) electrical
(5) piping
(6) insulation
(7) painting
(8) building (boiler)
Installation
0
1
0
1
0
0
1
1
1
0
1
1
of
lation
the following
Cost Factor3 Source
.78
.0
.68
.49
.0
.93
.18
.5
.6
.33
.0
.34
Refs. 26, 29
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Ref.
Raf.
Ref.
Ref.
Ref.
24
26
27
27
29
29
30
24
2H
24
24
Materials cost for piping includes installation.
2-14
-------
TABLE 2.1-7. MULTIPLE CYCLONE EQUIPMENT COSTS24
Multiclone Equipment Costs
Flow Rate, acfm Mid-1980 $
14,000 9,600
35,000 20,300
69,000 36,700
97,000 48,000
187,000 96,000
2-15
-------
TPA (ft2) = Gas Flow (acfm) x Design SCA (ft2/1000 acfm) x 1.1
where 1.1 is a design contingency factor. The ESP equipment cost (in $/ft2)
is estimated with one of two equations:
for TPA <28,000 ft2, cost ($/ft2) = 24.57 - 5.62 ,TPAN
for TPA >28,000 ft2, cost ($/ft2) = 9.65 - 2.54 ,TPAv
( — f)
10b
2.1.5.3 Wet scrubber and auxiliaries. Equipment costs for impingement
scrubbers are based on vendor data and are estimated as a function of the
0 *~
saturated gas flow leaving the scrubber. The cost correlation is:
Cost ($1000) = 3.15 X (Saturated Gas Flow, acfm)0-75
The cost correlation shown applies to impingement scrubbers made of SS 304.
Costs for scrubbers featuring different materials of construction are
adjusted by the following factors:
- for FRP-lined carbon steel, multiply above cost by 0.5
- for SS 316, multiply above cost by 1.30
Equipment costs for venturi scrubbers are estimated from GARD26 as a
function of the gas flow entering the scrubber, the required design pressure
drop, and the material of construction. The use of GARD's cost correlations
is described in detail in pages 5-11 through 5-18 of Reference 26, and is
not further described here. The GARD costs include the costs of the venturi
scrubber, elbow, cyclonic-type separator, pumps, and controls. Costs shown
in Chapter 3 assume the use of a manually adjusted variable venturi throat.
Equipment costs for mist eliminators are not considered in this cost
analysis because mist eliminators are inexpensive relative to the cost of
2-16
-------
scrubbers. (Energy costs due to the gas-phase pressure drop of the mist
eliminators are included.)
Scrubber auxiliaries include piping, circulation tanks, and circulation
pumps. The estimation of the cost of these auxiliaries varies with the type
of scrubber used.
Piping costs are estimated for both venturi and impingement scrubbing
systems. Piping costs are based on a 100-foot length of stainless steel
pipe with an average liquid velocity in the pipe of 10 feet/sec. The cost
of the piping is estimated from the required pipe diameter and pipe length,
?7
based on data from Process Plant Estimating Evaluation and Control. With
the unit piping cost in $/ft (mid-1970s) from Reference 27, piping costs,
including materials and installation, are then estimated as:
Cost $ = 100 ft X ($/ft) X 3.22 X 1.77
where 3.22 is a material adjustment factor for stainless steel, and 1.77 is
a cost escalation index factor.
Costs for circulation tanks for impingement and venturi wet scrubbers
OQ
are estimated from Plant Design And Economics For Chemical Engineers as a
function of the holding capacity (gal) and the material of the construction.
The circulation tank is based on a 5 minute holdup of liquid; holding
capacity is simply 5 minutes X L gpm. The equipment cost (January 1967$)
for a tank made of SS 304 is obtained directly from Reference 28. The
equipment cost in mid-1978 dollars is 2.05 times the January 1967 cost.
Costs for circulation pumps are estimated from Data and Techniques for
Preliminary Capital Cost Estimating. Pump costs are determined from the
liquid pumping capacity (gpm) and the pump head (psi). The pumping capacity
is determined from the gas flowrate and the 1iquid-to-gas ratio. The pump
head is determined from an energy balance.
The cost of a pump is reported in Reference 29 as a function of a "C/H
factor" with units of gpm-psi. The C/H factor is determined by multiplying
the pump capacity and head.
2-17
-------
For centrifugal pumps used with impingement scrubbers, the cost of the
circulation pump and its spare is estimated as:
Cost (mid-1978 $) = Cost (mid-1968 $) X 1.96 X 1.93 X 2
where 1.96 is an escalation cost factor, 1.93 is a cost adjustment factor
for stainless steel, and 2 is the number of pumps.
As noted previously, the costs for venturi scrubbers include the
cost of a circulation pump and its spare. Use of the correlations from
Reference 26 estimates the costs of pumps accurately unless the pump
construction material differs from the scrubber construction material.
For this cost analysis it was assumed that all scrubber auxiliaries are
constructed of stainless steel even when the scrubber is made of carbon
steel. (Stainless steel is preferred for its superior corrosion resis-
tance.) Thus, the incremental cost of stainless steel pumps needs to be
added as a scrubber auxiliary cost when the scrubber construction is lined
carbon steel. The incremental cost is estimated as:
Cost (mid-1978 $) = Cost (mid-1968 $) X 1.96 X 0.93 x 2
1.15
where 1.15 is a cost adjustment factor for fiberglass lining and 0.93 is an
incremental cost adjustment factor for stainless steel.
2.1.5.4 Fan and auxiliaries. Fan and auxiliaries (inlet damper, motor
and starter) costs are determined principally from cost correlations in
o c
GARO. The use of GARD's cost correlations is described in detail in
Pages 4-57 through 4-70 of Reference 26, and is not discussed further here.
Backwardly-curved fans are used in ESP applications and radial-tip fans are
used in all other applications.
Fan and inlet damper costs are estimated from the gas flow and the gas
pressure drop (corrected with a "sizing factor" from SARD). The costs are
corrected with a high-temperature correction factor (1.06) and are escalated
to mid-1978 $ by an escalation factor of 1.03.
Motor and starter costs are estimated from the bhp requirements, which
are simply calculated from the ghp requirements:
2-18
-------
1) bhp = ghp * 0.6 where 0.6 is the fan efficiency.
2) ghp = 1.576 X 10"4 (acfm) (AP, in. w.c.).
The motor and starter costs are then obtained directly from GARD
correlations (with an escalation factor of 1.03) unless the horsepower
requirements exceed the limits of the GARD data. When GARD data for
specific applications are unavailable, the cost of the motor and starter are
approximated with driver costs reported in Reference 27.
2.1-5.5 Solids separation. Scrubbing systems used for PM removal use
clarifiers to produce a sludge comprising 30 percent solids. The costs for
solids separation system is estimated from correlations of costs from the
Technology Assessment Report for Industrial Boiler Application: Flue Gas
Desulfurization. The correlation for solids separation without a vacuum
filter, the system used for PM removal is:
Cost ($1000) = 8.932 (kg/hr of wet sludge)0'351
Note that the sizing and cost of these processing modules depend on the
maximum amount of sludge produced. Independently estimated PM solids
separation costs may differ.
Bagasse-fired model boilers BAG-200-WS(0.30) and BAG-200-WS(0.20) do
not have a solids separation system included in wet scrubber costs. Because
these boilers are located at sugar mills, it is possible to combine the wet
scrubber waste water with other waste streams. The combined waste water is
treated in a central facility or sent to a settling pond.31 The incremental
cost of the addition of the wet scrubber waste water is assumed to be
negligible. An installed cost of $5,000 is included for the piping to
transport the scrubber waste water for final treatment or disposal.
2.1.5.6 Ducting. Ducting costs are estimated mainly from cost
26
correlations in GARD. Duct costs, in $/ft, are provided in GARD as a
function of the duct diameter. The duct costs are simply estimated as the
duct length (ft) times the unit duct cost ($/ft). Other ducting component
costs, such as costs for elbows, tees, dampers, and expansion joints, are
2-19
-------
estimated directly from GARD as a function of the duct diameter. All of the
costs obtained from GARD are indexed with an escalation factor of 1.03.
Duct diameter, which is the key component in estimating duct costs, is
calculated as D, in. = 13.54 Q/V°'5 where Q is the actual gas flowrate in
ftVnrin and V is the gas velocity, assumed to be 3,600 fpm (60 fps).
The costs for ESP transition ducting are determined directly from
PEDCo's "Capital and Operating Costs of Particulate Controls on Coal and
Oil-Fired Industrial Boilers".24 As estimated by PEDCo, transition ducting
costs vary only with the boiler size (or flue gas flow) and do not vary with
ESP size. Transition ducting costs were back calculated from PEDCo's
ducting costs by comparing reported ducting costs for comparable baghouse
and ESP applications: the difference in costs is assumed to be the cost of
the ESP transition ducting. Calculations for transition ducting costs are
shown in Table 2.1-8. Costs are not correlated as a function of flue gas
flow but instead the estimated transition costs in Table 2.1-8 are used
directly. Costs variations due to minor differences in flue gas flows are
negligible and are neglected.
2.1.5.7 Ash removal. For model boilers WOOD-30 and WOOD-75 the ash
handling systems are simple systems consisting of dumpsters into which the
sand classifiers empty directly. The costs for these systems are estimated
from Reference 24 as $3000.
For the other model boiler cases costs are based on combined boiler
bottom ash/fly ash handling systems. These more "complicated" systems
consist of pneumatic piping and valves, an ash storage silo (with affiliated
baghouse for dust control), piping and connections from the hoppers to the
pneumatic system, and electrical and sequencing controls. The cost for
these complicated systems depends on the size of the underhopper piping and
the amount of fly ash handled.
The cost correlation for the "complicated" ash handling systems is:
Cost ($1000) = 38.38 (Ibs/hr of ash removed)0'153
2-20
-------
TABLE 2.1-8. ESTIMATION OF ESP TRANSITION DUCTING COSTS (MID-1978 $)
Bojler Size PEDCo PEDCo Estimated Transition
10 Btu/hr ESP Duct Costs, $ Baghouse Duct Costs, $ Duct Costs, $
30 27,100 20,100 7,000
26,600 19,800 6,800
6,900 (avg)
75 - - 11,400
(interpolated)
150 64,100 45,000 19,100
63,000 44,300 18,700
18,900 (avg)
400 102,400 68,300 34,100
101,000 67,500 33,500
33,800
-------
and is based on data from Reference 24. (Note that the cost of ash handling
systems is based on the maximum amount of ash removed.) This correlation is
used to estimate the costs of bottom ash and combined handling systems. The
incremental cost of the combined handling system over the boiler bottom ash
system is attributed to the emission control system.
2.1.5.8 Sand classification. Little data are available to design and
cost sand classification systems used in fly ash reinjection. Rotary
screens appear to be commonly used for sand classification. Because rotary
screen costs are not readily available, costs for sand classifiers are
approximately estimated here from costs reported in Process Plant Construc-
30
tion Estimating Standards Volume 4 for vibrating screens (and costs from
GARD for required motors).
Screen costs and horsepower requirements are reported in Reference 31
as a function of the screening area. The required screening area is
determined from capacity data (in tons per hour of material passing through
one square foot of screen cloth) which is reported in Reference 32 as a
function of the screen size and the type of material. Both of these
parameters can only be very roughly estimated for wood fly ash reinjection
systems since so few data are available.
The estimated screen areas, horsepower requirements, and costs are
itemized in Table 2.1-9. Costs from Reference 32 are adjusted with an
escalation cost factor 0.88; costs from GARD (Reference 26) are adjusted by
a factor of 1.03.
2.1.5.9 Utilities and services. Utilities and services equipment and
installation costs are estimated as 6% of all other direct investment
costs.
2.2 ANNUALIZED COST
This section presents the methods used to calculate the annualized
costs for the standard boilers and control systems.
2-2?.
-------
TABLE 2.1-9. SCREEN AREA, HORSEPOWER REQUIREMENT, AMD
EQUIPMENT COST (MID 1978$) FOR FLY ASH REINJECTION SYSTEMS
Model Boiler No.
WOOD-30-MC (0.60)
WOOD-30-DM (0.40),
WOOD-30-MC/WS (0.30)
WOOD-30-MC/WS (0.15)
WOOD-30-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-DM (0.40),
WOOD-75-MC/WS (0.30)
WOOD-75-MC/WS (0.15)
WOOD-75-MC/WS (0.05)
WOOD-150-MC (0.60)
WOOD-150-DM (0.40),
WOOD-150-MC/WS (0.30
WOOD-150-MC/WS (0.15
WOOD-150-MC/WS (0.05
WOOD-400-MC (0.60)
WOOD-400-DM (0.40),
p
Screen Area, ft
24
18
9
9
56
45
»
»
112
90
),
),
320
240
Horsepower
Requirement
3
3
5
5
15
5
30
15
Equipment
Screen
7,200
7,100
8,700
8,400
13,400
10,300
24,200
20,900
Costs
Motor
150
150
350
350
540
350
750
540
WOOD-400-MC/WS (0.30)
WOOD-400-MC/WS (0.15)
WOOD-400-MC/WS (0.05)
2-23
-------
2.2.1 Annualized Cost Components
The annualized cost includes all the costs incurred in the yearly
production of steam. These costs include direct and indirect operating
costs and annual charges attributed to the initial capital expenditure.
Components of the annualized cost are itemized in Table 2.2-1.
The capital recovery factors used in this report are based on an
interest rate of 10 percent and a 15 year economic equipment life. Since
all costs in this report are in constant 1978 dollars, this interest rate is
in real dollars and represents the cost of capital above the general
inflation rate.
Utility and unit operating costs used in this report are presented in
Table 2.2-2.
2.2.2 Calculation of Annualized Costs for Annualized Costs for Boilers and
Control Systems
2.2.2.1 Labor and maintenance costs. Labor costs for NFFBs are based
on the labor costs for similar sized coal-fired boilers. Labor costs for
uncontrolled model boilers are shown in Table 2.2-3. For bagasse-fired
boilers the labor costs calculated from Table 2.2-3 are multiplied by 0.5
because these boilers operate only part of the year.
Costs of maintenance materials are calculated from the equations shown
in Table 2.2-4. The equations are based on data from Reference 20 and data
from boiler owners.
Costs of labor and maintenance materials for PM control systems are
calculated using the equations shown in Table 2.2-5. The equations are
based on Reference 24, data from boiler owners, and engineering judgement.
2.2.2.2 Electricity, chemicals, and process water costs. The combined
cost of electricity chemicals and water for uncontrolled wood- and bagasse-
fired boilers are calculated using the following equation:
cost = CF(29,303 + 719.8x)
where x is the system capacity in million Btu/hr and CF is the boiler
capacity factor expressed as a decimal.
2-24
-------
TABLE 2.2-1. ANNUALIZED COST COMPONENTS
(1) DIRECT OPERATING COSTS
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Chemicals
Waste Disposal
Solids (fly ash and bottom ash)
Sludge
Fuel
TOTAL DIRECT OPERATING COSTS
(2) INDIRECT OPERATING COSTS
Payroll Overhead3
Plant Overhead
TOTAL INDIRECT OPERATING COSTS
(3) CAPITAL CHARGES
G & A, Taxes, and Insurance^
Interest on Working Capital
Capital Recovery Charges
TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS (Direct Operating Costs + Indirect Operating
Costs + Capital Charges)
Estimated as 30% of the sum of Direct Labor and Supervision.
Estimated as 26% of the total of Direct Labor, Supervision, Maintenance
Labor, and Maintenance Materials.
Estimated as 4% of the Total Capital Cost.
Estimated as i% of the Working Capital where i is the interest rate.
Estimated as Capital Recovery Factor (CRF) x Total Capital Cost with the
CRF calculated as follows:
CRF = i(l + i)n
where: i is the interest rate and n is the life of the equipment.
2-25
-------
TABLE 2.2-2. UTILITY AND UNIT OPERATING COSTS, MID-1978 $ BASIS'
(1)
(2)
(3)
(4)
UTILITY COSTS
- Electricity
- Water
LABOR COSTS
- Operating labor
- Maintenance labor
- Supervision labor
FUEL COSTS
- High Sulfur Eastern Coal
- Nonfossil Fuels
SOLID AND SLUDGE DISPOSAL COSTS (Landfill)0
- Wood-fired Boilers (all sizes)
- MSW-fired Boilers ,-
(44 MW or 150 x 10° Btu/hr)
- MSW-fired Boilers K
(117 MW or 400 x 10° Btu/hr)
- Bagasse-fired Boilers
(200 x 10° Btu/hr)
(5) CREDITS FOR NOT LANDFILLING MSWC
- 44
or 150 x 10° Btu/hr
- 117 MW or 400 x 10° Btu/hr
$0.0258/kwh
SO.15/103 gal
$12.02/man-hour
Sl4.63/man-hour
$15.63/man-hour
$1.81/10° Btu
no cost
$20/ton
$12.50/ton
$9/ton
$10/ton
$9/ton
$9/ton
Except as noted, costs are based on PEDCo's Population and Characteristics
of Industrial/Commercial Boilers in the U.S.
For many companies nonfossil fuels may have a value greater than zero.
However, for this analysis the conservative approach is to assign no cost
to the fuel. This approach reduces the uncontrolled boiler cost thereby
increasing the impact of emission control costs.
'Unit landfill costs and credits are based on the unit costs and credits in
EEA's Estimated Landfill Credit for Nonfossil Fuel Fired Boilers. The
costs for each boiler are based on the smallest-size landfill capable of
absorbing ash and sludge from each model boiler. On-site landfills are
assumed for all boilers except MSW-fired boilers. MSW-fired boilers
feature off-site disposal 25 miles from the boiler site.
This is the 1990 price in mid 1978 dollars.
•2-26
-------
TABLE 2.2-3. LABOR COSTS FOR UNCONTROLLED MODEL BOILERS20
Boiler Capacity, MW i
8.8(30) 220(75)
Operating Labor3
Supervision3
Maintenance Labor3
1.5
0.5
0.5
2.25
1.0
0.75
44.0(150)
3.25
1.0
1.0
(106 Btu/hr)
58.6(200)
4.25
1.0
1.5
117(400)
6.75
1.5
3.0
Values shown are workers per shift. Labor costs in S/yr are the product
of the number of workers, 8760 hours per year, and the unit labor cost.
2-27
-------
TABLE 2.2-4. MAINTENANCE MATERIALS COSTS
FOR UNCONTROLLED MODEL BOILERS9'°
Cost of Maintenance Materials
Fuel
Wood boiler _<250 x 10 Btu/hr cost = 50,000 + lOOOx
boiler >250 x 106 Btu/hr cost = 180,429 + 405.4x
Bagasse cost = 450x
cost = 430x
x = boiler heat input, 10 Btu/hr.
Values are based on data from Reference 20 and boiler owner data.
2-28
-------
TABLE 2.2-5. OPERATION AND MAINTENANCE COSTS FOR PM CONTROL SYSTEMS3'b'C
Item
MCd'e
Direct Labor
Mid 1978 $/yr
5,075 + 530
Maintenance Labor
Mid 1978 S/yr
7,420 + 0.053Q2
Maintenance Materials
Mid 1978 $/yr
0.005 (TDI + Til)
MC, WS; WSd 10,150 + 106Q 14,840 + 0.106Q2 0.04 (TDI)
ESP 10,150 + 106Q 14,840 + 0.106Q2 0.005 (TDI + Til)
aQ = boiler heat input capacity in 10 Btu/hr.
MC = mechanical collector.
WS = wet scrubber.
ESP = electrostatic precipitator.
MC, WS = a mechanical collector followed by a wet scrubber in series.
The labor and maintenance materials costs for mechanical collectors are
based on owner data and engineering judgement. Costs for other control
devices are taken from "Capital and Operating Costs of Particulate Controls
on Coal- and Oil-Fired Industrial Boilers."
The cost of supervisory labor in $/yr is estimated as 15 percent of direct
labor costs in $/yr.
The labor costs calculated using the above equations are multiplied by a
factor of 0.5, and the maintenance materials cost by a factor of 0.85 when
applied to bagasse-fired boilers. This is because bagasse-fired boilers
operate only part of the year.
i
The labor costs for a MC are multiplied by a factor of 1.5 when applied to
DM control.
e
2-29
-------
Costs of electricity, chemicals, and water for MSW-fired boilers are
based on data from boiler owners. The owner data was used to develop the
following factors:
(1) water demand = 1.79 gpm per 106 Btu/per hour of heat input
(2) electricity demand = 3.06 kW per 106 Btu per hour
(3) chemical cost = $280 per million Btu per hour
The annual cost is calculated as the product of the above factor, annual
heat input, and unit costs.
The electricity cost for PM control systems is calculated as the
product of the total system energy demand, the boiler capacity factor, and
the unit cost of electricity.
2.2.2.3 Fuel costs. Nonfossil fuels are assumed to have no cost.
MSW-fired boiler costs include the cost of fossil fuel used for startup.
The amount of fuel use is based on data from boiler owners and is
0.5 percent of the total annual boiler heat input. The fuel type is natural
gas. The annual cost is calculated as the product of the annual fossil fuel
heat input and the price of natural gas ($2/106 Btu).
2.2.2.4 Solid waste disposal costs. The amount of solid waste
produced per year is calculated based on the amount of solid waste produced
at the rated boiler capacity and the boiler capacity factor. The amount of
boiler bottom ash produced and boiler load factors are shown in Table 2.1-2.
Table 2.2-6 shows the amounts of dry solid waste and sludge produced by
emission controls. The cost of solid waste disposal is the product of the
amount of solid waste produced per year and the disposal cost in $/ton shown
in Table 2.2-2.
In addition, boilers firing MSW receive a cost credit based on the
money saved by not having to landfill the MSW. The amount of this credit in
dollars per ton of MSW fired is shown in Table 2.2-2.
2.2.2.5 Other annualized costs. The remaining components of
annualized costs are calculated as percentages of labor, maintenance, and
capital costs. The factors used to calculate these costs are discussed in
Section 2.2.1 and shown in Table 2.2-1.
2-30
-------
TABLE 2.2-6. AMOUNTS OF SOLID WASTE PRODUCED BY
PARTICULATE EMISSION CONTROLS
Model Boiler Solids From Dry Particulate Sludge From Wet ,
Number Controls (Tons/yr) ' Scrubbers (Tons/yr)
WOOD-30-MC (0.60) 199
WOOD-30-DM (0.40) 215
WOOD-30-MC/WS (0.30) 169 178
WOOD-30-MC/WS (0.15) 169 215
WOOD-30-MC/WS (0.05) 169 242
WOOD-75-MC (0.60) 497
WOOD-75-DM (0.40) 536
WOOD-75-MC/WS (0.30) 423 444
WOOD-75-MC/WS (0.15) 423 539
WOOD-75-MC/WS (0.05) 423 604
WOOD-150-MC (0.60) 993
WOOD-150-DM (0.40) 1072
WOOD-150-MC/WS (0.30) 846 888
WOOD-150-MC/WS (0.15) 846 1080
WOOD-150-MC/WS (0.05) 846 1210
WOOD-400-MC (0.60) 2652
WOOD-400-DM (0.40) 2862
WOOD-400-MC/WS (0.30) 2260 2369
WOOD-400-MC/WS (0.15) 2260 2870
WOOD-400-MC/WS (0.05) 2260 3220
MSW-150-ESP (0.17) 1260
MSW-150-ESP (0.10) 1280
MSW-150-ESP (0.05) 1310
MSW-400-ESP (0.17) 3350
MSW-400-ESP (0.10) 3430
MSW-400-ESP (0.05) 3490
BAG-200-MC (0.62) 1750
BAG-200-WS (0.30) - 3745^
BAG-200-WS (0.20) - 3824d
Weight on a dry basis.
Weight based on a 30 percent solids sludge.
For wood-fired boilers a portion of the fly ash collected by the mechanical
collector is burned by reinjection. This reduces the amount of solid waste
generated.
Weight based on a 50 percent solids sludge.
2-31
-------
2.3 REFERENCES
1. Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-600/7-79-178i.
November 1979. p. 5-5 to 5-10, Appendices A and B.
2. Devitt, T., P. Spaite, and L. Gibbs. (PEDCo Environmental, Inc.)
"Population and Characteristics of Industrial/Commercial Boilers in the
U.S." Prepared for U.S. Environmental Protection Agency, Research
Triangle Park, N.C. EPA-600/7-79-789a. August 1979. p. 116.
3. Hall, E.H., et al. (Battelle-Columbus Laboratories.) Comparison of
Fossil and Wood Fuels. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. Publication No. EPA-600/2-
76-056. March 1976. p. 39.
4. Schwleger, B. Power from Wood. Power. 12^:5.4-5.5. February 1980.
5. Bozeka, C.G. Nashville Incinerator Performance Tests. In: 1976
National Waste Processing Conference Proceedings. New York, The
American Society of Mechanical Engineers. 1976. p. 223.
6. Wilson, E.M., et al. (The Ralph M. Parsons Company.) Engineering and
Economic Analysis of Waste to Energy Systems. (Prepared for
U.S. Environmental Protection Agency.) Cincinnati, Ohio. Publication
No. EPA-600/7-78-086. May 1978. p. A-14.
7. Reference 6, p. A-21.
8. Bagasse and Its Uses. In: Cane Sugar Handbook, Meade-Chen (ed.).
New York, John Wiley and Sons. p. 68.
9. McKay, C.M. (ed.). The Gilmore Sugar Manual. Fargo, North Dakota,
Sugar Publications, 1978. 169 p.
10. Reference 4.
11. Reference 5, p. 224.
12. Frounfelker, R. Small Modular Incinerator Systems with Heat Recovery:
A Technical, Environmental and Economic Evaluation, Executive Summary.
(Prepared for U.S. Environmental Protection Agencv.) Cincinnati, Ohio.
Publication No. SW-797. 1979. p. 3.
2-32
-------
13. Baker, R. (Environmental Science and Engineering, Inc.) Background
Document: Bagasse Combustion in Sugar Mills. (Prepared for
U.S. Environmental Protection Agency.) Research Triangle Park, N.C.
Publication No. EPA-450/3-77-007. January 1977. p. 3.
14. Memo from Barnett, K. and P. Murin, Radian Corporation, to file.
June 2, 1981. 31 p. Compilation of sales data for water tube boilers
for 1970 through 1978 from ABMA and other sources.
15. Scaramelli, A.B., et al. (MITRE Corporation.) Resource Recovery
Research, Development and Demonstration Plan. (Prepared for
U.S. Department of Energy.) Washington, D.C. DOE Contract No,
EM-78-C- 01-4241. October 1979. p. 137.
16. Reference 5, p. 221.
17. Devitt, T., et al. (PEDCo Environmental, Inc.) Population and Charac-
teristics of Industrial/Commercial Boilers in the U.S. (Prepared for
U.S. Environmental Protection Agency.) Research Triangle Park, N.C
Publication No. EPA-600/7-79-178a. August 1979. p. 110.
18. Franklin, W.E., et al. Solid Waste Management and the Paper Industry.
(Prepared for the Solid Waste Council of the Paper Industry.)
Washington, D.C., American Paper Institute, 1979. pp. 73-75.
19. U.S. Environmental Protection Agency. Nonfossil Fuel Fired Industrial
Boilers - Background Information. Research Triangle Park, N C
Publication No. 450/3-82-007. March 1982. pp. 3-17 to 3-41.
20. PEDCo Environmental, Inc. Cost Equations for Industrial Boilers.
Prepared for U.S. Environmental Protection Agency under Contract
No. 68-02-3074. January 1980. 23 p.
21. Abelcon, H. and J.J. Gordon. (The MITRE Corporation.) Distributed
Solar Energy Systems, Volume II: Wood Combustion Systems for Process
Steam and On-site Electricity. Prepared for the U.S. Department of
Energy. MITRE Publication No. MTR-79W00021-04. May 1980.
22. 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. 8-18 and
8-19.
23. Telecon. Murin, P., Radian Corporation with Dick Webber, Joy/Western
Precipitation Division. September 11, 1980. Multiple cyclone costs.
24. PEDCo Environmental, Inc. Capital and Operating Costs of Participate
Controls on Coal- and Oil-Fired Industrial Boilers. Prepared for
U.S. Environmental Protection Agency under contract No. 68-02-3074
August 1980. 129 p.
2-33
-------
25. Letter, Pilcher, L., GCA to Jack Podhorski, Joy/Western Precipitation
Div. July 26, 1979. Impingement scrubber costs.
26. Neveril, R.B. (CARD, Inc.) Capital and Operating Costs of Selected
Air Pollution Control Systems. Prepared for U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Publication
No. EPA-450/5-80-002. December 1978.
27. Guthrie, K.M. Process Plant Estimating Evaluation and Control. Solana
Beach, California, Craftsman Book Company of America, 1974. pp. 157,
163, 169, 170, 176, 355-360.
28. Peters, M.S. and K.D. Timmerhaus. Plant Design and Economics for
Chemical Engineers, Second Edition. New York, McGraw-Hill Book
Company, 1958. p. 477, 470, 133-134, 508.
29. Guthrie, K.M. (W.R. Grace & Company.) Data and Techniques for
Preliminary Capital Cost Estimating. Chemical Enqineering. Reprint
from March 24, 1969 issue. 29 p.
30. Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-600/7-79-178i.
November, 1979. pp. 2-147, 5-5 to 5-10, Appendices A and B.
31. Memo from Barnett, K. and Burt, R., Radian Corporation, to file.
March 31, 1982. 5 p. Handling of discharge from wet scrubbers on
bagasse-fired boilers.
32. Richardson Engineering Services, Inc. Process Plant Construction
Estimating Standards, Volume 4. San Marcos, California, Richardson
Engineering Services, Inc., 1980. File 100-65. p. 1-11.
33. Energy and Environmental Analysis, Inc. Estimated Landfill Credit for
Nonfossil-Fueled Boilers. Prepared for U.S. Environmental Protection
Agency. October 3, 1980. 38 p.
2-34
-------
3.0 COSTS OF PM CONTROL SYSTEMS AND UNCONTROLLED BOILERS
This chapter presents the results of the model boiler cost analysis
for uncontrolled NFFBs and the associated PM control systems. This analysis
focuses on the capital cost, annual operation and maintenance (O&M) costs,
and total annualized cost of control for boilers firing either wood,
municipal solid waste (MSW), or bagasse. The PM control technologies
examined for each fuel type are presented in Section 1.2.2. Detailed design
specifications for boilers and control systems were presented in
Sections 2.1.2 and 2.1.3 respectively.
In addition to the model boiler cost cases shown in Sections 1 and 2,
costs are also shown for certain additional cases. These cases include
wood-fired boilers with mechanical collectors followed by wet scrubbers
(MC/WS) controlled to emission levels of 0.2 and 0.1 lb/106 Btu. The
costs for these cases were not developed using the costing methods shown in
Section 2, but were interpolated from the costs for the other wood-fired
boiler MC/WS model boiler cases. The two additional wood-fired boiler cases
were included because the emission levels of 0.2 and 0.1 were considered as
regulatory options.
All costs in this chapter are presented as mid-1978 dollars. Bagasse-
fired boilers are assumed to have a capacity utilization factor of 0.45.
All other boilers have capacity utilization factors of 0.6. All boilers and
control equipment are assumed to have a capital recovery factor of 0.1315
which is based on an economic equipment life of 15 years and a 10 percent
rate of return on capital. All costs shown for wet scrubbers applied to
wood-fired boilers include the cost of the mechanical collector precleaner.
3.1 CAPITAL COSTS OF BOILERS AND CONTROLS
Table 3-1 presents the capital costs for uncontrolled NFFBs and PM
control systems applied to NFFBs. Table 3-1 shows that costs on a unit
capacity basis decrease with system size due to boiler and emission controls
3-1
-------
TABLE 3-1. CAPITAL COSTS FOR MODEL BOILERS
CO
I
ro
Capital Costs
Model
Boiler
WOOD-30-MC (0.60)
WOOD-30-DM (0.40)
WOOD-30-MC/WS (0.30).
WOOD-30-MC/WS (0.20)D
WOOD-30-MC/WS (0.15).
WOOD-30-MC/WS (0.10)D
WOOD-30-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-DM (0.40)
WOOD-75-MC/WS (0.30).
WOOD-75-MC/WS (0.20)D
WOOD-75-MC/WS (0.15).
WOOD-75-MC/WS (0.10)D
WOOD-75-MC/WS (0.05)
WOOD-150-MC (0.60)
WOOD-150-DM (0.40)
WOOD-150-MC/WS (0.30).
WOOD-150-MC/WS (0.20)D
WOOD-150-MC/WS (0.15).
WOOD-150-MC/WS (O.lOr
WOOD-150-MC/WS (0.05)
WOOD-400-MC (0.60)
WOOD-400-DM (0.40)
WOOD-400-MC/WS (0.30).
WOOD-400-MC/WS (0.20)D
WOOD-400-MC/WS (0.15).
WOOD-400-MC/WS (0.10)D
WOOD-400-MC/WS (0.05)
Uncontrolled
Boiler
1800
1800
1800
1800
1800
1800
1800
3660
3660
3660
3660
3660
3660
3660
6130
6130
6130
6130
6130
6130
6130
13500
13500
13500
13500
13500
13500
13500
PM Emission
Controls
96
141
314
356
366
376
389
155
243
489
543
563
584
617
309
442
748
836
880
936
1039
668
998
1419
1623
1700
1784
1927
($1000)
Normalized
Total Total
1896
1941
2114
2156
2166
2176
2189
3815
3903
4149
4203
4223
4244
4277
6439
6572
6878
6966
7010
7066
7169
14168
14498
14919
15123
15200
15284
15427
63.2
64.7
70.5
71.9
72.2
72.5
73.0
50.9
52.0
55.3
56.0
56.3
56.6
57.0
42.9
43.8
45.9
46.4
46.7
47.1
47.8
35.4
36.2
37.3
37.8
38.0
38.2
38.6
% Increase Over
Uncontrolled
5.3
7.8
17.4
19.8
20.3
20.9
21.6
4.2
6.6
13.4
14.8
15.4
16.0
16.9
5.0
7.2
12.2
13.6
14.4
15.3
16.9
4.9
7.4
10.5
12.0
12.6
13.2
14.3
-------
TABLE 3-1. CAPITAL COSTS FOR MODEL BOILERS (CONTINUED)
CO
I
CO
Capital Costs
Model
Boiler
MSW-150-ESP (0.17)
MSW-150-ESP (0.10)
MSW-150-ESP (0.05)
MSW-400-ESP (0.17)
MSW-400-ESP (0.10)
MSW-400-ESP (0.05)
BAG-200-MC (0.62)
BAG-200-WS (0.30)
BAG-200-WS (0.20)
Uncontrolled
Boiler
16500
16500
16500
35300
35300
35300
5450
5450
5450
PM Emission
Controls
1050
1136
1367
1696
2181
2984
398
543
545
($1000)
Normalized3
Total Total
17550
17636
17867
36996
37481
38284
5848
5993
5995
117.0
117.6
119.1
92.5
93.7
95.7
29.2
30.0
30.0
% Increase Over
Uncontrolled
6.4
6.9
8.3
4.8
6.2
8.5
7.3
10.0
10.0
Normalized total is total capital cost divided by boiler capacity
($1000/10° Btu/hr).
Interpolated result from Figure 3-6.
-------
economies of scale. Table 3-1 also shows that emission controls required
for more stringent levels of control are more expensive than controls
required for less stringent levels of control.
The uncontrolled MSW-fired boilers have significantly higher capital
costs than the other boiler types shown. This is because MSW-fired boilers
have different designs from wood- and bagasse-fired boilers.
Wet scrubbers applied to uncontrolled wood-fired boilers show more
significant cost impacts over mechanical collectors than wet scrubbers
applied to bagasse-fired boilers. This is because the wood-fired boiler wet
scrubber costs include the cost of a thickener used only for scrubber waste
water treatment. The thickener produces a sludge that is mixed with the
boiler bottom ash and landfilled and the thickener overflow is recycled to
the wet scrubber. Therefore, there is no waste water discharge for this
system. This design was used for wood-fired boilers because they are
located in many different types of facilities which will not necessarily
have an alternative waste water treatment system available. For new
wood-fired boilers located at sites where other water treatment systems are
available the thickener would not be required and the wet scrubber capital
costs would be significantly reduced. Table 3-2 shows a comparison of wet
scrubber capital costs with and without a thickener.
For bagasse-fired boilers the situation is different. Bagasse-fired
boilers are always located in sugar mills. Sugar mills provide several
waste water treatment alternatives for scrubber water discharges. These
are:
- treatment with the water used to wash the sugar cane
- using the water for irrigation
- disposing of the water in unused fields next to the plant
Because one or more of these alternatives will be available at a sugar mill
the cost of a separate water treatment facility was not included in the
costs of a wet scrubber for bagasse-fired boilers. The cost of piping
scrubber waste water to treatment disposal, and the cost of landfilling the
sludge which would result are included in the costs.
-------
CO
I
CT
TABLE 3-2. COMPARISON OF WET SCRUBBER CAPITAL COSTS WITH AND
WITHOUT THICKENERS FOR A 150 x 10° Btu/hr WOOD-FIRED BOILER9
Model Boiler
WOOD-150-MC/WS (0.30)
WOOD-150-MC/WS (0.15)
WOOD-150/MC/WS (0.05)
With Thickener
748
880
1039
Capital Cost ($1000)
Without Thickener
526
642
791
Percent Decrease
29.7
27.0
23.9
Wet scrubber costs include the cost of the mechanical collector precleaner.
-------
Figures 3-1 through 3-5 show uncontrolled boiler and PM emission
control costs as a function of boiler size. These figures can be used to
estimate boiler and control systems costs at boiler sizes not shown in
Table 3-1. The relationship between the PM emission level and wet scrubber
pressure drop or ESP specific collection area is shown in Table 3-3. In
addition, Figure 3-6 shows wet scrubber pressure drop versus wet scrubber
control system capital cost. This figure can be used to estimate wet
scrubber capital costs at different scrubber pressure drops.
3.2 O&M AND TOTAL AMNUALIZED COSTS OF BOILERS AND PM CONTROLS
Annual O&M costs for NFFBs are presented in Table 3-4. For each
uncontrolled wood-fired model boiler two annual O&M costs are shown. The
first O&M cost is based on the assumption that the wood fuel has no cost.
The second value shows the annual O&M cost if the wood fuel is assumed to
have a cost equal to HSC on a S/Btu basis. The actual cost of wood fuels is
expected to fall somewhere between no cost and a cost equal to HSC for a
majority of new wood-fired boilers. The normalized annual costs provide a
size independent measure of the annual O&M costs of the boiler and pollution
control system. Normalized annual costs ($l,000/yr) are computed by
dividing the annual cost by the annual heat input (106 Btu/yr).
Total annualized costs, which include annual capital charges, are
presented in a similar manner in Table 3-5. The normalized annualized costs
decrease with boiler size indicating economies of scale with larger boilers.
Two different annualized costs are shown for each uncontrolled wood-fired
boiler. One for the case where the wood fuel is assumed to have no cost,
and one for the case where the cost of the wood fuel is assumed to be equal
to the cost of HSC.
MSW-fired boilers have lower annualized costs than wood-fired boilers
even though the capital costs for MSW-fired boilers were much higher than
those for wood. The low annualized costs for MSW-fired boilers result from
a cost credit that is included in the annualized cost of these boilers.
This cost credit accounts for money saved by burning MSW rather than
landfilling it.
-------
Boiler Capital Costs (106 $)
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O
C_3
40
36
32
28
24
20
16
12 -
8 -
4 .
100 200
Boiler Size (106 Btu/hr)
300
400
Figure 3-2. MSW-fired boiler capital costs as a function of boiler size.
3-G
-------
OJ
I
-------
0.8
0.7 -
0.6
0.5 _
O
i— i
~ 0.4
V)
O
Q.
13
O
0.3
0.2
0.1
WS with 6 or 10 in. w.c.a
pressure drop
50 100 150 200
Boiler Size (106 Btu/hr)
250 300
Capital costs for 6 and 10 in. w.c. pressure drop wet scrubbers are
approximately equivalent.
Figure 3-4.
PM control capital costs for bagasse-fired boilers as a function
of boiler size.
3-10
-------
3.0
2.8
2.6
2.4
S 2.2
O
)—4
— 2.0
i/i
•M
-------
TABLE 3-3. RELATIONSHIP BETWEEN PM EMISSION LEVELS AND WET SCRUBBER
PRESSURE DROP OR ELECTROSTATIC PRECIPITATOR SCA FOR NONFOSSIL FUELS
CO
I
Fuel
WOOD
WOOD
WOOD
WOOD
WOOD
MSW
MSW
MSW
BAG
BAG
Control
Device
MC/WS
MC/WS
MC/WS
MC/WS
MC/WS
ESP
ESP
ESP
WS
WS
PM Emission
Level (lb/10b Btu)
0.30
0.20
0.15
0.10
0.05
0.17
0.10
0.05
0.30
0.20
Wet Scrubber Pressure
Drop (in. w.c.)
4
7
9
12
20
-
-
6
10
,. SCA
(fr/1000 acfm)
-
160
240
410
—
MC - mechanical collector; WS - wet scrubber; ESP - electrostatic precipitator.
-------
20
10
OJ
H-*
CO
o
Q_
O
01
.a
-Q
3
s_
o
CD
30 X 10° Btu/hr
75 X 10° Btu/hr
150 X 10 Btu/hr 400 X 10° Btu/hr
4 1 I I
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6
Capital Costs (106 $)
_J I
1.8 2.0
Figure 3-6. Wet scrubber capital costs versus pressure drop for four boiler sizes,
-------
TABLE 3-4. ANNUAL O&M COSTS FOR MODEL BOILERS
Annual Costs ($1000/yr)
Model
Boiler
WOOD-30-MC (0.60)
WOOD-30-DM (0.40)
WOOD-30-MC/WS (0.30) .
wooD-30-Mc/ws (o.zor
WOOD-30-MC/WS (0.15) ,
WOOD-30-MC/WS (0.10)
WOOD-30-MC/WS (0.05)
WOOD-30-MC (0.60)
WOOD-30-DM (0.40)
WOOD-30-MC/WS (0.30) .
WOOD-30-MC/WS (0.20)a
WOOD-30-MC/WS (0.15) .
WOOD-30-MC/WS (0.10)°
WOOD-30-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-DM (0.40)
WOOD-75-MC/WS (0.30) .
WOOD-75-MC/WS (0.20)a
WOOD-75-MC/WS (0.15) .
WOOD-75-MC/WS (0.10)a
WOOD-75-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-DM (0.40)
WOOD-75-MC/WS (0.30) .
WOOD-75-MC/WS (0.20)a
WOOD-75-MC/WS (0.15)
WOOD-75-MC/WS (0.10)
WOOD-75-MC/WS (0.05)
Uncontrolled
Boiler
568b
568
568
568
568
568
568
853C
853
853
853
853
853
853
918b
918
918
918
918
918
918
1632C
1632
1632
1632
1632
1632
1632
PM Emission
Controls
28.5
40.9
63.9
67.0
70.2
72.0
76.4
28.5
40.9
63.9
67.0
70.2
72.0
76.4
42.4
60.0
95.5
104
110
116
125
42.4
60.0
95.5
104
110
116
125
Normalized
Total Total
596
609
632
635
638
640
644
881
894
917
920
923
925
929
960
978
1014
1022
1028
1034
1043
1674
1692
1728
1736
1742
1748
1757
3.8
3.9
4.0
4.0
4.0
4.1
4.1
5.6
5.7
5.8
5.8
5.9
5.9
5.9
2.4
2.5
2.6
2.6
2.6
2.6
2.6
4.2
4.3
4.4
4.4
4.4
4.4
4.5
% Increase Over
Uncontrolled
5.0
7.2
11.2
11.8
12.4
12.7
13.5
3.3
4.8
7.5
7.9
8.2
8.4
8.9
4.6
6.5
10.4
11.3
12.0
12.6
13.6
2.6
3.7
5.9
6.4
6.7
7.1
7.7
-------
TABLE 3-4. ANNUAL O&M COSTS FOR MODEL BOILERS (CONTINUED)
CO
I
Annual Costs ($1000/yr)
Model
Boiler
WOOD-150-MC (0.60)
WOOD-150-DM (0.40)
WOOD-150-MC/WS (0.30) .
WOOD-150-MC/WS (0.20)d
WOOD-150-MC/WS (0.15).
WOOD-150-MC/WS (0.10)°
WOOD-150-MC/WS (0.05)
WOOD-150-MC (0.60)
WOOD-150-DM (0.40)
WOOD-150-MC/WS (0.30) .
WOOD-150-MC/WS (0.20)d
WOOD-150-MC/WS (0.15) .
WOOD-150-MC/WS (0.10)d
WOOD-150-MC/WS (0.05)
WOOD-400-MC (0.60)
WOOD-400-DM (0.40)
WOOD-400-MC/WS (0.30) .
WOOD-400-MC/WS (0.20)d
WOOD-400-MC/WS (0.15) .
WOOD-400-MC/WS (0.10)d
WOOD-400-MC/WS (0.05)
WOOD-400-MC (0.60)
WOOD-400-DM (0.40)
WOOD-400-MC/WS (0.30) .
WOOD-400-MC/WS (0.20)d
WOOD-400-MC/WS (0.15).
WOOD-400-MC/WS (0.10)
WOOD-400-MC/WS (0.05)
Uncontrol led
Boiler
1255b
1255
1255
1255
1255
1255
1255
2682C
2682
2682
2682
2682
2682
2682
2545b
2545
2545
2545
2545
2545
2545
6350C
6350
6350
6350
6350
6350
6350
PM Emission
Controls
68.2
92.8
148
165
176
189
209
68.2
92.8
148
165
176
189
209
156
211
329
371
401
432
482
156
211
329
371
401
432
482
Normalized9
Total Total
1323
1348
1403
1420
1431
1444
1464
2750
2775
2830
2847
2858
2871
2891
2701
2756
2874
2916
2946
2977
3027
6506
6561
6679
6721
6751
6782
6832
1.7
1.7
1.8
1.8
1.8
1.8
1.9
3.5
3.5
3.6
3.6
3.6
3.6
3.7
1.3
1.3
1.4
1.4
1.4
1.4
1.4
3.1
3.1
3.2
3.2
3.2
3.2
3.2
% Increase Over
Uncontrolled
5.4
7.4
11.8
13.1
14.0
15.1
16.7
2.5
7.4
5.5
6.2
6.6
7.0
7.8
6.1
8.3
12.9
14.6
15.8
17.0
18.9
2.5
3.3
5.2
5.8
6.3
6.8
7.6
-------
TABLE 3-4. ANNUAL O&M COSTS FOR MODEL BOILERS (CONTINUED)
Annual Costs ($1000/yr)
Model
Boiler
MSW-150-ESP (0.17)
MSW-150-ESP (0.10)
MSW-150-ESP (0.05)
MSW-400-ESP (0.17)
MSW-400-ESP (0.10)
MSW-400-ESP (0.05)
BAG-200-MC (0.62)
BAG-200-WS (0.30)
BAG-200-WS (0.20)
Uncontrolled
Boiler
1148
1148
1148
2941
2941
2941
787
787
787
PM Emission
Controls
104
108
116
211
222
244
53.2
111
121
Normalized9
Total
1252
1256
1264
3152
3163
3185
840
898
908
Total
1.6
1.6
1.6
1.5
1.5
1.5
1.1
1.1
1.2
% Increase Over
Uncontrolled
9.1
9.4
10.1
7.2
7.5
8.3
6.8
14.1
15.4
formalized total is total annual cost divided by the annual boiler heat input ($/10 Btu).
K
Annualized model boiler costs if the wood fuel is assumed to have no cost.
Annualized model boiler costs if the wood fuel is assumed to cost the same as high sulfur eastern
coal on a $/Btu basis.
Interpolated from annual O&M costs presented for WOOD-MC/WS (0.30), WOOD-MC/WS (0.15), and
WOOD-MC/WS (0.05).
-------
TABLE 3-5. TOTAL ANNUALIZED COSTS FOR MODEL BOILERS
CO
I
Annual ized Costs ($1000/yr)
Model
Boiler
WOOD-30-MC (0.60)
WOOD-30-DM (0.40)
WOOD-30-MC/WS (0.30) .
WOOD-30-MC/WS (0.20)fl
WOOD-30-MC/WS (0.15) .
WOOD-30-MC/WS (0.10)d
WOOD-30-MC/WS (0.05)
WOOD-30-MC (0.60)
WOOD-30-DM (0.40)
WOOD-30-MC/WS (0.30) ,
WOOD-30-MC/WS (0.20)
WOOD-30-MC/WS (0.15) .
WOOD-30-MC/WS (0.10)d
WOOD-30-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-DM (0.40)
WOOD-75-MC/WS (0.30) ,
WOOD-75-MC/WS (0.20)d
WOOD-75-MC/WS (0.15) .
WOOD-75-MC/WS (0.10)a
WOOD-75-MC/WS (0.05)
WOOD-75-MC (0.60)
WOOD-75-DM (0.40)
WOOD-75-MC/WS (0.30) .
WOOD-75-MC/WS (0.20)d
WOOD-75-MC/WS (0.15),
WOOD-75-MC/WS (0.10)a
WOOD-75-MC/WS (0.05)
Uncontrol led
Boiler
886 °
886
886
886
886
886
886
1171°
1171
1171
1171
1171
1171
1171
1562b
1562
1562
1562
1562
1562
1562
2276°
2276
2276
2276
2276
2276
2276
PM Emission
Controls
45.6
65.9
119
130
134
138
145
45.6
65.9
119
130
134
138
145
69.9
103
181
201
208
218
234
69.9
103
181
201
208
218
234
Normalized3
Total Total
932
952
1005
1016
1020
1024
1031
1217
1237
1290
1301
1305
1309
1316
1632
1665
1743
1763
1770
1780
1796
2346
2379
2457
2477
2484
2494
2510
5.9
6.0
6.4
6.4
6.5
6.5
6.5
7.7
7.8
8.2
8.3
8.3
8.3
8.3
4.1
4.2
4.4
4.5
4.5
4.5
4.6
6.0
6.0
6.2
6.3
6.3
6.3
6.4
% Increase Over
Uncontrolled
5.1
7.4
13.4
14.7
15.1
15.6
16.4
3.9
5.6
10.2
11.1
11.4
11.8
12.4
4.5
6.6
11.6
12.9
13.3
14.0
isio
3 1
*J • J-
4.5
8.0
8 8
\j • \J
9.1
9.6
10.3
-------
TABLE 3-5. TOTAL ANNUALIZED COSTS FOR MODEL BOILERS (CONTINUED)
CO
I
oo
Annual ized Costs ($1000/yr)
Model
Boiler
WOOD-150-MC (0.60)
WOOD-150-DM (0.40)
WOOD-150-MC/WS (0.30) .
WOOD-150-MC/WS (0.20)
WOOD-150-MC/WS (0.15) .
WOOD-150-MC/WS (0.10)
WOOD-150-MC/WS (0.05)
WOOD-150-MC (0.60)
WOOD-150-DM (0.40)
WOOD-150-MC/WS (0.30) .
WOOD-150-MC/WS (0.20)°
WOOD-150-MC/WS (0.15) .
WOOD-150-MC/WS (0.10)
WOOD-150-MC/WS (0.05)
WOOD-400-MC (0.60)
WOOD-400-DM (0.40)
WOOD-400-MC/WS (0.30) .
WOOD-400-MC/WS (0.20)a
WOOD-400-MC/WS (0.15) .
WOOD-400-MC/WS (0.10)a
WOOD-400-MC/WS (0.05)
WOOD-400-MC (0.60)
WOOD-400-DM (0.40)
WOOD-400-MC/WS (0.30) .
WOOD-400-MC/WS (0.20)
WOOD-400-MC/WS (0.15) .
WOOD-400-MC/WS (0.10)a
WOOD-400-MC/WS (0.05)
Uncontrolled
Boiler
h
2329
2329
2329
2329
2329
2329
2329
c
3756
3756
3756
3756
3756
3756
3756
4906b
4906
4906
4906
4906
4906
4906
8711°
8711
8711
8711
8711
8711
8711
PM Emission Normalized
Controls Total Total
123
171
280
313
331
352
391
123
171
280
313
331
352
391
274
387
579
664
701
745
823
274
387
579
664
701
745
823
2452
2500
2609
2642
2660
2681
2720
3879
3927
4036
4069
4087
4108
4147
5180
5293
5485
5570
5607
5651
5729
8985
9098
9290
9375
9412
9456
9534
3.1
3.2
3.3
3.4
3.4
3.4
3.4
4.9
5.0
5.1
5.2
5.2
5.2
5.3
2.5
2.5
2.6
2.6
2.7
2.7
2.7
4.3
4.3
4.4
4.5
4.5
4.5
4.5
% Increase Over
Uncontrolled
5.3
7.3
12.0
13.4
14.2
15.1
16.8
3.3
4.6
7.5
8.3
8.8
9.4
10.4
5.6
7.9
11.8
13.5
14.3
15.2
16.8
3.1
4.4
6.6
7.6
8.0
8.6
9.4
-------
TABLE 3-5. TOTAL ANNUALIZED COSTS FOR MODEL BOILERS (CONTINUED)
CO
I
Annual ized Costs ($1000/yr)
Model
Boiler
MSW-150-ESP (0.17)
MSW-140-ESP (0.10)
MSW-140-ESP (0.05)
MSW-400-ESP (0.17)
MSW-400-ESP (0.10)
MSW-400-ESP (0.05)
BAG-200-MC (0.62)
BAG-200-WS (0.30)
BAG-200-WS (0.20)
Uncontrol led
Boiler
2086
2086
2086
3953
3953
3953
1736
1736
1736
PM Emission
Controls
286
304
352
506
601
761
123
207
217
Normal ized
Total
2372
2390
2438
4459
4554
4714
1859
1943
1953
Total
3.0
3.0
3.1
2.1
2.2
2.2
2.4
2.5
2.5
% Increase Over
Uncontrolled
13.7
14.6
16.9
12.8
15.2
19.3
7.1
11.9
12.5
aNormalized total is total annualized cost divided by the annual boiler heat input ($/106 Btu).
Annualized model boiler costs if the wood fuel is assumed to have no cost.
£
Annualized model boiler costs if the wood fuel is assumed to cost the same as high sulfur eastern
coal on a $/Btu basis.
Interpolated result from Figure 3-11.
-------
Wood-fired model boilers show total annualized cost increases ranging
from 4,5 to 16.8 percent of the uncontrolled boiler costs if the wood fuel
is assumed to have no cost. However, if wood fuel is assumed to have a cost
equal to HSC ($/Btu basis), the total annualized model boiler cost increases
over the uncontrolled boilers are reduced to 3.1 to 12.4 percent. As shown,
assigning a value to nonfossil fuels significantly reduces the percentage
increase in costs due to emission controls.
As discussed in Section 3.1, wet scrubbers applied to wood-fired
boilers incur significant capital costs due to the requirement to treat the
scrubber waste water. The impact of waste water treatment (thickener) costs
on total annualized costs is shown in Table 3-6.
Figures 3-7 through 3-10 show uncontrolled boiler and PM control system
annualized costs as a function of boiler size. These figures may be used to
estimate annualized costs for boiler sizes not shown in Table 3-5.
Figure 3-11 shows wet scrubber annualized costs versus scrubber
pressure drop. This figure can be used to estimate wet scrubber annualized
costs at different scrubber pressure drops.
3-20
-------
TABLE 3-6. COMPARISON OF MODEL BOILER ANNUALIZED COSTS WITH AND WITHOUT
WET SCRUBBER THICKENERS FOR A 150 x 10 Btu/hr WOOD-FIRED BOILER
Model Boiler
WOOD-150-MC/WS (0.30)
WOOD-150-MC/WS (0.15)
WOOD-150-MC/WS (0.05)
With Thickener
2609
2660
2720
Annual ized Cost ($1000/yr)
Without Thickener
2563
2611
2670
Percent Decrease
1.8
1.8
1.8
Wet scrubber costs include the cost of the mechanical collector precleaner.
-------
6 r-
CJ
I
ix
ixi
10
CD
o
o
-a 3
-------
00
I
CO
to
o
1.0
0.9
0.8
0.7
0.6
o 0.5
-------
I
ro
UD
O
XJ
03
IM
0.32 r-
0.30
0.28
0.26
0.24
0.22
0.20
0.18
0.16
0.14
-------
O
O
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
100
200
Boiler Size (106 Btu/hr)
300
SCA = 410 fr/1000 acfm
SCA = 240 fr/1000 acfm
SCA = 160 fr/1000 acfm
400
Figure 3-10. Annualized costs of ESP's applied to MSW-fired boilers as a function of boiler si
ze.
-------
Pressure Drop in. w.c.
ro
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co
CT
CT
CD
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O>
-------
4.0 OTHER FUEL CASES
This chapter presents participate matter (PM) control system costs for
some individual fuel cases not covered in the general model boiler categories.
These costs are compared to the related model boiler costs shown in Chapter 3.
The cases cover salt-laden wood fuel, wood/fossil fuel mixtures, RDF, and
sol id waste/fossil fuel mixtures.
4.1 SALT-LADEN WOOD FIRED BOILERS
The cost impacts of PM controls for boilers firing salt-laden wood (SLW)
are examined for a 44 MW (150 x 10 Btu/hr) boiler size. The boiler design
specifications which would differ for a boiler firing SLW as compared to wood
are given in Table 4.1-1.
The PM control system for this model boiler consists of a fabric filter
(FF) with an upstream mechanical collector (MC) instead of the mechanical
collector/wet scrubber system used with wood firing. As shown in Table 4.1-1,
boilers firing SLW have higher uncontrolled emissions than boilers firing
other wood fuels (see Table 2.1-2). In addition, SLW produces a particulate
with a smaller particle size than wood firing. Fabric filters are more
effective than wet scrubbers on the higher loadings and smaller particle sizes
found in SLW emissions. Also, the particulate from SLW firing poses a smaller
fire threat than the particulate from wood firing due to the quenching effect
of the salt. The control system design specifications for the SLW-fired
boiler case are given in Table 4.1-2.
Uncontrolled PM emissions for the SLW model boiler are 2590 ng/J
(6.03 lb/10 Btu). The MC/FF control system shown can reduce emissions to
21.5 ng/J (0.05 lb/106 Btu). This control level is the only level shown
because it is easily achievable by the design of fabric filter systems
presently in operation on wood-fired boilers.
4.1.1 Capital Costs of a SLW-Fired Boiler PM Control System
The baghouse capital costs are estimated from a correlation based on data
2 3
from GARD and Wheelabrator-Frye. The baghouse cost correlation estimates
4-1
-------
TABLE 4.1-1. UNCONTROLLED SLW-FIRED BOILER DESIGN SPECIFICATIONS9
Thermal Input, MW (106 Btu/hr) 44.0 (150)
Fuela SLW
Fuel rate, kg/s (ton/hr) 4.18 (16.6)
Analysis
% sulfur 0.02
% ash 1.49b
Flue gas constituents,0 kg/hr (Ib/hr)
Fly ash (before mechanical collector) 411 (905)d
(after mechanical collector)6 142 (314)d
so2
NOX 17.0 (37.5)
Ash from sand classifier, kg/hr (Ib/hr) 147 (325)
SLW - salt-laden wood.
Salt makes up 0.5 percent of the fuel composition and is included here as
ash.
c
Uncontrolled emissions.
It is assumed that all salt present in the fuel leaves the boiler as fly
ash and that none of the salt is collected by the mechanical collector due
to its small particle size.
g
Fly ash reinjection in use.
The value shown represents the difference in the amount of fly ash
collected by the mechanical collector and the amount of fly ash reinjected
into the boiler furnace.
90ther design specifications not shown here are identical to those for a
44 MW (150 x 10 Btu/hr) wood-fired boiler.
4-2
-------
TABLE 4.1-2. EMISSION CONTROL SYSTEM DESIGN SPECIFICATIONS
FOR SLW-FIRED MODEL BOILER
Control System
Item
Specification
Multiple cyclone
Fabric Filter
Material of construction
Tube diameter
Pressure drop
Carbon steel
23 cm (9 in.)
750 Pa (3 in. w.c.)
Design PM removal efficiency 80% (for non salt
particulate only -
0% for salt particulate)
Material of construction
Cleaning method
Design air-to-cloth ratio
Pressure drop
Filter material
Filter life
Power demand
Carbon steel (insulated)
Pluse-jet
2 cm/s (4 ft/m)
1.5 kPa (6 in. w.c.)
Teflon-coated glass felt
2 years
2
4 W/m filter area
(0.5 hp/1000 ftr)
Fire extinguishing system Steam
Overall System
Pressure drop
Duct features
250-750 Pa (1-3 in. w.c.)
plus pressure drops from
individual control
equipment
Main duct length: 20-30 m
(60-100 ft). Expansion
joints for duct connecting
two pieces of equipment
Elbows bypass ducting
(including duct, tees,
elbows, dampers) for
fabric filters
4-3
-------
the baghouse equipment cost from the net filter area. Net filter area is
calculated as:
Net Filter Area (ft2) = Gas Flow (acfm) x 1.1
4fpm
where 1.1 is a design contingency factor and 4 fpm is the design air-to-cloth
ratio. The baghouse equipment cost, as a function of the net filter area, is:
Cost ($1000) = 0.0908 x (Net Filter Area, ft2)0'8138
Note that in this correlation, the equipment cost does not include taxes and
freight, since those items are included in the installation cost factor. The
installation cost factor for the baghouse equipment is 0.78.2'4
The cost of Teflon-coated glass felt bags is estimated as $1.42/ft2 in
mid-1978 dollars. This cost estimate is an average of costs reported by
Whellabrator-Frye ($1.53/ft2) and Huyglas ($1.89/ft2) indexed from mid-1980
to mid-1978. Bag costs are estimated by multiplying the unit bag cost by the
net filter area.
The installation cost factor for filter bags is based on an average
installation time of 15 min/bag for a four man crew.5 With 12 ft2 of cloth
per bag, the cost of bag installation is
1 man-hr $14.63 v 1.26 = $1.54/ft2
' "
-------
4.1.3 Comparison of PM Control System Costs for Wood Versus SLW
Table 4.1-3 compares the capital and annualized PM control system costs
for wood versus SLW. These costs are based on the requirement that outlet
emission levels not exceed 43 ng/J (0.1 lb/106 Btu). However, the costs
of control for the SLW-fired boiler are based on an actual emission level of
0.05 lb/10 Btu. This is because at the design A/C ratios commonly used
on FF applied to SLW-fired boilers the actual measured emission levels are
generally 0.05 lb/105 Btu or less even though the required control level
may be higher.
Table 4.1-3 shows that SLW-fired boilers will typically be about
12 percent more costly to control than wood-fired boilers on an annual
basis. However, uncontrolled SLW-fired boilers emit more particulate than
wood-fired boilers. Therefore, the higher costs of control are reflected in
a higher amount of particulate removed.
4.2 WCOD/FOSSIL FUEL MIXTURES
In most cases, wood-fired boilers are also designed to fire fossil
fuels. Fossil fuels are used when wood fuel is unavailable, the wood feed
system is inoperative, or additional heat input is required to meet peak
steam demands. The types of fossil fuels used are oil, natural gas, and
coal. In the case of natural gas and oil, uncontrolled emissions on a heat
input basis are significantly reduced when these fuels are combusted with
wood. Therefore, when gas and oil are fired with wood fuel, PM emissions
should be no more difficult to control than emissions from wood alone.
However, when coal is fired with wood, significant amounts of particulate
matter can be emitted from coal combustion. Therefore, the remainder of
this section will focus on the control of PM emissions from wood/coal
mixtures.
The control system which will be discussed in this section consists of
a mechanical collector followed by an electrostatic precipitator. This is
the type of control system commonly used on new wood/coal-fired boilers.
For boilers firing fuel mixtures the ESP must potentially be designed to
control PM emissions from either fuel fired alone, or both fuels when fired
4-5
-------
TABLE 4.1-3. COMPARISON OF THE PM CONTROL SYSTEM COSTS FOR
SLW VERSUS WOOD FOR A 44 MW (150 x 10b Btu) BOILER SIZE
Fuel
SLW
Wood
Control System
MC/FF
MC/WS
Emission Level
lb/10D Btu
0.05
0.10
Control System
Capital
1368
936
Cost - 10" $
Annual ized
398
352
4-6
-------
in combination. However, according to equipment vendors, electrostatic
precipitators used in multiple fuel applications are sized based on the
collection area required to reduce emissions to the desired level for the
most difficult control case for either fuel fired alone. Mixed fuel
emissions will be no more difficult to precipitate than the emissions from
either fuel fired alone. ' Therefore, the size of the ESP required to
meet a specific emission level for wood/coal-fired boilers is based on the
size required for either 100 percent wood or 100 percent coal firing
(whichever is larger). Table 4.2-1 shows the SCA's for ESP applied to wood
and coal-fired boilers based on an emission level of 43 ng/J (0.1 lb/106 Btu)
at the ESP outlet. As shown in this table, wood firing requires an SCA of
250 ft /1000 acfm whereas coal firing requires a smaller SCA for either
high or low sulfur coal. Therefore, an ESP designed to meet 43 ng/J
(0.1 lb/10 Btu) when firing wood will be able to achieve this emission
level, or less, when firing either high or low sulfur coals, or wood/coal
mixtures.
Table 4.2-2 shows comparison of the capital and annualized costs for a
MC/ESP control system capable of achieving an emission level of 43 ng/J
(0.1 lb/10 Btu) and the capital and annualized costs of a MC/WS system
designed to achieve the same emission level. The bases used to calculate
costs of the MC/ESP system are the same as discussed in Chapter 2 for ESPs
applied to MSW-fired boilers, except the capital costs are based on an SCA
2
of 250 ft /1000 acfm, and the costs of the same type of mechanical collector
and sand classifier systems used in the MC/WS control system are included.
As shown in Table 4.2-2, the annualized cost of PM emission control for
boilers firing wood/coal is basically the same as the cost for wood-fired
boilers controlled with MC/WS systems.
4.3 COSTS OF PM CONTROLS FOR RDF-FIRED BOILERS
No model boiler was evaluated for RDF-fired boilers. However, emission
test data from one site firing 100 percent RDF indicated that similarly
sized ESPs applied to RDF firing will achieve the same emission levels as
ESPs applied to MSW-fired boilers. Therefore, the costs of PM control for
s.-7
-------
TABLE 4.2-1. SCA'S REQUIRED TO ACHIEVE ESP OUTLET EMISSION
LEVELS OF 43 NG/J (0.1 LB/105 BTU)
Fueld
Wood
HSC
LSC
ESP Efficiency Required3
90
91
86
SCA ft2/1000 acfm
250C
100b
185b
Based on uncontrolled emission levels for spreader stoker boilers and the
assumption that the mechanical collector precleaner is 80 percent efficient
when firing either fuel.
Reference 10.
Reference 11.
HSC - high sulfur coal.
LSC - low sulfur coal.
4-8
-------
TABLE 4.2-2. CAPITAL AND ANNUALIZED PM CONTROL COSTS FOR
44 MW (150 x 10°) WOOD/COAL FIRED BOILER
PM Emission Control System Costs
Emission Level Capital Costs Annualized Costs
Fuel ng/J (lb/10°'Btu) ($1000) ($1000/yr)
Wood/Coal 43 (0.10) 1308 349
Wood3 43 (0.10) 936 352
Interpolated results from Tables 3-1 and 3-4.
4-9
-------
RDF-fired boilers would be approximately the same as the costs of PM control
for the MSW-fired boilers shown in Chapter 3.
4.4 SOLID WASTE/FOSSIL FUEL MIXTURES
As discussed in Section 4.2, PM control systems for boilers firing fuel
mixtures and using ESP's for PM control are sized based on the fuel which is
most difficult to control when it is fired alone. Boilers firing solid
waste (RDF or MSW) may also fire the same types of fossil fuels used with
wood fired boilers. For these boilers, as with wood, the most difficult,
case to control will be when firing 100 percent fossil fuels. Therefore,
the cost of PM control for boilers designed to fire solid waste/fossil fuel
mixtures will be no more expensive than the cost for the model boilers
firing 100 percent solid waste shown in Chapter 3.
4-10
-------
4.5 REFERENCES
1. U.S. Environmental Protection Agency. Nonfossil Fuel Fired Industrial
Boilers - Background Information. Research Triangle Park, N.C.
Publication No. 450/3-82-007. March 1982. p. 4-26.
2. Neveril, R. B. (GARO, Inc.) Capital and Operating Costs of Selected
Air Pollution Control Systems. Prepared for U.S. Environmental Protec-
tion Agency. Research Triangle Park, N.C. Publication No.
EPA-450/5-80-002. December 1978.
3. Telecon, Piccot, S., Radian Corporation with Wheelabrator-Frye, Inc.
September 12, 1980. Baghouse costs.
4. Guthrie, K.M. (W.R. Grace & Company.) Data and Techniques for
Preliminary Capital Cost Estimating. Chemical Engineering. Reprint
from March 24, 1969 issue. 29 p.
5. Telecon, Murin, P., Radian Corporation with Al Liepins, Flex-Kleen
Corporation. September 19, 1980. Baghouse costs.
6. Telecon, Barnett, K., Radian Corporation with Tom Davis, United McGill.
October 22, 1982. Sizing ESPs for Wood/Fossil Fuel Mixtures.
7. Telecon, Barnett, K., Radian Corporation with Robert Bump, Research
Control. October 22, 1982. Sizing ESPs for Wood/Fossil Fuel Mixtures.
8. Reference 1, p. 7-2.
9. U.S. Environmental Protection Agency. Fossil Fuel Fired Industrial
Boilers - Background Information. Research Triangle Park, N.C.
Publication No. EPA-450/3-82-006. March 1982. p. 7-2.
10. Bowen, M.L. and M.S. Jennings. (Radian Corporation.) Costs of Sulfur
Dioxide, Particulate Matter, and Nitrogen Oxide Controls on Fossil Fuel
Fired Industrial Boilers. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. Publication No.
EPA-450/3-82-021. May 1982. p. A-18.
11. Memo from Murin, P. and K. Barnett, Radian Corporation, to file.
June 22, 1982. 166 pp. Emission control specifications and model
boiler cost estimating.
4-11
-------
APPENDIX A
DETAILED LINE BY LINE COSTS
Appendix A presents the detailed line-by-line costs for uncontrolled
model boilers and PM control systems. Separate values are shown for the
equipment cost and the installation cost. The factors used to calculate the
installation cost are shown in Table 2.1-6 as a function of equipment cost.
Bases used to calculate other capital cost components are shown in
Table 2.1-1.
A-l
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APPENDIX B
ESCALATION FACTORS
Appendix B presents the escalation factors used to convert the costs
presented in this report (mid 1978 dollars) to a more current year basis.
These factors are based on the Chemical Engineering Plant cost index.1 To
convert to a later year basis, the costs in mid-1978 dollars are multiplied
by the escalation factor.
Basi's Escalation Factor
mid-1979 1 09
mid-1980 l'l9
mid-1981 1*37
mid-1982 1*44
Economic Indicators. Chemical Engineering. 85(21):7, September 25 1978-
86(20):7 September 24, 1979; 87(21):7, Octobi? 20 19^88(21)-' '
T5ctober 19, 1981; 89(9):7, Aug^t, 1981; 90( ):7. °°V^-'»
B-l
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/3-83-004
4. TITLE AND SUBTITLE
Costs or Particulate Matter Controls for Nonfossil
Fuel Fired Boilers
3. RECIPIENT'S ACCESSION NO.
5.
February 1983
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Keith W. Barnett, William D. Kwapil, Suzanne C. Margerum
Radian Corporation
8. PERFORMING ORGANIZATION REPORT NO.
:ORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Radian Corporation
3024 Picket Road
Durham, NC 27705
11. CONTRACT/GRANT NO.
68-02-3058
SPONSORING AGENCY NAME AND ADDRESS
Emission Standards and Engineering Division
Office of Air Quality Standards and Planning
US Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA 200/04
15. SUPPLEMENTARY NOTES
Project Officer: Larry Jones
This report is a resource document for the development of Federal standards
of performance for control of particulate matter from new nonfossil fuel-fired
boilers ranging in size from 30 to 400 million Btu/hour heat input. Capital
and annualized costs for a variety of alternative emission control systems are
given for wood, bark, solid waste (refuse), and bagasse fired boilers.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Boi lers, Nonfossil
Costs, Capital and Annualized
Air Pollution Control Costs
13 B
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (This page)
Unclassified
118
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
-------
rv -r-
U.S. Environmental Prelection Agency
Region V, Library ,-'
uth Dearborn Street
|!;:injs 60604
So
-------
United States Office of Air, Noise, and Radiation
Environmental Protection Office' of Air Quality Planning and Standards
Agency Research Triangle Park NC 27711
Official Business Publication No EPA-480/3-83X504
Penalty for Pr,v,,e Use
•iy" Environmental
Protection
Agency
EPA 335
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