&EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-89-14
May 1989
Air
Model Boiler Cost
Analysis for Controlling
Sulfur Dioxide (SCfc)
Emissions from Small
Steam Generating Units
-------
EPA-450/3-89-14
MODEL BOILER COST ANALYSIS
FOR CONTROLLING SULFUR DIOXIDE (SO2)
EMISSIONS FROM SMALL STEAM GENERATING UNITS
Emission Standards Division
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and.Standards
Research Triangle Park, N.C. 27711
May 1989
-------
This report has been reviewed by the Emission Standards 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 of use. Copies of the report
are available through the Library Service Office (MD-35), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711, or from
National Technical Information Services, 5285 Port Royal Road, Springfield,
Virginia 22161.
ii
-------
TABLE OF CONTENTS
Section £a§e
1.0 INTRODUCTION 1
2.0 SUMMARY 2
3.0 MODEL BOILER COSTING METHODOLOGY . 4
4.0 MODEL BOILER COST ANALYSIS RESULTS 6
4.1 COAL 6
4.2 OIL • 7
5.0 REFERENCES 9
111
-------
LIST OF TABLES
Table Page
1 S02 ALTERNATIVE CONTROL LEVELS 10
2 PROJECTED FUEL PRICES FOR EPA REGION V 11
3 MODEL BOILER COST ANALYSIS FOR SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR COAL-FIRED BOILERS IN REGION V AT 0.26
CAPACITY FACTOR 12
4 MODEL BOILER COST ANALYSIS FOR SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR COAL-FIRED BOILERS IN REGION V AT 0.55
CAPACITY FACTOR 13
5 COST EFFECTIVENESS RESULTS OF SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR COAL-FIRED BOILERS IN REGION V AT 0.26
CAPACITY FACTOR 14
6 COST EFFECTIVENESS RESULTS OF SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR COAL-FIRED BOILERS IN REGION V AT 0.55
CAPACITY FACTOR 15
7 MODEL BOILER COST ANALYSIS FOR SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR OIL-FIRED BOILERS IN REGION V AT 0.26
CAPACITY FACTOR 16
8 MODEL BOILER COST ANALYSIS FOR SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR OIL-FIRED BOILERS IN REGION V AT 0.55
CAPACITY FACTOR 17
9 COST EFFECTIVENESS RESULTS OF SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR OIL-FIRED BOILERS IN REGION V AT 0.26
CAPACITY FACTOR is
10 COST EFFECTIVENESS RESULTS OF SULFUR DIOXIDE CONTROL
ALTERNATIVES FOR OIL-FIRED BOILERS IN REGION V AT 0.55
CAPACITY FACTOR 19
iv
-------
1.0 INTRODUCTION
This report presents estimates of the costs and cost effectiveness
associated with controlling sulfur dioxide (S02) emissions from small coal-
and oil-fired steam generating units (i.e., boilers). The report was
prepared as part of the project to develop new source performance standards
(NSPS) for small boilers under Section 111 of the Clean Air Act. Small
boilers are defined as industrial-commercial-institutional boilers having
heat input capacities of 29 MW (100 million Btu/hour) or less. The
regulatory baseline and alternative control levels used in this cost
analysis are discussed in the report entitled, "Overview of the Regulatory
Baseline, Technical Basis, and Alternative Control Levels for Sulfur Dioxide
(S02) Emission Standards for Small Steam Generating Units".1
-------
2.0 SUMMARY
Capital, operation and maintenance (O&M), and annualized costs were
estimated for model boiler/S02 control systems firing coal and oil in EPA
Region V. The SO- control techniques examined for coal-fired boilers were
the use of low sulfur coal, flue gas desulfurization (FGD) systems, and
fluidized bed combustion (FBC) units. For oil-fired boilers, the use of
medium sulfur oil, very low sulfur oil, and FGD systems were examined.
Annualized costs for the model coal-fired boilers at the regulatory
baseline range from $599,000/yr at the 2.9 MW (10 million Btu/hour) boiler
size and 0.26 capacity factor to $3,661,000/yr at the 29 MW (100 million
Btu/hour) boiler size and 0.55 capacity factor. The increase in annualized
costs over the regulatory baseline for Alternative Control Level 1 (i.e.,
firing low sulfur coal) ranges from 4 to 7 percent. Alternative Control
Level 2 (i.e., 90 percent S02 reduction) increases annual ized costs by 22 to
56 percent over the regulatory bas'eline.
The incremental cost effectiveness of emission control associated with
Alternative Control Level 1 over the regulatory baseline ranges from $536/Mg
($486/ton) at the 29 MW (100 million Btu/hour) boiler size and 0.55 capacity
factor to $2,120/Mg ($l,920/ton) at the 2.9 MW (10 million Btu/hour) size
and 0.26 capacity factor. The incremental cost effectiveness of emission
control associated with Alternative Control Level 2 over Alternative Control
Level 1 ranges from $3,060/Mg ($2,830/ton) to $33,300/Mg ($30,200/ton) over
the same range in boiler size and capacity factor.
Annualized costs for model oil-fired boilers at the regulatory baseline
range from $330,000/yr at the 2.9 MW (10 million Btu/hour) size and 0.26
capacity factor to $2,623,000/yr at the 29 MW (100 million Btu/hour) size
and 0.55 capacity factor. Compared to the regulatory baseline, Alternative
Control Level 1 (i.e., firing medium sulfur oil) increases annualized costs
by 2 to 4 percent; Alternative Control Level 2 (i.e., firing very low sulfur
oil) increases annualized costs by 8 to 21 percent; and Alternative Control
Level 3 (90 percent S02 reduction) raises annualized costs by 29 to 96
percent.
-------
The incremental cost effectiveness of emission control associated with
Alternative Control Level 1 over the regulatory baseline averages about
$339/Mg ($308/ton) for all boiler sizes and capacity factors. The
incremental cost effectiveness of emission control associated with
Alternative Control Level 2 over Alternative Control Level 1 averages about
$l,560/Mg ($l,420/ton) for all boiler sizes and capacity factors. This is
because the only cost differences between these alternative control levels
are fuel cost differences. Since these costs vary in proportion to SO.
emission differences, incremental cost effectiveness does not change with
boiler size or capacity factor.
The incremental cost effectiveness of emission control associated with
Alternative Control Level 3 over Alternative Control Level 2 increases with
decreasing boiler size and capacity factor from $12,300/Mg ($ll,200/ton) to
$393,000/Mg ($357,000/ton). This reflects the economies of scale associated
with FGD systems.
-------
3.0 MODEL BOILER COSTING METHODOLOGY
This model boiler cost analysis estimates capital, O&M, and annualized
costs using the methodology discussed in References 2 and 3. The selection
of model boiler types and sizes used in this analysis is discussed in
Reference 4. All costs are presented in June 1985 dollars. Capital and O&M
costs were updated from other time bases using the Chemical Engineering (CE)
plant cost and Bureau of Labor Statistics (BLS) producer price indices,
respectively. The total cost for each model system includes the costs of
the boiler, fuel, and add-on SO- control equipment, where applicable.
The S02 alternative control levels used in this analysis are summarized
in Table 1. As discussed in Reference 1, a regulatory baseline of 1,550
ng/J (3.6 ID/million Btu) is selected for coal-fired boilers for purposes of
analysis. This emission level is represented by the firing of type
F-bituminous coal. This coal has a maximum expected S02 emission rate of
1,550 ng/J (3.6 Ib/million Btu) and a long-term average SO- emission rate of
1,230 ng/J (2.86 Ib/million Btu). Alternative Control Level 1. for coal is
an emission level of 520 ng/J (1.2 Ib/million -Btu). In the analysis, this
emission level is met by firing low sulfur, type-B bituminous coal.
Alternative Control Level 2 for coal is a requirement of 90 percent SO-
reduction on a continuous basis. This level can be achieved using either
FGD or FBC systems. Various coal types were examined to determine the
lowest cost option for FGD or FBC application. Type F-bituminous coal
results in the lowest annualized costs for a 90 percent SO- reduction
requirement.
As discussed in Reference 1, a regulatory baseline of 1,290 ng/J (3.0
Ib/million Btu) is selected for oil-fired boilers for purposes of analysis.
Alternative Control Level 1 for oil is an emission level of 690 ng/J
(1.6 ID/million Btu). In the analysis, this emission level is achieved by
the firing of medium sulfur oil. Alternative Control Level 2 for oil is an
emission level of 210 ng/J (0.50 Ib/million Btu), which is met by firing
very low sulfur oil. Although either very low sulfur residual oil or
distillate oil can be used to meet Alternative Control Level 2, only
distillate oil is considered to be universally available in this sulfur
-------
content range. The sulfur content of distillate oils can range up to
210 ng S02/J (0.50 Ib S02/million Btu), but the average distillate oil
contains about 130 ng S02/J (0.30 Ib SOg/million Btu). As a result, the
typical distillate oil selected for this analysis produces SCL emissions of
130 ng/J (0.30 Ib/million Btu). Ninety percent S02 reduction is required
under Alternative Control Level 3 and is met by use of FGD systems. High
sulfur oil was chosen for use with an FGD system to meet Alternative Control
Level 3 because it results in the lowest annualized costs for the FGD
option.
The costs associated with Alternative Control Level 2 for coal-fired
boilers and Alternative Control Level 3 for oil-fired boilers are based on
costs for sodium and dual alkali FGD systems. Although not specifically
included, costs for wet lime/limestone FGD, lime spray drying, and FBC are
in the same general range as those for sodium and dual alkali FGD.
Therefore, the costs presented for these alternative control levels are
representative of systems that are capable of achieving 90 percent SO-
reduction on a continuous basis.
The fuel prices used in this analysis are presented in Table 2. These
are projected prices for fuel delivered in EPA Region V, levelized over a
15-year period from 1992 to 2007. Region V fuel prices were used for
illustrative purposes. Similar cost results would be expected using fuel
prices for other EPA regions.
For the various alternative control levels, costs were estimated for
appropriate methods to. ensure compliance. For the reduced sulfur oil
alternatives, shipment fuel sampling and analysis are required. Both the
specified procedure and the associated costs for this compliance option are
discussed in Reference 6. The low sulfur coal alternative would require
continuous monitoring of some type, either daily fuel sampling and analysis
of the coal fired or installation of an outlet SO- continuous emission
monitor (CEM). Daily fuel sampling and analysis result in lower continuous
monitoring costs. For the 90 percent SO- reduction alternatives, continuous
monitoring is required. Costs for daily fuel sampling and analysis at the
inlet and an S02 CEM at the outlet are used in this analysis. (An inlet
S02 CEM could be used instead of fuel sampling and analysis for FGD
applications, but this would result in higher costs.)
-------
4.0 MODEL BOILER COST ANALYSIS RESULTS
4.1 COAL
Tables 3 and 4 present the costs of model coal-fired boilers operating
at capacity factors of 0.26 and 0.55, respectively. Annualized costs for
model boilers at the regulatory baseline range from $599,000/yr at the 2.9
MW (10 million Btu/hour) boiler size and 0.26 capacity factor to
$3,661,000/yr at the 29 MW (100 million Btu/hour) boiler size and 0.55
capacity factor. The increase in annualized costs over the regulatory
baseline for Alternative Control Level 1 ranges from 4 to 7 percent.
Requiring 90 percent reduction under Alternative Control Level 2 increases
annualized costs by 22 to 56 percent over the regulatory baseline.
Tables 5 and 6 present the results of the analysis for the model coal-
fired boilers at capacity factors of 0.26 and 0.55, respectively. The
incremental cost effectiveness of emission control associated with
Alternative Control Level 1 (i.e., firing low sulfur coal) over the
regulatory baseline ranges from $536/Mg ($486/ton) at the 29 MW (100'million
Btu/hour) boiler size and 0.55 capacity factor to $2,120/Mg ($l,920/ton) at
the 2.9 MW (10 million Btu/hour) boiler size and 0.26 capacity factor. The
incremental cost effectiveness of emission control associated with
Alternative Control Level 2 over Alternative Control Level 1 ranges from
$3,060/Mg ($2,830/ton) at the 29 MW (100 million Btu/hour) boiler size and
0.55 capacity factor to $33,300/Mg ($30,200/ton) at the 2.9 MW (10 million
Btu/hour) size and 0.26 capacity factor.
The incremental, cost effectiveness of emission control associated with
Alternative Control Level 1 decreases with increasing boiler size and
capacity factor. This is due to the fact that daily fuel sampling and
analysis are required for compliance under Alternative Control Level 1 but
not under the regulatory baseline. While the annualized costs associated
with the daily fuel sampling and analysis remain constant as boiler size and
capacity factor increase, the S02 emission reductions under Alternative
Control Level 1 increase. Other costs associated with S02 control (e.g.,
-------
fuel costs) increase in proportion to boiler size and capacity factor. As a
result, the incremental cost effectiveness of emission control decreases as
boiler size and capacity factor increase.
A similar trend occurs when comparing Alternative Control Level 2 to
Alternative Control Level 1. In this case, an outlet S02 CEM is required
for compliance under Alternative Control Level 2 in addition to fuel
sampling and analysis. While the annualized costs for the CEM remain
constant as boiler size and capacity factor increase, S02 emission
reductions increase. In addition, due to economies of scale, the annualized
costs of FGD systems (on a heat input capacity basis) decrease as boiler
size increases. Thus, the incremental cost effectiveness of emission
control between Alternative Control Level 2 and Alternative Control Level I
decreases as boiler size increases.
4.2 OIL
Tables 7 and 8 present the costs of oil-fired model boilers operating
at capacity factors of 0.26 and 0.55, respectively. Annualized costs for
boilers at the regulatory baseline .range from $330,000/yr at the 2.9 MW
(10 million Btu/hour) size and 0.26 capacity factor to $2,623,000/yr at the
29 MW (100 million Btu/hour) size and 0.55 capacity factor. Compared to the
regulatory baseline, Alternative Control Level 1 increases annualized costs
by .2 to 4 percent; Alternative Control Level 2 increases annualized costs by
8 to 21 percent; and Alternative Control Level 3 increases annualized costs
by 29 to 96 percent.
Tables 9 and 10 present the results of the analysis for oil-fired
boilers operating at 0,26 and 0.55 capacity factors, respectively. The
incremental cost effectiveness of emission control associated with
Alternative Control Level 1 over the regulatory baseline remains essentially
constant for all boiler sizes and capacity factors, averaging about $339/Mg
($308/ton). This is because the difference in annualized costs between
Alternative Control Level 1 and the regulatory baseline is due primarily to
the price difference between high and medium sulfur oil. Since both S02
-------
emission rates and fuel prices are specified on a heat input basis, varying
boiler size or capacity factor has little impact on incremental cost
effectiveness.
The incremental cost effectiveness of emission control associated with
Alternative Control Level 2 over Alternative Control Level 1 also does not
vary with boiler size or capacity factor. The annualized cost differences
between the two alternative control levels are again due primarily to the
price difference between medium sulfur and very low sulfur oil. As
discussed above, when both SO- emission rates and fuel prices are specified
on a heat input basis, varying boiler size or capacity factor has little
impact on incremental cost effectiveness. Thus, the incremental cost
effectiveness of emission control between Alternative Control Level 2 and
Alternative Control Level 1 remains essentially constant at an average
$l,560/Mg ($l,420/ton) for all boiler sizes and capacity.factors.
The incremental cost effectiveness of emission control associated with
Alternative Control Level 3 over Alternative Control Level 2 increases from
$12,300/Mg ($ll,200/ton) at the 29 MW (100 million Btu/hour) boiler size and
0.55 capacity factor to $393,000/Mg ($357,000/ton) at the 2.9 MW (10 million
Btu/hour) size and 0.26 capacity factor. This increase in incremental cost
effectiveness with decreasing boiler size and capacity factor is due to the
Alternative Control Level 3 continuous compliance requirement and FGD
economies of scale, as discussed for coal-fired boilers in Section 4.1.
8
-------
5.0 REFERENCES
1. Overview of the Regulatory Baseline, Technical Basis, and Alternative
Control Levels for Sulfur Dioxide (SO-) Emission Standards for Small
Steam Generating Units. U. S. Environmental Protection Agency,
Research Triangle Park, NC. EPA Publication No. EPA-450/3-89-12.
May 1989.
2. Industrial Boiler SO- Cost Report. Prepared by Radian Corporation.
Prepared for the U.S. Environmental Protection Agency, Research
Triangle Park, NC. Publication No. EPA-450/3-85-011. July 1984.
3. Development of an Algorithm for Estimating the Costs of Sodium Flue Gas
Desulfurization Systems Designed to Control Emissions of Particulate
Matter and Sulfur Dioxide. Prepared by Radian Corporation. Prepared
for the U.S. Environmental Protection Agency, Research Triangle Park,
NC. August 1986.
4. U. S. Environmental Protection Agency. Small Steam Generating Unit
Characteristics and Emission Control Techniques. Research Triangle
Park, NC. March 31, 1989.
5. Letter from Hogan, T., Energy and Environmental Analysis, Inc., to
Link, T. E., EPA/EAB. June 5, 1987. Annualized Industrial Fuel
Prices.
6. Memorandum from Copland, R., EPA/SDB, to Waddell, T., Radian
Corporation. March 27, 1989. Cost of Oil Shipment (Lot)
Sampling/Analysis Alternative for"Small Boilers.
7. Memorandum from Copland, R., EPA/SDB, to Link, T., EPA/EAB. July 2,
1987. Revised Regulatory Alternatives for Small Boiler Impacts
Analysis.
-------
TABLE 1. S02 ALTERNATIVE CONTROL LEVELS
S02 Emission Standard
Basis
Coal
Regulatory baseline
Alternative Control Level 1
Alternative Control Level 2
1,550 ng/J
(3.6 ID/million Btu)
520 ng/J
(1.2 Ib/nrillion Btu)
90% SO- reduction
Medium sulfur coal'
Low sulfur coal
FGD or FBCC
on.
Regulatory baseline
Alternative Control Level 1
Alternative Control Level 2
Alternative Control Level 3
1,290 ng/J
(3.0 Ib/million Btu)
690 ng/J
(1.6 Ib/million Btu)
210 ng/J
(0.5 ID/million Btu)
90% S02 reduction
High sulfur oil
Medium sulfur oil
Very low sulfur oil
FGD
Type F-bituminous
Type B-bituminous
CFGD = Flue gas desulfurization
FBC = Fluidized Bed Combustion
SOURCE: Reference 1.
10
-------
TABLE 2. PROJECTED FUEL PRICES FOR EPA REGION V
Coal: S/GJ (S/million Btu)a
Low sulfur bituminous 2.73 (2.88)
Medium sulfur bituminous 2.38 (2.51)
Oil:
High sulfur residual 3.51 (3.70)
Medium sulfur residual 3.70 (3.90)
Distillate 4.61 (4.86)
Natural Gas:b 4.49 (4.73)
aLevelized prices in June 1985 dollars.
Industrial non-carriage market price. Used during FGD malfunction.
SOURCE: Reference 5.
11
-------
TABLE 3. Model Boiler Cost Analyila for Sulfur Dioxide Control Alternative! for Coal-fired Boiler* In Region V at 0.26 Capacity Factor,
IVJ
Boiler
b.c.d.e.
Site/ Control
2.9 Ml
7.3 Ml
14.6 Ml
22.0 Ml
29.3 Ml
(10 HHatu/br)
Baaallna
Level 1/LSC
Level 2/n
(23 tMBtu/br)
Baaellne
Level 1/LSC
Level 2/n
(30 Ftffltu/br)
Baaellna
Level 1/LSC
Level 2/n
(71 Mffitu/hr)
Baseline
Level 1/LSC
Level 2/n
(100 Mffltu/hr)
Baaellne
Level 1/LSC
Level 2/n
Coal
typ«.
F-BIT
B-1IT
r-iit
F-BIT
•-BIT
F-BIT
B-BIT
B-BIT
r-BIT
r-m
B-BIT
r-B»
r-Bit
B-BIT
r-Bir
Actual SO
«oit*»lon rate,
n»/J (Ib/Mtttu)
1,2)0
465
»3
1,230
463
93
1,230
465
93
1.230
463
93
1.210
463
93
(2.86)
(1.08)
(0.22)
(2.86)
(1.08)
(0.22)
(2.B6>
(1.08)
(0.22)
(2.86)
(1.08)
(0.22)
(2.86)
(1-08)
(0.22)
Annual SO
•million*,
Ht/yr (toiufyr)
30
11
2.2
74
28
3.6
liO
56
11
220
• 4
17
300
109
22
(33)
(12)
(2.3)
(81)
(31)
(6.2)
, .
(160)
(61)
(12)
(240)
(92)
(18)
(330)
(120)
(23)
Caplol
coeca,
$1,000
1,353
1,380
2,399
2.797
2.823
3,833
4.967
4.994
6,366
7.136
7,163
8,761
9,138
9,189
14.991
0 I H
Fuel
57
66
57
143
164
143
286
328
286
429
492
429
372
656
572
coat a, $1,
Honfuel
285
311
479
391
418
603
592
619
817
663
689
936
742
768
1,042
000/yr
Total
342
377
536
534
582
748
878
947
1,123
1,092
1.181
1.365
1,314
1.424
1.614
Anmiallaad
colt,
$1,000/ yr
599
638
935
998
1.050
1.391
1.703
1.776
2.159
2.280
2.374
2,793
2.840
2.935
3.482
All caita ece In June 1983 dollara.
b
LSC • Low aulfur coal
PR - Percent reduction eyatea (Flue gee deaulfurlaation or fluldiaed bed coabuitloo)
c
Ha compliance coata are Included ultb the bateline option.
d
Alternative Control Lavel 1 Include I the compliance coiti aisoclated ulctl fuel >arcpl Ln(/analysis.
Alternative Control Level 2 Includes the costi a»oclaced with dally fuel aauf>llna./analy«I* at the FGD Inlet and continuous enlailon
manltorin( at the FCD outlet.
-------
TABLE 4. Model Boiler Cost Analysis for Sulfur Dioxide Control Alternatives for Coal-fired Boilers In Region V ac 0.33 Capacity Factor*
Boiler
Sice/Control '*' '*
2.*
7.1
14.6
22.0
29.1
m (10 MMBtu/hr)
Best line
Level 1/LSC
Laval tin.
Ml (23 Mffltu/hr)
Baseline
Level 1/LSC
Level 2/Hl
Ml (M Mffitu/hr)
less line
Level 1/LSC
Level 2/ftt
Ml (71 IMBtu/lu)
Baseline
Level 1/LSC
Level 2/ra
Ml (100 MUCu/hc)
Baseline
Level 1/LSC
Level 2/n
Coal
type.
F-BII
B-BIT
r-BIT
F-BIT
B-BIT
P-BIT
P-BIT
• -•IT
r-BiT
F-0IT
•-•IT
F-BIT
P-BIT
•B-BII
r-BiT
Actual SO
emission tale.
iuj/J (Ib/Matu)
1,210
463
93
1,210
463
91
1,210
463
93
1,210
465
91
1,210
463
91
(2.86)
(1.08)
(0.22)
(2.86)
(1.08)
(0.22)
(2.86)
(1.08)
(0.22)
(2.86)
(1.08)
(0.22)
(2.86)
(1.08)
(0.22)
Annual S
emissions,
Hg/yc (toni/yr)
63
24
4.7
150
39 '
12
MO
120
24
470
180
16
610
240
43
(69)
(26)
(3.2)
(170)
(6t)
(13)
•(140*
(130)
(26)
(320)
(200)
(1»>
(690)
(260)
(30)
Capital
costs,
$1.000
1.574
1.S99
2,424
2,810
2,838
1,877
3.020
3.031
6.413
7,207
7.241
8.831
9,247
9.283
11,106
O » M coats, $l,000/yr
Fuel
121
119
121
102
3*7
302
603
694
603
907
1.041
907
1,209
1,388
1,209
Nonfuel
3S3
382
381
492
318
731
729
733
1.O43
818
841
1.183
917
941
1.111
Total
476
321
702
794
863
1.031
,134
.449
.630
.723
.884
.092
2,126
2,129
2,342
Annual Iced
cost,
Sl.OOO/yr
735
784
1.107
1.261
1.117
1,112
2,163
2,283
2,731
2,920
1.083
1.618
1.661
1.870
4.463
All coat* are In June 1983 dollars.
bLSC - tow sulfur coal
PR - Percent reduction ayatsna (Flue |as desulfurlastlon or fluldlaed bed combustion)
Ho compliance, coats are included ulth the liasellne option.
4
Alternative Control Level 1 include* the coapllsnca cost* associated with fuel samplLoc/analysls.
Alternative Conceal Level 2 Includes the coat* associated with dally fuel aaopllnf/analysls at the FGO Inlet and continuous emission
•onltorlnc at the PCD outlet.
-------
TABLE 5. Cost Effectiveness Results of Sulfur Dioxide Control Alternatives
for Coal-fired Boilers In Region V at 0.26 Capacity Factor*
Boiler
SlEe/Controlb>C
-------
TABLE 6. Cost 'Effectlvenesa Result* of Sulfur Dioxide Control Alternatives
for Coal-fired Boilers In Region V at 0.55 Capacity Factor*
in
Boiler
Sl«e/Controlb'C'd'"
2.9
7.J
14.6
22.0
29.3
Ml (10 Mffitu/hr)
Baseline
Level 1/LSC
Level 2/PH
Mt (25 MMBtu/hr)
Baseline
Level 1/LSC
Level 2/FR
MU (50 MMBtu/hr)
Baseline
Level 1/LSC
Level 2/PR
HU (79 HMBtu/hr)
Baseline
Level 1/LSC
Level 2/PR
MU (100 >MBtu/hr)
Baseline
Level 1/LSC
Level 2/P«
Coal
typ«.
P-B1T
B-BIT
r-Bir
F-BIT
B-BIT
F-BIT
F-BIT
B-BIT
F-BIT
F-BIT
B-BIT
F-BIT
F-BIT
B-BIT
F-BIT
Actual SO
emission rate,
ng/J (Ib/MMBtu)
1,230
465
93
1.230
465
93
1,230
*6i
93
1.230
465
93
1,230
465
93
<2
(1
(0
(2
(1
(0
(2
(1
(0
(2
(1
(0
(2
(1
(0
.£6)
.08)
.22)
.86)
.OB)
.22)
.86)
.08)
.22)
.86)
.08)
.22)
.86)
.08)
.22)
Annual
emission
Hg/yr (ton/yr)
63
24
4.7
150
59
12
310
120
24
470
180
36
630
240
43
(69)
(26)
(5.2)
(170)
(65)
(13)
(340)
(130)
(26)
(520)
(200)
(39)
(690)
(260)
•(50)
Annuallztd
coat,
SlOOO/yr
1
1
1
1
2
2
2
2
3
3
3
3
4
735
784
.107
,261
.337
.712
.165
,285
,«3
.920
,085
.618
.661
,870
.465
Incremental
cost effectiveness,
$/Hg (S/ton)
-
1,260
17.100
-
835
7.950
-
632
4.850
-
569
3,690
-
536
3.060
-
(1.140)
(15.500)
-
(724)
(7.210)
-
-------
TABLE 1. Nodal Boiler Colt Analyst* lor Sulfur Dlonlde Control Alternative* for Oll-flred Boilers In
Region V at 0.26 Capacity Factor
Boiler SUe/Control1"'0'11'*
2.9 HU
7.1 MU
14.6 KU
22.0 KU
29.3 HU
(10 HMBtufhc)
Btaellne
Laval 1/MSRO
Laval 2/01810
Laval I/Ml
(23 HHBtu/hr)
8***llna
Laval 1/MSRO
Laval 2/OISIO
Laval 3/Wl
(50 HHBtu/hc)
Baaellne
Laval UHSRO
Laval Z/DISTO
Laval I/PR
(IS Mffitujhr)
Beaellne
Laval 1/MSRO
Laval 2/DISTO
Laval tin
(100 KMBtu/hr)
Baiellne
Laval 1/MSRO
Laval 2/DISTO
Laval tin
"a
eoUaslon rata,
luj/J (Ib/HMBtu)
1,290
688
129
98
1.290
668
129
98
1.290
688
129
98
1,290
6BS
129
98
1,290
6S8
129
9B
(1.00)
(1.60)
(0.30)
(0.21)
(1.00)
(1.60)
(O.JO)
(0.23)
(1.00)
(1.60)
(0.10)
(0.21)
<1.«0)
<1.<0)
(0.10)
(0.23)
(1.00)
(1.60)
(0.10)
(0.21)
Annual SO
emission*.
Ms/yr (tooa/yr)
31
17
1.1
2.4
77
41
7.7
5.9
155
81
IS
12
212
124
21
18
310
165
11
24
(1*)
(18)
(3.4)
(2.6)
(85)
(46)
(8.5)
(6.5)
(171)
(91)
(17)
(11)
(256)
(137)
(26)
(19)
(142)
(182)
(14)
(26)
Capital
coat*.
81.000
445
445
414
1.172
713
714
717
1,482
1.481
1.483
1,463
2.699
1.90O
1.903
1,883
1.141
2.277
2,281
2,262
1,921
O ( M coata, $1,
Fual Nonfual
84
89
111
84
211
222
277
211
421
444
551
421
612
666
810
612
841
888
1.107
841
174
175
174
374
210
232
230
455
274
275
274
536
318
119
318
615
361
362
361
691
000 /yc
Total
258
264
285
458
441
454
507
666
695
719
827
957
950
985
1.148
1,247
1,204
1,250
1,468
1,53*
Annuallcad
co«t,
$1.000/yc
130
136
155
648
561
571
624
942
939
963
.068
.406
,264
,299
.458
,805
1.379
1.626
1.839
2.186
*A11 eoata are In June 1985 dollar*.
bKSRO - Hadtun *uLfur raaldual oil
OISTO • DUtlllat* oil
PB - 901 S02 raooval (bated on flue fa* daaulfurlcatlon)
CTba> cooplUnce coit* for Alternative Control Laval 1 are the co*t< aasoclatad with thlpcMnc fuel •aoplln«/analy*la.
ddo coapllanca coata **)ocUted with dlatlllata oil combuttlon to meet Alternative Control Laval 2.
"the campllance coat* for Alternative Control Level 1 are the cost* aaaocUted with dally fuel sampling/analy*la at the FCD
inlet and continuous cmlsalon nonltorlne. at the FCO outlet.
-------
TABLE 8. Model Boiler Cost Analysis for Sulfur Dioxide Control Alternatives for Oil-fired Boilers in
Region V at 0.55 Capacity Factor*
Boiler Siie/Controlb'c'd'e
2.9 NU
7.3 NU
14.6 NU
22.0 NU
29.3 NU
(10 MMBtu/hr)
Baseline
Level 1/NSRO
Level 2/OISTO
Level 3/PR
(25 MMBtu/hr)
Baseline
Level 1/NSRO
Level 2/OISTO
Level 3/PR
(50 HMBtu/hr)
Baseline
Level 1/NSRO
Level 2/OISTO
Level 3/PR
(75 MMBtu/hr)
Baseline
Level 1/HSRO
Level 2/OISTO
Level 3/PR
(100 NMBtu/hr)
Baseline
Level 1/NSRO
Level 2/DISTO
Level 3/PR
emission rate,
ng/J (Ib/MMBtu)
1,290
688
129
98
1.290
688
129
98
1.29.0
688
129
98
1.290
688
129
98
1.290
688
129
98
(3.00)
(1.60)
(0.30)
(0.23)
(3.00)
(1.60)
(0.30)
(0.23)
(3.00)
(1.60)
(0.30)
(0.23)
(3.00)
(1.60)
(0.30)
(0.23)
(3.00)
(1.60)
(0.30)
(0.23)
Annual SO.
emissions;
Ng/yr (tons/yr)
66
35
6.6
5.0
164
87
16
12
328
175
33
25
492
262
49
37
656
350
66
50
(72)
(39)
(7.2)
(5.5)
(181)
(96)
(18)
(14)
(361)
(193)
(36)
(27)
(542)
(289)
(54)
(41)
(723)
(385)
(72)
(55)
Capital
costs,
$1.000
461
462
453
1.194
764
766
754
1.723
1.535
1.539
1.529
2,769
1.976
1.982
1.977
3.440
2.374
2.382
2.384
4.046
0 i N costs, $1.000/yr
fuel Honfuet
178
188
234
178
446
470
585
446
891
940
1.171
891
.337
.409
.756
.337
.783
.879
2.342
1.783
220
220
219
452
291
292
292
565
346
346
346
682
401
402
401
797
455
456
455
910
Total
398
408
453
630
737
762
877
1.011
,237
,286
,517
,573
.738
,811
2,157
2,134
2.238
2.335
2.797
2.693
Annualized
cost.
Sl.OOO/yr
1
1
1
1
2
2
2
2
2
2
2
3
3
471
482
526
824
860
885
997
.295
.487
t ^"""
.537
f ** •
.764
• • w»
.036
.059
.133
§ • «•*•
.476
f -* • W
.712
.623
* "»"»^
722
* • •"••
.181
.375
*All costs are in June 1985 dollars.
bNSRO » Nedium sulfur residual oil
DISTO = Distillate oil
PR - 90% S02 removal (based on flue gas desulfurization)
The compliance costs for Alternative Control Level 1 are the costs associated with shipment fuel sampling/analysis.
Mo compliance costs associated with distillate oil combustion to meet Alternative Control Level 2.
The compliance costs for Alternative Control Level 3 are the costs associated with daily fuel sampling/analysis at the FGO
inlet and continuous emission monitoring at the FGO outlet.
-------
TABLE 9. Cost Effectiveness Results of Sulfur Dioxide Control Alternatives for Oil-fired
Boilers in Region V at 0.26 Capacity factor
CD
Boiler Size/
Control8'8'8-'
2.9 HU
7.3 HU
U.6 NU
22.0 HU
29.3 NU
(10 KMBtu/hr)
Baseline
Level 1/MSRO
Level 2/DISro
Level 3/PR
(25 HMBtu/hr)
Baseline
Level 1/MSRO
Level 2/DISTO
Level 3/PR
(SO NNBtu/hr)
Baseline
Level 1/MSRO
Level 2/DISTO
Level 3/P8
(75 HMBtu/hr)
Baseline
Level 1/MSRO
Level 2/DISTO
Level 3/PR
(100 HMBtu/hr)
Baseline
Level 1/MSRO
Level 2/DISTO
Level 3/PR
emission rate,
ng/J (Ib/HHBtu)
1.290
688
129
98
1,290
688
129
98
1.290
688
129
98
1.290
688
129
98
1.290
688
129
98
(3.
(1.
(0.
(0.
(3.
(1.
(0.
(0.
(3.
(1.
(0.
(0.
(3.
(1.
(0.
(0.
(3.
(1.
(0.
(0.
00)
60)
30)
23)
00)
60)
30)
23)
00)
60)
30)
23)
00)
60)
30)
23)
00)
60)
30)
23)
Annua I Annua 4 i zed
eaissions, cost.
Mg/yr (ton/yr) »1000/yr
31
17
3.1
2.4
77
41
7.7
5.9
155
83
15
12
232
124
23
18
310
165
31
24
(34)
(18)
(3.4)
(2.6)
(85)
(46)
(8.5)
(6.5)
(171)
(91)
(17)
(13)
(2S6)
(137)
(26)
(19)
(342)
(182)
(34)
(26)
1.
1.
1.
1.
t.
1,
1.
1.
1,
2.
330
336
355
648
561
573
624
942
939
963
068
406
264
299
458
805
579
626
839
186
Incremental
cost effectiveness,
*/Mg ($/ton)
1.
393.
1.
171,
1.
90.
1.
62.
1.
46.
_
415
410
000
-
332
520
000
-
332
560
700
-
323
580
100
-
325
590
600
.
(376)
(1,280)
(357,000)
-
(301)
(1.380)
(155,000)
-
(301)
(1.420)
(82.300)
-
(293)
(1,430)
(56,300)
-
(295)
(1,440)
(42,300)
*All costs are in June 19B5 dollars.
bHSRO « HediuM sulfur residual oil
DISTO » Distillate oil
PR « 90X SO, removal (based on flue gas desulfuriiation)
cThe compliance costs for Alternative Control Level 1 are the costs associated with shipment fuel
sampling/analysis.
dNo compliance costs associated with distillate oil combustion to meet Alternative Control Level 2.
eThe compliance costs for Alternative Control Level 3 are the costs associated with daily fuel sampling/
analysis at the FGD inlet and continuous emission monitoring at the fCD outlet.
-------
1ABLE
10. Cost Effectiveness Results of Sulfur Dioxide Control Alternatives for Oil-fired
Boilers in Region V at 0.55 Capacity Factor
Boiler Size/ .
Control6'*'"'8
2.9
7.3
14.
22.
29.
HU (10 MHBtu/hr)
Baseline
Level 1/NSRO
Level 2/DIS10
Level 3/PR
HU (25 MKBtu/hr)
Baseline
Level 1/NSRO
Level 2/OIS10
Level 3/PR
6 HU (50 NHBtu/hr)
Baseline
Level 1/MSRO
Level 2/01 STO
Level 3/PR
0 HU (75 NHBtu/hr)
Baselfne
Level 1/HSRO
Level 2/01 STO
Level 3/PR
3 HU (100 MHBtu/hr)
Baseline
Level 1/NSRO
Level 2/DISTO
Level 3/PR
emission rate.
ng/J (tb/MMBtu)
1,290 (3.00)
688 (1.60)
129 (0.30)
98 (0.23)
1,290 (3.00)
688 (1.60)
129 (0.30)
98 (0.23)
1.290 (3.00)
688 (1.60)
129 (0.30)
98 (0.23)
1,290 (3.00)
688 (1.60)
129 (0.30)
98 (0.23)
1,290 (3.00)
688 (1.60)
129 (0.30)
98 (0.23)
Annual
emissions,
Mg/yr (ton/yr)
66
35
6.6
5.0
164
87
16
12
328
175
33
25
492
262
49
37
656
350
66
50
(72)
(39)
(7.2)
(5.5)
(181)
(96)
(18)
(14)
(361)
(193)
(36)
(27)
(542)
(289)
(54)
(41)
(723)
(385)
(72)
(55)
Annual! zed
cost,
*1000/yr
471
482
526
824
860
885
997
1,295
1,487
1,537
1,764
2,036
2,059
2,133
2,476
2.712
2,623
2.722
3,181
3,375
Incremental
cost effectiveness.
S/Hg (S/ton)
-
360
1.550
189.000
-
327
1,580
75.600
-
327
1.600
34,500
-
322
1,610
20,000
-
324
1.620
12,300
-
(330)
(1.400)
(172.000)
-
(297)
(1.430)
(68.600)
-
(297)
(1.450)
(31.300)
-
(293)
(1,460)
(18.100)
-
(294)
(1,470)
(11.200)
All costs are in June 1985 dollars.
bHSRO • Hediiw sulfur residual oil.
01STO « Distillate oil.
PR * 90X SO. removal (based on flue gas desulfurization)
cThe compliance costs for Alternative Control Level 1 are the costs associated with shipment fuel
sampling/analysis.
Ho compliance costs associated with distillate oil combustion to neet Alternative Control Level 2.
eThe compliance costs for Alternative Control Level 3 are the costs associated with daily fuel
sampling/analysis at the fCD inlet and continuous emission Monitoring at the FGD outlet.
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
REPORT NO.
EPA-450/3-89-14
2.
3. RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE
Model Boiler Cost Analysis for Controlling
Sulfur Dioxide (SC^) Emissions from Small
Steam Generating Units
5. REPORT DATE
May 1989
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
Emission Standards Division
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-4378
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
.TYPEO
Final
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report presents estimates of the cost and cost effectiveness
associated with controlling sulfur dioxide (S02) emissions from small coal-and
oil-fired industrial-commercial-institutional steam generating units (small boilers),
The report was prepared during development of proposed new source performance
standards (NSPS) for small boilers (boilers with heat input capacities of 100
million Btu/hour or less).
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution
Pollution Control
Standards of Performance
Steam Generating Units
Industrial Boilers
Small Boilers
Air Pollution Control
18. DISTRIBUTION STATEMENT
Release unlimited
19. SECURITY CLASS .(This Report/
Unclassified
1. NO. OF PAGES
20. SECURITY CLASS (Thispage 1
22. PRICE
Unclassified
EPA Form 2220-1 (R«v. 4-77) PREVIOUS EDITION is OBSOLETE
-------
INSTRUCTIONS
1. REPORT NUMBER
Insert the EPA report number as it appears on the cover of the publication.
2. LEAVE BLANK
X RECIPIENTS ACCESSION NUMBER
Reserved for use by each report recipient.
4. TITLE AND SUBTITLE
TITLE AND SUBTITLE
Title should indicate clearly and.briefly the subject coverage of the report, and be displayed prominently. Set subtitle, if used, in smaller
type or otherwise subordinate it to main title. When a report is prepared in more than one volume, repeat the primary title, aild volume
number and include subtitle for the specific title.
Each report shall carry a date indicating at least month and year. Indicate the basis on which it was selected (e.g.. date of issue, dale of
approval, date of preparation, etc.).
6. PERFORMING ORGANIZATION CODE
Leave blank.
Give name(s) in conventional order (John R. Doe. J. Robert Doe. ete.). List author's affiliation if il differs from the performing organi-
7. AUTHOR(S)
Give m
zation.
8. PERFORMING ORGANIZATION REPORT NUMBER
Insert if performing organization wishes to assign this number.
9. PERFORMING ORGANIZATION NAME AND ADDRESS ...
Give name, street, city, state, and ZIP code. List no more than two levels of an organizational hircarchy.
10. PROGRAM ELEMENT NUMBER
Use the program element number under which the report was prepared. Subordinate numbers may be included in parentheses.
11. CONTRACT/GRANT NUMBER
Insert contract or grant number under which report was prepared.
12. SPONSORING AGENCY NAME AND ADDRESS
Include ZIP code.
13. TYPE OF REPORT AND PERIOD COVERED
Indicate interim final, etc., and if applicable, dates covered.
14. SPONSORING AGtNCY CODE
Insert appropriate code.
Enter information not included elsewhere but useful, such as: Prepared in cooperation with. Translation of. Presented ui conlcrcmv of.
To be published in. Supersedes, Supplements, etc.
Include a brief (200 words or less) factual summary of the most significant information contained in Hie report. II the report contains a
significant bibliography or literature survey, mention it here.
(a) DESCRIPTORS - Select from the Thesaurus of engineering and Scientific Terms the proper authori/.cd terms thai identify the major
concept of the research and are sufficiently specific and precise to be used as index entries lor cataloging.
(b) IDENTIFIERS AND OPEN-ENDED TERMS - Use identifiers for project names, code names, equipment designators, etc. Use open-
ended terms written in descriptor form for those subjects for which no descriptor exists.
(c) COSAT1 HELD GROUP - Field and group assignments are to be taken from the 1965 COSATI Subject Category List. Since the ma-
jority of documents are multidisciplinary in nature, the Primary Held/Group assignments) will be specilic discipline, area ol human
endeavor, or type of physical object. The application(s) will be cross-referenced with secondary l-ield/(,roup assignments that will lollow
the primary posting(s).
Denote reusability to the public or limitation for reasons other than security for example "Release Unlimited." file any availability to
the public, with address and price.
19. & 20. SECURITY CLASSIFICATION
DO NOT submit classified reports to the National Technical Information service.
Insert the total number of pages, including this one and unnumbered pages, but exclude distribution list, il any.
22 PRICE
Insert the price set by the National Technical Information Service or the Government Printing Office, if known.
EPA Form 2220-1 (Rev. 4-77) (R»v«ne)
------- |