United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S2-82-070 Dec. 1982
Project Summary
Acid Rain Mitigation Study:
Volumes I and II.
J. G. Ball and W. R. Menzies
The U.S. EPA has initiated a multi-
phased study of the acid rain problem.
As part of Phase I, Radian Corporation
investigated SO2 emissions and con-
trols in the industrial sector. The
primary objective of this work was to
provide a consistent set of capital
investment and operating costs for
flue gas desulfurization (FGD) sys-
tems applied to both industrial and
electric utility boilers. Retrofit factors
and the cost of FGD systems applied
to new boilers were addressed. Wet
limestone scrubbing and lime spray
drying FGD systems were evaluated.
In conducting the work to provide a
consistent set of capital investment
and operating costs for FGD systems
retrofitted to existing boilers, the
following issues were investigated:
Apparent discontinuities in both
FGD system capital investment
and operating costs as a func-
tion of boiler capacity in the
region between industrial boil-
ers and small utility boilers.
FGD retrofit factors applied to
existing boilers based on published
reports.
Differences between PEDCo
Environmental, Inc. and TVA
cost estimates for utility boiler
FGD systems.
These costing issues were examined
on the bases of design scope, costing
factors (for equipment installation,
indirect investment, etc.), year of
costs, inherent strengths and weak-
nesses, and published data of actual
system costs. Recommendations are
made for the cost bases to use in
further acid rain studies.
This Project Summary was devel-
oped by EPA '$ Industrial Environmen-
tal Research Laboratory, Research
Triangle Park, NC, to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report
ordering information at back).
Introduction
There is a growing concern about the
acidity of precipitation in the north-
eastern United States and Canada.
Many scientists think that acidic precip-
itation kills aquatic and plant life,
damages crop-growing soil, and accel-
erates erosion and damage to buildings.
Although the mechanisms producing
acid rain are not clearly understood,
sulfur dioxide (S02) and oxides of
nitrogen (NOX) are thought to be the
precursors of the chemicals that cause
acid rain. Large quantities of SO2 and
NOx are produced by various combus-
tion and non-combustion processes in
both the utility and industrial sectors.
Reducing these S02 and NOX emissions
to the atmosphere should reduce the
potential for acid rain.
Because this concern is increasing,
the U.S. EPA initiated a multi-phased
study of the acid rain problem. As one
part of Phase I, Radian Corporation
investigated SOa emissions and con-
trols in the industrial sector; Teknekron,
Inc. made a similar study of the utility
sector. The results of these studies
would provide direction for additional
phases. The objectives of the later
phases are to investigate S02 sources in
more detail than Phase I, to investigate
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NOx sources, and to model source/
receptor relationships.
In support of the Phase I efforts,
Radian Corporation was asked to
provide a consistent set of capital
investment and operating costs for flue
gas desulfunzation (FGD) systems
applied to both industrial and electric
utility boilers. Since existing S02
sources are the primary targets for
reducing the impacts of acid rain,
retrofit factors as well as the cost for
FGD systems applied to new boilers
were addressed This report summar-
izes the results of that cost work.
The cost estimates used as the basis
for this study are:
Utility boiler FGD systems by TVA
and PEDCo Environmental, Inc.
Industrial boiler FGD systems by
Radian Corporation.
Wet limestone scrubbing and lime spray
drying FGD systems were evaluated.
The U S EPA has recognized that there
appear to be discrepancies in these
published cost estimates in two areas:
Utility boiler limestone FGD sys-
tem costs prepared by TVA and
PEDCo Environmental, Inc.
FGD system costs in the capacity
transition from industrial boilers
to small utility boilers.
To achieve the primary objective of
the study (provide a consistent set of
capital investment and operating costs
for FGD systems retrofitted to existing
boilers), the following issues were
investigated'
Apparent discontinuities in both
FGD system capital investment
and operating costs as a function
of boiler capacity in the region
between industrial boilers and
small utility boilers.
FGD retrofit factors applied to
existing boilers based on pub-
lished reports.
The differences between PEDCo
Environmental, Inc. and TVA cost
estimates for utility boiler FGD
systems.
The above costing issues are exam-
ined on the bases of design scope,
costing factors (for equipment installa-
tion, indirect investment, etc.), year of
costs, inherent strengths and weak-
nesses, and published data of actual
system costs Recommendations are
made for the cost bases to use in
further acid rain studies.
Summary of Results
The results of the investigations of
each issue are summarized below.
Utility and Industrial Boiler
FGD System Costs
Significant discontinuities in both the
FGD system capital investment and
operating cost areas as a function of
boiler capacity have been observed in
the capacity transition from industrial to
small utility boiler systems. This study
attempts to determine the causes of
these discontinuities and to provide a
consistent set of costs (capital and
operating) for both types of FGD
systems applied to new boilers. Cost
estimates by TVA (for utility boilers) and
Radian Corporation (for industrial
boilers) were used for this analysis
since these estimates are current and
well-documented. In order to properly
compare the TVA and Radian estimates,
the costs were adjusted to the same
economic and technical bases, which
include:
Identical design scope.
Same year of construction basis.
Same indirect investment algo-
rithm basis.
Same unit cost basis for labor,
raw materials, utilities, etc.
In addition, major components of
industrial boiler FGD systems are
usually shop-fabricated whereas utility
systems are field-erected. The capital
and operating costs developed after
accounting for the differences de-
scribed above were compared to deter-
mine if the discontinuities were real or
a result of inaccuracies in one or both
sets of cost data.
Wet limestone scrubbing and lime
spray drying FGD systems are the only
processes evaluated in this study. For
electric utility plants, wet lime and
limestone systems dominate the oper-
ating units; wet lime/limestone scrub-
bing and lime spray drying processes
are the prevalent systems being planned
for future facilities. For industrial
boilers, dual alkali and sodium (once-
through) systems dominate operating
and planned units, although spray
drying systems are beginning to be
applied. The dual alkali is more typical of
the FGD system that will be applied to
large industrial boilers Sodium (once-
through) will most likely be applied to
small boilers where the high TDS (total
dissolved solids) liquid waste can be
easily disposed of (such as on steam
generators used in oil field injection
where the liquid waste can be disposed
of by well injection or in evaporation
ponds)
To simplify the basis of this and other
studies, only the wet lime/limestone
FGD costs are recommended for use in
developing cost impacts of FGD con-
trol for acid ram mitigation. The
reasons for this recommendation are:
The capital and operating costsfor
wet limestone and dual alkali FGD
systems are comparable for in-
dustrial boiler FGD applications
over the capacity range of 30 -
200 x 106 Btu/hr. boiler heat
input.
Due to the large amounts of data
on existing utility boiler FGD
systems, the cost estimates for
limestone systems should be
more accurate than for lime spray
dryer systems. In addition, the
cost estimates supplied by TVA for
utility boiler spray dryer FGD
systems were preliminary and
had not been finalized prior to
completing this report.
Only the costs for wet limestone FGD
systems are presented and discussed in
this summary. However, the analysis of
spray drying in the report points out the
major factors that affect the costs for
these systems.
The capital and annual first year
operating and maintenance (O&M)*
costs for FGD systems applied to new
industrial boilers are derived from the
cost data developed by Radian Corpora-
tion. These costs are for limestone FGD
systems, however, Radian found that
dual alkali and limestone FGD costs
were comparable (within 10 percent)for
the capacity range evaluated. These
cost data are part of the background
information document which was
developed to support new source
performance standards for industrial
boilers. Table 1 presents a complete
breakdown of the capital investment
costs (1980 dollars) for FGD systems
applied to new industrial boilers ranging
in capacity from 30 to 200 million Btu
per hour. Table 2 shows the first year
O&M costs for those same FGD systems
These costs are recommended for use in
the acid rain study.
TVA has performed a similar cost
analysis for limestone FGD systems
applied to new utility boilers Their
costing work is part of an on-going
Includes raw materials, labor, maintenance,
utilities, solid waste disposal (if applicable), and
overhead Does not include capital-related costs
such as depreciation, income taxes, interest, and
return-on equity
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Table 1. Industrial Boiler Limestone FGD System Capital Investment
Boiler Heat Input
Capacity, 706 Btu/hr
Direct Investment
Raw Materials Handling
SOz Scrubbing
Fans
Solids Separation
Utilities & Service
Total Direct Investment (TDI)
Indirect Investment
Engineering
Construction & Field Expense
Construction Fees
Start-up
Performance Test
Total Indirect Investment (Til)
Contingencies
Total Turnkey Investment (TTI)
Land
Working Capital
Total Cap. Investment (TCI}
1978$
TCI x 1.21 = 7350$
TCI (1980$) 103$/106 Btu/hr
Capital Investment*, 103 $
30
59
149
20
160
23
-477
98
41
41
8
4
-192
121
~724
0.6
52
777
940
31.3
75
99
244
40
189
34
~~665
98
61
61
12
6
238
169
1073
0.8
72
1.086
1,314
17.5
150
147
368
69
227
49
~860
98
86
86
17
9
296
231
1357
1
106
1.494
1,808
12.1
200
171
401
76
275
55
~sn
98
98
98
19
10
~32~3
260
T$6J
1
126
1.688
2.042
10.2
program to develop detailed and accu-
rate costs for utility-sized FGD systems.
Table 3 presents the capital investment
costs; Table 4 shows the first year
annual O&M costs. These costs are also
recommended for use in the acid ram
study.
The industrial and utility boiler FGD
system capital investments, shown in
Tables 1 and 3, respectively, should
exhibit some discontinuity in the
capacity transition from large industrial
boilers to small utility boilers due to:
1. Design scope
Utility Boiler
*Bases given in Tables 2.1.2-4 and 2.1.2-5 of full report.
Includes spare absorber
modules, stack gas reheat,
and on-site sludge
disposal pond
Industrial Boiler
Does not include spare
absorbers, stack gas
reheat, or an on-site
pond
2. Method of installation
Table 2. Industrial Boiler Limestone FGD System First Year Operating
and Maintenance Costs
Boiler Heat Input
Capacity. 106 Btu/hr
Direct Costs
Raw Material
Limestone
Conversion Costs
Operating Labor
Supervision
Utilities
Process Water
Power
Maintenance Labor & Materials
Solid Waste Disposal
TOTAL DIRECT COSTS
Indirect Costs
Payroll Overhead
Plant Overhead
G&A
TOTAL INDIRECT COSTS
Total First Year O&M, 1978$
1981 $ (1978$ x 1.285)
$/10* Btu{1978$)
$/10e Btu (1981$)
Annual
30
10
105
21
0.2
7
33
28
~2~04~
38
40
31
~JOS
313
402
1.99
2.56
O&M Cost,* 103
75
24
105
21
0.7
18
48
71
~~2~55
38
44
43
-J75
413
531
1.05
1.35
$/yr (1978$)
150
49
105
21
1
36
68
143
~32~3~
38
48
60
-TUB
569
731
0.72
0.33
200
65
105
21
2
42
78
190
~W5
38
50
68
~T56
659
847
0.63
0.81
Utility Boiler
Field-erection
Industrial Boiler
Shop-fabrication of
major components
. Indirect investment plus
other capital
requirements
Utility Boiler
a eases given in Tables 2.1.2-4, 2.1.2-5, and 2.1.3-3 of full report.
1.0 times direct
investment
Industrial Boiler
~0.75 times direct
investment
The analyses performed in this report
illustrate that the three items listed above
account for most of the discontinuity in
the capital investment costs.
As with the capital investment costs,
the industrial and utility boiler annual
O&M costs presented in Tables 2 and 4,
respectively, are also likely to exhibit
some discontinuity due to:
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Table 3. Utility Boiler Limestone FGD System Capital Investment (1980$)
Capital Investment* JO3 $
Utility Boiler Capacity M We
Boiler Heat Input* (106 Btu/hr)
Direct Investment
Raw Materials Handling
SOt Scrubbing
Waste Disposal
Total Direct Investment (TDI)
Indirect Investment (II)
Engr. Design & Supv. plus
Architectural & Engr. (A&E}
Construction Expenses
Contractor Fees
Contingency
Fixed Investment (TDI + II)
Other Capital Requirements
Start-up & Modifications
Interest During Construction
Land
Working Capital
Total Capital Investment fTCIf
$/kWe
103$/10* Btu/hr*
WO
1,OOO
1,738
9,399
5,073
16,149
1,453
2,584
807
4,199
25, 192
1,938
3,779
634
820
32.363
323.6
32.4
250
2,500
1,875
16,070
8,859
26,805
2,412
4,289
1.340
6.969
41.816
3.217
6,272
1.247
1.388
53.932
215.7
21.6
500
5,000
3,844
26.764
14,058
44,666
4.020
7,147
2,233
11,613
69,679
5,360
10.452
2,107
2,349
89.947
179.9
18.0
1,000
10,000
4,541
53,272
22.743
80,556
7.250
12,889
4.028
20.945
125.667
9.667
18,850
3.573
4,270
162,027
162.0
16.2
1. Design scope
Utility Boiler
Stack gas reheat steam
used; sludge disposed
of in pond on-site
Industrial Boiler
No stack gas reheat
steam used; sludge
disposed of by outside
contractor at $15/ton
2. Unit costs for raw materials, labor,
utilities, etc.
Utility Boiler
See Table 2.1.3-1 in
full report
Industrial Boiler
See Table 2.1.3-3 in
full report
3 Ppnantw ntili7atinn fa^trvr
"Bases given in Tables 2.1.2-1 and 2.1.2-2 of full report.
"Assumes 10,000 Btu/kWh.
CTCI = TDI + 11 + Other Capital Requirements.
Table 4. Utility Boiler Limestone FGD System First Year Operating
and Maintenance Costs (1981$)
Annual OSMCosf, JO3 $/yr
Boiler Capacity MWe
Boiler Heat Inpuf (10* Btu/hr)
Direct Costs
Raw Material
Limestone
Conversion Costs
Operating Labor & Supervision
Utilities
Process Water
Electricity
Steam
Maintenance Labor & Materials
Analyses
TOTAL DIRECT COSTS
Indirect Costs
Overheads
Plant & Administrative
Total First year O&M Costs0
Mil/s/kWh
$/10BBtu"
WO
1,000
174
172
3
264
166
1.109
52
1.940
800
2.740
5.79
0.58
250
2,500
436
260
9
604
414
1,785
52
' 3,560
1.258
4.818
4.07
0.41
500
5.000
872
356
18
1,201
829
2,970
78
6.324
2.042
8,366
3.53
0.35
1,000
10,000
1.744
486
38
2.343
1.657
5,428
104
1 1.800
3.611
15.411
3.26
0.33
a Bases given in Tables 2.1.2-1, 2.1.2-2, and 2.1.3-1 of full report.
b Assumes 10,000 Btu/kWh.
0 Direct plus indirect costs.
d Based on boiler heat input.
Utility Boiler
0~54
Industrial Boiler
060
In addition to these factors, O&M costs
that are estimated based on capital
investment (such as maintenance and
sometimes overhead) will be signifi-
cantly different for the two systems
because of factors which cause discon-
tinuities in the capital investment (see
previous discussion on capital invest-
ment). The analyses performed illus-
trate that the items identified above
account for most of the cost discon-
tinuity
The discontinuities are shown graph-
ically by plotting the data presented in
Tables 1 through 4. Figure 1 is a plot of
the capital investment costs and Figure
2 is a plot of the first year O&M costs.
Also shown on these graphs is a plot of
the normalized cost values which result
from elimination of the differences in
design scope, installation and indirect
investment algorithms, capacity utiliza-
tion factors, and unit costs mentioned
above The final normalized curves
eliminate most of the discontinuities in
both sets of data. The rationale for
developing the normalized curve is
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50-
§
So ro-
-
re i
S.
Normalized Capital
Investment Curve
Limestone FGD System
3.35-3.5% Sulfur Coal
90% S02 Removal
Utility FGD Systems
Capital Investment Costs
(Table 3)
Industrial FGD Systems
Capital Investment Costs
(Table 1)
Cost Data from Tables 1 and 3
Resulting curve when industrial and
utility cost are adjusted to same basis.
This includes:
(1) Design scope
(2) Indirect investment algorithms
(3) Method of installation
(shop-fabricated or field-erected}
10
50
100
500 1000
5000 10000
Boiler Heat Input, 106Btu/hr
i
5
i
10
50 100
For Utility Boilers, MWe
Boiler Capacity
500 1000
NOTE: Utility boiler FGD unit investment estimates are provided for boiler
capacities of 100-500 MWe and are expressed as dollars per 1O6 Btu/hr of capacity
assuming a plant heat rate of 10,000 Btu/kWh. Industrial boiler FGD system
estimates are also expressed as dollars per 106 Btu/hr of boiler capacity. The utility
and industrial boiler investment and capacity scales are interchangeable if the
same 10,000 Btu/kWh conversion factor is assumed. This is a close approximation
of the heat rate for most utility plants.
Figure 1. Capital investment for industrial and utility boiler wet limestone FGD
systems.
discussed in detail in Section 2 of the
full report
However, due to the environmental
regulations and economy of scale, the
design scope is likely to be considerably
different for industrial and utility boiler
FGD systems as discussed previously.
Many components of industrial boiler
FGD units are likely to be shop-
fabricated; whereas, utility systems are
field-erected. In addition, unit costs for
raw materials, utilities, and solid waste
disposal are likely to be considerably
different due to volume or quantity
considerations. Different capacity utili-
zation factors may also be expected
The factors affecting capital investment
and, therefore, certain O&M costs (such
as maintenance and overhead), are also
important. Therefore, discontinuities in
the capital investment and O&M curves
similar to those shown in Figures 1 and
2 should be expected.
In summary, the annual O&M and
capital investment cost estimates for
wet limestone FGD systems presented
in this study* should be considered as
valid consistent data Therefore, it is
recommended that the cost data shown
in Tables 1 through 4 be used in later
acid ram studies as the basis for
assessing cost impacts for FGD con-
trols.** Of course, adjustment to the
bases (such as design scope, start-up
date, and site-specific unit costs for raw
*For FGD systems applied to new industrial and
utility boilers
"Retrofit factors will have to be used to adjust
these costs to reflect the costs of applying FGD
systems to existing boilers
materials, utilities, etc.) may be required
by a particular reader. The data in this
report is documented so that these
adjustments can be made, if desired.
FGD System Retrofit Factor
Evaluation
A retrofit factor is defined as the ratio
of the capital investment or operating
cost for installing a process in an
existing plant to the capital investment
or operating cost for the same process in
a new installation. This factor is often
applied to new installation costs to
estimate the costs of putting the sqme
basic equipment into an existing facility.
Retrofit factors were only evaluated
for utility boilers because there was no
published information on retrofit factors
for industrial boilers. Therefore, there is
no retrofit factor recommendation for
industrial boiler FGD systems.
Capital Investment
Retrofit factor studies performed by
TVA, PEDCo Environmental, Inc., M.W.
Kellogg, and Radian Corporation were
examined. Retrofit factors ranging from
0 9 to 3.0 were found in these studies.
Space availability was identified as the
principal factor affecting the capital
investment associated with retrofitting
FGD systems.
For a preliminary evaluation, a retrofit
factor of 1 2 is recommended for
"average" retrofits for boilers less than
10 yearsold and with capacities greater
than 200 MW. A retrofit factor range of
1.1 to 1.4 is also recommended. The
lower end of the range is applicable
when installation of the FGD system is
relatively uninvolved and when avail-
able space for FGD equipment is
adequate. Retrofit factors in the upper
range nearer 1.4 would be used when
'retrofitting is complex
The retrofit factor 1.2 is recom-
mended for use in a preliminary evalua-
tion of FGDsystem retrofit costs for util-
ity boilers. The reader should note that:
(1) Retrofit of FGD systems to some
boilers will be infeasible.
(2) Retrofit factors greater than 1.4
are possible.
Only a site-specific evaluation of the
factors associated with retrofit can
accurately quantify the costs.
Annualized Costs
No retrofit factor for annualized costs
is recommended. Increased annualized
costs for retrofits compared to new
-------
5-
8 5
o (Q
<*
o
2
C
5-
Industrial FGD Systems
First year O&M Costs
(Table 2)
Cost Data from Tables 2 and 4
Resulting curve when industrial and
utility costs are adjusted to same basis.
This includes:
(1) Design scope
(2) Indirect investment algorithms
(3) Unit cost for labor and materials
(4) Capacity utilization factor
(5) Method of installation
(shop-fabrication or field-erected)
Normalized O&M
Cost Curve
Utility FGD Systems
First Year O&M Costs
(Table 4)
10
50 1000
Boiler Heat Input, 10eBtu/hr
5000 10000
1
10 50 100
For Utility Boilers MWe
500 1000
Boiler Capacity
NOTE: Utility boiler FGD unit annual O&M estimates are provided for boiler
capacities of 100 -500 MWe and are expressed as$/10eBtu assuming a plant heat
rate of 10,000 Btu/kWh. Industrial boiler FGD system estimates are provided for
boiler heat input capacities of 30-200 x 10s Btu/hr and are expressed as$/106 Btu.
The utility and industrial boiler capacity scales are interchangeable if the same
10,000 Btu/kWh conversion fact or is assumed. This is a close approximation of the
heat rate for most utility plants.
Figure 2. First year O&M costs for industrial and utility wet limestone FGD
systems.
systems are primarily associated with
the higher capital investment. There-
fore an annualized cost retrofit factor
would be a strong function of the capital
investment retrofit factor, the load
factor of the boiler, and the remaining
useful life of the boiler.
The results of the study show that
capital investment and O&M costs for a
lime wet scrubbing system prepared by
both organizations are very similar
when all bases (economical and tech-
nical) are made identical.
TVA and PEDCo Environ-
mental. Inc. FGD System
Cost Comparison
Both TVA and PEDCo have developed
cost estimating procedures for utility
boiler FGD systems. In the past,
estimates from the two organizations
have shown significant differences.
Cost estimates by TVA and PEDCo were
evaluated to determine whether the
differences are real or a function of such
factors as design scope, indirect invest-
ment algorithms, unit cost for raw
materials, utilities, and other economic
parameters.
USGPO:1982-659-095-567
-------
J. G. Ball and W. R. Menzies are with Radian Corporation, Austin, TX 78766.
P. P. Turner is the EPA Project Officer (see below).
The complete report consists of two volumes, entitled "Acid Rain Mitigation
Study:"
"Volume I. FGD Cost Estimates (Technical Report)," (Order No. PB 83-101
329; Cost: $16.00, subject to change)
"Volume II. FGD Cost Estimates (Appendices)," (Order No. PB 83-117 366;
Cost: $20.50, subject to change)
The above reports will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park. NC 27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
Postage and
Fees Paid
Environmental
Protection
Agency
EPA 335
Official Business
Penalty for Private Use $300
AGENCY
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