-------
4.2.3 Staged Combustion Air
Early testing of staged combustion air demonstrated its ability to
reduce NOX emissions by up to 50 percent.35 Tests conducted at the EPRI/B&W
6'x6' unit show that N0x emissions resulting from the use of staged air can
be reduced to 0.15 lb/106 Btu from 0.5 lb/106 Btu without staged air.42
The variable with the greatest impact on N0x emissions for staged
combustion air is the primary/stoichiometric air ratio, defined as the ratio
of air introduced through the distributor plate to the calculated
stoichiometric air. Figure 4.2-3 illustrates the effect of this air ratio
on N0x emissions from a Battelle test unit. Operation of an AFBC boiler
with primary/stoichiometric air ratios less than 1.0 results in the creation
of a reducing zone. This promotes the reduction of NO by char and carbon
monoxide.
As stated previously, a tradeoff exists between NO and S02 emissions
when the combustion air is staged for NOX control. (Refer to Section 4.3
for a discussion of this tradeoff.)
4.2.4 Staged Beds
Staged bed AFBC boilers are designed to achieve low NO emissions by
operating with the lower bed at substoichiometric conditions; the balance of
the air necessary for combustion is added in the second bed. The only
steady-state data available for this configuration are from the United Shoe
Manufacturing Corporation's (USMC) Wormser unit. Emissions of NO averaged
0.35 lb/10 Btu which is above the NOX emission level achievable by a
conventional bubbling bed AFBC without solids recycle.43 Short-term'testing
of a Wormser unit at Iowa Beef Processors in March, 1983 demonstrated NO
emissions generally between 0.25 and 0.55 lb/106 Btu, but operating
conditions were fluctuating.
4.2.5 Circulating Bed
Circulating bed AFBC boilers feature very extensive recirculation of
elutriated solids. In addition, staged combustion is often employed. Both
of these techniques have been previously described as being effective for
4-27
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400
0.2
0.4
o.a o.a 1.0
Primary Air / Stoicrlimometric Air
1.2
1.4
Figure 4.2-3.
on
4-28
-------
reducing N0x emissions. Figure 4.2-4 demonstrates the NO emissions from
the Battelle IxlO6 Btu/hr test unit with staged combustion air.20 The
lowest NOX emission level achieved, 0.15 1b/106 Btu, was with a
primary/stoichiometric air ratio of 0.5.
4.2.6 Demonstration of NO Reduction
Table 4.2-1 summarizes N0x emissions data for the newer AFBC design
configurations. For comparison with first generation AFBC boilers, the
Georgetown University unit averages about 0.50 lb/106 Btu.45 The effect of
solids recycle on NOX emissions for conventional bubbling beds is
illustrated by data from TVA's 20 MWe pilot plant. In addition, the table
shows that staged combustion air significantly decreased NO emissions at
B&W's 6'x6' test unit. The NOX emissions control achievable by circulating
bed AFBC boilers with staged combustion air is illustrated by data from the
Battelle MS-FBC process. The NOX emissions data from Wormser's staged bed
process are also presented.
Several points should be emphasized when examining the results in Table
4.2-1. First, long-term testing at conditions producing very low NO
emissions, especially substoichiometric firing, has not been conducted.
Also, issues concerning proper materials of construction in reducing regions
in the unit have not been resolved. Finally, the data presented for NO and
S02 emissions do not necessarily reflect emissions control that can be
obtained simultaneously. While the interactions between SO,, and NO
Cm A
emissions must be further defined to establish optimum performance, the
trends in Tables 4.1-1 and 4.2-1 illustrate that factors such as solids
recycle, staged beds, and circulating bed designs can be used to reduce both
S0? and NO emissions.
£ A
4.3 S02/NOX TRADEOFF
Most design and operating factors which affect both S02 and NO can be
set to simultaneously reduce N0x and S02 emissions. These factors include
bed temperature, gas residence time, and solids recycle. However, the
4-29
-------
Tl
H-
oq
rt
H-
00
ID
O.
n
NO Emissions, lb/10° Btu
p
b
•^
1
CO
o
(A 14
rt O
JUX
OQ
ID m
O (A
O M
9 H-
tr o
ia
rt rt
H- ID
o u
3 rt
(U r|
H- (D
•1 (A
c
t,,^
NJ rt
O W
^s
*T\
O
>~t
O
H-
n
a
2
i
T
M
5*
o
o"
5"
^
a
n.
n
>
•»
31
U
»«•
5"
a>
B (13 I374U
NOX Emissions, ng/J
-------
TABLE 4.2-1. SUMMARY OF NO EMISSIONS FOR VARIOUS AFBC CONFIGURATIONS
Configuration
Conventional Bubbling Bed
Staged Bed
Circulating Bed
Location
TV A 20 MWe (9)
TVA 20 MUe (9)
B&U 6'x6' (42)
United Shoe Manu-
facturing Corp. (43)
Battelle MS-FBC (20)
Heat Input Type of
106 Btu/hr Dataa
155 Cont IS
155 Cont 15
24
3
1
1
1
Test
Duration,
hrs
15
12
-
-
-
-
-
Priniary/Stoich.
Air Ratio
-
-
-
-
0.50
0.90
1.15
N0x Emissions
lb/106 Btu
0.34
0.23
0.15
0.35
0.15
0.20
0.33
Recycle Ratio
0
1-3
0
-
-
-
-
I
CO
^Continuous readings were taken every 15 minutes.
-------
primary operating conditions used to reduce N0x emissions, low excess air
and staged combustion air, involve a tradeoff with SCL emissions. Low
excess air and staged combustion air were shown in Figures 4.2-1 and 4.2-3,
respectively, to decrease N0x emissions. However, these NO emission
reduction methods were shown in Section 4.1.1 and Figures 4.1-5 and 4.1-6 to
increase S02 emissions. Staged combustion air test results, in which both
S02 and NOX emissions were measured, are presented in Figure 4.3-1.46 As
the primary air ratio was lowered from 1.04 to 0.87, NO emissions dropped
from 240 to 90 ppm, and S02 removal decreased from 95 to 90 percent. The
increase in S0? emissions is small compared to the reduction in NO
x
emissions and can be offset by increasing the Ca/S ratio and/or the solids
recycle ratio. It should be noted, however, that both of these methods
involve an increase in operating costs.
4.4 PARTICULATE MATTER EMISSION DATA
The following design factors were identified by the ITAR as being
important to the quantity of particulate matter (PM) emitted from an AFBC
boiler:
Coal
-ash content
-sulfur content
-agglomeration characteristics
Sorbent
-particle size
-attrition and decreoitation characteristics
4-32
-------
10
90
80
70
i eo
Ul
IT
50
40
30
20
KEY
& NO,
O S02
OPERATING CONDITIONS
BED TEMP 1470-1490'F
Ca/S RATIO 5
RECYCLE RATIO 0.50
%S IN COAL 0.71
SIZE . 52 x 106 BTU/HH
0 3C
0 85 0 90 0 95
1 05
250
225
200
175
Q.
O.
50 Q
o
25
00
1.10
PRIMARY AIR RATIO
70A3547
Figure 4.3-1. NOX/S02 Tradeoff for Staged Combustion Air.
4-33
-------
Operation
-superficial velocity
-primary recycle
-use of carbon burnup cell
-additives
Bed Geometry
-cross sectional area
-bed depth
-orientation of boiler tubes
-grid design
-freeboard
Cyclones followed by a fabric filter or an ESP have both been used for
PM collection. Fabric filters have been used more widely for commercial
applications instead of ESPs due to the low resistivity of ash produced by
AFBC boilers. PM collection efficiencies of 99.81 to 99.94 percent (<0.03
Ib/MM Btu) have been obtained at the TVA 20 MWe pilot plant with the use of
cyclones followed by fabric filters with a 1.48 air-to-cloth ratio.9 EPA
Method 5 testing for particulate emissions at Georgetown University resulted
in an average of 0.065 lb/10° Btu for the cyclone and baghouse PM collection
system. A PM collection efficiency of 99.7 percent (0.06 lb/106 Btu) was
obtained using cyclones followed by an ESP (effective collection area of
2
21,000 ft ) at a paper mill in Kauttua, Finland. A consistently high
combustion efficiency and low carbon content in the fly ash may have
contributed to the good ESP performance.47
4.5 OTHER FACTORS RELATED TO BOILER PERFORMANCE
As indicated in the ITAR and in the preceding discussions, considerable
research emphasis has been directed towards the environmental
characterization of FBC technology. Furthermore, significant development
work has been undertaken to improve the environmental performance of the
4-34
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technology. However, other technical issues which are important to the
development of AFBC boiler technology for industrial boiler use have
received recent attention. These include:
Boiler efficiency,
Solid waste impacts,
Fuel use flexibility,
Erosion/corrosion, and
Turndown characteristics.
These performance factors and their relation to recent improvements in FBC
technology are reviewed in this section.
4.5.1 Boiler Efficiency
Boiler efficiency is defined as the percentage of the total energy
(fuel) input that is available for the generation of steam. Conventional
coal-fired industrial boilers typically achieve boiler efficiencies ranging
from approximately 80 percent to 85 percent, depending on design
configuration and coal type. By comparison, recent demonstration plant
testing of state-of-the-art bubbling bed FBC technology has also shown
boiler efficiency values of 80 to 85 percent.9 The portion of the total
energy input that is not available for steam production consists of (1) flue
gas heat losses, (2) hot solids heat losses, (3) net calcination and
sulfation reaction heat losses, (4) unhurried carbon heat losses, and (5)
radiation and miscellaneous heat losses.
Flue gas heat losses (in the form of sensible heat and the latent heat
of water vaporization) represent the major heat loss from industrial
boilers, typically approximating 10 to 15 percent of the total fuel energy
input. Traditional and advanced FBC boiler designs tend to have lower flue
4-35
-------
gas heat losses than conventional coal-fired industrial boilers primarily
because of lower excess air rates. FBC technologies typically feature
excess air rates of about 20 percent compared to levels as high as 50
percent for industrial spreader stoker boilers.
Also, the lower excess air levels and increased heat transfer rates of
FBC designs due to turbulent and well-mixed combustion zones allow for more
compact boiler designs. It is expected that, as the technology matures,
shop-fabricated package FBC boilers will be commercially available in steam
generation capacities greater than those available for conventional
coal-fired package boilers (currently about 200 x 106 Btu/hr).
Heat losses due to hot solids generation (spent sorbent products and
bottom and fly ash) are typically somewhat greater for traditional and
advanced FBC configurations than for conventional coal-fired boilers. This
result is due to the presence of increased solids levels, i.e., in-situ
sorbent products, in FBC boilers. Development work aimed at minimization of
solids heat losses has focused on reduction of Ca/S ratio and heat recovery
from spent bed material.
Net heat losses (or gains) due to calcination and sulfation reactions
in the boiler are inherent to FBC operation. Calcination and sulfation
reactions are endothermic and exothermic, respectively, and their heat
effects are off-setting. Depending on the Ca/S ratio, sorbent utilization
rate, and S02 emission limits^ the net effect may be a heat loss or a heat
gain.
Unburned carbon heat losses are typically expressed in terms of
combustion efficiency. Development efforts have targeted combustion
efficiency levels at 95 to 99 percent for FBC boiler technology so that it
can compete with conventional coal combustion in this area, -irst
generation FBC boilers often failed to meet the tarceted ccrs^sticn
efficiency level, even with a carbon burn-up cell or solids recycle.
However, recent improvements in AFBC-with-recycle operation and development
of novel configurations, e.g., circulating fluidized beds, have enabled 95
to 99 percent combustion efficiency levels to be achieved.
4-36
-------
Radiation and miscellaneous boiler heat losses, typically a minor
component of the total heat losses, are not expected to differ significantly
for FBC as compared to conventional coal combustion technology. However,
FBC technology may have the potential for somewhat lower radiation losses
due to lower operating temperatures and more compact boiler designs.
4.5.2 Solid Waste Impacts
Solid waste from FBC boilers differs in composition from that produced
in conventional coal-fired boilers. FBC waste typically contains greater
amounts of carbon, calcium, and sulfur-bearing compounds. The amount of
solids from an FBC boiler is expected to equal or exceed those from a
conventional coal-fired boiler with FGD.37 The amount of solids generated
in an FBC boiler is a function of (1) unit size, or coal feed rate, (2) Ca/S
ratio, or sorbent feed rate, (3) coal and sorbent properties, (4) coal
combustion efficiency, (5) degree of sorbent utilization, (6) SCL and
particulate emission levels, and (7) unit configuration (e.g., AFBC or
PFBC).
Two options are available to the industrial AFBC boiler user with
respect to alleviating solid waste impacts. These options are to market the
solid waste as a useful by-product or to dispose of the waste in an
environmentally acceptable manner.
The marketing option is currently less feasible than the disposal
option for the potential industrial AFBC user. Potential markets for AFBC
solid waste appear to be competitive and limited (e.g., construction
materials market) or undefined (e.g., agricultural supplements market).
Unresolved questions remain regarding the technical feasibility and
environmental acceptability of converting FBC solid wastes into useful
resources. Applications that have received considerable research emphasis
include the use of FBC solid waste as construction material additives,
agricultural supplements, acidic waste treatment agents, and road base
material.48'49'50'51'52'53'54
Because of apparently limited market potential for FBC solid wastes,
most FBC waste generated in the near-term will have to be disposed of in a
4-37
-------
manner consistent with applicable regulations. It appears that the most
significant regulations regarding disposal, in terms of cost to the AFBC
boiler use are those associated with the Resource Conservation and Recovery
Act (RCRA).J/
Hazardous characteristics currently defined by RCRA provisions are
ignitability, corrosivity, reactivity, and toxicity. The only
characteristic that may be applicable to FBC waste appears to be toxicity;
however, laboratory studies have indicated that typical FBC wastes would not
be classified as hazardous according to toxicity characteristics.55'56 Of
course, toxicity characteristics of FBC waste (and, ultimately, RCRA
classification as hazardous or nonhazardous) are dependent on specific coal
and sorbent properties, so additional data are necessary to conclusively
evaluate the classification of AFBC solid waste.
Recent data suggest that FBC solid waste can satisfy the RCRA
requirements for sanitary landfill disposal, i.e., ground water at the
disposal site boundary should be able to satisfy the National Interim
Primary Drinking Water Regulations (NIPOWR).37 Nonetheless, potential
environmental problems of landfill ing remain, including (1) heat release
from the solid waste as CaO hydrates to Ca(OH)2 upon exposure to moisture,
and (2) leachate characteristics, especially excessive pH, total dissolved
solids (IDS) content, and sulfate content.47
Recent improvements in design configuration, including recycle and
circulating bed options, have served to lessen the amounts of solid waste
generated, primarily through the use of lower Ca/S ratios.
4.5.3 Fuel Use Flexibility
A significant advantage of F3C technology tna* has sourr-d ~t~
develcDTent is its ability to efficiency burr, a wide variety of f^s. A
given FBC boiler design will not necessarily burn any type of fuel;
nonetheless, a specific unit can handle considerably wider fluctuations in
fuel composition than a conventional combustion boiler. Recent design
developments, such as the circulating bed principle, have further enhanced
AFBC fuel flexibility.
4-38
-------
The focus of the discussions presented in the ITAR and in this document
has been on FBC firing of coal. However, FBC technology has been shown to
satisfactorily burn a wide variety of fuels, including coal processing
wastes, oil shale, petroleum coke, waste wood, municipal waste, dried sewage
sludge, and other agricultural and industrial wastes.31'57'58'59 Several
investigations of alternate fuel feasibility have been performed at the
pilot or demonstration scale, e.g., the Shamokin anthracite culm project.57
However, alternate or low-grade fuels have also been fired in commercial
installations (e.g., Conoco's South Texas circulating bed design firing coal
and petroleum coke and over 2000 AFBC units firing low-grade coals and
industrial wastes in the People's Republic of China.31'50
4.5.4 Erosion/Corrosion
A significant amount of research has been undertaken to identify the
erosion/corrosion parameters and the potential for various FBC design
configurations. Earlier theories maintaining that corrosion in traditional
bubbling beds would not be significant because of the low-temperature
operation of the combustion zone have been rejected. Recent research has
shown that sulfidation/oxidation of metallic components does occur in FBC
bubbling beds, and that selection of tube material is critical in control of
these corrosion mechanisms. AFBC units which operate under
substoichiometric conditions to reduce NO formations also have potential
J\
corrosion problems due to the reducing environment.
The potential for erosion of boiler internals is enhanced by
circulating fluidized bed technology, due to impingement of high-velocity
particles on interior boiler surfaces. However, the potential for tube
corrosion is reduced because heat transfer surface is less likely to be
48
located in a reducing zone. Conversely, staged air and staged bed
configurations, by the nature of their design and operation, include
reducing zones in their combustion regions. This feature enhances the
possibility of metal corrosion; as result, heat transfer surface is either
excluded from these zones or is made of an appropriate alloy metal.
4-39
-------
Erosion/corrosion issues have been a major impediment in the commerical
development of PFBC technology. Significant research activity has been
undertaken to resolve problems associated with corrosion and erosion of
components of gas turbines powered by PFBC exhaust gases.62'63 Continuing
activity in this area is necessary to bring PFBC technology closer to
commercialization.
4.5.5 Turndown
A major technical problem associated with first generation traditional
AFBC designs was load turndown. The following methods were initially used
to control the amount of heat transferred to the boiler tubes: (1) bed
segment slumping, (2) temperature variation, and (3) bed height variation.
Problems were encountered with these methods, including failure to
refluidize slumped portions of the bed, compromise of S02 reduction
performance due to temperature swings, and difficulty in controlling bed
height to the desired level. Early target turndown levels for industrial
AFBC boilers approximated a ratio of 4:1. Newer design configurations have
incorporated improvements with regard to load turndown. The implementation
of solids recycle has provided more flexibility in load control for bubbling
bed designs. The recycle solids flow rate provides an additional parameter
that can be varied to effect changes in heat transfer rate. Similarly, the
circulating bed designs feature load control by variation of the solids
recirculation rate. Finally, the separation of combustion and
desulfurization reactions in the staged bed designs permits greater
flexibility with regard to load control. These features have allowed the
current turndown ratio of 4:1 to be achieved. However, it should be noted
that turndown is very complicated and can significant iy effect er-'ssicrs 3rd
overall AFBC performance.
4-40
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4.5 REFERENCES
1. Young, C.W., et al. Technology Assessment Report for Industrial Boiler
Applications: Fluidized-Bed Combustion. United States Environmental
Protection Agency Report No. EPA-6QO/7-79-178e. November 1979.
2. Munzner, H., and B. Bonn. Sulfur Capturing Effectlvlty of Limestones
and Dolomites in Fluidized Bed Combustion. Proceedings of the Sixth
International Conference on Fluidized Bed Combustion.
Bergbau-Farschung GmbH. Volume III, pp. 997-1003. August 1980.
3. O'Neill, E.P., et al. Criteria for the Selection of S00 Sorbents for
Atmospheric Pressure Fluidized-Bed CombustoTEVolume I.Westinghouse
Electric Corporation. December 1979.
4. Robinson, J.M., et al. Environmental Aspects of Fluidized-Bed
Combustion. U.S. Environmental Protection Agency Report No
EPA-600/S7-81-075. August 1981.
5. Goblirsch, G.M., S.A. Benson, D.R. Hajicek, and J.L. Cooper. Sulfur
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Testing.Proceedings of the Seventh International Conference on
Fluidized Bed Combustion. Grand Forks Energy Technology Center/
Combustion Power Company, Inc. Volume II, pp. 1107-1120. October
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of the Seventh International Conference on Fluidized Bed Combustion.
Babcock & Wilcox Co./Electric Power Research Institute. Volume I
pp. 373-380. October 1982.
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9. Castleman, J.M., et al. Campaign I Report: Technical Summary of
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Demonstrations and Technology Division. Volume I. May 1983.
4-41
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10. Tatebayashi, J., et al. Simultaneous NO and S00 Emission Reduction
rnn+a^:1Zed^ed^CQmuUn .,I' J^Q^Hqs of trie Sixth International
Conference on Muidized Bed Combustion. Kawasaki Heavy Industries
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11. Chiplunker D.G., et al. Performance of a Fluidized Bed Steam
Generator Burning Anthracite Lulm. Proceeding nf I-KO ^,*n+*
International Lonrerence on Fluidized Bed Combustion. Dorr-Oliver
Incorporated. Volume 1, pp. 567-572. October 1982.
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Emissions by Battelle's Multisolid Huidlzed-Bed Combustion Pr
• - "j- - _ _ _ ^'fa**^t^^^* OwiiiuUj u I UN i r UV.C w j
rnmh e..igs °! ^e Sixtn international conference on Huidized Bed ''
Combustion. Battelle Columbus Laboratories. Volume III, pp. 979-984
Mpn i iyou.
13. Abel, W.T., et al. Combustion of Western Coal in a Fluidized Bed
Proceedings of the Sixth International Conference on Fluidized Bed
Combustion. Volume III, pp. 840-849. April 1980.
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Package F8C Boilers. Proceedings of the Seventh International
Conference on Fluidized Bed Combustion. Johnston Boiler Company
Volume I, pp. 26-37. October 1982.
15. Lutes, I.G., and F.C. Wachtler. An Anthracite Culm Fired Fluidized Bed
Steam Generator for the City of Wi Ikes-Barre, Pennsylvania ~
Proceedings of tne Sixth International Conference on Fluidized Bed
Combustion. Foster Wheeler Boiler Corporation. Volume II
pp. 405-418. April 1980.
16' oeSS1'9:-W'S" et a1' Fl'nes Recycle in a Fluidized Bed Coal Combustor
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the ANL Hydratlon Process to Enhance the Calcium Utili/atinn nf "hra*
Lowellviile Limestone Sorbent Product Streams Upon 3einc Recycled Bark
Through the Babccck & Wilcox AF3C. Araonne National i aSnr-3r,-ry v3y
1982.
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States Department of Energy Report No. DOE/ET/15460-193. May 1981.
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4-42
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20. Kim, B.C., et al. Multiple Fuel Emissions Control. Proceedings of the
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Dolomite in the Fluidized-Bed Combustion of CoalTArgonne National
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4-43
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30. Sadowski, R.S., et al. Operating Experience with a Coal-Fired Two
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ot the Air Pollution Control Association. Wormser Engineering, Inc.
June lyoj.
31. Jones, 0. and E.G. Seber. Initial Operating Experience at Conoco's
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Seventh international Conference on Fluidized Bed Combustion. Conoco
Inc. Volume I, pp. 381-389. October 1982.
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and Destruction in Fluidized Combustion of Coal Presented at thP
Engineering houndation Conference on Fluidization. Massachusetts
Institute of Technology. April 1978.
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Prepared by the Fluidized combustion Control Group for the United
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PB-210-673. p. 137. September 1971.
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2, p. 73. November 15, 1969 to November 15, 1971.
36. Hirame, T., et al. "An Experimental Study for Low-NO Fluidized-3ed
Coal Combustor Development." 1. Combustion under SuBstoichiometric
Conditions. ES&T. Vol. 14, No. 8. pp. 955-960. August 1980.
37. Hubble, B.R. Fluidized-Bed Combustion: A Review of Environmental
AsPects- Argonne National Laboratory Report No. ANL/ECT-12. January
1982.
38. Furasawa, F., D. Kunii, A. Oguma, and N. Yamada. Rate of Nitric Oxide
bV Char- Proceedings: Society of Chemical Engineer?! Japan.—Vol—6~
pp. 562-566. 1978.
vn ] ' ''• ^'' ' :
-------
41. Beer, J.M., A.F. Sarofin, P.K. Sharma, T.Z. Chaung, and S.S. Sandhu.
Fluidized Coal Combustion: The Effect of Sorbent and Coal Feed Particle
Size Upon the Combustion Efficiency of NO Emission.
42. McGowin, C.R., C. Aulisio, S. Ehrlich. Technical and Economic Aspects
of a Lignite-Fired AFBC Boiler. Presentation at the Eleventh Biennial
Lignite Symposium. San Antonio, Texas. June 1981.
43. Morgantown Energy Technology Center. Topical Report: Atmospheric
Fluidized-Bed Projects Technology Overview. United States Department
of Energy Report No. DOE/METC/SP-191.April 1982.
44. Sadowski, R.S., and P.P. Fennelly. Operating Experience with a Coal-
Fired Two Stage FBC in an Industrial Plant. Presented at the 76th
Annual Meeting of the Air Pollution Control Association. Atlanta.
June 1983.
45. Fennelly, P.P., et al. Long-Term Emission Monitoring at Georgetown
University Fluidized-Bed Boiler.Proceedings of the Seventh
International Conference on Fluidized Bed Combustion. Volume 1,
pp. 506-513. October 1982.
46. Terada, H., et al. Current Topics on Testing of the 20 t/h Fluidized
Bed Boiler. Proceedings of the Seventh International Conference on
Fluidized Bed Combustion. Volume II, pp. 876-885. October 1982.
47. Engstrom, F. and H.H. Yip. Operating Experience at Commercial Scale
Pyroflow Circulating Fluidized Bed Combustion Boilers.Proceedings of
the Seventh International Conference on Fluidized Bed Combustion.
A. Ahlstrom Company/Pyropower Corporation. Volume II, pp. 1136-1143.
October 1982.
48. Owen, M.L., J.R. Blacksmith, and G.M. Blythe. Evaluation of
Atmospheric Pluidized Bed Combustion. Radian Corporation. October
1981.
49. Sun, C.C., et al. Disposal of Solid Residue from Fluidized-Bed
Combustion: Engineering and Laboratory Studies. Westinghouse Research
and Development Center. March 1978.
50, Keairs, D.L., et al. Fluid-Bed Combustion and Gasification Solids
Disposal. Proceedings of the ASCE/PRC-EPR! Workshop on Solid Waste
Research and Development Needs for Emerging Coal Technologies.
pp. 92-115. April 1979.
51.
Stone, . R. , et
Fluidized-Bed
June 1978.
al.
Fuel
Environmental
Processing.
Assessment
Ral
ph Stone
of
lo.
Solid
, Inc.
Residues
Final
from
Report
4-45
-------
52. Minnick, L.J., et al. Utilization of the By-Products from Fluidiz»d
Bed Combustion Systems. Proceedings of thp Siyth 1*+*™* + !^ - —
Conrerence on Fluidized Bed Combustion. Volume III, pp. 913-924.
Ap n l l you *
53. Bennett, O.L. An Evaluation of Fluidized Bed Combustion (FBC) Waste
for Agncu1turaTpurposes_. Semi -Annual Progrocc o*?n*.+ f,r jarmr..
June 1978. U.S. Department of Agriculture. July 1978.
54. Stout, W.L., et al . Fluidized-Bed Combustion Waste in Food Production
Proceedings of the ASCE/PRC-EPRI Workshop on Solid Waste Research and
Development Needs for Emerging Coal Technologies. U.S. Department of
Agriculture, pp. 170-184. April 1979.
55. Sun, C.C., et al . Impact of the Resource Conservation and Recovery Act
on FBC Residue Disposal. westinghouse Research and Development Center.
U.b. Environmental Protection Agency Report No. EPA-600/7-79-178c
November 1979.
56. Radian Corporation and Combustion Power Company, Inc. Testing and
Evaluation of Fluidized Bed Combustion of Texas Lignite" — Final Report
to Texas Energy and National Resources Advisory Council Proiect
#80-1-7-10. June 1982.
57. Richards, H.W., et al. Operating and Maintenance Experiences at the
Shamokin Culm Burning Boiler Plant. Proceedings of the Seventh -
Internationa] Conference on Fluidized Bed Combustion. Volume I
pp. 133-138, October 1982.
58. Terada, H., et al. Utilization of Sedimented Coal Sludge in Fluidized
Bed Boiler. Proceedings of the Seventh International Conference on
Fluidized Bed Combustion. Volume II, pp. 840-846. October 1982.
59. Rasmussen, G.P., and J.N. McFee. Fluidized Bed Systems for Steam
Generation from Scrap Tires. Proceedings of the Seventh International
Conference on Fluidized Bed Combustion, Volume II, no 870-874
October 1982.
60. Schwieger, B. "Fluidized-Bed Boilers Keep Chinese Industry Runninc on
Marginal Fuels." ?cvver, pp. 59-51, March 1933. " '"
61. Stringer, J., et al. In-3ed Corrosion of Alloys in Atmospheric
Fluidized Bed Combustors. Proceedings of the Sixth International
Conference on Fluidized Bed Combustion, Volume II, pp. 433-446. April
1980 .
4-46
-------
62. Alvin, M.A. and R.A. Wenglarz. An Assessment of Corrosion/Deposition
Potential for PFBC Power Plant Turbines.Proceedings of the Seventh
International Conference on Fluidized Bed Combustion Volume II
pp. 957-957. October 1982.
63. Suter, P. and O.K. Mukherjee. Particle Distribution and Expected
Erosion Rate in a Gas Turbine Driven by Pressurized Fluidized Bed Flue
Gas.Proceedings of the Seventh International Conference on Fluidized
Bed Combustion, Volume II, pp. 968-980. October 1982.
4-47
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SECTION 5
FBC COST ALGORITHM DEVELOPMENT
Cost algorithms are used in this study to estimate capital and
operating costs for FBC systems, as well as conventional boilers, over a
wide range of system sizes and operating conditions. An algorithm is a
mathematical expression which relates costs to key design and operating
parameters (e.g., boiler size, coal properties, raw material costs). One
advantage to the use of algorithms is that they can be loaded onto a
computer to allow efficient cost estimating for a large number of cases.
Cost algorithms have already been developed for both conventional
boilers and FGD systems and are well documented in other reports.1'2 A
major objective of this study has been to develop a workable, up-to-date,
and valid cost algorithm for industrial-size FBC systems. The development
of the FBC algorithm is described in this chapter as well as validation of
the algorithm with vendor-developed cost estimates.
5.1 BASIS OF DESIGN
The discussion in Sections 3 and 4 makes the point that three major FBC
boiler design types are being offered on a commercial basis to buyers in the
industrial boiler market: conventional "bubbling" FBC boilers, circulating
FBC boilers, and two-stage FBC boilers. Pressurized FBC technology is in a
relatively early stage of development and is more suitable for utility
applications than industrial steam generation. Although the circulating and
two-stage FBC boiler designs are making significant inroads in the
industrial sector, the information in Tables 3.2-6 to 3.2-8 indicates that
the majority of existing and planned FBC units are of the conventional
bubbling bed design. Given the conservative nature of the industrial boiler
market and the fact that circulating and two-stage FBC boilers are in an
earlier commercialization stage than conventional FBC boilers, it is likely
that a great majority of the industrial FBC systems installed over the next
five years will be atmospheric, conventional FBC units. Accordingly, the
5-1
-------
conventional AF3C boiler design has been chosen as the basis of the FBC
algorithm.
It is of interest to note, however, that the limited amount of cost
data available comparing atmospheric, circulating FBC to conventional FBC
indicate that CFBC capital costs are similar to those of conventional FBC
systems, while operating costs for CFBC are estimated to be slightly less.10
A 1979 cost comparison of both systems in an industrial setting (meeting a
1.8 Ib S02/10 Btu limit) found both the capital and operating costs of the
systems to be within the accuracy range (± 25 percent) of the study.
5.1.1 Comparison of Design Bases
One of the most extensive set of analyses currently available which
relates FBC design and operating factors to S02> N0x, and PM emissions is
contained in the FBC ITAR. Much of that discussion has been summarized in
Sections 3 and 4 of this report. The ITAR analyses assumes that the "best
system" of S02 emissions reduction is one which minimizes sorbent feed rates
and stm attains high levels of emissions control. The experimental
results and theoretical considerations discussed in the ITAR indicate that
"small particle sizes (in the range, of 500 urn) and sufficiently long gas
phase residence time (0.67 sec.) are representative conditions for effective
S02 control, although most FBC facilities currently are designed or operated
with shorter residence times and coarser particles."3 The conditions
specified in the ITAR for this "best system" of S02 control are listed in
the first column of Table 5.1-1.
Because of the depth of analyses and consideration of emission and cost
impacts which support this design basis, this basis been used for the
purposes of algorithm development. A more pragmatic consideration is :*at
an existing FBC cost algorithm has already beon d°v?lo53't "" i!~a ^sc-rt ~r
this "best system" design. Thus only a review of the existing algorithm,
and possibly minor modifications, are to provide a suitable algorithm for
the purposes of this report.
The ITAR "best system" design basis was formulated from information and
data available in the 1978-1979 time frame. Before accepting this design
5-2
-------
TABLE 5.1-1. AFBC DESIGN/OPERATING CONDITIONS FOR THE
ITAR MODEL PLANT AND THE TVA AND GU FACILITIES
Design Basis Variables
Bed Dept, ft
Superficial Gas Vel . , ft/sec
Residence Time, sec
In-Bed Sorbent Part. Size, urn
Coal/Sorbent Feed System
Solids Recycle Ratio
Bed Temperature, °F
Excess Air, percent
Boiler Efficiency, percent
Algorithm Input Variables
Sorbent Reactivity
SO- Removal , percent
Ca/S Ratio
Coal Type
Coal Sulfur, percent
Coal Heating Value, Btu/lb
Heat Input, 10 Btu/hr
ITAR3
"Best System"
4
6
0.67
600 - 700°
Inbed/Overbed
0.2 - 0.4
1,550
20
79 - 85
Medium
90
3.3
Eastern
Bituminous
3.5
11,800
30 - 200
TVAb
Campaign I
3.75
9
0.42
l,086e
Inbed
0 - 1.5
1,530
22
75 - 85
Medium
87 - 989
3.0
Eastern
Bituminous
4.2
^12,000
vL65
GUC
1982 Tests
4.5
8
0.56
2:1,000
Overbed
2.2
1,590
20
^80
Low
80 - 95
3-7
Eastern
Bituminous
1.7 - 3.5
+12,000
M20
Source: Reference 3.
Source: Reference 5.
"Source: References 3 and 4.
600 to 700 urn mass mean particle size is equivalent to 500 ym surface mean
particle size.
"Geometric mass mean particle size of bed drain material
c
Estimate based on actual PM emissions and assumed cyclone efficiency of
90 percent.
^Higher freeboard may have contributed to higher S02 removal values.
5-3
-------
basis as representative of currently available technology, it is useful to
compare it with the design bases of existing operating systems. Two such
systems are the TVA 20 MWfi AFBC pilot plant and the Georgetown University
(GU) FBC industrial boiler. These plants are generally representative of
AFBC systems being offered commercially to industrial plant owners.
The second column in Table 5.1-1 lists the conditions of the TVA pilot
plant during Campaign I testing. The final column summarizes the operating
conditions for the GU boiler which are representative of the conditions in
effect during the January/February 1982 emissions test series sponsored by
EPA.
The table shows that the design bases for these large, operating
systems are comparable to the "best system" conditions of the ITAR, upon
which the ITAR cost estimates, and ultimately, the FBC cost algorithm, are
based. This comparison demonstrates that the design/operating conditions
for industrial FBC units installed today, or in the next five years, will
not be fundamentally different from the ITAR design basis. The fact that
the gas residence time for the ITAR system is less than that for industrial
installations suggests that ITAR estimates of boiler costs may be slightly
higher than those for operating units.
5.1.2 Selection of Ca/S Ratios
One of the most important of the Table 5.1-1 parameters from the
standpoint of SO,, control is the Ca/S ratio. The data and discussion of
Sections 3 and 4 .and the FBC ITAR show that, for a given target S0? removal
level, the Ca/S ratio in a conventional AFBC unit is primarily a function
coal type, bed temperature, recycle ratio, sorbent reactivity, sorbent
particle size, and gas residence time in the fluidized bed. The Ca/S ^atics
specified in the ITAR are based on excerirnental data collected on be^ch- 3"d
pilot-scale units operating over a wide range of conditions. The Ca/S
ratios plotted in Figure 5.1-1 correspond to these data plus "best system"
design/operating conditions. Also plotted on the same figure are
performance data from the Georgetown University, B & W 5'x6', and TVA
facilities. These units have been selected for comparison because they are
5-4
-------
ui
i
01
4.0
3.5
3.0
2.5
2.0
1.5
{J li 6. W
Q B 6 W
A IV*
A 'IV A
ITAR Model
Recycle Ratio
0
1-3
0
1-3
Model 0.8-1.3
0.2-0.4
D
a
a
a
Conaervatlve Weetinghouue
Projection
Data Range | -^
Optlnlutic Westlnghouse
Projection
1.0
50
55
60
65
70
75
BO
95
100
SO. Removal (Percentage)
i,uri' 5.1-1. Ca/S versus SO Kuuoval For Industrial AFBC Facllltleu Operating on Hlgli Sulfur Eastern Coal.
-------
of a scale similar to commercial industrial FBC systems of conventional bed
design.
The ITAR estimate in this figure corresponds to a sorbent with medium
reactivity and 500 um surface mean particle size. The figure shows that the
ITAR estimate agrees reasonably well with other performance data for eastern
bituminous coal. An important limitation of the ITAR estimation procedure
for Ca/S ratios, however, is that it does not take into account the impact
of alkali species (e.g., CaO, MgO, Na20, K.,0) present in some coal ashes,
notably subbituminous coals and lignites. Under FBC conditions, as much as
50 percent of the coal sulfur can be captured by subbituminous coal ash.
This effect significantly reduces the required Ca/S ratios for these coals.
While this effect is not marked for eastern bituminous coals, which are the
subject of Figure 5.1-1, for western subbituminous coals the ITAR Ca/S
ratios are over 70 percent greater than reported values.6
Since the FBC cost algorithm is intended fo use with bituminous and
subbituminous coals, it is desirable to include a Ca/S estimated methodology
that will adequately account for ash alkalinity. Fortunately, such a
methodology exists in the form of semi empirical Ca/S projections from a
model developed by the Westinghouse Research and Development Center.7 The
model takes into account the chemistry and physics of the calcium-sulfur
interactions in the FBC bed (viz., release of coal sulfur primarily as S02
and reaction with calcined sorbent to form CaS04). The model incorporates
the following basic assumptions:
• Release of sulfur from coal as S02 due to char and volatile
combustion occurs uniformly throughout the combustor bed of AFBC
units;
t The rate-limiting process for S02 capture in the bed is governed
by diffusion within the sorbent particle itself; and
5-6
-------
• Sorbent reactivity is a function of the bed calcining conditions
and the degree of sulfation and is not independently affected by
the residence time of sorbent particles in the bed.
The model also takes into account factors such as coal-ash alkali sulfur
capture, the volume fraction of bed bubbles, bed voidage in the emulsion
phase, the fraction of emulsion volume occupied by inerts, and the fraction
of bed volume occupied by heat transfer surface. A complete description of
the model is contained in Appendix C of Reference 7.
A summary table of Westinghouse model Ca/S projections as a function of
S02 removal requirements and coal types is presented in Table 5.1-2. It
should be noted that the specifications for the coal types in this table are
the same as those used in the FBC-ITAR and this report. In addition, the
Ca/S projections are based on an AFBC unit operating at 1550°F bed
temperature, 4 feet bed depth, 6 feet/second superficial gas velocity, and
0.67 seconds residence time -- the same conditions as the ITAR "best system"
design.
The Westinghouse projections are plotted in Figure 5.1-1 with the
labels "optimistic" and "conservative" added to represent high
reactivity/500 ym sorbent and average reactivity/1,000 um sorbent,
respectively. (For S02 removal efficiencies outside the range of Table
5.1-2, extrapolations were made using a power curve.) Sorbent reactivity is
an intrinsic property of each stone and cannot, for practical purposes, be
controlled. Low reactivity sorbents are not considered in this study
because the high limestone feed rates and solid waste generation rates
associated with their use make this option economically infeasible.
In-bed sorbent particle size is partly dependent on intrinsic stone
properties such as feed particle size distribution and particle strength
(i.e., resistance to attrition). In-bed particle size is also a function of
solids residence time which in turn is determined by sorbent feed rate, bed
volume, and recycle ratio. Thus the optimistic Ca/S projections identified
above correspond to an FBC boiler feeding high reactivity limestone and
operating with a longer solids residence time and/or a low-strength stone.
5-7
-------
TABLE 5.1-2. WESTINGHOUSE PROJECTIONS FOR REQUIRED Ca/S RATIOS'
Sorbent Reactivity Category
High
Medium
Average Bed Particle Diameter
(Surface Mean), urn
500
1000
500
1000
SO,, Emission Control Standard:
(Percent Sulfur Removal)
Bituminous High-Sulfur Coal
(3.5 wt. Percent S)
Stringent
(90)
Intermediate
Moderate
(78
•
(85)
7)
2.
2.
2.
8
5
1
3.
2.
2.
5
9
5
3
2
2
Bituminous Low-Sul
(0.9 wt.
Stringent
Moderate
Stringent
Moderate
& Intermediate (84.7)
(75)
& Intermediate (84.0)
(75
\
2.
1.
1.
0.
4
9
1
7
2.
2.
Western
(0.6
1.
0.
3
3
Subbi
wt.
3
9
.4
.9
.5
fur Coal
4.
3.
3.
3
7
1
Percent S)
2
2
.9
.3
3.
2.
6
9
tuminous Coal
Percent S)
1
1
.3"
.0
1.
1.
7
2
Source: Reference 7.
5-8
-------
The conservative Ca/S projections correspond to average reactivity
limestone, a shorter residence time, and/or high-strength stone. Since
these conditions effectively cover the range of expected FBC boiler
conditions, the actual rates for a given site should fall somewhere in
between.
The data and information shown in Figure 5.1-2 demonstrate that the
optimistic and conservative Westinghouse projections for Ca/S (as a function
of S02 removal) form an envelope which contains most of the individual
performance data points for industrial-scale AFBC units of conventional bed
design. This agreement lends support to the use of the Westinghouse model
Ca/S projections to estimate limestone requirements for model FBC boilers.
It should be noted that the outstanding SCL removal performance of the
TVA 20 MWg pilot plant operating with solids recycle may be aided by the
higher freeboard of this unit. Freeboard height at the TVA unit is over 20
feet compared to near 10 feet for a typical industrial fluidized bed boiler.
The higher freeboard allows more time for S02 capture by entrained sorbent,
effectively increasing the in-bed gas residence time. Adjustment for this
difference would tend to bring the TVA data within the Westinghouse envelope
and closer to the optimistic projection. However, at this time, the impact
of freeboard height on S02 removal is not defined well enough to make a
quantitative adjustment.
The high Ca/S ratios observed in the Georgetown University tests may be
explained in part by the low sorbent reactivity. More likely, these high
Ca/S ratios reflect the design flaws and operational practices (e.g., the
fluidized bed level was controlled by limestone addition) of a
Q
first-generation unit. This unit is included for comparison, however,
because it is one of the few commercial industrial FBC systems for which
data are available.
In view of the fact that the Westinghouse model for Ca/S projections is
a rigorous model which (1) adequately accounts for sulfur capture by
coal-ash alkali species and (2) is in reasonable agreement with performance
data from large operating systems, it is entirely appropriate to utilize the
model results for purposes of cost algorithm development. The Westinghouse
5-9
-------
model is the best instrument currently available for projecting required
Ca/S ratios as a function of S02 removal efficiency over the studied range
of coal types and industrial F3C boiler operating conditions.
5.2 ALGORITHM DEVELOPMENT
The cost data in the FBC ITAR were based on a combination of FBC boiler
vendor cost estimates, estimates developed by GCA for the limestone and
spent solids handling and storage areas (based on vendor-supplied cost
data), and guidelines developed by PEDCo for conventional boilers.8 These
data were used to develop capital and operating cost estimates for
industrial AFBC boilers ranging in size from 30 to 200 million Btu/hr and
feeding coals ranging from low sulfur western subbituminous to high sulfur
eastern bituminous. It should be noted that Westinghouse has also developed
cost estimates for FBC boilers, based in part on their Ca/S projection
model. However, the cost sources for these estimates are Westinghouse
in-house cost files (for the boiler and solids handling equipment) and
literature references. The ITAR cost estimates are considered superior for
the purposes of this study because (1) the boiler cost estimates were
provided directly by commercial FBC vendors, and (2) data in the
Westinghouse in-house cost files are not easily verified or referenceable.
However, combining the ITAR cost data base with the Westinghouse model Ca/S
projections takes advantage of the strengths of both data sets and provide
the best basis currently available for developing FBC cost algorithms.
Details of the development history and modifications to the FBC cost
algorithms are contained in Appendix A. The final form of the algorithm, as
used in this report, is presented in Table A-l. Algorithm ter^s a^d units
are explained in Table A-2.
The battery limits of the plant for which the algorithm applies are
from, but not including, the coal receiving equipment and to, and including,
the stack and onsite spent solids storage (on a temporary basis) equipment.
It is assumed that spent solids are hauled by truck to an offsite landfill;
the cost of this haulage is reflected in the solid waste disposal fee. A
5-10
-------
boiler feedwater treatment facility is included in the costs but steam
piping to and from the process area is not. Battery limits include a
primary cyclone for solids recycle but not a final particulate control
device. No provisions are included for control of NO emissions below those
X
levels characteristic of conventional AFBC technology.
The algorithm applies to coals ranging from high sulfur eastern
bituminous to low sulfur western subbituminous (lignites are not included).
Other applicable limits are:
• Boiler size: 30 - 400 million 106 Btu/hr heat input capacity
• Coal sulfur content: 0.6 - 3.5 wt. percent, as received basis
• Coal heating value: 9,600 - 13,800 Btu/lb, as received basis
• Coal ash content: 5.40 - 10.58 wt. percent, as received basis
• Coal moisture content: 2.83 - 20.8 wt. percent
• SO- removal efficiency: 56 - 90 percent
• Ca/S ratio: 0.8 - 4.2
Extrapolations outside these ranges should be made with caution; the results
will have greater uncertainty than results within the indicated limits. It
should be noted that these ranges apply only to the developed FBC cost
algorithm. Although they represent typical conditions for industrial FBC
boiler applications, they in no way stand for 1 : m'tations to those
applications.
5-11
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5.3 COST COMPARISONS AMONG INDEPENDENT ESTIMATES
The performance data and results of Sections 3.0 and 4.0 indicate that
the FBC cost algorithms and cost estimates of Section 6.0 are based on a
realistic system design. To further test the validity of the FBC cost
projections, it is desirable to compare them with independent estimates
developed by other workers. In this section, the capital and annual cost
estimates derived from the FBC algorithm are compared with independent
estimates developed in the last few years by Combustion Engineering, Inc.
(CE) , Foster Wheeler Development Corporation (FW)13, Westinghouse Research
and Development Center (W)14, and Pope, Evans and Robbins, Inc. (PER)15, as
reported in literature sources. In addition, capital and operating costs
for an installed and operating coal-fired FBC unit were provided by Johnston
Boiler Company (JB). With the exception of W, these companies currently
offer commercial industrial-size FBC boilers.
Most of the vendor estimates identified above were developed for large
capacity (greater than 200 million Btu/hr) boilers operating on high sulfur
eastern coal in an industrial setting. In most instances, S02 emissions are
controlled to a level of approximately 1.2 lb/106 Btu and PM emissions are
controlled to near 0.05 lb/106 Btu. This set of conditions corresponds
closely to the FBC boiler design case of 30 percent S02 removal on a Type H
coal, as identified in Table 6.2-2. The exceptions to this rule are the JB
costs which represent a 50 million Btu/hr boiler controlling S02 emissions
to a 2.6 Ib/million Btu limit,
The capital and operating costs developed by CE, PA, w, PER, and J8
have been adjusted to achieve a consistent basis with the FBC algorithm
objections ss that valid corparisons car. be ~ade. ~-e retails Df these
2-jus.., en ..s r.ava oeen Su~~ar:icd in Appendix C. After aajustmencs, tne
resulting capital and annual costs have been normalized on the basis of heat
input capacity and plotted against boiler size in Figures 5.3-1 and 5.3-2,
respectively. FBC algorithm costs corresponding to 30 percent S0? removal
on a Type H coal have also been plotted on these figures for both'optimistic
and conservative Ca/S ratios. Error bands of = 30 percent have been added
5-12
-------
to the algorithm capital and annual costs to represent the accuracy of the
estimates (see Section 6.0).
For capital costs, Figure 5.3-1 demonstrates that the W_, PER, and JB
projections are well within the error limits of the FBC algorithm
projections; the CE and FW estimates are near the limit of the upper error
band. The actual algorithm projection for the JB case would be slightly
lower than the band shown in the figure owing to the smaller limestone
storage and spent solids handling equipment that correspond to a higher
emission limit. The annual cost estimates plotted in Figure 5.3-2 show very
good agreement among the FBC algorithm and the CE, FW, and W projections.
No annual cost estimate could be developed for PER or JB because of a lack
of information on O&M costs.
Overall, this comparison of five independent estimates with the FBC
algorithm projections lends added validity to the algorithm as a cost
estimating tool. Also, the fact that the independent estimates show some
scatter with respect to the algorithm projections indicates that the
algorithm is not biased either high or low.
5-13
-------
\
\
\
\
\ Capital Cost Error
Band +30%
\
\
\
\
70
60
\
Caoital Cost \
Er-cr 3.ind -30=;
50
0 100
Figure 5.3-1. Comparison
\
\
a
FW
*>
CE
PER
O
"3C Algorithm (Range of Capital
Costs Due to Ca/S Ratios)
5-14
-------
11.00
\
10.00
\
\
\
x Annual Cost Error
\ Band +30%
\
\
9.00
8.00
o
(J
FBC Algorithm (Range of
Annual Costs Due to Ca/S Ratios)
D
FW
7.00
/
CE
m
4-)
O
6.00
5.00
4.00
\
\
\
100
Annual Cost Error
Sard -30-$
200 300
Boiler Size (106 Btu/hr)
400
Figure 5.3-2. Comparison of Total Annual Cost Estimates
500
5-L5
-------
5.3 REFERENCES
1. Margerum, S. C. and E. F. Aul , (Radian Corporation). Model 8oil«r Cost
Analysis for Sulfur Dioxide Control Alternatives On Fossil Fuel Fired
industrial Boilers. (Prepared for U. S. Enviromental Protection
Agency.) Research Triangle Park, N. C. (In preparation).
2. Jennings, M. S. and M. L. Bowen, (Radian Corporation). Costs of Sulfur
Dioxide, Particulate Matter, and Nitrogen Oxide Controls on Fossil Fuel
Fired Industrial Boilers. EPA-450/3-82-021 , U. S. Environmental
Protection Agency, Research Triangle Park, N. C. March 1982.
3. Young, C. W J M. Robinson, C. B. Thunem, and P. F. Fennelly, (GCA
Corporation). Technology Assessment Report for Industrial Boiler
Applictions: Fluidized-Bed Combustion. (Prepared for U S
1rnn^n5al Proteci:ion Agency.) Research Triangle Park, N. C.
-600/7-79-178e. November 1979.
4. Fennelly, P._F., C. Young, G. Tucker, and E. Peduts, (GCA Corporation)
Long-Term emissions Monitoring at the Georgetown University '
Fluidized-Bed Boiler. (Prepared for U. S. Environmental Protection
Agency.) Research Triangle Park, N. C. EPA Contract No. 68-02-3168
October 1982.
5. .Tennessee Valley Authority. TVA/EPRI 20-MW AF3C Pilot Plant Test
Program, Campaign I Report, Volume I, Technical summary, July 1 1982 -
April 6, 1983. (Prepared for Electric Power Research Institute). Palo
A i to , Ca .
6. Bradley, W. J., S. Panico, D. L. Keairns, R. A. Newby, N. H. Ulerich,
b. M. Gobhrsch, W. H. Heher, Effect of Subbituminous Western Coal Ash
on AF8C Power Generation Costs, presented at AIChE National Meeting
Houston, TX, April 1979.
7. Ahmed, M. M. , D. L. Keairns, and R. A. Newby (Westinghouse Research and
Development Center). Effect of Emission Control Requirements on
Fluidized-Bed Boilers for Industrial Applications: Preliminary
Technical/Economic Assessment. (Prepared for U. S. Environmental
Protection Agency.) EPA-600/7-81-149. September 1981.
-2. Cevitt, \., ?. Spaite, and L. Gibos. (PEDCo Environmental).
Population and Characteristics of Industrial/Commercial Boilers in the
U. S. (Prepared for U. S. Environmental Protection Agency Research
Triangle Park, N. C. EPA-600/7-79-78a. Cincinnati, Ohio August
1979. 462 p.
5-16
-------
9. Telecon. Fennelly, Paul F., GCA Corporation, with E. F. Aul, Radian
Corporation. September 13, 1983. Conversation regarding operation
procedures at Georgetown Universdity fluidized-bed boiler during
February/March 1982 emissions testing.
10. Roeck, D. R. (GCA Corporation). Technology Overview: Circulating
Fluidized-Bed Combustion. (Prepared for U. S. Environmental Protection
Agency.) Washington, D. C. EPA-600/7-82-051. Bedford, Massachusetts.
June 1982. pp. 42-49.
11. (Arthur G. McKee and Company). Cost Comparison Study - 100,000 Lb/Hr
Industrial Boiler. (Prepared for U. S. Department of Energy.) DOE
Contract No. EX-77-C-01-2418. Cleveland, Ohio. April 1979.
12. Myrick, D. T. (Combustion Engineering, Inc.) DOE Cost Comparison
Study: Industrial Fluidized Bed Combustion VS. (Conventional Coal
Technology. (Prepared for U. S. Department of Energy.) FE-2473-T7.
January 1980.
13. Foster Wheeler Development Corporation. Industrial Steam Supply System
Characteristics Program, Phase 1, Conventional Boilers and Atmospheric-
Fluidized-Bed Combustor. (Prepared for Oak Ridge National Laboratory,
U. S. Department of Energy). ORNL/Sub-80/13847/1. August 1981.
14. Ahmed, M. M., D. L. Keairns, and R. A. Newby (Westinghouse Research and
Development Center). Effect of Emission Control Requirements on
Fluidized-Bed Boilers for Industrial Applicators: Preliminary
Technical/Economic Assessment. (Prepared for U. S. Environmental
Protection Agency.) EPA-600/7-81-149. September 1981.
15. Mesko, J. E. (Pope, Evans and Robbins, Inc.). Economic Evaluation of
Fluidized Bed Coal Burning Facilities for Industrial Steam Generation.
The Proceedings of the Sixth International Conference on Fluidized Bed
Combustion, Volume II. Atlanta, Georgia. August 1980.
16. Letter from Virr, M. J., Johnston Boiler Company, to Aul, E. F., Radian
Corporation. November 18, 1983. FBC boiler cost study.
5-17
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6.0 ECONOMIC COMPETITIVENESS OF FBC TECHNOLOGY: IMPACT OF S02 EMISSION
LIMITS
This section presents the capital and annual cost projections developed
to assess the impact of alternative S02 emission standards on the relative
competitiveness of industrial FBC steam generation systems. FBC costs are
compared to two other S02 control alternatives: a conventional boiler
equipped with an FGD system; and an uncontrolled conventional boiler burning
low-sulfur compliance coal. The emphasis of this analysis is on trends and
cost sensitivity. The costing techniques employed to develop the estimates
presented in this section are consistent with budget-quality cost estimates
(i.e., accurate to within ± 30 percent).
6.1 COSTING PREMISES
This report focuses on the cost competitiveness of industrial FBC
technology as a function of S02 emission level stringency. Only coal-fired
boilers have been assessed since S02 emission limits will have their
greatest impact on FBC boilers operating on this fuel. While PM and NO
emission limits are given due consideration, the objective of the analysis
is to determine changes in relative cost competitiveness between these three
S02 control alternatives as a function of S02 emission limits.
The S0? emission limits chosen for examination are 1.7, 1.2, and 0.8 Ib
C. C.
S02/10 Btu. The 1.2 Ib S02/10 Btu limit was chosen because it is
currently the New Source Performance Standard (NSPS) for coal-fired boilers
with heat input capacities greater than 250 million Btu/hr (40 CFR 60
Subpart D). The limits on either side of 1.2 were chosen to provide a
reasonable range for the sensitivity analysis.
In order to meet these three S02 control levels on specified coals, FBC
and conventional boiler/FGD options must achieve corresponding S0? removal
efficiencies. The costs to achieve these efficiency levels, in conjunction
with the emission limits identified above, will be used to assess the
6-1
-------
cost-competitiveness of FBC technology with FGO and low-sulfur coal options
under various regulatory alternatives.
Allowable emissions of particulate matter (PM) and NO are maintained
at consistent levels for all S02 control levels examined. PM and NO levels
for both FBC and conventional coal-fired boilers are those levels
recommended for new industrial steam generators under 40 CFR 60 Subpart D.
These emission control levels and the methods for achieving control are
summarized in Table 6.1-1.
6.1.1 Model Boilers
In this report, cost impacts are calculated using an analysis of the
costs for model boilers and air pollution control systems. Model boilers
and control system cost algorithms have been developed which represent
typical industrial steam generating facilities for conventional systems.1
The conventional system algorithms used in this study are presented in
Reference 1; the algorithm for the FBC unit is described in Section 5 and
Appendix A.
The model boiler sizes chosen for this study are 50, 100, 150, 250, and
400 million 8tu/hr heat input; these capacities were chosen to provide a
reasonable range of industrial boiler types and to include critical
transition sizes with respect to PM and NO emissions. All of the
conventional boilers are field-erected units, except the 50 million Btu/hr
unit which is a shop-fabricated unit. FBC model boiler costs are based on a
30 million Btu/hr shop fabricated unit; a 75 million Btu/hr unit that was
field erected from shop fabricated modules; and fully field erected 150 and
200 million Btu units. Costs for intermediate size units were interpolated
using the cost algorithm. The 400 million 3tu/hr facility consists or two
200 ml lien Stu/hr boilers but a single train of limestone and soent solids
storage and handing equipment. The conventional boiler types (viz.,
underfeed stoker, spreader stoker, and pulverized coal combustion) are
specified in Table 6.1-1.
Explicit N0x control methods are not required for F3C boilers to meet
the emission limits identified in Table 6.1-1 because, as the data of
6-2
-------
TABLE 6.1-1. NO AND PM EMISSION CONTROL LEVELS AND METHOD OF CONTROL
Boiler Size Boiler
(10° Btu/hr) Type
50
50
100
100
150
150
250
250
400
400
Underfeed
Stoker
AFBC
Spreader
Stoker
AFBC
Spreader
Stoker
AFBC
Pulverized
Combustion
AFBC
Pulverized
Combustion
AFBC
Emissio
Ob/10
N0x
0.6
0.6
0.6
0.6
0.6
0.6
0.7
0.7
0.7
0.7
3 Levels
5 Btu)
PM
0.05
0.05
0.05
0.05
0.05
0.05
0.05
0.05
0.05
0.05
Method of Control
N0x
Low excess air
None
Low excess air
None
Low excess air
None
LEA/SCAa
None
LEA/SCA3
None
PM
Fabric Filter
Fabric Filter
Fabric filter
Fabric filter
Fabric filter
Fabric filter
Fabric filter
Fabric filter
Fabric filter
Fabric filter
LEA/SCA - low excess air in combination with staged combustion air.
6-3
-------
Section 4 demonstrate, NOX emissions from FBC units are consistenly below
the 0.5 lb/10 Btu level specified for the smallest conventional boiler. A
primary cyclone is included in the FBC boiler design but a final PM control
device is necessary to reach the emission limits specified in the table.
6.1.2 SO,, Control Alternatives
The S02 control alternatives selected for analysis in this report are:
(1) an FBC boiler operating with limestone for S02 control (identified as
FBC); (2) a conventional boiler equipped with a lime spray drying FGD system
(identified as FGD); and (3) a conventional boiler firing low sulfur
compliance coal (identified as CC).
It is assumed here that various S02 limitations identified above are
based on continuous emission monitoring results. It is further assumed that
the emission limits and removal requirements identified above are based on
30-day rolling averages. In order to comply with these requirements,
compliance coal sulfur contents (on a Ib S02/106 Btu basis) must be slightly
lower than corresponding emission limits to allow for the natural variablity
of coal sulfur content. A factor of 1.2 has been used in specifying the
compliance coal corresponding to each emission limit (i.e., average SO-
emissions are equal to the emission limit divided by 1.2). This factor is
based on variability analyses of coal sulfur emissions data obtained from '
operating industrial boilers.2 In most cases, a reference coal with the
exact sulfur content required to meet the emission limit was not available;
an available coal with a slightly lower sulfur content was specified (e.g.,
compliance coal with a sulfur content of 0.95 Ib SO-/106 Btu was specified
to meet the 1.2 Ib S02/106 Btu limit).
The SO,, control alternatives, emission standards, and projected
emission levels examined in this reoort are su'^a'-izec! i* Tsb1? 5.1-2. ^o"
each FBC and FGD alternative in the table, two coal type options have been
specified for comparison. The coal types used in this study are summarized
in Table 6.1-3. Type H coal produces uncontrolled SO- emissions of 5.54
lb/10 Btu while Type F coal produces uncontrolled emissions of 2.85 lb/105
Btu. Of course the level of S02 removal efficiency required to meet a given
6-4
-------
TABLE 6.1-2.
S02 CONTROL ALTERNATIVES FOR MODEL BOILERS
en
i
01
S0? Emission
Boiler Sizes Limit
(Million Btu/hr) (lb/10 Btu)
50, 100, 150,
250, 400 0.8
50, 100, 150, 1.2
250, 400
50, 100, 150 1.7
Control
Al ternative
1A
IB
1C
ID
2A
2B
3
1A
IB
1C
ID
2A
2B
3
1A
IB
2
3
SOp Control
Technique
FBC
FBC
FBC
FBC
FGD
FGD
CC
FBC
FBC
FBC
FBC
FGD
FGD
CC
FBC
FBC
FGD
CC
Coala
Type
H
H
F
F
H
F
A
H
H
F
F
H
F
B
H
H
H
D
% so2
Removal
90
90
80
80
90
80
-
80
80
65
65
80
65
-
75
75
75
-
Ca/S
Ratio
4.30
2.80
3.20
2.20
1.68
1.29
-
3.20
2.20
1.95
1.25
1.29
1.00
-
2.75
1.85
1.16
so2
Emissions
(lb/10b Btu)
0.55
0.55
0.57
0.57
0.55
0.57
0.60
1.11
1.11
1.10
1.10
1.11
1.10
0.95
1.39
1.39
1.39
1.45
Coal type specifications are summarized in Table 6.1-3
SO. emissions are below the relevant emission limits to allow for the variability of coal sulfur
cohtent, FBC performance, and FGD performance. Compliance coal option emissions are sliqhtlv
different than FBC and FGD option emissions due to reference coal sulfur specifications
-------
TABLE 6.1-3. COAL SPECIFICATIONS USED IN MODEL BOILER ANALYSIS3
Coal Typed
Bituminous
Type A
Type B
Type D
Type F
Type H
Subbituminous
Type A
Type B
Fuel Rriceb
(S/10° Btu)
3.44
3.28
3.22
2.94
2.47
2.84
2.84
Sulfur Content
Heating Value (i
(Btu/lb) fwt %]
x ' ' \™ <~ • ° / -I?
b S0?/ Ash Content
12,500 Q.50 0.80 11.0
12,500 0.59 0.95 H.Q
12,600 0.91 1
11,500 1.64 2
11,700 3.23 5
8,825 0.35 0
3,825 0.42 0
.45 n.o
.85 10.9
.54 12.0
.80 6.9
•95 6.9
Source: References 3, 4, and 5.
1990 levelized fuel prices in 1983 dollars.
To obtain sulfur content in ng/J, multiply by 430.
Coal specifications are based on average specifications for Midwest region.
6-6
-------
emissions limit declines from Type H to Type F coal, as reflected in
Table 6.1-2. These coal types are examined to illustrate the sensitivity of
system costs to coal sulfur content and S02 removal efficiency requirements.
For the FBC cases, two levels of Ca/S ratio are examined, corresponding to
the optimistic and conservative Ca/S projections of Section 5.1.2, for each
coal type. S02 removal efficiency levels for FBC and FGO alternatives were
chosen to yield emission levels approximately equal to CC levels.
In the case of the 1.7 Ib S02/106 Btu limit, boiler sizes of
250 million Btu/hr and above were not considered since the limit for this
boiler category is already set at 1.2 Ib SCyiO6 Btu (see 40 CFR 60 Subpart
D).
The FGD system specified for this analysis is the lime spray drying
system. This system was chosen over other FGD systems (e.g., dual alkali,
lime/limestone, or sodium once-through wet scrubbing) because (1) the
technology is being widely applied for S02 control among industrial boilers;
(2) spray drying costs are representative of costs for other FGD
technologies (e.g., once-through sodium and dual alkali FGD) throughout the
studied size range; and (3) the technology is similar to FBC technology in
its use of a calcium sorbent and production of a dry waste material.1 Lime
spray drying systems include a fabric filter as an integral part of their
design and thus achieve combined PM and S02 control. Detailed
specifications for this system, as well as other PM and NO control
A
techniques are presented in Reference 1.
As mentioned above, lime spray drying costs are generally
representative of FGD costs over the range of industrial boiler applications
examined. For smaller boilers below about 200 million Btu/hr, sodium
once-through wet scrubbing appears to be the low-cost alternative while for
larger boilers above 300-350 million Btu/hr dual alkali wet scrubbing
exhibits the lowest costs. Throughout this range, dry lime scrubbing costs
fall between the costs for these two wet scrubbing alternatives. In no case
do the estimated annual costs for these three technologies differ by more
than 15 percent. In view of this comparison, lime spray drying costs were
chosen as most representative of industrial FGD costs in this boiler size
range.
6-7
-------
6.1.3 Coal Specifications
The largest operating and maintenance (O&M) cost for both conventional
and FBC boilers is fuel. Table 6.1-3 presents the specifications and costs
for the coals used in this analysis. The prices in this table are
projections for 1990 delivered fuel prices expressed in January 1983
dollars. ' ' These projections ignore the effects of inflation but assume
that fuel prices will escalate in real terms. In addition, the fuel prices
have been "levelized" over the life of the boiler (i.e., an equivalent
constant price has been calculated after allowing for escalation and the
time value of money). These fuel prices are used in this study to maintain
consistency with other industrial model boiler cost analyses conducted
within EPA.
Direct O&M costs for the boilers and control devices are calculated
using the algorithms referenced above. The key factors used in estimating
annual O&M costs are the system capacity utilization, utility unit costs
(steam, electricity, water), and unit costs for raw materials, waste
disposal, and labor. In keeping with the above-mentioned model boiler cost
analyses, non-fuel O&M costs are assumed to escalate at the same rate as
inflation so that there is no increase in "real" costs. Capacity
utilization is defined as the actual annual fuel consumption as a percentage
of the potential annual fuel consumption at maximum firing rate. A value of
0.6 has been assumed in this study; this value corresponds to current
practice as defined in other industrial boiler cost analyses.1 Table 6.1-4
summarizes the utility and unit costs used in calculating annual O&M costs
for the boilers and control equipment.
A complete description of the cost bases utilized for capital and
annual cost calculations is Dras3ritsd i'n Acoprvd"'< D
6.2 COST COMPARISON RESULTS
Before discussing cost comparison results, it should be noted that the
cost data on which both the FBC and conventional system cost algorithms are
based come from respective ITAR cost estimates, which are considered
6-8
-------
TABLE 6.1-4. UNIT COSTS USED IN MODEL BOILER CALCULATIONS3
Utilities
Electricity 0.0503/kwhb
Water 0.0396/m3 (SO.15/103 gal)c
Steam $3.5/103 lbd
Raw Materials
N32C03 $0.169/kg ($153/ton)c'e
Lime $0.098/kg ($89/ton)c'e
Limestone $0.013/kg ($8.5/ton)c
Labor
Direct Labor $11.75/man-hourf>g
Supervision $15.28/man-hourh
Maintenance Labor $14.34/man-hour1'
Waste Disposal
Solids (Ash, Spray Dried Solids) $0.0198/kg ($18/ton)J'
Sludge $0.0198/kg ($18/ton)d
aAll costs in January 1983 $.
Monthly Energy Review, April 1983.
TVA, Technical Review of Dry FGD Systems and Economic Evaluation of Spray
Dryer FGD Systems, February 1982.
EPRI, Technical Assessment Guide, May 1982.
g
Updated using ratio of commodity chemical price for January, 1983 to June,
1982 as given in the Chemical Marketing Reporter.
Monthly Labor Review April, 1982.
n
-Average of wate rates for Chemical and Allied Products and Petroleum and
Coal Products categories.
Estimated at 30 percent over direct labor rate.
Estimated at 22 percent over direct labor rate.
JAverage of waste disposal rates from Economics of Ash at Coal Fired
Power Plants, Oct. 1981, and EEA, Estimated Landfill Credit for Non"-Fossi1
Fueled Boilers. October, 1980. ~ ——
6-9
-------
accurate to approximately =30 percent. Thus the capital cost estimates in
this report retain the same level of accuracy. In making comparisons
between FBC and other technology options, however, the accuracy of capital
cost differences may be better than ±30 percent. This is due to the fact
that some equipment items are common to all algorithms and have been treated
in the same manner (e.g., use of PEDCo data to estimate the cost of boiler
feed pumps).
The accuracy of total annual cost estimates is also ± 30 percent.
However, relatively little error is associated with comparisons of toial O&M
costs between technologies since (1) raw material and fuel requirements can
be estimated with a high degree of accuracy (based on assumptions in most
cases) and (2) the same unit costs have been used in estimating operating
costs for each alternative (e.g., hourly labor rates, solid waste disposal
rate, plant and payroll overhead). Therefore, annual cost error bands are
primarily due to the error associated with annualized capital charges. On
this basis, total annual cost comparisons between technology options are
considered accurate to within about 15 percent over the boiler size range
examined.
The accuracy limits for capital and operating costs should be borne in
mind when reviewing the results discussion in this section and Sections 6.3
and 6.4. The absolute value of any single cost estimate is accurate only to
within the error bands specified above.
6.2.1 Overall Results
Tables 6.2-1 to 6.2-3 summarize the annual cost estimates for the S0?
control alternatives outlined in Section 6.1.2. The cost estimates have
been grouped by S00 emission limitations so that alteratives c»n be
compared witn other alternatives of aco'-o.xirately °-'j2l S
-------
TABLE 6.2-1. TOTAL ANNUAL COSTS FOR SO, CONTROL OPTIONS AT
1.7 LB/100 BTU EMISSION tIMIT
TOTAL ANNUAL COSTS (S1000)a
Boiler Size
(Million Btu/hr)
50
100
150
Fluidized Bed
Combustion j
75%/Type Ha
2,278
4,228
5,961
Conventional
Boiler/FGDc
75%/Type H
2,282
4,019
5,554
Conventional
Compl iance
Type D
2,076
3,931
5,562
Boiler/
Coal
aJanuary 1983 dollars.
Based on conservative Ca/S ratios (see Appendix B).
'Only Type H coals are examined for these options since firing a Type F
coal would correspond to only 50 percent SO- removal, a level which is
not encountered in typical industrial boiler applications.
S02 removal percentage/coal type.
6-11
-------
TABLE 6.2-2. TOTAL ANNUAL COSTS FOR S09 CONTROL OPTIONS AT
1.2 LB/100 BTU EMISSION tlMIT
TOTAL ANNUAL COSTS ($1000)*
en
I
Boiler Size
(Million Btu/hr)
50
100
150
250
400
Huidized Red
80%/Type HC
2,297
4,291
6,024
9,510
15,293
Combustion
65%/Type F
2,326
4,316
6,056
9,586
15,451
Conventional
80%/Type H
2,301
4,053
5,604
9,504
13,810
Boiler/FGD
65%/Type F
2,330
4,124
5,727
9,723
14,183
Conventional
Compliance
Type B Sub
2,266
3,915
5,519
9,332
13,656
Boiler/
Coal
Type B Bit
2,160
4,004
5,667
9,709
14,342
January 1983 dollars.
Based on conservative Ca/S ratios (see Appendix B)
"S0« removal percentage/coal type.
-------
TABLE 6.2-3. TOTAL ANNUAL COSTS FOR S09 CONTROL OPTIONS AT
0.8 LB/100 BTU EMISSION tIMIT
TOTAL ANNUAL COSTS ($1000)a
01
I
Boiler Size
(Million Btu/hr)
50
100
150
250
400
Fluidized Bed
90%/Type Hc
2,341
4,393
6,177
9,765
15,702
Combustion
80%/Type F
2,355
4,370
6,159
9,753
15,695
Conventional
90%/Type H
2,355
4,154
5,751
9,743
14,183
Boiler/FGD
80%/Type F
2,358
4,173
5,797
9,834
14,354
Conventional
Compliance
Type A Sub
2,266
3,915
5,519
9,332
13,656
Boiler/
Coal
Type A Bit
2,140
4,088
5,793
9,922
14,682
January 1983 dollars.
Based on conservative Ca/S ratios (see Appendix B)
SO^ removal percentage/coal type.
-------
to differences between the optimistic and conservative projections, as
explained in Section 5.1-2. Despite this large difference in Ca/S ratios,
annual costs differ by only 1 to 4 percent over the range of boiler sizes
and S02 emission limits examined. This is due to the fact that limestone
raw material costs and solid waste disposal costs are a relatively small
fraction of overall annual costs. Thus Ca/S ratios have only a small impact
on total annual FBC system costs. In light of this small difference, and
the desire to develop conservative estimates of FBC technology costs (i.e.,
to err on the high side), only the conservative Ca/S ratios results will be
considered in the discussion of this and following sections of the report.
A careful examination of the cost estimates summarized in Tables 6.2-1
to 6.2-3 reveals several important overall results:
• For the S02 control options meeting a 1.2 lb/106 Btu limit, the
annual costs for both the FBC and FGO alternatives are lower (2 to
3 percent) for the Type H coal options than the Type F coal
options. This is because the added fuel charges for the lower
sulfur content, but more expensive, Type F coal outweigh the
capital and operating cost savings which result from lower
limestone feed and solid waste disposal requirements.
t For the 0.8 Ib SC>2/10 Btu cases, this same trend applies for the
FGD alternatives but is reversed for the FBC alternatives above 50
million Btu/hr heat input. Due to the higher Ca/S ratios
associated with 90 percent S02 removal in an FBC unit, a crossover
point is reached between 50 and 100 million Btu/hr heat input at
which lower overall annual ccsts are incurred by re.rcvirg or,"!/ 33
t-*ayi1~pr»-«-«-£4.u^c;n ry"->-^^Ti'-^r~-\-"' •*•'-,•- ~ • L
r-, x.c, v. vi ..,-, _.^2 , ru,., a '.j^s r »oa i . ,1,1s i-rcisover point is
not observed for the FGD alternatives in the studied ranges
because of the lower Ca/S ratios associated with this technology.
• When comparing bituminous to subbituminous Type A and B coals,
lower annual costs are incurred in most cases by firing the
6-14
-------
subbituminous coals since their lower fuel costs more than offset
the higher boiler capital costs due to lower heating values. The
exceptions to this rule are the 50 million Btu/lb boilers where
low fuel use rates do not generate sufficient fuel cost savings to
offset higher capital costs. For small boilers meeting 1.2 and
0.8 Ib S02/10 Btu emission limits firing bituminous coal results
in lower overall annual costs. This advantage disappears at the
100 million Btu/hr size and above.
• When comparing the low annual cost options for FBC with the low
annual cost options for FGD and CC, the FBC technology costs are
shown to be comparable to the costs for the other alternatives
over the boiler size range and SC>2 emission range examined. That
is, annual cost differences between options do not exceed
15 percent, which is within the overall accuracy of the annual
cost comparisons.
• Capital costs for the three S02 control options are also
comparable (i.e., within ±30 percent) for boilers above 50 million
Btu/hr heat input. For small boilers near 50 million Btu/hr, CC
capital costs are significantly lower than those for FBC units.
6.2.2 FBC Competitiveness Across SO,, Emission Limits
In order to gain perspective on the influence of S02 emission limits on
relative economic competitiveness, FBC annual costs are compared with costs
for FGD and compliance coal in Table 6.2-4. Negative values in this table
represent cases where FBC is projected to be more attractive than the other
options. Total annual costs for these technology options are also plotted
in Figures 6.2-1 and 6.2-2 as a function of SOp emission rates (equivalent
to coal sulfur contents for compliance coals). The focus of this analysis
is on annual costs since both plant owners and various boiler/fuel choice
analysis models make their selection among S02 control alternatives
primarily on the basis of total annual costs.
6-15
-------
TABLE 6.2-4. FBC ANNUAL COST COMPETITIVENESS WITH FGO AND
COMPLIANCE COAL AS A FUNCTION OF EMISSIONS LIMIT
FBC vs
FGDC
FBC vs.C
Compliance
Boiler Size
(Million Btu/hr)
50
100
150
250
400
Boiler Size
(Million Btu/hr)
50
100
150
Coal
250
400
SO, Emission
" 1.7
-0.2
5.2
7.3
-
-
SO,, Emission
~ 1.7
9.7b
7.6
7.2
-
-
Limit
1.2
-0.2
5.9
7.5
0.1
10.7
Limit
1.2
6.3
9.6
9.2
1.9
12.0
(lb/106 Btu)
0.8
-0.5
5.8
7.4
0.2
10.7
(lb/105 Btu)
0.8
9.4
12.2
11.9
4.6
15.0
Values correspond to (FBC annual costs/FGD annual costs) x 100 - 100.
Values correspond to (FBC annual costs/compliance coal costs) x 100 - 100,
Annual cost for each alternative corresponds to lowest annual cost option
in Appendix B tables; FBC costs are based on conservative Ca/S ratios.
6-16
-------
FIGURE 6.2-1
FBC ANNUAL COST COMPETITIVENESS WITH FGD
eom:
-fSD- COST!
16
•466-
UD
O
oo
o
CJ
.Q = aso_._i__
J3=
Q = IbU
—^-^-^—-^
-0;—M»e-
Q = 50
J I
0.5 l.o
S02 EMISSIONS (lb/106 BTU)
1.5
6-17
-------
FIGURE 6.2-2
FBC ANNUAL COST COMPETITIVENESS WITH COMPLIANCE COAL
20
r—FBC- COSTS—
I COMPLIANCE- CQAfc- €8£F5-
=£11
-o
^=f
01
o
o
e—e-
4 —
00
=0=
*.-.!•»
0.5 1.0
SOo EMISSIONS (lb/106/BTU)
1.5
6-18
-------
The information in Table 6.2-4 and Figure 6.2-1 indicates that FBC
competitiveness relative to FGD remains nearly constant as the SCL emissions
limitation becomes stricter for all boiler sizes. Thus FBC cost
effectiveness as an S02 control technology relative to FGD systems does not
change as emission level stringency changes. These results are based on the
use of conservative or high Ca/S ratio for the FBC alternatives. It is
interesting to note that for optimistic, or low Ca/S ratios, FBC
competitiveness relative to FGD increases as the SC>2 emissions limitations
becomes stricter for all boiler sizes. Thus larger incentives for research
and development efforts aimed at lowering required Ca/S ratios for
industrial FBC units will occur as SO^ emission limits are reduced. This
trend for optimistic Ca/S ratios is also consistent with the general
observation that FBC systems can be very attractive relative to FGD when
plant operators have only very high sulfur (greater than 4 percent) coal
available for use. In general, FBC economic competitiveness increases as
the mass rate of S02 removal increases, either due to more stringent
emission limits or higher sulfur content coal.
Comparing FBC and FGD costs within a given emissions limit category,
Table 6.2-4 indicates that FBC competitiveness increases as boiler size
decreases. In fact, FBC costs are marginally lower than those for FGD units
at the 50 million Btu/hr size range. The exception to this trend occurs
between the 150 and 250 million Btu/hr boiler size levels. The principal
reason for the change in relative cost competitiveness between these levels
is that the boiler design specified for the FGD option switches from a
spreader stoker boiler at the lower level to a pulverized coal (PC) boiler
at the higher level. As illustrated in Figure 6.2-3 (for the case of a 1.2
Ib/million Btu SO^ emissions limit), this switch occurs at the 200 million
Btu/hr boiler size level for the model boilers examined and is accompanied
by a 13 percent increase in total annual costs. FBC costs, on the other
hand, show a steady increase as boiler size increases throughout the range
examined. The change from spreader stoker to PC boilers in the 200 to 300
million Btu/hr size range is consistent with industry practice.5 Two
secondary reasons for the shift in relative cost competitiveness between the
6-19
-------
FIGURE 6.2-3
FBC AND FGD ANNUAL COSTS FOR A 1.2 LB S02/106
BTU EMISSION LIMIT
16
14
12
10
o
t—*
<*=v
3 a
4 —
FBC COSTS
FGD COSTS
CHANGE FROM SPREADER
STOKER TO PULVERIZED
COAL CONVENTIONAL BOILER
100 200 300
BOILER SIZE (MILLION BTU/HRi
400
600
6-20
-------
150 and 250 million Btu/hr boiler size levels are: (1) the cost of NO
A
emission controls on the conventional boiler changes from a negative cost
(due to effect of LEA use on stoker boiler fuel savings) to a net positive
cost associated with the use of LEA/SCA on PC boilers; and (2) multiple
boilers are specified for the FBC option above the 200 million Btu/hr range
which results in a slight decrease in annual costs (less than 1 percent).
Figure 6.2-3 also shows that FGD option annual costs generally increase
at a slower rate than FBC option costs as boiler size increases. As a
result, FBC cost competitiveness decreases as boiler size increases, except
in the case noted above.
Assessment of the information in Table 6.2-4 and Figure 6.2-2
concerning FBC cost competitiveness relative to compliance coal combustion
indicates that most of the same trends apply: (1) relative cost
competitiveness between the two alternatives remains nearly constant over
the studied range of S02 emission limits and (2) FBC cost competitiveness
decreases slightly as boiler size increases except in the range of 150 to
250 million Btu/hr. This latter behavior is illustrated in Figure 6.2-4.
As discussed earlier, the principal reason for the change in relative cost
competitiveness between these levels is the switch from spreader stoker to
PC boilers for the compliance coal option.
There is a slight decrease in FBC cost competitiveness relative to CC
as the emission limit is reduced from 1.2 to 0.8 lb/106 Btu. This is due
primarily to the fact that FBC annual costs increase with decreasing
emission levels (owing to higher capital and operating costs for limestone
and spent solids disposal) while compliance coal prices either do not change
between Type A and B coals (for subbituminous coals) or change only slightly
(for bituminous coals). An expanded discussion of the impact of coal prices
on FBC competitiveness is presented in Section 6.3.
Unlike the FBC-FGD cost comparison, FBC competitiveness relative to CC
remains constant as the SO,, emission limit decreases if the optimistic Ca/S
ratios are used. The only case for which FBC costs appear marginally lower
than CC costs at the lower Ca/S ratios occurs at the 250 million Btu/hr
boiler level.
6-21
-------
16
FIGURE 6.2-4
FBC AND COMPLIANCE COAL ANNUAL COSTS FOR A
1.2 LB S02/106 BTU EMISSION LIMIT
FBC COSTS
COMPLIANCE COAL COSTS
14
12
10
o
.—I
<**
(J-l
i s
_l
-------
Table 6.2-5 provides an overview of the capital cost competitiveness of
FBC with the FGD and CC alternatives. It shows that capital cost
competitiveness remains relatively constant among alternatives as the
emission limit varies. FBC capital costs are most attractive at the larger
boiler sizes. FBC capital costs are significantly above those of CC
alternatives at the 50 million Btu/hr level.
6.2.3 FBC Competitiveness Based on SO,, Percent Removal Requirements
A second type of S02 emission limitation which currently applies to
electric utility boilers above 250 million Btu/hr heat input capacity
[Subpart Da (40 CFR Part 60)] is a requirement for a specific level of SO-
removal efficiency. To evaluate this type of limitation, FBC annual costs
are compared with FGD costs for equal S02 removal performance levels in
Table 6.2-6. Not surprisingly, the data follow the same trends identified
earlier for an emissions limit measured in Ib S02/106 Btu heat input. FBC
competitiveness vis-a-vis FGD remains relatively unchanged over the studied
range of S02 percentage removal requirements. If the optimistic Ca/S ratios
are used for the FBC alternatives, FBC competitiveness increases as S02
removal levels become more stringent.
As was the case in Table 6.2-4, FBC competitiveness in Table 6.2-5
relative to FGD increases as boiler size decreases, all other things being
equal. The same factors as cited above also account for the change in
relative competitiveness between the 150 and 250 million Btu/hr boiler size
categories.
The capital cost figures shown in Table 6.2-7 indicate that FBC
competitiveness relative to FGD on a capital cost basis remains constant as
S02 removal efficiency varies. FBC capital costs are slightly below those
of the FGD alternatives for 250 and 400 million Btu/hr boilers.
6.3 CONDITIONS UNDER WHICH FBC IS ECONOMICALLY FAVORED
One of the objectives of this study is to identify those conditions
under which FBC is economically favored over a conventional boiler/FGD
6-23
-------
TABLE 6.2-5. FBC CAPITAL COST COMPETITIVENESS WITH FGO AND
COMPLIANCE COAL AS A FUNCTION OF EMISSIONS LIMIT
FBC vs
FGOC
FBC vs.C
Compl iance
Boiler Size
(Million Btu/hr)
50
100
150
250
400
Boiler Size
(Million Btu/hr)
50
100
150
Coal
250
400
SO,, Emission
~ 1.7
12. 7a
8.1
9.5
-
-
SO, Emission
" 1.7
39. 3b
21.1
17.9
-
Limit
1.2
12.8
9.9
10.1
-2.3
1.1
Limit
1.2
30.8
10.9
9.1
-O.I
3.3
Ob/106 Btu)
0.8
12.8
4.0
4.5
-7.2
-4.5
(lb/106 Btu)
0.8
41.5
6.3
4.7
-4.1
-1.4
Values correspond to (FBC capital costs/FGD capital costs) x 100 - 100.
Values correspond to (FBC capital costs/compliance coal caoital costs)
x 100 - 100. '
Capital cost for each alternative corresponds to lowest annual cost ootion
in Appendix B tables; FBC costs are based on conservative Ca/S ratios'.
6-24
-------
TABLE 6.2-6. FBC ANNUAL COST COMPETITIVENESS WITH, FGD AS A
FUNCTION OF S02 PERCENT REMOVAL REQUIREMENT
Boiler Size
(Million Btu/hr)
50
100
150
250
400
65
-0.2a
4.7
5.7
-1.4
8.9
SO,, Removal Efficiency
75
-0.2
5.2
7.3
-
-
(Percent)
80
-0.2
5.9
7.5
0.1
10.7
90
-0.6
5.8
7.4
0.2
10.7
aValues correspond to [(FBC annual costs/FGD annual cost) x 100 - 100].
Annual cost for each alternative corresponds to lowest annual cost option
in Appendix B tables; FBC costs are based on conservative Ca/S ratios.
6-25
-------
TABLE 6,2-7. F8C CAPITAL COST COMPETITIVENESS WITHUFGD AS A
FUNCTION OF S02 PERCENT REMOVAL REQUIREMENT5
Boiler Size
(Million Btu/hr)
50
100
150
250
400
•
65
12. 6a
6.9
6.1
-6.4
-4.9
SO,, Removal Efficiency
75
12.7
8.1
9.5
-
-
(Percent)
80
12.8
9.9
10.1
-2.3
-1.1
90
12.8
4.0
4.5
-7.2
-4.5
Values correspond to [(FBC capital costs/FGD capital cost) x 100 - 100].
Capital cost for each alternative corresponds to lowest annual cost option
in Appendix B tables; FBC costs are based on conservative Ca/S ratios.
6-26
-------
system or compliance coal. The cost information in Tables 6.2-1 through
6.2-3 indicate that FBC is economically equivalent on an annual cost basis
to FGD and compliance coal combustion for the cases under consideration in
view of the overall accuracy of the annual cost comparisons (i.e., ± 15
percent).
To be significantly favored over the other alternatives, FBC should be
approximately 15 percent less expensive on an annual cost basis. This
assumes that there is a high probability that the true cost differential
between two technologies will be within 15 percent of the cost differential
estimated by the algorithms. Using this criterion of a 15 percent cost
differential, key parameters can be varied in the annual cost basis to
identify those conditions under which FBC is a clear favorite.
A 150 million Btu/hr boiler and 0.8 Ib S02/MM Btu emission limit have
been chosen as the basis of this analysis. The cost data of the previous
sections show that FBC is least competitive, in most cases, at the
150 million Btu/hr boiler size. Thus the parameter adjustments required for
the 150 million Btu/hr boiler will be generally greater than those required
for other boiler sizes. The 0.8 Ib S02/106 Btu standard has been chosen
because it is the most stringent control limit considered in this study as
regards both final emissions and percent reductions as well as the annual
cost savings required.
6.3.1 FBC Versus FGD
As indicated in Table 6.2-3, in order to be 15 percent less expensive
than FGD, the FBC option annual costs should be no more than $4,888,000
(i.e., (1.00-0.15) x $5,751,000). The annual costs for the FBC option in
this case are summarized in Table 6.3-1. To achieve the target annual cost
identified above, a cost savings of 51,271,000 is required. A study of
Table 6.3-1 shows that FBC limestone and solid waste disposal costs could
drop to zero, simultaneously, and only reach about one-fifth of the desired
annual cost savings. This is not possible, of course, since the minimum
theoretical Ca/S molar ratio for SO,, capture is 1.0. The point here is that
6-27
-------
(a
(BASIS:
DETAILED ANNUA1- COST BREAKDOWN FOR FBC
BTU/HR, TYPE F coal, 80 PERCENT S00 REMOVAL
Ca/S = 3.20,
AN 1983 $
0
2
Direct Operating Cost
Direct Labor
Supervision
Maintenance Labor
Replacement Parts
Electricity
Process Water
Fuel
Limestone
Waste Disposal
Total Direct Cost
Overhead
Payroll
Pi ant
Total Overhead Cost
Capital Charges
Capital Recovery
Working Capital Interest
Miscellaneous
Total Capital Charges
Total Annual Costs
FBC Boiler
$ 217,000
92,000
86,000
213,000
230,000
19,000
2,319,000
53,000
142,000
3,371,000
65,000
158,000
223,000
1,677,000
46,000
510,000
2,233,000
S 5,827,000
Baghouse
$ 19,000
13,000
12,000
39,000
15,000
98,000
5,000
11,000
17,000
164,000
2,000
50,000
216,000
S 332,000
Total
$ 236,000
92,000
99,000
225,000
259,000
19,000
2,319,000
53,000
157,000
3,470,000
71,000
169,000
240,000
1,341,000
48,000
560,000
2,449,000
^ f, 1 so npn
— ' -'^••^-'•jWVW
6-28
-------
reducing the Ca/S ratio alone will not have a significant impact on FBC
competitiveness relative to FGD.
The two largest factors influencing annual FBC costs are fuel charges
and capital costs. Since the FBC and FGD alternatives use the same fuel at
the same rate (i.e., boiler efficiencies for FBC and conventional boilers
are assumed equivalent), a comparative cost savings based on fuel charges is
not possible. With respect to capital costs, the information in Appendix D
indicates that model boiler turnkey costs are multiplied by a factor of
0.1715 to calculate the annual costs due to capital recovery and
miscellaneous costs. Thus a turnkey cost reduction of $7.41 million
($1,271,000 T 0.1715), or 51 percent would be required to lower total FBC
annual costs to a level 15 percent below FGD costs. Conversely, FGD capital
costs would have to rise by 73 percent to accomplish the same effect.
Neither of these changes, at least of this magnitude, are likely to occur in
the foreseeable future as a result of technological developments.
6.3.2 FBC Versus Compliance Coal
Annual FBC cost reductions relative to compliance coal combustion must
be even greater than those relative to FGD. To achieve the same 15 percent
annual cost advantage over the CC option at the base conditions, FBC costs '
should be $4,691,000 per year, or a reduction of $1,468,000.
Table 6.3-1 results indicate that either fuel charges or capital costs,
or both, should be reduced to effect this cost reduction. In the case of
fuel charges, a differential of $1.86/106 Btu would be sufficient to make
FBC a clear economic favorite over compliance coal. This differential could
be achieved either by lowering the unit cost of the Type H coal burned in
the FBC unit or raising the unit cost of the Type A coal burned in the
conventional spreader stoker boiler, or a combination thereof. This
corresponds to a 63 percent reduction of unit coal costs for the FBC option
or a 65 percent increase for the compliance coal unit cost.
As with the FGD comparison, the relative turnkey capital costs for the
FBC and CC options could be shifted to achieve the targeted FBC annual cost
advantage. This target translates to a $8.56 million turnkey capital cost
6-29
-------
differential which corresponds to a 59 percent reduction of FBC costs or a
62 percent increase for CC costs, or a combination of the two. Again, as
with the earlier discussion concerning FGO costs, the likelihood of cost
changes of this magnitude occurring in the foreseeable future as a result of
coal market or technological changes is quite remote.
The figures presented in this section are not projections or
predictions of changes that will occur among the three technology alterna-
tives. Rather, the calculations are meant to illustrate the length to which
unit costs and turnkey capital costs would have to change to make the FBC
option a clear-cut favorite over FGD and CC for a 150 million Btu/hr boiler
operating to meet a 0.8 Ib S0,,/106 Btu limit on a continuous basis.
Relative changes of a similar magnitude would be required for other boiler
sizes and emission limits. Of course, if detailed design and cost
calculations were performed so as to reduce the uncertainty of the cost
comparisons, clear economic choices between the three technology options
could be made on a case-by-case basis.
6.4 Coal Price Sensitivity
Since fuel changes represent a significant portion of the total annual
costs for each of the S02 control alternatives examined, it is useful to
quantify the impact of coal price changes on model boiler total annual
costs. The algorithm format of the total annual cost estimation procedure
allows ready derivation of formulas for coal price sensitivity. These
formulas are presented in Table 6.5-1 for the model boilers examined in this
study.
Annual costs for a 150 million Btu/hr boiler operated to meet a 1.2 Ib
S02/10 Btu emission limit are used to illustrate t^e coal ?-1ce servith-r-.
or trie various SO,, techno!cry *} i-av-nari"nc- nc-.-^n »i__ *_..„.,1.. c ..<
<_ ~ Jj " ~ • --'•«-• - -• i .3 ., = j.,...». ij i r j.r. ^."c
table, one can show that a Sl.OO/million Btu coal price increase translates
to an annual cost increase of $795,000 for an FBC boiler and 3788,000 for a
spreader stoker boiler equipped with LEA NOX control. The latter cost
increase applies equally to both the compliance coal and the FGD control
alternatives. For a pulverized coal boiler equipped with LEA/SCA NO
6-30
-------
TABLE 6.5-1. COAL PRICE SENSITIVITY OF TOTAL ANNUAL COSTS
FOR MODEL BOILERS
For an FBC boiler:
ATAC = 8833 x CF x Q x AFC
For a spreader stoker boiler (with LEA NO control):
A
ATAC = CF x Q x AFC [8833 - 5.5 x 10"4 x FFAC x (UNCEA - CTREA)]
For a pulverized coal boiler (with LEA/SCA NO control):
X
ATAC = 8855 x CF x Q x AFC
Where,
TAC = Total annual costs, $.
CF = Capacity factor, expressed as a decimal.
Q = Boiler heat input capacity, 10 Btu/hr.
FC = Fuel cost, $/106 Btu.
FFAC = F factor, Dry SCF/106 Btu heat input (9820 for coal).
UNCEA = Uncontrolled excess air, percent.
CTREA = Controlled excess air, percent.
6-31
-------
control, the annual cost change due to a Sl.OO/million Btu coal price change
is $797,000. Again, this increase applies equally to both the compliance
coal and FGD alternatives. The nearness of the total annual cost changes
indicates that the coal price sensitivities of the three S02 control
alternatives are equivalent for practical purposes.
6.5 CONCLUSIONS
The overall conclusion that can be drawn from the cost data and
analysis of this section is that annual cost differences among FBC
technology, conventional boiler/FGO systems, and compliance coal combustion
are expected to be small (± 15 percent or less) over the range of SO-
emission limitations and boiler sizes examined. Absolute economic competi-
tiveness among these alternatives will be determined by site-specific
parameters. In addition, FBC cost data show that Ca/S ratios have only a
minor effect on system capital and operating costs; significant reductions
in the required Ca/S ratio for a given level of SC>2 removal (which is an
objective of research at the Tennessee Valley Authority pilot plant and
elsewhere) will not noticeably alter the economic competitiveness of FBC
technology for industrial applications.
Given the small cost differences among the studied S02 control
alternatives in the current context, and the lack of expectations for
dramatic changes in the near future, it is unlikely that economics alone
will be the deciding factor when a choice is made among options by an
industrial plant owner. Rather, less tangible factors such as requirements
for fuel flexibility and preference for risk are likely to play more
important roles in the dec^sio^ orcr=<;-
6-32
-------
6.5 REFERENCES
1. Laughlin, J. H., J. A. Maddox, and
Corporation). SCL Cost Report.
3,
4.
5.
6.
S. C. Margerum, (Radian
(Prepared for U.S. Environmental
' • y _j__.__ v _ j_ -^ , _ _ . v , w • >»/ « L_fi*iiwiiini_iii*ui
Protection Agency.) Research Triangle Park, N.C. (In Preparation).
DuBose, D. A., W. D. Kwapil, and E. F. Aul (Radian Corporation).
Statistical Analysis of Wet Flue Gas Desulfurization Systems and Coal
Sulfur Content. Volume I: Statistical Analysis. (Prepared for
U. S. Environmental Protection Agency.) Research Triangle Park, N.C.
EPA Contract No. 68-02-3816. August 1983;
Hogan, Tim (Energy and Environmental Analysis, Inc.) Memorandum to
Robert Short (EPA/EAB). Recent Changes to IFAM Model. June 22, 1983.
Hogan, Tim (Energy and Environmental Analysis.) Memorandum to
Robert Short (EPA/EAB). Industrial Coal Prices. July 19, 1983.
Hogan, Tim (Energy and Environmental Analysis, Inc.) Memorandum to
Robert Short (EPA/EAB). Industrial Fuel Prices. June 19, 1983.
Devitt, T., P. Spaite, and L. Gibbs. (PEDCo Environmental).
Population and Characteristics of Industrial/Commercial Boilers in the
U.S. (Prepared for U.S. Environmental Protection Agency.) Research
Triangle Park, N.C. EPA-600/7-79-78a. Cincinnati, Ohio. August 1979.
462 p.
6-33
-------
APPENDIX A
FBC COST ALGORITHM DEVELOPMENT
In 1979, the FBC-ITAR cost estimates were translated into cost
algorithms by Acurex Corporation. The Acurex algorithms are generally
faithful to the ITAR design basis and costs. Exceptions were noted on
review, however, and were corrected as summarized below:
9 The Acurex expressions for turnkey costs for limestone and spent
solids storage and handling seriously underestimated the ITAR
costs. These expressions were revised to duplicate the original
estimation procedures outlined by GCA in the ITAR;
• The term for supervisory labor had been left out of the expression
for plant overhead costs; this oversight was corrected.
• A correlation had been developed for flue gas flow rate as a
function boiler size but data for air flow rates to the boiler had
been used instead of flue gas rates. A new expression for flue
gas flow was derived from the flue gas rate-versus-boiler capacity
data in Table C-5 of the ITAR;
In addition, a number of algorithm modifications were made to make the
final expressions consistent with existing algorithms for conventional
boilers and air pollution control devices and/or more flexible for use in
this study. These modifications included:
3 Added provisions for estimating costs for a 400 million Btu/hr
boiler. The largest boiler which had been costed in the ITAR was
a 200 million Btu/hr unit. A recent study by Combustion
Engineering, Inc. indicates that 250 million Btu/hr is the maximum
capacity for shop-assembled, rail-shippable FBC boilers.2
However, the ITAR costs were based on a 30 million Btu/hr fully
A-l
-------
shop fabricated unit; a 75 million Btu/hr unit that was field
erected from shop fabricated modules; and fully field erected 150
and 200 million Btu/hr units. Since the ITAR cost basis did not
extend to a 400 million Btu/hr unit, two 200 million Btu/hr FBC
boilers were specified for the 400 million Btu/hr case. This unit
has a single train of limestone and spent solids storage and
handling equipment, however. Appropriate factors were applied to
capital cost estimates as recommended by PEOCo for dual unit
boilers;
Eliminated Acurex equations which predicted Ca/S ratio as a
function of S02 removal efficiency. In this report, the Ca/S
ratios used in cost calculations are those projected by the
Westinghouse model as summarized in Table 5.1-2 (or extrapolated
via power curve). To provide greater flexibility, Ca/S ratios are
now specified as input data by the user;
Added an expression to calculate uncontrolled particulate matter
from the FBC unit. The FBC boiler design includes a primary
cyclone for solids recycle. To maintain consistency with the
ITAR, the flow of PM from the cyclone was set equal to 10 percent
of the non-combustible solids flow (i.e., coal ash, unraacted
limestone, calcined limestone, and sulfated limestone) into the
boiler. This ratio was selected in the ITAR because it was
consistent with the experimentally documented range of particulate
matter loadings at the primary cyclone exit. Based on ITAR mass
'lew rates, the solids recycle rate varies -Vc~ 3.2 to 0.4. ~he
aigoricnm exoressicn incoroorates this ^a^ce c? r=>c'--!a r5^--
A-2
-------
• Revised the expression for working capital to be consistent with
algorithms for other technologies (see Appendix D);
a Adjusted the costs for performance tests from $12,000 in the
Acurex algorithms to 1 percent of boiler total direct cost; this
specification is consistent with other algorithms (see Appendix
D);
• Added a labor factor to these same equations to account for
reduced labor requirements at reduced capacity to maintain
consistency with other algorithms (see Appendix D);
• Added provisions to revise capital and annual costs to a different
time basis using capital equipment cost indices and specific unit
costs;
The resulting cost algorithm for industrial atmospheric FBC technology
is listed in Table A-l. A description of the terms used in the algorithm
and their corresponding units are contained in Table A-2.
A-3
-------
TABLE A-l. COST EQUATIONS FOR COAL-FIRED FLUIOIZED
BED COMBUSTION (FBC) BOILERS3
Routine Code:
Capital Costs:
TK = TKB + TKLS + TKSW
TKS = 1.596 * TDB Q < 58 6 MW
= L'484 * TDB Q > 58.6 MW
where
TDB = (814,200 + 362,000 (Q - 8.8)°'7) fl.23 - ^U-Vor Q > 58 6 MW
\ 10b /
TDB = 1.748 (814,200 + 361,000 (Q/2 - 8.8}°'7) A.23 - 8-|1H^Q > 73 2 MW
V 106 /
TKLS = 2.317 (CL * VCL + 4.4 * LSFR)
CL = 0.2409 * LSFR
VCL = 349.3 - 0.244 CL CL < 283
VCL = 383
LSFR = (Q/H) (1.25 x 105) (S) (FCS)
TKSW = 2.422 * CW * VCW •
CW = 0.2139 * SWFR
VCW = 396.8 - 0.3278 CW cw < 23;
VCW = 421 -;, .. 25-
SWFR = 0.9 (0.524 * LSFR + CFR/(S)(EFF502(2.5) + J_
\ 10,000 100/
CFR = 3.6 x 106 (Q/H)
TD = TDB * 1^ + ™§W
1.56 1.56
A-4
,
5
-------
TABLE A-l. COST EQUATIONS FOR COAL-FIRED FLUIDIZED
BED COMBUSTION (FBC) BOILERS3 (Continued)
IND * 0.33 TDB + 0-3 Q > 58 6
OB"
IND = 0.237 TDB + " + n > 58 6
Oe
Annual Costs
DL = LF * 123,000 Exp (0.02 * Q) (DLR/12.02) Q <_ 58.6
DL = LF * 397,100 (DLR/12.02) Q > 58.6
SPRV = LF * 62,520 * (SLR/15.63) Q < 15
= LF * 125,040 * (SLR/15.63) Q > 15
MANT = 58,500 * LF * (AMLR/14.63) Q ^_ 15
= 117,000 * LF * (AMLR/14.63) 15 < Q < 50
= 176,000 * LF * (AMLR/14.63) 15 < Q
SP = 157,000 EXP (2.52 x 10"7 (TDB) - 3.8 x 1015 (H))
ELEC = 8,760 (CF) (ELECR) (19.82 Q - 1.78)
WT = 8,760 (CF) (WTRR) (2.06) (Q)
FUEL = 8,760 (CF) (FC) (Q) (3,600)
LMS = 8,760 (CF) (LSFR) * (ALS)
SW = 8,760 (CF) (SWDR) (0.9U0.624 IMS + FUEL /(2.5 (EFFSO,) (S) + A
V LSFR FC I 10,000" TO
A conservative estimate of PCS is:
FCS = 7.605 x 10"5 EFFS02 2.431
algorithm uses metric units as shown in Table A-2.
A-5
-------
TABLE A-2. NOMENCLATURE FOR FBC ALGORITHM
Description
A Ash content (wt. percent)
ALS Limestone Rate (S/hr)
AMLR Maintenance Labor Rate (S/man-hr)
CF Capacity Factor (unit less)
CFR Coal Feed Rate (kg/hr)
CL Limestone Storage Capacity (m3)
Cw Solid Waste Storage Capacity (m3)
DLR Direct Labor Rate (S/man-hr)
EFFS02 S02 Removal Efficiency (percent)
ELECR Electricity Rate (S/kw-hr)
Fc Fuel Cost (S/106 Btu)
FCS Calcium to Sulfur Ratio (unit less)
FUEL Annual Fuel Cost ($/year)
H Heating Value (Btu/lb)
LF Labor Factor (unit less)
LMS Annual Limestone Cost ($/year)
LSFR Limestone Feed Rate
Q Heat Input (106 Btu/hr)
S Sulfur Content (wt. percent).
SLR Supervision Labor Rate (S/man-hr)
SWDR Solid Waste Rate (S/kg)
SWFR Solid Waste Feed Rate (kg/hr)
iL'k Total Direct Boiler Cost (3)
Boiler Turnkey Cost (S)
Limestone Turnkey Cost ($)
TKSW Solid Waste Turnkey Cost ($)
VCL Limestone Storage Cost (S/m3)
vcw Solid Waste Storage Cost (S/m3)
A-6
-------
APPENDIX A REFERENCES
1. Gardner, R., R. Chang, and L. Broz. (Acurex Corporation.) Cost,
Energy and Environmental Algorithms for NO , SCL and PM controls for
Industrial Boilers. Final Report. (Prepared f&r U. S. Environmental
Protection Agency.) Cincinnati, Ohio. EPA Contract No. 68-03-2567.
December 1979. p. 20-52.
2. Myrick, D. T. (Combustion Engineering, Inc.) DOE Cost Comparison
Study: Industrial Fluidized Bed Combustion Vs. Conventional Coal
Technology. (Prepared for U. S. Department of Energy.) FE-2473-T7
January 1980.
3. Devitt, T., P. Spaite, and L. Gibbs. (PEDCo Environmental) Population
and Characteristics of Industrial/Commercial Boilers in the U. S.
(Prepared for U. S. Environmental Protection Agency.) Research
Triangle Park, N. C. EPA-600/7-79-78a. Cincinnati, Ohio. August
1979. 462 p.
A-7
-------
APPENDIX B
SUMMARY OF CAPITAL AND OPERATING COSTS FOR MODEL BOILERS
Model boiler costs for the three S02 control limits examined in this
study are summarized in this appendix. Costs are segregated by boiler, NO
control, S02 control, and PM control equipment and normalized on the basis
of boiler heat input capacity.
B-l
-------
CO
I
TABLE B-l. CAPITAL COSTS OF MODEL BOILERS FOR S02 STANDARD - 1.7 LB/106 BTU
(JANUARY 1983, DOLLARS)
Capital Costs ($1000)
Control
Alternative Hode) Boiler
1A
18
2
3
1A
IB
2
3
IA
IB
2
3
50-FBC. Type H9. 75. 2.75. ff
bO-fBC. Type H. 75. 1.85. ff
'jQ-fGO. Type H. 75. LEAb
60 -CC, Type D. ff . LEAC
100-fBC. Type H. 75. 2.75. ff
100-fBC. Type H. 75. 1.85. ff
100-FGO. Type H. 75 LEA
100-CC. Type 0. 55. LEA
150-FBC. Type M. 75. 2.75, ff
150-fBC. Type H. 75. 1.85. ff
150-fGD. Type H. 75 LEA
IbO-CC. Type 0. ff . LEA
Boiler Control
5.273
5.194
3.716 19
3.515 19
9.823
9,596
7.924 24
'.760 24
13,656
13.345
11.110 29
10.883 29
Control" Control
477
477
1.368
594
922
921
1 .994
1.090
1.273
1 .272
2.498
1 .489
Total
5.750
5.671
5.103
4.128
10,745
10,518
9.942
a. 874
14.929
14.616
13.637
12.401
Normal lied /$100° \
Total { |06 Btu/hr )
115
113
102
83
107
10S
99
89
100
98
91
83
'Boiler slze-teumology. coal type. S02 renoval (percent). N0x control technique.
'Boiler size-technology, coal type, PM control dtvire. N0x control technique.
NO control lullIMSIC to FBC boiler.
x
e
SO., control intrinsic to fBC boiler.
PM control intrinsic to liuie spray drying FGO system.
All coal typtb are bltuoiinaus coals except where noted.
-------
TABLE B-2. CAPITAL COSTS OF MODEL BOILERS FOR S0? CONTROL =° 1.2 LB/106 BTU
(JANUARY 1963. DOLLARS)
CD
I
CO
Capital Costs ($1000)
Control
Alternative Model Boiler
1A
IB
1C
ID
2A
2B
3A
3B
1A
IB
1C
10
2A
2B
3A
3B
1A
50
1C
ID
2A
50-FBC. Type H. 80. 3.2. FF
50-FBC. Type H. 80. 2.2, FF
50-FBC. Type F. 65. 1.95. FF
50-FBC. Type F. 65. 1.25. FF
50-FGO, Type H. 80. LEAb
50-FGO. Type F. 65. LEA
50-CC. Type B. FF. LEAC
50-CC. Type B. FF. LEAh
100-FBC. Type H. 80. 3.2. FF
100-FBC. Type H, 80. 2.2. FF
100-FBC. Type F. 65. 1.95 FF
100-FBC. Type F. 65. 1.25. FF
100-FGD, Type H. 80. LEA
100-FGD. Type F. 65. LEA
100-CC, Type B. FF. LEA
100-CC. Type B. FF. LEAh
150-FBC. Type H. 80, 3.2. FF
150-FBC. Type H. 80. 2.2. FF
150-FBC, Type F. 65, 1.95. FF
150-FBC. Type F. 65. 1.25. FF
150-FGO, Type H. 80, LEA
Boiler
5,313
5.227
5,123
5,087
3,716
3,786
4.831
3,814
10.054
9.651
9.479
9.414
7,924
7,991
8,737
8,006
13,819
13,473
12.925
12.836
11,110
N"x d 5°2 . PHf
Control" Control6 Control
477
477
476
476
19 1.400
19 1.167
19 - 623
19 - 594
922
922
920
920
24 2.041
24 1.713
24 - 1.134
24 - 1 ,090
1.273
1 .272
1,270
1.270
30 2.559
N
Total
5.790
5.704
5,599
5.564
5.135
4,969
5.473
4.427
10.976
10.573
10.400
10.334
9.989
9.728
9,895
9,120
15.092 .
14.745
14.195
14.106
13.699
ormaliicd/'1000 }
Total \106Btu/hr/
116
114
112
111
103
99
109
89
110
106
104
103
100
97
99
91
101
98
95
94
91
-------
TABLE B-2. (CONTINUED) CAPITAL COSTS OF MODEL BOILERS fOR S0? CONTROL * 1.2 LB/106 BTU
(JANUARY 1983. DOLLARS)
oo
I
Capita) Costs ($1000)
Control
Alternative
28
3A
3B
1A
IB
1C
10
2A
2B
3A
3B
1A
IB
1C
10
2A
2B
3A
3B
Model Boiler
150-FGD. Type f , 65. LEA
150-CC. Type B. FF. LEA
150-CC. Type B. FF. LEAh
2bO-FBC. Type H. 80, 3.2. FF
250-FBC, Type II. 80. 2.2. FF
250-FBC. Type F. 65. 1.95. FF
250-F8C. Type F. 65, 1.25. FF
250-FGO. Type H. BO, SCA
250-FGD. Type F. 65. SCA
250-CC, Type 8. FF. SCA
250-CC, Type B. FF. SCAh
400-fBC. Type II. 80. 3.2. Ff
400-FBC. Type H. BO, 2.2. FF
400-FBC. Type F. 65. 1.95. FF
400-FBC. Type F, 65, 1.25, FF
4GO-FCO. Type II. 80, SCA
400-FGO. Type F, 65, SCA
400-CC. Type fl, FF. SCA
400-CC. Type B. FF. SCAh
MX
Bailer Cuntruld
11.206 29
12,253 29
11.228 29
20.373
19,797
19.002
18,837
19.101 89
19,218 89
19,979 89
18,905 89
29.024
28.102
26.957
26.534
26.J41 127
26,502 127
27.403 127
26.144 127
SO, mf
Control Control
2.144
1 .546
-
1.870
1 .869
1.665
1 .865
3.576
2.975
2.201
2.118
2.655
2.652
2.647
2.646
4 .856
4.056
3.129
3.010
Total
13.379
13.828
12.746
22.243
21 .666
20.867
20.702
22.766
22.282
22.269
21.113
31.679
30.754
29.604
29.179
31,324
30.685
30.659
29.281
Normal lied/*1000 \
Total \106fltu/hr/
89
92
85
89
87
83
83
91
89
B9
84
79
77
74
73
78
77
77
73
-------
TABLE B-3. CAPITAL COSTS OF MODEL BOILERS FOR S02 STANDARD = 0.8 LB/106 BTU
(JANUARY 1963, DOLLARS)
CO
I
Capital Costs ($1000)
Control
Alternative Model Boiler
1A
IB
1C
ID
2A
2B
3A
38
1A
IB
1C
10
2A
2B
3A
3B
1A
IB
1C
10
2A
50-FBC. Type H. 90. 4.3, FF
50-FBC. Type H, 90, 2.8, FF
50-FBC, Type F. BO. 3.2, FF
50-FBC. Type F. 80, 2.2. FF
50-FGO. Type H. 90. LEAb
50-FGD, Type F, 80, LEA
50-CC. Type A, FF. LEAC
50-CC. Type B. FF, LEAh
100-FBC, Type H. 90, 4.3, FF
100-FBC. Type H, 90, 2.8, FF
100-FBC. Type F, 80, 3.2. FF
100-FBC, Type F, 80, 2.2. FF
100-FGO, Type H, 90. LEA
100-FGD. Type F. 80, LEA
100-CC, Type A, FF, LEA
100-CC, Type A. FF. LEAh
150-FBC, Type H, 90. 4.3. FF
150-FBC, Type H, 90, 2.8, FF
150-FBC. Type F, 80, 3.2. FF
150-FBC. Type F. 80. 2.2, FF
150-FGD, Type H, 90, LEA
Boiler
5.404
5.283
S.1B7
5.138
3.716
3,786
4,831
3,545
10,317
9,971
9,593
9,507
7,924
7,991
8,737
8.013
14,214
13,695
13,212
12,962
11,110
"°x d », fi nf
Control Control Control
478
477
476
476
19 1,480
19 1,226
19 - 623
19 - 594
923
922
921
921
24 2,163
24 1,797
24 - 1,134
24 - 1 ,090
1.275
1.273
1,271
1.271
30 2,717 •
N
Total
5,881
5,760
5,664
5,615
5,215
5.028
5.473
4,157
11,240
10,893
10,514
10,428
10.111
9,812
9,895
9,127
15,488
14 ,968
14.483
14.232
13.857
ormaliicd/*1000 \
Total ^106 Btu/hr/
118
115
113
112
104
101
109
83
112
109
105
104
101
98
99
91
103
100
96
95
92
-------
TABU B-3. (CONTINUED) CAPITAL COSTS Of HODEL BOILERS FOR S02 STANDARD = 0.8 IB/106 BTU
(JANUAHY J9B3. DOLLARS)
CD
cn
Capital Costs ((1000)
Control
Alternative Model Boiler
2B
3A
38
1A
IB
1C
10
2A
2B
3A
38
1A
IB
1C
ID
2A
26
3A
36
150-FGO. Type F, 80. LEA
150-CC, Type A. FF. LEA
150-CC. Type A. FF. LEAh
250-FBC, Type II. 90. 4.3, FF
250-F8C. Type H, 90. 2.8, FF
250-FBC. Type F. 80, 3.2. FF
260-FBC. Type F. 80, 2.2. FF
250-FGD. Type H. 90. SCA
250-FGD. Type F. BO. SCA
2SO-CC. Type A. FF. SCA
250-CC. Type B. FF. SCAh
400-FBC. Type II. 90. 4.3. FF
400-FBC, Type H. 90. 2.8. FF
400-FBC. Type F. 80. 3.2, FF
400-FBC. Type F. 80. 2.2. FF
400-FGO. Type II. 90. SCA
400-FGO. Type_F. 80. SCA
400-CC. Type A. Ff. SCA
400-CC. Type A. FF. SCAh
Bollerd
11.206
12.253
11.239
21.031
20.167
19.479
19.181
19.101
19,218
19.979
18.923
30.077
28.694
27.582
27.106
26.341
26.502
27.403
26.172
Control6 Control Control
29 2.251
29 - 1.546
29 - J.489
1.873
1.870
1.867
1 .866
89 3,807
89 3.12S
B9 - 2.201
89 - 2.118
2.658
2.654
2.649
2,647
127 5.175
127 4.258
127 - 3.129
127 - 3.010
Total
13.486
13.828
12.757
22.904
22.037
21.346
21.047
22.997
22.432
22.269
21.130
32.735
31.348
30.231
29.754
31.643
30.867
30,659
29,309
Normal tied /*1000 \
Total Vl06Btu/hr/
90
92
85
92
88
85
84
92
90
89
85
82
78
76
74
79
77
77
73
-------
TABLE B-4. ANNUAL COSTS OF MODEL BOILERS FOR S0? STANDARD =° 1.7 LB/10° BTU
(JANUARY 1983. DOLLARS)
DO
I
Annual Costs ($1000)
Control
Alternative
1A
18
2
3
1A
IB
I
3
1A
IB
2
3
Model Boiler
50-FBC. Type H. 75. 2.75, FF
50-FBC, Type H, 75. 1.85, Ff
50-FGO, Type H, 75, LEAb
50-CC, Type D. FF, LEAC
100-FBC. Type H, 75, 2.75, FF
100-FBC. Type H. 75, 1.85, FF
100-FGO. Type H, 75 LEA
100-CC, Type D. FF, LEA
150-FBC. Type H, 75, 2.75, FF
150-FBC, Type H. 75, 1.85. FF
150-FGD. Type H, 75 LEA
150-CC, Type D. FF. LEA
Boiler
2,139
2.105
1.778
1.923
3.981
3.901
3.299
3.661
5.622
5,507
4.649
5.196
NOX S02 pMt
Control*1 Control8 Control
139
137
-2 506
-4 - 157
247
244
-6 726
-10 - 280
339
335
-11 916 0
-16 - 382
Total
2. 278
2.243
2,282
2.076
4,228
4.145
4,019
3,931
5.961
5.841
5,554
5,562
Normalized
Total
$/106 Btu
8.4
8.3
8.7
7.6
8.1
7.9
7.6
7.1
7.6
7.4
7.0
7.1
-------
TABIt B-b. ANNUAL CObfS OF MOOFl BOILFRS FOK SO STANDARD - 1.2 IB/106 BIU
(JANUARY 1983, OOLLAHS)
CO
I
00
— • — ' ' —
Con t nil
Alternative Model Builer
IA
IB
1C
IP
2A
28
3A
3B
IA
IB
1C
ID
2A
2B
3A
3B
IA
111
1C
10
2A
bO-FBC. Type II, BO. 3.2. FF
'jO-FBC. lypu II, BO. 2.2. FF
50-FBC. Type F. 65. 1.95. FF
iO-FBC, Type F, 66. 1.25. FF
50-FGO. Type II. BO. llKb
50-FCO. Type F. 65. IF. A
50-CC. Type B. FF. L£AC
50-CC. Type B, FF. LEAh
100-FBC. Type H. BO. 3.2, FF
100-FBC. Type II. 80. 2.2. Ff
100-FBC. Type F. 65. 1.95. FF
100-FBC. Type F. 65. 1.25. FF
100-FGD. Type II, BO. UA
100-FGD. Type F. 65. LEA
100-CC. Type B. FF. LCA
IIMJ-CC. lype B, II . LLA1'
I'jO-fBC. lype II. 80. 3.2. FF
IbO-FUC. lype II. BO. 2.2, FF
IbO-FBC. Type F. 65. 1.95. FF
IbO-FUC. Type f . 65, 1.25. FF
150-FGO. Type H. BO. LLA
Annual Coits (t 11)00)
N°x a 'W~
BuiK'r Control Control6
2.157
2.120
?.I9I .
2.177
1.778 -2 525
1.912 -3 421
2.105 -3
2.007 -4
4.043
3.928
4,076
4.049
3.299 -6 760
3,555 -9 57B
3.62'J -8
3./J-, -U
5 .683
5.555
5.728
5.688
4.649 -J| 966
PHf
Control
140
138
135
135
-
-
164
157
248
245
240
239
-
-
294
280
341
336
328
327
-
Totdl
2,297
2.258
2.326
2.312
2.301
2,330
2.266
2.160
4.291
4.173
4.316
4.287
4.053
4,124
3.915
4.004
6.024
5.891
6,056
6.014
5,604
Noruulued
Totdl
$/106 Btu
8.7
8.6
B.9
8.8
8.8
8.9
8.6
8.2
8.2
7.9
8.2
8.2
7.7
7.8
7.4
7.6
7.6
7.5
7.7
7.6
7.1
-------
TABLE B-5. (CONTINUED) ANNUAL COSTS OF MODEL BOILERS FOR S02 STANDARD - 1.2 LB/106 BTU
(JANUARY 1983. DOLLARS)
CO
I
vo
Annual Costs ($1000)
Control
Alternative Model Boiler
2B
3A
36
1A
IB
1C
ID
2A
2B
3A
3B
1A
IB
1C
ID
2A
2B
3A
3B
150-FGO. Type F. 65. LEA
150-CC. Type B. FF. LEA
150-CC. Type B. FF. LEAh
250-FBC. Type H. 80. 3.2. FF
250-FBC. Type H. 80. 2.2. FF
250-FBC. Type F, 65, 1.95. FF
250-FBC. Type F. 65. 1.25. FF
250-FGO. Type H. 80. SCA
250-FGD. Type F, 65, SCA
250-CC. Type B. FF, SCA
250-CC. Type B. FF. SCAh
400-FBC. Type H. 80. 3.2. FF
400-FBC, Type H. 80. 2.2. FF
400-FBC. Type F. 65. 1.95. FF
400-FBC. Type F. 65, 1.25. FF
400-FGD. Type H. 80, SCA
400-FGD, Type F, 65, SCA
400-CC, Type B, FF, SCA
400-CC. Type B. FF. SCAh
Boiler
5,033
5,131
5.302
9,001
8,787
9,097
9.028
8.098
8,691
8,697
9.080
14.548
14,206
14,740
14,600
11.761
12.768
12,708
13,415
"°x d *>2 pMf
Control Control Control
-14 708
-14 - 402
-17 - 382
509
502
488
486
58 1 ,388
60 972
60 - 585
570
745
733
712
708
90 1 ,959
92 1.323
92 - 856
835
Total
5.727
5.319
5,667
9.510
9.289
9.586
9,513
9,504
9,723
9.332
9.709
15.293
14,939
15.451
15,308
13,810
14.183
13.656
14.342
Normalized
Total
$/106 Btu
7.3
7.0
7.2
7.2
7.1
7.3
7.2
7.2
7.4
7.1
7.4
7.3
7.1
7.3
7.3
6.6
6.7
6.5
6.8
-------
TABU 8-6. ANNUAt COSTS OF MODEL BOILERS FOR S0? STANDARD = 0.8 lfl/106 BTU
(JANUARY 1983. DOLLARS)
03
I
Control
Alternative
1A
IB
1C
ID
2A
28
3A
3B
1A
IB
1C
ID
2A
2B
3A
3B
1A
IB
1C
ID
2A
Hodel Boiler
50-FBC, Type H. 90, 4.3, Ff
60-FBC. Type H. 90, 2.B. FF
50-FBC. Type F. 80. 3.2. FF
50-FBC. Type F. BO. 2.2. FF
50-FGO. Type H. 90. LEAb
50-FGD, Type F. 80, UK
50-CC. Type A. FF, LEAC
50-CC. Type A. FF. LEAh
100-FBC. Type II. 90, 4.3. FF
100-FBC. Type H. 90. 2.8. FF
100-FBC, Type F, 80, 3.2. FF
100-FBC, Type F, 80. 2.2. FF
100-FGO, Type H, 90. LEA
100-FGO. Type F. 80. LEA
100-CC. Type A. FF. LEA
1UO-CC. Type A, FF, LEA1'
150-FBC. Type H. 90. 4.3. FF
150-FBC. Type H, 90. 2.8. FF
150-FBC. Type F. 80. 3.2. FF
150-FBC, Type F, 80. 2.2, IT
150-FGD. Type H, 90, LEA
Annual Costs (11000)
NO, Sd2
Boiler Control*1 Control6
2.200
2.144
2,218
2,198
1 .778 -2 579
1.912 -3 449
2,105 -3
1 ,987 -4
4,142
4.013
4,128
4,089
3,299 -6 861
3,555 -9 627
3.629 -8
3.B20 -11
5.831
5.639
5,827
5.746
«."9 -11 1,113
fvf
Control
141
139
136
136
-
-
164
157
252
247
242
240
-
-
294
280
346
340
332
329
-
Total
2,341
2,284
2.355
2,334
2.355
2.358
2.266
2,140
4.393
4.261
4.370
4.330
4.154
4.173
3.915
4.088
6.177
5.978
6.159
6,076
5.751
Normalized
Total
1/106 Btu
8.9
a. 7
9.0
8.9
9.0
0.9
8.3
a.i
8.4
B.I
8.3
8.3
7.9
7.9
7.4
7.8
7.8
7.6
7.8
7.7
7.3
-------
TABLE B-6. (CONTINUED) ANNUAL COSTS OF MODEL BOILERS FOR S02 STANDARD = 0.8 LB/10b BTU
(JANUARY 1983, DOLLARS)
CO
I
Annual Cost:, ($1000)
Control
Alternative Model Boiler
2B
3A
3B
1A
IB
1C
ID
2A
2B
3A
3B
1A
IB
1C
ID
2A
2B
3A
3B
150-FGO. Type F. 80, LEA
150-CC. Type A. FF, LEA
150-CC, Type A, FF, LEAh
250-FBC. Type H, 90. 4.3, FF
250-FBC, Type H, 90, 2.6, FF
250-FBC, Type F, 80, 3.2, FF
250-FBC, Type F. 80, 2.2, FF
250-FGO, Type H. 90. SCA
250-FGD, Type F. 80, SCA
250-CC, Type A, FF, SCA
250-CC. Type A, FF, SCAh
400-FBC, Type H. 90. 4.3, FF
400-FBC. Type H, 90, 2.8. FF
400-FBC, Type F, 80, 3.2, FF
400-FBC. Type F. 80. 2.2, FF
400- FGO, Type H. 90, SCA
400-FGD. Type F, 80. SCA
400-CC. Type A. FF. SCA
400-CC. Type A. FF, SCAh
Boiler
5.033
5,131
5,429
9.248
8,927
9.259
9,149
8,058
8,691
8,687
9,292
14,943
14,429
14.975
14.798
11.761
12.768
12,708
13,754
N0x S0? PM'
Controld Control6 Control
-14 778
-14 - 402
-19 - 382
518
507
494
490
58 1,627
60 1 ,083
60 - 585
60 - 570
759
742
720
714
90 2,332
92 1 ,494
92 - 3.119
93 - 835
Total
5.797
5,519
5,793
9.765
9,434
9.753
9,638
9,743
9,834
9,332
9,922
15,702
15.171
15,695
15,512
14.183
14.354
15,929
14.682
Normalized
Total
$/106 Btu
7.4
7.0
7.3
7.4
7.2
7.4
7.3
7.4
7.5
7.1
7.6
7.5
7.2
7.5
7.4
6.7
6.8
6.5
7.0
-------
APPENDIX C
ADJUSTMENTS TO INDEPENDENT COST ESIMTATES
This appendix summarizes details of the adjustments that have been made
to FBC cost estimates developed by independent workers. The purpose of the
adjustments was to place all estimates on a common design and scope basis so
that fair comparisons can be made among them.
C.I COMBUSTION ENGINEERING, INC. ESTIMATE
This estimate is derived from a report which projects costs for a new
FBC boiler located in Ft. Wayne, Indiana producing 250,000 Ib/hr steam at
900 psig and 7SQ°F.1 Two FBC designs are considered in this study: (1) Two
shop assembled, rail-shippable units rated at 125,000 Ib/hr, and (2) a
single field assembled unit producing 250,000 Ib/hr steam. Since the FBC
algorithm specifies dual boilers for this size (352 million Btu/hr input),
the first case was selected for comparison. The CE estimate is based on
detailed equipment designs and layout and internal cost files. Other
important factors in the CE system design include:
Air emission standards:
1.2 Ib S02/106 Btu plus 85 percent reduction
0.5 Ib NOX/106 Btu
0.03 Ib PM/106 Btu plus 99 percent reduction
Coal: Midwest bituminous, 10,430 Btu/lb, 3.5 percent sulfur, 9.2
percent ash
Coal and limestone handling:
Coal - crushing, drying, and 2 days prepared coal storage
C-l
-------
Limestone: 4 days storage of crushed and sized limestone,
1/8 inch particle size
- Solid waste disposal: landfilled at a site adjacent to the plant,
6 days on-site storage
Ca/S Ratio: 3.0
Mid-1979 cost basis
Load factor of 0.68
Boiler efficiency of 84 percent
Table C-l shows the major adjustments made to the CE estimates to
achieve compatibility with FBC algorithm projections. These adjustments
resulted in a total capital cost of $37,473,000 and a total annual cost of
$13,268,000/year.
C-2 FOSTER WHEELER ESTIMATE
The FW estimate corresponds to new industrial FBC boiler generating
212,000 Ib/hr of steam at 650 psig and 750°F.2 Costs are estimated for both
Western and Eastern coal operation; only the Eastern coal costs are
presented here. The specified coal feed rate and heat content correspond to
291 million Btu/hr heat input. The FW estimate was developed from detailed
equipment designs and internal cost files. Other particulars of the FW
estimate include:
Air emission standards:
1.2 lb S02/106 Btu
0.5 lb N0x/106 Btu
0.03 Ib PM/105 Btu
C-2
-------
TABLE C-l. MAJOR ADJUSTMENTS TO THE COMBUSTION ENGINEERING COST BASIS
1. Contingencies on new product design were subtracted from total
delivered capital costs; re-estimated at 20 p9ercent of direct plus
indirect costs.
2. Land costs (for landfill adjacent to boiler site) were subtracted
except for $6000.
3. A load factor of 0.6 (as opposed to 0.68) was used to determine annual
costs; a labor factor of 0.75 was applied.
4. Capital costs were updated from June, 1979 to January, 1983 using the
Chemical Engineering Plant Cost Index.
5. Table 6.1-4 unit costs were utilized to update O&M costs.
6. The algorithm cost basis was used for working capital, overhead, and
capital charge estimation.
C-3
-------
Coal: Eastern bituminous, 11,026 Btu/lb, 3.6 percent sulfur, 10.3
percent ash.
Limestone handling: truck delivery, 7 days storage
Solid waste disopsal: hauled by truck to offsite storage
Ca/S ratio: 2.5
December 1980 cost basis
Gulf coast location
Boiler efficiency of 85 percent
The major adjustments made to the FW estimate to achieve compatibility
with the FBC algorithm projections are summarized in Table C-2. These
adjustments translated to a total capital cost of $31,110,000 and a total
annual cost of $12,250,000. It should be noted that the extensive list of
adjustments listed in Table C-2 is due primarily to scope and plant boundary
differences between the FW and ITAR estimates, particularly as they effect
ancillary equipment. After adjusting costs to a common basis with respect
to time of construction, location, and size, the direct capital cost
difference for major equipment items (including the boiler fans, ducts,
mechanical collector, baghouse, stack, feeders, crushers, limestone handling
and storage system, spent solids/ash handling and storage system, and
instrumentation) was lass than eight percent.
C.3 WESTINGHOUSE ESTIMATE
Westinghouse has estimated FBC capital and operating costs for new
industrial boilers over a range of boiler sizes, coal types, and final
emission levels. For comparison purposes, the Westinghouse case
C-4
-------
TABLE C-2. MAJOR ADJUSTMENTS TO THE FOSTER WHEELER COST BASIS
1. A load factor of 0.6 (as opposed to 0.9) was used to determine annual
costs; a labor factor of 0.75 was applied.
2. Guard labor was subtracted from operating labor requirements.
3. Capital costs were adjusted from a Gulf coast to Midwest basis using a
factor of 1.028.
4. Capital costs were updated from December 1980 to January 1983, using
the Chemical Engineering Plant Cost Index.
5. Table 6.1-4 unit costs were utilized to update O&M costs.
6. The algorithm cost basis was used for land, working capital, overhead,
and capital charge estimation.
7. Substituted ITAR coal handling system costs for FW costs since FW
design basis included live storage, dead storage, and reclaim
equipment. This design basis was significantly more elaborate than the
ITAR basis.
8. Substituted ITAR makeup water treatment and chemical feed system costs
for FW costs since FW estimate assumed 50 percent makeup water
requirement while the ITAR design basis assumed a 20 percent
requirement. More importantly, the FW design basis includes a
wastewater treatment system which process the following streams:
Rainwater runof from paved areas and coal pile.
Boiler blowdown.
Demineralized regeneration systems.
Sanitary waste.
This equipment is not included within the ITAR plant boundaries.
9. Substituted ITAR cost estimates for the deaeration, boiler feed pumps,
and condensate system in place of the FW estimate due to significant
differences in design basis.
10. Substituted ITAR cost estimates for buildings and support facilities in
place of the FW estimates due to significant differences in scope.
11. Added a 20 percent allowance for contingencies to the FW capital cost
estimate.
C-5
-------
corresponding to 200 million Btu/hr boiler achieving 80 percent S02 removal
on a high sulfur Eastern coal has been selected. Three boiler modules are
specified for this case. Costs for the boiler and solids (coal, limestone,
and bed drain) handling are based on Westinghouse cost files; costs for PM
control equipment come from literature sources; costs for boiler
auxiliaries are based on PEDCo estimates. Important design factors in the
Westinghouse estimate include:
Air emission standards:
1.2 Ib S02/106 Btu
0.5 Ib NOX/106 Btu
0.03 Ib PM/106 Btu
Steam conditions: 110 psig at 750°F
Coal: Eastern bituminous,. 11,800 Btu/lb, 3.5 percent sulfur, 10.6
percent ash.
Coal and limestone handling: Not specified but assumed to be
consistent with FBC-ITAR.
Ca/S ratio: 2.09
June 1978 cost basis
Mid-west location
Boiler efficiency of 84.3 percent
The Westinghouse cost basis is consistent, for the most part, with the
ITAR basis. Five modifications to the .W estimate were required to achieve
consistency with the FBC algorithm basis, as shown in Table C-3. After
C-6
-------
TABLE C-3. MAJOR ADJUSTMENTS TO THE WESTINGHOUSE ESTIMATE
1. A labor factor of 0.75 was applied to operating, supervisory, and
maintenance labor costs.
2. An allowance for performance tests (1 percent of total direct costs)
was added.
3. Capital costs were updated from June 1978 to January 1983 using the
Chemical Engineering Plant Cost Index.
4. O&M costs were updated using the unit costs of Table 6.1-4.
5. The algorithm cost basis was used to estimate working capital,
overhead, and capital charges.
C-7
-------
making these adjustments, the Westinghouse capital cost estimate amounts to
316,760,000; the total annual estimate is $7,579,000/year.
C.4 POPE, EVANS AND R08BINS ESTIMATE
PER estimated the costs for new FBC boilers at six locations in the
Northeast and Midwest to replace existing oil/gas fired boilers.4 Although
costs for cogeneration of steam and electric power were also calculated,
only steam generation costs are used for comparison purposes. Heat inputs
to the plants were not specified but were estimated from the steam rate,
steam conditions, and an assumed boiler efficiency of 85 percent. The case
selected for comparison generates 280,000 Ib/hr steam at 325 psig
(saturated) for an equivalent heat input of 325 million Btu/hr. A Midwest
location is assumed. Other particulars of the design basis include:
Air emission standards: Not specified but assumed to be NSPS for
boilers capacities greater than 250 million Btu/hr.
Three boilers are specified, each rated at 50 percent of total
capacity.
1979 cost basis.
Insufficient information was provided in the PER estimate description
to make adjustments for annual costs. Major adjustments to the PER capital
costs to achieve consistency with the FBC algorithm cost basis are
summarized in Table C-4. These adjustments resulted in a total capital cost
estimate of 331,365,000.
C.5 JOHNSTON BOILER COSTS
JB provided actual installed costs for a 50 million Btu/hr FBC unit
operating on Ohio 3.2 percent sulfur coal and controlling SO- emissions to
C-8
-------
TABLE C-4. MAJOR ADJUSTMENTS TO THE POPE, EVANS AND ROBBINS ESTIMATE
1. Capital cost basis was adjusted to two boilers instead of three as
specified.
2. Capital costs were updated from mid-1979 to January 1983 using the
Chemical Engineering Plant Cost Index.
C-9
-------
2.6 lb S02/10 Btu with limestone.5 The boiler delivers 50,000 15 steam/hr
at 120 psig.
JB provided installed equipment costs for the FBC boiler, baghouse,
instrumentation, and auxiliaries. These costs were within 13 percent of the
algorithm estimate for a similar boiler. A total capital cost estimate of
$4,867,000 was developed by adding algorithm estimates for indirect costs,
contingencies, land, and working capital to the JB installed equipment
costs. No other adjustments are necessary as the JB costs conform to a
December 1982 basis.
Insufficient information was provided with the JB cost description to
make adjustments for annual costs.
C-10
-------
APPENDIX C REFERENCES
1. Myrick, D. T. (Combustion Engineering, Inc.) DOE Cost Comparison Study:
Industrial Fluidized Bed Combustion VS. (Conventional Coal Technology.
(Prepared for U. S. Department of Energy.) FE-2473-T7. January 1980.
2. Foster Wheeler Development Corporation. Industrial Steam Supply System
Characteristics Program, Phase 1, Conventional Boilers and Atmospheric-
Fluidized-Bed Combustor. (Prepared for Oak Ridge National Laboratory,
U. S. Department of Energy). ORNL/Sub-80/13847/1. August 1981.
3. Ahmed, M. M., D. L. Keairns, and R. A. Newby (Westinghouse Research and
Development Center). Effect of Emission Control Requirements on
Fluidized-Bed Boilers for Industrial Applicators: Preliminary
Technical/Economic Assessment. (Prepared for U. S. Environmental
Protection Agency.) EPA-600/7-81-149. September 1981.
4. Mesko, J. E. (Pope, Evans and Robbins Inc.). Economic Evaluation of
Fluidized Bed Coal Burning Facilities for Industrial Steam Generation.
The Proceedings of the Sixth International Conference on Fluidized Bed
Combustion, Volume II. Atlanta, Georgia. August 1980.
5. Letter from Virr, M. J., Johnston Boiler Company, to Aul, E. F., Radian
Corporation. November 18, 1983. FBC boiler cost study.
C-ll
-------
APPENDIX D
BASES FOR COST ESTIMATES
D.I COSTING METHODOLOGY
Costs for model boilers have been developed on the basis of
construction and operation in the Midwest region of the U.S. Although the
absolute costs for model boilers and various S02 control alternatives will
vary from region to region, the cost differentials between alternatives are
not expected to differ significantly on a regional basis. For the purposes
of this report, costs have been developed for the Midwest region only.
All costs in this report are presented on a January 1983 basis, except
where noted.
The costs of each model boiler can be broken down into three major cost
categories:
- Capital Costs (total capital investment required to construct
and make operational a boiler and control system),
- Operation and Maintenance (O&M) costs (total annual cost
necessary to operate and maintain a boiler and control
system), and
- Annualized Costs (total O&M costs plus capital-related
charges).
Each of these cost categories can be further subdivided into individual cost
components.
Capital Costs
Table D-l presents the individual capital cost components and the
general methodology used for calculating total capital costs. The plant
boundaries include inlets to coal and sorbent storage, boiler feedwater
inlet to the economizer, steam outlets from the steam generator, on-site
D-l
-------
TABLE 0-1. CAPITAL COST COMPONENTS3
(1) Direct Costs
Equipment
+ Installation
- Total Direct Costs
(2) Indirect Costs
Engineering - 10% of direct costs for boilers and PM controls5
coLrfinf %°?rS°i-erS <2°°X 1Q Btu/hr' FGD engineering
costs are 10% of FGD direct costs for an FGD system that is
applied to a 200 x 105 Btu/hr boiler.
rn^J^nfV" b°Uers >200 * ™ Btu/hr, FGD engineering
costs are 10% of specific FGD system's direct costs.
rC°"S^]ln £lF1eld Expenses (10? °f ^>ect costs)5
(10% of direct costs)
* tart Up Costs \2% 0°f %™% %*£ b
+ Performance Costs (i% of direct costsjc
= Total Indirect Costs
(3) Contingencies5 = 20% of (Total Indirect + Total Direct Costs)
(4) Total Turnkey Cost = Total Indirect Cost + Total Direct Cost +
Contingencies
(5) Working Capital1 = 25% of Total Direct Operating Costsd
(6) Land8 .
(7) Total Capital Cost = Total Turnkey + Working Capital + Land
Boiler and each control system costed seoarately; factors apolv tc '-ost of
boiler^or control system considered; i.e., the engineerina cost for%he PM
control system is 10% of the direct cost of the PM control system.
Reference 1.
Reference 2.
This equation is used for control device working capital calculations
For boilers, fuel supplies are included so a different equation is used
\S66 IdDlS D™2 j »
Land costs are assumed to apply to boilers only.
0-2
-------
spent solids storage outlets, and the stack outlet. The costs for the steam
and condensate return lines from the process area are not included. Battery
limits of the emissions control systems include the control devices
themselves, raw material handling, temporary waste storage, and any
additional ducting required.
Direct capital costs consist of the basic and auxiliary equipment costs
in addition to the labor and material required to install the equipment.
Indirect costs are those costs not attributable to specific equipment items.
Other capital cost components are contingencies, the cost of land, and
working capital.
Contingencies are included in capital costs to compensate for
unpredicted events and other unforeseen expenses. Costs for land are
included in boiler capital costs but not in control system costs. All
boilers except pulverized coal boilers are assumed to have land costs of
$2,800. Pulverized coal boilers are assumed to have land costs of SSJOO.1
The computation of working capital in this analysis also differs
slightly between boilers and control equipment. The equations shown in
Table D-2 are used to calculate the cost for working capital. These
equations are based on three months of direct annual non-fuel operating
costs and one month of fuel costs.
Operation and Maintenance (O&M) Costs
Table D-3 lists the individual O&M cost components and the general
methodologies used in calculating total O&M costs. Direct O&M costs include
operating and maintenance labor, fuel, utilities, spare parts, supplies,
waste disposal and chemicals. Indirect operating costs include payroll and
plant overhead and are calculated based on a percentage of some key O&M cost
components (e.g. direct labor, supervisory labor, maintenance labor and
spare parts).
D-3
-------
TABLE D-2. WORKING CAPITAL CALCULATIONS FOR BOILERS AND CONTROL DEVICES
Working Capital (WC)
Boilers - Assume three months of direct annual non-fuel operatinq costs
an uye'aung costs
and one month of fuel costs
=0°0fl5 /Direct annual non-fuel operating costs) +
Control Equipment - Assume three months of direct annual operating costs
WC
0.25 (Direct annual operating costs)
Reference 3.
Reference 1.
D-4
-------
TABLE D-3. OPERATING AND MAINTENANCE COST COMPONENTS3
(1) Direct Operating Costs
Direct Labor
+ Supervision
+ Maintenance Labor, Spare Parts and Supplies
+ Electricity
+ Water
+ Steam
+ Waste Disposal
Solids (Fly ash and bottom ash)
Sludge
Liquid
+ Chemicals
Total Non-Fuel O&M
+ Fuel
= Total Direct Operating Costs
(2) Indirect Operating Costs (Overhead)13
Payroll (30% Direct Labor)
+ Plant (26% of Direct Labor + Supervision + Maintenance Costs +
Spare Parts)
(3) Total Annual Operating and Maintenance Costs = Total Direct +
Total Indirect Costs
Boilers and each control systems are costed separately; factors apply to
boiler or control system being considered, (i.e., payroll overhead for
FGD system is 30% of the direct labor requirement for the FGD system).
Factors recommended in Reference 4.
D-5
-------
The key factors used in calculating annual O&M costs are the system
capacity utilization, utility unit costs (steam, electricity, water), and
unit costs for raw materials, waste disposal, and labor. Capacity
utilization is defined as the actual annual fuel consumption as a percentage
of the potential annual fuel consumption at maximum firing rate. Table 0-4
presents the utility and unit costs used in calculating annual O&M costs for
the boilers and control equipment.
The largest O&M cost for boilers is fuel. Table 6.1-3 presents the
specifications and costs for the fuels used in this analysis. To maintain
consistency with the Industrial Fuel Choice Analysis Model (IFCAM), which is
used to project the national impacts of alternative SO- standards, the
values in Table 6.1-3 are projections for 1990 delivered fuel prices
expressed in January 1983 dollars.7'8 These projections ignore the effects
of inflation but assume that fuel prices will escalate in real terms. In
addition, the fuel prices have been "levelized" over the life of the boiler
(i.e., an equivalent constant price has been calculated after allowing for
escalation and the time value of money).
Annualized Costs
Total annualized costs are the sum of the annual O&M costs and the
annualized capital charges. The annualized capital charges include the
payoff of the capital investment (capital recovery), interest on working
capital, general and administrative costs, taxes, and insurance.
Table D-5 presents the methods used in this report to calculate the
individual annualized capital changes components. The capital recovery cost
is determined by multiplying the capital recovery factor, which is based on
the real interest rate and the equipment life, by the total turnkey costs
(see Table D-l). For this analysis, a 10 percent real interest rate and a
15 year equipment life are assumed for the boilers and control equipment.
This translates into a capital recovery factor of 13.15 percent. The real
0-6
-------
TABLE D-4. UNIT COSTS USED IN MODEL BOILER CALCULATIONS3
Utilities
Electricity 0.0503/kwhb
Water 0.0396/m3 ($0.15/103 gal)c
Steam $3.5/103 lbd
Raw Materials
Na2C03 $0.169/kg ($153/ton)c'e
Lime $0.098/kg ($89/ton)c'e
Limestone $0.013/kg ($8.5/ton)c
Labor
Direct Labor $11.75/man-hourf'g
Supervision $15.28/man-hourh
Maintenance Labor SH.SVman-hour1
Waste Disposal
Solids (Ash, Spray Dried Solids) $0.198/kg ($18/ton)J'h
Sludge $0.0198/kg ($18/ton)j
aAll costs in January 1983 $.
Monthly Energy Review, April 1983.
TVA, Technical Review of Dry FGD Systems and Economic Evaluation of Spray
Dryer FGD Systems, February 1982.
EPRI, Technical Assessment Guide, May 1982.
G
Updated using ratio of commodity chemical price for January, 1983 to June,
1982 as given in the Chemical Marketing Reporter.
Monthly Labor Review April, 1982.
9Average of wate rates for Chemical and Allied Products and Petroleum and
Coal Products categories.
Estimated at 30 percent over direct labor rate.
Estimated at 22 percent over direct labor rate.
JAverage of waste disposal rates from EPA, Economics of Ash at Coal Fired
Power Plants, Oct. 1981, and EEA, Estimated Landfill Credit for Non-Fossil
Fueled Boilers, October, 1980. ~ '
0-7
-------
TABLE D-5. ANNUALIZED COST COMPONENTS
(1) Total Annual ized Cost = Annual Operating Costs + Capital Charges
(2) Capital Charges = Capital recovery + interest on working capital +
miscellaneous (G&A, taxes and insurance)
(3) Calculation of Capital Charges Components
A. Capital Recovery = Capital Recovery Factor (CRF) x Total Turnkey
UO S u
CRF
i = interest rate
n = number of years of useful life of boiler or control system
n j CRF
Boiler, control systems 15 10 0.1315
B. Interest on Working Capital = IQ% of working capital
C. G&A, taxes and insurance = 4% of total turnkey cost
D-8
-------
interest rate of 10 percent was selected as a typical constant dollar rate
of return on investment to provide a basis for calculation of capital
recovery charges. This interest rate is the "real" interest rate above and
beyond inflation.
Table D-5 also presents the methods to calculate the other annualized
capital charges components. Interest on working capital is based on a
10 percent interest rate. The remaining components (general and administra-
tive costs, taxes, and insurance) are estimated as 4 percent of total
turnkey costs.
D.2 BOILER AND CONTROL COST PARAMETERS
Capital and annualized costs for model boilers and PM, NO , and S02
control techniques are estimated in this report by the use of cost
"algorithms". Each algorithm is an algebraic function which projects
capital and annual costs for a particular system based on key process
parameters (e.g., heat input to boiler, S02 removal efficiency, capacity
utilization factor, flue gas flow rate). The algorithms have been
computerized to allow rapid and accurate cost calculations over a wide range
of boiler/control system size ranges and operating conditions. Summary
information describing the boiler and emission control costing algorithms
used in this report is presented in Table D-6. A complete listing of the
algorithms is provided in Appendix A and Reference 21. The specific
equipment lists and assumptions used to develop the various algorithms are
discussed in the following sections.
Boiler Costs
This section presents the specific cost assumptions and methodologies
that were used to calculate the industrial boiler costs presented in Section
6.0. References 9 and 10 detail the specific equipment lists and
assumptions used to develop the boiler algorithms presented in Appendix A
and Reference 21 .
D-9
-------
TABLE D-6. SUMMARY OF BOILER AND EMISSIONS CONTROL COSTING ALGORITHMS
Abbreviation Algorithm Type f/
UNDR Boiler, underfeed stoker, watertube, package
SPRD Boiler, spreader stoker, watertube, field-
erected
PLVR Boiler, pulverized coal, watertube, field-
erected
FBC Boiler, fluidized bed,
shop fabricated
FF Fabric filter applied
DS Lime spray drying (dry
watertube,
to coal -fired boiler
scrubbing) FGD system
LEA Low excess air operation for NO control
SCA Staged combustion air
Krt T 1 A v»e»
applied to coal-fired
Boiler Size
Applicability
!W (10° Btu/hr)
<22 (<75)
18
(60
>58
8.8
(30
8.8
(30
All
All
>44 •
- 58
- 200)
120°)
- 117.2
- 400)
- 204
- 700)
sizes
sizes
(±150)
0-10
-------
As mentioned previously, the capacity utilization factor and labor
factor are used to adjust O&M costs for boiler operation at less than full
capacity. The factors used in this report are summarized in Table D-7.
These factors are considered representative of industrial boiler operation,
and are supported by information in References 3 and 11. The capacity
utilization and labor factors shown in Table D-7 are also used to adjust O&M
costs for PM, N0x, and S02 controls.
The boiler specifications presented in Table D-8 have been used to
calculate the conventional boiler capital costs presented in this report.
It is assumed that all boilers are operating under low excess air firing
conditions. The flue gas flow rates presented were calculated from
applicable algorithms.
2.3.2 Particulate Matter (PM) Control Costs
The algorithms used to calculate capital and operating costs for PM
control devices are presented in Reference 21. The cost algorithms for
reverse-air fabric filters were developed by PEDCo, Inc. Detailed
documentation of the cost bases for these controls can be found in PEDCo1s
12 13
final report. ' Table 0-9 lists the general specifications for the PM
control devices investigated. These specifications are typical for
industrial boiler control devices currently in use.
NQ.t Control Costs
The algorithms used to calculate capital and operating costs for NO
control devices are presented in Reference 21. The cost algorithms for low
excess air (LEA) operation, and staged combustion (SCA) were developed by
Radian based on costs presented in the Individual Technology Assessment
Report (ITAR) for NOX Combustion Modification.14 Table D-10 presents the
general specifications for LEA and SCA.
D-ll
-------
TABLE D-7. CAPACITY UTILIZATION AND LABOR FACTORS USED
FOR MODEL BOILER COST CALCULATIONS3
Capacity
Boiler Type Utilization Factor (CF) Labor Factor (LF)
Coal-fired 0.60 Q 75
(Underfeed, spreader stoker,
pulverized feed)
Labor Factor Equations
CF LF
>0.7 i
0-5 - 0.7 0.5 H- 2.5 (CF - 0.5)
<0.5 0.5
References 3 and 11.
0-12
-------
TABLE 0-8. SPECIFICATIONS FOR CONVENTIONAL COAL-FIRED BOILERS
Therm 1 Input. HU
(10° Btu/hr)
Fuel firing method
Fuel analysis
Percent sulfur
Percent ash
Heating value. kJ/kg
(Btu/lb)
Excess air, percent
Flue, gas flow rate,
M/S (acfra)
Load factor, percent
Efficiency, percent
Steam production,
kg/hr (Ib/hr)
14.5 (SO)
Underfeed stoker
3.23
12.0
27.200 (11,700)
35
8.70 (18,400)
60
79.0
17.600 (38,800)
29.0 (100)
Spreader stoker
3.23
12.0
27.200 (11.700)
35
17.4 (36,800)
60
80.0
32.000(70.400)
44.0 (150)
Spreader stoker
3.23
12.0
27.200 (11.700)
35
26.0 (55.100)
60
80.9
48,500 (106.900)
73.0 (250)
pulverized coal
0.42
6.9
20,500 (8,825)
35
43.9 (93,000)
60
82.0
78,400 (173.000)
117.2 (400)
Pulverized coal
0.42
6.9
20,500 (8.825)
35
67.0 (142.000)
60
83.1
127,010 (280.000)
Conditions correspond to low excess air operation.
-------
TABLE D-9. GENERAL DESIGN SPECIFICATIONS FOR PM CONTROL SYSTEMS
Control Device ite,n Specification
Fabric Filter (FF) Material of construction Carbon steel (insulated)
Cleaning method Reverse-air (multi-compartment)
Air to cloth ratio 2 acfm/ftz
Bag material Teflon-coated fiberglass
Bag life 2 years
Pressure drop 6 in> H 0
o
A a
Pressure drop refers to gas side pressure drop across entire control system.
-------
TABLE D-10. N0x COMBUSTION MODIFICATION EQUIPMENT REQUIREMENTS ON CONVENTIONAL BOILERS
Control Device
Low Excess Air (LEA)
Staged combustion Air (SCA)
Pulverized coal-fired boilers
Specification
Oxygen trim system - 0? analyzer, air flow
regulators
Wind box modifications (may be required for
multi-burner boilers)
Oxygen trim system - 0? analyzer, air flow
regulators
Airports
Wind box modifications
Larger forced draft fan power
-------
S02 Control Costs
The cost algorithms used to calculate capital and annual operating
costs for flue gas desulfurization units are also presented in Reference 21.
The cost basis for the lime spray drying FGD systems is presented in the FGO
ITAR. Cost algorithms based on the ITAR cost estimates were developed by
Acurex Corporation. The algorithms presented in Reference 21 however, do
not represent the costs in the final ITAR or the Acurex report for the spray
drying systems. The Acurex algorithms were modified to reflect revised
installation factors and revised fabric filter costs for the spray drying
systems. These revisions are documented in a several technical memos.16'17
Table D-ll presents the general specifications for the lime
spray-drying FGO system analyzed in this report. These specifications are
typical for lime spray drying systems currently in use.
Liquid and Solid Waste Disposal
The major liquid and solid waste streams from uncontrolled conventional
boilers are: water softening sludge, condensate blowdown, bottom ash
disposal, and coal pile runoff. Bottom ash collection, handling, and
disposal costs have been incorporated into the uncontrolled boiler cost
estimates. Bottom ash disposal costs were estimated based on a
non-hazardous waste classification under RCRA regulations. If industrial
boiler wastes are classified as hazardous in the future, the disposal costs
and overall boiler control costs (for coal-fired boilers) would increase
significantly.
Disposal of fly ash (from PM control devices), spray dryer solids (from
the dry SC<2 scrubbing process), and spent solids (from FBC boilers) has also
been estimated on the basis of a non-hazardous waste classification.
0-16
-------
TABLE D-ll. GENERAL DESIGN SPECIFICATIONS FOR THE LIME SPRAY DRYING FGD SYSTEM
Control Device
Item
Specification
o
i
Dry scrubbing (spray drying,
S02 and PM removal) (DS)
Material of construction
Reagent
Fabric filter
Pressure drop3
L/G
Solids disposal
Carbon steel spray dryer and fabric
filter (insulated)
Lime; with solids recycle at 2 kg
recycle solids/kg fresh lime feed
Pulse jeti air-to-cloth ratio of
4 acfm/fr
6 in. H20
0.3 gal/acf
Trucked to off-site landfill
All pressure drops refer to gas side pressure drop across entire control system.
-------
Costs for treating the other three waste streams were not
quantitatively evaluated in this study. The costs associated with waste
stream disposal are highly site-specific and are influenced by the following
parameters:
- Water softening sludge rate and composition: raw water quality,
steam quality, and water makeup rate.
- Condensate blowdown rate and composition: effluent discharge
quality requirements, raw water quality, and condensate blowdown
quantity.
- Coal pile runoff rate and composition: coal quality, meterological
conditions, and effluent discharge quality requirements.
However, these costs would be associated with the boiler itself and would
not affect the analysis of incremental costs for air pollution control
systems.
D-18
-------
APPENDIX D REFERENCES
1. Devitt, T.t P. Spaite, and L. Gibbs. (PEDCo Environmental) Population
and Characteristics of Industrial/Commercial Boilers in the U.S.
(Prepared for U. S. Environmental Protection Agency.) Research
Triangle Park, N. C. EPA-600/7-79-78a. Cincinnati, Ohio.
August 1979. 462 p.
2. Dickerman, J.C. and K.L. Johnson, (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Application: Flue Gas
Desulfurization. (Prepared for U. S. Environmental Protection Agency.)
Research Triangle Park, N. C. EPA-600/7-79-78c. November 1979
664 p.
3. Letter from Medine, E. S., Energy and Environmental Analysis, Inc. to
Short, R., EPArEAB. September 14, 1981. 6 p. Comparison of IFCAM and
Radian Cost Algorithms for S0? and PM Control on Coal- and Oil-Fired
Industrial Boilers.
4. Reference 2, p. 117.
5. U. S. Environmental Protection Agency. Fossil Fuel Fired Industrial
Boilers - Background Information. Volume I. Research Triangle Park,
N. C. Publication No. 450/3-82-006a. March 1982. pp. 4-1 - 4-213.
6. Hogan, Tim (Energy and Environmental Analysis, Inc.) Memorandum to
Robert Short (EPA/EAB). Recent Changes to IFCAM Model. June 22, 1983.
7. Hogan, Tim (Energy and Environmental Analysis, Inc.) Memorandum to
Robert Short (EPA/EAB). Industrial Coal Prices. July 19.1983.
8. Hogan, Tim (Energy and Environmental Analysis, Inc.) Memorandum to
Robert Short (EPA/EAB). Industrial Fuel Prices. June 19, 1983.
9. Reference 2, p. 118-122.
10. PEDCo Environmental, Inc. Cost Equations for Industrial Boilers.
Final report. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. EPA Contract No. 68-02-3074.
January 1980. 22 p.
11. Reference 2, pp.95-102, 110.
12. PEDCo Environmental, Inc. Capital and Operation Costs of Particulate
Controls on Coal- and Oil-Fired Industrial Boilers. (Prepared for
U.S. Environmental Protection Agency.) Research Triangle Park, N.C.
EPA-450/5-80-009. August 1980. 129 p.
D-19
-------
13. Bowen, M.L., (Radian Corporation.) Costs of Mechanical Collectors
Applied to Fossil Fuel Fired Industrial Boilers. June 2, 1982. 12 p.
14. Lim, K.J., et. al. (Acurex Corporation) Technology Assessment Report
for Industrial Boiler Applications: NO Combustion Modification.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. EPA-600/7-79-178f. December 1979.
15. Gardner, R., R. Chang, and L. Broz. (Acurex Corporation ) Cost
Energy and Environmental Algorithms for NO. S09, and PM Controls for
Industrial Boilers. Final Report. (Prepared f&r U. S. Environmental
Protection Agency.) Cincinnati, Ohio. EPA Contract No. 68-03-2567
December 1979. p. 20-52.
16. Aul, E.F., M.A. Palazzolo, and R.S. Berry (Radian Corporation)
Memorandum to C.B. Sedman (EPA/ISB). Revised Cost Algorithms for Lime
Spray Drying and Dual Alkali FGD Systems. May 16, 1983.
17. Letter from Berry, R.S. (Radian Corporation) to C.B. Sedman (EPA/ISB).
Changes to FGD Cost Algorithms. July 5, 1983.
18. Dickerman, J.C. and M.E. Kelly. "Issue Paper: Jompliance Monitoring
Costs. Radian Corporation. Durham, N.C. September 25, 1980. 20 p.
19. Smith, S.A., F.H. Sheffield, and W.R. Menzies. "Issue Paper:
Reporting Requirements." Radian Corporation. Durham, N.C.
September 1980. 40 p.
20. Kelly, M.E. and K.L. Johnson. "Issue Paper: Control Equipment
Malfunction Provisions." Radian Corporation. Durham, N.C
September 25, 1980. 43 p.
21. Laughlin, J. H., J. A. Maddox, and S. C. Margerum, (Radian
Corporation). S02 Cost Report. (Prepared for U.S. Environmental
Protection Agency.) Research Triangle Park, N.C. (In Preparation).
0-20
-------
APPENDIX E
AUXILIARY LISTINGS OF AFBC MANUFACTURERS AND UNITS
As a supplement to the information presented in Section 3.0, this
appendix contains summary lists of foreign AFBC manufacturers, existing and
planned foreign coal-fired AFBC units, and existing and planned multi-fuel
and alternative fuel AFBC units.
-------
TABLE E-i. FOREIGN AFBC MANUFACTURERS35
AFBC Boiler Technology
Built
Under Licensing
Company Address License Company
A. Ahlstrom Dy No
f. 0. Box 329
SF -00101 Helsinki 10, Finland
Ans a i do SpA No
Vlale Sarca, 336
M llano 20126. Italy
Babcock Hitachi KK No
6-2. 2-Chowe. Ota-machi
Chtyodo-Ku. Tokyo 100. Japan
Combustion Systems Ltd. No
BP Research Centre
Sunbury-on-Thames, Hlddlusex
England TU16 7LN
Danks of Netherton, Ltd. Ves Combustion
Haiesowen Rd. Netherton Systems
Dudley. West Midlands ltd.
Boiler Capabilities Commercially Available
Watertube Types of
or FBC
Flretube Systems Steam Capacity
Boiler Offered 1000 Ib/hr
Ut Fx. Fcb 20-400
Ut Fx Up to 400
Ut Fx 22-1100
Ht. Ft2 Fx2 25-5002
Ut. Ft Fx 15-70
, Pressure, Temperature,
pslg "F Fuel(s)
140-2500 350-1000 -1
NAv Up to 1000 Coal.
Uoodwaste
100-2400 Up to 1050 -'
1000-24002 Up to 10052 -l
100-900 Up to 900 -'
Number of
Units
Installed
USA
0
1
2
0
0
Total
9
0
2
0
4
England OV2 9PG
Deborah FluldUed Cou^uUlun,
Ltd.
6 Davy Dr.
NU Industrial Estate
Peterlee, Durham, England
Deutsche Bibcock Uerke AQ
Duisburger Strasse 375
Oberhausen 0-4200. U. Gtruuny
Fluldlsed Combustion
Contractors Ltd.
11 The Boulevard
Crawley. Sussex
England RH10 1UX
Foster Wheeler Power
Products Ltd.
Greater London House
Hampstead Rd.. London
England NU) 7QN
Generator Industrie AB
P. 0. Box 95
S-433 22 Partille. Sweden
No
No
res Solids
Circulation .
Systems, Inc.
Ves
Ves Fluidized
Combustion Co.
Ut Fcb
Wt Fx. Pet
Wt. Ft Fx. Pcb.
Fcb
Ut Fx. Fcb
Ut Fx. Fcb
1-50 100-900 -s -l
20-700 145-2600 360-1100 -l
-S -5 .5 J
30-600 200-2000 200-1000 -'
1 12
0 14
1 2
0 2
17-170 150-1000 Up to BOO Coal. 0 a
Uoodwaste,
Blomass
-------
T1BLE f-1. FORCIGN AFBC hANUFACTURERS35 (Continued)
m
i
ro
AFBC Boiler Technnlmw
Company Address
E. Green i Son Ltd.
Wakefield
England WF1 5PF
Ishikawajima-Harima
Heavy Industries Co., Ltd.
Built
Under Licensing
License Company
No
Yes
Fluidized
Udtertube
or
Fire tube
Boiler
Ut
Wt. Ft
Types of
FBC
Systems
Offered
Fx
Fx
Boiler Capabilities Commercially Available
Steam Capacity, Pressure, Temperature
1000 Ib/hr psig °F Fuel(s)
20-80 150-900 Up to 900 -1
-S .5 .5 ,
• -
Number of
Units
Installed
|IC« Tntal
1 1
A *i
Ves Combustion
Systems, Ltd.
No
30-13 5-Chome. Toyo
Koto-ku, Tokyo 135, Japan
HE Boilers Ltd.
ME House, Fengate
Peterborough, Cambs.
England PE1 5BQ
NEI Cochran Ltd.
Newbie Works
Annan, Dumfriesshire
Scotland DG12 5QU
Tampella Ltd., Boiler Oiv. NO
P. 0. Box 626
SF-33101 Tampera 10, Finland
Wall send Slipway Engineers Ltd. No
Point Pleasant
Ma11 send, Tyne A Wear
England NE2B 6QN
footnotes:
1. Designed to burn the following fuels separately
or in combination: cual, woodwaste, biowss
liquid wastes or sludges, coal-washing wastes.
2. Rdiige of equipment specifications offered.
3. Temperature depends un customer requirements.
4. Fluidized Combustion Contracts Ltd offers
e" C""lbustion s*ste"'s of 'ts own design
Ut
Ft
Wt
Ft
Fx
Fx
Fx
Fx
20-100 Up to 2500 Up to 900 -1
2-36 100-250 Sat -1
13-225 400-1800 Up to 1000 -1
5.3-59.8 150-250 Sat -1
0 1
0 6
0 6
0 0
5. Designed to meet customer
requirements.
6. Foster wht-tler Power Products Ltd. licenses
the fluidized-bed technology for some of
the equipment it offers from Fluidized
Combustion Co.. a joint venture of Foster
Wheeler Development Corp. and Pope Combustion
Systems Inc., and from Battelle Memorial
Institute
Abbreviations:
Fcb—Full circulating bed
Ft—Firetube boiler
Fx—Fixed (bubbling) bed
NAv—Hot available
Pcb—Partial circulating bed
Sat—Saturation temperature
Wt—Watertube boiler
-------
TABU E-2. EXISTING AND PLANNED FOREIGN COAL-MRED AfBC UNITS36
m
i
OJ
Plant Owner
Atlas Consol Mining t Ctv.
Corp.
Elektrfzitatswerk
Uesertral GmbH
Olbso Power Plant
Saarbergwerke AG
National Coal Hoard
ENEL4
Shell Nederland
Rafflnaderji BV
Jtangapen
Ruhrkohl AG
British Steel Corp.
Vulyany
Milsui Tousu Chemicals,
Inc.
City of Vastervlk
Babcock Power Ltd.
Hitsui
Location
Cebu, Philippines
Hani in, M. Ger.
China
Volklingen. U. Ger.
Grinethorpe. £ng.
Porto Vesiia. Italy
Pirnus, Holland
Guangdong, China
Dusseldorf, U. Ger.
Sheffield, Eng.
Hunan, China
Sunagawa, Japan
Vastervik. Sweden
Heiifrew, Scotland
loatsu Chan, Japan
Steam
Capacity,
1000 Ib/hr
3S21
309
286
2?3l
176
1?5
110
110
109
BO
?7
£9
66
60
55
Steam
Pressure
psig
914
1741
saa
3
4)5
640
1174
605
247
650
650
356
1/5
400
356
Steam
Temperature
•F
905
986
840
3
824
890
923
794
752
820
794
S36
375
SIB
482
Design
FuelU)
L
C
C
C
C
C
C
C
C
C
C
C
C
C
C
Manufacturer
DBU2
OBU2
_
DBU2
DBW2
ANS
FUC
.
DBU2
Mffl
-
IHI
GEN
FCL
-
Type of
Project
Con
Cow
Con
Con
0
0
Com
Coo
0
Con
Con
Com
Com
D
Con
Type of
Financing
P
P/G
G
P/G
G
P/G
P
a
JVC
P/G
P/G
P
P
P
P/G
Connercial
Service
Date
19B2
1983
4/80
1982
1980
1984
7/82
1981
1979
7/81
1981
4/82
12/83
5/75
NAv
-------
TABLE E-2. EXISTING AND PLANNED FOREIGN COAL-FIRED AF8C UNITS35 (Continued)
Plant Owner
Babcock Hitachi KK
Chalmers University
Canadian Dept. of Defense
Mooning Petroleum
Tsinghum University
Chemical Plant Cogen
Undisclosed
Danks of Netherton Ltd.
Hastra
rn Saarbergwerke AG5
-P*
Odnks Engineering Ltd.
Smith's Brewery Ltd.
Sulzer Brothers Ltd.
E. Green I Son Ltd.
Undisclosed
National Coal Board
North York County Council
Steam
Capacity,
Location 1000 Ib/hr
Uakamatsu, Japan
Gothenburg, Sweden
Summersido. PUI, Can.
China
Beiding, China
Trlchy. India
Undisclosed
Dudley, Eng.
Luneburg, M. Ger.
Volklingen, U. Ger.
Oldbury, Eng.
Tadeaster, Eng.
Winterthur, Switzerland
Wakefield, Eng.
Undisclosed
Selby, Eng.
Knaresborough, Eng.
44
44
401
32
30
26
24
20
191
173
16
IS
12
10
10
46
47
Steam
Pressure
psig
853
580
160
180
336
200
384
400
885
3
150
150
435 '
180
150
50
NAv
Steam
Temperature
•F
1000
800
Sat
482
734
480
Sat
Sat
923
3
Sat
Sat
572
Sat
Sjt
Sat
NAv
Design
Fuel(s)
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
Type of
Manufacturer Project
HIT
GEN
FWC
-
-
BHEL
HIT
DHL
DBU
DBH2
DNL
NEI
SUL
GRE
DNL
NEI
DFC
0
Con
D
Con
Con
Com
Com
D
Com
D
Com
Com
D
0
Com
Com
NAv
Type of
Financing
P/G
P/G
G
G
P/C
P
P/G
P
P
P
P
P/G
P
P
P/G
NAv
Commercial
Service
Date
4/81
3/82
12/82
12/65
6/64
10/81
1984
NAv
1983
1980
5/81
1981
9/79
6/82
5/82
1981
1982
-------
FOOTNOTES, ABBREVIATIONS, AND MANUFACTURERS FOR TABLE E-2
Footnotes:
1. Two units installed.
2. In conjunction with Vereinigte Kesselwerke AG.
3' Smhn^iS I? m11li0n 8tU/hr; hot combtjstion gas exiting fluidized-bed
combustor flows to a conventional fired boiler.
4. Steam at 80 percent quality.
5. Prototype power station.
6. Four units installed.
7. Rating is in million Btu/hr; unit is a fluidized-bed hot-water boiler
Operating pressure and temperature are for hot water.
Abbreviations:
C—Coal
Com—Commercial contract
D—Demonstration project
G—Government financing
NAv—Not available
P--Private financing
P/G--Private/government financing
Sat—Saturated
E-5
-------
FOOTNOTES, ABBREVIATIONS, AND MANUFACTURERS FOR TABLE E-2 (Continued)
Manufacturers:
ANS—Ansaldo SpA
BHEL--Bharat Heavy Electricals Ltd.
DBW—Deutsche Babcock Werke AG
DFC—Deborah Fluidised Combustion Ltd.
DNL--Danks of Netherton Ltd.
FCL--F1uidized Combustion Contractors Ltd.
FWC—Foster Wheeler Boiler Corporation
GEN«Generator Industrie AB
GRE--E. Green & Sons Ltd.
HIT—Babcock Hitachi KK
IHI—Ishikawajima-Harima Heavy Industries Co.
MEB—M E Boilers Ltd.
NEI--NEI Cochran Ltd.
SUL—Sulzer Brothers Ltd.
E-6
-------
TABU E-3. EXISTING AND PLANNED MULTI-FUfl AND ALTERNATE FUEL AFBC UNITS35
_
Plant Owner
AshUnd Petroleum Company
y
A Ahlstron Oy
Kemlra Oy
2ellttoff-und Paplerfabrik
AG
Northern States Power Co.
Hylle Bruks AB
Dortmund Colliery
Fllngorn Power Station
Undisclosed
Hyvlnkaan Lawpovoina Oy
Klrby liwfcer Co.
City of Galhvare
American Can Co.
State of California
OeArnond Stud Hill
1. Stroudsburg State Coll.
Ueyerhaeuser Co.
Atlantic Veneer Corp.
City of Eksjo
Idaho forest Industries
Sunter Plywood Corp.
Northwestern Mississippi
Jr. College
— — - — —
Location
Catlettsburg. Ky.
Kauttus. Finland
Oulu. Finland
Frantschach. Austria
LaCrosse, Mis.
Hyltebruk. Sweden
Dortmund. W. Ger.
Dusseldorf. W. Ger.
Undisclosed •
llyvinkas. Finland
Stlsbee, Texas
Galllvare, Sweden
Bellamy. Ala.
Sacramento. Calif.
Cueur d'Alene. Idaho
E. Stroudsburg, Pd.
Raymond. Wash.
Hcaufort. N. C.
Eksjo. Sweden
Coeur d'Alene. Idaho
Livingston, Ala.
^enatObla, HISS.
Steam
Capacity,
1000 Ib/hr
325 l
200
155
154
150
M3
73
110
93
853
70
6B
55
45
40
40
40
35
34
30
27
27
Stean
Pressure
pslg
450
1200
1275
1215
450
925
485
250
327
J303
350
232
150
275
150
1M)
150
200
115
ISO
180
150
Steam
Temperature
•f
700
930
960
970
750
B40
797
750
Sat
355
Sat
356
Sat
Sat
C a*.
J«l
Sdt
Cat
•Jal
**At
J*l
tin
J^U
Sat
C i*.
J«l
Sat
Design
Fuel(s)
CO.Ng
Pt.C
Pt.C
U.Bc
U
Pt.U.C
Cww
Be
PrU
Pt.C.W
y
Pt
u
w
u
Ac
W
W
u
u
w
w
Hanufacturer
FUC
AHL
AM.
AHL
F.PI
AHL
DBU
nftu
UOH
IH1
AHL
EPI
TAX
VSI
EPI
EPI
F£C
EPI
rsi
GEN
EPI
EPI
EPI
: '."
Type of
Project
Com
Con
Con
Con
Con
COM
Con
Con
Co*
Con
Con
Con
Con
Co*
D
Con
Con
Cow
Com
Con
Com
1 ••• i. • i .. - -~
Type of
Financing
P
P
P
P
P
P
P/G
P/G
p
p
P
p
p
G
P
P/G
P
P
P
P
P
P
— -••• • i ,
Commercial
Service
Date
— ~-^ —^. _
2/83
4/81
1/BJ
11/83
12/flI
a /ft?
W/U£
2/82
IQttfi
I7UU
4/Q-l
^/OJ
Q/fll
7/Ui
12/BO
Q IA1
9/OJ
A tan
4/UO
10/82
6/78
6/83
11/75
5/77
2/81
9/73
12/77
3/80
-------
TABLE 1-3. EXISTING AND PLANNED MULTI-FUEL AND ALTERNATE FUEL AFBC UNITS35 (Continued)
Plant Owner
Boise Cascade Corp.
Boise Cascade Corp.
Webster Lumber Co.
Diamond International Corp.
Atlantic Veneer Corp.
Shamokin Area Ind. Corp.
Kogap Manufacturing Co.
Skelleflea Kraft AB
Savon Volma Oy
pi Sumitomo Coal Mining Co.
i
CO Nagel Lumber Co.
Hade Lumber Co.
Chapleau Lumber Co.
Superwood Corp.
Eastnont Forest Products
Merritt Brothers Lumber Co.
Multnomah Plywood Corp.
City of Eksjo
H48 Lumber Co.
Undisclosed
Tenneco Ltd.
Btnghamton Psychiatric
f*ttn*Ar
Steam
Capacity,
Location 1000 Ib/hr
Emmet t, Idaho
Honour, N. C.
Bangor, Wis.
Redmond, Ore.
Beaufort, N. C.
Shamokin, Pa.
Hedford, Ore.
Skelleftea, Sweden
Suonerjokt, Finland
Akabira City, Japan
Land 0' Lakes, Mis.
Waiie, N. C.
Chapleau, Ont. , Can.
Phillips, Wis.
Ashland, Mont.
Priest River, Idaho
St. Helens, Ore.
Eksjo, Sweden
Marion, N. C.
Undisclosed
Bristol, Eng.
Binghamton, N. 1.
26
26
26
25
24<
24
24
243
243
22
21
21
21
20
20
20
20
1?
14
12
10
10
Stean
Pressure
psig
150
150
150
ISO
200
200
180
1303
ISO3
100
175
150
15
250
150
150
150
115
150
ISO
250
150
Steam
Temperature
°F
Sat
Sat
Sat
Sat
Sat
Sat
Sat
3553
2503
Sat
Sat
Sat
Sat
Sat
Sat
Sat
Sat
340
Sat
Sat
Sat
Sat
Design
Fuel(s)
U
w
w
w
w
Ac
W
Pt
Pt
Cww
W
W
w
H
W
W
U
R
U
NAv
Wt
W
Type of
Manufacturer Project
EPI
EPI
EPI
EPI
YSI
KEE
EPI
AHL
AHL
HIT
YSI
YSI
YSI
EPI
EPI
EPI
EPI
GEN
YSI
NEI
DNL
DEO
Com
Com
Com
Com
Com
D
Com
Com
Cora
Com
Com
Com
Com
Com
Com
Com
Com
Com
Con
Com
Com
Com
Type of
Financing
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P/G
P
P
P
P
Commercial
Service
Date
3/77
11/77
3/77
12/80
3/81
10/81
4/79
12/81
11/79
4/79
8/77
6/79
2/77
7/77
3/74
1/76
9/79
12/79
11/75
1982
8/80
11/80
-------
IABU t-J, EXISTING AND PLANNED HULTI-FUEl ALTERNATIVE FUEL AfBC UNITS35 (Continued)
, . . — .
Plant Owner
Boise Cascade Corp.
Lindsay Olive Growers
Hossl Corp.
Kelly Enterprises
Walnut Products, Inc.
Iowa-Missouri Malnul Co.
Undisclosed
Oy Alto Ab
City of llsalml
ro City of Scandvllcan
l£>
Conoco, inc.
Campbell Soup Co.
Stevenson Dyers Ltd.
Campbell Soup Co.
Campbell Soup Co.
Boise Cascade Corp.
0
A AhlUrooi Oy
5
Oy Kyro Ab'
House of Raeford
City o( Kemljarvl
Central Soya Company
Undisclosed
y
Tampella ltd/
Steam
Steam
Capacity, Pressure
location 1000 lb/hr pstg
Cascade. Idaho
Lindsay. Calif.
Hlgganum, Ct.
Pittsfield. Hass.
St. Joseph, Ho.
St. Joseph Ho.
Haifa Bay, Israel
Koskenkorva, Finland
(i salmi, Finland
Scandvikan. Sweden
Uvalde, Texas
Maxton, N. C.
Ambergate, Cny.
Napoleon, Oliio
Salisbury, fid.
Kenora, Ont. , fan.
Port, Finland
Kytostoski, Finland
Rose Hill. N. C.
KciMijarvi. Finland
Marion, Ohio
Undisclosed
Anjalankoski, Finland
10
10
10
10
9
7
60
56
b.3
SI1
50
ISO5
SO
I505
50
45
44
44
43
413
40
10'
40
ISO
ISO
ISO
IS
ISO
ISO
200
585
2323
175
2450
300
250
240
ISO
250
1200
870
ISO
2323
200
120
1420
Steam
Temperature Design
°f Fuel(s)
Sat
Sat
Sat
Sat
Sat
Sat
Sat
840
3563
375
665
Sat
460
Sat
Sat
Sat
970
914
Sat
3S63
Sat
Sal
Sat
U
Op
u
w
u
Ch.PrW
Pt.O
Pt.W
W.C.Pt
C.L.Ck
C.Prtf6
C.PrU
C.Prtf6
C.PrM
u.s
Pl.W
W.Pt
W.PI
Pt.U
C.Ng
C.Ng
u.s.c
Type of
Manufacturer Project
EPI
EPI
YSI
(SI
1 J 1
YS1
EPI
AIIL
I AM
GEN
SMC
JBC
FWL
JBC
JBC
EPI
AIIL
TAH
VSI
I AM
JBC
JBC
TAH
Com
Com
Com
Com
Com
Com
Com
Com
Com
Con
Com
Com
D
Com
Com
Com
Com
Com
Com
Com
Com
Com
Com
.—
Commercial
Type of Service
Financing lUtc
—
p
P
P
P
P
P
P
p
P
P
p
p
P/G
p
P
P
P
p
P
p
p
P
P
3/BO
4/76
12/79
2/75
10/75
10/75
19B2
1/83
11/83
11/83
12/81
10/82
7/82
8/82
11/82
10/77
1/79
5/81
5/82
11/83
4/80
3/83
11/82
-------
TABLE E-3. EXISTING AND PLANNED MULTI-FUEL AND ALTERNATUVE FUEL AFBC UNITS35 (Continued)
• • —
Plant Owner
City of Bolinas
City of Landskrona
City of Vastervik
Woolcombers Ltd.
Tobacco Processing
Undisclosed
Lumber Mill
IBM
Undisclosed
G.A. Serlachium Lielahtr
Hayward Tyler Pump Co.
U.S. Department of HUD
Tenneco Organics Ltd.
Undisclosed
Struthers Thermo-Flood
Steam
Capacity,
Location 1000 Ib/hr
Bolinas, Sweden
Landskrona, Sweden
Vastervik, Sweden
Bradford, Eng.
Brazil
Providence, R.I.
Crestview, Fla.
Charlotte, N. C.
Erving, Mass.
Tampere, Finland
Keighley, Eng.
Norfolk, Va.
Avonmouth, Eng.
Rome, Italy
Winfield, Kan.
341
34»
34'
25
25S
201
20
20
20
19
10
103
6
6
5
Steam
Pressure
psig
175
175
175
200
150
300
300
225
150
653
125
203
250
150
2650
Steam
Temperature Design
°F Fue'l(s)
375
375
375
Sat
Sat
Sat
Sat
Sat
Sat
842
Sat
2003
Sat
Sat
660
R.W
RDF
R.W
C.PrH
C.AL
Ng.C
W.Ng
Ng.O.C
C.O.Ng
S.H.Pt
C.Ng
Uo.Ti
Ut.Ho
Wt.PrW
C.L.Ck
Type of
Manufacturer Project
GEN
GEN
GEN
FUL
JBC
JBC
JBC
JBC
JBC
TAM
JBC
DFC8
DFC
DFC
sue
Com
Com
Com
Com
Com
Com
Com
Com
Com
Com
Com
Com
Com
Com
T
Type of
Financing
P
P
P
P/G
P
P
P
P
P
P
P
G
P
P
P
Commercial
Service
Date
9/83
8/83
6/84
8/82
2/81
5/83
3/81
7/80
4/83
2/80
1/80
10/82
6/80
NAv
10/81
-------
FOOTNOTES, ABBREVIATIONS, AND MANUFACTURERS FOR TABLE E-3
Footnotes:
1.
2.
3.
Two units installed.
Application for fluidized-bed boiler is steam production in a
papermill.
Rating is in million Btu/hr; unit is a fluidized-bed hot-water boiler
Operating pressure and temperature are for hot water.
4. Rating is in million Btu/hr; hot combustion gas exiting fluidized-bed
combustor flows to a conventional fired boiler.
5. Three units installed.
6. Also oil and natural gas.
7. Nine units installed.
8. In conjunction with International Boiler Works Co.
Abbreviations:
Ac--Anthracite culm
Al—Alcohol
Be—Brown coal
C—Coal
Ch—Cotton hulls
Ck—Petroleum coke
CO—Carbon monoxide
Com—Commercial contract
Cww—Coal-washing wastes
D---Demonstration project
D/C—Demonstration/commercial project
G—Government financing
L—Lignite
NAv—Not available
Ng--Natural gas
0—Oil
Op—Olive pits
P—Private financing
P/G—Private/government
financing
PL—Poultry litter
PrW—Process wastes
Pt—Peat
R~Refuse
RDF—Refuse-derived fuel
S—Sludge
Sat—Saturated
T—Test facility
Ti—Tirss
W—Wood, wcodwaste,
byproducts
Wo—Waste oil
Wt—Waste tars
E-ll
-------
FOOTNOTES, ABBREVIATIONS, AND MANUFACTURERS FOR TABLE E-3
Footnotes:
1.
2.
3.
4.
5.
6.
7.
8.
Two units installed.
Application for fluidized-bed boiler is steam production in a
papermill.
Rating is in million Btu/hr; unit is a fluidized-bed hot-water boiler.
Operating pressure and temperature are for hot water.
Rating is in million Btu/hr; hot combustion gas exiting fluidized-bed
combustor flows to a conventional fired boiler.
Three units installed.
Also oil and natural gas.
Nine units installed.
In conjunction with International Boiler Works Co.
Abbreviations:
Ac—Anthracite culm
Al—Alcohol
Be—Brown coal
C—Coal
Ch—Cotton hulls
Ck—Petroleum coke
CO—Carbon monoxide
Com—Commercial contract
Cww—Coal-washing wastes
D—Demonstration project
D/C—Demonstration/commercial project
G--Government financing
I—Lignite
NAv—Not available
Ng—Natural gas
0—Oil
Op—Olive pits
P—Private financing
P/G—Pr i vate/government
financing
PL—Poultry litter
PrW—Process wastes
Pt—Peat
R—Refuse
RDF—Refuse-derived fuel
S—Sludge
Sat—Saturated
T—Test facility
Ti--Tires
W—Wood, woodwate, wood
byproducts
Wo—Waste oil
Wt—Waste tars
E-12
-------
FOOTNOTES, ABBREVIATIONS, AND MANUFACTURERS FOR TABLE E-3 (Continued)
Manufacturers:
AHL--Ah 1strom Oy
DBW—Deutsche Babcock Werke AG
DED—Dedert Corp., Thermal Processes Division
DFC—Deborah Fluidized Combustion Ltd.
DNL—Danka of Netherton Ltd.
EPI—Energy Products of Idaho
FEC—Fluidyne Engineering Corporation
FWC—Foster Wheeler Boiler Corporation
FWL«Foster Wheeler Power Products Ltd.
GEN—Generator Industrie AB
HIT—Babcock Hitachi KK
IHI —Ishikawajima-Harima Heavy Industries Co.
JBC—Johnston Boiler Co.
KEE--E. Keeler Co.
NET—NEI Cochran Ltd.
SWC—Struthers Wells Corp.
TAM—Tampella Ltd.
YSI—York Shipley, Inc.
E-13
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. ' 2.
EPA-45/3-85-010
4. TITLE AND SUBTITLE
Fluidized Bed Combustion: Effectiveness as an $02
Control Technology for Industrial Boilers
7. AUTHOR(S)
E. F. Aul , Jr., M. L. Owen, A. F. Jones
9, PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
3200 E. Chapel Hill Road/Nelson Highway
Research Triangle Park, North Carolina 27709
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Policy Analysis
U. S. Environmental Protection Agency
401 M Street, S.W.
Washington, DC 20460
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
September 1984
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
1 1. CONTRACT/GRANT NO.
68-01-6558
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/ 200/04
15. SUPPLEMENTARY NOTES
Project Officer - Judith M. Greenwald
16. ABSTRACT
Atmospheric fluidized bed combustion (AFBC) boilers have developed rapidly over
recent years and are now offered commercially in several different configurations.
S02 reduction levels of 90 percent and above have been achieved by coal-fired AFBC
boilers in the industrial size category. Based on the data available, industrial
FBC NOX emissions have been consistently below 0.5 Ib/million Btu. PM emissions
of less than 0.5 Ib/million Btu have been routinely achieved with fabric filters.
AFBC boiler system costs were compared with costs for a conventional boiler equipped
with an FGD system and with costs for a conventional boiler using low sulfur com-
pliance coal. The conclusions drawn from the economic analyses are that (1) studied
cost difference between AFBC Technology, conventional boiler/FGD systems, and
compliance coal combustion are projected to be small over the S02 emission range of
1.7 to 0.8 Ib/million Btu and S02 reduction range of 65 to 90 percent, and (2) that
cost competitiveness among these technologies is not expected to change significantly
as the emission limitations change over this range. Absolute economic competitive-
ness among these options will be sensitive to site-specific parameters and decided
on a case-by-case basis.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Fluidized Bed Combustion
Coal Air Pollution
$02 Emission Data
Emission Standards
Combustion Products
Boilers
Air Pollution Control
Coal
Stationary Sources
Industrial Boilers
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
.
219
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77)
PREVIOUS EDITION IS OBSOLETE
-------