United States
Environmental Protection
Agency
Air and Energy
Engineering Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-88/014 Jan. 1989
&EFA Project Summary
Ohio/Kentucky/TVA Coal-Fired
Utility SO2 and NOX Retrofit
Study
T. E. Emmel, S. D. Piccot, and B. A. Laseke
This document summarizes initial
results from an ongoing National
Acid Precipitation Assessment Pro-
gram (NAPAP) study, the objective of
which Is to significantly improve
engineering cost estimates for
retrofit of the following control
technologies at the 1980 "top 200"
SOj-emlttlng coal-fired power
plants in the 31 eastern states:
lime/limestone FGD, lime spray
drying FGD, coal switching and
cleaning, furnace sorbent injection
with humldification (LIMB), duct
sorbent Injection, low NOX burners,
overfire air, natural gas reburn, and
selective catalytic reduction. Retrofit
cost factors and costs were
developed for 12 coal-fired power
plants: 5 In Ohio, and 7 in Kentucky
and the TVA system (Tennessee,
parts of Alabama, and Kentucky).
Activities included: selecting plants
with boilers representative of the top
200 population; conducting plant
visits and collecting site specific
data; developing boiler/control-
specific retrofit difficulty factors; and
developing boiler/plant-specific
cost and performance estimates.
Results from this effort are being
used to develop simplified proce-
dures to estimate the retrofit costs
for a number of the remaining top
200 plants which are not visited.
This Project Summary was devel-
oped by EPA's Air and Energy
Engineering Research Laboratory,
Research Triangle Park, NC, to an-
nounce key findings of the research
project that is fully documented in a
separate report of the same title
(see Project Report ordering infor-
mation at back).
Introduction
The National Acid Precipitation Assess-
ment Program (NAPAP) is responsible
for developing cost and performance in-
formation on various methods for
reducing the emissions of acid rain
precursors. Coal-fired utility boilers are
major emitte'rs of S02 and NOX. How-
ever, estimating the cost and per-
formance of SC>2 and NOX controls for
coal-fired power plants is difficult due to
differences in plant layout and boiler
design.
This report documents the initial results
of an ongoing study conducted under
NAPAP, the objective of which is to
significantly improve the accuracy of
engineering cost estimates used to
evaluate the economic effects of applying
SOg and NOX controls to existing coal-
fired utility boilers.
This report presents the SOg/NOx
control technology cost and performance
estimates developed for 12 coat-fired
utility plants in Ohio, Kentucky, and the
Tennessee Valley Authority (TVA)
system. The following procedures were
used to develop the cost performance
estimates: select plants with boilers
representative of the population, conduct
plant visits and collect site-specific data,
develop boiler/control specific retrofit
difficulty factors, and develop boiler/
plant-specific cost and performance
estimates for the SOg and NOX controls
selected for evaluation. This performance
and cost estimating process is dynamic:
it incorporates recommendations from a
technical advisory group and partici-
-------
pating utilities, as well as experience
from site visits and performance/cost
evaluations.
Control Technologies
Evaluated
The commercial and developmental
SC>2 and NOX control technologies
selected for inclusion in the program are
listed in Table 1. Evaluated qualitatively
without cost estimates were FBC and
CG. Additional technologies were at first
considered - chemical coal cleaning,
pressurized FBC, and advanced
S02/NOX (combined) control devices -
were not included in this study due to
their general inapplicability to retrofit
situations and early development status.
All of the estimates were developed
using computer-based simulation
models. This approach was taken
because of the large quantity of data
which needed to be accessed, used in
computation, and stored. Although a
number of mainframe- and personal-
computer-based models were evalu-
ated, the Integrated Air Pollution Control
Systems (IAPCS) cost model was finally
selected for use in this study because of
its versatility. The IAPCS model has
been upgraded to include the tech-
nologies being evaluated in this program.
Plants Visited
Four criteria were used to select the
plants to be visited: (1) plant selection
focused on boiler types and sizes
accounting for the majority of 802
emissions; (2) within the limits of cri-
terion, the selected plants were repre-
sentative examples of the diversity of the
boiler population; (3) due to costs, the
number of plants selected for detailed
study were limited to less than 30; and
(4) the plants selected contained multiple
boilers of diverse types.
Boilers in the top 200 S02-emitting
plants were categorized by generating
capacity, coal percent sulfur, firing type,
age, and capacity factor. The top 200
plants were ranked according to their
diversity, and the 30 highest-scoring
plants were evaluated by boiler category
to see if a realistic, proportional sample
had been achieved successfully. Plants
near the bottom of the list (with dispro-
portional, extreme ratings) were repla<
to ensure the representa-tiveness of
sample. From this list of 30 plants,
were chosen for evaluation: 5 in Ol
and 7 in Kentucky and the TVA syst
(Tennessee, parts of Ala-bama, &
Kentucky).
The Ohio and Kentucky plants wi
selected for evaluation first because
the opportunity to conduct the progr
jointly with Ohio and Kentucky State A
Rain (STAR) programs. In addition to c
TVA plant in Kentucky, three TVA pla
outside of Kentucky were includ
through TVA's participation in t
Kentucky STAR program. These w<
considered to be representative of 1
top 200 SOg emitting plants. Table 2 li
the plant/boiler characteristics for the
12 plants.
Prior to the plant site visit, a pi;
profile was completed using sources
public information; a primary referen
with the Department of Energy's (DOE
Energy Information Agency (EIA) Fo
767. The plant profile included
information and data needed 1
performance/cost analyses. The pl<
Table 1. Emission Control Technologies Selected
Development Status
Species Controlled
Control Technology
SO?
/VCX
Commercial
Limited
Commercial
Experience
Near
Commerical
Demonstration
Lime/limestone (ULS) flue gas
desulfurization (FGD) X
Additive enhanced ULS FGD X
Ume spray drying (LSD) FGD* X
Physical coal cleaning (PCC) X
Coal switching and blending (CS/B) X
Low-NOx combustion (LNC)
Furnace sorbent injection (FSI) with
humidification (UMB) X
Duct spray drying (DSD) X
Natural gas rebuming (NGRp X
Selective catalytic reduction (SCR)
Fluidized bed combustion (FBC) or
coal gasification (CG) retrofit? X
X
X
X
X
X
X
X
X
X
X
^Commerical on low-sulfur coals, demonstrated at pilot scale on high sulfur coals.
hFor wet bottom boilers and other boilers where LNC is not applicable.
cEvaluated qualitatively as combined life extension and SOX/NOX control option. No costs were developed.
-------
Table 2. Boiler Characteristics of Plants
Boiler
Plant (State) No.
Burger (OH)
Conesville (OH)
Muskingum River (OH)
Sammis (OH)
J. M. Stuart (OH)
E. W. Brown (KY)
Elmer Smith (KY)
Big Sandy (KY)
Paradise (KY)
Johnsonville (TN)
Cumberland (TN)
Colbert (AL)
1-4
5-6
7-8
1-2
3
4
5-6
1-2
3-4
5
1-4
5
6-7
1-4
1
2
3
1
2
1
2
1-2
3
1-4
5-6
7-10
1-2
1-4
5
Evaluated Using Detailed Procedures
Net Dependable
Generating Capacity
Capacity Factor,
Per Unit, MW Age, yr Percent
30
45
75
125
165
720
375
205
215
585
180
300
600
559
100
156
410
151
265
260
800
704
1150
125
147
173
1300
200
550
40-43
37
32
28-30
25
14
9-11
33-34
29-30
19
25-28
20
16-18
13-17
30
24
16
23
13
24
18
24
17
35-36
34-35
28-29
14
32
22
29-30
31
38-56
32-26
37
58
45-48
63
55
61
44-57
53
44-51
54-66
50
65
65
30
50
63
63
30
30
39
30
41
60
50
50
Coal
Sulfur,
Percent
3.4
3.4
3.4
2.9
2.9
2.9
4.1
4.4
4.4
4.4
0.9
2.4
2.4
1.2
1.9
1.9
1.9
2.9
2.9
1.2
1.2
2.9
2.9
1.7
1.7
1.7
2.9
2.3
2.3
Firing Type
Roof
Roof
Wall
Cyclone
Wall
Tangential
Tangential
Wall (Wet Botom)
Cyclone
Wall
Wall
Wall
Wall
Wall (Cell Burner)
Wall
Tangential
Tangential
Cyclone
Tangential
Wall
Wall
Cyclone
Cyclone
Tangential
Tangential
Wall
Wall
Wall
Wall
profile data were verified and completed
using information obtained during the 1-
day site visit.
Summary of Performance and
Cost Estimates
Using the data and information
obtained from the plant visits, site-
specific cost estimates were developed
using the IAPCS cost model. These cost
estimates reflect site-specific retrofit
costs because retrofit factors, scope
(cost) adders, and performance esti-
mates were developed and input to the
model. Figure 1 shows the methodology
used to develop the retrofit costs using
the IAPCS cost model.
For all technologies, retrofit factors and
scope adders were developed using the
Electric Power Research Institute (EPRI)
report, "Retrofit FGD Cost Estimating
Guidelines." Retrofit factors are process
area multipliers which adjust the cost
model to reflect the following location
and retrofit effects:
• Location - regional material and labor
costs, foundation and support structure
costs related to soil conditions and
seismic zone, and freeze protection
costs.
• Retrofit - access/congestion, under-
ground obstructions, and distance
between process areas.
Scope adders are additional costs that
are included in the cost of retrofit but not
in the cost model algorithm bases. These
cost adders include: a new chimney
liner, draft control modifications, equip-
ment demolition and replacement, and
particulate control modifications.
For CS, fuel cost differentials were
developed from the cost of currently
used coals using data from FERC Form
423. Two fuel price differentials (FPDs)
were evaluated: the current low to high
sulfur coal FPD and the current FPD plus
$15 a ton. The $15 a ton fuel cost
addition was assumed to span the
potential fuel price premium that would
result if extensive CS occurred due to
acid rain legislation. For PCC, the
incremental fuel cost was determined by
assuming that the plant coal had
properties similar to one of the six coals
contained in the IAPCS cost model PCC
module.
Performance estimates were devel-
oped for the spray drying technologies
and the low NOX combustion tech-
nologies. LSD, FGD and DSD SOX per-
formance estimates were developed
based on flue gas temperature and
particulate control type: ESP or fabric
filter. Low NOX burner and over-fire air
performance estimates were developed
by evaluating the furnace heat release
rates versus flue gas residence time and
coal properties.
-------
The full report describes in detail the
procedures used to develop the retrofit
factors, scope adders, and LNC control
NOX reduction estimates. However, a
brief summary of the cost results
arranged by control technology follows.
The costs presented are levelized annual
costs based on August 1987 dollars. The
capital recovery and operating cost
levelization factors are based on the
1986 EPRI Technical Assessment
Guidelines report and are: 0.18 capital
recovery factor and 1.45 operating cost
levelization factor.
FGD Cost Estimates
Figure 2 and Table 3 summarize the
plant level cost estimates developed for
conventional L/LS FGD. Figure 2 shows
the annual cost versus SOX reduction for
the 12 plants evaluated. Table 3
summarizes the plant level average
annual unit cost of control and retrofit
difficulty range for each boiler/plant.
Note that L/LS FGO was applied only
to units 6 and 7 at the Sammis Plant.
This was due to the extreme retrofit
difficulty for unit 6. The retrofit difficulty
and annual cost of control would be
much greater for units 1-5 than for unit
6, making it unlikely that conventional
FGD would be applied to units 1-5. The
plants having the lowest unit cost of
control were Cumberland and Muskin-
gum River. The Cumberland units are
large (1300 MW each), fire a 2.9% high
Plant Visits and El A - 767 Data
PM Control &
Disposal Data
Boiler Design &
Operating Data
Plot Plans &
Other Drawings
Demolition
Relocation
Performance
Estimates
Process/PM Control
Retrofit Factors
Cost Adder
Retrofit Factors
sulfur coal, and have moderate retro I
difficulty. The Muskingum River Plai
units have low unit cost of control eve
though units 1-4 have high retrof
difficulty factors; these units have hig
capacity factors (40 to 60%) and burn
very high 4.4% sulfur coal.
Figure 3 and Table 4 summarize th
plant level cost estimates developed fc
lime spray drying. Two control option
were considered for the retrofit of thi
technology: (1) reuse of the existing ES
and (2) a new fabric filter. For units wher
the SCA of the existing ESP was sma
(<43.3 m2/act. m3/sec) or the addition (
new plate area was impractical (e.g., ro(
mounted ESPs), reuse of the existin
ESP was not considered. In such case:
Integrated Air Pollution Control System Cost Model
Figure 1. Methodology using IAPCS cost model.
-------
Table 3. Summary of ULS FGD Cost and Performance Estimates
Levelized Annual Costs
Plant
Burger
Sammis
Muskingum River
Conesville
J. M. Stuart
E. W. Brown
Elmer Smith
Big Sandy
Paradise
Cumberland
Johnsonville
Colbert
DUII&I
No.
1-6
7
a
6
7
1-2
3-4
5
1
2
3
4
1
2
3
4
1
2
3
1
2
1
2
3
1
2
1-10
1-4
5
r\ju neirum
Difficulty
1.30
1.26
1.29
3.01
1.86
1.70
1.66
1.54
1.54
1.54
1.51
1.55
1.43
1.45
1.44
1.44
1.70
1.60
1.41
1.66
1.26
1.50
1.54
1.35
1.46
1.40
1.48
1.54
1.38
$/ton S02
1,218
1,112
845
1,397
1,122
671
704
496
1,961
1,779
1,526
703
1,429
1,449
1,469
1,283
2,306
1,526
1,035
1,906
867
2,018
1,416
956
598
575
1,213
1,222
807
mills/kWh
32.2
29.4
22.3
24.2
19.5
22.8
23.9
26.9
40.2
36.5
31.3
14.4
13.1
13.3
13.5
11.8
30.2
20.0
13.5
42.5
19.4
16.4
11.5
18.0
12.6
12.1
16.7
22.2
14.7
0^/2 ncuwoi/u",
tonslyr
14,500
13,300
19,500
46,200
39,900
76,600
71,300
106,800
7,100
8,100
10,900
74,500
25,200
24,900
24,300
29,700
5,700
11,600
30,000
8,900
26,000
11,600
35,800
63,300
141,000
141,000
60,000
69,200
44,200
a new fabric filter was required for
participate control after the spray drying
reactor. However, reuse of the ESP was
considered impractical for many units.
Boilers where LSD with ESP reuse (LSD
+ ESP) and LSD with new fabric filters
(LSD + FF) were applied are identified
on Figure 3 and Table 4. Note that the
cost of retrofitting new fabric filters
results in a high retrofit difficulty factor
and a high cost of control. For the
Sammis plant, only unit 7 was evaluated
because retrofit of LSD FGD would be
very costly for units 1-6.
Coal Switching and Cleaning
Figure 4 and Table 5 summarize the
plant level cost estimates developed for
coal switching (CS). For these tech-
nologies a number of plants and units
were not considered applicable for CS
for the following reasons: the units
already burn a low sulfur coal; the plant
'eceives coal by conveyor from local
mines and the construction of truck, rail,
and barge receiving facilities would be
very costly; and the units have wet
bottom boilers which can burn only coals
having special ash fusion properties. As
Figure 4 shows, the unit cost of control
for CS is very dependent upon the fuel
cost differential. The impact of paniculate
control and coal handling upgrades are
generally small by comparison.
Table 6 summarizes the plant level
cost of physical coal cleaning (PCC). A
number of plants were not evaluated for
PCC because the coal already is
extensively cleaned, and the IAPCS coal
cleaning costs are based on cleaning
run-of-mine coals. As Table 6 shows,
the unit cost and the amount of 862
reduction obtained by PCC are both low.
Sorbent Injection Cost and
Performance Estimates
Two sorbent injection technologies in
active research and development were
evaluated in this study: furnace sorbent
injection (FSI) with humidification (LIMB)
and duct spray drying (DSD). Figure 5
and Table 7 summarize the plant level
cost estimates developed for these
technologies. Not all boilers were
considered good candidates for these
technologies for the following reasons:
• LIMB and DSD with ESP reuse were
not considered practical for boilers
having an ESP SCA of <43.3 m2/act.
m3/sec, and
• DSD with ESP reuse was not
considered if the duct residence time
from the injection point after the air
heater to the ESP inlet was less than 2
sec (< 100 ft-30.5 m-of duct length).
For boilers where ESP reuse was not
considered practical, DSD with new fabric
filter was evaluated. The costs presented
for FSI assume 70% SOx control and
35% sorbent utilization.
-------
200.
is
«
1
o
Levelizec
s>.
D
/
/
//
f<
r/3
V
'/'
' /
/
'
/
/
5
Key
Plant
3 Burger
4 Sammis
5 Muskingum River
6 Conesville
7 Stuart
8 Brown
40 80 120 160 200
S02 Reduction, thousand tons/year
240
280
(B
X
O
ed Cost, mil
§
• 1
Leve/iz
§
/
/*
13
\A
14
/
/
'
/
/
Key
'„
Plant
9 Elmer Smith
1 0 Big Sandy
1 1 Paradise
12 Cumberland
13 Johnsonville
14 Colbert
Figure 2.
40 80 120 160 200
S02 Reduction, thousand tons/year
L/LS FGD cost versus S02 reduction.
240
280
-------
Table 4. Summary of ULS FGD Cost and Performance Estimates
Levelized Annual Costs
Plant
Burger
Sammis
Muskingum River
Conesville
J. M. Stuart
E. W. Brown
Bmer Smith
Big Sandy
Paradise
Cumberland
Johnsonville
Colbert
Diwer
No.
1-6
7
8
7
1-2
3-4
5
1
2
3
4
1
2
3
4
1
2
3
1
2
1
2
3
1
2
1-10
1-4
5
r\ju noiruiH
Difficulty
1.50*
1.19
1.19
-1.93
2.01*
1.96*
1.70
1.63
1.63
1.60
2.07*
1.70
1.72
1.71
1.70
2.00*
1.69
1.25
1.88*
1.38
1.88*
1.75*
1.71
1.66
1.32
1.82*
1.80*
1.30
$/ton SO2
1,463
954
704
1,012
612
650
501
1,649
1,479
1,260
751
1,634
1,678
1,709
1,422
2,016
1,194
814
1,923
846
1,953
1,507
947
624
555
1,350
1,171
784
mills/kWh
37.1
17.9
13.2
12.5
19.1
21.2
11.0
28.7
25.7
21.9
14.8
8.8
9.1
9.2
7.7
25.3
13.2
8.5
41.4
13.9
14.8
11.8
15.1
10.3
9.2
17.9
19.7
10.1
tons/yr
13,900
9,400
13,900
28,400
70,200
68,500
69,000
6,100
6,800
9,300
71.600
14,900
14,700
14,400
17,600
5,500
9,800
24,000
8,600
19,100
10,900
34,400
53,700
110,000
110,000
57,500
64,000
31,300
*This retrofit difficulty includes fabric filter; all others assume reuse of ESP.
As Figure 5 shows, the cost of FSI at
Big Sandy and Johnsonville is very high
as a result of the need to retrofit new
fabric filters.
Retrofit of Fluidized Bed
Combustion and Coal
Gasification
The retrofit potential of FBC or CG with
reuse of the existing steam turbine and
other plant facilities was qualitatively
assessed for each boiler using the
following criteria: boiler size, boiler heat
rate, boiler capacity factor, boiler age,
particulate control performance, and
S02/NOX emission levels. The following
boilers were found to qualify as potential
candidates, based on the boiler age and
size criteria: Burger boilers 1-8,
Sammis boilers 1-4, Muskingum River
boilers 1-4, Conesville boilers 1-3,
Smith boiler 1, Big Sandy boiler 1,
Johnsonville boilers 1-10, and Colbert
boilers 1-4. However, other criteria are
also important and are discussed in more
detail for each plant in the full report.
Low NOX Combustion
Figure 6 and Table 8 summarize the
plant level cost and performance
estimates for application of low NOX
burners on dry-bottom wall-fired
boilers, over-fire air on tangential-fired
boilers, and natural gas reburn on other
boilers (wet bottom and roof fired). As
Figure 6 and Table 8 show, the unit cost
of low NOX burners and over-fire air is
low (<$400/ton). However, for plants/
boilers where NCR is applied, the unit
costs are much higher ($800 to $1200
per ton). This is due to the high cost of
natural gas relative to coal ($2 per
million Btu fuel price differential).
Selective Catalytic Reduction
Cost Estimates
Figure 7 and Table 9 summarize the
plant level cost estimates for application
of SCR. Except for Sammis units 1-6,
tail-end systems were assumed (reactor
downstream of particulate control or
scrubbers). For Sammis units 1-6,
space limitations require that a hot-side,
high-dust system configuration be used
after the economizer and before the air
heater. Use of the tail-end system
minimizes unit downtime, which reduces
the uncertainty of estimating the cost of
replacement power, and maximizes the
catalyst life (cost trade-off with energy
penalty associated with flue gas
reheating).
The cost estimates for SCR presented
in this report are based on 1 year of
catalyst life. German and Japanese ex-
perience indicates that a 3- to 5-year
-------
750
<8
SL
x
100
8
o
•0
91
5 50
Legend
• LSD + ESP
x LSD + FF
/
/
/'.
'" /
6
u
/
/
/"
5
/»
Plant
3 Burger
4 Sammis
5 Muskingum River
6 Conesville
7 Stuart
8 Brown
40
80 120
160
200
240
SOi Reduction, thousand tons/year
I
'lized Cost, million
3 i
-------
Table 5. Summary of Coal Switching Unit Cost Estimates
Levelized Annual Cost
Plant
Muskingum River
Conesville
J. M. Stuart
E. W. Brown
Elmer Smith
Big Sandy
Paradise
Cumberland
Johnsonville0
Colbert
No.
1-2
1-4
5
Baseline FP&>
Baseline FPD + $i5/ton
$/ton SO2 mills/kWh $!ton SO2
mills/kWh
176
458
392
763
764
769
736
838
777
395
238
2,235
2,226
189
182
146
5.4
7.2
6.1
2.5
2.5
2.5
2.4
6.2
5.7
6.7
4.0
9.6
9.5
3.0
2.2
1.8
523
1,158
1,073
3,862
3,865
3,874
3,811
2,117
2,056
981
802
4,313
4,304
809
693
657
16.0
18 1
16.8
12.7
12 7
127
12.5
15.6
15.1
16.6
136
18.5
18.4
13.0
8.6
8.1
tons/yr
Burger
Sammis
1-6
7
8
5
6
7
571
480
459
584
585
591
12.9
10.8
103
7.1
7.1
72
1,044
945
913
1.467
1,471
1,484
234
21.2
20.5
178
17.8
18.0
12.900
11.300
16.600
16,800
32.300
27,900
96,300
8.300
56,900
9,000
9,000
8,700
10,700
6,500
16,900
6,700
19,600
6,100
18,100
106,900
11,800
30,100
*FPD = fuel price differential.
bCoal switching was not evaluated for wet bottom boilers.
c Coal switching was not evaluated for boiler at this plant, since boilers have small roof-mounted ESPs. Adding additional
plate area is not possible, and the use of 803 conditioning is likely to be marginally beneficient
For CS and PCC, the major retrofit
factors, excluding fuel price differential,
were participate control upgrade costs
and boiler performance impacts. The
latter was not assessed because detailed
coal analyses were not available. As a
result, CS was not evaluated for wet
bottom boilers, since boiler performance
impacts are likely to be significant.
For the sorbent injection technologies,
FSI and DSD, particulate control upgrade
costs would have the greatest impact.
Additionally, for DSD, sufficient duct
residence time must be available to
ensure good droplet drying.
For LNC and NGR, boiler type and
configuration are important. Low NOX
burners were applied only to dry-
bottom wall-fired boilers. Overfire air
was applied only to tangential-fired
units. NGR was applied to wet bottom
boilers and other miscellaneous boiler
types. Boiler heat release rates and
residence times in different furnace
zones would have significant effects on
NOX removal efficiency for LNC and
NGR.
SCR costs would be greatly affected
by access and congestion near the
economizer area for high dust
applications and the chimney area for
tail-end applications and by flue gas
ducting distances. For high dust
systems, boiler downtime costs and
catalyst life would be significant cost/
performance factors. For tail-end sys-
tems, the energy penalty for preheat is
balanced by increased catalyst life and
reduced catalyst costs.
As discussed earlier, the objective of
the program is to improve significantly
the cost/performance estimates used to
evaluate impacts of potential acid rain
legislation. The information presented in
this document is very useful in that
regard. However, cost comparisons have
not been made for retrofit options for
specific boilers at each plant. For
example, costs have bee projected for
L/LS FGD and the other SO2 control
technologies (LSD FGD, CS, PCC, FSI,
and DSD), but no comparison has been
made regarding the best option.
From the utility company's perspec-
tive, a decision concerning which retrofit
control to apply to a given boiler is very
complex and would be based on the
following criteria:
-------
OS
£
X
-------
Table 6. Summary of Coal Cleaning Unit Costs Estimates
Plant
Boiler
No.
Levelized Annual Cost
Baseline FPDa
$lton SO2
mills/kWh
SOZ Reduction,
tons/yr
Burger
Sammis
Muskingum Riverb
Conesvillet>
J. M. Stuart
£. W. Brown
Elmer Smith
Paradise0
Cumberland13
Johnsonville0
Colbert
1-6
7
8
5
6
7
2
3
1
2
1-4
5
600
397
363
381
382
3S6
7.546
1,549
1,556
1,502
389
375
843
527
676
595
5.7
3.7
3.4
2.5
2.5
2.6
3.2
3.2
3.2
3.1
3.2
3.1
5.9
3.7
3.7
3.3
5,200
4,700
6,900
9,200
17,700
15,300
5,700
5,600
5,500
6,700
7,400
19,100
2,800
8,100
5,300
13,400
aFPD = fuel price differential.
b Physical coal cleaning (PCC) was not evaluated because coal presently is washed to reduce sulfur and ash
prior to firing. Insufficient data were available to evaluate the cost/performance of advanced coal cleaning.
c PCC not evaluated, since boilers have small roof-mounted ESPs. Adding additional plate area is not possible,
and the use of SOS conditioing is likely to be marginally beneficient.
11
-------
13
.§
• x
/
/
12
^
Key
Plant
9 Elmer Smith
10 Big Sandy
1 1 Paradise
12 Cumberland
13 Johnsonville
14 Colbert
1
40 80 120 160
SO2 Reduction, thousand tons/year
200
Figure 5. LIMB (70% removal) and DSD costs versus SOi reduction
12
-------
TaWe 7. Summary of Sorbent Injection
Boiler
Plant No.
Burger
Sammis
Muskingum
Conesville
J. M. Stuart
E. W. Brown
Elmer Smith
Big Sandy
Paradise
Cumberland
Johnsonville
Colbert
1-6
7
8
1
2
3
4
5
6
7
1
2
3
4
5
1
2
3
4
1
2
3
4
1
2
3
1
2
1
2
3
1-2
1-10
1-4
5
Cost and Performance
Technology
DSD-FF
LIMB
LIMB
LIMB
LIMB
LIMB
LIMB
LIMB
LIMB
LIMB
DSD-FF
DSD-FF
DSD-FF
DSD-FF
LIMB
LIMB
LIMB
LIMB
DSD-FF
LIMB
LIMB
LIMB
LIMB
DSD-FF
LIMB
LIMB
DSD-FF
LIMB
DSD-FF
DSD-FF
LIMB
LIMB
DSD-FF
DSD-FF
LIMB
Estimates
Levelized
$/ton S02
1,284
602
519
736
725
693
622
540
476
499
581
583
628
640
364
597
832
754
652
655
688
607
577
7,874
773
563
7,583
588
7,684
7,302
673
469
7,747
585
567
Annual Costs
mills/kWh
25.4
12.4
10.6
3.7
3.6
3.5
3.1
7.3
6.4
6.7
14.3
14,4
16,0
6,3
9,6
14.3
13.3
12.0
10.0
4.7
4.8
4.3
4.1
17.8
7.3
5.7
26.6
10.2
10.0
7.9
9.0
7.7
11.8
8.2
8.0
SO2 Reduction,
tons/yr
10,900
10,300
15,200
3,500
3,500
3,800
4,500
18,600
35,900
31,000
27,800
27,700
27,100
26,400
83,100
5,600
6,300
8,500
55,900
79,600
79,400
78,900
23,700
4,300
9,000
23,300
6,700
20,200
8,600
26,900
49,300
279,400
44,900
53,700
34,400
13
-------
.i
a
1
Legend
• LNC
xNGR
,13
14
f
Key
Plant
3 Burger
4 Sammis
7 Stuart
S Brown
9 Elmer Smith
10 Big Sandy
12 Cumberland
13 Johnsonvitle
14 Colbert
6 8 10 12 14
/VO« Reduction, thousand tons/year
16
18
20
40
| 30
\
o
8 20
-------
1^
s
i
M 0
? UOI//IUJ 'I
elized Cos
8 S
i i
^ "-
01
~4
0
\y
/f6 /
re
X
) 2C
^
X^
) 3C
', X
/y^>
^
7
Key
Plant
3 Burger
4 Sammis
5 Musk ing urn River
6 Conesville
7 Stuart
8 Brown
) 40 Si
N0f Reduction, thousand tons/year
770-
150'
V
I
O
O
120.
90.
60
30'
j
'13
14
Key
Plant
9 Elmer Smith
10 Big Sandy
1 1 Paradise
12 Cumberland
13 Johnsonville
14 Colbert
10 20 30
NO, Reduction, thousand tons/year
40
50
Figure 7. SCR costs versus NO, reduction.
15
-------
Table 8. Summary of Low NOX Combustion Cost and Performance Estimates
Levelized Annual Costs
NOX Reductions
Plant
Burger
Sammis
Muskingum River
Conesville
J. M. Stuart
£. W. Brown
Elmer Smith
Big Sandy
Paradise
Cumberland
Johnsonville
uoiier
No.
1-2
3-4
5
6
7
8
1
2
3
4
6
7
1-2
3
4
5
1
2
3
1
2
3
4
1
2
3
1
2
1
2
1-2
3
1
2
1-6
7-10
LNC Type*
NGR
NRG
NGR
NGR
LNB
LNB
LNB
LNB
LNB
LNB
LMB
LNB
NGR
NGR
NGR
LNB
NGR
NGR
LNB
LNB
LNB
LNB
LNB
LNB
OFA
OFA
NGR
OFA
LNB
LNB
NGR
NGR
OFA
OFA
LNB
LNB
$/ton NOX
2,797
2,765
2,631
2,536
478
325
527
515
482
407
194
224
1,237
1,147
1,150
203
1,389
1,359
473
197
199
204
167
456
183
103
1,192
152
281
144
1,200
1,182
200
200
370
427
mills/kWh
6.0
5.9
5.4
5.4
1.0
0.7
0.8
0.8
0.7
0.6
0.3
0.4
4.6
4.7
4.7
0.3
5.2
5.1
1.0
0.3
0.3
0.3
0.3
1.0
0.1
0.1
5.2
0.1
0.4
0.2
4.7
4.7
0.2
0.2
0.3
1.0
Efficiency, %
50
50
50
50
50
50
35
35
35
35
40
40
50
50
50
30
50
50
50
35
35
35
35
50
25
20
50
25
35
35
50
50
20
20
25
50
tons/yr
160
170
260
300
1,070
1,570
1,000
1,000
1,100
1,400
4,600
4,000
4,200
4,300
4,200
4,400
1,300
1,500
1,100
4,400
4,400
4,200
5,200
1,000
700
1,800
1,700
1,000
2,400
6,930
8,000
13,300
6,000
6,100
300
1,200
a/JVC Types: Low NOX burners (LNB) for dry-bottom dwall-fired boilers and overfire (OFA) for tangential-fired boilers;
and natural gas reburning (NGR) used on all other boilers.
16
-------
Table 9. Summary of SCR Unit Cost Estimates
Boiler
Plant No. System Type
Burger
Sammis
Muskingum River
Conesville
J. M. Stuart
£ W. Brown
Bmer Smith
Big Sandy
Paradise
Cumberland
Johnsonville
Colbert
1-6
7
a
1
2
3
4
5
6
7
1
2
3
4
5
1
2
3
1
2
3
4
1
2
3
1
2
1
2
1
2
3
1-2
1-10
1-3
4
5
Tail-End
Tail-End
Tail-End
High-Dust
High-Dust
High-Dust
High-Dust
High-Dust
High-Dust
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Tail-End
Levelized Annual Costs3
$/ton A/OX
10,940
7,272
5,004
5,048
4,940
4,632
3,937
4,094
3,992
2,242
2,352
2,363
2,585
2,567
3,302
5,705
5,071
8,067
3,497
3,527
3,600
2,977
6,548
5,846
5,704
5,272
5,847
4,161
3,474
3,612
3,694
3,304
3,346
2,428
4,728
4,864
4,004
mills/kWh
38.6
24.8
17.1
17.4
17.0
16.0
13.6
14.2
13.8
7.8
14.1
14.1
16.8
16.7
12.2
34.
30.2
27.3
12.8
12.9
13.2
10.9
22.8
14.6
14.2
36.9
16.6
15.0
12.5
22.9
23.4
20.9
12.1
6.4
17.1
17.6
14.5
NOX Reductions
Efficiency, %
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
tons/yr
1,900
1,700
2,500
2,400
2,400
2,600
3,100
4,800
9,200
8,000
6,800
6,700
6,900
6,700
11,600
2,100
2,300
1,800
10,000
10,000
9,700
11,900
1,500
2,200
5,700
2,800
3,300
5,200
15,900
12,900
12,900
21,300
24,100
11,400
3,500
3,500
8,800
"Costs are based on 1-year catalyst life. Costs based on 3-year catalyst life would be 40-50% less.
17
-------
Table 10. Retrofit Factors Affecting Cost/Performance
X
X
X
X
X
X
Additional
Control Access and Ducting Particulate Boiler Boiler
Technology Congestion Distance Control Type Configuration
Lime/Limestone
Flue Gas
Desulfurization
Lime Spray
Drying
Coal Switching/
Blending
Physical Coal
Cleaning
Furnace Sorbent
Injection with
Humidification
(LIMB)
Duct Spray
Drying
Low A/0X
Combustion
Natural Gas
Returning
Selective
Catalytic
Reduction
X
X
X
X
X
T. E. Emmel and S. D. Piccot, are with Radian Corp., Research Triangle Park, NC
27709; and B. A. Laseke is with PEI Associates, Inc., Cincinnati, OH 45246..
Julian W. Jones is the EPA Project Officer (see below).
The complete report, entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02 and NOX
Retrofit Study," (Order No. PB 88-244 447IAS; Cost: $49.95, subject to change)
will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air and Energy Engineering Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
18
-------
o
3*.
n
co -
» <
|c
q =
2 I
- e
0~
vt
N>
CD
00
------- |