United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-85/006 Sept. 1985
&ERA Project Summary
Economics of Nitrogen
Oxides, Sulfur Oxides, and
Ash Control Systems for
Coal-Fired Utility Power Plants
J. D. Maxwell and L R. Humphries
An EPA-sponsored economic evalua-
tion was made of three processes to
reduce NOX, SO2, and ash emissions
from coal-fired utility power plants;
one based on a 3.5% eastern bitumi-
nous coal; and the other two, on 0.7%
western subbituminous coal. NOX con-
trol is based on an 80% reduction from
current new source performance stan-
dards (NSPS); S02 and fly ash control
are based on meeting the current
NSPS. Selective catalytic reduction
(SCR) is used for NOX control with both
coals. Limestone scrubbing and a cold-
side electrostatic pradpitator (ESP) are
used with the 3.5% sulfur coal. Lime
spray dryer flue gas desurfurization
(FGD) and a baghouse for particulate
collection are used with one 0.7% sulfur
coal; and limestone scrubbing and a
hot-side ESP, with the other. The eco-
nomics consist of detailed breakdowns
of the capital investments and annual
revenue requirements. For systems
based on a 500-MW power plant, capi-
tal investments range from $167 to
$187 million (333 to 373 $/kW) and first-
year annual revenue requirements from
$54 to $60 million (29 to 33 mills/kWh).
The 3.5% sulfur coal case is highest be-
cause of the higher SO2 control costs.
The case with the spray dryer and bag-
house is marginally lower in cost than
that with limestone scrubbing and hot-
side ESP. Costs for NOX control range
from 25 to 50% of the total costs,
largely because of the high cost of the
catalyst. The costs of the overall sys-
tems and the relationships of the com-
ponent costs are complexly interrelated
because of the interactions of the three
processes.
This Project Summary was devel-
oped by EPA '9 Air and Energy Engineer-
ing Research Laboratory, Research Tri-
angle Park, NC, to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report or-
dering information at back).
Introduction
Most NOX emission control require-
ments now in force are being met by
modifications to the boiler combustion
process, including: staged combustion
(bias firing, burners out of service, and
overfire air), flue gas recirculation, low
excess air, and dual-register burner de-
signs. Advanced burner and furnace de-
signs now under development have the
potential to provide significantly lower
NOX emissions than today's standards.
These new combustion systems include
fuel-staging and after-burning. How-
ever, these new designs are still several
years from commercial availability. If
stricter regulations were adopted in the
near future, these combustion modifica-
tion methods would not—at least for
several years—be adequate, and flue
gas treatment would be necessary. The
most highly developed method of flue
gas treatment for NOX control is selec-
tive catalytic reduction (SCR) in which
flue gas is treated with ammonia and
passed over a solid catalyst to reduce
the NOX to molecular nitrogen. The
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need for flue gas treatment to meet NOX
emission limits would probably be met
by the use of SCR processes, several
variants of which are offered commer-
cially. A generic SCR process, derived
from these commercial processes, is
therefore used in all three cases.
Limestone scrubbing remains the
predominant method of flue gas desul-
furization' (FGO), increasingly with pro-
visions to produce gypsum by forced or
natural oxidation to reduce waste dis-
posal problems. The use of low-sulfur
coal has, however, led to the rapid
adoption of spray dryer FGD in which
the flue gas is contacted with a fine
spray of absorbent that evaporates to
solid particles in the spray dryer and can
be collected as a solid. More -than a
dozen spray dryer FGD systems have
been selected by utilities for low- and
medium-sulfur coal applications in the
last 5 years. This trend is represented by
the use of a lime-based spray dryer sys-
tem in case 2, one of the low-sulfur coal
cases. For case 1, the high-sulfur coal
case, and case 3, the other low-sulfur
coal case, conventional limestone FGD
systems producing gypsum are used.
The use of low-sulfur coal has also led
to the adoption of new methods of fly
ash control because the ash is difficult
to collect in conventional cold-side (af-
ter the boiler air heater) electrostatic
precipitators (ESPs) that have served as
the industry standard for many years. In
many such cases, hot-side (before the
air heater) ESPs have been used be-
cause the higher ash temperature im-
proves the electrical properties of the
ash that affect the efficiency of collec-
tion. In both cases, however, strict fly
ash emission regulations (e.g., the 1979
NSPS) strained the capabilities of then-
existing ESP technology, leading to the
rapid adoption of fabric filter baghouses
for fly ash control. Baghouses, which
are proving quite effective, have also
been the predominant choice for use
with spray dryer FGD in which the fly
ash and FGD wastes are collected to-
gether. These uses are represented by
a conventional cold-side ESP in case 1,
a baghouse in case 2, and a hot-side
ESP in.case 3.
Process Descriptions
The base case designs are applied to
a new 500-MW boiler fired with pulver-
ized coal that operates 5,500 hr/yr for
30 years. The boiler meets the 1979
NSPS NOX emission requirements by
combustion modifications. The emis-
sion control systems are designed for
an 80% reduction in these NOX emis-
sions and for reduction of S02 and fly
ash emissions of the 1979 NSPS levels.
The designs upon which the costs are
based include all equipment involved in
the collection and disposal of wastes,
including a common onsite landfill, and
all boiler modifications—air heater
modifications and larger induced-draft
(ID) fans—made necessary by the pres-
ence of the emission control systems.
Major conditions are shown in Table 1.
The SCR systems consist of two trains
of insulated reactors with ash hopper
bottoms (except in case 3 with an up-
stream ESP) and provisions for chang-
ing catalyst beds. The beds are com-
posed of 0.15- by 0.15- by 1-m
honeycomb blocks in metal modules.
Flue gas is ducted from economizer (or
hot-side ESP) outlet and returned to the
air heater. Modifications to the air
heater to accommodate ammonia salt
buildup are included. An ammonia stor-
age and handling system to inject an
ammonia/air mixture in the inlet duct is
provided. An economizer bypass to
maintain the reactor temperature dur-
ing low-load operation is included. The
catalyst life is assumed to be 1 year,
with changes during scheduled boiler
outages.
The limestone FGD systems consist
of multiple trains of spray tower ab-
sorbers connected to a common inlet
plenum and discharging to the stack
plenum. Each train consists of a presat-
urator, the absorber with a hold tank
and the associated absorbent recircula-
tion system (and an oxidation tank in
case 1), and a booster fan. A steam re-
heater is included in case 1 to provide a
stack temperature of 175°F. Flue gas is
bypassed in the low-sulfur coal case to
eliminate reheating costs (in this case, a
less expensive alternative than full
scrubbing at the low removal efficiency
required). A single slurry preparation
area supplies the system. The gypsum
waste is dewatered in a thickener and
rotary vacuum filters and trucked 1 mile
to the landfill. A spare absorber train
and emergency bypasses for half of the
scrubbed flue gas are provided in all
cases. A similar arrangement is used for
the spray dryer system in case 2, except
that the baghouse booster fans also
serve for the spray dryer system. The
spray dryers are cylindrical vessels with
conical bottoms with single rotary at-
omizers. The absorbent slurry consists
Table 1. Major Design Conditions
Case 1
Case 2
Case3
Coal and boiler conditions
Coal
Coal sulfur, % as fired
Coal ash, % as fired
Btu/lb, as fired
Sulfur emitted, % of total
Fly ash, % of total ash
NOX emitted, lb/106 Btu"
Boiler size3, MW
Heat rate, Btu/kWh
Emission control
Nox control
Nox reduction, %
So2 control
Absorber trains13
Bypassed flue gas, %
SC>2 removal, overall %
SC<2 removal, absorber %
fly ash control
Fly ash removal, %c
East. bit.
3.36
15.1
11,700
92
80
0.6
500
9,500
SCR
80
Limestone FGD
5
0
89
89
Cold-side ESP
99.7
West, subbit.
0.48
6.3
8,200
85
80
0.5
500
10,500
SCR
80
Lime spray dryer
4
12
65
73
Baghouse
99.9
West, subbit.
0.48
6.3
8,200
85
80
0.5
500
10,500
SCR
80
Limestone FGD
5
28
65
90
Hot-side ESP
99.6
a. Based on coal consumption and heat rate.
b. Including one spare train.
c. In collection device, excluding upstream fallout.
'Readers more familiar with metric units are asked to use the conversion factors provided at the end of this
Summary.
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of slaked lime and recycled solids from
the baghouse.
The ash control systems consist of the
ESPs or baghouses (two parallel identi-
cal units), hoppers, conveying systems,
a bottom ash dewatering system, stor-
age silos for fly ash, and equipment for
trucking the waste to the landfill. The
bottom ash is collected in a conven-
tional hopper and sluiced to the dewa-
tering system. Fly ash is conveyed to
silos with a vacuum-pneumatic system.
The mixed fly ash and FGD waste in
case 2 is conveyed by a pressure-
vacuum pneumatic system.
Economic Procedures
The economics consist of the capital
investment in 1982 dollars and the first-
year and levelized annual revenue re-
quirements in 1984 dollars. The annual
revenue requirements consist of operat-
ing and maintenance costs plus capital
charges. The capital charges are lev-
elized in both the first-year and levelized
annual revenue requirements; whereas,
the operating and maintenance costs
are also levelized in the latter. The lev-
elizing factor in all cases is 1.886, which
represents a 6% annual inflation and a
10% discount rate over the 30-year life
of the project
Costs include all those associated
with the construction and operation of
the systems, including modifications to
the boiler air heater and the incremental
increase in the boiler ID fans to account
for the pressure drop in the emission
control equipment that is not compen-
sated for by separate booster fans. Con-
struction and operating costs of the
landfill are also included.
Costs are divided into three sections,
representing NOX, S02, and ash control,
and are further divided into categories
j-epresenting particular unit operations
within the processes. Where equipment
or operations serve more than one pro-
cess (incremental increases in boiler ID
fans and the common landfill, for exam-
ple), the costs are prorated using the
appropriate factors (pressure drops or
waste volume, for example). Baghouse
costs are not prorated, however, be-
cause of the effect of flue gas volume on
baghouse costs.
Results
Capital investments and annual rev-
enue requirements are summarized in
Tables 2 through 5. With the choice of
processes determined, at least in part
by the type of coal, and the costs of the
individual processes influenced by
Table 2.
Summary of Capital Investments in $l06a-b
Capital investment, mid-1982 $
$We
NO,
SO2
Paniculate
Total
Base case, 500 MW, 80% NOX
removal
Case 1 41.9 101.8
Case 2 50.1 54.0
Case 3 48.1 69.4
Case variation, 200 MW, 80%
NOX removal
Case 1 20.6 58.2
Case 2 24.2 31.7
Case 3 24.3 41.4
Case variation, 1,000 MW, 80%
NOX removal
Case 1 77.7 175.7
Case 2 94.8 97.4
Case3 91.2 121.1
Case variation, 500 MW, 90%
NOX removal
Case 1 48.2 101.9
Case 2 55.5 54.0
Case 3 53.9 69.4
42.9
62.6
53.5
22.6
31.4
27.8
73.3
110.7
94.6
42.9
62.7
53.5
186.6
166.7
171.0
101.5
87.3
93.5
326.6
302.9
306.9
193.0
172.2
176.8
"Table 1 lists the major design conditions for each case.
bAII values have been rounded; therefore, totals do not necessarily correspond to the sum of
the individual values indicated.
Table 3.
Summary of Capital Investments in $/KWa-b
Capital investment, mid-1982 $
$/kW
NO,
S02
Paniculate
Total
Base case, 500 MW, 80% NOX
removal
Case 1 83.7 203.7
Case 2 100.2 108.0
Case 3 96.1 138.7
Case variation, 200 MW, 80%
NOX removal
Case 1 103.1 291.0
Case 2 121.0 158.3
Case 3 121.6 206.9
Case variation, 1,000 MW, 80%
NOX removal
Case 1 77.7 175.7
Case 2 94.8 97.4
Case 3 91.2 121.1
Case variation, 500 MW, 90%
NOX removal
Case 1 96.4 203.8
Case 2 111.0 108.0
Case3 107.8 138.8
85.8
125.3
107.1
113.2
157.2
139.0
73.3
110.7
94.6
85.8
125.4
107.1
373.2
333.4
342.0
507.3
436.6
467.5
326.6
302.9
306.9
386.0
344.3
353.6
'Table 1 lists the major design conditions for each case.
bAII values have been rounded; therefore, totals do not necessarily correspond to the sum of
the individual values indicated.
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Table 4. Summary of Annual Revenue Requirements in $106 **
Annual revenue requirements, 1984 $
First year
Levelized
$10*
$106
NOX
SO,
Paniculate
Total
SO,
Paniculate
Total
Base case, 500 MW, 80% NOX removal
Case 1 21.9 28.8 9.8 60.4 35.8 41.0 12.8 89.7
Case 2 26.5 12.7 14.4 53.6 43.5 16.9 19.0 79.4
Case 3 24.7 18.0 12.1 54.8 40.4 24.9 15.8 81.0
Case variation, 200 MW, 80% NOX removal
Case 1 9.7 16.3 5.2 31.2 15.6 23.1 6.9 45.6
Case 2 11.6 7.6 7.7 26.8 18.7 10.1 10.4 39.2
Case3 11.1 11.0 6.6 28.7 17.8 15.3 8.8 41.9
Case variation, 1,000 MW, 80% NOX removal
Case 1 41.5 48.8 16.1 106.4 68.1 69.2 20.9 158.2
Case 2 51.2 22.2 24.5 97.9 84.2 29.2 31.8 145.1
Case 3 47.9 30.3 20.5 98.7 78.4 41.4 26.4 146.3
Case variation, 500 MW, 90% NOX removal
Case 1 26.1 28.8 9.8 64.6 42.9 41.0 12.8 96.7
Case 2 30.1 12.7 14.4 57.2 49.5 16.9 19.0 85.4
Case3 28.6 18.0 12.1 58.6 46.8 24.9 15.8 87.5
'Table 1 lists the major design conditions for each case.
bAII values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
Table 5. Summary of Annual Revenue Requirements in Mills/KWH6 a-b
Annual revenue requirements, 1984 $
First year
Levelized
Milts/kWh
NO,
SO,
Paniculate
Total
NOr
SO? Paniculate
Total
Base case, 500 MW, 80% NOX removal
Case 1 8.0 10.5 3.5 22.0 13.0 14.9 4.7
Case 2 9.6 4.6 5.2 19.5 15.8 6.2 6.9
Case3 9.0 6.5 4.4 19.9 14.7 9.0 5.7
Case variation, 200 MW, 80% NOX removal
Case 1 8.8 14.8 4.7 28.4 14.2 21.0 6.3
Case 2 10.6 6.9 7.0 24.4 17.0 9.2 9.4
Case 3 10.1 10.0 6.0 26.1 16.2 13.9 8.0
Case varaition, 1,000 MW, 80% NOX removal
Case 1 7.5 8.9 2.9 19.3 12.4 12.6 3.8
Case 2 9.3 4.0 4.5 17.8 15.3 5.3 5.8
Case3 8.7 5.5 3.7 18.0 14.3 7.5 4.8
Case variation, 500 MW, 90% NOX removal
Case 1 9.5 10.5 3.5 23.5 15.6 14.9 4.7
Case 2 10.9 4.6 5.2 20.8 18.0 6.2 6.9
Case3 10.4 6.5 4.4 21.3 17.0 9.0 5.7
32.6
28.9
29.5
41.5
85.7
38.1
28.8
26.4
26.6
35.2
31.1
31.8
"Table 1 lists the major design conditions for each case.
bAII values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
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other processes in the system, eco-
nomic comparisons on a process-by-
process basis must be interpreted with
care, as seen in the detailed breakdown
of the base case costs.
Base Case Capital Investments
Breakdowns of the base case capital
investments are shown in Table 6. The
case 1 (3.5% sulfur coal, SCR, limestone
FGD, and cold-side ESP) capital invest-
ment is $187 million (373 $/kW), of
which NOX control accounts for 22% of
the total; S02 control, 55%; and particu-
late control, 22%. The case 2 (0.7% sul-
fur coal, SCR, spray dryer FGD, and bag-
house) capital investment is $167
million (333 $/kW), and the breakdown
is 30%, 32%, and 38%. The case 3 (0.7%
sulfur coal, hot-side ESP, SCR, and lime-
stone FGD) capital investment is $171
million (342 $/kW), and the breakdown
is 28%, 40%, and 32%. The low percent-
age for S02 control in case 2 with the
spray dryer results from the paniculate
collection costs for FGD waste being
combined with the fly ash collection
costs and assigned to particulate control
costs.
NOX Control
For NOX control, the most important
capital cost is the initial catalyst charge,
which is almost one-third of the total
capital investment. Most of the remain-
ing capital costs are for the reactor and
the associated internal and external cat-
alyst supports and handling system,
and for the incremental fan cost and flue
gas ductwork associated with flue gas
handling. The remaining capital costs-
ammonia storage and injection system,
air heater modification, waste disposal
(of spent catalyst), land, and royalties—
are relatively minor. Incremental fan
costs are minor; 90% of the flue gas-
handling costs is for ductwork.
Most of the capital costs are directly
related to the flue gas volume, particu-
larly for the major cost areas. As a re-
sult, the total capital investment for NOX
control in case 1 is lowest because of
lower flue gas volume with the high-Btu
coal. Case 3 is slightly lower than case 2
because of the absence of fly ash.
Air heater modification costs are
associated with the increase in size, the
more tightly packed elements, and the
use of thicker and more corrosion-
resistant elements.
The ammonia storage and injection
costs are almost the same for all three
cases. The only cost differences result
from differences in the injection grid,
which vary with the flue gas duct size
and design.
S02 Control
The capital investments for SO2 con-
trol are highest for case 1 and lowest for
case 2, but the capital investment for
case 2 does not contain the costs for
FGD waste collection. In all three cases,
most of the costs are associated with
the S02 absorption area (the absorbers
and the absorbent liquid system or the
spray dryers) and the flue gas-handling
area (fans and ductwork). These two
areas account for 65% of the process
equipment costs in case 1 and about
80% of the process equipment costs in
cases 2 and 3.
The higher capital investment for
case 1 (as compared with case 3) is al-
most entirely related to the larger quan-
tities of SO2 removed. The materials
handling (limestone), feed preparation,
Table 6. Base Case Capital Investment Comparison8
Case 1,$1000s
Process capital
NH3 storage and injection
Reactor
Flue gas handling
Air heater
Materials handling
Feed preparation
SO2 absorption
Oxidation
Reheat
Solids separation
Lime particulate recycle
Particulate removal and storage
Particulate transfer
NOX
1,314
7,829
3,843
819
S02
11,343
2,528
4.717
20,411
2,677
3,653
3,681
Particulate Total
1,314
7,829
1,311 16,497
819
2,528
4,717
20,411
2,677
3,653
3,681
10,509 10,509
5,636 5,636
NOX
1,328
9,278
4,543
1,220
Case 2, $1000s
S02
7,374
1,132
1,258
12,992
2,140
Particulate Total
1,328
9,278
4,961 16,878
1,220
1,132
1,258
12,992
2,140
15,446 15,446
6,779 6,779
NOX
1,297
8,453
5,386
861
Case 3, $1000s
S02 Particulate
11,175 4,290
1,266
2,363
18,070
2,265
14,354
4,378
Total
1,297
8,453
20,851
861
1,266
2,363
18,070
2,265
14,354
4,378
Total process capital, $1000s
Other Capital Investment
13,805 49,010 17,456
80,271 16,369 24,896 27,186
68,451 15,997 35,139 23,022
74,158
Waste disposal direct investment
Land
Catalyst
Royalty
Other»
Total, $1000s
Total, $/kW°
19
10
12,028
463
15,530
41,855
83.7
4,011
458
48,360
101,839
203.7
3,344
377
21,710
42,887
85.8
7,374
845
12,028
463
85,600
186,581
373.2
34
15
14,678
563
18,431
50,090
100.2
527
75
28,478
53,976
108.0
2,749
326
32,388
62,649
125.3
3,310
416
14,678
S63
79,297
166,715
333.4
30
15
13,455
563
18,001
48,061
96.1
847
113
33,272
69,371
138.7
2,628
313
27,583
53,546
107.1
3,505
441
13,455
563
78,856
170,978
342.0
'Table 1 lists the major design conditions for each case.
bConsists of costs for "services, utilities, and miscellaneous;" all six items of "indirect investment;" "allowance for start-up and modifications;'
"interest during construction;" and "working capital" as listed in the appendix tables of the full report.
CAII values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
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and solids separation area costs are
roughly two times higher and waste dis-
posal costs are almost five times higher
for case 1 than for case 3. In addition,
the S02 removal requirements in case 1
require both full scrubbing—necessitat-
ing steam reheat of the flue gas—and
forced oxidation, neither of which is
necessary in case 3.
SOX control in case 2 is the least ex-
pensive, primarily because of lower
costs in the S02 absorption area (be-
cause there is no liquid recirculation
system) and in the flue-gas-handling
areas (because of the lower pressure
drop in the spray dryers and the econ-
omy of scale with fan costs prorated be-
tween S02 and particulate control). An
accurate comparison of S02 control
capital investment in cases 2 and 3,
however, must include the costs of par-
ticulate collection, which are discussed
in the following section.
Particulate Control
The capital investments for particu-
late control are $43 million for case 1,
$63 million for case 2, and $54 million
for case 3. In all three cases, the particu-
late removal and storage area accounts
for about 60% of the total particulate
control process equipment costs, with
the ESPs or baghouses and their hop-
pers accounting for most of the area
cost. The cold-side ESPs of case 1 have
an installed cost of $5.9 million, and the
hot-side ESPs of case 3 have an in-
stalled cost of $9.8 million. Most of this
difference is a result of the larger flue
gas volume in case 3—both in an abso-
lute sense and because the ESPs in
case 3 operate at a higher temperature.
The baghouses have an installed cost of
$7.4 million. Much of the cost difference
between cases 2 and 3 is a result of the
larger size of the baghouses and the
corresponding larger and more com-
plex hoppers required.
Particulate transfer process equip-
ment costs are $5.6 million for case 1,
$6.8 million for case 2, and $4.4 million
for case 3. Case 2 has a more compli-
cated pressure-vacuum conveying sys-
tem, which accounts for most of the
cost difference between cases 2 and 3.
Flue-gas-handling costs are $1.3 mil-
lion for case 1, $5.0 million for case 2,
and $4.4 million for case 3. The lower
costs for case 1 result from the smaller
absolute volume and lower tempera-
ture of the flue gas. In addition, the
costs for cases 1 and 3 are almost totally
composed of the cost of ductwork since
the incremental fan costs are negligible.
In the case of the baghouses, however,
fan costs are significant, about equal to
ductwork costs, because of the large
pressure drop through the baghouses.
Base Case Comparisons - An-
nual Revenue Requirements
The base case annual revenue re-
quirements are shown in Table 7. The
first-year annual revenue requirements
for case 1 (3.5% sulfur coal, SCR, lime-
stone FGD, and cold-side ESP) are $60
million (22 mills/kWh) with 36% associ-
ated with NOX control, 48% with SO2
control, and 16% with particulate con-
trol. For case 2 (0.7% sulfur coal, SCR,
spray dryer FGD, and baghouse), the
first-year annual revenue requirements
are $54 million (19.5 mills/kWh) with
49% associated with NOX control, 24%
with S02 control, and 27% with particu-
late control. For case 3 (0.7% sulfur coal,
hot-side ESP, SCR, and limestone FGD),
the first-year annual revenue require-
ments are $55 million (19.9 mills/kWh)
with 45% associated with NOX control,
33% with SO2 control, and 22% with par-
ticulate control.
The levelized annual revenue require-
Table 7. Annual Revenue Requirement Element Analysis for Base Cases
500-MW Unit with 80% NOX Removal*
Case 1
Direct costs
Ammonia
Catalyst
Lime/limestone
Operating labor and supervision
Process
Landfill
Steam
Electricity
Fuel
Maintenance
Analysis
Other
NOX
364
13,899
66
3
51
278
1
586
46
13
S02
1,216
658
523
1,369
2,146
162
4,276
104
27
Particulate
230
436
581
135
1,025
6
19
Total
364
13,889
1,216
954
962
1.420
3,005
298
5,887
156
59
NOX
336
16,962
66
5
65
492
1
695
46
17
Case 2
SO,
708
263
83
780
18
1,599
88
16
Particulate
296
435
966
95
1,811
6
36
Total
336
16,962
708
625
523
65
2,238
114
4,105
140
69
NOX
336
15,549
66
4
63
391
1
679
46
41
Case3
S02
186
594
127
1,477
28
3,005
69
19
Particulate
230
393
993
87
1,299
6
36
Total
336
15,549
186
890
524
63
2,861
116
4,983
121
96
Total direct costs, $1000
INDIRECT COSTS
Overheads
Capital charges
Total first-year annual revenue
requirements
57000s
Mills/kWhi>
15,307 10,481
421
6,153
21,881
8.0
3,337
14,970
28,788
10.5
2,432
1,018
6,304
9,754
3.5
28,220 18,68S 3,555
4,776 487
27,427 7,363
60,423 26,535
22.0 9.6
1,220
7,934
12,709
4.6
3,645
1,529
9,209
14,383
5.2
25,885 17,176 5,505
3,236
24,506
477
7,065
53,627 24,718
19.5 9.0
2,277
10,198
17,980
6.5
3,044
1,157
7,871
12,072
4.4
25,725
3,911
25,134
54,770
19.9
Levelized annual revenue
requirements
$1000s
Mills/kWht-
35,816
13.0
41,031
14.9
12,811
4.7
89,658
32.6
43,521
15.8
16,940
6.2
18,967
6.9
79,428
28.9
40,359 24,875
14.7 9.0
15,794
5.7
81,028
29.5
'Table 1 lists the major design conditions for each case.
hAII values have been rounded; therefore, totals do not necessarily correspond to the sum of the individual values indicated.
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ments are $90 million (33 mills/kWh),
$79 million (29 mills/kWh), and $81 mil-
lion (30 mills/kWh) for cases 1, 2, and 3,
respectively. For cases 1, 2, and 3, re-
spectively, 40%, 55%, and 50% of the
total levelized annual revenue require-
ments are associated with NOX control;
46%, 21%, and 31% with S02 control;
and 14%, 24%, and 19% with paniculate
control.
The cost per ton of pollutant removed
is presented for the base cases in
Table 8 based on each of first-year and
levelized annual revenue requirements.
A comparison on this basis indicates
that NOX control is significantly less cost
effective than S02 and paniculate con-
trol. For example, with first-year annual
revenue requirements, the costs in
Table 8 range from about 3,500 $/ton to
4,600 $/ton for NOX control, from about
500 $/ton to over 1,900 $/ton for S02
control, and from 60 $/ton to 130 $/ton
for particulate control.
NOX Control
The first-year annual revenue require-
ments for the NOX control processes in
cases 1, 2, and 3, respectively, are $22
million (8 mills/kWh), $27 million (10
mills/kWh), and $25 million (9 mills/
kWh). In all cases, the catalyst replace-
ment costs are the overwhelmingly
dominant cost elements; over 90% of
the direct costs and two-thirds of the
total annual revenue requirements are
for the yearly replacement of catalyst.
Except for this cost, the annual revenue
requirements are modest, appreciably
less than the costs for similar cost cate-
gories for S02 and paniculate control.
S02 Control
The first-year annual revenue require-
ments for the S02 control processes are
$29 million (11 mills/kWh), $13 million
(5 mills/kWh), and $18 million (7 mills/
kWh) for cases 1, 2, and 3, respectively.
Again, case 2 with the spray dryer does
not include costs associated with opera-
tion of the baghouse. Excluding capital
charges (which are proportional to capi-
tal investment) and overheads (which
are proportional to the direct costs), the
direct costs of the annual revenue re-
quirements reflect appreciably wider
differences in operating costs. The di-
rect costs are $10.5 million, $3.6 million,
and $5.5 million for cases 1, 2, and 3,
respectively. Maintenance costs are the
highest element of direct costs in all
three cases, followed again in all three
cases by electricity costs. Steam for re-
Table 8. Cost per Ton of Pollutant Removed for Base Cases
500-MW Unit with 80% NOX Removal
$/ton, 1984$
First year
Case 1
Case 2
Case3
NOX
3,490
4,600
4,280
SO2
470
1,370
1,930
Paniculate
60
130
110
NOX
5,710
7,540
6,990
Levelized
SO2
670
1,820
2,680
Paniculate
80
170
140
heating the flue gas is the third largest
direct cost (13% of the total) in case 1, a
cost not incurred by cases 2 and 3,
which have bypass reheat. These costs
and the. remaining direct costs are all
higher for case 1 than the correspond-
ing costs for cases 2 and 3, a result of
the large quantity of S02 removed for
case 1. With the exception of lime costs,
which are 20% of the total direct costs,
case 2 has lower direct costs in every
category as compared with case 3.
Paniculate Control
The first-year annual revenue require-
ments for particulate control are $10
million (4 mills/kWh), $14 million
(5 mills/kWh), and $12 million (4 mills/
kWh) for cases 1, 2, and 3, respectively.
The annual revenue requirements for
case 2, however, also include the collec-
tion of the spray dryer FGD solids.
Among the direct costs, maintenance
costs are the highest direct cost in all
three cases, followed by electricity costs
and labor costs. Maintenance costs are
highest for case 2, which are about 75%
higher than case 1 and 40% higher than
case 3. Electricity costs are lowest for
case 1 and highest for case 3, while
case 2 has only slightly lower electricity
costs than case 3. Labor costs do not
differ appreciably, although process
labor in case 2 is about 25% higher than
in cases 1 and 3.
Energy Requirements
The energy consumptions of the base
cases, expressed in Btu equivalents,
are shown in Table 9. The total energy
requirements range from 4.89% of the
boiler capacity for case 1 to 2.31% of the
boiler capacity for case 2. The NOX con-
trol energy requirements are the lowest
in all three cases and most are for the
incremental electricity consumption of
the boiler ID fan that compensates for
the relatively small pressure loss in the
reactors. For SOX control, cases 1 and 3
have large electricity requirements be-
cause of the FGD booster fans and the
pumping requirement for the absorbent
liquid recirculation systems. These are
similar in both cases. The electricity re-
quirements for the spray dryer in case 2
are lower because there is no liquid re-
circulation system. Paniculate control
energy requirements in cases 1 and 3
are mostly for-ESP electricity, which is
substantially lower for the cold-side
ESP. In case 2, most of the electricity is
for the booster ID fans that compensate
for the relatively higher pressure drop in
the baghouse.
Power Unit Size Case Variation
The capital investments and annual
revenue requirements of systems for
200-MW, 500-MW, and 1,000-MW sys-
tems are shown in Tables 2 through 5.
Compared with the 200-MW systems,
the 500-MW systems are 83% to 91%
higher and the 1,000-MW systems are
222% to 247% higher in capital invest-
ment. In terms of $/kW, the 1,000-MW
systems are about one-third less expen-
sive, however, because of the economy
of scale. The general relationships of
the three cases remain the same at all
three power unit sizes. The rate of capi-
tal investment increase is greatest for
the NOX control processes (an increase
of 275% to 292% between the 200-MW
and 1,000-MW sizes, as compared with
193% to 207% for the S02 control pro-
cesses and 224% to 253% for the partic-
ulate control processes), and it is also
higher for the spray dryer FGD process
and the baghouse than for the lime-
stone FGD process and ESPs. As a re-
sult, the rate of capital investment in-
crease with size is greatest for case 2.
Compared with the 200-MW systems,
the annual revenue requirements of
500-MW systems are 91% to 100%
higher, the 1,000-MW systems are 241%
to 265% higher, and there is approxi-
mately a one-third reduction in costs in
terms of $/kWh. As with capital invest-
-------
ment, the annual revenue requirements
retain the same general relationships at
the three power unit sizes, the rates of
increase for the NOX control processes
are higher (328% to 341% between the
200-MW and the 1,000-MW sizes, com-
pared with 175% to 199% for the S02
control processes and 210% to 218% for
the paniculate control processes) and
the rates for the spray dryer FGD and
bag house are higher than those of the
limestone FGD systems and ESPs.
2-Year Catalyst Life Case
Variation
To illustrate the effect of catalyst life
on annual revenue requirements, the
annual revenue requirement for the
three 500-MW base cases were also de-
termined for a 2-year catalyst life. The
only change in NOX control annual rev-
enue requirements is a reduction in the
catalyst cost by 50%—$7.0 million,
$8.5 million, and $7.8 million for cases
1,2, and 3, respectively. The longer cat-
alyst life reduces the annual revenue re-
quirements of NOX control by one-third.
The annual revenue requirements of the
overall systems are reduced by 12% to
16%.
90 Percent NOX Reduction Case
Variation
To evaluate the economic effects of a
90% reduction in NOX, as compared
with the 80% used in the other evalua-
tions, the economics of the three 500-
MW cases were determined with 90%
NOX reduction. The primary differences
from the base case conditions are an
NH3:NOX ratio of 0.91:1.0 instead of
0.81:1.0, a 12% increase, and an in-
crease in catalyst (based on vendor rec-
ommendations) of 22.5% for case 1,
15.0% for case 2, and 18.0% for case 3.
The capital investments of the NOX con-
trol processes are increased 11 % to 15%
and the total for the three systems by
3% to 4%, all of which is a result of the
increase in NOX reduction. The first-year
annual revenue requirements for the
NOX process are increased 19%, 14%,
and 16% for cases 1, 2, and 3, respec-
tively. The effect on the annual revenue
requirements of the overall system of
increasing the NOX from 80% to 90% is
an increase of 7% in all three cases.
Ammonia Price Case Variation
Changes in the price of ammonia
would have little effect on the overall
cost of the NOX control process. The an-
nual revenue requirements for the NOX
Table 9. Comparison of Base Case Energy Requirements
Case
Steam,
106 Btu/hr
Electricity,
106 Btu/hr
Diesel fuel,
106 Btu/hr
Percent of
power unit,
input energy
Case 1"
NOX
SOX
Paniculate
Total
Case 2"
NOX
SOX
Paniculate
Total
Case 3"
NOX
SOX
Paniculate
Total
3.15
83.79
0.00
86.94
4,00
0.00
0.00
4.00
3.88
0.00
0.00
3.88
12.97
100.20
27.14
140.31
25.40
40.26
49.85
115.51
20.18
76.20
51.22
147.60
0.01
2.65
2.20
4.86
0.02
0.30
1.55
1.87
0.02
0.46
1.41
1.89
0.34
3.93
0.62
4.89
0.56
0.77
0.98
2.31
0.46
1.46
1.00
2.92
Note: Does not include energy requirement represented by raw materials.
"Based on a 500-MW boiler, a gross heat rate of 9,500 Btu/kWh for generation of electricity, and
a boiler efficiency of 90% for generation of steam.
bBased on a 500-MW boiler, a gross heat rate of 10,500 Btu/kWh for generation of electricity,
and a boiler efficiency of 90% for generation of steam.
control processes (in the 500-MW base
case) increase only 1.5% to 1.9% as the
ammonia price is doubled from the
base case value of 155 $/ton to 310 $/
ton.
Conclusions
The total costs for case 1, based on
3.5% sulfur coal, and cases 2 and 3,
based on 0.7% sulfur coal, differ less
than 15% in capital investment and an-
nual revenue requirements in spite of
the differing control processes. This is a
result in part of offsetting differences—
the much higher SO2 control costs for
case 1 are offset by lower fly ash control
costs and a smaller flue gas volume.
The costs for the two low-sulfur coal
cases, one with a spray dryer FGD sys-
tem and baghouse and the other-with
limestone FGD and a hot-side ESP, dif-
fer only marginally in cost. In the two
low-sulfur coal cases, the low spray
dryer FGD costs and the advantage of
combined •particulate collection are off-
set by the higher NOX control costs and
higher baghouse costs. When only the
S02 and fly ash control costs are com-
pared, the spray dryer-baghouse case is
5% lower in capital investment and 12%
lower in annual revenue requirements
than the hot-side ESP and limestone
FGD case.
The combined emission control pro-
cesses increase the power plant capital
investment by about 35% on the aver-
age, of which the NOX portion is about
one-third. Base on levelized annual rev-
enue requirements, the average in-
crease in the cost of power is about
45%, of which the NOX portion is about
half.
The energy requirements of 2% to 5%
of the boiler input energy are mostly for
SO2 and particulate control. For the
cases with limestone FGD, S02 control
has the highest energy requirements.
The use of flue gas treatment for IMOX
control, such as the SCR process in this
study, would add significantly to emis-
sion control costs. An SCR process for a
500-MW power plant would have a cap-
ital investment of 80 to 100 $/kW and
annual revenue requirements of 8 to
9 mills/kWh. The high cost is largely as-
sociated with the catalyst replacement
cost, which accounts for 90% of the di-
rect costs in annual revenue require-
ments. A 2-year catalyst life reduces the
annual revenue requirements by over
one-third, however, so the costs for NOX
control in this study, which are based on
a 1-year life, could be substantially re-
duced if extended catalyst lives are
attained.
Other than catalyst life, the main fac-
8
-------
tor affecting N0>< control costs is the flue
gas volume which determines the fan
and ductwork costs and the catalyst vol-
ume. Increasing the NOX reduction effi-
ciency from 80% to 90% increases the
costs by 10% to 20%, again because of
the larger catalyst volume needed. Am-
monia costs have almost no effect on
costs; doubling the price of ammonia
increases the annual revenue require-
ments by about 2%.
Although the costs of NOX control are
in the same general range as those for
S02 and fly ash control, if the processes
are compared on the basis of the
pounds of pollutants reduced, the costs
for NOX control are 2 to 10 times greater
than for S02 control and 40 to 60 times
greater than for ash control.
In S02 control, the major costs are as-
sociated with the absorption area and
flue gas handling (ductwork and fans).
These costs do not differ greatly among
the three cases because of offsetting dif-
ferences—a larger cost for liquid circu-
lation in the high-sulfur coal case but a
larger flue gas volume in the low-sulfur
coal cases, which requires larger equip-
ment and has larger fan costs. The
higher costs for the high-sulfur coal
case are in large part the result of the
much larger quantity of sulfur removed:
the materials-handling, waste-handling,
and disposal costs are two to five times
higher for the high-sulfur coal case than
for the low-sulfur coal case with lime-
stone FGD.
Conversion Factors
Certain non-metric units are used in
this Summary for the reader's conve-
nience. Readers who are more familiar
with metric units may use the following
to convert to that system:
Non-metric Times Yields metric
Btu
°F
Ib
mi
ton
1.06
5/9(°F-32)
0.454
1.61
907.2
kJ
°C
kg
km
kg
J, D. Maxwell and L R. Humphries are with TV A, Off ice of Power, Muscle Shoals,
AL 35660.
J. David Mobley is the EPA Project Officer (see below).
The complete report, entitled "Economics of Nitrogen Oxides, Sulfur Oxides, and
A sh Control Systems for Coal-Fired Utility Power Plants," (Order No. PB 85-243
103/AS; Cost: $28.95, 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 Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
if U. S. GOVERNMENT PRINTING OFFKU985/559-111/20695
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