METHODOLOGY,
ASSUMPTIONS,
AND
REFERENCES
PRELIMINARY
NOx
CONTROLS
COST
ESTIMATES
FOR
INDUSTRIAL
BOILERS
By
Sikander
Khan
Environmental
Engineer,
U.
S.
EPA
OCTOBER­
NOVEMBER
2003
Preliminary
NOx
Controls
Cost
Estimates
2
PRELIMINARY
COST
ESTIMATES
FOR
NOx
CONTROLS
INDUSTRIAL
BOILERS
1.0
METHODOLOGY
The
cost
estimates
covered
in
this
report
were
developed
as
part
of
the
investigations
conducted
for
the
proposed
Interstate
Air
Quality
Rule
(
IAQR)
for
industrial
boilers.
These
costs
are
preliminary
and
are
being
reviewed
further
by
the
EPA.

The
costs
were
developed
for
three
boiler
sizes,
with
heat
inputs
of
100,
250,
and
1,000
MMBtu/
hr.
The
following
NOx
control
technologies
were
included
in
these
estimates
for
coal­,
natural
gas­,
and
oil­
fired
boilers
(
except
as
noted
below):

Low­
NOx
burner
(
LNB)
Overfire
air
(
OFA)
Gas
recirculation
(
GR)
(
only
for
gas­
and
oil­
fired
boilers)
SCR
SNCR
It
is
to
be
noted
that
the
purpose
of
this
evaluation
was
to
develop
cost
information
for
a
large
range
of
industrial
boiler
sizes
and
associated
NOx
control
technologies.
The
decision
on
the
use
of
this
information
in
the
proposed
IAQR
will
be
made
as
part
of
the
Rule
itself.

The
methodology
can
be
divided
into
two
major
activities:
1)
Developing
design
basis
for
each
NOx
control
system
and
determining
its
operating
impacts
on
the
boiler
performance
and
2)
determining
capital
and
operating
costs
associated
with
retrofitting
the
NOx
control
system.
These
two
activities,
along
with
the
associated
assumptions
and
references,
are
described
below.

2.0
DESIGN
BASIS
AND
PERFORMANCE
IMPACTS
Combustion
and
boiler
efficiency
calculations
were
performed
using
standard
procedures(
1,2),
for
the
three
boiler
sizes
of
100,
250,
and
1,000
MMBtu/
hr.
Tables
1
and
2
summarize
the
key
data
determined
from
these
calculations
for
the
three
boilers
firing
coal,
oil,
and
gas.
In
addition,
the
average
uncontrolled,
baseline
NOx
levels
for
these
boilers
were
established
as
follows
(
see
Attachments
1
and
2):

1.
Coal­
fired
boilers
(
bituminous
and
sub­
bituminous
coals):
0.72
lb/
MMBtu
2.
Gas­
fired
boilers:
0.25
lb/
MMBtu
3.
Oil­
fired
boilers:
0.22
lb/
MMBtu
The
above
NOx
levels
are
mainly
based
on
the
ICI
database.
Based
on
a
further
clarification
provided
by
ICF(
3),
the
NOx
levels
provided
in
Attachment
1
for
oil
firing
do
Preliminary
NOx
Controls
Cost
Estimates
3
not
represent
the
maximum
levels
reported
in
the
ICI
database.
Therefore,
the
costs
were
calculated
for
two
additional
baseline
NOx
levels
of
0.36
and
0.5
lb/
MMBtu.
ICF
indicated
that
these
costs
would
be
applied
selectively
to
the
oil­
fired
boilers
with
the
reported
baseline
levels
around
these
two
high
values.

The
above
information
was
used
to
determine
the
NOx
reduction
levels
and
the
boiler
performance
impacts,
as
described
below
separately
for
each
type
of
control
technology:

2.1
LNB,
OFA,
and
GR
The
NOx
reduction
levels
achievable
with
LNB,
OFA,
and
GR
technologies
for
different
fuels
are
summarized
in
Table
3,
along
with
the
supporting
references.
The
following
assumptions
and
criteria
were
used
to
establish
the
impacts
of
these
technologies
on
the
plant
performance:

1.
With
the
use
of
OFA
on
coal
firing,
the
unburned
carbon
level
at
the
boiler
outlet
increases
by
50
percent.
This
increase
in
the
unburned
carbon
level
reduces
the
boiler
efficiency
and
results
in
an
increased
coal
consumption
and
auxiliary
power
consumption
associated
with
the
draft
fans.

2.
The
GR
systems
for
the
gas­
and
oil­
fired
boilers
are
designed
for
a
recirculation
rate
of
20
percent.
For
full­
load
operation,
a
gas
recirculation
rate
of
15
percent
is
used
to
estimate
the
fan
power
consumption
requirement.

3.
LNB
and
OFA
do
not
result
in
a
change
in
the
gas­
and
oil­
fired
boiler
efficiencies.
In
general,
the
gas
recirculation
does
not
have
a
substantial
impact
on
the
heat
transfer
within
the
boiler
and
the
original
steam
temperatures
can
be
maintained.
It
is
recognized
that
some
boiler
would
require
modification
of
the
heating
surfaces
for
these
temperatures.

The
plant
performance
impacts
associated
with
the
use
of
LNB,
OFA,
and
GR
are
summarized
in
Table
4.
These
impacts
were
used
for
the
estimation
of
operating
resulting
from
the
use
of
these
technologies.

2.2
SCR
The
SCR
technology
is
considered
applicable
to
all
three
fuel
(
coal,
gas,
and
oil)
applications.
A
conservative
NOx
reduction
effectiveness
of
80
percent
was
selected
for
this
estimating
effort.
The
following
assumptions
and
criteria
were
used
to
establish
the
SCR
design
parameters
and
the
impacts
on
the
plant
performance:

1.
The
methodology
described
in
Attachment
5
was
used
to
estimate
the
catalyst
volumes
for
various
boiler
applications.
The
space
velocities
(
1/
hr)
used
were
3,750
for
coal,
16,800
for
gas,
and
11,800
for
oil.
The
ammonia
slip
levels
used
were
5
ppm
for
coal
and
oil
and
10
ppm
for
gas.
Preliminary
NOx
Controls
Cost
Estimates
4
2.
The
reagent
was
assumed
to
be
anhydrous
ammonia
with
electrical
heating
for
vaporization.

3.
The
pressure
drop
through
the
SCR
reactor
and
additional
ductwork
was
assumed
to
be
6
in.
wt.

4.
Catalyst
replacement
requirement
was
based
on
a
very
conservative
assumption
of
1/
3rd
of
the
catalyst
being
replaced
every
year.
There
is
substantial
industry
information
available
that
the
average
catalyst
life
span,
especially
with
catalyst
management
schemes,
is
substantially
more
than
the
3
years
assumed
for
these
estimates
(
see
Attachment
6).

The
above
assumptions
were
used
to
determine
the
impacts
of
the
use
of
SCR
on
plant
performance,
which
are
summarized
in
Table
5.

2.3
SNCR
The
cost
estimates
have
been
developed
for
SNCR
systems
for
all
three
fuel
applications.
However,
it
is
recognized
that
SNCR
technology
may
not,
in
general,
be
effective
for
small,
shop­
assembled
gas­
and
oil­
fired
boilers
(
the
physical
constraints
associated
with
such
boilers
may
not
permit
proper
location
of
the
SNCR
reagent
injection
nozzles).

The
SNCR
system
design
and
boiler
performance
impacts
have
been
estimated,
based
on
the
methodology
provided
in
an
EPRI
report(
4).
Additional
assumptions
and
criteria
used
are
as
follows:

1.
A
NOx
reduction
effectiveness
of
40
percent
was
used
for
all
boiler
cases.
Attachment
7
lists
information
on
many
SNCR
installations,
especially
for
the
smaller
boiler
sizes,
which
supports
the
40
percent
effectiveness
level
selected
for
this
study.

2.
The
reagent
was
assumed
to
be
urea.

3.
Because
of
the
injection
of
water
within
the
boiler,
as
part
of
the
SNCR
process,
there
will
be
a
reduction
in
boiler
efficiency.
This
reduction
will
result
in
increased
fuel
consumption
and
ash
generation,
as
applicable(
4).

Table
6
summarizes
the
plant
performance
impacts
resulting
from
the
use
of
SNCR.

3.0
CAPITAL
AND
LEVELIZED
COSTS
The
capital
costs
($/
MMBtu/
hr)
for
the
application
of
the
NOx
control
technologies
for
various
boiler
sizes
included
in
this
evaluation
were
based
on
recent
industry
data(
5)
and
Attachments
3
and
5.
In
general,
these
costs
were
identified
for
one
boiler
size
and
then
scaling
factors
were
used
to
project
these
costs
for
other
boiler
sizes.
The
costs
are
based
on
1999
dollars.
Preliminary
NOx
Controls
Cost
Estimates
5
The
levelized
costs
($/
ton
of
NOx
removed)
were
calculated
using
the
estimates
of
the
capital
costs
and
increased
consumable
rates
associated
with
each
technology,
as
shown
in
Tables
4
through
7.
The
economic
factors
used
in
these
calculations(
5­
9)
were
as
follows:

Anhydrous
ammonia,
$/
ton
260
Urea,
$/
gal
0.95
Water,
$/
gal
0.0006
Bituminous
coal,
$/
MMBtu
1.45
Sub­
bituminous
coal,
$/
MMBtu
1.20
Oil,
$/
MMBtu
3.5
Gas,
$/
MMBtu
5.0
Power,
mills/
kwh
25.0
Solid
waste
disposal,
$/
ton
12
Operator
cost,
$/
hr
30
SCR
catalyst,
$/
cu.
ft.
396
Useful
life,
years
30
Carrying
charges,
%
12.00
Levelization
factor
1.0
Maintenance
cost
(%
of
capital
cost)
1.5
A
US
Department
of
Commerce,
Bureau
of
Economic
Analysis(
10),
price
index
was
used
to
adjust
cost
basis
from
one
year
to
another.
The
levelized
costs
for
various
technology
retrofits
are
presented
in
Table
8.

3.1
Sensitivity
Cases
Two
sensitivity
cases
were
evaluated
to
see
the
effect
of
changes
in
the
study
assumptions
on
the
technology
costs:
1)
increased
cost
of
power
from
25
mills/
kwh
to
50
mills/
kwh
and
2)
an
increase
of
25
percent
in
the
SCR
capital
cost.
Only
a
few
retrofit
options
were
evaluated
to
see
the
impact
of
these
changes
 
the
impact
on
other
options
will
be
similar.
Table
9
presents
the
results.
A
comparison
of
Table
9
and
corresponding
values
in
Table
8
shows
that:

1.
Increase
in
the
cost
of
power
has
virtually
no
impact
on
the
LNB/
OFA
option,
since
the
increase
in
power
consumption
for
this
option
is
quite
small.

2.
Increase
in
the
cost
of
power
has
a
relatively
small
impact
on
the
SCR
option.
This
impact
ranges
from
approximately
0.8
to
6.8
percent
of
the
total
cost
in
$/
ton
of
NOx
removed.

3.
Increase
in
the
capital
cost
of
SCR
results
in
an
increase
of
approximately
13
to
19
percent
in
the
total
cost
in
$/
ton
of
NOx
removed.
It
is
to
be
noted
that,
with
a
25
percent
increase
in
capital
cost,
the
levelized
cost
remains
around
$
2000
per
ton
of
NOx
removed
for
boilers
250
MMBtu/
hr
and
larger,
with
a
capacity
factor
of
50
percent
or
higher.
Preliminary
NOx
Controls
Cost
Estimates
6
5.0
REFERENCES
1.
"
Steam
Its
Generation
and
Use,"
Babcock
and
Wilcox,
40th
Edition
2.
"
Power
Test
Code
 
Steam
Generating
Units,"
ASME
PTC
4.1,
1991
3.
"
Personal
Call
from
S.
Khan
of
EPA
to
B.
Galef
of
ICF,"
9/
29/
03
4.
"
SNCR
Feasibility
and
Economic
Evaluation
Guidelines
for
Fossil­
Fired
Utility
Boilers,"
EPRI
TR­
103885,
May
1994
5.
"
Status
Report
on
NOx
Controls
for
Gas
Turbines/
Cement
Kilns/
Industrial
Boilers/
Internal
Combustion
Engines,
Technologies
&
Cost
Effectiveness,"
NESCAUM,
December
2000
6.
"
Coal
Utility
Environmental
Cost
(
CUECost)
Workbook
User's
Manual,
Version
1.0,"
EPA­
600/
R­
99­
056
(
NTIS
PB99­
151938),
June
1999
7.
"
EPA
Modeling
Application
Using
The
Integrated
Planning
Model,",
http://
www.
epa.
gov/
airmarkets/
epa­
ipm/
index.
html
8.
"
Annual
Energy
Review
2000,"
DOE,
http://
www.
eia.
doe.
gov/
aer/
aerpdf.
html
9.
"
Electric
Power
Monthly
September
2003,"
DOE,
http://
www.
eia.
doe.
gov/
cneaf/
electricity/
epm/
epm.
pdf
10.
"
Implicit
Price
Deflator,"
Table
7.3.
Quantity
and
Price
Indexes,
http://
www.
bea.
doc.
gov/
bea/
dn/
nipaweb/
TableViewFixed.
asp
Preliminary
NOx
Controls
Cost
Estimates
7
TABLE
1
COMBUSTION
CALCULATIONS­
COAL­
FIRED
BOILERS
Bituminous
Coal
Sub­
Bituminous
Coal
Parameter
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Fuel
carbon,
wt.
%
67.94
67.94
67.94
42.22
42.22
42.22
Fuel
ash,
wt.
%
12.71
12.71
12.71
7.41
7.41
7.41
Fuel
sulfur,
wt.
%
3.43
3.43
3.43
0.73
0.73
0.73
Fuel
heating
value,
Btu/
lb
11922
11922
11922
7090
7090
7090
Steam
flow,
lb/
hr
86455
205750
822978
81680
194500
777500
Steam
temp.,
F
460
600
600
460
600
600
Unburned
carbon,
%
0.5
0.5
0.5
0.5
0.5
0.5
Stack
gas
temp.,
F
330
330
330
280
280
280
Boiler
efficiency,
%
87.798
88.028
88.098
82.981
83.211
83.281
Fuel
use,
lb/
hr
8424
21005
83955
14160
35324
141086
Flue
gas
temp.
at
boiler
outlet,
F
685
685
685
650
650
650
Flue
gas
from
combustion,
lb/
hr
99,500
248,130
991,730
104,810
261,200
1.101,660
TABLE
2
COMBUSTION
CALCULATIONS­
GAS­
&
OIL­
RED
BOILERS
Natural
Gas
Oil
Parameter
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Fuel
ash,
wt.
%
NA
NA
NA
0.06
0.06
0.06
Fuel
sulfur,
wt.
%
NA
NA
NA
0.99
0.99
0.99
Fuel
heating
value,
Btu/
lb
22548
22548
22548
18268
18268
18268
Steam
flow,
lb/
hr
79580
189900
797410
81930
196190
824460
Steam
temp.,
F
460
600
600
460
600
600
Stack
gas
temp.,
F
480
480
250
480
480
345
Boiler
efficiency,
%
81.131
81.361
85.439
83.554
84.081
88.338
Fuel
use,
lb/
hr
4437
11091
44349
5475
13685
54740
Flue
gas
temp.
at
boiler
outlet,
F
650
650
650
650
650
650
Flue
gas
from
combustion,
lb/
hr
78,840
197,080
788,060
93,422
233,530
934,100
Preliminary
NOx
Controls
Cost
Estimates
8
TABLE
3
NOx
REDUCITON
CAPABILITIES
OF
VARIOUS
TECHNOLOGIES
NOx
Level
At
Boiler
Outlet,
lb/
MMBtu
Boiler
Fuel
LNB
LNB/
OFA
LNB/
OFA/
GR
Bituminous
coal(
1)
0.45
0.35
NA
Sub­
bituminous
coal
(
1)
0.35
0.25
NA
Natural
gas(
2)
See
note
0.1
0.05
Oil
(
0.36
lb/
MMBtu)(
3)
NA
NA
0.25
Oil
(
0.5
lb/
MMBtu)(
2)
See
note
0.35
0.25
Notes
1.
The
NOx
levels
achievable
for
bituminous
and
sub­
bituminous
coals
are
based
on
information
provided
in
Attachments
3
and
4,
which
takes
into
account
the
limitations
caused
by
the
relatively
smaller
sizes
of
the
industrial
boilers
compared
to
the
utility
boilers.
Also,
gas
recirculation
technology
is
not
considered
applicable
to
coal­
fired
boilers.

2.
It
is
recognized
that
some
of
the
smaller
boilers
(
especially
the
shop­
built
boilers)
may
not
have
space
to
add
OFA.
The
NOx
reduction
capability
is
conservatively
selected
for
the
gas­
and
oil­
fired
boilers,
so
that
the
boilers,
which
cannot
be
retrofitted
with
OFA,
would
still,
on
an
average,
be
able
to
achieve
the
NOx
level
listed
for
the
LNB/
OFA.

3.
For
oil
firing
with
the
baseline
emission
of
0.36
lb/
MMBtu,
the
LNB
and
LNB/
OFA
technologies
may
not
provide
significant
NOx
reduction.
Preliminary
NOx
Controls
Cost
Estimates
9
TABLE
4
BOILER
PERFORMANCE
IMPACTS
OF
LNB,
OFA,
AND
GR
Technology
Boiler
Size
MMBtu/
hr
Reduction
in
Boiler
Efficiency
%
Increased
Auxiliary
Power
kW
Increased
Fuel
Use
lb/
hr
Increased
Ash
Generation
lb/
hr
100
0.23
0.5
19
20
250
0.23
1.0
48
51
LNB/
OFA
on
bituminous
coal
1000
0.23
4.5
193
204
100
0.23
0.5
33
20
250
0.23
1.0
81
51
LNB/
OFA
on
subbituminous
coal
1000
0.23
4.5
325
203
100
NA
18
NA
NA
250
NA
45
NA
NA
LNB/
OFA/
GR
on
gas
1000
NA
159
NA
NA
100
NA
21
NA
NA
250
NA
52
NA
NA
LNB/
OFA/
GR
on
oil
1000
NA
197
NA
NA
Preliminary
NOx
Controls
Cost
Estimates
10
TABLE
5
BOILER
PERFORMANCE
IMPACTS
OF
SCR
Fuel
Boiler
Size
MMBtu/
hr
Anhydrous
Ammonia
Use
lb/
hr
Increased
Auxiliary
Power
kW
Catalyst
Replacement
Ft3/
yr
100
20
72
138
250
49
184
345
Coal
1000
195
691
1380
100
9
65
21
250
21
140
58
Gas
1000
83
425
247
100
15
67
39
250
38
144
97
Oil,
0.5
lb/
MMBtu
Inlet
NOx
1000
150
538
387
100
11
62
42
250
27
131
102
Oil,
0.36
lb/
MMBtu
Inlet
NOx
1000
109
488
406
Preliminary
NOx
Controls
Cost
Estimates
11
TABLE
6
BOILER
PERFORMANCE
IMPACTS
OF
SNCR
Technology
Boiler
Size
MMBtu/
hr
Reduction
in
Boiler
Efficiency
%
Urea
Use
gph
Water
Use
gpm
Increased
Fuel
Use
lb/
hr(
1)
Increased
Auxiliary
Power
kW
Increased
Ash
Generation
lb/
hr
100
0.48
13
3
40
3
5
250
0.48
34
7
100
6
13
Coal
1000
0.48
134
29
399
26
52
100
0.18
5
1
169
0.4
NA
250
0.18
13
3
423
3
NA
Gas
1000
0.18
52
11
1776
10
NA
100
0.37
10
2
19
1
0.14
250
0.35
26
6
48
5
0.34
Oil,
0.5
lb/
MMBtu
Inlet
NOx
1000
0.35
103
22
202
19
1.43
100
0.27
7
2
14
1
0.1
250
0.26
19
4
35
5
0.25
Oil,
0.36
lb/
MMBtu
Inlet
NOx
1000
0.25
74
16
145
14
1.1
Notes
1.
The
fuel
use
is
expressed
in
lb/
hr
for
coal
and
oil
and
scf/
hr
for
gas.
Preliminary
NOx
Controls
Cost
Estimates
12
TABLE
7
CAPITAL
COSTS
FOR
NOx
CONTROL
TECHNOLOGY
APPLICATIONS
Capital
Costs,
NOx
Control
Retrofits
$/
MMBtu/
hr
Technology
Fuel
Boiler
Size
100
MMBtu/
hr
Boiler
Size
250
MMBtu/
hr
Boiler
Size
1000
MMBtu/
hr
LNB
Coal
(
bit.
and
sub­
bit.)
5097
3872
2554
LNB/
OFA
Coal
(
bit.
and
sub­
bit.)
7281
5531
3649
LNB/
OFA
Gas
2554
1940
1280
LNB/
OFA/
GR
Gas
3991
3031
2000
LNB/
OFA
Oil
2554
1940
1280
LNB/
OFA/
GR
Oil
3991
3031
2000
SCR
Coal
14562
11062
7298
SCR
Gas
8009
6084
4014
SCR
Oil
11067
8407
5547
SNCR
Coal
5266
4000
2639
SNCR
Gas
4212
3200
2111
SNCR
Oil
4081
3100
2045
Notes
1.
The
cost
for
each
technology
was
established
based
on
recent
industry
data(
5)
and
Attachment
3.

2.
A
scaling
factor
of
0.3
was
used
to
project
costs
for
different
boiler
sizes.
Preliminary
NOx
Controls
Cost
Estimates
13
TABLE
8
NOx
Technology
Retrofit
Costs
COAL­,
GAS­
&
OIL­
FIRED
INDUSTRIAL
BOILERS
Fuel
Technology
NOx
Reduction
%
Capacity
Factor
%
$/
Ton
of
Pollutant
1000
MMBtu/
hr
250
MMBtu/
hr
100
MMBtu/
hr
Coal
LNB,
sub­
bituminous
51
14
1520
2304
3033
50
426
645
849
83
256
389
512
Coal
LNB/
OFA,
sub­
bituminous
65
14
1727
2608
3428
50
496
743
972
83
306
454
593
Coal
LNB/
OFA,
bituminous
51
14
2197
3317
4358
50
634
947
1239
83
392
581
757
Coal
SCR
80
14
4481
5924
7262
50
1359
1766
2141
83
876
1123
1349
Coal
SNCR
40
14
2962
4015
4970
50
1510
1814
2073
83
1285
1473
1625
Gas
LNB/
OFA
60
5
5260
7973
10521
50
526
797
1052
94
280
424
559
Gas
LNB/
OFA/
GR
80
5
6204
9415
12374
50
656
981
1278
94
368
543
700
Gas
SCR
80
5
14815
21095
26859
50
1670
2330
2933
94
986
1354
1689
Gas
SNCR
40
5
14,165
20,870
27,105
50
2,452
3,116
3,735
94
1,842
2,193
2,521
Oil
LNB/
OFA
(
0.5
lb/
MMBtu
30
10
2630
3986
5260
inlet
NOx)
50
526
797
1052
86
306
464
612
Oil
LNB/
OFA/
GR
(
0.5
lb/
MMBtu
50
10
2505
3790
4973
inlet
NOx)
50
533
791
1028
86
326
477
615
Oil
LNB/
OFA/
GR
(
0.36
lb/
MMBtu
30
10
5694
8613
11303
inlet
NOx)
50
1210
1798
2337
86
741
1085
1399
Oil
SCR
(
0.36
lb/
MMBtu
inlet
NOx)
80
5
14,601
20,113
25,838
50
1,622
2,178
2,767
86
1,017
1,343
1,694
Oil
SCR
(
0.5
lb/
MMBtu
inlet
NOx)
80
5
10,458
14,443
18,544
50
1,191
1,595
2,014
86
760
997
1,245
Oil
SNCR
(
0.5
lb/
MMBtu
inlet
40
10
4271
5892
7399
NOx)
50
1749
2070
2367
86
1485
1670
1840
Oil
SNCR
(
0.36
lb/
MMBtu
inlet
40
10
5497
7753
9842
NOx)
50
1995
2444
2853
86
1628
1889
2123
Preliminary
NOx
Controls
Cost
Estimates
14
TABLE
9
COST
SENSITIVIY
EVALUATIONS
 
NOx
TECHNOLOGIES
$/
ton
of
NOx
Fuel
Technology
Sensitivity
Parameter(
1)
NOx
Reduction
%
Capacity
Factor
%
1000
MMBtu/
hr
250
MMBtu/
hr
100
MMBtu/
hr
Coal
LNB/
OFA,
bituminous
Increased
power
cost
51
14
50
83
2198
635
393
3318
948
582
4359
1240
758
Coal
SCR
Increased
power
cost
80
14
50
83
4541
1418
936
5988
1830
1187
7325
2203
1412
Coal
SCR
Increased
capital
cost
80
14
50
83
5179
1554
994
6981
2062
1301
8653
2531
1584
NOTES
1.
Two
sensitivity
parameters
were
evaluation:
1)
increased
power
cost
from
25
mills/
kwh
to
50
mills/
kwh
and
2)
an
increase
of
25
percent
in
the
SCR
capital
cost.
