Document ID: EPA-HQ-OAR-2003-0053-1890
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-10-05T04:00Z

METHODOLOGY,
ASSUMPTIONS,
AND
REFERENCES
PRELIMINARY
SO2
CONTROLS
COST
ESTIMATES
FOR
INDUSTRIAL
BOILERS
By
Sikander
Khan
Environmental
Engineer,
U.
S.
EPA
OCTOBER­
NOVEMBER
2003
Preliminary
SO2
Controls
Cost
Estimates
2
COST
ESTIMATES
FOR
SO2
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
SO2
control
technologies
were
included
in
these
estimates
for
coal­
and
oil­
fired
boilers,
as
indicated
below:

In­
duct
dry
sorbent
injection
(
coal
only)
Spray
Dryer
Absorber
(
coal
only)
Wet
Flue
Gas
Desulfurization
(
coal
and
oil)

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
SO2
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
SO2
control
system
and
determining
its
operating
impacts
on
the
boiler
performance
and
2)
determining
capital
and
operating
costs
associated
with
retrofitting
the
SO2
control
system.
These
two
activities,
along
with
the
associated
assumptions
and
references,
are
described
below.

2.0
DESIGN
BASIS
AND
PERFORMANCE
IMPACTS
Boiler
combustion
calculations
were
performed
using
standard
procedures(
1,2),
for
the
three
boiler
sizes
of
100,
250,
and
1,000
MMBtu/
hr.
These
calculations
were
performed
for
boilers
firing
coal
and
oil
with
various
sulfur
contents,
which
were
selected
based
on
coal
sulfur
data
available
from
the
EPA
databases
(
see
Attachment
1).
Tables
included
in
this
report
list
key
data
determined
from
these
calculations
for
the
three
boilers
firing
coal
and
oil.
These
data
were
used
to
develop
the
design
parameters
and
plant
performance
impacts
for
each
SO2
control
technology,
as
discussed
below:

2.1
In­
duct
Dry
Sorbent
Injection
(
IDIS)

The
design
parameters
and
plant
performance
impacts
for
the
IDIS
system
were
established
based
on
the
criteria
provided
in
a
US
Department
of
Energy
(
DOE)
design
handbook(
3),
which
lists
detailed
process
design
and
engineering
guidelines
for
this
technology.
These
estimates
were
developed
for
coal­
fired
boilers
only.
The
following
key
factors
and
assumptions
were
used:
Preliminary
SO2
Controls
Cost
Estimates
3
1.
A
SO2
reduction
efficiency
of
40
percent
was
used
for
each
boiler
application
(
higher
reduction
rates
are
possible,
as
per
the
above
handbook).

2.
No
waste
recycling
was
used.

3.
The
reagent
used
was
lime,
which
required
provision
of
a
hydrator
for
each
boiler
application.

4.
It
was
assumed
that
the
solid
waste
generated
would
be
disposed
off
in
a
landfill.

5.
It
was
assumed
that
the
existing
ash
handling
system
could
not
handle
the
increased
solid
ash
generated
with
the
IDIS
system,
requiring
an
extension
of
this
system
.

6.
The
existing
particulate
control
technology
was
assumed
to
be
a
precipitator.

The
design
parameters
and
plant
performance
impacts
associated
with
the
use
of
IDIS
system
are
presented
in
Table
1.
These
impacts
were
used
for
the
estimation
of
operating
costs
resulting
from
the
use
of
this
technology.

2.2
Spray
Dryer
Absorber
(
SDA)

The
design
parameters
and
plant
performance
impacts
for
the
SDA
system
were
established
based
on
the
criteria
taken
from
various
sources(
4­
7),
which
list
detailed
process
design
and
engineering
guidelines
for
this
technology.
These
estimates
were
developed
for
coal­
fired
boilers
only.
The
following
key
factors
and
assumptions
were
used:

1.
A
SO2
reduction
efficiency
of
90%
was
used,
based
on
industry
data
supporting
this
level
of
reduction(
5,6)
(
see
Attachment
2).

2.
No
waste
recycle
is
used.

3.
The
existing
particulate
control
technology
was
assumed
to
be
a
precipitator.

4.
It
was
assumed
that
the
solid
waste
generated
would
be
disposed
off
in
a
landfill.

5.
Auxiliary
power
was
assumed
to
be
0.7
percent
of
the
boiler's
equivalent
power
generation
capability.

The
design
parameters
and
plant
performance
impacts
associated
with
the
use
of
SDA
system
are
presented
in
Table
2.
These
impacts
were
used
for
the
estimation
of
operating
costs
resulting
from
the
use
of
this
technology.

2.3
Wet
Flue
Gas
Desulfurization
(
WFGD)

The
design
parameters
and
plant
performance
impacts
for
the
WFGD
system
were
established
based
on
the
criteria
taken
from
various
sources(
5­
9),
which
list
detailed
process
design
and
engineering
guidelines
for
this
technology.
These
estimates
were
Preliminary
SO2
Controls
Cost
Estimates
4
developed
for
coal­
fired
boilers
only.
The
following
key
factors
and
assumptions
were
used:

1.
A
SO2
reduction
efficiency
of
90%
was
used,
based
on
industry
data
supporting
this
level
of
reduction(
5,6)
(
see
Attachment
2).

2.
The
reagent
was
assumed
to
be
limestone.

3.
It
was
assumed
that
the
solid
waste
generated
would
be
disposed
off
in
a
landfill.

4.
Auxiliary
power
was
assumed
to
be
2.0
percent
of
the
boiler's
equivalent
power
generation
capability.

The
design
parameters
and
plant
performance
impacts
associated
with
the
use
of
WFGD
system
are
presented
in
Tables
3
and
4
for
coal
and
oil
fuels,
respectively.
These
impacts
were
used
for
the
estimation
of
operating
costs
resulting
from
the
use
of
this
technology.

3.0
CAPITAL
AND
LEVELIZED
COSTS
The
capital
costs
($/
MMBtu/
hr)
for
the
IDIS
system
were
developed
using
information
from
the
aforementioned
DOE
design
handbook(
3).
For
the
SDA
and
WFGD
systems
budgetary
cost
estimates
were
obtained
from
vendors
(
see
Attachments
3
and
4).
The
balance­
of­
plant
costs
were
developed
using
information
from
the
EPA
`
s
CueCost
Program(
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
costs
are
based
on
1999
dollars.

In
general,
an
EPRI
methodology(
11)
was
used
for
the
above
cost
estimates,
with
the
following
cost
factors
used
for
the
non­
process
costs:

General
Facilities:
5.0
%
of
total
direct
process
cost
Engineering
and
home
office
fees:
10%
of
total
direct
process
cost
Process
contingency:
5.0%
of
total
direct
process
cost
Project
contingency:
15%
of
total
direct
process
and
the
above
three
non­
process
costs
Retrofit
factor:
30%
Preproduction
cost:
2.0%
of
total
plant
investment
with
retrofit
costs
Inventory
capital:
cost
for
a
30­
day
reagent
storage
The
capital
costs
for
various
SO2
technology
applications
are
provided
in
Tables
5
through
8.
It
is
to
be
noted
that
the
budgetary
costs
obtained
from
the
vendors
were
adjusted
for
the
gas
flow
for
the
SDA
system
and
for
the
items
described
in
Attachment
4
for
the
WFGD
system.
A
conservative
retrofit
factor
of
30
percent
was
used
to
account
for
the
expected
difficulty
of
retrofitting
the
FGD
equipment
in
an
existing
plant
setting
Preliminary
SO2
Controls
Cost
Estimates
5
and
certain
modifications
required
to
the
existing
plant
equipment
and
structures
that
are
not
included
in
the
estimates.

The
levelized
costs
($/
ton
of
SO2
removed)
were
calculated
using
the
estimates
of
the
capital
costs
and
increased
consumable
rates
associated
with
each
technology,
as
shown
in
Tables
1
through
4.
The
economic
factors
used
in
these
calculations(
1­
4)
were
as
follows:

Lime,
$/
ton
50
Limestone,
$/
ton
15
Water,
$/
gal
0.0006
Solid
waste
disposal,
$/
ton
12
Operator
cost,
$/
hr
30
Useful
life,
years
30
Carrying
charges,
%
12.00
Levelization
factor
1.0
Maintenance
cost
(%
of
capital
cost)
3.0
(
for
WFGD)
2.0
(
for
SDA
and
IDIS)

The
levelized
costs
for
various
technology
retrofits
are
presented
in
Table
9.

3.1
Sensitivity
Cases
Two
sensitivity
cases
were
evaluated
to
see
the
effect
of
changes
in
the
study
data
and
assumptions
on
the
technology
costs:
1)
increased
cost
of
power
from
25
mills/
kwh
to
50
mills/
kwh
and
2)
an
increase
of
20
percent
in
the
technology
capital
cost.
Only
a
few
retrofit
options
(
IDSI
on
high
sulfur
coal,
SDA,
and
WFGD
on
high
sulfur
coal)
were
evaluated
to
see
the
impact
of
these
changes
 
the
impact
on
other
options
should
be
similar.
Table
10
presents
the
results.
A
comparison
of
Table10
and
the
corresponding
values
in
Table
9
shows
that:

1.
Increase
in
the
cost
of
power
has
a
relatively
small
impact
that
includes:

 
an
increase
of
0.8
to
4.5
percent
of
the
levelized
cost
for
the
IDSI
technology
 
an
increase
of
0.2
to
2.6
percent
of
the
levelized
cost
for
the
SDA
technology
 
an
increase
of
0.57
to
5.1
percent
of
the
levelized
cost
for
the
WFGD
technology
2.
Increase
in
the
capital
cost
has
the
following
impacts:

 
an
increase
of
11.5
to
17.7
percent
of
the
levelized
cost
for
the
SDA
technology
 
an
increase
of
13.9
to
17.3
percent
of
the
levelized
cost
for
the
WFGD
technology
It
is
to
be
noted
that,
even
with
an
increase
of
20
percent
in
the
capital
cost,
the
levelized
costs
($/
ton
of
SO2)
remain
below
$
1,500
for
plant
capacity
factors
of
50
percent
and
higher.
Preliminary
SO2
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.
"
Duct
Injection
for
SO2
Control
Design
Handbook,"
By
Raytheon
Engineers
and
Constructors,
B&
W,
Energy
and
Environmental
Research
Center
for
U.
S.
DOE,
Agreement
DE­
AC22­
88PC88852
4.
"
Spray­
Dryer
Flue
Gas­
Cleaning
System
Handbook,"
By
Argonne
National
Laboratory
for
U.
S.
DOE,
ANL/
ESD­
7,
April
1988
5.
"
Coal
Utility
Environmental
Cost
(
CUECost)
Workbook
User's
Manual,
Version
1.0,"
EPA­
600/
R­
99­
056
(
NTIS
PB99­
151938),
June
1999
6.
"
EPA
Modeling
Application
Using
The
Integrated
Planning
Model,",
http://
www.
epa.
gov/
airmarkets/
epa­
ipm/
index.
html
7.
R.
Srivastava,
et.
al.,
"
Flue
Gas
Desulfurization:
The
State
of
the
Art,"
Journal
of
the
Air
&
Waste
Management
Association,
Volume
51,
December
2001
8.
"
Limestone
FGD
Scrubbers:
Users
Handbook,"
By
PEDCO
Environmental,
Inc.
for
U.
S.
EPA,
EPA­
600/
8­
81­
017
9.
E.
Rubin,
et.
al.,
"
New
Models
For
FGD
Performance,
Cost
And
Hazardous
Air
Pollutant
Removal,"
1995
SO2
Control
Symposium,
Miami,
Florida,
March
28­
31,
1995
10.
"
Implicit
Price
Deflator,"
Table
7.3.
Quantity
and
Price
Indexes,
http://
www.
bea.
doc.
gov/
bea/
dn/
nipaweb/
TableViewFixed.
asp
11.
"
Technical
Assessment
Guide,
Vol.
I:
Electricity
Suppl­
1993
(
Revision
7);
EPRI
TR­
102276s;
Electric
Power
Research
Institute
Preliminary
SO2
Controls
Cost
Estimates
7
TABLE
1
DESIGN
PARAMETERS
AND
PERFORMANCE
IMPACTS
FOR
IN­
DUCT
DRY
SORBENT
INJECTION
High­
Sulfur
Coal
Lower­
Sulfur
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
sulfur,
wt.
%
3.43
3.43
3.43
2.0
2.0
2.0
Fuel
ash,
wt.
%
12.71
12.71
12.71
13.2
13.2
13.2
Fuel
heating
value,
Btu/
lb
11,922
11,922
11,922
11,922
11,922
11,922
Fly
ash
as
%
of
total
ash
90
90
90
90
90
90
CaO
in
lime,
%
90
90
90
90
90
90
Flue
gas
flow,
acfm
38,230
95,400
381,000
35,800
89,300
356,700
Flue
gas
temperature,
oF
330
330
330
285
285
285
Approach
to
saturation,
oF
40
40
40
40
40
40
Reagent
recycle
(
yes
or
no)
No
No
No
No
No
No
Ca/
S
ratio
2.4
2.4
2.4
2.4
2.4
2.4
Lime
required,
lb/
hr
1,301
3,253
13,010
759
1,897
7,586
Water
required,
gpm
10
25
98
7
17
70
Waste
produced,
ton/
hr
0.97
2.43
9.71
0.57
1.42
5.66
Auxiliary
power
required,
kW
133
333
1,333
94
234
1,011
Additional
operating
labor,
hr/
yr
2190
2190
2190
2190
2190
2190
Preliminary
SO2
Controls
Cost
Estimates
8
TABLE
2
DESIGN
PARAMETERS
AND
PERFORMANCE
IMPACTS
FOR
SPRAY
DRYER
ABSORBER
Coal
Parameter
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Fuel
sulfur,
wt.
%
1.8
1.8
1.8
Fuel
ash,
wt.
%
13.2
13.2
13.2
Fuel
heating
value,
Btu/
lb
9000
9000
9000
Fly
ash
as
%
of
total
ash
90
90
90
CaO
in
lime,
%
90
90
90
Flue
gas
flow,
acfm
36,516
91,086
363,834
Flue
gas
temperature,
oF
285
285
285
Existing
particulate
control
type
ESP
ESP
ESP
Approach
to
saturation,
oF
40
40
40
Reagent
recycle
(
yes
or
no)
No
No
No
Lime
required,
lb/
hr
710
1,776
7,103
Water
required,
gpm
6
14
56
Waste
produced,
ton/
hr
0.67
1.68
6.72
Auxiliary
power
required,
kW
70
175
700
Additional
operating
labor,
hr/
yr
2190
2920
4380
Preliminary
SO2
Controls
Cost
Estimates
9
TABLE
3
DESIGN
PARAMETERS
AND
PERFORMANCE
IMPACTS
FOR
WET
FLUE
GAS
DESULFURIZATION
 
FOR
COAL
High­
Sulfur
Coal
Lower­
Sulfur
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
sulfur,
wt.
%
3.43
3.43
3.43
2.5
2.5
2.5
Fuel
ash,
wt.
%
12.71
12.71
12.71
12.71
12.71
12.71
Fuel
heating
value,
Btu/
lb
11,922
11,922
11,922
11,922
11,922
11,922
Flue
gas
flow,
acfm
38,230
95,400
381,000
38,230
95,400
381,000
Flue
gas
temperature,
oF
330
330
330
330
330
330
Limestone
required,
lb/
hr
947
2,367
9,464
689
1,723
6,898
Water
required,
gpm
13
32
127
12
31
124
Waste
produced,
ton/
hr
0.81
2.0
8.1
0.59
1.5
5.9
Auxiliary
power
required,
kW
200
500
2,000
200
500
2,000
Additional
operating
labor,
hr/
yr
4,160
8,320
18,720
4,160
8,320
18,720
Preliminary
SO2
Controls
Cost
Estimates
10
TABLE
4
DESIGN
PARAMETERS
AND
PERFORMANCE
IMPACTS
FOR
WET
FLUE
GAS
DESULFURIZATION
 
FOR
OIL
Oil
Parameter
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Fuel
sulfur,
wt.
%
2.18
2.18
2.18
Fuel
ash,
wt.
%
0.06
0.06
0.06
Fuel
heating
value,
Btu/
lb
18,268
18,268
18,268
Flue
gas
flow,
acfm
41,100
102,600
371,100
Flue
gas
temperature,
oF
480
480
344
Limestone
required,
lb/
hr
393
983
3,931
Water
required,
gpm
18
46
120
Waste
produced,
ton/
hr
0.34
0.84
3.4
Auxiliary
power
required,
kW
200
500
2,000
Additional
operating
labor,
hr/
yr
4,160
8,320
18,720
Preliminary
SO2
Controls
Cost
Estimates
11
TABLE
5
CAPITAL
COSTS
­
IN­
DUCT
DRY
SORBENT
INJECTION
Cost
Item
High­
Sulfur
Coal
Lower
Sulfur
Coal
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
DIRECT
COSTS
($):
Pebble
lime
system
468,787
839,447
2,215,315
324,845
575,451
1,518,624
Hydrate
lime
handling
system
54,480
97,545
257,422
37,751
66,868
176,466
Ash
system
modifictions
187,608
356,296
940,270
128,607
244,245
644,566
Miscellaneous
equipment
291,655
522,209
1,378,118
202,102
357,981
944,717
Civil,
electrical,
and
other
miscellaneous
equipment
(
40%)
451,138
726,199
1,916,450
277,322
497,818
1,313,749
TOTAL
DIRECT
PROCESS
CAPITAL
($)
1,453,668
2,541,696
6,707,575
970,626
1,742,363
4,598,122
INDIRECT
COSTS:
GENERAL
FACILITIES
72,683
127,085
335,379
48,531
87,118
229,906
ENGINEERING
AND
HOME
OFFICE
FEES
145,367
254,170
670,758
97,063
174,236
459,812
PROCESS
CONTINGENCY
72,683
127,085
335,379
48,531
87,118
229,906
PROJECT
CONTINGENCY
261,660
457,505
1,207,364
174,713
313,625
827,662
TOTAL
PLANT
COST
(
TPC)
($):
2,006,062
3,507,541
9,256,454
1,339,465
2,404,461
6,345,409
CONSTRUCTION
YEARS
<
1
<
1
<
1
<
1
<
1
<
1
ALLOAWANCE
FOR
FUNDS
DURING
CONSTRUCTION
0
0
0
0
0
0
TOTAL
PLANT
INVESTMENT
(
TPI)
($)
2,006,062
3,507,541
9,256,454
1,339,465
2,404,461
6,345,409
TOTAL
PLANT
INVESTMENT
WITH
RETROFIT
FACTOR,
$
2,607,881
4,559,803
12,033,390
1,741,304
3,125,799
8,249,031
ROYALTY
ALLOWANCE
0
0
0
0
0
0
PREPRODUCTION
COST
52,158
91,196
240,668
34,826
62,516
164,981
INVENTORY
CAPITAL
23,418
58,554
234,180
23,418
58,554
234,180
INITIAL
CATALYST
AND
CHEMICALS
0
0
0
0
0
0
TOTAL
PLANT
REQUIREMENTS
($)
2,683,457
4,709,553
12,508,238
1,799,548
3,246,869
8,648,192
TOTAL
PLANT
REQUIREMENTS
($/
MMBtu):
26,835
18,838
12,508
17,995
12,987
8,648
Preliminary
SO2
Controls
Cost
Estimates
12
TABLE
6
CAPITAL
COSTS
­
SPRAY
DRYER
ABSORBER
Cost
Item
Coal
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
DIRECT
COSTS
($):
SDA
Vessels/
Reagent/
Accessories
1,145,452
1,666,112
2,603,300
Flue
gas
handling
(
including
ID
fans)
647,356
1,010,172
2,312,618
Chimney
515,451
978,916
2,633,019
Waste
handling
358,320
680,501
1,845,819
Miscellaneous
support
equipmentm,
$
316,733
601,522
1,637,391
TOTAL
DIRECT
PROCESS
CAPITAL
($)
2,983,312
4,937,223
11,032,147
INDIRECT
COSTS:
GENERAL
FACILITIES
149,166
246,861
551,607
ENGINEERING
AND
HOME
OFFICE
FEES
298,331
493,722
1,103,215
PROCESS
CONTINGENCY
149,166
246,861
551,607
PROJECT
CONTINGENCY
536,996
888,700
1,985,786
TOTAL
PLANT
COST
(
TPC)
($):
4,116,971
6,813,368
15,224,363
CONSTRUCTION
YEARS
<
1
<
1
<
1
ALLOAWANCE
FOR
FUNDS
DURING
CONSTRUCTION
0
0
0
TOTAL
PLANT
INVESTMENT
(
TPI)
($)
4,116,971
6,813,368
15,224,363
TOTAL
PLANT
INVESTMENT
WITH
RETROFIT
FACTOR,
$
5,352,062
8,857,378
19,791,671
ROYALTY
ALLOWANCE
0
0
0
PREPRODUCTION
COST
107,041
177,148
395,833
INVENTORY
CAPITAL
8,748
21,870
87,480
INITIAL
CATALYST
AND
CHEMICALS
0
0
0
TOTAL
PLANT
REQUIREMENTS
($)
5,467,851
9,056,396
20,274,985
TOTAL
PLANT
REQUIREMENTS
($/
MMBtu)
54,679
36,226
20,275
Preliminary
SO2
Controls
Cost
Estimates
13
TABLE
7
CAPITAL
COSTS
­
WET
FLUE
GAS
DESULFURIZATION
Cost
Item
High­
Sulfur
Coal
Lower
Sulfur
Coal
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
DIRECT
COSTS
($):
Scrubber
and
miscellaneous
equipment
1,350,509
2,564,812
6,768,580
1,350,510
2,564,812
6,768,580
Reagent
feed
and
prep
system
943,100
1,791,082
4,677,047
728,540
1,383,601
3,601,701
Flue
gas
handling
(
including
ID
fans)
405,153
769,444
2,030,574
405,153
769,444
2,030,574
Waste
handling
148,556
282,129
744,544
120,189
228,256
602,372
Chimney
515,451
978,916
2,633,019
515,451
978,916
2,633,019
Electrical,
piping,
valves,
and
other
accessories
135,051
256,481
676,858
135,051
256,481
676,858
TOTAL
DIRECT
PROCESS
CAPITAL
($)
3,497,819
6,642,864
17,530,623
3,254,893
6,181,510
16,313,105
INDIRECT
COSTS:
GENERAL
FACILITIES
174,891
332,143
876,531
162,745
309,076
815,655
ENGINEERING
AND
HOME
OFFICE
FEES
349,782
664,286
1,753,062
325,489
618,151
1,631,311
PROCESS
CONTINGENCY
174,891
332,143
876,531
162,745
309,076
815,655
PROJECT
CONTINGENCY
629,607
1,195,716
3,155,512
585,881
1,112,672
2,936,359
TOTAL
PLANT
COST
(
TPC)
($):
4,826,991
9,167,152
24,192,260
4,491,753
8,530,484
22,512,085
CONSTRUCTION
YEARS
<
1
<
1
<
1
<
1
<
1
<
1
ALLOAWANCE
FOR
FUNDS
DURING
CONSTRUCTION
0
0
0
0
0
0
TOTAL
PLANT
INVESTMENT
(
TPI)
($)
4,826,991
9,167,152
24,192,260
4,491,753
8,530,484
22,512,085
TOTAL
PLANT
INVESTMENT
WITH
RETROFIT
FACTOR,
$
6,275,088
11,917,298
31,449,938
5,839,279
11,089,629
29,265,711
ROYALTY
ALLOWANCE
0
0
0
0
0
0
PREPRODUCTION
COST
125,502
238,346
628,999
116,786
221,793
585,314
INVENTORY
CAPITAL
23,418
58,554
234,180
3,720
9,310
37,250
INITIAL
CATALYST
AND
CHEMICALS
0
0
0
0
0
0
TOTAL
PLANT
REQUIREMENTS
($)
6,424,007
12,214,198
32,313,117
5,959,784
11,320,732
29,888,275
TOTAL
PLANT
REQUIREMENTS
($/
MMBtu):
64,240
48,857
32,313
59,598
45,283
29,888
Preliminary
SO2
Controls
Cost
Estimates
14
TABLE
8
CAPITAL
COSTS
­
WET
FLUE
GAS
DESULFURIZATION
Cost
Item
Oil
Boiler
 
100
MMBtu/
hr
Boiler
 
250
MMBtu/
hr
Boiler
 
1000
MMBtu/
hr
DIRECT
COSTS
($):
Scrubber
and
miscellaneous
equipment
1,329,344
2,524,615
6,662,499
Reagent
feed
and
prep
system
666,534
1,265,844
3,340,582
Flue
gas
handling
(
including
ID
fans)
398,803
757,384
1,998,750
Waste
handling
91,651
174,059
459,344
Chimney
372,216
706,892
1,865,500
Electrical,
piping,
valves,
and
other
accessories
132,934
252,462
666,250
TOTAL
DIRECT
PROCESS
CAPITAL
($)
2,991,483
5,681,255
14,992,925
INDIRECT
COSTS:
GENERAL
FACILITIES
149,574
284,063
749,646
ENGINEERING
AND
HOME
OFFICE
FEES
299,148
568,126
1,499,292
PROCESS
CONTINGENCY
149,574
284,063
749,646
PROJECT
CONTINGENCY
538,467
1,022,626
2,698,726
TOTAL
PLANT
COST
(
TPC)
($):
4,128,246
7,840,132
20,690,236
CONSTRUCTION
YEARS
<
1
<
1
<
1
ALLOAWANCE
FOR
FUNDS
DURING
CONSTRUCTION
0
0
0
TOTAL
PLANT
INVESTMENT
(
TPI)
($)
4,128,246
7,840,132
20,690,236
TOTAL
PLANT
INVESTMENT
WITH
RETROFIT
FACTOR,
$
5,366,720
10,192,172
26,897,307
ROYALTY
ALLOWANCE
0
0
0
PREPRODUCTION
COST
107,334
203,843
537,946
INVENTORY
CAPITAL
2,000
5,000
19,500
INITIAL
CATALYST
AND
CHEMICALS
0
0
0
TOTAL
PLANT
REQUIREMENTS
($)
5,476,054
10,401,016
27,454,753
TOTAL
PLANT
REQUIREMENTS
($/
MMBtu)
54,761
41,604
27,455
Preliminary
SO2
Controls
Cost
Estimates
15
TABLE
9
SO2
Technologies
Levelized
Costs
Fuel
Technology
SO2
Reduction
Capacity
Factor
$/
Ton
of
SO2
%
%
Boiler­
100
MMBtu/
hr
Boiler­
250
MMBtu/
hr
Boiler­
1000
MMBtu/
hr
Coal
IDSI
high
sulfur
coal
40
14
3543
2471
1703
50
1292
992
776
83
943
763
633
Coal
IDSI
lower
sulfur
coal
40
14
4283
2952
1986
50
1504
1131
870
83
1075
849
697
Coal
SDA
90
14
3,920
2,611
1,500
50
1,209
842
531
83
790
569
381
Coal
Wet
FGD
high
sulfur
coal
90
14
3,513
2,708
1,789
50
1,046
820
563
83
664
528
373
Coal
Wet
FGD
lower
sulfur
coal
90
14
4,495
3,460
2,273
50
1,326
1,036
704
83
836
661
461
Oil
Wet
FGD
90
10
10,160
7,801
5,082
50
2,126
1,654
1,109
86
1,285
1,011
693
Preliminary
SO2
Controls
Cost
Estimates
16
TABLE
10
COST
SENSITIVIY
EVALUATIONS
 
SO2
TECHNOLOGIES
$/
ton
of
SO2
Fuel
Technology
Sensitivity
Parameter(
1)
SO2
Reduction
%
Capacity
Factor
%
100
MMBtu/
hr
250
MMBtu/
hr
1000
MMBtu/
hr
Coal
IDSI
high
sulfur
coal
Increased
power
cost
40
14
50
83
3572
1320
972
2500
1020
792
1732
805
662
Coal
SDA
Increased
power
cost
90
14
50
83
3929
1218
799
2620
852
578
1509
541
391
Coal
WFGD
high
sulfur
coal
Increased
power
cost
90
14
50
83
3533
1065
683
2727
839
547
1808
582
392
Coal
SDA
Increased
capital
cost
90
14
50
83
4613
1403
906
3070
971
646
1757
603
425
Coal
WFGD
high
sulfur
coal
Increased
capital
cost
90
14
50
83
4120
1216
766
3170
949
606
2094
648
425
NOTES
1.
Two
sensitivity
parameters
were
evaluation:
1)
increased
power
cost
from
25
mills/
kwh
to
50
mills/
kwh
and
2)
an
increase
of
20
percent
in
the
technology
capital
cost.