Document ID: EPA-HQ-OAR-2003-0053-2077
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-03-10T05:00Z

C­
1
APPENDIX
C
PRELIMINARY
ESTIMATES
OF
COSTS
OF
MERCURY
EMISSION
CONTROL
TECHNOLOGIES
FOR
ELECTRIC
UTILITY
BOILERS
Ravi
K.
Srivastava,
Charles
B.
Sedman,
and
James
D.
Kilgroe
U.
S.
Environmental
Protection
Agency
National
Risk
Management
Research
Laboratory
Research
Triangle
Park,
NC
27711
As
noted
in
Chapter
1
of
this
report,
the
U.
S.
Environmental
Protection
Agency
(
EPA)
has
conducted
an
examination
of
the
"
co­
benefits"
of
potential
pollution
control
options
for
the
electric
power
industry
to
lower
the
emissions
of
its
most
significant
air
pollutants.
One
of
these
pollutants
is
mercury.
The
examination
of
the
co­
benefits
was
conducted
using
the
Integrated
Planning
Model
(
IPM)
[
1].
For
the
co­
benefits
study,
this
model
had
to
be
supplemented
with
information
on
performance
and
cost
of
mercury
emission
control
technologies.
Described
in
this
appendix
is
the
development
of
a
preliminary
assessment
of
performance
and
cost
of
mercury
emission
control
technologies
for
utility
boilers.

Behavior
of
Mercury
in
Combustion
Systems
In
combustion
systems,
mercury
is
volatilized
and
converted
to
elemental
mercury
(
Hgo)
in
the
high
temperature
regions
of
furnaces.
As
the
flue
gas
is
cooled,
Hgo
is
oxidized
to
ionic
forms
of
mercury
(
Hg++).
The
rate
of
oxidization
is
dependent
on
the
temperature,
flue
gas
composition,
and
the
properties
and
amount
of
fly
ash
and
any
entrained
sorbents.

The
time/
temperature
profile
within
a
combustion
system
determines
the
instantaneous
equilibrium
conditions,
the
kinetics
of
chemical
reactions,
and
the
time
available
for
reactions.
In
incinerators
the
flue
gas
concentration
of
chlorine,
in
the
form
of
hydrogen
chloride
(
HCl),
is
substantially
higher
than
the
concentration
of
Hgo.
When
the
concentration
of
HCl
is
greater
than
the
concentration
of
Hg,
thermochemical
calculations
indicate
that
Hgo
is
preferentially
converted
to
mercuric
chloride
(
HgCl2).
In
coal­
fired
combustors,
where
the
concentrations
of
HCl
are
much
lower
and
where
equilibrium
conditions
are
not
achieved,
Hgo
may
be
oxidized
to
mercury
oxide
(
HgO),
mercury
sulfate
(
HgSO4),
HgCl2,
or
some
other
form
of
mercury.
The
oxidization
of
Hgo
to
HgCl2
and
other
ionic
forms
of
mercury
is
abetted
by
catalytic
reactions
on
the
surface
of
fly
ash
or
sorbents
that
may
be
present
in
the
flue
gas.

Hg
°
,
HgCl2,
and
HgO
are
primarily
in
a
vapor
phase
at
flue
gas
cleaning
temperatures,
and
special
methods
must
be
used
for
their
capture.
Each
of
these
forms
of
mercury
can
be
adsorbed
onto
porous
solids
such
as
fly
ash,
powdered
activated
carbon
(
AC),
and
calcium­
based
acid
gas
C­
2
sorbents
for
subsequent
collection
in
a
particulate
matter
(
PM)
control
device.
These
mercury
compounds
can
also
be
captured
in
carbon
bed
filters
or
other
reactors
containing
appropriate
sorbents.
In
the
U.
S.,
the
control
of
mercury
in
municipal
waste
combustors
(
MWCs)
is
based
on
the
injection
of
powdered
AC
upstream
of
an
electrostatic
precipitator
(
ESP)
or
a
fabric
filter
(
FF).

HgCl2
is
water
soluble
and
readily
reacts
with
alkali
metal
oxides
in
an
acid­
base
reaction;
therefore,
conventional
acid
gas
scrubbers
used
for
sulfur
dioxide
(
SO2)
control
can
effectively
capture
HgCl2.
Hgo
is
insoluble
in
water
and
must
be
adsorbed
onto
a
sorbent
or
converted
to
a
soluble
form
of
mercury
that
can
be
collected
by
wet
scrubbing.
HgO
has
low
solubility
and
probably
has
to
be
collected
by
methods
similar
to
those
used
for
Hgo.

Where
scrubbers
are
already
employed,
mercury
control
is
a
function
of
the
ratio
of
HgCl2
to
total
mercury
concentrations
in
the
flue
gas
­­
a
ratio
that
is
inherent
to
the
properties
of
coal
or
other
material
being
burned.
The
total
mercury
removal
efficiency
of
scrubbers
has
been
reported
by
the
Electric
Power
Research
Institute
(
EPRI)
and
the
Department
of
Energy
(
DOE),
to
range
from
30
to
90%
[
2].
Where
scrubbers
are
not
employed,
activated
carbon
can
be
added
upstream
of
the
PM
control
device
(
ESP
or
FF).
While
full­
scale
tests
have
not
yet
been
attempted,
EPRI
reports
poor
carbon
utilization
in
tests
with
a
pilot­
scale
ESP
installed
on
a
flue
gas
slip
stream
from
a
coal­
fired
utility
boiler.

Status
of
Technologies
for
Control
of
Mercury
Emissions
A
variety
of
air
pollution
control
technologies
are
now
commercially
used
to
control
mercury
emissions
from
MWCs.
In
Europe
these
technologies
include
activated
carbon
injection
(
ACI)
followed
by
collection
in
a
PM
control
device,
the
use
of
wet
scrubbers,
the
use
of
carbon
bed
filters,
and
the
use
of
reagents
(
sodium
sulfide
or
sodium
tetrasulfide)
to
convert
mercury
into
more
easily
captured
forms.
In
the
U.
S.,
mercury
emissions
from
MWCs
are
typically
controlled
by
the
use
of
ACI
in
conjunction
with
dry
scrubbing
systems.
Few,
if
any,
MWCs
use
wet
scrubbers.

The
control
of
mercury
emissions
from
coal­
fired
boilers
is
not
commercially
practiced
in
the
U.
S.
The
direct
application
of
MWC
mercury
control
technologies
to
coal­
fired
boilers
is
difficult
because
of
factors
that
make
mercury
more
difficult
and
costly
to
capture:

 
There
is
typically
a
higher
fraction
of
Hg
°
in
the
flue
gas
from
coal­
fired
boilers
than
in
MWCs.
This
means
that
more
effective
sorbents
must
be
developed
for
Hg
°
capture
or
that
Hg
°
must
be
converted
to
more
a
easily
captured
form
such
as
HgCl2.

 
The
concentration
of
mercury
in
coal­
fired
utility
flue
gas
is
typically
less
that
10
µ
g/
dscm
while
the
concentration
of
mercury
in
MWCs
may
range
from
less
the
200
to
more
than
1500
µ
g/
dscm.
As
a
consequence,
the
stack
mercury
concentrations
of
well­
controlled
MWCs
will
typically
be
higher
than
the
inlet
mercury
flue
gas
concentrations
in
coal­
fired
utility
boilers.
C­
3
The
low
mercury
concentrations
at
the
inlet
to
coal­
fired
boiler
air
pollution
control
devices
and
the
large
volumes
of
flue
gases
that
must
be
cleaned
increase
the
difficulty
and
cost
of
control.

EPA,
DOE,
and
EPRI
are
all
engaged
in
research
to
develop
more
cost­
effective
mercury
control
technologies
for
coal­
fired
boilers.
This
includes
research
on
mercury
speciation,
studies
of
mercury
capture,
and
the
development
of
improved
control
technologies.

Major
objectives
of
these
research
efforts
are
to:

 
Develop
improved
manual
methods
to
measure
mercury
speciation
in
coal­
fired
boilers
and
other
combustion
systems.
Evaluate
continuous
emission
monitors
(
CEMs)
that
are
being
developed
for
measuring
total
and
speciated
mercury
in
flue
gases.
Effective
CEMs
can
be
used
to
monitor
and
adjust
mercury
control
technology
performance
as
well
as
serve
as
a
compliance
monitoring
tool.

 
Determine
the
factors
that
affect
mercury
speciation
in
flue
gases
and
develop
methods
that
can
be
used
to
control
speciation
in
order
to
improve
mercury
capture.

 
Develop
more
effective
sorbents
and
reagents
for
mercury
capture.
More
effective
sorbents
or
reagents
can
be
expected
to
accomplish
one
or
more
of
the
following
goals:
lower
sorbent
or
reagent
unit
costs
($/
lb),
increase
sorbent
collection
efficiency
or
reagent
reactivity,
increase
sorbent
or
reagent
utilization
rates,
and
provide
more
effective
multi­
pollutant
control.

 
Evaluate
and
develop
improved
control
technologies
as
embodied
in
more
effective
equipment
or
process
conditions.
For
example:
the
use
of
additional
ducting
upstream
of
the
PM
control
device
to
improve
sorbent
utilization
through
increased
residence
time,
recycling
of
collected
fly
ash
and
sorbent
into
the
flue
gas
upstream
of
the
PM
control
device
to
increase
sorbent
utilization,
and
equipment
modifications
needed
to
inject
a
reagent
into
the
flue
gas
to
increase
conversion
of
Hg
°
to
HgCl2
for
collection
in
wet
scrubbers.

It
is
believed
that
this
research
will
develop
improved
technologies
for
controlling
mercury
emissions
from
coal­
fired
boilers.
While
substantial
progress
is
expected
over
the
next
several
years,
it
is
not
now
possible
to
quantify
the
improvements
in
performance
and
costs
that
will
accrue
from
these
efforts.

Control
Technology
Options
Approximately
67%
(
capacity
basis)
of
the
existing
coal­
fired
utility
boilers
in
the
U.
S.
are
equipped
only
with
ESPs
for
the
control
of
PM.
Another
7%
employ
ESPs
followed
by
wet
scrubbers.
The
remaining
boilers
employ
dry
scrubbers
(
spray
dryers
and
ESPs
or
FFs)
or
employ
FFs
for
control
of
PM.
C­
4
In
this
study,
model
plants
with
eight
different
flue
gas
cleaning
equipment
configurations,
called
existing
configurations,
were
used.
In
addition,
it
was
assumed
that
each
of
the
existing
flue
gas
cleaning
system
configurations
could
be
associated
with
a
coal­
fired
utility
boiler
that
burns
either
bituminous
or
subbituminous
coal
­­
depending
on
the
plant
location.
These
16
model
plants,
reflecting
differences
in
flue
gas
cleaning
equipment
and
type
of
coal
burned,
are
shown
in
Exhibit
C1.

Each
retrofit
option
shown
in
Exhibit
C1
was
based
on
the
use
of
ACI.
This
is
the
only
technology
for
which
there
is
pilot­
scale
performance
data
for
both
eastern
and
western
coals.

Two
major
performance
parameters
were
selected
for
each
retrofit
option:

 
The
mercury
collection
efficiency
across
the
air
pollution
control
system,
and
 
The
ratio
of
the
required
carbon
injection
rate
to
mercury
flow
rate
in
the
flue
gas
at
the
inlet
to
the
first
air
pollution
control
device.

Mercury
collection
efficiencies
in
combustion
systems,
equipped
only
with
ESPs
or
FFs,
are
affected
by
the
concentration
of
mercury
in
the
flue
gas
at
the
inlet
to
the
PM
control
device,
and
the
amount
of
mercury
that
is
adsorbed
onto
the
fly
ash
and
subsequently
removed
in
the
PM
control
device.
No
attempt
was
made
in
this
study
to
quantify
the
capture
of
adsorbed
mercury
on
PM
since
there
is
only
fragmentary
information
on
this
subject.
Two
assumptions
were
made
on
the
effects
of
low
mercury
inlet
concentrations
in
order
to
obtain
reasonable
mercury
control
retrofit
costs.

In
the
EPA
Mercury
Study
Report
to
Congress,
the
required
mercury
control
efficiency
for
each
retrofit
option
was
assumed
to
be
90%
[
3].
In
this
study
90%
control
was
assumed
to
be
required
for
only
those
units
whose
existing
equipment
configuration
includes
wet
scrubbers.
Lower
collection
efficiencies
were
assumed
for
units
that
now
employ
ESPs,
FFs,
or
dry
scrubbers
(
see
Exhibit
C1).
An
85%
collection
efficiency
was
assumed
for
non­
FGD
units
that
select
some
combination
of
ACI
and
FFs
as
the
mercury
control
method.
For
the
two
cold­
side
ESP
cases
that
use
SC
+
ACI
as
the
retrofit
option,
collection
efficiencies
of
80
and
65
percent
are
assumed
respectively
for
the
plants
that
burn
bituminous
coal
(
Case
1A)
and
subbituminous
coal
(
Case
1B).

Dropping
the
collection
efficiency
from
90
to
85,
from
90
to
80,
or
from
90
to
65%
will
have
a
disproportionate
effect
on
the
amount
of
carbon
needed.
At
high
collection
efficiencies,
increasingly
larger
amounts
of
carbon
are
required
for
each
percentage
point
in
collection
efficiency
gain.
For
Case
1B,
a
plant
with
a
cold­
side
ESP
that
burns
subbituminous
coal,
a
combination
of
lower
performance
requirements
(
65%
collection
efficiency)
and
lower
carbon/
mercury
ratio
(
7,500)
was
selected
because
of
the
potentially
lower
mercury
flue
gas
inlet
concentrations
associated
with
the
combustion
of
subbituminous
coals.
C­
5
Units
equipped
only
with
ESPs
will
be
the
most
difficult
to
retrofit
in
a
cost­
effective
manner.
Cost
trade­
off
studies
indicated
that
the
most
cost
effective
retrofit
option,
for
which
pilot­
scale
test
data
exist,
is
spray
cooling
(
SC)
followed
by
carbon
injection
upstream
of
a
new
(
relatively
small)
FF
installed
downstream
of
the
existing
ESP.

It
will
be
less
difficult
to
effectively
retrofit
plants
with
existing
configurations
that
consist
of
FFs,
either
with
or
without
dry
scrubbers.
Activated
carbon
in
the
FF
cake
provides
better
gasparticle
contact
than
an
ESP,
and
the
longer
effective
carbon
residence
times
greatly
improve
sorbent
utilization.
This
has
been
validated
in
full­
scale
tests
on
MWCs
and
pilot
scale
tests
on
coal­
fired
combustors.
Field
tests
have
shown
that
it
takes
two
to
three
times
more
ACI
to
achieve
the
same
performance
on
MWCs
equipped
with
dry
scrubbers
and
ESPs
than
with
dry
scrubbers
and
FFs
[
4].

It
is
anticipated
that
current
research
on
wet
scrubbers
will
result
in
improved
performance
through
the
use
of
reagents
or
catalysts
to
convert
mercury
to
chemical
forms
that
are
soluble
in
aqueous
based
scrubbers.
However,
since
there
are
no
published
pilot­
scale
test
data
that
confirm
this
hypothesis,
it
was
assumed
for
this
study
that
ACI
is
needed
for
facilities
with
existing
wet
scrubbers.
For
utilities
with
cold­
side
ESPs,
this
will
entail
SC
followed
by
ACI.
In
facilities
with
existing
hot­
side
ESPs,
the
installation
of
FF
downstream
of
the
existing
ESP
will
also
be
required.

Described
in
the
following
sections
is
the
development
of
the
information
shown
in
Exhibit
C­
1.
This
is
followed
by
a
description
of
the
cost
methodology
that
EPA
adopted
in
this
work.
Finally,
costs
associated
with
each
of
the
model
plants
of
Exhibit
C1
are
provided.

Model
Performance
Parameters
Based
on
the
information
in
EPA's
Mercury
Study
Report
to
Congress
[
3]
and
other
published
literature
[
2,
5­
10],
control
technologies
based
on
injection
of
AC
into
the
flue
gas
appear
to
hold
promise
for
reducing
mercury
emissions
from
utility
boilers.
EPA
arrived
at
this
determination
by
considering
that:
(
1)
ACI
technologies
have
been
applied
successfully
on
MWCs;
(
2)
information
on
results
achieved
in
pilot­
scale
ACI
tests,
conducted
on
coal­
fired
utility
boilers,
is
available
in
published
literature;
and
(
3)
limited
cost
data
are
available
for
applications
of
ACI
­
based
technologies
on
utility
boilers.

As
discussed
below
and
summarized
in
Exhibit
C1,
the
estimates
of
mercury
emission
reduction
performance
and
associated
carbon
injection
rates
are
based
on
reported
pilot­
scale
applications
[
6­
10].

In
arriving
at
the
contents
of
Exhibit
C1,
six
assumptions
were
made
with
respect
to
mercury
control
system
hardware
and
performance.
These
assumptions
are
described
below.
C­
6
1.
The
performance
estimates
presented
in
Exhibit
C1
reflect
the
mercury
emission
reduction
percent
calculated
using
Reduction
(%)
=
100*(
Emissionin
­
Emissionstack)
/
Emissionin
(
1)

where:

Emissionin
=
flue
gas
mercury
concentration
at
the
inlet
to
the
first
air
pollution
control
device;
and
Emissionstack
=
mercury
emission
level
at
stack
exhaust.

2.
It
is
known
that
the
type
of
coal
fired
in
the
boiler
can
influence
the
performance
of
mercury
emission
reduction
technologies.
Therefore,
as
shown
in
Exhibit
C1,
separate
estimates
of
mercury
emission
reduction
performance
and
carbon
injection
rate
were
determined
for
bituminous
and
subbituminous
coals.
As
described
in
assumptions
4,
5,
and
6,
below,
these
estimates
are
based
on
published
data
[
6­
10].

3.
In
each
of
the
technologies
shown
in
Exhibit
C1,
the
boiler
flue
gas
is
spray
cooled
before
injection
of
AC.
In
general,
the
operating
costs
associated
with
use
of
AC
comprise
a
significant
portion
of
total
costs
for
ACI­
based
technologies.
Since
spray
cooling
of
flue
gas
results
in
significantly
reduced
requirements
of
AC,
this
cooling
was
included
in
each
of
the
technologies
shown
in
Exhibit
C1.
Note
that
the
capital
costs
associated
with
spray
cooling
equipment
are
independent
of
the
degree
of
cooling
needed,
within
the
range
of
referenced
applications.
Note
also
that
spray
cooling
is
assumed
to
exist
at
boiler
sites
with
dry
scrubbers.
Consequently,
no
additional
SCs
are
needed
in
Cases
7A,
7B,
8A,
and
8B.

4.
The
performance
estimates
for
cases
1A,
1B,
5A,
5B,
7A,
7B,
8A,
and
8B
were
interpolated
from
field
pilot
data
in
references
[
6­
10],
as
described
below.

Reference
[
6]
describes
AC
injection
application
on
a
low­
sulfur,
high
chlorine,
Eastern
bituminous
coal­
fired
boiler
served
by
parallel
pilot
ESP
and
pilot
FF
units.
In
this
application:
(
1)
with
an
ESP
and
gas
cooling
(
Case
1A),
80%
mercury
control
was
achieved
at
55,000:
1
C/
Hg
and
(
2)
with
a
FF
and
gas
cooling
(
Case
5A),
90%
mercury
control
was
achieved
at
40,000:
1
C/
Hg.
The
high
chlorine
content
of
coal
was
thought
to
be
responsible
for
the
poor
carbon
utilization.
Reference
[
10]
describes
subsequent
attempts
to
add
lime
with
ACI
upstream
of
the
FF,
which
resulted
in
improved
performance
of
ACI.
In
this
application,
using
an
FF
(
Case
5A),
90%
mercury
control
was
achieved
at
12,000:
1
C/
Hg.
Interpolation
of
these
results
suggests
that
85%
mercury
reduction
may
be
achieved
using
C/
Hg
of
10,000:
1
as
shown
in
Exhibit
C1.
C­
7
For
the
analyses,
C/
Hg
at
10,000:
1
was
selected
for
Case
5A.
Since
no
comparable
data
are
available
for
Case
1A,
the
proportional
improvement
in
ACI
performance
due
to
the
removal
of
HCl
by
lime
is
assumed
to
hold
for
ESPs.
Therefore,
75%
improvement
in
AC
utilization
suggests
that
ESPs
(
Case
1A)
can
achieve
80%
Hg
control
at
15,000:
1
C/
Hg
with
hydrated
lime
assistance,
or
with
no
HCl
present
in
the
flue
gas.

It
is
observed
that
the
supplemental
use
of
hydrated
lime
with
ACI
to
enhance
mercury
capture
will
not
negatively
impact
the
estimated
costs
of
control.
Capital
costs
are
already
covered
by
the
sorbent
storage
and
injection
system
costs,
and
lime
is
relatively
cheap
compared
to
the
AC
that
it
may
displace
(
the
cost
of
hydrated
lime
is
about
$
85/
ton
compared
with
$
909/
ton
for
the
AC
used
in
this
study).
In
addition,
the
use
of
hydrated
lime
will
generate
additional
credits
for
the
control
of
SO2
,
SO3
and
fine
PM.

Reference
[
7]
describes
similar
pilot
ACI
testing
on
low
sulfur
subbituminous
coal.
Using
the
results
of
this
testing,
mercury
emission
reduction
performance
and
carbon
requirements
for
Cases
1B
and
5B
were
determined.
In
the
tests
with
an
ESP
(
Case
1B),
up
to
74%
mercury
removal
was
achieved
at
a
C/
Hg
of
<
10,000:
1.
This
suggests
that
an
average
of
65%
mercury
removal
can
be
achieved
at
a
C/
Hg
of
7500:
1
with
gas
cooling
(
Case
1B).
Again
in
the
tests
with
a
FF
(
Case
5B),
90%
mercury
removal
was
achieved
at
a
C/
Hg
of
10,000:
1.
This
suggests
that
an
average
of
85%
mercury
removal
can
be
achieved
at
a
C/
Hg
of
6,000:
1
with
gas
cooling
(
Case
5B).
The
improved
carbon
utilization
achieved
in
subbituminous
coal
tests
over
the
bituminous
coal
results
provided
above
is
thought
to
be
directly
related
to
high
fly
ash
alkalinity
and
low
chlorine
content
of
subbituminous
coal.

Reference
[
8]
describes
mercury
removal
using
a
pilot
dry
scrubber
and
ACI
on
a
simulated
flue
gas
with
no
chlorine
and
elemental
mercury
vapor
present.
AC
removed
essentially
all
of
the
mercury
at
a
C/
Hg
of
770
(
using
iodine­
impregnated
AC).
Reference
[
9]
describes
mercury
removal
using
wet
and
dry
scrubbers
on
a
midwestern
coal
in
which
the
dominant
form
of
mercury
is
known
to
be
HgCl2.
Mercury
removals
of
75­
85%
were
observed
using
no
ACI,
where
the
HgCl2
behaved
as
an
acid
gas
and
was
sequestered
by
the
alkaline
FGD
sorbent.
Assuming
that
50%
of
the
mercury
in
the
typical
coal
flue
gas
is
oxidized
and
that
remaining
is
elemental
mercury,
it
is
judged
that
dry
scrubbing
will
control
50%
of
the
mercury
in
Eastern
coals
and
65%
of
the
mercury
in
high
alkalinity
Western
subbituminous
coals.
With
ACI,
85%
removal
can
be
achieved
on
both
types
of
coal,
but
the
AC
needed
will
vary
from
3000:
1
C/
Hg
on
the
alkaline
ash
coals
with
FF
control
(
Case
7B)
up
to
10,000:
1
C/
Hg
on
Eastern
bituminous
coal
with
ESP
control
(
Case
8A).
Intermediate
levels
of
AC
addition
 
around
6,000:
1
 
were
judged
necessary
for
Cases
7A
and
8B
to
achieve
85%
control.

5.
The
performance
and
carbon
requirements
associated
with
Cases
2A
and
2B
are
assumed
to
be
identical
to
Cases
5A
and
5B,
respectively.
This
assumption
is
made
because
a
FF
is
the
PM
control
device
in
each
of
these
cases.
However,
whereas
in
Cases
5A
and
5B
FFs
C­
8
exist
at
boiler
sites,
in
Cases
2A
and
2B
small
FFs
are
considered
to
be
needed
to
collect
AC.

6.
If
wet
FGD
is
available
at
a
boiler
site
in
addition
to
an
ACI­
based
technology,
then
90%
mercury
reduction
is
assumed
to
be
available
without
any
change
in
cost
over
the
corresponding
case
without
wet
FGD.
Thus,
for
example,
costs
for
Cases
1A
and
3A
of
Exhibit
C1
would
be
identical
but
90%
reduction
is
available
in
Case
3A
in
contrast
to
80%
in
Case
1A.
Thus
costs
for
Cases
3A,
3B,
4A,
4B,
6A,
and
6B
are
identical
to
Cases
1A,
1B,
2A,
2B,
5A,
and
5B,
respectively,
but
90%
mercury
removal
is
available
in
cases
with
wet
FGD.

Based
on
the
carbon
injection
rates
shown
in
Exhibit
C1,
costs
associated
with
the
use
of
each
of
the
ACI
technologies
were
developed.
Described
in
the
ensuing
paragraphs
is
the
methodology
used
in
arriving
at
these
costs.
C­
9
Exhibit
C1
Viable
Mercury
Emission
Control
Technologies
for
Utility
Boilers
Case
Existing
Coal
Type
Mercury
Emission
Reduction
C/
Hg
Equipment
Equipment
(%)
(
g
carbon
/
g
Hg)

1A
Cold
ESP
bituminous
SC
+
ACI
80
15,000
1B
Cold
ESP
subbituminous
SC
+
ACI
65
7,500
2A
Hot
ESP
bituminous
SC
+
ACI
+
FF
85
10,000
2B
Hot
ESP
subbituminous
SC
+
ACI
+
FF
85
6,000
3A
Cold
ESP
+
FGD
bituminous
SC
+
ACI
90
15,000
3B
Cold
ESP
+
FGD
subbituminous
SC
+
ACI
90
7500
4A
Hot
ESP
+
FGD
bituminous
SC
+
ACI
+
FF
90
10,000
4B
Hot
ESP
+
FGD
subbituminous
SC
+
ACI
+
FF
90
6,000
5A
FF
bituminous
SC
+
ACI
85
10,000
5B
FF
subbituminous
SC
+
ACI
85
6,000
6A
FF
+
wet
FGD
bituminous
SC
+
ACI
90
10,000
6B
FF
+
wet
FGD
subbituminous
SC
+
ACI
90
6,000
7A
DS
+
FF
bituminous
ACI
85
6,000
7B
DS
+
FF
subbituminous
ACI
85
3,000
8A
DS
+
ESP
bituminous
ACI
85
10,000
8B
DS
+
ESP
subbituminous
ACI
85
6,000
Abbreviations:

ACI:
activated
carbon
injection
DS:
dry
scrubber
(
either
a
spray
dryer
absorber/
particulate
matter
removal
system
or
a
dry
alkali
sorbent
injection/
particulate
matter
removal
system)
ESP:
electrostatic
precipitator
FGD:
flue
gas
desulfurization
system
FF:
fabric
filter
(
or
baghouse)
Hg:
mercury
SC:
spray
cooler
C­
10
Determination
of
Capital
Costs
ACI
systems,
FFs,
and
SCs
are
utilized
in
the
ACI­
based
technologies
shown
in
Exhibit
C­
1.
Some
cost
information
on
these
hardware
elements,
in
the
context
of
ACI­
based
technologies,
is
available
in
the
EPA's
Mercury
Study
Report
to
Congress
[
3]
and
a
recent
Department
of
Energy
(
DOE)
publication
[
11].
This
cost
information,
pertinent
to
specific
applications
on
boiler
sizes
of
100
and
975
MW,
is
shown
in
Exhibit
C2.

Exhibit
C2
Cost
in
$
s
of
Major
Equipment
Used
in
ACI­
based
Technologies1
FF
SC
ACI
System
100
MW
975
MW
100
MW
975
MW
100
MW
975
MW
EPA2
1,813,479
12,978,750
258,627
2,993,796
109,448
109,448
DOE3
Same
as
EPA
Same
as
EPA
Same
as
EPA
Same
as
EPA
257,000
2,231,000
DOE
has
reported
that
it
examined
EPA's
cost
estimates
for
FF
and
SC
provided
in
refrence
[
3]
and
found
them
to
be
reasonable
[
11].
However,
as
described
in
reference
[
11],
DOE
appears
to
have
conducted
more
detailed
cost
estimates
for
ACI
systems.
Accordingly,
EPA's
costs
for
FFs
and
SCs
and
DOE's
costs
for
ACI
systems
were
used
to
develop
the
capital
cost
functions
for
each
of
the
ACI­
based
technologies
shown
in
Exhibit
C­
1.
Note,
however,
that
DOE
used
a
carbon
injection
rate
of
30,000
g
of
carbon/
g
of
mercury
[
11].
Therefore,
the
DOE
ACI
system
costs
were
adjusted
to
correspond
to
the
injection
rates
shown
in
Exhibit
C­
1.

The
steps
taken
in
calculating
capital
cost
($/
kW)
of
applying
a
specific
ACI­
based
technology
on
a
specific
boiler
are
shown
in
Exhibit
C3.

1
The
EPA
and
DOE
costs
presented
in
this
table
were
based
on
the
same
model
boilers.
A
description
of
these
model
boilers
of
sizes
100
MW
and
975
MW
can
be
found
in
references
[
3]
and
[
11].

2
Per
Appendix
B
of
Volume
VIII
of
the
Mercury
Study
Report
to
Congress
[
3],
purchased
equipment
costs
for
SC
and
ACI
systems
were
based
on
vendor
contacts
reported
in
1993
and
FF
costs
were
based
on
1992
data.
Accordingly,
in
this
study,
EPA's
costs
for
SC
and
FF
are
considered
to
be
in
1993
dollars.

3
Per
the
reference
[
11],
DOE's
costs
are
on
1989
basis.
These
costs
were
escalated
to
1993
dollars
using
the
inflator
factor
of
1.144003567.
This
inflator
factor
has
been
derived
from
the
Economic
Report
of
the
President,
Council
of
Economic
Advisers,
Feb
1998
[
13].
C­
11
Exhibit
C3
Capital
Cost
Calculation
Description
Cost
or
Data
Symbol
Boiler
size
(
MW)
MW1
Purchased
equipment
cost
($)
PE
Installation
cost
($)
4
Inst
=
x*
PE
Indirect
cost
($)
5
Ind
=
y*
PE
Total
capital
cost
($)
TCC
=
PE
+
Inst
+
Ind
Retrofit
factor6
1.15
Total
capital
cost
w/
retrofit
($)
TC
=
1.15*
TCC
Capital
cost
($/
kW)
CC
=
TC/(
MW1*
1000)

For
each
of
the
ACI­
based
technologies,
capital
costs
($/
kW)
were
calculated
for
model
boiler
sizes
of
100
and
975
MW.
These
model
boilers
are
described
in
the
references
[
3]
and
[
11].
The
capital
costs
($/
kW)
obtained
were
used
to
develop
the
capital
cost
function
relating
($/
kW)
to
boiler
size
(
MW).
This
function
has
the
form
C1
=
C2
(
MW2/
MW1)
a
(
2)

where:

C1
=
capital
cost
($/
kW)
of
ACI­
based
technology
installation
at
the
first
model
boiler;
C2
=
capital
cost
($/
kW)
of
ACI­
based
technology
installation
at
the
second
model
boiler;
MW1
=
first
model
boiler
size
in
MW;
MW2
=
second
model
boiler
size
in
MW;
and
a
=
a
scaling
factor
reflecting
economy­
of­
scale.

Capital
cost
functions,
expressed
by
Equation
(
2),
were
obtained
for
each
of
the
ACI­
based
technologies.

4
The
values
of
the
installation
cost
factor,
x,
used
are
identical
to
those
used
in
the
Mercury
Study
Report
to
Congress
[
3].
These
values
are:
0.34
for
SC,
0.15
for
ACI,
and
0.72
for
FF.

5
The
values
of
the
indirect
cost
factor,
y,
used
are
identical
to
those
used
in
the
Mercury
Study
Report
to
Congress
[
3].
These
values
are:
0.45
for
SC,
0.30
for
ACI,
and
0.45
for
FF.

6
A
retrofit
factor
of
1.15
was
included
in
the
cost
estimation
procedure
to
account
for
more
difficult
retrofits.
C­
12
Determination
of
Annual
Fixed
Operation
and
Maintenance
(
O&
M)
Costs
Fixed
O&
M
costs
include
costs
related
to
maintenance
requirements
(
labor
and
materials);
taxes,
insurance,
and
administration;
and
capital
recovery.
Following
the
guidelines
in
the
Electric
Power
Research
Institute's
Technical
Assessment
Guide
[
12],
the
annual
cost
of
maintenance
labor
and
materials,
expressed
in
($/
kW),
is
assumed
to
be
1.5%
of
the
capital
cost
($/
kW).
The
annual
carrying
charge
used
in
the
IPM
model
includes
the
effects
of
capital
recovery
as
well
as
taxes
and
insurance.
Note
that,
as
mentioned
in
Chapter
2
of
this
report,
administration
costs
were
not
modeled
in
this
effort.

Determination
of
Annual
Variable
O&
M
Costs7
Variable
O&
M
costs
include
labor
charges,
costs
related
to
consumption
of
activated
carbon
and
power,
any
incremental
waste
disposal
cost,
cost
of
operating
materials
(
water
for
SC),
and
overhead.
Calculation
of
each
of
these
is
described
below.

Labor
cost:
Both
operating
labor
and
supervisory
labor
are
accounted
for
in
the
cost
estimates.
Following
the
information
provided
in
reference
[
3],
the
labor
rate
is
taken
to
be
$
12/
hr
and
supervisory
labor
costs
total
15%
of
operating
labor
costs.
Then
for
a
capacity
factor
(
CF),
labor
cost
is
computed
using
Labor
(
mills/
kWh)
=
1.15*$
12/
hr*
CF*
8760
hr/
yr*
1000
mills/$
/
(
MW*
1000
kW/
MW*
8760
hr/
yr*
CF)
(
3)

Activated
carbon
cost:
Based
on
recent
information,
8
the
cost
of
activated
carbon
is
taken
to
be
$
1.00
per
kg
of
activated
carbon.
Using
this
cost
along
with
the
flue
gas
flow,
concentration
of
mercury
in
the
flue
gas,
CF,
and
carbon
injection
rate,
the
cost
of
activated
carbon
consumption
(
mills/
kWh)
is
determined
for
each
model
boiler
application.
An
average
of
the
costs
for
the
model
boiler
applications
is
considered
to
be
the
carbon
consumption
cost
(
mills/
kWh)
for
each
of
the
ACI­
based
technologies.

Power
consumption
cost:
Power
costs
provided
in
reference
[
3]
for
model
boiler
applications
were
based
on
a
unit
power
cost
of
46
mills/
kWh
and
on
a
carbon
injection
rate
of
460
g
of
carbon
per
g
of
mercury.
For
this
work,
the
annual
power
consumption
costs
($/
yr)
provided
in
reference
[
3]
were
adjusted
to
reflect
any
change
in
carbon
injection
rate
and
a
power
cost
of
19.4
mills/
kWh
in
1993.
The
adjusted
power
consumption
costs
($/
yr)
were
used
to
arrive
at
the
7
Note
that
although
the
Mercury
Study
Report
to
Congress
[
3]
was
released
in
December
1997,
the
cost
data
in
this
study,
at
least
for
equipment,
appear
to
be
pertinent
to
1993
(
see
footnote
2).
As
a
conservative
measure,
for
this
study
all
of
the
cost
data
presented
in
[
3]
were
assumed
to
be
for
the
year
1993.

8
Personal
communication
between
Charles
Sedman
and
Jim
Kilgroe
of
EPA
and
Anthony
Licata
of
Licata
Energy
&
Environmental
Consultants,
Inc.,
Yonkers,
NY,
December
14,
1998.
C­
13
power
consumption
cost
(
mills/
kWh)
for
model
boiler
applications.
The
average
of
the
costs
for
the
model
boiler
applications
is
considered
to
be
the
carbon
consumption
cost
(
mills/
kWh)
for
each
of
the
ACI­
based
technologies.

Disposal
cost:
Annual
disposal
costs
($/
yr)
for
the
model
boiler
applications
provided
in
reference
[
3]
were
adjusted
to
reflect
any
change
in
carbon
injection
rate
and
then
were
used
to
arrive
at
disposal
costs
expressed
in
mills/
kWh.
The
average
of
the
costs
for
the
model
boiler
applications
is
considered
to
be
the
carbon
consumption
cost
(
mills/
kWh)
for
each
of
the
ACI­
based
technologies.

Operating
materials
cost:
These
costs
for
the
various
applications
were
taken
from
the
Mercury
Study
Report
to
Congress
[
3].

Overhead:
Following
the
information
in
reference
[
3],
the
overhead
cost
for
each
of
the
ACIbased
technologies
was
taken
to
be
60%
of
the
labor
and
maintenance
costs.

Results
The
costs
of
the
ACI­
based
technologies,
developed
using
the
above
methodology,
are
shown
in
Exhibits
C­
4
through
C­
13
at
the
end
of
this
appendix.

Caveats
The
performance
and
cost
estimates
of
the
ACI­
based
technologies
presented
in
this
appendix
are
considered
to
be
preliminary
for
several
reasons.
First,
the
performance
estimates
and
associated
carbon
requirements
are
based
on
relatively
few
data
points
that
have
been
established
in
pilot­
scale
tests.
Factors
that
are
known
to
affect
adsorption
of
mercury
on
activated
carbon
are:
speciation
of
mercury
in
flue
gas,
available
residence
time
(
duct
length),
effect
of
flue
gas
and
ash
characteristics,
and
adequacy
of
mixing
between
flue
gas
and
activated
carbon.
The
effect
of
these
factors
may
not
be
accounted
for
in
the
relatively
few,
pilot­
scale,
data
points
that
comprised
the
basis
for
this
work.
The
research
being
conducted
by
EPA,
DOE,
and
EPRI
is
expected
to
address
these
issues
in
the
next
few
years.
In
addition
to
the
technical
issues
surrounding
the
use
of
AC
for
mercury
control,
more
accurate
estimation
of
equipment
costs
is
needed
to
better
capture
the
economy­
of­
scale
that
would
be
expected.
C­
14
References
1.
Analyzing
Electric
Power
Generation
Under
CAAA,
Office
of
Air
and
Radiation,
U.
S.
Environmental
Protection
Agency,
Washington,
D.
C.,
March
1998.
Available
at
the
web
site
www.
epa.
gov/
capi.

2.
EPA
Study
of
Hazardous
Air
Pollutant
Emissions
from
Electric
Utility
Steam
Generating
Plants
 
Final
Report
to
Congress,
Volume
1,
EPA
453R­
98­
004a
(
NTIS
PB98­
131773),
Office
of
Air
Quality
Planning
and
Standards,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC,
February
1998.

3.
Keating,
M.
H.,
et.
al.,
Mercury
Study
Report
to
Congress,
EPA­
452/
R­
97­
003
(
NTIS
PB98­
124738),
Office
of
Air
Quality
Planning
and
Standards
and
Office
of
Research
and
Development,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC,
December
1997.

4.
Kilgroe,
J.
D.,
Control
of
Dioxin,
Furan,
and
Mercury
Emissions
from
Municipal
Waste
Combustors,
Journal
of
Hazardous
Materials,
47
(
1966)
163­
194.

5.
R.
Chang
and
G.
Offen,
"
Mercury
Emission
Control
Technologies:
An
EPRI
Synopsis,"
Power
Engineering,
November
1995.

6.
Waugh,
E.,
et
al.,
"
Mercury
Control
in
Utility
ESPs
and
Baghouses
through
Dry
Carbon­
Based
Sorbent
Injection
Pilot­
Scale
Demonstration,"
in
EPRI­
DOE­
EPA
Combined
Air
Pollutant
Control
Symposium,
Particulates
and
Air
Toxics,
Volume
3,
EPRI
TR­
108683­
V3,
Electric
Power
Research
Institute,
Palo
Alto,
CA,
August
1997.

7.
Haythornthwaite,
S.,
et
al.,
"
Demonstration
of
Dry
Carbon­
Based
Sorbent
Injection
for
Mercury
Control
in
Utility
ESPs
and
Baghouses,"
in
EPRI­
DOE­
EPA
Combined
Air
Pollutant
Control
Symposium,
Particulates
and
Air
Toxics,
Volume
3,
EPRI
TR­
108683­
V3,
Electric
Power
Research
Institute,
Palo
Alto,
CA,
August
1997.

8.
Helfritch,
D.,
P.
Feldman,
and
S.
Pass,
"
A
Circulating
Fluid
Bed
Fine
Particulate
and
Mercury
Control
Concept,"
in
EPRI­
DOE­
EPA
Combined
Air
Pollutant
Control
Symposium,
Particulates
and
Air
Toxics,
Volume
3,
EPRI
TR­
108683­
V3,
Electric
Power
Research
Institute,
Palo
Alto,
CA,
August
1997.

9.
Redinger,
K.,
et
al.,
"
Mercury
Emissions
Control
in
FGD
Systems,"
in
EPRI­
DOE­
EPA
Combined
Air
Pollutant
Control
Symposium,
Particulates
and
Air
Toxics,
Volume
3,
EPRI
TR­
108683­
V3,
Electric
Power
Research
Institute,
Palo
Alto,
CA,
August
1997.
C­
15
10.
Waugh,
E.
G.,
et
al.,
"
Mercury
Control
on
Coal­
Fired
Flue
Gas
Using
Dry
Carbon­
Based
Sorbent
Injection:
Pilot­
Scale
Demonstration,"
presented
at
the
1998
Air
&
Waste
Management
Association
Annual
Meeting
and
Exhibition,
San
Diego,
CA,
June
1998.

11.
Brown
T.,
W.
O'Dowd,
R.
Reuther,
and
D.
Smith,
"
Control
of
Mercury
Emissions
from
Coal­
Fired
Power
Plants:
A
Preliminary
Cost
Assessment,"
in
Proceedings
of
the
Conference
on
Air
Quality,
Mercury,
Trace
Elements,
and
Particulate
Matter,
Energy
&
Environmental
Research
Center,
McLean,
VA,
December
1998.

12.
Technical
Assessment
Guide,
Volume
1:
Electricity
Supply
 
1993
(
Revision
7),
EPRI
TR­
102276s
Vol.
1
Rev.
7,
Electric
Power
Research
Institute,
Palo
Alto,
CA,
1993.

13.
Economic
Report
of
the
President,
Council
of
Economic
Advisers,
February
1998.
Available
at
the
web
site
www.
access.
gpo.
gov/
eop/.
C­
16
Exhibit
C4
SC+
ACI
+
cold
ESP
with
Bituminous
Coal
Case
1A:
SC+
ACI
+
cold
ESP
with
bituminous
coal
Data
for
975
MW
from
Table
B­
12
in
EPA's
Report
to
Congress
(
RTC)
[
3]

Data
for
SC+
ACI
for
100
MW
from
Table
B­
11
in
EPA's
RTC[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
15000
15000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
9
$
0.89
$
0.89
Capital
Costs:
1993$

Spray
cooling
system
($)
$
2,993,796
$
258,627
RTC,
1993
$
s
Carbon
injection
system
($)
10
$
1,276,136
$
147,004
Purchased
equipment,
PE,
($)
$
4,269,932
$
405,631
Installation
($)
$
1,209,311
$
109,984
Indirect
($)
$
1,730,049
$
160,483
Total
capital
cost
($)
$
7,209,292
$
676,099
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
8,290,686
$
777,514
Total
capital
cost
($/
kW)
$
8.50
$
7.78
Exponent
=
­
0.04
Capital
cost
($/
kW)
=
8.50*(
975/
MW)^­
0.04
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.13
0.12
Maintenance
($/
kW­
Yr)
=
0.13*(
975/
MW)^­
0.04
975
100
Formula
Labor
($/
yr)
$
59,616
$
49,680
RTC
Labor
(
mills/
kWh)
=
0.01
0.09
Given
below
Carbon
cost
($/
yr)
$
3,077,496
$
312,309
RTC
Carbon
(
mills/
kWh)
=
0.55
0.55
0.55
Power
($/
yr)
$
964,396
$
88,921
RTC
Power
(
mills/
kWh)
=
0.07
0.07
0.07
Disposal
($/
yr)
$
139,826
$
94,630
RTC
Disposal
(
mills/
kWh)
=
0.025
0.166
0.096
Operating
materials
($/
yr)
$
219,572
$
18,968
RTC
Operating
matls
(
mills/
kWh)
=
0.04
0.03
0.04
Overhead
(
mills/
kWh)
0.02
0.06
Given
below
Labor
varies
with
usage
(
not
with
boiler
size);
overhead
at
60%
of
labor
&
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
(
1993$)

Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
Yr)
+
labor(
mills/
kWh)]

9
The
carbon
cost
of
$
1.00/
kg,
see
footnote
8,
has
been
deflated
using
a
deflator
of
0.8896797.
The
deflator
was
obtained
using
a
1997
to
1992
relationship
from
CEA,
Economic
Report
of
the
President
(
ERP),
using
February
1998
as
a
proxy
for
1998
to
1993
relationship.

10
Carbon
injection
system
costs
were
determined
by
adjusting
the
DOE
costs,
expressed
in
1989
$
s,
for
carbon
injection
rate
and
escalating
1989
dollars
to
1993
dollars
using
the
inflation
factor
of
1.144003567.
This
inflation
factor
has
been
derived
from
CEA,
ERP,
1993.
C­
17
Exhibit
C5
SC+
ACI
+
Cold
ESP
with
Subbituminous
Coal
Case
1B:
SC+
ACI
+
cold
ESP
with
subbituminous
coal
Data
for
975
MW
from
Table
B­
12
in
EPA's
RTC
[
3]

Data
for
SC+
ACI
for
100
MW
from
Table
B­
11
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
7500
7500
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$

Spray
cooling
system
($)
$
2,993,796
$
258,627
RTC,
1993
$
s
Carbon
injection
system
($)
$
638,068
$
73,502
See
footnote
10
Purchased
equipment,
PE,
($)
$
3,631,864
$
332,129
Installation
($)
$
1,113,601
$
98,959
Indirect
($)
$
1,538,629
$
138,433
Total
capital
cost
($)
$
6,284,093
$
569,521
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
7,226,707
$
654,949
Total
capital
cost
($/
kW)
$
7.41
$
6.55
Exponent
=
­
0.05
Capital
cost
($/
kW)
=
7.41*(
975/
MW)^­
0.05
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.11
0.10
Maintenance
($/
kW­
Yr)
=
0.11*(
975/
MW)^­
0.05
975
100
Formula
Labor
($/
yr)
$
59,616
$
49,680
RTC
Labor
(
mills/
kWh)
=
0.01
0.09
Given
below
Carbon
cost
($/
yr)
$
1,538,748
$
156,154
RTC
Carbon
(
mills/
kWh)
=
0.28
0.27
0.28
Power
($/
yr)
$
961,379
$
85,856
RTC
Power
(
mills/
kWh)
=
0.07
0.06
0.07
Disposal
($/
yr)
$
69,913
$
47,315
RTC
Disposal
(
mills/
kWh)
=
0.013
0.083
0.048
Operating
materials
($/
yr)
$
219,572
$
18,968
RTC
Operating
matls
(
mills/
kWh)
=
0.04
0.03
0.04
Overhead
(
mills/
kWh)
0.01
0.06
Given
below
Labor
varies
with
usage
(
not
with
boiler
size);
overhead
at
60%
of
labor
&
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
Yr)
+
labor(
mills/
kWh)]
C­
18
Exhibit
C6
Hot
ESP
+
SC+
ACI
with
Bituminous
Coal
Case
2A:
Hot
ESP
+
SC+
ACI
+
FF
with
bituminous
coal
Data
from
Tables
B­
10
and
B­
11,
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
10000
10000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
0.89
0.89
See
footnote
9
Capital
Costs:
1993$

Spray
cooling
system
($)
$
2,993,796
$
258,627
RTC,
1993
$
s
Carbon
injection
system
($)
$
850,757
$
98,003
See
footnote
10
Fabric
Filter
($)
$
12,978,750
$
1,813,479
RTC,
1993
$
s
Purchased
equipment
($)
$
16,823,303
$
2,170,109
Installation
($)
$
10,490,204
$
1,408,339
Indirect
($)
$
7,442,873
$
961,849
Total
capital
cost
($)
$
34,756,380
$
4,540,296
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
39,969,838
$
5,221,340
Capital
cost
($/
kW)
$
40.99
$
52.21
Exponent
=
0.11
Capital
cost
($/
kW)
=
40.99*(
975/
MW)^
0.11
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.61
0.78
Maintenance
($/
kW­
Yr)
0.61*(
975/
MW)^
0.11
975
100
Formula
Labor
($/
yr)
$
238,464
$
109,296
RTC
Labor
(
mills/
kWh)
=
0.04
0.19
Given
below
Carbon
cost
($/
yr)
$
2,051,664
$
208,206
RTC
Carbon
(
mills/
kWh)
=
0.37
0.37
0.37
Power
($/
yr)
$
2,050,797
$
203,834
RTC
Power
(
mills/
kWh)
=
0.16
0.15
0.15
Disposal
($/
yr)
$
621,152
$
63,087
RTC
Disposal
(
mills/
kWh)
=
0.112
0.111
0.111
Operating
materials
($/
yr)
$
521,674
$
79,785
RTC
Operating
matls
(
mills/
kWh)
=
0.09
0.14
Given
below
Overhead
(
mills/
kWh)
0.07
0.17
Given
below
Labor
and
operating
materials
costs
(
mills/
kWh)
vary
with
boiler
size;
overhead
at
60%
of
labor
&
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000/
MW*
1000*
8760*
CF
Operating
materials
(
mills/
kWh)
=
(
0.09­
0.14)/
875*(
MW­
100)
+
0.14
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
Yr)
+
labor(
mills/
kWh)]
C­
19
Exhibit
C7
Hot
ESP
+
SC+
ACI
with
Subbituminous
Coal
Case
2B:
Hot
ESP
+
SC+
ACI
+
FF
with
subbituminous
coal
Data
from
Tables
B­
10
and
B­
11,
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
6000
6000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$

Spray
cooling
system
($)
$
2,993,796
$
258,627
RTC,
1993
$
s
Carbon
injection
system
($)
$
510,454
$
58,802
See
footnote
10
Fabric
Filter
($)
$
12,978,750
$
1,813,479
RTC,
1993
$
s
Purchased
equipment
($)
$
16,483,000
$
2,130,908
Installation
($)
$
10,439,159
$
1,402,458
Indirect
($)
$
7,340,782
$
950,088
Total
capital
cost
($)
$
34,262,941
$
4,483,454
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
39,402,382
$
5,155,972
Capital
cost
($/
kW)
$
40.41
$
51.56
Exponent
=
0.11
Capital
cost
($/
kW)
=
40.41*(
975/
MW)^
0.11
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.61
0.77
Maintenance
($/
kW­
Yr)
=
0.61*(
975/
MW)^
0.11
975
100
Formula
Labor
($/
yr)
$
238,464
$
109,296
RTC
Labor
(
mills/
kWh)
=
0.04
0.19
Given
below
Carbon
cost
($/
yr)
$
1,230,998
$
124,924
RTC
Carbon
(
mills/
kWh)
=
0.22
0.22
0.22
Power
($/
yr)
$
2,049,188
$
202,199
RTC
Power
(
mills/
kWh)
=
0.16
0.15
0.15
Disposal
($/
yr)
$
372,691
$
37,852
RTC
Disposal
(
mills/
kWh)
=
0.067
0.066
0.067
Operating
materials
($/
yr)
$
521,674
$
79,785
RTC
Operating
matls
(
mills/
kWh)
=
0.09
0.14
Given
below
Overhead
(
mills/
kWh)
0.07
0.17
Given
below
Labor
and
operating.
materials.
costs
(
mills/
kWh)
vary
with
boiler
size;
overhead
at
60%
of
labor
&
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000/
MW*
1000*
8760*
CF
Operating
materials
(
mills/
kWh)
=
(
0.09­
0.14)/
875*(
MW­
100)
+
0.14
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
Yr)
+
labor(
mills/
kWh)]
C­
20
Exhibit
C8
SC+
ACI
+
FF
with
Bituminous
Coal
Case
5A:
SC+
ACI
+
FF
with
bituminous
coal
Using
SC
+
ACI
costs
from
Tables
B­
10
&
B­
11
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
10000
10000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$

Spray
cooling
system
($)
$
2,993,796
$
258,627
RTC,
1993
$
s
Carbon
injection
system
($)
$
850,757
$
98,003
See
footnote
10
Purchased
equipment,
PE,
($)
$
3,844,553
$
356,630
Installation
($)
$
1,145,504
$
102,634
Indirect
($)
$
1,602,435
$
145,783
Total
capital
cost
($)
$
6,592,493
$
605,047
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
7,581,367
$
695,804
Total
capital
cost
($/
kW)
$
7.78
$
6.96
Exponent
=
­
0.05
Capital
cost
($/
kW)
=
7.78*(
975/
MW)^­
0.05
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.12
0.10
Maintenance
($/
kW­
Yr)
=
0.12*(
975/
MW)^­
0.05
975
100
Formula
Labor
($/
yr)
$
59,616
$
49,680
RTC
Labor
(
mills/
kWh)
=
0.01
0.09
Given
below
Carbon
cost
($/
yr)
$
2,051,664
$
208,206
RTC
Carbon
(
mills/
kWh)
=
0.37
0.37
0.37
Power
($/
yr)
$
962,385
$
86,878
RTC
Power
(
mills/
kWh)
=
0.07
0.06
0.07
Disposal
($/
yr)
$
621,152
$
63,087
RTC
Disposal
(
mills/
kWh)
=
0.112
0.111
0.111
Operating
materials
($/
yr)
$
219,572
$
18,968
RTC
Operating
matls
(
mills/
kWh)
=
0.04
0.03
0.04
Overhead
(
mills/
kWh)
0.014
0.059
Given
below
Labor
varies
with
usage
and
not
with
boiler
size;
overhead
at
60%
of
labor
amd
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
yr)
+
labor(
mills/
kWh)]
C­
21
Exhibit
C9
SC+
ACI
+
FF
with
Subbituminous
Coal
Case
5B:
SC+
ACI
+
FF
with
subbituminous
coal
Using
SC
+
ACI
costs
from
Tables
B­
10
&
B­
11
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
6000
6000
Based
on
Published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
0.89
0.89
See
footnote
9
Capital
Costs:
1993$

Spray
cooling
system
($)
$
2,993,796
$
258,627
RTC,
1993
$
s
Carbon
injection
system
($)
$
510,454
$
58,802
See
footnote
10
Purchased
equipment,
PE,
($)
$
3,504,250
$
317,429
Installation
($)
$
1,094,459
$
96,753
Indirect
($)
$
1,500,345
$
134,023
Total
capital
cost
($)
$
6,099,054
$
548,205
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
7,013,912
$
630,436
Total
capital
cost
($/
kW)
$
7.19
$
6.30
Exponent
=
­
0.06
Capital
cost
($/
kW)
=
7.19*(
975/
MW)^­
0.06
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.11
0.09
Maintenance
($/
kW­
Yr)
=
0.11*(
975/
MW)^­
0.06
975
100
Formula
Labor
($/
yr)
$
59,616
$
49,680
RTC
Labor
(
mills/
kWh)
=
0.01
0.09
Given
below
Carbon
cost
($/
yr)
$
1,230,998
$
124,924
RTC
Carbon
(
mills/
kWh)
=
0.22
0.22
0.22
Power
($/
yr)
$
960,776
$
85,243
RTC
Power
(
mills/
kWh)
=
0.07
0.06
0.07
Disposal
($/
yr)
$
372,691
$
37,852
RTC
Disposal
(
mills/
kWh)
=
0.067
0.066
0.067
Operating
materials
($/
yr)
$
219,572
$
18,969
RTC
Operating
matls
(
mills/
kWh)
=
0.04
0.03
0.04
Overhead
(
mills/
kWh)
0.014
0.059
Given
below
Labor
varies
with
usage
and
not
with
boiler
size;
overhead
at
60%
of
labor
amd
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
yr)
+
labor(
mills/
kWh)]
C­
22
Exhibit
C10
DS
+
ACI
+
FF
with
Bituminous
Coal
Case
7A:
DS
+
ACI
+
FF
with
bituminous
coal
Taking
only
ACI
costs
from
Tables
B­
10
&
B­
11
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
6000
6000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$

Carbon
injection
system
($)
$
510,454
$
58,802
See
footnote
10
Purchased
equipment
($)
$
510,454
$
58,802
Installation
($)
$
76,568
$
8,820
Indirect
($)
$
153,136
$
17,641
Total
capital
cost
($)
$
740,159
$
85,263
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
851,183
$
98,052
Capital
cost
($/
kW)
$
0.87
$
0.98
Exponent
=
0.05
Capital
cost
($/
kW)
=
0.87*(
975/
MW)^
0.05
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.013
0.015
Maintenance
($/
kW­
Yr)
=
0.013*(
975/
MW)^
0.05
975
100
Formula
Labor
($/
yr)
$
29,808
$
29,808
RTC
Labor
(
mills/
kWh)
=
0.005
0.05
Given
below
Carbon
cost
($/
yr)
$
1,230,998
$
124,924
RTC
Carbon
(
mills/
kWh)
=
0.22
0.22
0.22
Power
($/
yr)
$
2,413
$
2,452
RTC
Power
(
mills/
kWh)
=
0.00018
0.00182
0.00100
Disposal
($/
yr)
$
372,691
$
37,852
RTC
Disposal
(
mills/
kWh)
=
0.067
0.066
0.067
Operating
materials
($/
yr)
$
0
$
0
RTC
Operating
matls
(
mills/
kWh)
=
0.00
0.00
0.00
Overhead
(
mills/
kWh)
0.004
0.032
Given
below
Labor
varies
with
usage
and
not
with
boiler
size;
overhead
at
60%
of
labor
and
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
yr)
+
labor(
mills/
kWh)]
C­
23
Exhibit
C11
DS
+
ACI
+
FF
with
Subbituminous
Coal
Case
7B:
DS
+
ACI
+
FF
with
subbituminous
coal
Taking
only
ACI
costs
from
Tables
B­
10
&
B­
11
in
EPA's
RTC
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
3000
3000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$

Carbon
injection
system
($)
$
255,227
$
29,401
See
footnote
10
Purchased
equipment
($)
$
255,227
$
29,401
Installation
($)
$
38,284
$
4,410
Indirect
($)
$
76,568
$
8,820
Total
capital
cost
($)
$
370,079
$
42,631
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
425,591
$
49,026
Capital
cost
($/
kW)
$
0.44
$
0.49
Exponent
=
0.05
Capital
cost
($/
kW)
=
0.44*(
975/
MW)^
0.05
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.007
0.007
Maintenance
($/
kW­
Yr)
=
0.007*(
975/
MW)^
0.05
975
100
Formula
Labor
($/
yr)
$
29,808
$
29,808
RTC
Labor
(
mills/
kWh)
=
0.005
0.05
Given
below
Carbon
cost
($/
yr)
$
615,499
$
62,462
RTC
Carbon
(
mills/
kWh)
=
0.11
0.11
0.11
Power
($/
yr)
$
1,207
$
1,226
RTC
Power
(
mills/
kWh)
=
0.00009
0.00091
0.00050
Disposal
($/
yr)
$
186,346
$
18,926
RTC
Disposal
(
mills/
kWh)
=
0.034
0.033
0.033
Operating
materials
($/
yr)
$
0
$
0
RTC
Operating
matls
(
mills/
kWh)
=
0.00
0.00
0.00
Overhead
(
mills/
kWh)
0.004
0.032
Given
below
Labor
varies
with
usage
and
not
with
boiler
size;
overhead
at
60%
of
labor
and
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
yr)
+
labor(
mills/
kWh)]
C­
24
Exhibit
C12
DS+
ACI
+
Cold
ESP
with
Bituminous
Coal
Case
8A:
DS+
ACI
+
cold
ESP
with
bituminous
coal
Data
for
975
MW
from
Table
B­
12
in
EPA's
Report
to
Congress
[
3]

Data
for
100
MW
from
Table
B­
11
in
EPA's
Report
to
Congress
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
10000
10000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$
.

Carbon
injection
system
($)
$
850,757
$
98,003
See
footnote
10
Purchased
equipment,
PE,
($)
$
850,757
$
98,003
Installation
($)
$
127,614
$
14,700
Indirect
($)
$
255,227
$
29,401
Total
capital
cost
($)
$
1,233,598
$
142,104
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
1,418,638
$
163,420
Total
capital
cost
($/
kW)
$
1.46
$
1.63
Exponent
=
0.05
Capital
cost
($/
kW)
=
1.46*(
975/
MW)^
0.05
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.02
0.02
Maintenance
($/
kW­
Yr)
=
0.02*(
975/
MW)^
0.05
975
100
Formula
Labor
($/
yr)
$
29,808
$
29,808
RTC
Labor
(
mills/
kWh)
=
0.01
0.05
Given
below
Carbon
cost
($/
yr)
$
2,051,664
$
208,206
RTC
Carbon
(
mills/
kWh)
=
0.37
0.37
0.37
Power
($/
yr)
$
4,022
$
4,087
RTC
Power
(
mills/
kWh)
=
3.1E­
04
3.0E­
03
1.7E­
03
Disposal
($/
yr)
$
621,152
$
63,087
RTC
Disposal
(
mills/
kWh)
=
0.112
0.111
0.111
Operating
materials
($/
yr)
$
0
$
0
RTC
Operating
matls
(
mills/
kWh)
=
0.00
0.00
0.00
Overhead
(
mills/
kWh)
0.005
0.033
Given
below
Labor
varies
with
usage
(
not
with
boiler
size);
overhead
at
60%
of
labor
&
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
(
1993$)

Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
Yr)
+
labor(
mills/
kWh)]
C­
25
Exhibit
C13
DS+
ACI
+
Cold
ESP
with
Subbituminous
Coal
Case
8B:
DS+
ACI
+
cold
ESP
with
subbituminous
coal
Data
for
975
MW
from
Table
B­
12
in
EPA's
Report
to
Congress
[
3]

Data
for
SC+
ACI
for
100
MW
from
Table
B­
11
in
EPA's
Report
to
Congress
[
3]

Source
Size
(
MW)
975
100
RTC
Capacity
factor
0.65
0.65
RTC
g
carbon
/
g
Hg
6000
6000
Based
on
published
data
Hg
concentration
(
µ
g/
dscm)
10
10
RTC
Flue
gas
flowrate
(
dscm/
hr)
4050000
411000
RTC
Carbon
($/
kg)
$
0.89
$
0.89
See
footnote
9
Capital
Costs:
1993$
.

Carbon
injection
system
($)
$
510,454
$
58,802
See
footnote
10
Purchased
equipment,
PE,
($)
$
510,454
$
58,802
Installation
($)
$
76,568
$
8,820
Indirect
($)
$
153,136
$
17,641
Total
capital
cost
($)
$
740,159
$
85,263
Retrofit
factor
1.15
1.15
Total
capital
cost
w/
retrofit
($)
$
851,183
$
98,052
Total
capital
cost
($/
kW)
$
0.87
$
0.98
Exponent
=
0.05
Capital
cost
($/
kW)
=
0.87*(
975/
MW)^
0.05
Annual
O&
M:

Maintenance
($/
kW­
Yr)
0.01
0.01
Maintenance
($/
kW­
Yr)
=
0.01*(
975/
MW)^
0.05
975
100
Formula
Labor
($/
yr)
$
29,808
$
29,808
RTC
Labor
(
mills/
kWh)
=
0.01
0.05
Given
below
Carbon
cost
($/
yr)
$
1,230,998
$
124,924
RTC
Carbon
(
mills/
kWh)
=
0.22
0.22
0.22
Power
($/
yr)
$
2,413
$
2,452
RTC
Power
(
mills/
kWh)
=
1.8E­
04
1.8E­
03
1.0E­
03
Disposal
($/
yr)
$
372,691
$
37,852
RTC
Disposal
(
mills/
kWh)
=
0.067
0.066
0.067
Operating
materials
($/
yr)
$
0
$
0
RTC
Operating
matls
(
mills/
kWh)
=
0.00
0.00
0.00
Overhead
(
mills/
kWh)
0.004
0.032
Given
below
Labor
varies
with
usage
(
not
with
boiler
size);
overhead
at
60%
of
labor
&
maintenance.
Hence
use:

Labor
(
mills/
kWh)
=
1.15*
12*
CF*
8760*
1000
/
MW*
1000*
8760*
CF
Overhead
(
mills/
kWh)
=
0.6
[
1000/
8760*
fixed
O&
M($/
kW­
Yr)
+
labor(
mills/
kWh)]