TO:
Bill
Maxwell,
U.
S.
Environmental
Protection
Agency,
OAQPS
(
C439­
01)

FROM:
Jeffrey
Cole,
RTI
International
DATE:
December
2003
SUBJECT:
Beyond­
the­
floor
analysis
for
existing
and
new
coal­
and
oil­
fired
electric
utility
steam
generating
units
national
emission
standards
for
hazardous
air
pollutants
This
memorandum
describes
the
development
of
the
beyond­
the­
floor
analysis
for
existing
and
new
coal­
and
oil­
fired
electric
utility
steam­
generating
units
National
Emission
Standard
for
Hazardous
Air
Pollutants
(
NESHAP).
In
this
memorandum,
we
considered
available
regulatory
options
(
i.
e.,
technologies
or
work
practices)
that
were
more
stringent
than
the
MACT
floor
level
of
control
for
each
of
the
different
subcategories
that
make
up
the
Electric
Utility
source
category.

OUTLINE
1.0
Introduction
2.0
Beyond­
the­
floor
Options
for
Existing
Coal­
and
Oil­
fired
Electric
Utility
Steam
Generating
Units
2.1
Coal­
fired
Units
2.2
Integrated­
coal
Gasification
Combined
Cycle
Units
2.3
Coal
Refuse­
fired
Units
2.4
Oil­
fired
Units
3.0
Beyond­
the­
floor
Options
for
New
Coal­
and
Oil­
fired
Electric
Utility
Steam
Generating
Units
3.1
Coal­
fired
Units
3.2
Integrated­
coal
Gasification
Combined
Cycle
Units
3.3
Coal
Refuse­
fired
Units
3.4
Oil­
fired
Units
2
1.0
INTRODUCTION
As
discussed
in
the
memorandum
entitled
"
MACT
Floor
Analysis
for
Coal­
and
Oil­
Fired
Electric
Utility
Steam­
Generating
Units
National
Emission
Standards
for
Hazardous
Air
Pollutants,"
the
EPA
chose
to
set
MACT
for
mercury
(
Hg)
from
existing
and
new
coal­
fired
electric
utility
steam­
generating
units
and
nickel
(
Ni)
from
existing
and
new
oil­
fired
electric
utility
steam­
generating
units.
Therefore,
this
discussion
addresses
beyond­
the­
floor
control
options
for
existing
or
new
units.

2.0
BEYOND­
THE­
FLOOR
OPTIONS
FOR
EXISTING
COAL­
AND
OIL­
FIRED
ELECTRIC
UTILITY
STEAM
GENERATING
UNITS
In
order
to
determine
possible
beyond­
the­
floor
control
options
for
existing
units,
we
analyzed
all
available
emissions
data
on
air
pollution
control
devices
(
APCD)
that
are
currently
utilized
or
experimental
(
both
full­
size
and
pilot­
scale).
The
following
are
the
possible
beyond­
the­
floor
control
options
for
existing
units.

2.1
Coal­
fired
Units
Conventional
PM
controls
(
electrostatic
precipitators
[
ESP]
and
fabric
filters)
generally
do
not
remove
the
vapor­
phase
HAP
(
i.
e.,
elemental
Hg,
hydrochloric
acid
[
HCl],
and
hydrogen
fluoride
[
HF])
from
coal­
fired
unit
emissions.
This
is
because
these
controls
do
not
effectively
capture
gaseous
pollutants.
Two
technologies
that
possibly
could
be
used
to
further
reduce
the
amount
of
vapor­
phase
HAP
emitted
from
utilities
are
sorbent
injection
and
selective
catalytic
reduction
(
SCR).
1
2.1.1
Sorbent
injection.
Due
to
their
multiple
internal
pores
and
high
specific
surface
area,
sorbents
have
the
potential
to
improve
the
removal
of
Hg
(
mostly
through
the
capture
of
elemental
mercury
(
Hg0;
sorbents
will
also
remove
Hg++)
as
well
as
other
gaseous
pollutants
that
are
carried
with
combustion
fine
particulates
in
all
coal­
fired
subcategories
(
except
for
integrated
gasification
combined
cycle
[
IGCC]
units
because
of
their
lack
of
external
PM
control
device).
3
The
extent
of
the
potential
Hg
removal
is
dependent
on:
(
1)
efficient
distribution
of
the
sorbent
(
e.
g.,
activated
carbon)
in
the
flue
gas;
(
2)
the
amount
of
sorbent
needed
to
achieve
a
specific
level
of
Hg
removal,
which
will
vary
depending
on
the
fuel
being
burned;
(
3)
the
amount
of
chlorine
(
Cl)
present
in
the
fuel;
and
(
4)
the
type
of
PM
control
device
(
e.
g.,
at
a
given
sorbent
feed
rate,
a
fabric
filter
provides
more
Hg
control
than
an
ESP
because
of
the
additional
adsorption
that
occurs
on
the
bags
of
the
fabric
filter
because
of
the
increased
gas
contact
time).

Sorbents
can
be
introduced
by
two
basic
methods:
by
channeling
flue
gas
through
a
bed
of
sorbent
or
by
direct
sorbent
injection.
Sorbent
bed
designs
consist
of
fixed­
sorbent
filter
beds,

moving
beds,
or
fluidized
sorbent
filter
beds.
With
direct
sorbent
injection,
after
sorbent
is
introduced
into
the
flue
gas,
it
adsorbs
Hg
and
other
contaminants
and
is
captured
downstream
in
an
existing
or
sorbent­
specific
PM
control
device.
The
types
of
sorbent
that
may
be
viable
in
sorbent
injection
include
two
basic
types
of
activated
carbon
(
AC;
regular
and
impregnated)
as
well
as
other
carbon
(
mixed
with
other
sorbents)
and
noncarbon
sorbents.

Activated
carbon
is
a
specialized
form
of
carbon
produced
by
pyrolyzing
coal
or
various
hard,
vegetative
materials
(
e.
g.,
wood)
to
remove
volatile
material.
The
resulting
carbon­
based
material
(
char)
then
undergoes
a
steam
or
chemical
activation
process
to
produce
an
AC
that
contains
multiple
internal
pores
and
has
a
very
high
specific
surface
area.
With
this
internal
pore
structure,
the
AC
can
adsorb
a
broad
range
of
contaminants.
Various
studies,
shown
in
Table
1,

have
shown
good
to
excellent
Hg
removal
with
the
injection
of
AC
(
particularly
on
bituminous­
fired
units);
however,
other
studies
(
also
shown
in
Table
1)
have
not
shown
good
Hg
removal
(
particularly
on
subbituminous­
and
lignite­
fired
units).
The
Hg
removal
performance
of
AC
injection
seems
to
be
highly
dependent
on
coal
rank
and
composition
(
i.
e.,
Hg
and
Cl
content
of
the
coal)
and
specific
utility
plant
configuration
(
e.
g.,
sequencing
of
APCD
equipment).

Further,
little
long­
term
data
are
available.

Chemically
impregnated
AC
is
AC
that
has
been
supplemented
with
chemicals
to
improve
its
Hg
removal.
The
Hg
in
the
flue
gas
reacts
with
the
chemical
that
is
bound
to
the
AC,
and
the
resulting
compound
is
removed
by
the
PM
control
device.
Typical
impregnants
for
AC
are
chlorine,
sulfur,
and
iodide.
Chemically
impregnated
AC
has
shown
enhanced
Hg
removal
over
regular
AC.
Chemically
impregnated
AC
requires
smaller
rates
of
carbon
injection
than
does
regular
AC
for
equivalent
Hg
removals.
The
required
carbon­
to­
mercury
mass
ratio
may
be
4
reduced
by
a
factor
of
from
3
to
10
with
the
chemically
impregnated
AC.
2
The
cost
per
mass
unit
of
impregnated
AC
may,
however,
be
significantly
greater
than
that
of
unmodified
AC.

Other
commercially
available
sorbent
materials
are
Sorbalit
 
(
a
mixture
of
lime
with
additives
and
3
to
5
percent
AC)
and
Darco
FGD
(
an
AC
derived
from
lignite).
2
Zeolites
constitute
another
category
of
sorbent.
There
are
naturally
occurring
mineral
zeolites,
in
addition
to
commercially
available
synthetic
zeolites.
Both
types
contain
large
surface
areas
and
have
a
good
potential
for
Hg
removal.

The
AC
test
data
available
to
EPA,
representing
full­
scale
electric
utility
units,
consists
of
tests
taken
at
four
sites.
The
sites
had
initial
baseline
tests
conducted
without
AC
injection
in
2001,
and
parametric
tests
and
long­
term
test
programs
conducted
in
2002
and
2003
after
installation
of
AC
injection.
The
test
sites'
sampling
description,
coal
type,
control
device
configuration,
and
total
Hg
removal
(
both
the
maximum
Hg
removal
during
each
test
and
average
Hg
removal
during
the
entire
test
period)
are
listed
in
Table
1.
Even
though
these
tests
were
taken
over
an
extended
period
of
time,
the
summary
data
available
show
that
there
appears
to
be
variability
in
Hg
removal
results
between
the
maximum
Hg
removal
during
each
test
and
the
average
Hg
removal
during
the
entire
test
period
at
a
given
site.

Although
AC,
chemically
impregnated
AC,
and
other
sorbents
show
potential
for
improving
Hg
removal
over
what
is
achieved
with
conventional
PM
and
SO
2
controls,
this
technology
is
not
currently
available
on
a
commercial
basis
and
has
not
been
installed,
except
on
a
demonstration
basis,
on
any
electric
utility
unit
in
the
United
States
to
date.
Further,
limited
long­
term
data
(
e.
g.,
longer
than
a
few
days)
are
available
to
indicate
the
performance
of
this
technology
on
all
representative
coal
ranks
or
on
a
significant
number
of
different
power
plant
configurations.
Therefore,
these
technologies
do
not
provide
a
viable
basis
for
either
establishing
or
going
beyond
the
floor.

2.1.2
Selective
catalytic
reduction
(
SCR).
The
SCR
test
data
available
to
EPA,

representing
full­
scale
electric
utility
units,
consists
of
tests
taken
at
four
sites
in
2001,
two
of
the
original
four
sites
were
then
retested
in
2002,
and
finally
two
additional
sites
were
tested
in
2002,

for
a
total
of
eight
sets
of
data.
The
test
sites'
coal
type,
control
device
configuration,
and
total
Hg
removal
(
with
SCR
turned
off
and
SCR
operating)
are
listed
in
Table
2.
The
data
suggests
5
that,
although
designed
as
a
nitrogen
oxides
(
NO
x)
control
technology,
the
SCR
has
ability
to
transform
certain
species
of
Hg
into
other
speciated
forms
that
are
easier
for
conventional
PM
and
SO
2
controls
to
capture.
The
transformation
of
Hg
species
can
be
seen
most
prominently
when
an
SCR
is
operating
at
a
site
with
a
PM
control
device
and
a
wet
FGD
control
device
or
a
site
with
only
a
single
particulate
(
venturi)
scrubber.
The
Hg
emitted
during
combustion,
which
would
(
in
the
absence
of
the
SCR)
tend
to
remain
as
Hg0,
is
oxidized
to
Hg++.
The
highly
soluble
oxidized
Hg
is
then
removed
by
the
wet
FGD
or
particulate
(
venturi)
scrubber.
However,
this
Hg
reduction
effect
has
been
observed
in
limited
stack
testing
on
bituminous
coal­
fired
sites
(
S2
and
S4),
and
results
on
a
subbituminous
coal­
fired
site
have
not
been
uniformly
successful.
3
Sites
S1
and
S3
showed
only
minimal
Hg
oxidation
across
the
SCR.
To
EPA's
knowledge,
no
commercial­
scale,
lignite­
fired,
SCR­
equipped
unit
has
been
tested
to
date,
though
it
is
entirely
possible
that
greater
Hg
removal
would
result
when
applied
to
a
lignite­
fired
unit.
Similarly,
SCR
has
not
yet
been
tested
on
all
types
of
coal
sources
as
well
as
on
blends
of
coal.
It
should
be
noted
that
these
tests
were
of
short­
term
nature
and
the
maximum
Hg
removal
seen
may
not
represent
the
long­
term
average
observed
even
at
a
given
site.
Also,
the
data
show
that
SCR
does
not
lead
to
increased
Hg
oxidation
and
removal
in
all
cases
on
all
coal
ranks.

In
summary,
sorbent
injection
has
not
been
sufficiently
demonstrated
in
practice,
nor
have
long­
term
economic
considerations
(
e.
g.,
carbon
availability,
waste
disposal
issues,
and
required
permitting
for
new
waste
landfill
and
sludge
ponds)
been
evaluated
to
allow
sorbent
injection
to
be
considered
viable
as
a
beyond­
the­
floor
option.
With
regard
to
the
use
of
SCR,
there
is
inadequate
effectiveness
information
on
which
to
base
a
beyond­
the­
floor
standard.
6
Table
1.
Full­
scale
Activated
Carbon
Injection
Emission
Tests
at
Coal­
fired
Electric
Utility
Sites
Test
site,
Location
Description
of
test
plan
Coal
type
Control
device
Maximum
Hg
removal
during
each
test
Average
Hg
removal
during
the
entire
test
period
Alabama
Power,

Gaston4
Long­
term
tests
over
10
days,
constant
conditions,
are
scheduled
for
2002­
2003.
Bituminous
Hot­
side
ESP;
COHPAC
FF
S­
CEM:

°
90%
S­
CEM:

°
78%

Ontario­
Hydro:

°
90%
total
°
86%
oxidized
°
>
98%
elemental
WE
Energies,

Pleasant
Prairie5
Long­
term
tests
over
10
days,
constant
conditions.
Note:
The
S­
CEM
removal
efficiencies
shown
here
averages
and
maximums
taken
over
(
1)
three
days
with
an
average
injection
rate
of
1.6
lbs/
MMacf,
(
2)

four
days
with
an
average
injection
rate
of
3.7
lbs/
MMacf
and
(
3),
five
days
with
an
average
injection
rate
of
11.3
lbs/
MMacf.
Powder
River
Basin
Subbituminous
Cold­
side
ESP,
SCA
S­
CEM:

°
49%,
61%,
and
70%
S­
CEM:

°
47%,
57%,
and
66%

Ontario­
Hydro:

°
72.9%
total
°
74.5%
oxidized
°
70.7%
elemental
PG&
E
NEG
Salem
Harbor
Station3
Parametric
tests
and
long­
term
tests
in
Spring
2002.
Bituminous
Cold­
side
ESP;
SNCR
280­
290F:
68%,
70%

298­
306F:
67%,
75%,
78%

322­
327F:
65%,
85%,
85%

343­
347F:
25%,
45%
280­
290F:
69%

298­
306F:
73%

322­
327F:
78%

343­
347F:
35%

PG&
E
NEG
Brayton
Point
Station6
Parametric
tests
and
long­
term
tests
in
Fall
2002.
Bituminous
2
Cold­
side
ESP,
in
series
with
combined
SCA
Hg
capture
varied
based
on
sorbent
and
operating
conditions.
S­
CEM:

°
62%

COHPAC
­
combination
of
an
upstream
electrostatic
precipitator
followed
by
a
high
air­
to
cloth
ratio
fabric
filter
SCA
­
Specific
Collection
Area
S­
CEM
­
Semi­
Continuous
Emissions
Monitor
Ontario
Hydro
­
Ontario
Hydro
speciated
mercury
analysis
method
SNCR
­
Selective
Non­
Catalytic
Reduction
7
Table
2.
Full­
scale
SCR
Emission
Tests
at
Coal­
fired
Electric
Utility
Sites7
Site
Coal
Year
sampled
PM
Control
SO2
Control
Total
Hg
removal,
%
(
w/
SCR
off:
w/
SCR
on)

S1
Powder
River
Basin
Subbituminous
2001
ESP
None
60
/
78
S2
Ohio
Bituminous
2001
ESP
Wet
FGD
51
/
88
S2*
Ohio
Bituminous
2002
ESP
Wet
FGD
NA
/
84
S3
Pennsylvania
Bituminous
2001
ESP
None
16
/
13
S4
Kentucky
Bituminous
2001
Particulate
(
Venturi)
Scrubber
None
46
/
90
S4*
Kentucky
Bituminous
2002
Particulate
(
Venturi)
Scrubber
None
44
/
91
S5
West
Virginia
Bituminous
2002
ESP
Wet
FGD
51
/
91
S6
Kentucky
&
West
Virginia
Bituminous
2002
ESP
None
No
data
currently
available
*
Retest
NA
­
Not
analyzed
with
SCR
off.

2.2
IGCC
Units
Integrated
gasification
combined
cycle
units
are
specialized
units
in
which
coal
is
first
converted
into
synthetic
coal
gas.
In
this
conversion
process,
the
carbon
in
the
coal
reacts
with
water
to
produce
hydrogen
gas
and
carbon
monoxide
(
CO).
The
synthetic
coal
gas
(
syngas)
is
then
combusted
in
a
combustion
turbine,
which
drives
an
electric
generator.
Hot
gases
from
the
combustion
turbine
then
pass
through
a
waste
heat
boiler
to
produce
steam.
This
steam
is
fed
to
a
steam
turbine
connected
to
a
second
electric
generator.
Because
of
their
design,
IGCC
units
have
no
external
APCD.
Therefore,
we
believe
the
best
potential
way
of
reducing
Hg
emissions
from
existing
IGCC
units
is
to
remove
Hg
from
the
syngas
before
combustion.
An
existing
industrial
IGCC
unit
has
demonstrated
a
process,
using
sulfur­
impregnated
AC
carbon
beds,
that
has
proven
to
yield
90
to
95
percent
Hg
removal
from
the
coal
syngas.
8
This
technology
could
potentially
be
adapted
to
the
electric
utility
IGCC
units.
8
To
our
knowledge,
neither
of
the
two
existing
IGCC
units
have
run
tests
of
this
type
of
carbon
bed,
fuel
cleaning,
device.
Because
of
concerns
about
the
costs
involved
and
because
existing
IGCC
units
utilize
older
technology,
it
is
not
clear
if
using
sulfur­
impregnated
AC
carbon
beds
would
be
effective
on
the
particular
syngas
burned
in
these
units.

2.3
Coal
Refuse­
fired
Units
Coal
refuse
units
(
i.
e.,
99
percent
of
their
heat
input
supplied
by
burning
coal
refuse)
are
located
adjacent
to
old
coal
mine
refuse
piles.
The
units
are
specially
designed
to
burn
this
highash
silt.
All
of
the
13
coal
refuse­
fired
units
existing
in
1999
are
equipped
with
fluidized
bed
combustors
(
FBC);
10
of
these
13
units
inject
limestone
as
a
sorbent
for
SO
2
control,
and
4
of
these
13
units
are
equipped
with
SCR
for
NO
x
control.
The
only
two
coal
refuse­
fired
units
on
which
performance
tests
were
conducted
in
response
to
the
ICR
are
the
MACT
floor
facilities
for
the
coal­
refuse
fired
subcategory.

To
our
knowledge,
there
are
no
currently
available
technologies
that
could
be
used
as
beyond­
the­
floor
options
for
coal
refuse
units.

2.4
Oil­
fired
Units
The
only
emission
control
technology
that
we
are
aware
of
to
consider
as
a
beyond­
the­
floor
option
for
existing
oil­
fired
units
is
fabric
filtration.
Fabric
filters
have
been
shown
in
pilot­
scale
testing
to
be
more
effective
at
reducing
Ni
emissions
than
an
ESP.
However,

the
use
of
fabric
filters
on
oil­
fired
units
is
also
known
to
be
problematic
due
to
the
prevalence
of
the
"
sticky"
PM
emitted
from
such
units,
which
sticks
to
the
fabric
and
creates
a
fire
safety
hazard.
No
existing
oil­
fired
units
are
known
to
employ
fabric
filters
as
their
PM
control.

Because
of
this,
fabric
filters
are
not
considered
to
be
a
viable
beyond­
the­
floor
option
for
oilfired
units.

3.0
BEYOND­
THE­
FLOOR
OPTIONS
FOR
NEW
COAL­
AND
OIL­
FIRED
ELECTRIC
UTILITY
STEAM
GENERATING
UNITS
9
Once
the
MACT
floor
determinations
were
done
for
new
units
in
each
subcategory
(
by
fuel
type),
EPA
considered
various
regulatory
options
more
stringent
than
the
MACT
floor
level
of
control
(
i.
e.,
additional
technologies
or
other
work
practices
that
could
result
in
lower
emissions)
for
the
different
subcategories.
Due
to
the
technical
complexities
of
controlling
Hg
and
Ni
emissions
from
the
sources
affected
by
this
rule,
we
have
not
been
able
to
determine
whether
(
identified)
potential
beyond­
the­
floor
options
are
available.
The
following
describes
the
possible
beyond­
the­
floor
options
of
which
we
are
aware
for
new
units.

3.1
Coal­
fired
Units
As
discussed
in
Section
2
of
this
memorandum,
two
technologies
that
possibly
could
be
used
to
further
reduce
the
amount
of
vapor
phase
Hg
emitted
from
utilities
are
sorbent
injection
and
SCR.
However,
as
explained
in
Section
2,
sorbent
injection
is
not
available
on
a
commercial
basis
and
has
not
been
demonstrated
on
a
utility
unit
operating
at
full
capacity
over
an
extended
period
of
time.
Similarly,
SCR
has
not
shown
the
same
change­
in­
speciation
effect
on
Hg
emissions
on
all
types
of
coal
sources
(
and
among
different
seams
within
a
coal
rank).

3.2
IGCC
Units
Because
of
their
design,
IGCC
units
have
no
external
APCD
controls.
Therefore,
as
is
explained
in
Section
2
of
this
memorandum,
the
best
potential
way
of
improving
Hg
removal
from
IGCC
units
is
to
remove
the
Hg
from
the
syngas
before
combustion.
Based
on
published
information
regarding
the
industrial
IGCC
unit
noted
in
Section
2,
EPA
believes
that
a
90
percent
reduction
in
Hg
emissions
is
possible
from
new
IGCC
units
based
on
the
use
of
carbon
bed
technology.
Therefore,
we
believe
that
proposing
a
90
percent
Hg
reduction
based
on
the
use
of
carbon
bed
technology
as
a
beyond­
the­
floor
level
for
new
IGCC
units
is
reasonable.

3.3
Coal
Refuse­
fired
Units
Existing
coal
refuse­
fired
units
utilizing
100
percent
coal
refuse,
all
of
which
utilize
FBC
technology,
have
demonstrated
the
best
Hg
control
of
any
emissions­
tested
electric
utility
unit
in
the
industry
based
on
the
electric
utilities
information
collection
request
(
ICR).
10
3.4
Oil­
fired
Units
There
has
not
been
a
new
oil­
fired
unit
constructed
in
the
United
States
since
1981.
As
discussed
in
Section
2
of
this
memorandum,
if
a
new
oil­
fired
unit
is
constructed,
the
only
technology
that
would
offer
emissions
control
better
than
the
proposed
new
MACT
limits
for
emission
control
is
the
use
of
fabric
filtration;
however,
fabric
filtration
is
not
presently
considered
to
be
a
viable
control
option
for
oil­
fired
units
because
of
the
prevalence
of
the
"
sticky"
PM
emitted
from
these
units,
which
sticks
to
the
fabric
and
creates
a
fire
safety
hazard.
11
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Kilgroe,
James
D.,
Charles
B.
Sedman,
Ravi
K.
Srivastava,
Jeffrey
V.
Ryan,
C.
W.
Lee,
and
Susan
A.
Thorneloe.
"
Control
of
Mercury
Emissions
from
Coal­
fired
Electric
Utility
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Interim
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Chapter
5.
EPA­
600/
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01­
109.
December
2001.

2.
New
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1:
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and
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pp.
50­
52.
December
2001.

3.
Srivastava,
Ravi
K.
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21­
22,
2003,
Denver,
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C.
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3:
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May
2003,

pp.
31­
32.

5.
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2:
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into
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41005R12,

May
2003,
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27­
28.

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Scale
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Injection
for
Control
of
Mercury
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slide
show
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ADA
Environmental
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to
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MACT
Working
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8,
2002.
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E­
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Chu,
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C.
W.
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on
mercury
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fired
Power
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by
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&
Environmental
Research
Center
(
EERC)

University
of
North
Dakota.

8.
Rutkowski,
M.
G.,
M.
G.
Klett,
and
R.
C.
Maxwell.
"
The
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of
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Based
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27­
30,
2002,
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