Document ID: EPA-HQ-OAR-2002-0056-0073
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-01-29T05:00Z

EMISSION
CONTROL
TECHNOLOGIES
FOR
COAL­
FIRED
POWER
PLANTS
Ravi
K.
Srivastava
and
Frank
Princiotta
Air
Pollution
Prevention
and
Control
Division
National
Risk
Management
Research
Laboratory
Office
of
Research
&
Development
U.
S.
Environmental
Protection
Agency
January
16,
2004
2
What
We'll
Cover
Today
.
.
.

°
Electric
power
industry
°
Pollutant
emissions
°
Control
technologies
3
Electric
Power
Industry
°
$
250
billion
in
annual
electricity
sales
in
2002;
likely
to
have
annual
sales
between
$
250
and
$
270
billion
in
2010
to
2015
°
Industry
operates
16,500
units
and
5,700
plants
°
There
are
3,100
electric
utilities,
2,800
IPPs,
230
IOUs,
and
2,000
publicly
owned
utilities
°
The
industry
employs
362,000
people
°
In
the
last
five
years,
we
have
seen
industry
spend
$
88
billion
in
new
power
plant
investments
4
Oil
&
Natural
Gas
20%

Nuclear
20%
Hydro
7%
Other
3%
Coal
50%
Electricity
Generation
Electric
Generation
in
2002
Historical
&
Projected
Electric
Generation
Source:
2002
and
historical
generation
is
from
EIA's
Annual
Energy
Review.
Projected
generation
is
from
EPA's
Integrated
Planning
Model.

Total
Generation
=
3,858
billion
kWhs
­
1,000
2,000
3,000
4,000
5,000
1970
1980
1990
2000
2010
2020
Billion
kWh
Coal
Oil/
Gas
Nuclear
Hydro
Other
5
Source:
EEI
6
Coal­
Fired
Power
Plants
°
There
are
about
530
power
plants
with
305
GW
of
capacity
that
consist
of
about
1,300
units.

°
Coal
plants
generate
the
vast
majority
of
power
sector
emissions:

­
100%
Hg
­
95%
SO2
­
90%
of
NOx
7
NOx
Emissions
­
5
10
15
20
25
30
1970
1980
1990
2000
2010
2020
SO2
Emissions
­
5
10
15
20
25
30
35
1970
1980
1990
2000
2010
2020
Emissions
of
SO2
&
NOx
Source:
EPA
Million
Tons
Million
Tons
Power
Sector
Power
Sector
Power
Sector
Power
Sector
All
Other
Sources
All
Other
Sources
8
Emissions
of
Mercury
Source:
EPA
1999
Mercury
Emissions
Power
Sector
40%

Other
60%
47.9
Tons
72.4
Tons
2020
Mercury
Emissions
w/
o
further
controls
Power
Sector
35%

Other
65%
44.9
Tons
82.6
Tons
9
°
Emissions
reductions
possible
through:

 
Emissions
control
technologies
 
Advanced
power
generation
technologies
 
Power
plant
upgrading
options
 
Fuel
switching
°
Focus
on
emissions
control
technologies
Pollutant
Reduction
10
NOx
Control
Technologies
°
Primary
 
reduce
the
NOx
produced
in
the
primary
combustion
zone.

 
Widely
used
­
low
NOx
burners
(
LNBs)
and
overfire
air
(
OFA)

°
Secondary
­
reduce
the
NOx
already
present
in
the
flue
gas
 
Widely
used
­
reburning,
selective
non­
catalytic
reduction
(
SNCR),
and
selective
catalytic
reduction
(
SCR)
11
Low
NOx
Burners
°
Limit
NOx
formation
by
delaying
complete
mixing
of
fuel
and
air
 
Reduced
oxygen
in
primary
flame
zone
 
Reduced
flame
temperature
 
Reduced
residence
time
at
peak
temperature
°
Can
provide
reductions
in
excess
of
50%
12
Overfire
Air
°
5
to
20%
of
the
total
combustion
air
is
injected
through
ports
located
downstream
of
the
top
burner
level
 
Burners
operate
at
lower
than
normal
air­
to­
fuel
ratio
resulting
in
NOx
control,
OFA
added
to
achieve
complete
combustion
 
Can
be
used
with
LNB
to
increase
NOx
reduction
by
10
to
25%
13
Reburning
°
Reburn
fuel
(
natural
gas,
coal,

other
fuels)
is
injected
to
provide
15­
25%
of
total
heat
input
°
>
50%
NOx
reduction,

mercury
and
SO2
reduction
°
Low
capital
costs
°
Fuels
costs,
availability
of
adequate
residence
time
°
Applications:
cyclone,
wall,

tangential;
33­
600
MWe
Main
fuel
and
air
Reburn
zone
Burning
zone
Flue
gas
Superheaters
Reburn
air
Reburn
fuel
Main
fuel
and
air
14
SNCR
°
Urea
or
NH3
injection,

generally
between
980
to
1150
oC
°
30
to
60
%
NOx
reduction
°
Low
capital
costs
°
Load
following,
NH3
slip,

performance
on
larger
boilers
°
Applications:
cyclone,

wall,
tangential;
50­
620
MW
Burning
zone
Flue
gas
Superheaters
Reagent
Main
fuel
and
air
15
SCR
°
NH3
injection,
generally
between
350­
400
oC
°
More
than
90
%
reduction
is
possible,
especially
with
LNB
°
Capital
intensive,
space
requirements,
NH3
slip,

SO3
emissions,
catalyst
deactivation
°
Applications:

 
More
than
75
boilers;

cyclone,
wall,
tangential;

122
­
1300
MW
16
SO2
Control
Technologies
Limestone
Forced
Oxidation
Limestone
Inhibited
Oxidation
Lime
Magnesium­
Enhanced
Lime
Seawater
Wet
Lime
Spray
Drying
Duct
Sorbent
Injection
Furnace
Sorbent
Injection
Circulating
Fluidized
Bed
Dry
Throwaway
Sodium
Sulfite
Magnesium
Oxide
Sodium
Carbonate
Amine
Wet
Activated
Carbon
Dry
Regenerable
Flue
Gas
Desulfurization
Limestone
Forced
Oxidation
Limestone
Inhibited
Oxidation
Jet
Bubbling
Reactor
Lime
Magnesium­
Enhanced
Lime
Dual
Alkali
Seawater
Wet
Lime
Spray
Drying
Furnace
Sorbent
Injection
LIFAC
Economizer
Sorbent
Injection
Duct
Sorbent
Injection
Duct
Spray
Drying
Circulating
Fluidized
Bed
Hypas
Sorbent
Injection
Dry
Once­
through
Sodium
Sulfite
Magnesium
Oxide
Sodium
Carbonate
Amine
Wet
Activated
Carbon
Dry
Regenerable
Flue
Gas
Desulfurization
17
Wet
Scrubbers
FGD
at
Centralia
Power
Plant
°
State­
of­
the­
art
is
95%

SO
2
removal
°
98
GW
(
33%)
of
coal­
fired
units
have
scrubbers
°
We
project
115
GW
to
have
scrubbers
by
2010
for
Title
IV
and
State
regs
18
Flue
Gas
In
Slurry
In
Recycle
Tank
Recycle
Loop
Disposal
Flue
Gas
Out
Lime
Spray
Drying
°
State
of
the
art
is
90%

removal
°
More
than
14
GW
of
installation
19
Performance
50
60
70
100
90
80
Wet
Limestone
Spray
Drying
1970s
1980s
1990s
Median
Design
SO2
Removal
Efficiency,

%

0
20
>
2500
°
C
Hg
°
APCD
Inlet
Entrained
PM
CO
2
H
2
O
SO
2
NO
x
HCl
N
2
Hg
Coal
Mercury
Speciation:
300
°
F
Hgo,
Hg2+
compounds,
particulate
mercury
Hg(
p)

Mercury
in
Coal­
fired
Boilers
21
Mercury
Speciation
°
In
general,
speciation
depends
on:

 
Coal
properties
(
mercury,
chlorine,
and
ash
contents)

 
Time/
temperature
profile
 
Flue
gas
composition
and
fly
ash
characteristics
(
carbon,
calcium,
iron,
porosity)

 
Flue
gas
cleaning
conditions
22
Mercury
Capture
in
Existing
Equipment
Removal
in
PM
Controls
°
Mercury
can
be
adsorbed
onto
fly
ash
surfaces;
Hg2+
is
more
readily
adsorbed
than
Hg0
°
Mercury
can
be
physically
adsorbed
at
relatively
lower
temperatures
(
hot­
side
ESP
vs.
cold­
side
ESP)

Capture
in
Wet
Scrubbers
°
Hg2+
capture
depends
on
solubility
of
each
compound;

Hg0
is
insoluble
and
cannot
be
captured
°
Capture
enhanced
by
SCR
23
ICR
Data
0
20
40
60
80
100
Hg
Removal
(%)
Bituminous
Subbituminous
°
Bituminous
vs
subbituminous
°
Hg
capture
for
different
coal­
control
technology
combinations
correlate
with
coal
chlorine
content
24
Chlorine
vs.
Mercury
Speciation
°
ICR
data
for
Hg0
at
ESP
&
FF
inlet
°
Hg0
oxidation
appears
to
be
independent
of
chlorine
above
100
µ
g/
g
°
Other
important
factors
 
Temperature
 
Fly
ash
carbon
0%
20%
40%
60%
80%

100%
10
100
1,000
10,000
Coal
Chlorine,
ppm
dry
%

Hg0
at
PCD
Inlet
Cold­
side
ESP
&
FF
Hot­
side
ESP
25
°
Speciation
influences
emissions
control
 
Ionic
Hg2+
is
removed
easily
by
wet
scrubbers
 
Volatile
elemental
Hg0
is
difficult
to
capture
°
SCR
units
are
being
used
extensively
to
meet
current
NOx
regulations
°
SCR
can
convert
elemental
mercury
in
coal
combustion
flue
gas
into
the
ionic
form
 
field
data
in
Europe
and
U.
S.
reflects
increase
in
Hg2+
across
SCR
reactor
SCR
and
Mercury
Interactions
26
SCR­
Mercury
R&
D
°
Tested
4
utility
plants
in
the
2001
and
2
in
2002;
retested
2
plants
in
2002;

total
of
8
data
points
°
Oxidized
mercury
increase
across
SCR:
bit.
­
up
to
71%;
subbit.
­
10%
(
one
data
point
only)

°
Removal
in
PM
control
and
FGD
(
5
data
points)
­
~
85%
­
90%

°
Results
from
repeated
tests
were
consistent
with
previous
data;
impacts
of
SCR
catalyst
aging
not
apparent
°
SCR
systems
with
relatively
lower
catalyst
volumes
(
space
velocity
greater
than
3500
hr­
1)
also
showed
significant
oxidation
increases
°
Data
gaps:
PRB,
blends
°
Ongoing
EPA
bench­
and
pilot­
scale
research:
HCl
provides
critical
chlorine
source
for
Hg0
oxidation;
NOx
has
a
significant
promotional
effect;
SO
x
has
little
effect
under
the
conditions
of
this
study
27
PM
Control
Technologies
for
Power
Plants
°
Electrostatic
precipitators
(
ESPs)

 
72%
of
U.
S.
coal­
fired
boilers,
total
PM
up
to
99.9%,
fine
PM
80­
95%

°
Baghouses
 
14%
of
U.
S.
coal­
fired
boilers,
total
PM
up
to
99.9%,
fine
PM
99­
99.8%
28
Sometimes
a
picture
is
worth
a
 
29
How
Does
an
ESP
Work?

Corona
(
Negative
polarity)

Particulate
Matter
(
PM)
Discharge
Electrode
(
High
Voltage
Wire)

Collection
Plate
(
Positive
Polarity)

Particle
Flow
Charged
Particles
Collected
Particles
Dust
Layer
30
Emerging
Technologies
31
Sorbent
Injection
°
The
extent
of
capture
depends
on:

 
Sorbent
characteristics
(
particle
size
distribution,

porosity,
capacity
at
different
gas
temperatures)

 
Residence
time
in
the
flue
gas
 
Type
of
PM
control
(
FF
vs.

ESP)

 
Concentrations
of
SO
3
and
other
contaminants
Flue
Gas
Ash
and
Sorbent
Sorbent
Injection
ESP
or
FF
32
Activated
Carbon
Injection
(
ACI)

Activated
carbon
injection
system
Activated
carbon
storage
and
feed
system
°
ACI
successfully
used
to
reduce
mercury
emissions
from
waste­

toenergy
facilities.
Effort
underway
to
transfer
to
coal­
fired
power
plants.

°
Not
currently
installed
at
any
power
plant,
but
short­
term
testing
suggests
it
may
eventually
be
able
to
achieve
90%
control
for
all
coal
types.
33
Carbon
Injection
Projects
°
Alabama
Power
E.
C.
Gaston:
unit
3,
270­
MW,
low­
sulfur
eastern
bit.

coals
(
0.14
ppm
Hg
and
160
ppm
Cl);
hot­
side
ESP,
COHPAC
baghouse;

testing
on
one­
half
of
the
gas
stream,
nominally
135
MW;
wet
ash
to
pond
°
WEPCO
Pleasant
Prairie:
unit
2,
600­
MW,
PRB
coal
(
0.11
ppm
Hg
and
8
ppm
Cl);
ESP
(
468
ft2/
kacfm),
spray
cooling,
SO
3
conditioning;
testing
on
one
ESP
chamber
(
1/
4
of
the
unit);
fly
ash
sold
for
use
in
concrete
°
PG&
E
Brayton
Point:
unit
1,
245­
MW,
low­
S
bit.
coal
(
0.03
ppm
Hg
and
2000­
4000
ppm
Cl);
SO
3
conditioning
system;
2
ESPs
in
series
(
550
ft2/
kacfm);
PAC
injection
between
the
ESPs
°
PG&
E
Salem
Harbor:
85­
MW,
low­
S
bit.
coal
(
0.03­
0.08
ppm
Hg
and
206
ppm
Cl);
ESP
(
474
ft2/
kacfm);
SNCR
34
Mercury
Removal
Trends
with
ACI
0
20
40
60
80
100
0
5
10
15
20
25
30
Injection
Concentration
(
lb/
MMacf)

Mercury
Removal
(%)
Brayton
Point
PPPP
Gaston
Source:
ADA
Environmental
Solutions
(
2003)
35
PG&
E
Salem
Harbor
(
w/
o
PAC
Injection)

°
85­
MW,
low­
S
bit.
coal
(
0.03­
0.08
ppm
Hg
and
206
ppm
Cl);
ESP
(
474
ft2/
kacfm);
SNCR
°
High
baseline
removal
due
to
high
levels
of
LOI;
minimal
impact
on
reducing
LOI
from
30­
35%
to
15­

20%
at
300
oF
°
Temperature
has
greater
effect
than
LOI
°
SNCR
has
no
impact
on
Hg
removal
Source:
ADA­
ES
0
10
20
30
40
50
60
70
80
90
100
270
290
310
330
350
370
17­
19%
LOI
(
45
lb/
M
Macf)

20­
24%
LOI
(
55
lb/
M
Macf)

25­
29%
LOI
(
68
lb/
M
Macf)

>
30%
LOI
30­
35%
LOI,
C1,
High
Load
21­
27%
LOI,
C2,
High
Load
LS
bitum
coal
Hg
Removal
(%)
Temperature
(
oF)
36
PG&
E
Salem
Harbor
(
w/
PAC
Injection)

°
At
lower
temperatures,

removal
by
PAC
affected
by
high
baseline
removal
°
At
higher
temperatures,

linear
behavior
(
similar
to
that
at
Brayton
Point
0
10
20
30
40
50
60
70
80
90
0
5
10
15
20
25
280­
290
F
298­
306
F
322­
327
F
343­
347
F
Source:
ADA­
ES
Hg
Removal
(%)
Injection
Concentration
(
lb/
106
acf)
37
A
few
more
things
.
.
.
38
Wet
FGD
Modification
°
Capable
of
removing
SO2
in
excess
of
95
%

°
Can
remove
oxidized
Hg
°
Three
routes
for
NO
removal:

 
gas
phase
oxidation
to
N2O5
 
oxidation
to
NO2
and
reduction
to
N2
in
the
scrubber
via
sulfate
and
bisulfate
ions
°
Investigate
SO2,
Hg,
NOx
removal
and
SO2
to
SO3
conversion
39
ESFF
°
Electrostatically
Stimulated
Fabric
Filtration
(
ESFF)­­
developed
by
EPA
°
Pulsejet
fabric
filter
with
high
voltage
electrodes
centered
between
groups
of
four
bags
°
Pilot­
scale
performance
data:

 
PM2.5
with
ESFF=
0.14
mg/
m3
 
PM2.5
without
ESFF=
0.51
mg/
m3
 
PM1
with
ESFF=
0.05
mg/
m3
 
PM1
without
ESFF=
0.17
mg/
m3
°
BHA
Group,
Inc.
licensee
has
developed
preliminary
commercial
design
40
Development
of
Multipollutant
Sorbents
°
Sorbent
Development
 
Synthesis,
Characterization,

Evaluation
&

Optimization
 
Relate
structure
and
chemical
nature
to
adsorption
characteristics
0
20
40
60
80
100
120
140
160
A
m
o
u
n
t
A
d
s
o
r
b
e
d
NO2
SO2
Hg
Pollutant
Capture
Capacity
of
Various
Sorbents
A­
Clay
K­
Clay
Act
C
Lime
ox­
CSH
NO2
and
SO2
capacity
given
as
mg/
g
adsorbed
in
1
hr
at
80
 
C;

Hg
0
capacity
given
as
µ
g/
g
adsorbed
in
1
hr
at
80
 
C
°
Types
of
Sorbents
Being
Studied
 
Sorbents
synthesized
using
industrial
by­
products
 
Modified
carbon­
type
sorbents
 
Surface
modified
Calcium
Silicate
Hydrate
(
C­
S­
H)

 
Multipollutant
sorbents
that
also
have
adsorptive
capacity
for
CO
2