TO:
Jeffrey
Cole,
RTI
International
FROM:
Clark
Allen,
RTI
International
DATE:
December
2003
SUBJECT:
Mercury
Emission
Estimates
for
Coal­
fired
Power
Plants
The
purpose
of
this
memorandum
is
to
explain
the
basis
of
the
mercury
(
Hg)
air
emission
estimates
from
the
coal­
fired
power
plant
units.
These
emission
estimates
are
then
used
to
determine
the
need
for
additional
air
emission
controls
in
order
for
the
plant
to
comply
with
the
regulatory
requirements.

Are
all
coal
fired
power
plant
units
included
in
the
estimates?

Certain
co­
generation
facilities
are
excluded
on
the
basis
of
the
fraction
of
power
used
on­
site
and
the
capacity
of
the
unit.
Coal­
fired
electric
utility
units
of
less
than
25
MWe
capacity
are
excluded
from
the
scope
of
the
regulation.
Other
than
these
excluded
units,
all
coal­
fired
electric
utility
units
are
included,
as
well
as
units
that
combust
supplemental
fuels
such
as
petroleum
coke
and
tire
derived
fuel
(
TDF).

What
was
calculated?

The
total
enthalpy
(
Btu)
of
the
fuel
combusted
in
the
utility
unit
for
the
year
1999
was
calculated
from
the
reported
fuel
rate
and
the
reported
heat
content
of
the
fuel.
The
total
amount
of
Hg
in
the
fuel
that
was
combusted
in
the
utility
unit
for
the
year
1999
was
calculated
from
the
reported
fuel
rate
and
the
reported
Hg
concentration
in
that
fuel.
The
plant
average
Hg
content
for
that
type
of
fuel
was
assumed
for
those
months
without
reported
Hg
fuel
concentrations.
The
emission
factor
for
the
utility
unit
was
obtained
by
identifying
a
similar
type
of
unit
in
the
test
data
set.
The
Hg
removal
in
that
similar
type
of
tested
unit
was
used
to
estimate
the
Hg
control
for
the
utility
unit.
The
emission
factor
and
the
total
amount
of
Hg
in
the
fuel
was
used
to
estimate
the
amount
of
Hg
that
was
discharged
from
the
stack
of
the
utility
unit
in
1999.
The
ratio
of
the
pounds
of
Hg
discharged
from
the
stack
to
the
total
heat
content
of
the
fuel
burned
in
the
unit
was
calculated
as
the
Hg
rate,
with
the
units
of
lb
Hg/
TBtu.
For
the
case
that
a
plant
had
multiple
coal­
fired
units,
the
total
Hg
rate
for
all
of
the
plant
units
were
obtained
by
calculating
the
total
plant
Hg
(
lb)
and
the
total
plant
energy
(
TBtu).
The
plant
Hg
rate
was
obtained
as
the
ratio
of
2
those
two
totals
(
lb/
TBtu).
This
Hg
rate
was
compared
to
the
MACT
regulatory
requirement,

and
emissions
greater
than
the
regulatory
requirement
were
identified.

What
was
the
source
of
the
data?

There
were
two
data
sets
that
were
used
in
this
emission
estimation
procedures:

°
reported
data.
Each
coal­
fired
electric
utility
unit
that
had
a
capacity
greater
than
25
MWe
reported
1999
data
for
coal
use
and
composition
for
the
unit.
The
data
were
processed
and
stored
in
a
master
central
data
base.
The
software
for
examining
the
data
base
and
estimating
the
air
emissions
was
provided
to
the
public.
Comments
about
the
data
base
were
used
for
correcting
and
updating
this
data
base.

°
test
data.
A
series
of
80
emission
tests
were
conducted
at
coal­
fired
electric
utility
units.
Most
of
the
units
that
were
tested
were
tested
with
three
independent
measurements
of
Hg
removal
by
the
control
device.
The
results
of
these
tests
were
used
to
evaluate
the
performance
of
different
types
of
air
emission
controls
for
the
purpose
of
estimating
the
amount
of
Hg
removal
that
occurred
in
1999.

How
was
the
Hg
removal
from
existing
air
emission
controls
determined?

Emission
factors
were
determined
from
the
test
data.
The
total
Hg
in
the
flue
gas
was
measured,
and
a
summation
of
the
Hg
was
partitioned
in
three
phases
(
particulate­
bound,
ionic,

and
elemental).
The
emission
factor
was
based
on
the
fraction
of
the
total
Hg
that
remained
in
the
flue
gas
after
the
control
device.
In
the
case
of
multiple
air
emission
controls
in
series,
the
fractional
removal
of
Hg
by
each
control
was
assumed
not
to
be
influenced
by
the
other
controls.

How
was
the
MACT
floor
requirements
determined
for
each
unit?

First
the
regulatory
requirements
were
obtained
from
the
MACT
floor
analysis.
These
requirements
are
shown
below
as
MACT
floor
limits.
The
estimated
Hg
rate
(
lb/
TBtu)
was
compared
to
the
regulatory
requirements
for
the
specific
coal
type.
If
the
estimated
Hg
rate
from
a
unit
was
greater
than
the
regulatory
requirement,
then
it
was
assumed
that
the
unit
would
require
additional
air
emission
control
to
reduce
the
unit
emissions
to
the
regulatory
requirements.
3
Regulatory
Requirements
in
this
Analysis
Fuel
Type
MACT
Floor
Limit*

Bituminous
2.0
lb/
TBtu
Subbituminous
5.8
lb/
TBtu
Lignite
9.2
lb/
TBtu
Coal
refuse
0.38
lb/
TBtu
IGCC
(
Coal
gas)
19
lb/
TBtu
*
These
limits
were
determined
after
applying
variability
as
described
in
the
memorandum
titled,
MACT
Floor
Analysis
for
Coal­
and
Oil­
Fired
Electric
Utility
Steam
Generating
Units
National
Emission
Standards
for
Hazardous
Air
Pollutants"
and
then
rounding
the
results
to
2
significant
digits.

What
if
a
unit
burned
two
types
of
coal
with
different
MACT
floor
requirements
for
each
type?

In
the
case
of
multiple
types
of
fuels
in
the
same
unit
at
different
times,
a
fuel
massweighted
average
of
the
regulatory
requirement
for
each
fuel
type
was
calculated.
The
regulatory
requirement
was
this
composite
weighted
average.
In
the
case
of
combined
types
of
fuels
in
the
same
unit
at
the
same
time,
the
heat
content
of
the
fuel
was
used
to
determine
the
fraction
of
the
different
types
of
fuel
that
was
combusted.
Then,
a
fuel
mass­
weighted
average
was
used
to
determine
the
composite
regulatory
requirement.

The
following
heat
contents
(
BTU/
lb)
were
used
for
the
fuel
types:

°
bituminous
12,250
Btu/
lb,
°
subbituminous
9,900
Btu/
lb,
and
°
lignite
7,300
Btu/
lb.

Fuel
mixtures
with
a
heat
content
greater
than
that
of
the
bituminous
specification
were
assumed
to
be
bituminous.

What
additional
information
was
obtained
from
the
data
base?

In
addition
to
the
calculated
quantities,
the
following
information
was
provided
in
the
report,
as
obtained
from
the
data
base:

°
name
of
the
unit
°
name
of
the
plant
°
type
of
fuel(
s)
°
quantity
of
fuel
burned
°
type
of
NO
x
control
°
type
of
sulfur
control
°
type
of
particulate
control
4
°
capacity
of
the
unit
°
is
the
unit
a
cogeneration
unit?

How
many
units
should
have
additional
air
emission
control?

Not
all
units
require
additional
air
emission
controls
to
meet
the
regulatory
requirements.

The
following
list
illustrates
the
distribution
of
units
that
require
additional
control
or
changes
to
existing
controls.
Units
not
requiring
additional
control
are
also
shown.

Regulatory
Requirements
for
Fuels
in
this
Analysis
Fuel
Type
MACT
Floor
Limit*
Need
More
Control,
No.
of
units**
More
Control
Not
Needed,
No
of
units**

Bituminous
2.0
lb/
TBtu
549
152
Subbituminous
5.8
lb/
TBtu
68
168
Lignite
9.2
lb/
TBtu
5
19
Coal
Refuse
0.38
lb/
TBtu
3
14
IGCC
(
Coal
Gas)
19
lb/
TBtu
0
2
Blended
Coals
Individual
Composite***
94
44
*
These
limits
were
determined
after
applying
variability
as
described
in
the
memorandum
titled,
MACT
Floor
Analysis
for
Coal­
and
Oil­
Fired
Electric
Utility
Steam
Generating
Units
National
Emission
Standards
for
Hazardous
Air
Pollutants"
and
then
rounding
the
results
to
2
significant
digits.
**
The
total
number
of
coal­
fired
electric
utility
units
in
the
last
two
columns
of
this
table
total
to
1,118
not
the
industry
total
of
1,143.
This
difference
is
due
to
25
units
firing
no
coal
in
1999.
***
Depending
on
the
proportion
of
each
coal
type
burned
this
number
would
vary.
Thus,
it
is
a
blended
MACT
Floor
limit.

Are
regulatory
requirements
used
for
each
unit
or
each
plant?

The
emission
estimates
described
her
are
based
on
each
unit
in
the
database.
If
plant
totals
are
desired,
aggregated
limits
and
emissions
can
be
obtained
for
each
plant.

What
was
the
format
of
the
emission
estimates?

The
calculated
values,
along
with
the
additional
information
from
the
data
base,
were
placed
in
an
electronic
spreadsheet.
The
format
for
this
spreadsheet
was
designed
to
facilitate
the
determination
of
the
cost
of
additional
controls.
