Boiler Simulator Studies On Sorbent Utilization For So2 Control


United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-86/028 Jan  1987
Project  Summary
Boiler  Simulator   Studies
on  Sorbent  Utilization  for
S02   Control
B. J. Overmoe, L. Ho, S. L. Chen, W. R. Seeker, D. W. Pershing, and
M. P. Heap
  The objective of this program was to
provide process design information for sor-
bent utilization as applied to the LIMB pro-
cess.  Specifically,  the program  was
designed to investigate the role of boiler
thermal history, sorbent injection location,
calcium to sulfur molar ratio, and SO2
partial pressure on capture effectiveness
with limestones,  dolomites, and slaked
limes with and without metallic promoters.
The experimental studies were supported
by theoretical calculations using grain and
pore models that considered both the
heterogeneous chemical reaction and the
relevant diffusional processes.
  The experimental results and the sulfa-
tion model calculations indicate that the
sorbent injection  locations and  the
residence  time  within  the  sulfation
temperature window can significantly in-
fluence overall sulfur capture for any par-
ticular sorbent. Unless the sorbent is pro-
moted with a metal additive, downstream
injection at about 2250 °F* results in op-
timum sorbent utilization. Increasing the
gas-phase S02 concentration improves
sorbent utilization, but the dependence is
non-linear due to the combined effects of
intrinsic chemistry and diffusion.
  In general dolomitic sorbents perform
better than calcitic sorbents and hydrox-
ides are superior to carbonates. The true
influence of pressure slaking is unclear;
however, the best sorbents tested  were
the pressure slaked dolomites. The perfor-
mance of all sorbents can be enhanced by
adding appropriate metallic compounds in
relatively small quantities.
  This Project Summary was developed
by EPA's Air and Energy Engineering
Research Laboratory, Research Triangle
Park, NC, to announce key findings of the
research project that is fully documented
in a separate report of the same title (see
Project Report ordering information at
back).

Introduction
  This report describes experimental and
analytical work, the objective of which
was to provide process design information
for sorbent utilization as applied to the
EPA's Limestone  Injection  Multistage
Burner (LIMB) process. Specifically, the
program was designed to investigate the
role of boiler  thermal history, sorbent in-
jection location, calcium to sulfur molar
ratio, and S02 partial pressure on capture
effectiveness with limestones, dolomites,
and slaked limes with and without metallic
promoters. The experimental studies were
supported by theoretical calculations us-
ing grain and pore models that considered
both the heterogeneous chemical reaction
and the  relevant diffusional processes.
  All of the data presented in this report
were obtained with the 106 Btu/hr* Boiler
Simulator Furnace (BSF). The facility con-
sisted of a refractory-lined vertical tower
section 18 ft* tall with an ID of 1.8 ft, and
a horizontal air-cooled convective section.
The tower section consisted of eight mod-
ular units, each with multiple access ports
for sampling, injection, or cooling. The BSF
was used to simulate a wide range of time/
temperature profiles by positioning water-
*To convert to the metric equivalent, use
 TK = (Top + 459.671/1.8.
*To convert to the metric equivalents, use
 Btu/hr = 0.293 W, and ft = 0.305 m.

-------
cooled panels or rods appropriately in the
furnace. A Iow-N0x distributed mixing
burner was positioned at the top of the
tower to down-fire either coal or natural
gas.
The first portion of this study focused
on the influence of the boiler design/sor-
bent injection parameters on overall SO2
capture. These studies included considera-
tion of overall excess air, burner stoichi-
ometry, radiant zone heat removal rate,
burner swirl, general sorbent injection
location (burner versus downstream),
importance of sorbent premixing with fuel,
and impact of low NOX operation. The
results of these studies indicated that the
parameters which were most critical for
the optimization of sorbent utilization were
sorbent injection location and the
time/temperature history between injec-
tion and 1700 °F.

Combustion Parameters
Figure 1 summarizes results obtained on
the impact of sorbent injection location
with a typical limestone and slaked lime.
These data indicate that the SO2 capture
increased approximately linearly with in-
creasing calcium to sulfur ratio and higher
capture was achieved with downstream
injection at about 2250 °F for both
sorbents. Figure 1 indicates that the slak-
ed lime was more sensitive to injection
location than the limestone, and that is
typical of results with other calcium hy-
droxide materials. The desirability of
downstream injection (compared to sor-
bent premixed with the fuel) shown in
Figure 2 is typical of the trends obtained
with a wide variety of other sorbents with
both gas- and coal-firing under both
favorable and highly quenched thermal
conditions. Injection downstream of the
burner greatly enhances the surface area
available for subsequent sulfation due to
increased surface area (reduced grain
growth). However, if the injection is
delayed beyond the beginning of the reac-
tion window (about 2250 °F), the effec-
tive residence time in the sulfation zone
decreases rapidly. In addition, a larger por-
tion of the available residence time must
be used for in situ calcination of the stone,
and lower temperatures produce reduced
diffusion and chemical rates. Therefore,
the overall optimum injection temperature
appears to be near the front of the sulfa-
tion window (about 2250°F). Injection
above this temperature results in decreas-
ed sorbent reactivity due to excessive
grain growth; injection significantly below
2250°F produces an even higher initial
surface area, but this effect is more than
Limestone
(Vicron)
Slaked Lime
(Warner Hydrate)
60

j,50
^3
20
10
0 Downstream
Injection

. * Fuel Injection
123 123
Ca/S Ca/S
Figure 1. Influence of injection location
on sulfur capture.
111
K/sec
222
333
70

i 50
&
-------
\
i
80
70
60
50
40
30
20
10
400 7200 2000

Initial SOi Concentration (0% Oa dry), ppm

Figure 3. The effect of initial S02 concentrations.
2800
to sulfur capture by magnesium. They
were followed by the natural dolomite, the
two limes slaked at atmospheric pressure,
and finally the Vicron limestone. For injec-
tion with the fuel, both the natural and the
pressure-slaked dolomites gave the high-
est capture, while the calcitic carbonate
(Vicron) and the calcitic hydroxide gave
the lowest capture.
Since the sorbents studied include both
calcitic and dolomitic materials, the total
mass feed rate can vary substantially for
a given Ca/S molar ratio: hence, both the
initial sorbent cost and the amount of ash
which must ultimately be disposed of are
variable. In order to compare the different
sorbents on a total mass output basis, the
results are presented as a function of the
mass parameter, MgO + CaO divided by
the total inherent coal ash mass (assuming
a 1 percent sulfur, 10 percent ash coal), as
shown in Figure 4. Compiling the data on
this basis indicates the capture that can be
achieved relative to the amount of addi-
tional material that must be removed from
the paniculate collection devices. Even on
this basis the dolomitic pressure-slaked
limes appear extremely attractive as does
the Warner hydrated lime. Again the poor-
est performance was achieved with the
Vicron limestone. These results suggest
that capture in excess of 60 percent can
be achieved with about a 50 percent in-
crease in the dry ash handling require-
ments (i.e., sorbent addition is like switch-
ing from a 10 to a 15 percent ash coal with
1 percent sulfur).

Enhancement by Promoter
Addition
The final primary area of study was the
addition of various promoters to enhance
sulfur capture. Initially, Cr203 was found
to dramatically improve capture with Vic-
ron, especially when the promoted sorbent
was injected into the high temperature re-
gion at the burner. Many of the transition
metal promoters were evaluated for possi-
ble capture enhancement; however, only
molybdenum and chromium enhanced
capture significantly relative to Vicron.
Subsequently, it was found that alkali
metal components (lithium, sodium, po-
tassium) gave positive results similar to
those found with the chromium series
materials. The most unusual thing about
the chromium promoted limestone sorbent
was that, in contrast to all previous results,
the capture with high temperature injec-
tion was equivalent to that with down-
stream, low temperature injection. Chrom-
ium appears to have the ability to negate
the effect of thermal sintering of the sor-
bent. Figure 5 shows the influence of
Cr203 addition with three types of
sorbents. The open bars represent the cap-
ture measured with the sorbents alone and
the shaded bars indicate the increase in
capture that resulted from five percent
chromium addition. With all of the sor-
bents and with both burner zone and
downstream sorbent injection, the capture
increases with chromium promotion were
significant. Even the performance of the
Genstar pressure-slaked dolomite was im-
proved: 70 to 85 percent capture for the
downstream sorbent injection and 35 to
70 percent capture for injection with the
fuel. In general the enhancement above
the base line was greater when the pro-
moted sorbents were injected into the high
temperature region, although the absolute
capture levels were generally higher for
downstream injection.
The exact mechanism for the chromium
and sodium enhancement is not clear;
however, it appears likely that these mate-
rials promote capture by enhancing the
product layer diffusion step since the
model calculations indicate that product
layer diffusion is the primary limitation to
increased sulfation rates. Additional work
is needed to optimize the method of pro-
moter addition and clarify the controlling
mechanisms.

Conclusions
The experimental results and the sulfa-
tion model calculations indicate that the
sorbent injection locations and the resi-
dence time within the sulfation temper-
ature window can significantly influence
the overall sulfur capture for any sorbent.
Unless the sorbent is promoted with a
metal additive, downstream injection at
about 2250 °F results in optimum sorbent
utilization. Increasing the heat removal rate
between about 1700 and 2250 °F results
in decreased sulfur capture. Increasing the
gas-phase S02 concentration (e.g., due to
increased coal sulfur content) improves
sorbent utilization, but the dependence is
nonlinear due to the combined effects of
intrinsic chemistry and diffusion.
In general dolomitic sorbents perform
better than calcitic sorbents, and hydrox-
-------
With Fuel
Downstream
s
I
70
60
50
40
30
20
10
(Q Vicron, O Cotton Hydrate.
O Warner Hydrate. A Dolomite.
O Genstar Blends. Q Genstar
Dolomitic Hydrate(s). O Warner
Dolomitic Hydratefs)
o
0.2
0.4 0.6
0.8
0.2
0.4 0.6
0.8
Prided Sorbent Mass (MgO + CaO;
Inherent Coal Ash Mass
ides are superior to carbonates. The true
influence of pressure slaking is unclear;
however, the best sorbents tested (on
either a calcium molar or total mass basis)
were pressure-slaked dolomites. The mag-
nesium in the dolomite materials does not
react to produce magnesium sulfate; it
probably enhances product layer diffusion.
The performance of all sorbents can be
enhanced by adding appropriate metallic
compounds in relatively small quantities.
Thus, the results of this study suggest
that it is possible to achieve relatively high
capture levels by at least two alternative
methods: use of advanced sorbents (e.g.
pressure-slaked dolomites) or promoted
limestones. Clearly these two concepts
can be combined to produce even higher
capture levels.
In general the results of this study show
that it is possible to exceed the current
EPA performance goal of 50 percent at a
Ca/S ratio of 2.0 with either an inexpen-
sive limestone promoted with a material
as simple as sodium carbonate or a
pressure-slaked dolomite if the sorbent is
injected downstream of the main heat
release zone.
Figure 4. Capture comparison—mass basis.
W/Fuel
Downstream
90

I 50

I 40

«
^ 30

10\
Nat. GBS/H&

Reduced Load

Open Bars: Sorbent Alone

Shaded Bars: Increase with CR

Ca/Cr= 14.8

Ca/S = 2.0

V = Vicron

C = Co/ton Hydrate

G = Genstar Dolomiticfs)
Figure 5. Capture enhancement with Cr^Oa •
-------
B. Overmoe, L Ho, S. Chen. W. Seeker, D. Pershing, andM. Heap are with Energy
and Environmental Research Corp., Irvine, CA 92718.
Dennis C. Drehmel is the EPA Project Officer (see below).
The complete report, entitled "Boiler Simulator Studies on Sorbent Utilization for
SOz Control,"(Order No. PB87-101 77Q/AS; Cost: $16.95, subject to change)
will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield. VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection
Agency
Center for Environmental Resenrrh
Information
Cincinnati OH 45268
Official Business
Penalty for Private 'Jse $300

EPA/600/S7-86/028
0000329 PS
U S ENVIR PROIECTION ft6€ltCY
CHICAGO
-------
United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-86/029 Jan. 1987
&EPA Project Summary

Analysis of Utility Control
Strategies Using the
LIMB Technology
T. E. Emmel and B. A. Laseke
The report gives results of a study to
evaluate the impact of proposed acid rain
legislation on the potential application of
limestone injection multistage burner
(LIMB) technology to achieve sulfur diox-
ide (SO2) and nitrogen oxide (NOX) reduc-
tions at coal-fired utility power plants.
The study found that proposed acid rain
legislation, which mandates the retrofit of
high efficiency control technologies such
as flue gas desurfurization (FGD) or which
requires national S02/NOX reduction
levels greater than 10 million tons per year,
would significantly reduce the application
of LIMB. For regulatory strategies which
do not mandate the use of FGD and which
require emission reductions of 8 to 10
million tons per year, the potential LIMB
application ranges from 15,000 to
100,000 MW of coal-fired boiler capacity
in the 31 eastern state acid rain region.
This Project Summary was developed
by EPA's Air and Energy Engineering
Research Laboratory, Research Triangle
Park, NC, to announce key findings of the
research project that is fully documented
in a separate report of the same title (see
Project Report ordering information at
back).

Introduction
A number of bills have been proposed
by Congress that would require reductions
of acid rain precursor emissions. These
congressional bills would require different
mixes of emission control technologies to
achieve SO2 and NOX reductions at coal-
fired utility power plants. The objective of
this research program was to evaluate the
impact of proposed acid rain legislation on
the potential application of LIMB tech-
nology incorporating recent LIMB research
and development findings.
A number of regulatory strategies and
emission reduction targets were developed
by reviewing acid rain legislation proposed
in the 97th and 98th congressional ses-
sions. For each regulatory strategy devel-
oped, the control technology mix of LIMB,
FGD, and coal switching required to
achieve the selected emission reduction
level was determined. Next, the maximum
number of boilers to which LIMB tech-
nology could be applied was determined
by examining technical and regulatory
constraints and emission reduction tar-
gets. The cost effectiveness of each regu-
latory case and control technology mix
was estimated to evaluate the cost of each
control technology mix.

Regulatory Case Development
The primary differences in the congres-
sional bills are a result of the level of SO2
reductions that is required at each plant
due to plant/boiler specific emission limits
or due to requiring high overall SO2 reduc-
tion levels. All of the bills use 1980 as the
base year for which emission reduction
levels apply. Differences in the method of
calculating excess emissions, implemen-
tation years, financing methods, and state
reduction allocation and implementation
were not considered important for the pur-
poses of this study. The following three
legislative/regulatory cases were analyzed:
Regulatory Case
S02 Reductions,
million tons/yr
Boiler Performance 10
Standard
Regional Reduction Levels 10
Regional Reduction Levels 8
-------
For this study, a regulatory strategy was
developed based on bills which base re-
ductions on boiler and/or state reduction
performance standards (S 1709, HR 4816,
HR 3400). These bills require that existing
boilers must comply with New Source Per-
formance Standards (1971 or 1979) if their
emissions are greater than a specified
amount of S02 per million Btu of fuel.
These bills also require state wide reduc-
tions. Because these bills require very high
levels of SO2 reduction at individual
plants/boilers, the use of wet FGD will be
required at most affected plants. These
legislative cases are entitled "Boiler Per-
formance" cases, and FGD is applied to
boilers at the largest emitting utility power
plants.

The other major type of bill introduced
in Congress (HR 4829, S 3041) allocates
state level emission reductions generally
based on the portion of emissions from
facilities with emission rates greater than
1.2 Ib SO2 per million Btu fuel input.
These bills allow the states to determine
how the allocated emission reductions for
that state are to be achieved and in some
cases allow trading of emission reduc-
tions. Because these bills provide much
greater flexibility in how emission reduc-
tions are achieved on a plant/boiler basis,
they do not require the use of certain types
of SO2/NOX control technologies. Study
cases based on this type of legislative
scenario are entitled "Regional Reduc-
tion" cases.

The other major difference between bills
that would impact the mix of control tech-
nologies used by utilities is the amount of
emission reduction required because, as
the S02 reduction target increases, the
average emission reduction needed to be
achieved at each coal-fired boiler in-
creases. For this study three SO2 emis-
sion reduction levels were evaluated: 8 and
10 million tons per year, consistent with
the different levels proposed by the con-
gressional bills reviewed; and 12 million
tons per year, a sensitivity case to evaluate
the impact that this level of reduction
would have on the control technology mix
needed to achieve this high level of
reduction.
The Congressional bills differ in the
amount of credit given for NOX reduc-
tions. For this study half credit was given
for NOX reductions; e.g., 1.0 ton of NOX
removed equals 0.5 ton of S02 reduction.
Thus, for this study, a NOX credit was
included for low NOX combustion
modification assumed to be made with
furnace sorbent injection.
Region and Boiler Specific
Data Base
A major part of the study was develop-
ment of a boiler specific data base and
boiler specific control costs for LIMB, FGD,
and coal switching. Developing an ac-
curate data base for all coal-fired boilers
in the 31 eastern states was not feasible.
However, an accurate data base was easily
developed for the top 100 S02 emitting
coal-fired utility power plants. These top
100 plants accounted for over 72% of
total U.S. utility power plant S02 emis-
sions in 1980. Results of the applicability
study for the top 100 plants were then ex-
trapolated to the boilers in the 31 eastern
state region. S02 emission reduction
targets used for each regulatory case, bas-
ed on allocating 72% of the emission
reduction target to the top 100 coal-fired
boiler population, are
tion cases. Figures 3 and 4 summarize the
results of the 8,10, and 12 million ton per
year S02 reduction cases.
10 Million Ton Par Year SO2
Reduction Cases
Figure 1 summarizes the results of the
10 million ton per year S02 reduction
cases. Two cases were run for the Boiler
Performance Standard strategy to provide
an upper and lower bound on the amount
of LIMB which would be used to achieve
the desired S02 reductions. In both
cases, FGD was applied to the boilers in
the top 50 SO2 emitting power plants
with post 1965 service year achieving over
5.5 million tons per year of S02 reduc-
tion. In the first case LIMB was applied to
the remaining boilers which were consid-
ered technically applicable (post 1960
Regulatory Strategy
SO2 Emission Reduction
From Top 100 Plants,
106 tons per year
Total Required
S02 Reduction,
106 tons per year
Boiler Performance Standard
Regional Reduction
Regional Reduction
Regional Reduction
7.2
7.2
5.8
8.6
10
10
8
12
Control Technology
Performance/Cost
Three coal-fired boiler SO2 reduction
technologies were examined: (1) limestone
FGD with 90% S02 control; (2) LIMB
with 50-60% SO2 control and 50% NOX
control; and (3) switching to 2.5 Ib SO2
per million Btu eastern bituminous coal.
Boiler specific costs for FGD and LIMB
were provided, using the IAPCS-2 com-
puter model. Table 1 summarizes the cost/
performance assumptions used to make
the computer runs.
The cost of coal switching was based
on a coal cost differential of $1.00 per
million Btu above the current higher sulfur
coal. Although boiler specific costs for
high and low sulfur coals were available,
due to the current soft market, several
plants are actually obtaining low sulfur
coal at prices below high sulfur coal. This
is not anticipated if many plants were
required to switch coals because the
added demand for low sulfur coal would
drive up its price relative to high sulfur
coals.
Discussion of Results
Figures 1 and 2 summarize the results
of the 10 million ton per year S02 reduc-
wall/tangential fired boilers with sulfur
emissions between 1.2 and 6.0 Ib/million
Btu). This case results in 69,000 MW of
FGD application, 13,000 MW of LIMB ap-
plication and 3,000 MW of coal switching.
For the second Boiler Performance Stan-
dard case, coal switching (MAX CS) was
applied before LIMB resulting in 8,400
MW of coal switching. Because coal
switching can be achieved on the 1950's
boiler to meet the required emission reduc-
tion target, no LIMB was applied.
Three different cases were run for the
10 million ton per year regional allocation
scenario. The first two cases provided an
upper and lower bound on the amount of
LIMB which would be used versus coal
switching. The other case looks at the im-
pact of high performance (HP) LIMB (60%
S02 reduction). For the maximum (MAX)
LIMB case, LIMB was applied first to the
applicable boilers resulting in half of the
boiler population (71,000 MW) being con-
trolled with the LIMB technology, 15,000
MW of FGD, and 11,000 MW of coal
switching. For the second 10 million ton
reduction case, coal switching was maxi-
mized (MAX CS) by applying it first to all
the 1950's boilers. This reduces LIMB ap-
plication to 65,000 MW and increases
-------
Table 1. Performance and Cost Parameters Used to Estimate FGD and LIMB
Annualized Costs and Emission Reductions
LIMB Performance Parameters
5O% LIMB Cases
60% LIMB Cases
50% SO2 Reduction
50% NOX Reduction
Calcitic Hydrate
2.5:1 Ca/S Ratio
7OO°F Quench Rate
60% SO2 Reduction
50% NOX Reduction
Calcitic Hydrate
3:1 Ca/S Ratio
700°F Quench Rate
ESP upgrade and S03 conditioning for control of additional paniculate matter.

FGD Performance Parameters
90% SO2 Reduction and No NOX Reduction
Limestone Slurry Sorbent
No Spare Absorbers
Number of Absorber Towers Based on Boiler Size:
Boiler Size, MW No. of Towers
<100
100-250
250-500
500-750
>750
1
2
3
4
5
General Cost Bases
EPRI Cost Premises Used
Costs are in 1995 Dollars
Equipment Book Life of 15 Years
FGD Retrofit Difficulty Factor: 1.2 Times New Plant Cost
150,000
100,000-
1 50,000
Oj
.:•;.:•;.•:.• Coal Switching Capacity
xxxxxxx: FGD Capacity
tSaa LIMB Capacity
"mi" Retired FGD Capacity
Max LIMB
Max CS Max LIMB Max CS
HP LIMB
Boiler Performance
Standard Cases
Regional Reduction
Level Cases
coal switching to 25,000 MW of applica-
tion. For the third 10 million ton per year
reduction case, high performance (HP
LIMB) LIMB was applied, followed by FGD
and coal switching as in the MAX LIMB
case This case decreases the penetration
of FDG due to the greater S02 reduction
achieved by high performance (60%) LIMB
technology.
Figure 2 summarizes the cost results in
the five 10 million ton per year SO2 re-
duction cases. The boiler performance
standard cases have the highest annual
control cost of $13-$14 billion per year due
to the large number of boilers which must
apply FGD. The regional annual costs of
the regional reduction level cases are
significantly lower and range from $9.9 to
$11.7 billion per year.
8, 10, and 12 Million Ton Per Year
Cases
Figure 3 presents the results analyzing
the impact of various emission reduction
scenarios on the application of LIMB. The
10 million ton per year S02 reduction
case is the same as for the Max LIMB
regional allocation case discussed above.
For this case, 71,000 MW of LIMB was ap-
plied to achieve the emission reduction
target.
For the 8 million ton per year reduction
case, coal switching to the 1950's boilers
was applied first (lowest unit cost), follow-
ed by LIMB and FGD to achieve the emis-
sion reduction target. This results in boiler
application of 71,000 MW of LIMB,
25,000 MW of coal switching, and 3,200
MW of FGD.
For the 12 million ton per year emission
reduction case, the application of LIMB
cannot be maximized if the emission
reduction target is to be achieved. For this
case, LIMB application was reduced by in-
creasing the use of FGD and allowing all
boilers where FGD and LIMB were not ap-
plied to switch coal. This results in the
following boiler applications: 38,000 MW
of LIMB, 50,000 MW of FGD, and 25,000
MW of coal switching.
Figure 4 presents the annual cost for the
three cases. The annual costs and unit
costs increase significantly as the emis-
sion reduction levels increase over 10
million tons per year:
Figure 1. Boiler application results for 10 million ton per year of SO2 reductions.
-------
Annual Reduction,
106 tons per year
8
10
12
Increase Emission
Reduction, %
25
50
Increase
in Cost, %
23
73
Average Unit
Cost, $/ton
1381
1397
1678
These cost increases are due to the signif-
icantly increased application of FGD need-
ed to obtain the very high overall average
emission reductions per boiler/plant.

31 Eastern State Region
To estimate the potential LIMB applica-
bility for all of the coal-fired boilers in the
31 eastern state region, the number of
boilers in that region that fit the LIMB and
FGD technical applicability was determin-
ed from the 31 eastern state utility boiler
data base. The amount of capacity for
which LIMB was applicable was 103,000
MW. The amount of FGD capacity for this
boiler population was 108,000 MW.
The average unit cost of applying FGD
to the applicable boilers not in the top 100
plants is significantly greater due to the
smaller boiler sizes and lower coal sulfur
contents. This means that LIMB tech-
nology would be favored over FGD, and
the LIMB applicability potential for the 10
million ton per year S02 reduction strat-
egy not mandating the use of FGD could
be as high as 100,000 MW of boiler
capacity.

Conclusions
This study indicates that up to 100,000
MW of boiler capacity of LIMB application
is possible depending on the type of acid
rain legislation adopted and the amount of
coal switching that is economically and
politically practical. Currently proposed
legislative strategies requiring S02 reduc-
tions of 8-10 million tons per year will
maximize the application of LIMB because
it is anticipated to be more cost effective
than FGD. Control strategies requiring
S02 reductions greater than 10 million
tons per year will decrease the application
of LIMB, because the average level of
S02 control required at each boiler would
exceed that available with a broad applica-
tion of LIMB. Legislative strategies which
would require high levels of control
(>60%) at each boiler would also reduce
the application of LIMB unless combined
with fuel substitution.
15.000
Coal Switching Cost
yWxYxY: FGD Cost
LIMB Cost
Figure 2.

150,000
Boiler Performance
Standard Cases

Levelized annual cost of control (1995 $ I.
Regional Reduction
Level Cases
100,000-
%
u
I
h*
fso.ooo
oo
••'.".:•" Coal Switching Capacity
VWAW FGD Capacity
BBS LIMB Capacity
11111111 Retired FGD Capacity
8 x 10* tons/yr 10 x 10* tons/yr 12x10" tons/yr

Figure 3. Boiler application results for 8, 10, and 12 million ton per year cases.
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15.000
10.000

5.000-
•::::::::; Coal Switching Cost
WWW FGO Cost
LIMB Cost
Figure 4.
8 x 10* tons/yr 10 x 10s tons/yr 12 x 10s tons/yr
Level/zed annual cost of control for 8, 10. and 12 mil/ion ton per year cases
(1995 $).
T. Emmel is with Radian Corp.. Research Triangle Park, NC 27709; and B. Laseke
is with PEI Associates, Inc., Cincinnati, OH 45246.
Norman Kaplan is the EPA Project Officer (see below).
The complete report, entitled "Analysis of Utility Control Strategies Using the
LIMB Technology," (Order No. PB 87-100 574/AS; Cost: $9.95, subject to
change} will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
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United States
Environmental Protection
Agency
Official Business
Penalty for Private Use $300

EPA/600/S7-86/029
Center for Environmental Research
Information
Cincinnati OH 45268
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