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. 1 987
&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 (S02) 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 S02 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
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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 S02 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 S02 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 SO2 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 SO2 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 SO2 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 SO2 reduction cases.
10 Million Ton Per Year SO3
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 SO2 reduc-
tion. In the first case LIMB was applied to
the remaining boilers which were consid-
ered technically applicable (post 1960
Regulatory Strategy
S02 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 S02 reduction
technologies were examined: (1) limestone
FGD with 90% SO2 control; (2) LIMB
with 50-60% SO2 control and 50% NOX
control; and (3) switching to 2.5 Ib S02
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
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Table 1. Performance and Cost Parameters Used to Estimate FGD and LIMB
Annual/zed 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 SO3 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
1OO.OOO
I
fla
50.000
.•.v.v.v.v Coal Switching Capacity
xxxxxxx: FGD Capacity
SSB^B LIMB Capacity
"""" Retired FGD Capacity
Man 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 S02 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 ofSOa reductions.
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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 SO2 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
SO2 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.
7 5,000
10,000-
,3 5,000
Coal Switching Cost
VYxYxW FGD Cost
LIMB Cost
Figure 2.
150.000
Boiler Performance
Standard Cases
Level/zed annual cost of control (1995 $).
Regional Reduction
Level Cases
100,000-
o
I
is
"550,000
CO
Coal Switching Capacity
FGD Capacity
LIMB Capacity
Retired FGD Capacity
8x10* tons/yr 10x10* tons/yr 12x10* tons/yr
Figure 3. Boiler application results for 8, 10, and 12 million ton per year cases.
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J 5,000
10,000-
<0
B>
5,000-
•.•.v.v.v.v Coal Switching Cost
WMW FGO Cost
S^BB LIMB Cost
Figure 4.
8 x JOS tons/yr 10 x 10* tons/yr 12 x 10s tons/yr
Levelled annual cost of control for 8, 10, and 12 million ton per year cases
(1995 $).
T. Emmel is with Radian Corp.. Research Triangle Park, NC 27709; andB. 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-WO 574/AS; Cost: $9.95, 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
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• Indirect
heated —Unisulf on
Unishale B gases
• Integral
combustor —DBA + Stretford on
Lurgi gases
—Unisulf on
Unishale C gases
Major equipment costs were taken
from EPA Pollution Control Technical
Manuals (PCTMs). ASSP equipment
was sized and costs factored from in-
house data and PCTMs. Costs were fac-
tored to first quarter 1985.
Results of the cost study showed
changes in incremental capital and op-
erating costs for ASSP relative to con-
ventional processing (see Table 1).
These cost comparisons show that
the best potential for application of
ASSP are processes that already have a
spent shale combustor integrated into
the retorting process (e.g., Lurgi, Uni-
shale C, Chevron STB, and Tosco HSP).
Capital and operating cost savings for
Unishale C and Lurgi are primarily a re-
sult of deleting the Unisulf and Stretford
plants.
Economics for the indirect and direct
heated retorts are good to marginal.
Factors which will affect the economics
are:
• How effectively combustor heat
can be utilized (simple steam
raising is the least desirable).
• The value of steam.
• The use of fast or circulating fluid
beds to reduce investment in com-
bustor equipment.
Phase II Pilot Plant Testing
Pilot plant tests were performed in a
bubbling fluid bed combustor of the
type which is integrated into the retort
process. A total of 44 individual tests
were performed. Variables evaluated
were combustor temperature, solids
residence time, gas residence time, oxy-
gen concentration, inlet gas sulfur con-
centration, staged combustion, and raw
shale injection. Over the entire range of
conditions tested, emissions of primary
pollutants were:
Table 1. Cost Comparison For ASSP
Component
Range
S02
NOX
CO
Trace Hydrocarbon
1-38 ppmv
80-670 ppmv
0.05-1.80 vol%
51-8465 ppmv
Key findings of the tests were:
• S02 emissions were easily con-
trolled to low levels at virtually all
conditions tested, probably as a re-
sult of the high Ca/S ratios used.
• NOX emissions were primarily sen-
sitive to oxygen concentration, as
were S02 emissions to a lesser ex-
tent (Figure 2). Reasonably good
NOX control could be obtained with
flue gas oxygen concentrations
below about 3 vol %. The lowest
NOX concentrations were seen at 02
levels approaching zero but at the
expense of higher CO and trace hy-
drocarbon emissions.
• CO and trace hydrocarbon emis-
sions were primarily sensitive to
flue gas oxygen concentration (Fig-
ure 3). Good control of both could
be obtained at O2 levels above
about 2 vol %.
Emissions of NOX move in a direction
opposite to S02, CO, and trace hydro-
carbon emissions. Thus, operating con-
ditions that minimize all four represent
a compromise. One test was run which
produced nearly optimum results.
Conditions for this test were:
Bed Temperature 664°C
Solids Residence
Time 9.4 min
Gas Residence Time 0.9 sec
Gas Supply
Velocity 134.1 cm/sec
Flue Gas 02 2.6 vol %
Ca/S Mole Ratio 10.3
Raw Shale/Spent
Shale Ratio 1:36
At these conditions the following re-
sults were obtained:
SO2 11 ppmv
NOX
CO
Trace Hydrocarbon
Combustion Efficiency
160 ppmv
0.27 vol %
388 ppmv
89%
Retort Type
Direct Heated
Case A, Case B
Indirect
Heated
Integral Combustor
Retorting Process
ASSP Incremental
Cap. Cost, $W6
ASSP Incremental
Annual Oper. Cost, $W6/yr +10.83
MIS/Unishale C
-71.2 -63.2
+12.07
Unishale B Lurgi Unishale C
+90.2 -13.0 -32.1
-19.21 -2.29 -1.56
During selected tests, both combus-
tor flue gas and retort gas were sampled
and analyzed for selected trace ele-
ments: mercury, cadmium, arsenic,
lead, beryllium, and fluorine. During
these tests, solids streams were also an-
alyzed for trace elements in an attempt
to determine where trace elements go.
One run was performed where a spike
solution of mercury and cadmium was
added to the combustor.
Results of the trace element tests indi-
cated some relative trends with regard
to emissions but, because of the brevity
of the sampling, no hard conclusions
can be reached which would allow ex-
trapolation of results to long-term
steady-state operations. Some of the
key observations were:
• Lead, beryllium and fluorine were
found to have low volatility; i.e., of
the amounts present in raw shale,
only very small percentages were
volatilized to the gas streams.
• Arsenic was found in significant
concentrations in the retort gas
(100-400 ppmv), although the
amount of arsenic found repre-
sented less than 15% of that in the
raw shale.
• So little mercury was present in the
raw shale that mercury emissions
could not be characterized with high
accuracy. Mercury emissions were
very low except during the spike in-
dicating that mercury, if present in
higher concentrations in the raw
shale, could possibly pose emis-
sions problems.
• Although significant amounts of
cadmium was found in the gases at
higher retort and combustor tem-
peratures, emissions represented
less than 10% of cadmium present
in raw shale.
There is some evidence that mercury
and cadmium introduced to the com-
bustor during the spike test condensed
within the retort equipment and
revolatilized over time. However, be-
cause of the limited number of samples
taken, it would not be prudent to draw
any conclusions. Longer term steady-
state operations would have to be stud-
ied to determine the fate of mercury and
cadmium with more certainty.
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Q:
40
35.
30-
25 -
20-
15-
10-
5 .
0
700
-600
-500
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-200
- 100
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d
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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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