TECHNOLOGICAL OPTIONS FOR ACID RAIN CONTROL
Frank T. Princiotta
and
Charles B. Sedman
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
ABSTRACT
Compliance with Title IV of the Clean Air Act Amendments (CAAA) of 1990 will
require careful scrutiny of a number of issues before selecting control options to reduce
sulfur dioxide (S02) and nitrogen oxide (NOx) emissions. One key consideration is the
effect of fuel switching or control technology upon the existing dust collector, with
particular emphasis on potential emissions of air toxics. A number of likely SO2 and
NOx retrofit technologies and estimated costs are presented, along with results of retrofit
case studies. New hybrid particulate controls are also being developed to meet future
requirements.
For presentation at the "Electric Utility Business Environment Conference,"
Denver, CO, March 17,1993.
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TECHNOLOGICAL OPTIONS FOR ACID RAIN CONTROL
BACKGROUND
Title IV of the Clean Air Act Amendments (CAAA) of 1990 mandates reductions
in acid rain precursors as follows:
o By January 1,1995 (deadline for Phase I) 5 million tons* of SO2 will be
reduced by reducing allowable emissions to 25 pounds per million Btu
heat input (Ib/lCr Btu) for 110 of the largest emitting stations.
o By the year 2000 (deadline for Phase II), virtually all power plants greater
than 25 MWe must meet a 1.2 lb/10 Btu SO^ emission limit.
o NOx emissions are to be reduced by 1 million tons annually by the 110
Phase I plants, with specific emission limits for wall-fired (0.50 lb NOX/10"
Btu) and tangentially fired (0,45 lb NOX/10 Btu) units.
o SO2 emissions are capped after the year 2000.
A number of allowances, exceptions, and issues involving compliance and
emissions trading are acknowledged; however, this paper focuses on the technical options
currently available to meet the above requirements. There is a danger, however, in
isolating Title IV from the balance of the CAAA. Prudent decision-making must also
include future requirements in air toxics (Title III), ozone-nonattainment, and carbon
dioxide (global warming) issues. For example, conventional flue-gas desulfurization
(FGD) systems, !ow-NOx burners, or fuel switches which reduce unit efficiency may
appear imprudent in the near future. Current technology choices which do not consider
impacts on air toxics control or visibility issues may also be shortsighted. Solid waste-
issues not even mentioned in the CAAA may become critical at the state and local
levels. In certain cases water consumption may also force technology decisions.
CANDIDATE TECHNOLOGIES AND COSTS
The electric utility industry will have to make very many cost intensive decisions
to comply with provisions of the legislation. For S02 control, the industry will have the
choice of locating an adequate supply of low sulfur coal, selecting a control technology,
or selectively burning natural gas. The utility will likely look for available low sulfur coal
supplies from both Eastern and Western U.S. mines to determine the most economical
fuel for that particular utility system. The utility will likely compare the coal switching
option to the control technology options available. Table 1 describes current and
(*) Readers more familiar with metric units may use the conversion factors at the end of
this paper to convert to that system.
2
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emerging technologies for retrofit SO^ and NOx control) Combined S€>2/NOx
technologies In Table 2 reflect modified combustion where both S02 and NOx are
reduced in the process of fuel combustion. The tables briefly describe the technology,
the estimated level of control of SO2 and NOx, and projected commercial availability,
including comments primarily related to capability. Note that the overwhelming current
choice of utilities for SO2 control technology has been lime and limestone wet scrubbers.
A considerable number of combined S€>j/NOx technologies are not listed in
Table 2, primarily due to the complexity and economic factors which make their choice
unlikely for retrofits. These include atmospheric fluidized bed combustion, pressurized
fluid bed/combined cycle combustion, and integrated gasification combined cycle
technologies which are 5 to 10 years from commercial availability. Table 3 lists a
number of novel combined SOx/NOx technologies which are near commercial use or
demonstration today, but not economically attractive for acid rain retrofit.
Although many decisions have already been made regarding Phase I and Phase 11
retrofits, essentially the decisions have been to use either wet flue gas desulfurization or
lower sulfur fuels. We interpret the latter choice to be "deferred decision" on technology
in that the utility may elect to use lower sulfur fuel until a more cost effective
strategy/technology becomes commercially demonstrated or until the low-sulfur fuel
strategy becomes more costly than available technology due to fuel price increases or air
toxics legislation (discussed at the end of this paper).
The technologies shown in Tables 1 and 2 include three distinct technologies
developed by the Air and Energy Engineering Research Laboratory (AEERL)-
Limestone/Lime Injection Multistage Burner (LIMB), E-SOx, and ADVACATE.
LIMB technology (Figure 1), which has been demonstrated at 60+% S02
removal and 45% NOx control on a 105 MWe wall-fired unit, is currently being
demonstrated on a 180 MWe tangential unit in Yorktown, Virginia. ' LIMB, as with
most sorbent injection technologies, appears cost-effective with decreasing size, coal
sulfur, and plant life expectancy compared to conventional FGD.
The E-SOx technology has been evaluated at a 5 MWe scale and appears capable
of 50-60% SC>2 removal at a very low ($40/kWg) capital cost, but is limited to larger
electrostatic precipitators (>40 m^/m^/min specific collection area).^> ^
The ADVACATE technology (Figure 2) is perhaps the most competitive with
conventional FGD technology, offering 90% SO2 control at a lower cost. To date
ADVACATE has very limited field operation on a 10 MWe pilot basis, but is being
strongly considered for demonstration in the U.S. and Eastern Europe.
Table 2 includes natural gas reburning technology for NOx which has been
promoted by AEERL through demonstration at a 108 MW£ cyclone unit in Ohio® and is
3
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currently operating on a 300 MWe wet-bottom, wall-fired boiler in the Ukraine. In both
cases 50 to 65% NOx control is being achieved over baseline coal operation. Technical
papers on both demonstrations will be presented at the 1993 NOx Control Symposium,
co-sponsored by AEERL and the Electric Power Research Institute, May 23-27, 1993 in
Miami Beach, Florida.
One major cost study on retrofit FGD technologies has been completed as
reflected in Figures 3 and 4. Figure 3 shows the results of an evaluation of 22 FGD
technologies for capital investment retrofit cost when applied to a 300 MWe plant
burning 2,6% sulfur coal. Typical conventional wet FGD costs (Figure 3) average
$200/kW, while a number of dry sorbent injection systems including LIMB (FSI) and
ADVACATE (ADV) are between $50 and $100/kW, and are generally applicable to
older, lower-utilized plants. Figure 4 shows corresponding levelized annual costs in
$/ton of S02 removed. Here the wet FGD systems at $500/ton S02 fare somewhat
better than the lower capital dry systems except for two noteworthy exceptions-the Lurgi
circulating fluid bed (CFB) absorber at $400/ton S02 and ADVACATE (ADV) at less
than $300/ton S02. This is due largely to their inherently higher SO2 removal capability
(90%) than other dry removal systems (50-60%),
Costs of retrofit NOx control technologies have been examined bv EPA's Office
of Air Quality Planning and Standards and are summarized in Table 4. The wide
range of costs in the combustion modification technologies reflects the number of issues
encountered in altering the air/fuel delivery systems within a boiler. Since this study
focuses on one size boiler, results are to be interpreted in a general sense. For Figures 3
and 4 and Table 4, refer to the glossary at the end of this paper for descriptions of
acronyms.
RETROFIT CASE STUDIES
To elaborate on the choices facing the utility industry, it is worthwhile to
summarize the results of a recent study sponsored by AEERL.* * The objective of this
study was to significantly improve the accuracy of engineering cost estimates used to
evaluate the economic effects of retrofitting S02 and NOx controls to the top 200 S02-
emitting coal-fired utility boilers. This project was conducted in several phases. In
Phase 1, detailed, site specific procedures were developed and used to evaluate retrofit
costs at 12 actual plants. In Phase 2, simplified procedures were developed to evaluate
the site specific costs, and these procedures were used to evaluate retrofit costs at 50
plants. In Phase 3 all remaining 138 plant costs were evaluated. This recently published
report presents the cost estimates developed for 576 boilers in 188 plants using the
simplified procedures. The study evaluated retrofit costs for the following technologies:
o Limestone FGD
o Additive-enhanced limestone FGD
o Lime spray drying FGD
4
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0
Physical coat cleaning
0
Coal switching and blending
0
Low NOx combustion
0
Furnace sorbent injection with humidification (LIMB)
0
Duct spray drying
0
Natural gas reburning
0
Selective catalytic reduction
To generate retrofit costs for each plant, a boiler profile was completed using sources of
public information. Additionally, toiler design data were obtained from power plants,
from a data base maintained by Power magazine, and aerial photographs, obtained from
state and federal agencies. The plant and boiler profile information was used to develop
the input data for the performance and costs models. To enhance the credibility of cost
Information, which is almost always controversial, the performance and cost results
incorporate recommendations from utility companies and a technical advisory group.
This group included the utility industry, FGD vendors, and government agency
representatives. All the cost estimates were developed using the integrated air pollution
control systems (IAPCS) cost model. The IAPCS model was upgraded to include the
technologies being evaluated in this program.
The results of this study confirm that costs of various acid rain retrofit options
vary considerably from plant to plant. What might be an economical approach at one
plant could be prohibitively expensive at another plant due to unique local conditions,
such as lack of space or other site-specific factors. Figures 5-8 summarize some of the
results of this study. They describe the costs of retrofit control for coal switching,
lime/limestone desulfurization, LIMB (for SO2 control), and three combustion
technologies for NOx control. Figure 5 summarizes the cost per ton of S02 removed for
coal switching and blending. Coal price differentials (new vs. existing coal) of both $5
and $15 per ton of coal were assumed in this cost analysis since they bracket the likely
differential for many existing boilers in the Eastern U.S. Note that, for about 50% of the
applicable boilers for a $5 price differential, the levelized cost of control will be
substantially less than $1,000 per ton of sulfur removed. (All costs were calculated on a
Ievelized basis; i.e., they were increased over first year costs to take into account likely
inflation over the control's lifetime.) However, for boilers already burning relatively low-
S coal, even this relatively small coal price differential can yield substantially higher cost
of controls per ton of sulfur removed. For the higher coal price differential, typically for
plants far from available low sulfur coal, only 25% of the generating capacity in the 200
plant study can be controlled at less than $1,000 per ton. Utilities will likely look very
closely at the low sulfur coal option which in many cases will be the least expensive
option.
Figure 6 summarizes the cost per ton of SO2 removed for lime or limestone FGD
technology. Two options were examined: 1) a standard system meeting new source
performance standards with at least one absorber per boiler and maximum absorber
5
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capacity of 125 MW and one spare absorber per boiler, and 2) a low cost option with a
maximum absorber capacity of 250 MW and no spare absorber. As shown, certain plants
can be controlled for less than $1,000 a ton; but, for most, costs will be higher than that.
For the most expensive, 25% controlled capacity, costs will be quite high, due primarily
to difficulty of retrofit.
Figure 7 summarizes the cost per ton of S©2 removal for LIMB technology. Two
cases are studied corresponding to 50 or 70% S02 removal by the LIMB/humidification
technology. For most cases, this technology is less expensive than wet FGD per ton of
SC>2 removed, especially if 70% SOj removal is achievable for a given plant.
The last figure in this series, Figure 8, summarizes costs per ton of NOx removed
utilizing three low N€>x combustion technologies: low NOx burners (LNB), natural gas
rebuming (NGR), and overfire air (OFA), another combustion modification technology.
As shown, the combustion technologies LNB and OFA are considerably less expensive
than natural gas rebuming. However, for certain classes of boilers, such as cyclones,
rebuming may be the only feasible option. Also note that 75% of the generating
capacity can be controlled with a low NOx burner or overfire air system for costs below
$500 per ton of NOx removed.
Results of this study should be useful to utilities, states, and others who will likely
be making or monitoring the difficult choices of control mandated by Title IV of the
CAAA of 1990.
In January' 1990, the authors of the retrofit study (Reference 11) were asked to
apply the results of this study to a hypothetical 10 million ton per year SOj reduction
program (from 1980 emission levels). The objective was to estimate the maximum
potential benefit of emerging technologies (i.e., LIMB and ADVACATE) to an acid rain
retrofit program.
The methodology involved selecting the lowest cost option for a particular plant,
ultimately achieving the required 10 ton reduction by retrofitting the top 200 SC^-
emitting plants.
For this analysis, the following limited sets of available control options were
assumed:
Cases 1 & 2
Cases 3 & 4
Coal Switching/Blending
Limestone FGD
LIMB (50% removal)
Coal Switching/Blending
Limestone FGD
LIMB (50% removal)
ADVACATE (limestone, 90% removal)
6
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Cases 1 and 3 assumed a low-sulfur coal incremental cost of $5/ton; whereas.
Cases 2 and 4 assumed a $I5/ton differential. Cases 3 and 4 included the ADVACATE
process to estimate the impact of such a technology assuming costs half those of wet
FGD and retrofittability similar to that of wet FGD. Note that ADVACATE is not a
demonstrated technology; cost savings should be considered only as an upper limit of
what might be achievable if successfully demonstrated and freely selected by the utility
industry, despite lack of extensive field operation experience.
Figure 9 shows the results of this analysis. For Cases 1 and 2, coal switching,
FGD, and LIMB would all play roles, with coal switching particularly important at the
low ($5 per ton) coal price differential (Case 1). For Cases 3 and 4, ADVACATE
would play the major role, essentially displacing all other options for the high ($15 per
ton) coal price differential (Case 4). Maximum possible annual cost savings associated
with ADVACATE technology availability are in the order of $2 billion,
OTHER CONSIDERATIONS
Perhaps overlooked in selecting control strategies for SO2, NOx, and air toxics
control is the impact on the particulate matter collector. If early indications of massive
fuel switching for CAAA compliance are correct, then profound effects upon operation
of electrostatic precipitators (ESPs) can be anticipated. Existing ESPs are the dominant
particulate matter control technology on U.S. utility boilers and are sensitive to the
physical properties of flue gas and fly ash, especially particle size distribution and
loading, electrical resistivity, and cohesivity. With the exception of wet FGD technology,
which is usually located downstream of the ESP, all other NOx and SOx retrofit systems
alter either gas or particle characteristics, or both, in ways which almost always degrade
ESP performance.
In addition toxic air pollutants mentioned earlier add to the dust collection
concerns because: (1) most of the heavy metals are contained in the coal ash, (2) the
fine particulate matter emanating from the boiler presents the highest concentration of
metals, (3) the most volatile elements-mercury, arsenic, selenium, and halogen
compounds-may remain in the gas phase, but largely condense out into fine particulate
matter, (4) scrubbing systems remove volatile trace metals efficiently except for mercury,
and (5) Western low-sulfur coals may exhibit significantly higher concentrations of heavy
metals than Eastern coals.
If the objective is to remove toxics from the air, then a variety of options appear
to be available in the choice and arrangement of back-end, flue-gas cleaning systems. To
illustrate: most experts conclude that a fabric filter is superior to an ESP for collecting
fine particulates, although tradeoffs may exist in the form of pressure drop across the
bags, cost, significant releases of fly ash because of bag failure, etc. Wet FGD systems
provide insurance against air-toxics emissions, except perhaps mercury.
7
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Because of these concerns at least two new hybrid particulate controls have been
developed. The COHPAC system, being evaluated by the Electric Power Research
Institute, adds a small pulse-jet fabric filter immediately downstream of an existing ESP
as a retrofit option. A long-term goal is to eventually develop a hybrid system where
the fabric filter is physically located inside the existing ESP housing. AEERL has
recently patented and is currently licensing a hybrid system, Retrofit Electrostatic
Filtration. Figure 10 illustrates this concept where the last ESP stage is replaced by an
electrostatically augmented fabric filter (E8FF) array. Because particles tend to follow
electrostatic field lines rather than gas flow, the fabric penetration is one to two orders
of magnitude low-pr than, and pressure drops are only a fraction of that for, conventional
fabric filtration. The better features of ESP and fabric filtration are combined-no
reentrainment or sneakage, low pressure drops, and one to two orders of magnitude
more efficient dust collection.
CONCLUSIONS
The utility industry will likely face major challenges in implementing acid rain
provisions through the year 2000, and perhaps beyond 2000 as economics change and
new technologies become available. In anticipation of the need for cost-effective
technologies, AEERL has supported development of three S02 retrofit technologies,
one NOx retrofit technology, and a novel improved dust collection technology to meet
these needs. As implementation of strategies takes place and new problems arise,
AEERL will continue to sponsor research to minimize the cost of compliance.
REFERENCES
1. Princiotta, FX, Technological Options for Acid Rain Control," in The New
Clean Air Act: Compliance and Opportunity. Public Utilities Reports, Inc.,
Arlington, VA, pp. 112-130, June 1991.
2. Power. Vol. 134, No. 9, pp. 26-28, September 1990.
3. Nolan, P. et al, "Results of the EPA LIMB Demonstration at Edgewater," in
Proceedings: 1990 S02 Control Symposium, Vol. 1, EPA-600/9-91 -015a (NTIS
PB91-197210), pp. 3A-83-102, May 1991.
4. Clark, J. et al., "Status of the Tangentially Fired LIMB Demonstration Program at
Yorktown Unit No. 2," in Proceedings: 1990 S02 Control Symposium, Vol. 1,
EPA-600/9-91-015a (NTIS PB91-197210), pp. 3A-169-188, May 1991.
5. Redinger, K. et al, "Results from the E-SOx 5 MWe Pilot Demonstration," in
Proceedings: 1990 S02 Control Symposium, Vol. 4, EPA-600/9-91-015d (NTIS
PB91-197244), pp. 7A-71-89, May 1991.
8
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6. Becker, D. and I. DuBard, "Conceptual Designs and Cost Estimates for E-SOx
Retrofits to Coal-Fired Utility Power Plants," EPA-600/7-87-028 (NTIS PB88-
143995), December 1987.
7. Hall, B. W. et al.» "Current Status of the ADVACATE Process for Flue Gas
Desulfurization," JAWMA 42,103 (1992).
8. Borio, R.W. et al., "Long Term NOx Emissions Results with Natural Gas
Reburning on a Cyclone Fired Boiler," presented at the 1992 International Joint
Power Generation Conference, Atlanta, GA, October 18-22, 1992,
9. Keeth, R.T. et al., "Economic Evaluation of 28 FGD Processes," presented at the
1991 SC>2 Control Symposium, Washington, DC, December 3-6, 1991.
10. Castaldini, C., "Evaluation and Costing of NOx Controls for Existing Utility
Boilers in the NESCAUM Region," EPA-453/R-92-010 (NTIS PB93-142016),
December 1992.
11. Emmel, T. and M. Maibodi, "Retrofit Costs for SO2 and NOx Control Options at
200 Coal-Fired Plants, Volumes I-V," EPA-600/7-90-021 (NTIS PB91-133314),
November 1990.
12. Maibodi, M. et al., "Integrated Air Pollution Control System, Version 4.0,
Volumes Mil," EPA-6QQ/7-90-022 (NTIS PB91-506477), December 1990.
13. Power. Vol. 135, No. 12, p. 28.
14. U.S. Patent Office, Patent No. 5,159,580, October 27, 1992.
15. U.S. Patent Office, SN 67/826302, January 24, 1992.
16. Plate, N. and B. Daniel, "Advances in Electrostatically Stimulated Fabric
Filtration," in Proceedings: Seventh Symposium on the Transfer and Utilization
of Particulate Control Technology, Vol. 2» EPA-600/9-89-046b (NTIS PB89-
194047), p. 26-1, May 1989.
GLOSSARY
FGD Terminology (Figures 2» 3, and 4)
CSTR Continuous Stirred Tank Reactor
LSFO Limestone Forced Oxidation
LSWS Limestone Wet Scrubbing
LSINH Inhibited Oxidation
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LSDBA Dibasic Acid Enhanced Limestone Scrubbing
CT121 Chiyoda 121 Limestone FGD
PURE Pure Air (Mitsubishi) FGD
MGL Magnesium Enhanced Lime FGD
BSAF Bischoff-Essen Limestone FGD
S-H Saarberg-Hoelter Limestone FGD (Formic Acid Buffer)
KRC Noell-KRC/Research Cottrell Double Loop FGD
NSP Northern States Power Bubbler Scrubber
LDA Lime Dual Alkali
LSD A Limestone Dual Alkali
LSD Lime Spray Drying
LIFAC Tampella L1FAC (Furnace Injection and Spray Chamber)
CFB Lurgi Circulating Fluid Bed Absorber
FSI Furnace Sorbent Injection (LIMB)
EI Economizer Injection
DSI Duct Sorbent Injection
DSD Duct Spray Drying
ADV ADVACATE (ADVAnced SiliCATE)
N(X Terminology (Table 4)
OFA Overfire Air
LNB Low-NOx Burner
NGR Natural Gas Reburning
CCOFA Close-Coupled Overfire Air
SOFA Separate Overfire Air
Metric Equivalents
1 Btu = 1.056 kJ
1 lb = 0.454 kg
1 ton = 907.2 kg
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Table 1. SO2 and N0X Control Technologies for Coal-Fired Boilers
Technology
Description
Control, %*
S02 NO,
Estimated Commercial
Availability**
Comments
Wet flue gas
desulfurization
(FGD)
Limestone or lime in water
removes SO2 in a scrubber
vessel. Additives may be
used to enhance SOj re-
moval, A wet waste or
gypsum is produced.
70-97
Current for new boilers
and retrofit.
State-of-the-art for
higher S coal and FGD.
Certain retrofits diffi-
cult.
Dry FGD
Lime in water removes
SO5 in a spray dryer,
which evaporates the water
prior to the vessel exit.
Produces a dry waste.
70-95
Current for low to
moderate S coal for
new boilers. High S
coal retrofit, 5 yrs.
Demonstration for high
S coal retrofit is neces-
sary, but may be limit-
ed to 90% St>2 remov-
al.
E-SOx/io-duct
injection
Lime and water are inject-
ed in a boiler duct and/or
ESP (E-SOx) and react
with SO2 similar to a spray
dryer.
50-70
Pilot scale only. Dem-
onstrations required, 3-
7 yrs.
Potentially low cost
retrofits. May be site-
specific limits.
Advanced silicate
(ADVACATE)
Several variations. Most
attractive; adding lime-
stone to boiler, generating
lime. Lime/flyash collect-
ed in cylone and reacted to
generate highly reactive
silicate sorbent. Moist
sorbent added to down-
stream duct.
Up to 90
Pilot scale only. Dem-
onstrations required, 3-
7 yrs.
Most promising emerg-
ing retrofit technology.
Capable of 90% remov-
al with costs 50% of
wet scrubber.
Low NOx burners,
overfire air modi-
fications
Burner/boiler design con-
trols coal/air mixing to
reduce NOx formation.
40-60 Now, new boilers and
retrofit.
Additional retrofit
demonstrations desir-
able.
(Continued)
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Table 1, SO2 and NQX Control Technologies for Coal-Fired Boilers (Continued)
Technology
Description
Control, %*
*2>
Estimated Commercial
Availability**
Comments
Selective catalytic
reduction (SCR)
Reacts NO with NH^ over
a catalyst at 500-70(rF
(260-370°C).
0
80-90 Pilot plant only in U.S.
4 yrs.
Catalyst cost and life
main issues. Retrofit or
new, if demonstrations
in U.S.
Selective non-
catalytic reduction
(SNCR)
Reacts NO with NH-j in
furnace at 1400-1830°F
(760-1000°C)
30-60
Several demonstrations
completed.
NjO generation, NH3 slip,
and bisulfate fouling of air
heater are issues.
"Control efficiency is % reduction from emission levels for uncontrolled coal-fired power plants.
••Estimated commercialization for some technologies is strongly dependent on successful demonstrations.
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Table 2, Combined SC^/NO^ Control Technologies for Coal-Fired Boilers
Technology
Description
Control, %*
i°2L_
Estimated Commercial
Availability**
Comments
Limestone injection
multistage burners
Low NOx burners and
upper furnace sorbent
injection. May use hu-
midifkation to improve
SO2 capture and ESP per-
formance.
50-70
4M0
Wall, current;
T-ftred, 2 yrs.
T-fired wall-fired dem-
onstration complete.
Applicable to <3% S
coai retrofits.
Natural gas
reburning
Boiler fired with 80-90%
coal. Remaining fuel
(natural gas) is injected
higher in boiler to reduce
NOx. Air added to com-
plete burnout. Sorbent
may be injected to capture
Without sor-
bent, 10-20;
with sorbent
50-60 Demonstrations In
progress.
May be only combus-
tion NOx control for
cyclones. Sensitive to
natural gas price. New
or retrofit.
¦"Control efficiency is % reduction from emission levels for uncontrolled coal-fired power plants.
"Estimated commercialization for some technologies is strongly dependent on successful demonstrations.
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Table 3. Combined SC^/NO^ Technologies Near Commercialization
Control, %
S02 NOx
Commercial Status/Comments
90 90
90 90
95 90
5 MWe pilot plant in operation
5 MWe pilot plant in Clean Coal
Technology program
35 MWe pilot in CCT program; 1
unit in Denmark
95 75-95
90 70
85 80
90+ 90+
Commercial construction in Europe
Operational on 3 plants in Europe,
1 in Japan
20 MWe demo operating in Germany
Several vendors/processes; pilot-
scale systems in operation
90 30-70
3 MWe pilot plant in operation
Technology
Description
SNRB
NOxSO
NHj and lime/sodium injection upstream
of catalyst-coated baghouse
SC>2/NOx absorption on alumina in fluid
bed reactor
WSA-8NCL
MONO.
Activated char
DESONCL
Amine absorption
Ferrous chelate
additive
Catalytic reduction of NO and oxidation
of SO2 in two stages. Sulfuric acid
recovery
Ozone/NH-j promoted absorption of
SOj/NO^. in wet scrubber
NH3 injection and absorption of
SO2/SO3 on char; NO reduction
One step variant of W8A~SNOx above
Amine absorption of SO2 and NOx
followed by regeneration; acid
production
Ferrous chelate added to magnesium/
calcium FGD solubilizes NO
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Table 4. Retrofit N0X Control Costs for Coal-Fired 200 MWC Boiler
Estimated
Control Costs
Range in NOx
Total
Uncontrolled
Control
Capital
Levelized
Cost
Boiler Firing
NOx Control
NOx Level
Levels
Requirement
Busbar
Effectiveness
Type
Technology8
(lb/10^ Btu)
(lb/106 Btu)
($/kW)
(mifls/kWh)
($/ton)
Wall-firing
OFA
0.95
0.70 - 0.80
20
0.49 - 0.75
410 - 1,100
LNB
§.95
0.45 - 0.60
20
0.43 - 0.69
160 - 450
LNB + OFA
0.95
0.35 - 0.55
40
0.88 - 1.7
270 - 800
NGR
0.95
0.40 - 0.50
42
2,1 -2.9
710 - 1,200
Tangential-firing
LNB w/CCOFA
0.60
0.40 - 0.45
24
0.52 - 1.0
490 - 1,270
LNB fSOFA
0.60
0.30 - 0.45
30
0.67- 1.3
420 - 1,590
NGR
0.60
0.25 - 0.35
42
2.1 - 2.9
1,110-2,180
Cyclones
NGR
1.28
0.50 - 0.70
42
2.1 -2.5
500- 800
Wall-firing
SNCR
0.95
0.50 - 0.65
18
O
**5
i
s ON
590 - 1,100
LNB + SNCR
0.60
0.35 - 0.45
18
1.0- 1.4
760 - 1,680
SCR
0.95
0.15-0.25
192
7.0 - 12
1,650 - 3,220
LNB + SCR
0.60
0.10-0.20
148 - 192
5.1 - 12
2,100 - 4,970
Tangential-firing
SNCR
0.60
0.30 - 0.40
18
1.0- 1.4
630- 1,260
LNB+ SNCR
0.45
0.25 - 0.35
18
0.84 - 1.2
790 - 2,200
SCR
0.60
0.10-0.15
192
7.0- 12
2,600 - 4,970
LNB + SCR
0.45
0.05 - 0.10
148 - 192
5.1 - 12
2,200 - 6,370
a Technologies are defined In Glossary.
-------
cleaned gases*
storage silo
hyd rated lime
solids pump
botler
feeder
water
solids pum
in-duct
humidifier
a
bunker
windbox and
burners
air
coal
pulverizer
FD fan
water—#»
ash pit
*
PARTICULATE COLLECTOR
(codI ash and rooctsd chonnicsil)
fly ash vacuum system
I
bottom ash
to disposal
ash
silo
wate
PROCESS CHEMISTRY
2 CaO + 2 SO2 + 02 —2 CaSO 4
% pug mill
V
Figure 1. LIMB Process.
-------
MIXER
ESP/BAGHOUSE
BOILER
1
TO MIXER
STACK
TO MIXER
£
MIX
TANK
DISPOSAL
Figure 2. ADVACATE Process.
-------
WET THROWAWAY CAPITAL COSTS
250 —
200
$
*
8
«
150
100
50
LSFO LEWS LSINH LSDBA CT121 HIRE WGLM B5HF S-H KRC HBP IDA ISO*
VALUES ESTIMATED FROM OMGINAL DRAWIMSS
250
200
150
100
50
DRY THROWAWAY CAPITAL COSTS
RO %
90 %
90 %
LSD LIFAC CFB FSI El DSI DSD ADV
VALUES ESTIMATED FROM ORIGINAL DHAWWQS; TECHNOLOOCS D?MED M OLOMAHV
90 %
50 % 50 % — %
50 %
LSFO
Figure 3. Flue gas desulfurization capital costs,
retrofit 300 MWe» 2.6% S.
-------
WET THROWAWAY LEVELIZED COSTS
600
> 500
o
-------
9,000
¦ $15 Fuel Price Differential
A $5 Fuel Price Differential
1988 Constant Dollars
8,000 -
7,000
ir 6,000
-------
9,000 -|
¦ Wet FGD - NSPS
A Low Cost FGD
8,000 )988 Constant Dollars
7,000
S 6,000
cc
cs
§ 5,000
4,000
75% of Total MW
=> 2,000
50% of Total MW
25% of Total MW
1,000
80,000 100,000 120,000
20,000
80f000
0
40,000
Sum of MW
Figure 6. Summary of cost per ton of SOj removed results
for lime/limestone flue gas desulfurization.
-------
2,600
¦ 50% Removal
A 70% Removal
1988 Constant Dollars
2,400 -
_ 2,200 H
¦O
> 2,000 ~
® 1,800
o 1,800
° 1,400
c
1 1,200
g 1,000
75% of Total MW
800
50% of Total MW
\X^
25% of Total MW
600
400
200
100,000
40,000
60,000
80,000
20,000
0
Sum of MW
Figure 7. Summary of cost per ton of SO2 removed
results for furnace sorbent injection (LIMB).
-------
1,600
A LNB
* OFA
¦ NGR
1988 Constant Dollars
1,400-
1,200
800
600
75% of Total MW
50% of Total MW
400
25% of Total MW
200
20,000
40,000
0
Sum of MW
Figure 8. Summary of cost per ton of N0X removed
results for low N0X combustion.
-------
5
4.5
4
3.5
3
2.5
2
1.5
1
0.5
0
:l»tSd*MOVM,;;|
LUW-S COAL
LOW-S COAl"
¦ «WB»
CASE 1 CASE 2
FPD = Fuel Price Differential
This is based on an assumed reduction of
2.2 million tons between 1980 and 1985,
and 7.8 million tons from 1985 top 200
S02 emitting coal burning power plants.
SIMULATED
IJ MB
SO* SOjKEMOVAL
LOW SCOAL
• is mo
CASE 3 CASE 4
Figure 9. Annual cost of achieving a 10 million ton reduction of SO 2
per year from 1980 emission levels in the eastern region
of the United States.
-------
1.
PARTICLE LADEN GAS
9.
TUBE SHEET
2.
ESP FIELDS
10.
T/R POWER SUPPLY
3.
EXIT DUCT
11.
ESFF SECTION
4.
INLET DUCT
12.
PLENUM
5.
INLET TRANSITION SECTION
13.
OUTLET TRANSITION SECTION
6.
ESP HOUSING
14.
BAFFLE PLATE
7.
TRANSFORMER/RECTIFIER (T/R) UNITS
15.
ESFF HOPPER
8.
DIFFUSION PLATES
16.
HOPPERS
10
Figure 10. Retrofit Electrostatic Filtration.
------- |