United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-83-062 Feb. 1984
Project Summary
The Current Status of
Commercial Utility Flue Gas
Desulfurization Systems
G. P. Behrens and J. C. Dickerman
This summarizes a report on the
status of commercial flue gas desulfur-
ization (FGD) processes applied to coal-
fired utility boilers in the U.S. Major
objectives of this work were to examine
the impacts of the 1979 New Source
Performance Standards on FGD system
design and operation and to identify
recent improvements in the technol-
ogy. In the 4 years since the promulga-
tion of the NSPS, the wet limestone
process has been selected by utilities
for 75 percent of the new plant
capacity. In this time period, 77 plants
representing over 37,000 MW of
capacity have selected FGD systems.
Several major trends in the design of
limestone systems have become fairly
standardized. Nearly all new systems
are being built with spare absorber
modules to qualify for the NSPS
emergency bypass provisions. The
predominant absorber design is the
open spray tower, due to minimal main-
tenance requirements. Forced
oxidation to produce gypsum solids,
which can then be landfilled, is being
incorporated in many new units.
Selection of the spray drying process
for 15 percent of the new sites has also
occurred in the last 4 years. The
remaining throwaway and regenerable
systems have not experienced any sig-
nificant increases in applications.
Finally, organic acid addition has been
successfully demonstrated on lime-
stone systems to improve SO2 removal
and system reliability. Organic acid
addition is being used at two sites to
upgrade the performance of older
limestone systems.
This Project Summary was developed
by EPA's Industrial Environmental
Research Laboratory, Research Tri-
angle 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 order-
ing information at back).
Introduction
This report examines the current status
of flue gas desulfurization (FGD) systems
applied to coal-fired utility boilers to
control sulfur dioxide (SO2) emissions. It
documents changes in the design of FGD
systems which have occurred over the
years, specifically in response to the
requirements of the 1979 New Source
Performance Standards (NSPS) for utility
boilers. This information is useful to EPA
Regional Offices in evaluating SO2
control technology for new utility
applications, to the Office of Air Quality
Planning and Standards (OAQPS) in their
review of the 1979 NSPS, and to the
Office of Research and Development in
establishing research initiatives. This
information is also useful to architects,
engineers, vendors, utility companies,
and others interested in FGD technology.
-------
Objectives of this study were to examine
differences in the designs and applica-
tions of FGD systems applied to plants
subject to the 1971 and 1979 NSPS. The
basic difference between the two
standards is inclusion of a minimum
percent reduction requirement of SO2
emissions in the new standard. The 1971
standard limited SO2 emissions to 1.2 Ib*
SO2/million Btu of heat input. The 1979
NSPS requires a minimum of 70 percent
removal for all controlled emissions less
than 0.6 Ib SO2/million Btu. A sliding-
percentage removal scale is used as
sulfur levels increase. The maximum
emission limit under the new standard is
also 1.2 Ib S02/million Btu. Figure 1
shows the removal requirement of the
NSPS for different sulfur levels. The
major effect of the new standard has
been to require sulfur oxide
(SOx)emission controls for most low
sulfur coals which, under the 1971
standard, would not have required any
SO2 removal. The rationale behind the
decision to require SOx emission controls
for most coals is discussed in detail in the
Federal Register. Two major reasons
cited were to promote the use of the best
available FGD technology according to
provisions of the Clean Air Act, and to
maintain a competitive economic balance
between high- and low-sulfur coal pro-
ducing regions in the U.S.
FGD Technology Status
The most dominant trend in FGD
technology is the overwhelm! ng selection
of the limestone FGD process for new
units. Table 1 shows the status of the
various FGD technologies as of
September 1978, priorto promulgation of
the 1979 NSPS, and as of January 1983.
The equivalent scrubbed gas capacity (in
megawatts) and number of units are
presented for each process. The
percentage distribution (by megawatts) of
the various processes is also shown. The
totals presented are for units operating,
in construction , contracted, and planned
which have selected an FGD technology.
The processes in Table 1 are listed in
order of application over the last 3 years.
As can be seen, limestone systems have
been specified for 75 percent of the
capacity of these units. Spray drying
systems account for most of the remain-
ing units. The other throwaway and
Although EPA policy is to use metric units, certain
nonmetric units are used here for convenience.
Readers mor familiar with the metric system may
use the conversion factors at the back.
regenerable technologies show only
minor increases in application. The two
processes showing decreases represent
the shutdown of a magnesium oxide test
unit and a reduction in size of several
units which had planned (in 1978) to use
alkaline ash scrubbing. Of particular note
is the reduced use of the lime FGD
process: in September 1978, 25 percent
of the FGD capacity used the wet lime
process; however, in the next 3 years,
lime processes were specified at only 5
percent of the new units. Sixteen times as
many limestone systems were selected
as lime units in this interval. In 1978, the
ratio was two limestone systems to each
lime unit.
The decline in the use of lime systems is
due to: (1) the higher reagent cost of lime
7.4-
1.2-
a
$
-------
Table 1 . Comparison of FGD System Status in September 1978 and January 1983
September 1978 January 1983 Increase from 1978 to 1982
Process MW
Limestone 23,849
Spray Drying 400
Lime 12,065
Sodium Carbonate 884
Dual Alkali 1. 102
Wellman-Lord 1,855
Aqueous Carbonate 100
Citrate 60
Magnesium Oxide 846
Alkaline Ash-
Lime/Limestone 7,316
Total 48,477
for small size units or low sulfur fuels: in
both applications, the cost of lime is a
fairly small portion of the total revenue
requirement. However, the spray drying
process has recently attained
prominence in low sulfur applications,
due to anticipated favorable economics
and performance characteristics.
Therefore, the relative ranking of the wet
lime process will probably continue to
decline in future applications. Lime is the
predominant reagent used in the spray
drying systems, which may result in an
increase in industry's demand for this
reagent.
The regenerable systems (Wellman-
Lord, magnesium oxide (MgO), Citrate,
and Aqueous Carbonate) have not shown
any substantial increase in applications.
Part of the reason includes the develop-
mental nature of two of these processes,
as well as the higher costs associated
with regenerable systems in general.
Table 2 shows the distribution of pro-
cesses according to the emission require-
ments of each unit. Again, the totals are
for systems operating, in construction,
contracted, and planned.
Each process in Table 2, except MgO,
Aqueous Carbonate, and Citrate, will be
or have been used in commercial
applications to meet the 1 979 NSPS or a
more stringent state standard. However,
the selection of a process technology is
very site specific; not all processes are
applicable to every situation. The
following discussion outlines the range of
applications of each process and
Percent Percent Percent
Number MW MW Number MW MW Number MW
54 49.2 51,662 103 60.3 27.813 49 74.8
1 0.8 6.353 18 7.4 5.953 17 16.0
29 24.9 13.736 32 16.0 1.671 3 4.5
4 1.8 3,155 9 3.7 2,271 5 6.1
3 2.3 2.288 6 2.7 1.186 3 3.2
6 3.8 2.074 8 2.4 219 2 0.6
1 0.2 100 1 0.1
1 0.1 60 1 0.1
4 1.8 724 3 0.9 (122) (1) 1-0.3)
1± 15.1 5.493 13 6.4 (1.823) (1) (-4.9)
117 100.0 85.645 194 100.0 37,168 77 100.0
Table 2. FGD Systems and Regulatory Classifications - January 1983
Applicable Emission Standard. MW. (Number of Units)
More Stringent
Than 1971 NSPS.
More Stringent But Less Than Less Than
Process 1979 NSPS 1 971 NSPS Than 1979 NSPS 1979 NSPS 1971 NSPS
Limestone 27,461(45) 9.309(25) 7.239(14) 3.151(10) 4,502(9)
Lime 715(2) 4.551(10) 2.140(4) 5.486(12) 844(4)
Spray Drying 2.077(8) 1.180(3) 2.099(4) 887(2) 110(1)
Alkaline Ash-
Lime/ 'Limestone 475 (1) 1,374 (4) 1.979 (5) 1,665 (3)
Sodium Carbonate 1,900 (4) 375 (3) 330 (1) 550 (1)
Wellman-Lord - - 7,779 (4) 295 (4)
Dual Alkali 1.107 (3) 881 (2) - 300 (1)
Magnesium Oxide 724 (3)
Aqueous Carbonate - WO (1)
Citrate - 60 (1)
Total 33.735 (63) 17.73O (48) 15,566 (32) 13.058 (36) 5.556 (15)
comments generally on performance, requirements, environmental considera-
energy requirements, environmental tions, and reliability. Table 3 summarizes
effects, and reliability. these comments.
FGD Applications and Applications and Recent
Characteristics Process Improvements
Although most commercial FGD The limestone process is the
processes could be used at many types of predominant FGD system in use because
sites, generally the plants using the same of several factors. First, limestone
process have some similar characteris- deposits are, in many parts of the country,
tics which favor the use of the selected leading to low transportation and reagent
process. These trends are discussed, and costs. Second, limestone systems have
general comments are made on energy been in use longer than other types of
-------
Table 3. Qualitative Evaluation of Commercial FGD Processes
Process
Performance
Energy Requirements Environmental Considerations Reliability
Limestone
New systems are being de-
signed to meet the 1979
NSPS with high and low
sulfur coals. Additives
can be used to enhance
SO2 removal.
Moderate to high. Depends
on absorber pressure
drop, amount of grinding
required to prepare
limestone.
Produces large volumes
of sludge.
Historically the lowest
of commercial processes,
additives may improve
performance.
Lime
Traditionally lime sys-
tems are somewhat more
effective than limestone
units at equivalent operat-
ing parameters.
Moderate, since reagent
preparation does not
require grinding.
Produces large volumes
of sludge.
Better than limestone;
however, still can experi-
ence scaling and plugging.
Spray Drying
Currently only able to
meet NSPS for lower
sulfur fuels.
Very low because of small
pumping requirements
and no reheat require-
ments.
Dry waste product often
requires wetting for
disposal.
Insufficient data
base; however,
process simplicity
is an advantage.
Alkaline Ash
Limited to certain fuel
types, usually only low
sulfur coals.
Comparable to lime
systems.
Produces large volume
of fly ash/FGD sludge.
Comparable to lime
systems.
Sodium Carbonate
High SO2 removal
achievable.
Low due to high alka-
linity of reagent.
Large volume of soluble
waste produced. Requires
special disposal.
Very reliable due to
simplicity.
Dual Alkali
High SO2 removal
achievable on high
sulfur fuels.
Low due to high alkalinity
of reagent.
Large volume of sludge
produced.
Based on operating units,
most reliable commer-
cial system.
Wellman-Lord
Magnesium Oxide
High SO2 removal
achievable on high
sulfur coal.
High SO2 removal
achievable.
Fairly high because of
steam requirements and
gas for regeneration.
Moderate, coal can be
used in drying and
regeneration.
Produces sulfur, sulfuric
acid, and sodium sulfate,
saleable by-products.
Produces sulfuric acid.
Fairly good, but may
suffer somewhat due to
process complexity.
No commercial systems.
Prototype plants had
many mechanical problems.
processes; consequently, vendors and
utilities are familiar with them. Perhaps
most importantly, until the advent of
spray drying, limestone units were
typically the lowest cost process
available. Commercial experience has
also shown that limestone systems can
be used successfully on a wide variety of
fuels. Several innovations in process
design have become commonplace in
limestone process designs. The absorber
vessel is almost always an open spray
tower, which requires less maintenance
than packed towers. Forced oxidation of
the sludge produces better handling
solids and reduces the scaling potential of
the slurry. Additives such as magnesium
and organic acids are being used
commercially to raise the SO2 removal
closer to levels typically reached by more
reactive sodium and lime systems. This
flexibility has resulted in the large
number of limestone systems in use.
However, because of site specific factors
and utility preferences, other processes
have often been selected.
The most significant determinant of
process selection is probably fuel
composition, specifically sulfur level,
although chloride and ash levels are also
important. The sodium based processes
(dual alkali, Wellman-Lord) are good
candidates for high sulfur fuels because
of the high sorption capability of the
scrubbing liquor. A dual alkali system
vendor is now marketing a process using
limestone (rather than the more
expensive lime) as the regenerant to
improve process economics.
For low sulfur applications, spray
drying is currently the most popular
process, due to the reduced reagent
volumes needed and reduced capital
costs. Depending on the ash composition,
the alkaline ash process can also be used
in low sulfur applications, although no
new units are being planned for this pro-
cess. High chloride coals can cause both
process chemistry problems and
corrosion. A prescrubber before the SO2
absorber is often used to remove the
chloride, although it can cause serious
corrosion.
Land availability favors the regenerable
over the throwaway processes such as
the Wellman-Lord and MgO systems.
These processes produce saleable by-
products rather than throwaway sludges.
The local availability of a reagent also
affects process selection. All sodium
carbonate systems are near natural
deposits of the material. If transportation
costs are a major portion of the delivered
reagent price, lime can have an
advantage over limestone because of its
greater reactivity per pound.
Water availability is often cited as a
factor in FGD process selection; however,
all processes use nearly the same
4
-------
amount of water. Spray drying may use
slightly less water because the flue gas is
not totally saturated; however, the dry
waste product is moistened before
disposal. The water requirements of the
FGD system are typically less than 10
percent of the plant's total requirement. A
more important consideration is the type
of water used in the FGD system.
Throwaway systems can generally tole-
rate poorer quality water than
regenerable systems.
Energy Requirements
Energy requirements for FGD systems
vary significantly, depending on the
basis for analysis. For example, electrical
and steam requirements for commercial
processes have been generally shown to
increase as follows (lowest to highest):
spray drying, sodium carbonate, dual
alkali, alkaline ash, lime, limestone, MgO,
and Wellman-Lord. The energy
requirement as a percentage of new
power plant output is often reported to be
less than 1 percent for sodium svstems,
normally about 3 percent for limestone
systems (excluding reheat), and even 10
percent for some regenerable units. The
problem with comparing the energy
consumption required by the FGD system
alone is that it does not reflect the energy
required to process the reagents or the
sludge, nor does it include any by-product
energy credit. These energy
requirements are reflected in the reagent
cost and by-product credits.
A TVA study examined the ground-to-
ground energy requirements of three
FGD systems. The design basis was a 500
MW unit burning 3.5 percent sulfur coal
meeting the 1971 NSPS. Results for the
three systems are shown in Table 4. The
lime system had the lowest energy
requirement if only the FGD system is
considered. However, the energy
required to calcine limestone into lime
(which is reflected in the price of lime) is
significant. When all of these energy
requirements are considered, the
limestone process has the lowest energy
requirement. The credit for sulfuric acid
in the MgO process reflects the energy
required to mine and convert an
equivalent amount of elemental sulfur.
This credit makes the regenerable
process almost as efficient as the lime
system. Since spray drying and dual
alkali systems use lime, their overall
ground-to-ground energy requirements
are much closer to the other systems than
would be indicated by just comparing the
FGD system energy requirement.
Environmental Considerations
The six commercial throwaway FGD
systems produce large volumes of waste
material requiring disposal. The calcium
based sludge from the limestone, lime,
alkaline ash, and dual alkali processes
are very similar in composition. Typically,
this sludge is disposed of in a clay-lined
pond. A thickened slurry is pumped to the
pond where the solids settle out.
Supernatant water is usually returned to
the FGD system. Many of the newer
plants are using landfilling for disposal. In
this practice, the sludge is vacuum
filtered or centrifuged to a higher solids
content, and mixed with lime and/or fly
ash to form a stable mass. In either
installation, a liner material is used to
prevent ground water contamination due
to leachate from the sludge.
Solid waste from spray drying, if lime is
used as the reagent, is also similar to the
material described above, except that it is
a dry powder. However, to dispose of this
Table 4. FGD Ground-to-Ground Energy Requirements
Btu/lb Sulfur Removed
Function
Mining
Absorbent Processing
Transportation
FGD
Waste Disposal
By-product Credit
Total
Btu/kWh
% Gross Power Unit Output
Limestone
438
176
J 4.042
22
14.678
291
3.2
Lime
356
6.198
143
13.165
15
19,877
395
4.4
Magnesium Oxide
25
161
33
26.387
(5,491)
21.115
420
4.7
waste, it is often wetted to increase its
compressive strength and to reduce
dusting problems. Several research
programs are being sponsored by the EPA
and EPRI to determine the best methods
of disposing of spray drying wastes.
The sodium carbonate process
produces a liquid purge stream high in
sodium sulfites and sulfates. The plants
which use the process, use evaporation
ponds to crystallize the salts. This
technique is only applicable in arid
regions. Pond liners may also be
necessary to prevent ground water
contamination.
The regenerable processes have a
much smaller secondary environmental
impact since they produce by-products
which are sold to user industries.
However, lime and limestone processes
may be designed to produce gypsum wall
board or other by-products if desired.
Reliability
The reliability of an FGD system is a
major concern to utilities operating plants
subject to the 1979 NSPS. Older plants
and regulations often allowed bypassing
flue gas around malfunctioning absorber
modules or the entire system. However,
the 1979 NSPS has significantly reduced
the possibility of bypassing the FGD
system except in emergencies. The final
standards allow an owner or operator to
bypass uncontrolled flue gas around a
malfunctioning FGD system if: (1) the
FGD system has a built-in spare FGD
module, (2) enough FGD modules are not
available to treat the entire quantity of
flue gas generated, and (3) all available
electric generating capacity is being
utilized in a power pool or network
consisting of the generating capacity of
the affected utility company (except for
the capacity of the largest single
generating unit in the company), and the
amount of power that could be purchased
from neighboring interconnected utility
companies. From the constraints
expressed in the third requirement it is
evident that utility companies are
expected to install reliable FGD equip-
ment. This requirement also places an
economic incentive on the utilities to
obtain reliable operation from their FGD
systems, since the available electric gen-
erating capacity will often include
uneconomic gas-fired turbines and oil- or
gas-fired boilers.
The few operating units regulated by
the 1979 NSPS have not experienced
enough operating time to determine if
they are more reliable than older units.
-------
Several studies have addressed the
reliability of some of the older units. A
study by the National Electric Reliability
Council (NERC) has categorized causes of
outages for 400 MW and larger FGD
systems. Results of the study are given in
Table 5. As can be seen, two-thirds of the
outage time was caused by non-specific
FGD technology problems. This indicates
that FGD processes often suffer a poor
reliability image because of peripheral
equipment failures rather than process
related problems.
Table 5. Percent of Plant Outage Time
Caused by Specified FGD Compo -
nent Failure (NERC Data)
Table 6. Dependabilities of FGD Systems (March 1981-March 1982)
Component
Percent of
Outage
Time-
Dampers 28
Duct system, baffles 19
Absorber tower 16
Fans, ID. FD, blades, vibration 17
Mist eliminator 9
Reaction tank 4
Spray pumps 3
External causes 2
Thickener 1
Test programs 1
An FGD data base, maintained for the
EPA by PEDCo, contains information on
availability and operability of individual
plants. The average availability and
operability of the commercial FGD
processes are presented in Table 6, along
with definitions of the two terms. The
availability index can be artificially high if
the boiler is not in operation although the
FGD system could operate. The
operability index is a more accurate
estimates of the reliability of the various
processes since it involves the actual
time that the boiler is operated. It can be
lowered, however, if a decision is made
not to operate the FGD system.
Table 6 indicates that limestone and
lime systems are generally the most un-
reliable processes. However, it is difficult
to compare reliability data of various
processes because of differences in plant
designs and operating requirements. No
data are available from plants regulated
by the 1979 NSPS. Very few operating
systems in the EPA/PEDCo data base
have spare modules which increase
reliability. Additionally, the design differ-
ences make it difficult to compare
reliability figures. New units are
incorporating design improvements
obtained from experience with existing
Process
Limestone
Lime
Wellman-Lord
Alkaline Ash
Sodium Carbonate
Dual Alkali
Number of
Operating
Systems
39
24
7
9
5
3
Systems
Included
in Averages
24
23
7
6
4
3
Availability*
73.5
84.1
88.5
89.3
89.9
96.2
Operability**
73.8
75.4
70.0
78.0
87.4
79.7
Percentage of hours the FGD system is available for operation (whether used or not) divided by
the hours in the period.
* Percentage of hours the FGD system was operated divided by the boiler operating hours during
the period.
systems. Many of the older limestone and
lime systems with poor designs are
included in the averages. Their recurring
problems reduce the reliability figures for
the process. Consequently, the construc-
tion of new units should produce a
gradual increase in overall process
reliability. The effects of a new technol-
ogy, such as the use of adipic acid with
limestone systems, can also significantly
improve the reliability of a system.
However, it is difficult to quantify in
advance the magnitude of reliability
increases due to process improvements.
A recent study examined the effect of
forced outages of scrubber modules on
utility system production costs. Two
different utility fuel-mix systems were
analyzed. The results indicate that, in
many instances, the addition of a second
spare module is economically justified.
For the system based primarily on coal
capacity (49 peu'ent coal, 24 percent oil),
module outage time greater than 14
percent favors using a second spare. In
the oil-based system,(19 percent coal, 57
percent oil), two spare modules are justi-
fied above a 10 percent module forced
outage rate. The assumptions used in this
study are site specific; however, they do
provide an interesting perspective on reli-
ability. However, the most crucial piece of
data, the actual module outage rate for a
well designed system, is not given.
Economics
The costs of FGD systems are very site
specific. Coal composition, degree of
control required, and economic bases all
have a major influence on the reported or
estimated costs. Consequently, the
actual cost of a "standard" FGD system
can vary considerably, leading to
confusion as to what the actual costs are.
Several recent reports have estimated
the costs of various FGD processes for a
standard size plant by examining the
various design and economic bases. TVA
has published the most recent economic
study of limestone and lime systems,
using a mid-1982 time basis for capital
costs. The standard plant is a 500 MW
unit burning 3.5 percent sulfur bitumi-
nous coal meeting the 1979 NSPS. A
bypass duct capable of handling 50
percent of the flue gas is also included.
Although many site specific factors affect
the capital cost of an FGD system, four
parameters account for most of the cost
differences between estimates for a
standard size plant and fuel: the estimate
date, use of a spare module, bypass ducts,
and the S02 removal requirement.
Examining the various site-specific
cost factors used to estimate the costs of
several FGD systems, and adjusting the
factors to a common basis, can produce a
fairly consistent set of cost estimates. The
results of this exercise are shown in Table
7, and in Figures 2 and 3. As shown in
Table 7 and Figure 2, the raw
(unadjusted) cost estimates reported for
six commercial FGD processes vary
considerably. However, when these
estimates are adjusted to a common
basis (Figure 3) the variance in the
estimate significantly decreases.
Costs were adjusted, using the
Chemical Engineering plant cost index to
adjust for inflation. A spare module and
associated equipment for a 500 MW unit
was assumed to increase capital costs 25
percent. Bypassducts increased the costs
5 and 10 percent, respectively, for 50 and
100 percent bypass. Increasing the S02
removal from the 1971 to the 1979 NSPS
was estimated as a 5 percent increase.
As shown in Table 7, the 1982 cost of
most of the FGD systems is about
$200/kW. The average costs show the
same relative rankings as in individual
reports which estimate several processes.
Lime systems have the lowest capital cost,
followed by limestone and dual alkali
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Table 7. Estimates of FGD
System Costs
and spray drying are usually the
expensive, followed by lime and
flange of
Number
Unadjusted
of Cost
Process
Limestone
Lime
Dual Alkali
Estimates
Spray Drying*
Wellman-Lord
Magnesium
Oxide
5
3
2
3
4
Costs.
$/kW
Average of
Unadjusted
Costs.
$/kW
98-206
90-192
101-166
102-200
126-267
162
144
134
165
176
Range of
least
dual
Average of alkali, and then, the regenerable systems.
Adjusted
Costs,
$/kW
169-240
155-193
174-214
176-248
181-345
Adjusted The EPA/PEDCo
utility
Cosrs, compiles reported cost data
$/kW systems and adjusts
the
FGD survey
on operating
costs
to a
203 common basis. Averages of the different
processes are shown in Table 8. The low
sulfur systems have the lowest capital
734 and operating costs.
The high sulfur lime-
stone, lime, and dual alkali units all cost
208 between $140 and $150/kW. Since
246 these are operating systems, they are
predominantly units designed for the
4
132- 193
159
195-227
1971 NSPS, with no spare modules or
^ kwnnnf rlim+n nn~J n !»...__ O/-» 1
*Costs include a baghouse for paniculate control. An ESP would be used for the other FGD systems requirement Using the previous cost
($38/kW) but was not included in the process cost estimates. multipliers results in a 1 982 cost of $200-
processes. The regenerable systems are
20-30 percent higher. The spray drying
systems include integral particulate
control, and have an average cost of
$208/kW. ESPs for the other processes
will add about 20 percent to the total air
pollution control equipment cost. Note
that the designs
of the spray drying units
have not been successfully demonstrated
for high-sulfur coal.
360
340
320
300
280
260
240
220
200
., 1 on
;*c / OU
w- 160
w
3 740
720
80
60
40
20
0
-
-
-
-
-
-
-
-
_
-
-
.
.
-
___
Limestone
Systems
The annual costs of the different FGD 220/kW, which is very close to the
processes depend as much on capital estimated costs previously presented. As
charges as fixed and Variable operating can be seen- wnen tne costs are P|aced on
costs. There are too many variables a common basis, they agree very well.
(reagent costs, interest rates,
operating profile return on
labor rates, __
investment SO2 Removal Test
Results
(ROI), etc.) to use a simplistic approach to Before promulgation of the
1979
present standardized annual costs as was NSPS, the EPA performed emission tests
done for the capital costs. In individual on various types of FGD systems. These
reoorts using the same bases, limestone units were built to meet the 1971 NSPS
Lime
Systems
^~"
Dual
Alkali
Systems
i
Spray Wellman-Lord
j^
CM
IQ
CM
W
°9
Magnesium
Drying Systems
Systems
Oxide
Systems
Figure 2. Raw estimates of FGD system costs.
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o
o
360
340
320
300
2SO
260
240
220
200
180
160
140
120
100
80
60
40
20
0
-
-
-
-
-
-
-
-
-
-
_
-
fx
10
(M
?
Limestone Lime Dual Spray Wellman-Lord Magnesium
Systems Systems Alkali Drying Systems Oxide
Systems Systems Systems
Figure 3. FGD system cost estimates adjusted to consistent basis.
Table 8. Average Costs of Operating FGD Systems (1981 Dollars)
Process
Limestone-Low Sulfur*
Lime-Low Sulfur
Sodium Carbonate
Alkaline Ash
Dual Alkali
Limestone-High Sulfur**
Lime-High Sulfur
Wellman-Lord
Number of
Units
16
5
4
7
3
7
15
3
Capital Cost
$/kW
79
72
111
118
147
149
141
272
Annual Cost
mills /kWh
4.8
5.1
6.4
6.7
8.7
9.2
10.5
18.1
* Low sulfur - < 1.5 percent.
**High sulfur -> 1.5 percent.
or state standards, which were not as
stringent as the current NSPS. However,
many of the units tested meet the 1979
NSPS, or are very close to satisfying its
requirements. Based on these test re-
sults, EPA set the new standard at a level
attainable by current technology. The
sites tested and test results are shown in
Table 9. In addition, a comment column
indicates the SO2 removal level that
would be required for each site to achieve
compliance with the 1979 NSPS. As can
be seen, 7 of the 13 units built under
more lenient standards meet the current
NSPS. Several of the other units were
within a few percentage points of
meeting the standard. Consequently,
designing and operating an FGD system
to meet the 1979 NSPS required only a
moderate advance in the status of FGD
technology.
Two readily apparent deficiencies in
the continuous emission monitoring
results data base need to be recognized:
(1) the limestone systems tested were not
typical of those being designed and built,
predominantly using spray towers; and
(2) the growing 'acceptance of spray
drying by the utility industry indicates
that a number of these units should also
be tested.
Conclusions
The 1979 NSPS for utility boilers
requires FGD systems on all new coal-
fired boilers. Since initial promulgation
on September 18,1978, 73 FGD systems
representing over 35,000 MW of capacity
have been constructed, contracted, or
planned by the utility industry. In the
previous seven years, 48,000 MW (117
units) had been built with FGD systems.
8
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Table 9. FGD System Continuous Emission Monitoring Results
Process
Unit
Emission
SO2 Removal Rate
Efficiency Ib SO2//06
percent Btu Comments
Limestone
Lime
Dual Alkali
Wellman-Lord
Magnesium Oxide
Spray Drying
Shawnee V/ST*
Lawrence 4
Southwest 1
Cane Run 4
Conesville 5
Bruce Mansfield 1
Shawnee TCA
Pleasants 1
A.B. Brown 1
Cane Run 6
D.H. Mitchell 1 1
Eddy stone 1A
Celanese Amcelle^
96.1
96.6
>90
83.8
89.2
85.3
88.6
>90
87.7
91.6
89.6
96.8
70.0
0.22
0.03
<0.64
0.88
0.80
0.78
0.64
<0.50
0.85
0.70
0.60
0.16
0.92
meets 1979 NSPS
meets 1979 NSPS
meets 1979 NSPS
88.8% removal needed
for 1979 NSPS
90.0% removal needed
for 1979 NSPS
88.5% removal needed
for 1979 NSPS
89.3% removal needed
for 1979 NSPS
meets 1979 NSPS
90.0% removal needed
for 1979 NSPS
meets 1979 NSPS
meets 1979 NSPS
meets 1979 NSPS
80.4% removal needed
for 1979 NSPS
*Units tested with adipic acid additive.
VndustrM boiler, utility SO2 NSPS not directly comparable.
Since the promulgation of the 1979
NSPS, the wet limestone FGD process
has been selected for nearly two-thirds of
the future plants. The predominance of
this process is due to its technical
flexibility and favorable economics.
Improvements in reliability and efficiency
(due to the use of spray towers, forced
oxidation, and SO2 removal enhance-
ment additives} enable the limestone
process to be used in many applications.
The use of spray drying to control SO2
and particulates from lower sulfur coal is
the only other technology to be widely
favored in the industry. Many commercial
spray drying systems will soon be on-line
demonstrating this technology. The other
throwaway systems (lime, dual alkali,
alkaline ash, sodium carbonate) will
probably be used infrequently at new
plants. Higher reagent costs are the
primary reason for the lack of new orders
for these systems. The regenerable
systems, due to their higher costs, will
probably be used only in specialized
applications; e.g., land-restricted sites
and those with favorable S02 regenera-
tion opportunities.
Conversion Factors
Nonmetric Times Equals Metric
G. P. Behrens andJ. C. Dickerman are with Radian Corp., Austin, TX 78766.
J. David Mobley is the EPA Project Officer (see below).
The complete report, entitled "The Current Status of Commercial Utility Flue Gas
Desulfurization Systems," (Order No. PB 84-133 016; Cost: $20.50, 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:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
Btu
Btu/lb
lb/106 Btu
1055
2326
430
J
J/kg
ng/J
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ft US. GOVERNMENT PRINTING OFFICE: 1984-759-102/87
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