U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78-032d
Off ice of Research and Development Laboratory «n^o
Research Triangle Park, North Carolina 27711 (vldCCR 1978
FLUE GAS DESULFURIZATION
SYSTEM CAPABILITIES FOR
COAL-FIRED STEAM GENERATORS
Volume I. Executive Summary
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-032a
March 1978
FLUE GAS DESULFURIZATION SYSTEM
CAPABILITIES FOR COAL-FIRED
STEAM GENERATORS
Volume I. Executive Summary
by
T. Devitt, R. Gerstle, L. Gibbs,
S. Hartman, and R. Klier
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2603, Task No. I
Program Element No. EHE624
EPA Project Officers:
John E. Williams and Kenneth R. Durkee
Industrial Environmental Research Laboratory Emission Standards and Engineering Division
Office of Energy, Minerals, and Industry Office of Air Quality Planning and Standards
Research Triangle Park, N.C. 27711 Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
and Office of Air and Waste Management
Washington, D.C. 20460
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CONTENTS
Figures iv
Tables iv
History of FGD Systems 2
Application of FGD Systems 4
FGD Systems and Their Efficiency 8
Lime and Limestone Scrubbing 8
Wellman-Lord Process 15
Magnesium Oxide Systems 17
Double Alkali Flue Gas Desulfurization Systems 19
FGD System Efficiency Summary 21
FGD System Operation 23
Lime Systems 27
Limestone Systems 29
Operating Problems and Solutions 3C
Scaling and Plugging 30
Erosion and Corrosion 32
Equipment Design 33
FGD System Manufacturer Capability 36
iii
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FIGURES
Number
1 Actual and design emissions vs potential emissions for
existing and planned FGD systems subject to NSPS or
more stringent regulations 7
2 Average plant FGD availability/operability versus plant
start-up date 24
3 Average availability for selected FGD systems 28
TABLES
Number Page
1 Number and Capacity of U.S. Utility FGD Sys terns--
August 1977 5
2 Number and Capacity of FGD Systems and Their
Regulatory Classifications 6
3 Plants Reporting 90 Percent or Greater SC>2 Removal 22
4 Identification of Plants in Figure 2 25
5 Calculated FGD System Availability Based on Number
of Scrubber Modules 26
6 Manufacturers Responding to the Flue Gas Desulfur-
ization System Capability Study and the Process
Offered by Each 37
iv
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EXECUTIVE SUMMARY
This project was undertaken, at the request of the U.S.
Environmental Protection Agency (EPA) to evaluate SO-
emission control techniques. It is part of EPA's overall
program to review New Source Performance Standards for coal-
fired steam generators. Specifically, the project examined
maximum SO2 emission control levels attainable with demon-
strated techniques which include low-sulfur content coal,
coal conversion processes, physical and chemical coal
cleaning, and flue gas desulfurization (FGD) systems. Flue
gas desulfurization systems were emphasized, since the other
control techniques are being studied elsewhere by EPA.
The main emphasis of this study was the objective
appraisal of FGD systems with respect to both S0~ removal
potential and system operability. This appraisal was made
by reviewing the performance of operating systems and the
features of new systems designed to alleviate previous
problems.
The study reviewed five major FGD processes in detail.
The impact of key design parameters on removal efficiency
and process operability was investigated, from a theoretical
point of view and by using data from operating systems. In
addition to process design and operation, the operating
experience of major FGD installations was reviewed. Operating
problems and their solutions were analyzed with respect to
their impact on process operation. This assessment included
major systems in both the United States and Japan. In
addition, research studies were selected and their data used
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to evaluate the status of process development and the
potential for sustained system operation and high removal
efficiencies.
It was concluded from this investigation that the major
systems, comprising lime and limestone slurry, Wellman-Lord,
magnesium oxide scrubbing and double alkali processes, are
capable of removing SO2 with efficiencies in excess of 90
percent when applied to both high- and low-sulfur coal
combustion facilities. Such results have been obtained in
pilot, prototype and full-scale systems. Though sustained
operation at high SO_ removal efficiencies has not been
widely achieved, a basis for design of such systems has been
developed. When required, new systems are being designed
for 90-percent removal efficiency, and an availability of
90-percent or greater.
This Executive Summary gives a brief history of FGD
systems, followed by information on FGD applications and
planned installations. This summary then presents infor-
mation on FGD system problems and solutions, operability,
and the design factors affecting efficiency. The capability
of equipment manufacturers to supply equipment to meet
alternative S02 emission standards is also summarized.
4
HISTORY OF FGD SYSTEMS
The concept of scrubbing flue gases from coal-fired
boilers and other industrial processes is not new. In 1926,
the 125-MW coal-fired Battersea Power Station in London,
England, was equipped with a spray-packed tower and an
alkaline wash section. The process was more than 90-percent
efficient in the removal of S02 and particulate from the
combustion gas of coal with a sulfur content of 0.9 percent.
Lime-based systems for removal of sulfur dioxide were
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installed at the Swansea power plant in 1935 and at the
Fulham power plant in 1937. The first lime scrubber in
Japan started up on a large sulfuric acid plant in 1966.
In the United States, the Tennessee Valley Authority
(TVA) conducted small-scale and limited pilot plant studies
in the 1950's. The first major pilot plant work appears to
have been that of Universal Oil Products (at a Wisconsin
utility installation), beginning in 1965. Limestone slurry
circulating through a mobile-bed scrubber treating 0.94 m /s
(2000 acfm) gave good SO2 removal.
In 1966, Combustion Engineering tested a technique
involving injection of limestone, followed by scrubbing, in
a pilot unit [1.4 m /s (3000 acfm)] at a Detroit Edison power
plant. At a stoichiometric limestone-to-SO- ratio of 1.1 to
1, SO2 removal was 98 percent. On the basis of this pilot
plant work, the company offered the process to the utility
industry and five systems were installed. One installation
was at the Union Electric Co. in St. Louis, Missouri (140
MW). Kansas Power and Light Co. installed one on a 125-MW
boiler in Lawrence in 1968; another on a 400-MW unit at the
same plant started up in 1971. Kansas City Power and Light
has used the process on two boilers, one at 100 MW, the
other at 140 MW.
Because of major problems associated with dry limestone
injection, these systems proved inadequate. The Union
Electric installation has been abandoned, and the Kansas
Power and Light systems are being replaced by a technique in
which a limestone slurry is introduced into the scrubber.
The Kansas City Power and Light installations are being
converted to lime scrubbing. Problems associated with
limestone injection include plugging (especially of the
boiler tubes), low S02 absorption, and reduced particulate
collection in the electrostatic precipitators.
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Since then, considerable progress has been made in
developing both lime/limestone and other alkali based
scrubbing processes. A significant number are already
operating on coal-fired boilers, and even more are scheduled
for operation in the next few years. Other processes that
incorporate major design and operating changes, and thereby
differ significantly from conventional direct lime/limestone
systems have been evaluated at pilot and prototype develop-
ment levels, and a few systems have progressed to the
installation and operation of demonstration units. A rapid
evolution of technology is thus occurring in the FGD tech-
nology area.
APPLICATION OF FGD SYSTEMS
Table 1 summarizes the number and capacity of FGD
systems on utility boilers in the United States as of August
1977. Of these systems, 29 were operational (8,914 MW) ; 28
were under construction (11,810); and 68 systems were planned
(32,628 MW). This table omits 16 installations (8,592 MW)
whose operators are considering FGD as well as other control
systems (low sulfur coal, for example). Some 12 to 15
boilers (6000 MW) that are definitely planning to use FGD
systems are excluded, because the information is not ready
for public release. Also shown in the table are 16 systems
(1488 MW) that have been shut down for various reasons.
Several of these were demonstration systems; others were
based on first-generation technology.
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Table 1. NUMBER AND CAPACITY OF U.S.
UTILITY FGD SYSTEMS - AUGUST 1977
Number
Status of units
Operational
Under construction
Planned
Contract awarded
Letter of intent signed
Requesting/evaluating bids
Considering FGD (pre-
liminary design stage)
Shutdown
29
28
23
5
5
35
16
Capacity,
MW
8,914
11,810
11,880
1,892
2,825
16,031
1,488
There have been significant changes in the status of
FGD systems between 1974 and 1977:
0 The number of operational systems has increased
from 19 to 29.
0 The average unit size has increased from 173 MW to
307 MW.
The megawatt capacity associated with operational
lime and limestone systems has increased from 80
percent to over 90 percent of the total.
0 The capacity of FGD systems associated with
full-scale boilers has increased from 2,360 MW
to 8,914 MW.
Table 2 summarizes the FGD systems according to the
regulatory standards the facility must meet. Of the 125
operational and pending systems, 57 (23,930 MW) are designed
to meet state standards that are more stringent than the
current Federal New Source Performance Standard (NSPS).
Forty-four systems (22,728 MW) are designed to meet the NSPS
and 21 systems (5,819 MW) are designed to meet regulations
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less stringent than the NSPS. Of 29 operational systems,
more than half (approximately two-thirds of the equivalent
megawatts) are meeting standards more stringent than the
current NSPS requirement. Figure 1 shows the actual and
design SO2 emission rates for FGD systems which meet or
exceed current NSPS requirements.
Table 2. NUMBER AND CAPACITY OF FGD SYSTEMS AND
THEIR REGULATORY CLASSIFICATIONS
Regulatory classification
Federal NSPS
More stringent than Federal NSPS
Less stringent than Federal NSPS
Undetermined
Total
Systems
44
57
21
3
125
Capacity, MW
22,728
23,930
5,819
875
53,352
ii t
Also of interest are the data on the use of high- and
low-sulfur coal. Because of the imprecision of the terms,
"low-sulfur" coal has been defined for this purpose as any
coal that emits up to 520 ng/J (1.2 lbs/106 Btu) of SO9
when burned; "high-sulfur" coal is any coal that produces
higher emission values. Using these definitions, the
following observations hold:
0 Among the operating systems, approximately 85
percent of the equivalent electrical megawatt
capacity is on high-sulfur coal.
0 Among the systems under construction, approxi-
mately 75 percent of the equivalent electrical
megawatt capacity is for high-sulfur coal applica-
tion.
0 With regard to planned systems, approximately 90
percent of the equivalent electrical megawatt
capacity involves high-sulfur coal application.
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2.0
1.5 -
.02
.5 .6 .7 .8 .9 1.
1.5
2. 2.5 3. 4. 5. 6. 7. 8. 9. 10
POTENTIAL EMISSIONS (LBS S02/106 Btu HEAT INPUT)
Figure 1. Actual and design emissions vs potential
emissions for existing and planned FGD
systems subject to NSPS or more stringent
regulations.
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FGD SYSTEMS AND THEIR EFFICIENCY
Flue gas desulfurization is the process of removing S02
from combustion gases. Flue gases are brought in contact
with a chemical absorbent in a unit known as an absorber or
scrubber which reacts chemically with the S02.
Flue gas desulfurization processes are categorized as
regenerable or nonregenerable depending on whether sulfur
compounds are separated from the absorbent as a by-product
or disposed of as a waste. Nonregenerable processes produce
a sludge that requires disposal in an environmentally sound
manner. Regenerable processes have additional steps to
produce by-products such as liquid SO2/ sulfuric acid/ and
elemental sulfur. The nonregenerable group includes lime
and limestone, sodium carbonate and double alkali scrubbing
techniques. The regenerable systems currently in operation
are typified by the magnesium oxide and the Wellman-Lord
systems. The following sections briefly describe these
processes, their efficiency and reliability, and present
information on their performance at selected installations.
Lime and Limestone Scrubbing
Lime slurry scrubbing is a wet scrubbing process that
uses a lime slurry to react with SO2 in the flue gas. Lime
is fed into the system, combined with water to form a
slurry, which is then contacted with the flue gas to absorb
S02- Sulfur dioxide reacts with the slurry to form calcium
sulfite and sulfate, which are removed from the system as
sludge. The limestone slurry scrubbing process is similar,
although it uses limestone rather than lime as the reagent.
Facilities using lime and limestone systems have reported
both long and short term S02 removal efficiencies in excess
of 90 percent in the United States. Both have successfully
operated on high- and low-sulfur coal-fired applications.
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Many operating lime and limestone systems were designed
for SO2 collection efficiencies of less than 90 percent,
since this was all that was required to meet an applicable
regulation. Often an efficiency in the range of 60 to 70
percent was sufficient, and such values were used to estab-
lish system design. Extensive experimental data relating
SO_ removal efficiency to FGD system operating parameters
are not available from any of the existing full scale sys-
tems; therefore, data from pilot or prototype units must be
used for conclusions concerning higher removal capabilities.
Design of newer systems which are required to achieve
high efficiency must take into account a number of key
design variables including:
0 inlet S02 concentration
0 liquid to gas ratio
0 scrubber gas velocity
0 scrubber liquor inlet pH
0 type of absorber
0 magnesium content
Higher removal efficiencies can be more easily achieved
at lower S02 inlet concentrations because the amount of S0_
that must be absorbed per unit of scrubbing liquor to
achieve a specified outlet concentration is smaller. At low
SO- concentrations the alkali in the liquor can react with a
greater percentage of the S02 and affect a greater removal
efficiency under a given set of operating conditions.
Higher efficiencies are realized at higher liquid to
gas (L/G) ratios for lime and limestone systems. For a
given absorber, increased L/G ratios will yield higher
efficiencies until flooding and poor gas distribution occur.
For new designs, absorbers which can accommodate high L/G
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ratios can be selected and high efficiency maintained.
Higher liquid ratios also require larger pumps, pipes, and
slurry reaction tanks. Again, these can be designed into
the system and should cause no unusual operating problems.
The effects of changes in flue gas absorber velocity on
S0« removal efficiency, when other variables are kept con-
stant, vary with the type of absorber. For a spray tower,
the efficiency decreases at a fixed L/G ratio. This effect
is much less noticeable on packed and turbulent contact type
absorbers. For a new plant, the scrubber would be designed
for the required L/G when considered along with other design
parameters.
Increased efficiency is achieved at higher pH since
more alkali is available and higher dissolution rates are
achieved. Operation at very high pH, however, causes scal-
ing problems. Maintenance of the desired pH by careful
measurement and close control of reagent feed and mixing
system will prevent the pH variations which reduce effi-
ciency (if too low) or cause scaling (if too high).
A large variety of absorber designs have been utilized
to achieve SO2 removal efficiencies as high as 99 percent.
These include cross-flow horizontal spray chambers (Weir),
spray towers, packed-grid towers, and turbulent contact
(mobile bed) absorbers. The venturi type has also been
used, however, it is more useful as a particulate removal
scrubber and not as efficient for S02 absorption ducts
short residence times (unless and additive such as MgO is
used). The final selection and design of an absorber are
usually based on previous test data and on the required
liquid and gas flow rates. Spray towers (either horizontal
or vertical) offer a number of advantages including simple
internal design which decreases scaling potential, accep-
tance of high liquid flows and decreased maintenance.
10
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The addition of relatively small amounts of soluble
magnesium (less than 1 percent by weight) to the scrubber
liquor in the form of magnesium oxide, magnesium sulfate, or
dolomitic lime (in lime systems) can greatly increase the
SC>2 collection efficiency of the system. Magnesium com-
pounds are much more soluble, compared to calcium, and can
react rapidly in the liquid phase with S02.
Facilities at which high removal efficiencies have been
obtained are briefly described below:
(1) The Mohave Station of the Southern California
Edison Company, reported 863 removal efficiencies
of 95 percent or more with limestone, and of 98
percent with lime. The tests were conducted
intermittently over one-year on low-sulfur coal.
The unit was a 170-MW equivalent, prototype scrub-
ber.
(2) The packed module on the 115-MW Unit No. 1 at the
Cholla Station of Arizona Public Service shows 92-
percent removal of SC>2 using limestone slurry
scrubbing. This is also a low-sulfur-coal ap-
plication (0.8%).
(3) Recent tests at the Paddy's Run Station of Louis-
ville Gas and Electric have shown SC>2 removal
efficiencies in excess of 99 percent on 3-percent-
sulfur coal. This extremely high removal effi-
ciency was due to the addition of magnesium oxide
to the lime slurry.
(4) Several tests were conducted at the 10-MW TVA
Shawnee Pilot Plant, where S02 removal efficiencies
of 95 to 99 percent were reported for lime-basec
systems, and of more than 90 percent for limestone
systems. During one test run an efficiency of 96
percent on a turbulent contact absorber (TCA)
unit, high-sulfur coal application, was achieved
for the limestone system.
A brief summary of three lime-based systems follows,
namely: the Green River facility of Kentucky Utilities, the
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Bruce Mansfield Station of Pennsylvania Power Company, and
the Mohave Station of Southern California Edison. Two
limestone slurry systems are also discussed: the LaCygne
Station of Kansas City Power and Light, and Sherburne No. 1
and 2 of Northern States Power Company.
0 Kentucky Utilities, Green River No. 1, 2, and 3
The FGD system is installed on three boilers which
generate an equivalent of 64-MW and burn coal with a sulfur
content of 3.8 percent. This system is designed to remove
80 percent of the S02 in a turbulent contact scrubber and 99
percent of particulates. The unit started up in September
1975 and commercial operation began in the late fall of
1975. Before commercial service, the system went through an
extensive four-phase, pre-startup evaluation.
Sulfur dioxide removal efficiency has been well above
the design value, averaging about 90 percent. After com-
mercial start-up, several relatively minor problems were
encountered and corrected. Closed-loop, full-capacity
operation began in March" 1976, with the initiation of a six-
month vendor qualification test. To date, performance of
the system has been good; mechanical reliability is ex-
cellent. Average system operability has been above 90
percent since March of 1976, with the exception of a period
between February and April of 1977, when the unit was shut
down for stack repair.
0 Pennsylvania Power Company, Bruce Mansfield No. 1
This two stage venturi FGD system is installed on Unit
No. 1, which is rated at 839 MW and burns coal with a
sulfur content between 4.5 and 5.0 percent. The FGD system
was designed for 92-percent SO2 removal and 99.8-percent
particulate removal. Unit No. 1 started -up in April 1976,
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and full commercial operation began in May 1976. Availa-
bility was reportedly very high during the first seven
months after start-up; operating problems were solved with-
out causing boiler downtime. Since then, however, the unit
has experienced serious problems with the stack liner, and
the load must be reduced by approximately 50 percent for
about a year for liner repairs.
Two performance tests were conducted in July 1977. The
results were 190 and 540 ng/J (0.44 and 1.26 Ibs S02/106
Btu), representing 94-percent and 83-percent removal respec-
tively. The allowable emission rate is 300 ng/J (0.6 Ibs
SO2/10 Btu). The variations in emissions were apparently
due to pH fluctuations which have since been corrected.
0 Southern California Edison, Mohave Station
Participants in the Navaho/Mohave Power Project funded
a full-scale scrubber demonstration at the Mohave Generating
Station. The 170-MW demonstration facility was installed on
a 790-MW boiler firing coal with an average sulfur content
of 0.4 percent. Two types of scrubber were installed for
the demonstration tests: a horizontal cross-flow scrubber,
and a vertical countercurrent unit. The vertical module was
operated both in a TCA and in a packed grid configuration.
Sulfur dioxide removal efficiency was excellent for all
three absorbers. Although the SO2 inlet concentration was
only 200 ppm, all three configurations were capable of
removing 95 percent of the inlet S0». Calculated avail-
ability percentages for the horizontal and vertical modules
were 81.3 and 72.8 percent, respectively. Since this was a
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test facility, several design changes that contributed to
low availability were made during the period.
0 Kansas City Power and Light Company, LaCygne No. 1
The unit is rated at 820 MW and burns coal with a
sulfur content ranging from 5 to 6 percent. The FGD system
installed in 1972 consists of eight identical scrubbing
modules, each with a venturi scrubber for particulate emis-
sion control and an absorber for S0_ control. Particulate
removal efficiency is from 97 to 99 percent. The system was
designed for 76-percent S02 removal. Actual SO- removal
efficiency is 80 percent with seven modules operating on
729-MW. Under maximum load, the removal efficiency averaged
76.2 percent. Efficiencies under both conditions should
improve now that eight modules are operating.
The FGD installation was plagued with start-up prob-
lems. However, analysis reveals that nearly all of them
were due to mechanical design rather than to process chem-
istry limitations. The availability of this system has
improved steadily as solutions to the various problems have
been found. The system is now one of the most reliable FGD
systems on a large boiler in the United States. The avail-
ability for 1976 averaged 91 percent, and for the first half
of 1977 averaged about 93 percent.
0 Northern States Power Company, Sherburne Station No. 1
and No. 2
Each unit has a net generating capability of 700 MW and
fires a subbituminous western coal with a 28-percent mois-
ture, 9-percent ash and 0.8-percent sulfur content. Each
system has 12 scrubber modules, 11 of which are required for
full-load operation. Sulfur dioxide removal is between 50
and 55 percent, which is sufficient to meet local require-
14
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ments and approximates the value for which the system was
designed. Availability for Unit No. 1, which started up in
March 1976, averaged 85 percent for the first four months of
operation. During the past 12 months, availability has been
in excess of 90 percent. Unit No. 2 started up in April
1977 and has shown even better start-up performance.
Availabilities have averaged about 95 percent for the first
four months.
Wellman-Lord Process
The Wellman-Lord Process uses an aqueous sodium sulfite
solution to absorb SO- and form sodium bisulfite. The
solution is regenerated and SOp is released in an evapora-
tor-crystallizer. The regenerated sodium sulfite is dis-
solved for recycle in the absorber. The concentrated S0«
stream is recovered as liquid S02/sulfuric acid, or elemental
sulfur. Guidelines to obtain high efficiency for Wellman-
Lord Systems include:
Installation of a prescrubber with a separate water
recirculation system for final particulate control and
reduction of SO-, and chlorides.
Use of a three to five tray absorber with an L/G of l.C
to 1.3 1/m3 (6 to 10 gal/1000 acf).
A superficial gas velocity in the range of 2.7 to 3.1
m/sec (9 to 10 ft/sec).
Maintenance of the required sodium sulfite scrubbing
solution at a pH of 6.0 at the absorber inlet.
System make-up of fresh, 20 percent sodium carbonate
solution should be approximately 0.07 1/m3 CO.5 gallon/
1000 acf) per tray.
As S02 inlet concentration decreases, the number of
trays required to obtain high S02 removal should be
increased.
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Seven WeiIman-Lord systems are operating in the United
States. Six units are installed on S0_ or Glaus sulfur
recovery plants. The SO,, removal efficiency of these six is
typically 90 percent or -greater, and removal efficiencies in
excess of 97 percent have been reported. On-stream time for
the absorption area of these plants is more than 97 percent.
The No. 11 unit at the D. H. Mitchell Generating Sta-
tion at Northern Indiana Public Service Company (NIPSCO) is
currently the only operational Wellman-Lord system on a
utility boiler in the United States. It is also the only
coal-fired application in the world. The process is de-
signed to remove at least 90 percent of the S0_ when firing
^
coal containing up to 3.5 percent sulfur. The supplier
guarantees the mechanical soundness and product quality of
the process, as well as water, electricity, and chemical
consumption. The initial start-up of the NIPSCO unit began
July 19, 1976, and an extended shake-down period began
November 28, 1976. During this period, the Unit 11 boiler
operated for 121 full days and 10 partial days, whereas the
S02 removal system operated for 71 full days and 23 partial
days, and was down for 38 days. In course of the three
sustained operating periods, the absorber demonstrated the
capability of greater S02 removal than specified. A boiler-
related mishap occurred January 15, 1977, causing the unit
to be shut down for repairs until May 1977. The absorber
resumed operation June 13, 1977. Operation has been erratic
since then, again primarily because of boiler problems.
Trials began on August 29, 1977 and were successfully com-
pleted on September 15, 1977. The equipment met the guar-
antee covering SO- and particulate removal, chemical makeup,
and utility usage.
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Three Wellman-Lord systems are currently under con-
struction. Two of these will be on coal-fired boilers at
the San Juan Station of the Public Service Company of New
Mexico. Each unit will be on a coal-fired boiler with
approximately a 350-MW rating. Both units are designed for
90-percent removal of SC>2. The third unit is at ARCO/Polymers
in Monaca, Pennsylvania, where a single scrubber will re-
ceive flue gases from three coal-fired boilers with a total
equivalent rating of 100 MW. The unit is designed for
approximately 87.5-percent S02 removal.
Magnesium Oxide Systems
This process uses a magnesium oxide slurry to react
with S02. The reaction product, magnesium sulfite, is dried
and calcined to regenerate magnesium oxide. Sulfur dioxide,
liberated in the regeneration step, is recovered for con-
version to sulfuric acid or for reduction to elemental
sulfur. Guidelines to achieve high efficiency include:
High efficiency particulate removal should precede the
absorber.
A prescrubber should be used to remove any remaining
particulate and most of the chlorides and SO-.
Utilize venturi absorbers, typically operating at a
pressure drop of 25 cm (10 inches) of water or greater,
or Turbulent Contact Absorbers operating at approxi-
mately 20 cm (8 inches) of water pressure drop, at an
L/G of 5.3 to 6.6 1/m3 (40 to 50 gal/1000 acf).
The absorber superficial gas velocity should not exceed
approximately 3.0 m/sec (10 ft/sec) range.
The slurry pH measured at the absorber discharge should
be maintained in the 6.0 to 7.5 range.
Three full-scale units have been operated in the United
States: Mystic Station, Unit No. 6, of Boston Edison (oil
17
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fired); Dickerson No. 3, of Potomac Electric and Power; and
Eddystone No. 1A, of Philadelphia Electric (both coal
fired). All used fuel with 2- to 2.5-percent sulfur con-
tent. Sulfur dioxide removal efficiencies at all three
locations have been in excess of 90 percent. In general,
however, the three oanits experienced serious problems:
mechanical, material-related, product-related, corrosion,
and handling. These problems have limited operability to
between 27 and 80 percent. When reviewing these operability
levels, however, several points must be kept in mind:
0 Sulfur dioxide collection efficiencies were fre-
quently over 90 percent during test periods.
0 Two units (Mystic and Dickerson) were trial in-
stallations, built to obtain operating data. As
such, various construction materials were used
that would not have been used in a full-scale
plant designed for long-term operation.
0 The sulfuric acid plant that was to receive SC>2
from the Eddystone MgO regeneration facility was
shut down by its owner and another had to be
found.
0 The single regeneration facility at Rumford, Rhode
Island, could not process material from the Mystic
and Dickerson stations simultaneously since it was
too small.
0 Many problems at the Eddystone installation are
related to particulate scrubbing and not to the
SO2 absorber section.
0 Many design and operating problems at these in-
stallations were solved during these early pro-
grams and would not be encountered in new designs.
In the past, the MgO systems installed by Chemico
(Mystic and Dickerson) and United Engineers (Eddystone) have
18
-------
not had overall performance guarantees. Rather, the manu-
facturers of certain components guaranteed them against
manufacturing defects only. Now, however, Chemico is
willing to guarantee the entire MgO system mechanically, as
well as specify that the unit will meet applicable SO-
emission regulations, including a 90-percent removal effi-
ciency.
Double Alkali Flue Gas Desulfurization Systems
Double alkali scrubbing is an indirect lime/limestone
process, in which a soluble alkaline medium is used in the
scrubbing vessel to react with S02. The scrubber effluent
is then treated with lime or limestone in a reactor outside
the scrubber loop, where calcium sulfites and sulfates are
precipitated and the scrubbing liquor regenerated and
returned to the scrubber. This system greatly reduces the
problems of plugging and scaling. Various double alkali
process configurations are available and are described in
the full report. Guidelines to achieve high efficiency
include:
Utilization of a prescrubber with a separate water
recirculating system for control of particulates and
chlorides for high chloride coal (>0.04 percent Cl by
weight in the coal).
Use of a two-stage tray or packed tower absorber with
an L/G in the 1.3 to 2.7 1/m3 (10 to 20 gal/1000 acf).
Typically the absorber pressure drop is 15 to 30 cm (6
to 12 inches) of water.
The absorber scrubbing liquor pH being recycled to the
absorber should be in the range 6.0 to 7.0 pH range.
If lime regeneration is used, the reaction tank resi-
dence time should be approximately 10 minutes.
19
-------
If limestone regeneration is used, the reactor tank
residence time should be approximately 30 minutes.
A number of successful bench-scale, pilot plant, and
prototype double alkali systems have been tested on both
industrial and utility boiler flue gas applications in the
United States. The success of these programs has resulted
in commitments by three separate utilities to install full-
scale, double alkali systems on coal-fired boilers. As yet,
however, no full-scale system is operating on utility
boilers, although several are in operation on coal-fired
industrial boilers.
At the Cane Run No. 6 unit of Louisville Gas and Elec-
tric, a 277-MW coal-fired unit, the double alkali system is
scheduled to start up in February 1979. The unit is de-
signed to have 200 ppm of S02 or less in the discharge from
the scrubber, and 95-percent SO,, removal when the sulfur
content of the coal is 5 percent or greater. Coal sulfur
content is expected to be between 3.5 and 4 percent.
At the A. B. Brown No. 1 installation of Southern
Indiana Gas and Electric, the double alkali system will be
applied to a 250-MW boiler firing coal with an average
sulfur content of 3.5 percent. The unit is scheduled for
start-up in April 1979, and designed to remove 85 percent of
the SO2 when burning 4.5-percent sulfur coal, the maximum
sulfur content expected.
At the Newton No. 1 unit of Central Illinois Public
Service, the double alkali system will be installed on a
575-MW boiler firing coal with an average sulfur content of
4 percent. The unit will start up in November 1979. The
20
-------
design S02 removal efficiency is 95 percent, or less than
200 ppm in the exit gas.
Four double alkali systems have been installed on
industrial coal-fired boilers. These systems have operated
with high removal efficiency, ranging from 85 to 99 percent
(mostly 90 to 95 percent). While some have had mechanical
problems, the systems have shown themselves reliable;
generally operability has been over 90 percent. In addi-
tion, two prototype double alkali systems were operated on
utility coal-fired boilers, one on low-sulfur coal and the
other on high-sulfur coal. Both had SO,, removal effici-
encies above 90 percent, and their success has resulted in
the design of a full-scale system that is expected to have
high levels of operability and efficiency.
FGD System Efficiency Summary
Table 3 identifies facilities at which FGD systems have
removed 90 percent or more of SO,,. In addition, systems are
operating or are being designed for efficiencies of 90
percent or greater (see Figure 1).
Furthermore, the major suppliers of systems are now
offering SO2 removal guarantees. Levels of S02 removal
which vendors will guarantee exceed 90 percent, and in some
cases 95 percent, but they often have a lower limit on
outlet SO,, concentration (e.g. 50 ppm). For lower sulfur
^
coals, this lower limit, rather than efficiency, would
become the basis of the guarantee. Thus existing technology
is adequate for meeting a 90-percent SO,, removal requirement.
21
-------
Table 3. PLANTS REPORTING 90 PERCENT OR GREATER SO- REMOVAL
Utility Company
Arizona Public Service
Duquesne Light
Louisville Gas & Electric
Northern Indiana Public
Service
Philadelphia Electric
Tennessee Valley Authority
Boston Edison
Detroit Edison
General Motors
Gulf Power
Potomac Electric & Power
Southern California Edison
U.S. Air Force
Kentucky Utilities
Station
Choi la
Four Corners
Phillips
Cane Run
Paddy ' s Run
Mitchell
Eddy stone
Shawnee
Mystic
St. Clair
Parma
Scholz
Scholz
Scholz
Dickerson
Mohave
Mohave
Rickenbacker
Green River
Unit
No. 1
No. 5
Nos. 1-6
No. 4
No. 6
No. 11
No.. 1
No. 10
No. 6
No. 6
No. 1-4
No. 1
No. 1-2
No. 2
No. 3
No. 1
No. 2
No. 1-9
No. 1-3
MW
115
160
410
175
65
115
120
10
150
163
32
20
20
20
95
170
170
20
64
Nature
Full-scale
Demons tration
Full-scale
Full-scale
Demonstration
Demonstration
Demonstration
Prototype
Demonstration
Demonstration
Full-scale*
Prototype
Prototype
Prototype
Demonstration
Demons trat ion
Demonstration
Full-scale**
Full-scale
Process
Limestone
Lime
Lime
Lime
Lime
Wei Iman- Lord
Mag-Ox
Lime/limestone
Mag-Ox
Limestone
Double- alkali
Double-alkali
Chiyoda
Carbon
Mag-Ox
Limestone
Lime
Lime
Lime
% S
in fuel
0.4-1.0
0.7
1.0-2.8
3.5-4.0
3.5-4.0
3.2-3.5
2.5
0.8-5.0
2.5
0.3
4.0
3.0
3.0
3.0
2.0
0.6
0.6
3.6
3.8
SO2
removal ,
%
92
95
90+
85
99.5
90
95-98
95-99
90
90-91
90+
95
95
90+
90
95
95
99
90+
to
* Industrial
** Military Base
+ Oil Fired
NOTE:
Most reported S02 removal data are based on intermittent manual tests,
-------
FGD SYSTEM OPERATION
Two basic features characterize FGD performance:
removal efficiency, and process operating ability. This
operating ability has been defined in various ways, but
the terms most commonly referred to are system availability
and operability. These terms are defined as follows:
0 Availability: Hours the FGD system is operated or
available for operation divided by total hours in
the time period.
0 Operability: Hours the FGD system is operated
divided by hours the boiler is operated.
FGD system availability is dependent on both system
design and the manner in which the system is operated. Even
so, there is a trend in overall system availability, as a
function of the year the system was started up (Figure 2).
Continuing improvement in availability is evident as the
newer, improved units come on line. Although some recent
installations have not shown particularly high availability,
a statistically significant correlation does exist between
start-up date and average availability. In addition, only
one of these newer stations had a redundant (spare) module
available for use in the event of malfunction of the operating
modules. A redundant scrubbing module has a significant
effect on overall system availability since it can replace a
module which may be shut down for any reason. This is shown
in Table 5 where calculated availabilities with and without
a spare module are shown.
When operation at less than full load is required,
which is usually the case, opportunities for preventative
23
-------
to
HH <
co a
CO
ea
100
90
80
s!< 70
i >
•i 60
LU
fc 50
_i
40
OQ
Q- <
O _J
oc
30
—• o
OQ on
< uu <-U
_J CO
10
4
»
NOTE:
15
51
CORRELATION COEFFICIENT FOR THIS LEAST
SQUARES LINEAR PLOT INDICATES A
STATISTICAL CERTAINTY OF 99 PERCENT.
STANDARD DEVIATION = 18
A OPERABILITY
H) AVAILABILITY
(D RELIABILITY
1972
1973
1974
PLANT START-UP DATE
1975
1976
Figure 2. Average plant FGD availability/operability
versus plant start-up date.
(See Table 4 for plant identification)
-------
Table 4. IDENTIFICATION OF PLANTS IN FIGURE 2
1. Will County No. 1 ,
Commonwealth Edison
2. Mystic No. 6
Boston Edison
3. Hawthorn No. 4
Kansas City Power and Light
4. Hawthorn No. 3
Kansas City Power and Light
5. LaCygne No. 1
Kansas City Power and Light
6. Paddys Run No. 6
Louisville Gas and Electric
7. Cholla No. 1
Arizona Electric Power Co-Op
8. Reid Gardner No. 1
Nevada Power
9. Reid Gardner No. 2
Nevada Power
10. Scholz No. IB and 2B
Gulf Power Co.
11. Scholz No. 1A
Gulf Power Co.
12. Green River No. 1 and 2
Kentucky Utilities
13. Sherburne County Station No. 1
Northern States Power Co.
14. Bruce Mansfield No. 1
Pennsylvania Power
15. Reid Gardner No. 3
Nevada Power
16. Cane Run No. 4
Louisville Gas and Electric
-------
Table 5. CALCULATED FGD SYSTEM AVAILABILITY
BASED ON NUMBER OF SCRUBBER MODULES
FGD System Availability based on
Single Module Availability of:
Number of
modules
1
2
3
4
5
6
7
8
No spares
70
70
49
34
24
16
12
8
6
80
80
64
51
41
37
30
24
19
90
90
81
73
66
59
53
48
43
One spare
70
91
78
65
53
42
33
26
20
80
96
90
82
74
66
58
50
44
90
99
97
95
92
89
85
82
77
Assumes continuous full load operation is required.
26
-------
maintenance and repair occur without effecting system opera-
tion and still better availability can be achieved compared
to continuous full load operation.
Continued improvement in system availability is also
shown in Figure 3 where average availability data for
selected FGD systems serving high and low sulfur coal
applications are presented. High availabilities are be-
coming more common as design and operating advances are
implemented. This improvement in system availability has
also prompted some FGD system supplies to guarantee a 90-
percent availability level. In a survey conducted for this
study, seven out of twelve FGD system suppliers offered
availability guarantees of 90-percent.
Several examples of the improved availability and
operability of new FGD systems are described below.
Lime Systems
0 Louisville Gas and Electric, Cane Run Unit No. 4,
Louisville, Kentucky (178 MW).
The unit began operation in August 1976. With the
exception of a shutdown caused by the lack of lime
(frozen rivers prevented barge deliveries), and
process modifications, the unit has averaged in
excess of 95 percent operability through July
1977.
0 Louisville Gas and Electric, Paddy's Run Unit No.
6, Louisville, Kentucky (65 MW).
The unit began operation in April 1973. Start-
up problems, modifications, and an extended boiler
shut-down kept operability low until October 1974.
Operability from October 1974 to August 1977 has
been in the 95 to 100 percent range, although the
boiler operates primarily as a peak load station.
0 Kentucky Utilities, Green River Units No. 1, 2,
and 3, Central City, Kentucky (64 MW).
27
-------
100
90-
80-
70-
60-
50-
40-
30
-
-
-
CTi
1
LT>
CTl
ID
CTi
1 —
2
LaCYGNE
(
5.4%
S)
CTI
LT>
CTi
I^W
r^
\J I
r-.
CTi
CSL
O
u_
UJ
O3
UJ
f--.
CTl
(/)
UJ
_J
Q
O
_!
CO
UJ
Q
O
1
C£
o
u.
UJ
UJ
>
<40
-
CTl
-
-
1 ->.
CTl
CHOLLA SHERBURNE BRUCE
(0.6% S) (0
.8%
S) MANSFIELD
(5.0% S)
ANNUAL AVERAGE
AVAILABILITY FOR
ENTIRE FGD SYSTEM
RANGE IN INDIVIDUAL
MODULE AVAILABILITY
Figure 3. Average availability for selected FGD systems
28
-------
This FGD unit began operation in December 1975.
After the initial operating period (Dec. 1975-Feb.
1976), the operability of the unit has been 97
percent through June 1977.
Limestone Systems
Kansas City Power and Light, La Cygne Unit No. 1,
La Cygne, Kansas (820 MW).
Operation of this FGD system began in January,
1974. Since all the flue gas must be treated by
the FGD system, availability is a more meaningful
parameter. From February 1976 through July 1977,
unit availability has averaged 93 percent.
Northern States Power, Sherburne No. 1 and 2,
Sherburne, Minnesota (700 MW each).
After start-up, No. 1 unit averaged 92-percent
availability. No. 2 unit has averaged 95 percent
since start-up.
In summary, the availability of full-scale scrubbing
facilities has increased steadily to where current systems
are demonstrating long-term availabilities in excess of 90
percent.
29
-------
OPERATING PROBLEMS AND SOLUTIONS
There have been and still are problems associated with
FGD systems; however, many of these problems have been
solved and the methods of reducing the severity of the
remaining items are much better understood.
To date, the problems encountered with FGD systems and
the severity of these problems varied both with system type
and within units of the same system. The more common prob-
lems encountered are listed below.
0 Formation of scale in the absorber and associated
equipment in lime and limestone systems leading to
plugging and reduced capacity.
0 Plugging of mist eliminators, lines, and some
types of absorbers.
0 Failure of ancillary equipment such as pumps,
piping, pH sensing equipment, reheaters, centri-
fuges, fans and duct and stack linings.
0 Inadequate absorbent make-up preparation.
0 Handling and disposal of sludge in nonregenerable
systems.
Scaling and Plugging
In lime and limestone systems, scaling has been a
particular problem and has reduced operability. Both a soft
sulfite scale and a hard sulfate scale may form in the
absorber, mist eliminator, and ancillary tanks, pumps, and
pipes. Specific process control techniques which have
produced significant improvements include:
0 Use of Magnesium
Full-scale and test facilities in this country have
effectively reduced saturation and scaling by addition of
magnesium to the circulating slurry. The TVA Shawnee facil-
ity, the Phillips facility, and the Paddy's Run facility
* -^
Discussed in full report only.
30
-------
demonstrated that the addition of magnesium to the lime and
limestone slurry eliminated scrubber scale formation. The
Bruce Mansfield and Conesville stations use lime containing
magnesium oxide to prevent scaling.
0 Operation at subsaturation levels for calcium sulfate
and sulfite
By maintaining high liquid to gas (L/G) ratios, the
proportion of unreacted lime or limestone remains high
relative to the absorbed S0~ There is thus less chance of
2* •
creating a supersaturated solution of sulfites or sulfates.
The higher L/G ratio also improves overall S02 collection
efficiencies, as described in Section 3.1. The actual L/G
will vary with the type of absorber, and values in excess of
10.8 1/m (80 gal/acf) have been used in spray towers.
Increased reaction tank holding time will also decrease
saturation by allowing further reaction between the absorbed
SO- and the lime or limestone slurry. Slurry residence time
at the Green River facility is greater than twenty minutes,
and scale formation is not a major problem.
0 pH Control
Work at the EPA-Shawnee test facility has shown that an
important parameter in controlling scale formation is solu-
tion pH. The measurement of pH has also received consider-
able attention. More rugged and dependable sensors are
being used; they are located in the slurry stream where they
are subject to less breakage, are more accessible, and where
they yield data which is more reliable and responsive for pH
control. The Bruce Mansfield facility has just completed a
renovation program to incorporate these design features into
their pH system.
31
-------
0 Co-precipitation of sulfate
Minimizing the oxygen content in the flue gas by re-
ducing any air in-leakage, favors co-precipitation of sul-
fate crystal. Therefore, air exposure is reduced by cover-
ing open reaction tanks, clarifiers, etc.
Plugging caused by deposition of solids on equipment
surfaces has sometimes restricted the passage of liquids or
gas in FGD systems. It is usually easily removed by flush-
ing with water or steam. Plugging in pipes can be prevented
through designs which avoid low flow velocities. Careful
control of raw material particle size and screening of the
slurry also decrease plugging problems, especially in spray
nozzles, pipes and pumps. Since this problem is caused by
the deposition of solids from the recirculating slurry,
reduction of the overall amount of solids will reduce the
plugging. The minimum stoichiometry that will effect the
required SO2 removal efficiency should be used. This has
been demonstrated in this country at Shawnee and LaCygne.
Erosion and Corrosion
Many problems with ancillary equipment were due to
corrosion and erosion.
Erosion in venturi prescrubbers has resulted from high
fly ash loadings. Likewise, prescrubbers remove the bulk of
any chlorides and sulfur trioxide in the gas stream; both of
these components are highly corrosive. Corrosion occurs
more frequently in areas after the absorber subject to wet
saturated flue gas as opposed to areas subject to alkaline
slurry streams.
There are so many factors involved in FGD operation
which affect corrosion rates, that generalizations regarding
corrosion resistant materials are difficult. A sufficient
amount of data has been accumulated, however, to provide
32
-------
general guidelines for the construction of critical elements
in FGD systems as summarized below:
(a) Some systems are incorporating such alloys as
Hastelloy C-276, Hastelloy Gf Inconel 625, Incoloy
825, 317L stainless steel, 904L stainless steel
and Jessop JS700 in wet/day high temperature, high
chloride environments, such as in presaturators.
The LaCygne Station has found that these materials
give excellent reheat service. The Bruce Mans-
field station has had good results with Hastelloy
wetted parts of the fan.
(b) Synthetic and natural rubber coatings predominate
in recycle tanks, pumps, and lines. These mate-
rials have been reported to give superior erosion
resistance once application problems have been
overcome. For instance rubber lined pumps have
been used successfully at the following facil-
ities: Green River, LaCygne, Bruce Mansfield, and
Conesville.
(c) For liners in the absorbers, exhaust ducts and
stacks, a number of materials such as resins,
ceramics, polyesters, polyvinyls, polyurethanes,
Carboline, and Gunite, have been used with varying
degrees of success. Although successful applica-
tions have been reported, widespread failures of
the liners have been attributed to the undepend-
ability and inexperience of lining applicators,
instability of the materials at high temperatures,
inconvenience of repair, and cost-related factors.
These problems are especially evident on higher
sulfur coals. Extensive effort is continuing by
FGD suppliers to fully solve this problem.
Equipment Design
Approaches utilized to reduce problems with ancillary
equipment include:
0 Recirculation Pumps - Slurry recirculation pumps provide
the driving force for the liquid circuit in FGD systems. In
their design, special attention must be given to an accurate
service description (solution pH, specific gravity, solids
33
-------
content, gas entrairanent, flow rates, and head). A number
of general trends are evident and summarized below:
(a) New systems mast incorporate spare pumps. Spare
capacity from 50 percent Cone spare for every two
operational) to 100 percent (one spare for every
one operational) is useful to avoid downtime.
This type of spare equipment is found at new
large stations including Bruce Mansfield and
Conesville.
(b) Natural and synthetic molded rubber lining should
be specified for wetted parts in the pumps.
(c) Flush-water wash systems are needed to purge the
pumps of solids, which tend to settle out during
periods of inactivity.
0 Mist Elimination - Chevron and baffle-type mist elimina-
tors have been and are currently being used in virtually
every FGD system in the United States. The popularity of
these collectors is due primarily to design simplicity, high
collection efficiency (for moderate to large size drops),
low pressure drop, wide-open construction, and low cost.
Within these two preferred types of mist eliminators, a
number of specific design and construction innovations have
been implemented:
(a) Chevron designs (continuous vane construction) are
predominate over baffle designs (discontinuous
slat construction).
(b) Fiberglass-reinforced plastic is now used at
nearly all facilities.
(c) The horizontal configuration (vertical gas flow)
is also used in almost all installations for cost
reasons.
(d) Two-stage designs predominate over single-stage
designs, because they yielded higher elimination
efficiencies.
(e) Operation at high alkali utilization.
34
-------
(f) Bulk entrainment separators, perforated plates,
impingement plates and other precollection devices
are becoming integral parts of mist elimination
systems. These reduce plugging and improve sepa-
ration. The Conesville facility employs this as
well as LaCygne and Coal Creek.
(.g.) Mist eliminator wash systems that employ intermit-
tent, high-velocity sprays predominate over con-
tinuous wash systems. These produce a hydraulic
washing effect.
Application of these approaches greatly diminishes
mist eliminator problems.
0 Reheat - Virtually all the FGD systems coming on-line and
planned for future operation incorporate some type of stack
gas reheat system. These systems heat the flue gas to avoid
condensation with subsequent corrosion to downstream equip-
ment, ductwork, and stack and to suppress plume visibility
as well as enhance plume rise and pollutant dispersion. To
date, a number of "wet stack" FGD systems (no reheat) have
been installed and have encountered corrosion problems. The
trend in reheat systems is toward heating of ambient air and
mixing with the flue gas and mixing of hot untreated flue
gas with scrubbed gas. In-line reheat systems have been
subject to corrosion and solids deposition, the latter often
occurring because of inefficient upstream mist elimination.
Application of heated ambient air reheat systems essentially
eliminates reheater problems.
0 Fans - Fans installed immediately after an FGD system (wet
fans) have experienced corrosion, chloride attack, and
solids deposition problems. Deposition problems have caused
fan imbalance resulting in excessive bearing wear and damage
to the fan. Only two systems have this trouble: Phillips
and Bruce Mansfield. The problems associated with fans
installed upstream of the FGD system (dry fans) include
35
-------
operation at higher temperatures (over 150°C) resulting in
higher gas velocities and abrasion by fly ash. Dry fan
problems are more easily solved, and the tendency is toward
fans upstream of the FGD system. Where necessary/ however,
the use of various steel alloys have made wet fans a viable
alternative.
FGD SYSTEM MANUFACTURER CAPABILITY
Based on the new coal-fired boilers now planned for
construction and a projected growth rate of 5.56 percent per
year for the construction of new boilers, approximately
510,000 MW of coal-fired boiler capacity will be built
between 1978 and the year 2000. The alternative NSPS
standards assumed for this study indicate that all of these
new units will require FGD systems.
To determine the capability of FGD system manufacturers
to provide these systems, eighteen manufacturers were con-
tacted. Table 6 shows those manufacturers that provided
information for this study. The responses from these 13 FGD
system manufacturers indicate they will be capable of sup-
plying the design personnel and equipment for the FGD sys-
tems required by the alternative standards. The capability
of manufacturers to meet FGD system requirements is flexible
and increases in proportion to demand. However, even with
present staffs, adequate capability apparently exists to
supply FGD systems for all new coal fired plants as shown
on the last page of this report.
36
-------
Table 6. MANUFACTURERS RESPONDING TO THE FLUE GAS DESULFURIZATION SYSTEM
CAPABILITY STUDY AND THE PROCESS OFFERED BY EACH
Manufacturer
1. Babcock ft Wllcox
Company
2. Chemlco Air Pollution
Control Company
3. Chtyoda International
Corp.
4. Combustion Engi-
neering. Inc.
5. Davy Powergas, .Inc.
6. Environeerlng, Inc.
7. Flakt. Inc.
8. FMC Corp.
9. Peabody Process
Systems. Inc.
10. PullMn, Inc.
11. Research-Cottrell,
Inc.
12. UOP. Inc.
13. Zurn Air Systems
Type of FGD
Regenerative system
Magnesium
oxide
X
Phosphate
X
Wellman-
Lord
X
Catalytic
oxidation
X
Citrate
X
System Offered
Nonregeneratlve system
Double
alkali
X
X
X
X
Lime
X
X
X
X
X
X
X
X
Limestone
X
X
X
X
X
X
X
X
X
Chiyoda
thoroughbred
101
X
Sodium
carbonate
X
X
Hydro
X
LO
-------
Projected
FGD demand with
manufacturers' alternative NSPS,
Time period capability, MW MW
1978-1982 205,700 75,500
1983-1987 212,890 65,400
1988-1992 218,540 109,000
These same manufacturers would usually guarantee 90-
percent or greater S02 removal efficiency. In addition
approximatley two-thirds would provide an operation and
maintenance service and guarantee a specified level of
availability.
Ample limestone, and to a lesser extent, lime, supplies
exist in this country to supply all FGD systems. Shortages
in specialized construction personnel are a possibility,
however the added personnel needs for new FGD systems are a
very small portion of the total labor requirement. By about
1990, shortages in large scrubber modules and fans are also
predicted by several of the suppliers depending on the sizes
required at that time.
38
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-78-032a
2.
3. RECIPIENT'S ACCESSION NO.
>. TITLE AND SUBTITLE Flue Gas Desulfurization System Capa-
bilities for Coal-fired Steam Generators
Volume I. Executive Summary
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
T.Devitt, R. Gerstle, L.Gibbs, S.Hartman, and
R.Kller
8. PERFORMING ORGANIZATION REPORT NO.
|. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo. Environmental, Inc.
11499 Chester Road
incinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2603, Task 1
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development*
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND.PERIOD COVERED
Task Final; 4-12/77
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES (*) Cosponsored by EPA's Office of Air and Waste Management.
Project officers are J.E.Williams (IERL-RTP, 919/541-2483) and K.R.Durkee
(OAQPS/ESED. 919/541-5301).
i6. ABSTRACT
report discusses the availability of technology for reducing SO2 emis-
sions from coal-fired steam generators using flue gas desulfurization (FGD) systems.
Foreign and domestic lime, limestone, double alkali, magnesium slurry, and Well-
man-Lord FGD systems are described, and the design parameters and operating
experiences are discussed. Steps that have been taken to achieve high system opera-
bility are discussed. Also, disposal of FGD system wastes is discussed briefly.
7.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Coal
Boilers
Wastes
Alkalies
Scrubbers
Calcium Oxides
Limestone
Sulfur Dioxide
Dust
Air Pollution Control
Stationary Sources
Alkali Scrubbing
Particulate
Venturi/Spray Towers
Mist Eliminators
13B
2 IB
07A,07D 07B
21D 08G
13A
11G
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
39
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