U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78-0303
Office of Research and Development Laboratory
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RESEARCH REPORTING SERIES
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EPA-600/7-78-030a
March 1978
FLUE GAS DESULFURIZATION SYSTEMS:
DESIGN AND OPERATING CONSIDERATIONS
Volume I. Executive Summary
by
C. C. Leivo
Bechtel Corporation
50 Beale Street
San Francisco, California 94119
Contract No. 68-02-2616
Task 2
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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FOREWORD
EPA has undertaken a review of the New Source Performance Standards
for SO. emissions from coal-fired steam generators. As part of this
review, EPA is assembling information related to the SC^ removal
capability of FGD systems and technical and economic data for the
design of FGD systems for higher SC>2 removal efficiencies.
In the conduct of this review the EPA has contracted for the services
of a number of supporting organizations, each of which will make specific
contributions to the total subject. In this respect, a substantial num-
ber of separate, but related, issues will be investigated, including
such broad issues as economic, energy, social, technological, and
environmental issues.
This report addresses itself to the following specific tasks:
(1) Describe FGD system parameters which are commonly
monitored to ensure proper operation and explain how
those parameters are varied to accommodate combustion
system variations such as changing boiler loads, changes
in S0» inlet concentrations, and changes in other fuel
characteristics. Describe the parameters which are
controlled to limit scale build-up in the scrubber
system and mist eliminator and the ranges within which
they must be controlled and parameters which are con-
trolled to limit other problems.
(2) Where an installed full-scale FGD system has demon-
strated good operation, but at lower S0~ removal
efficiencies (such as 60 to 85 percent), define the
changes that would be applied to a new facility to
obtain 90 percent or greater S0_ removal and present
data showing the effects of these changes. For example,
iii
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SO removal efficiency may be increased by increasing
the liquid-to-gas ratio, changing pH, addition of MgO
to lime/limestone scrubbers, changes in scrubber gas
velocity, increasing bed heights in absorption towers,
and others. Any rationale, engineering calculations,
etc., necessary to extrapolate from an existing FGD
system operating well at lower percent SO- removal to
a 90 percent or greater S0? removal should be presented.
(3) Define the effects of changes in coal characteristics
on FGD systems and describe operating parameters or
design techniques which can be used to compensate for
local and nationwide variations in coals. For example,
coals with high chloride contents affect S0~ removal
efficiency, may corrode FGD constituents, and may
require the purge of additional waste streams. As
another example, describe the effects of different
coals on the resultant mixture of combustion gases
(e.g., percent oxygen in exhaust) and the resulting
effects on the chemical reactions and efficiency of the
scrubber. Define the scrubber system parameters
which are controlled to compensate for these variations.
(4) Describe the purpose, need, and methods for reheat of
exhaust gases downstream of FGD systems. Define
energy consumption for reheat of these gases for typical
plants ranging in size from 25 to 1000 megawatts for
the different FGD systems. Describe problems exper-
ienced with reheaters and design and operating or main-
tenance factors used to satisfactorily overcome these
problems. Assess approaches which have been or could
be used to eliminate reheat of these gases.
As used herein, the term "S02 removal efficiency" is limited to per-
formance obtained from a single module of removal equipment over
a short time, and tested over a period of several weeks to show
that scale accumulation is not likely. The term does not reflect the
longer periods of time necessary for commercial operations, nor any
implication concerning the equipment reliability or availability.
Inasmuch as increasing the percent S0_ removal above currently demon-
strated levels will require greater chemical work, it will inherently
cause some reduction in the equipment reliability and availability
unless suitable counteracting steps (such as the use of more modules)
iv
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are taken. It will also somewhat increase the energy consumption
requirements, the chemical feed requirements, and the waste disposal
requirements over those currently being used. It is understood that
these specific subjects, their quantification, and potential solutions
are being addressed by others and that their results will be integrated
with the results reported herein. Thus, the results contained in this
report should not be construed as a complete assessment of all factors
related to the judgment as to the establishment of S09 removal New
Source Performance Standards.
This volume is an executive summary of the above report.
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ABSTRACT
A brief introduction is given to flue gas desulfurization technology.
The SO. removal mechanisms for wet scrubbing and dry processes are
described, along with the typical gas contacting equipment used.
Processes and their critical operating parameters are described for:
• Lime and limestone scrubbing
• Sodium carbonate scrubbing
• Double alkali (soda lime) scrubbing
• Magnesium oxide scrubbing
• Sodium sulfite (Wellman Lord) scrubbing
The report describes the implications of requiring 90 percent or greater
SO removal for new FGD installations. For lime and limestone scrubbing
data are presented from the EPA Shawnee Test Facility to show the effects
of process operating parameters on SO removal efficiency. Mathematical
correlations of the data are also presented. Additional test data is
presented for sodium carbonate and double alkali scrubbing.
Coal characteristics and their effects on FGD system design and oper-
ation are summarized. A qualitative description is given for the effects
of coal heating value and sulfur, ash, moisture, and chlorine content.
The reasons and methods for reheating scrubbed flue gases are described.
Energy consumption of the various methods is defined, and problems
experienced with reheater design, operation, and maintenance are
presented. Alternative approaches to eliminating reheat are discussed.
vil
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CONTENTS
Page
SUMMARY 1
FGD Processes 1
Implications of Requiring 90 Percent or Greater
S0_ Removal for New FGD Systems 6
Effect of Coal Properties on FGD Systems 10
Reheat of Scrubbed Flue Gases 15
ix
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SUMMARY
FGD PROCESSES
All commercial flue gas desulfurization (FGD) installations operating
on U.S. coal-fired utility boilers are wet scrubbing processes that
contact the flue gas with a water solution of soluble (or sparingly
soluble) alkali to absorb the SCL. The SO- removal is carried out in
devices (scrubbers) designed to provide intimate contact between gas
and liquid over a large gas-liquid interface area. The S0~ removal
efficiency of an FGD system is a function of the type of scrubber
selected, the absorbent composition and circulation rate to the scrub-
ber, and additional operating parameters.
Table 1 summarizes by process the number and capacity of full scale
operational FGD systems and systems under construction on utility
boilers in the U.S.
A major distinction is generally made between recovery processes,
which recover SO in useful forms such as sulfuric acid or elemental
sulfur, and throwaway processes, which produce a solid or liquid waste.
In the throwaway case, the waste product must be stored in a pond or
treated and used for landfill.
Wet FGD processes fall into two classifications — slurry scrubbing and
clear liquor. In slurry scrubbing the absorbent and reaction products
are present as suspended solid particles in water. During the absorp-
tion phase of slurry scrubbing, the suspended alkali dissolves to
react with the absorbed S02 and to precipitate waste solids which are
disposed of in throwaway processes or treated to regenerate active
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Table 1
SUMMARY OF FGD PROCESSES ON U.S. COAL-FIRED UTILITY BOILERS
Process
Limestone
Lime
Alkaline fly ash with
lime or limestone
Sodium carbonate
Magnesium oxide
Double alkali
Well man Lord
Aqueous carbonate
Operational
No.
9
9
2
3
1
-
1
-
MW
3,767
2,702
720
375
120
-
115
-
Construction
No.
16
9
1
-
-
1
2
-
MW
6,750
4,158
450
-
-
575
715
-
Contract Awarded
No.
10
4
2
1
-
2
-
1
MW
4,911
2,350
1,400
509
-
527
-
100
June 1977
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alkali in recovery processes. The circulation of saturated solutions
and crystallization of reaction products makes the control of process
chemistry very important to prevent scaling in the scrubber. Slurry
system components are also vulnerable to plugging and erosion. Clear
liquor scrubbing processes minimize the problems of the slurry systems
by keeping the absorbent and reaction products dissolved in water.
Some wet scrubbers are suitable for the removal of both fly ash and
SO so that, for a new power plant, one of the options for the control
of these pollutants may be to let the FGD system remove both. In
practice, however, there are some valid reasons for collecting fly
ash separately with an electrostatic precipitator. For example,
possible interference with process chemistry is prevented, erosion of
process equipment by fly ash slurry is minimized, contribution to
additional throwaway sludge volume is avoided (although the fly ash
must still be disposed of), and, in the case of recovery processes,
contamination of by-products is prevented. Another consideration is
that if the power plant has an FGD system bypass and separate dust
removal equipment, particulate removal operation can be continued during
periods of FGD system maintenance (if such operation is allowed) .
In a wet scrubber the flue gas is cooled by evaporation of water. It
may then be desirable to reheat the gas to minimize condensation,
fouling, and corrosion in ducts, fans, and stacks; to avoid a visible
plume; and to improve plume rise and disper-sion.
Lime and Limestone Scrubbing
Of the potentially available processes, lime and limestone slurry
scrubbing have received the most attention and are presently operating
on a number of coal-fired boilers. Additional new units are under con-
struction. These processes achieve high S02 absorption efficiencies,
use naturally occurring raw materials, produce relatively insoluble
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wastes, and have lower capital and operating costs than many other
processes. Significant improvements have been made over the past sev-
eral years in the areas of improved reliability, variable load opera-
tion, system control, and sludge disposal techniques.
Sodium Carbonate Scrubbing
Sodium carbonate scrubbing is a clear liquor absorbent process that is
less susceptible to scaling than calcium-based systems. This process
has had limited application because it consumes an expensive alkali
and produces a soluble sodium waste product that must either be regen-
erated at a substantial cost or impounded in suitably lined retention
ponds. To date, application has been limited to geographical areas
having a cheap source of low-grade carbonate; these include three
units operating at a power station in Nevada and one under construction
in Wyoming.
Double Alkali Scrubbing
The double alkali process retains the desirable characteristics of the
clear liquor sodium carbonate system. It minimizes the soluble waste
problem by reacting the scrubber effluent with lime or limestone to
precipitate an insoluble waste product and regenerate the costly sodium
absorbent. However, the process operation is somewhat more complex
and requires additional equipment.
Approximately 12 installations totaling 700 MW equivalent have been
operated on oil-fired and coal-fired industrial boilers in the U.S.
and Japan. Also, three installations totaling 1,050 MW on oil-fired
utility boilers have operated in Japan, and 20 MW prototype testing
has been carried out on a Gulf Power Company coal-fired utility boiler
in Florida. Three full-scale units totaling 1,100 MW are scheduled
for operation in the U.S. on coal-fired utility boilers.
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Magnesium Oxide Scrubbing
The magnesium oxide recovery process features recovery of sulfuric
acid or sulfur. It has been demonstrated to be feasible on full-scale
coal-fired boilers and is capable of high S0? removal efficiency,
although the reliability of these installations must be improved. Two
full-scale installations have been operated in the U.S., one on an
oil-fired boiler and the other on coal. A third unit of 120 MW is
currently undergoing testing on a coal-fired boiler.
Sodium Sulfite (Wellman Lord) Scrubbing
The Wellman Lord system is a clear liquor sodium alkali scrubbing pro-
cess with thermal regeneration and sulfuric acid or elemental sulfur
recovery. About 17 installations are in operation in the U.S. and
Japan on industrial plants and oil-fired boilers. A 115 MW installa-
tion on the coal-fired D. H. Mitchell Station of Northern Indiana Pub-
lic Service has been completed and is currently undergoing a compre-
hensive one-year demonstration program. This is the first application
of the process on a coal-fired boiler. Two additional units are under
construction. This process is more complex and costly than lime and
limestone scrubbing processes.
FGD System Process Control Parameters
A number of FGD system parameters must be monitored and controlled to
ensure proper operation, to accommodate variations such as changing
boiler load and inlet SCL conditions, to ensure proper mist eliminator
operation, and to prevent scaling in scrubbers. These parameters
include a varying alkali feed rate to match inlet SCL and boiler load
changes, and a number of mist eliminator washing schemes and design
configurations to maintain trouble-free operation. Techniques employed
to prevent scaling typically include control of scrubber pH, adequate
hold tank residence time, control of suspended solids concentration in
slurry systems, and high liquid-to-gas ratios. Clear liquor scrubbing
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processes such as the sodium carbonate, double alkali and Wellman Lord
are not susceptible to scaling problems to the extent that the lime and
limestone processes are.
IMPLICATIONS OF REQUIRING 90 PERCENT OR GREATER
S02 REMOVAL FOR NEW FGD SYSTEMS
For the FGD processes described in this report, S0~ removal efficiencies
of 90 percent or greater — as defined in the foreword to this report —
are obtainable by suitably changing a number of the operating conditions.
This section discusses the changes in a demonstrated FGD system design
of, for example, 80 percent SO,, removal efficiency to obtain a capability
of 90 percent or more. In summary, these design changes could involve:
0 Increase in absorbent circulation rates
e Increase in scrubbing (contacting) stages or in
contacting intensity (scrubber-type)
• More stringent requirements for uniform flow
distribution
• Elimination of gas by-pass if used for reheat
• Increases in absorbent concentrations which may in
turn require residence time or other changes to
control enhanced scaling tendencies
If the increased SO removal requirement is also accompanied by an
increase in coal sulfur content, this change will intensify all of
the above requirements. Other fuel related factors such as coal heat-
ing value, ash content and composition must also be accommodated and
with increasing difficulty as removal requirement rises.
Lime and Limestone Scrubbing
For a given inlet S0~ concentration, or coal sulfur content, the
removal efficiency of a lime or limestone FGD system can be substan-
tially varied by changing a number of operating conditions, including
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scrubber type, liquid-to-gas ratio, gas velocity (for some scrubbers),
scrubber inlet pH, magnesium addition, and the number of scrubbing
stages. Raising the design efficiency of such systems to 90 percent
or greater affects a number of process design parameters. Among pos-
sible required changes:
• Scrubbers. More elaborate and equally reliable
scrubber modules must be engineered to provide
greater slurry holdup and gas-liquid interfacial
area, or existing design must be upgraded to in-
clude additional internal devices. The number of
vessels could be doubled to provide operation with
two scrubbers in series.
• Recycle Pumps and Piping. If L/G is increased to
improve absorption efficiency, pump size is in-
creased. Recycle slurry pipe diameters must be in-
creased to maintain design flow velocities
• Limestone Preparation Equipment. To accommodate
greater feed rates in a limestone system, larger
grinding equipment, storage silos, transfer equip-
ment, slurry makeup tanks and feed pumps, and other
related equipment will be needed
o Lime Preparation Equipment. To accommodate greater
feed rates in a lime system, the slaking equipment,
storage silos, transfer equipment, slurry tanks and
feed pumps, and other related equipment must be
larger
• Magnesium Addition Equipment. If magnesium is added
to improve efficiency, the magnesium handling equip-
ment must be added to the process design, or dolo-
mitic lime used. The waste sludge must be treated
or contained to prevent groundwater contamination
by the dissolved compounds
• Scrubber Recirculation Tanks. Tanks must be larger
to maintain design residence time for increased L/G
and to provide residence time for increased SO
absorption. These tanks may be directly under the
scrubber, integrated into the scrubber vessel de-
sign, or offset. Slurry agitators will require
redesign
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• Slurry Solids Separation Equipment. This equipment
must be larger to accommodate greater solids dis-
charge. This applies to clarifiers, filters, centri-
fuges, and all related slurry pumps and piping
• Fans. If greater gas pressure drop is incurred,
the fans must either be larger, or there must be
more of them — with corresponding increases in the
complexity of the fan control system
• Reheat. Bypass reheat would be marginal or impos-
sible because all the flue gas must be treated
• Nonair Quality Environmental Effects. As S02 removal
is increased, provision must be made for handling the
increased waste products produced. If soluble addi-
tives are used to enhance absorption efficiency, steps
must be taken to prevent groundwater contamination
• Energy Requirement. Power requirements would increase
with larger equipment loads
This list illustrates the complexity of considerations that must be
addressed in designing lime and limestone FGD systems for 90 percent
or greater S0~ removal efficiencies. Such an effort inevitably
involves higher cost and energy requirements. The energy requirement
will be in the form of increased auxiliary power consumption. The
cost penalties can be not only in terms of heavier equipment, but of
greater operating complexity and higher maintenance as well.
Sodium Carbonate Scrubbing
The sodium carbonate process is capable of high efficiency over a wide
range of inlet S0~ concentrations. This clear liquor process is gas-
phase controlled — rather than being limited by the slow dissolution
of suspended solids. However, as previously indicated, the process
consumes a premium chemical and produces a soluble waste salt which,
to avoid water pollution, must either be stored in lined impoundments
or regenerated at substantial cost.
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To date application for coal-fired utility plant FGD systems has been
limited to geographical areas having a cheap source of low-grade car-
bonate. These include three units operating at a power station in
Nevada (Reid Gardner — 375 MW) and one under construction in Wyoming
(Jim Bridger — 520 MW). Both stations burn low-sulfur coal and the
FGD systems are designed to realize about 90 percent absorption
efficiency.
Double Alkali Scrubbing
The clear-liquor sodium-based double alkali process, like the sodium
carbonate process, is aimed at realizing high removal efficiencies
over a wide range of inlet concentrations. The absorption is gas-
phase rather than solid dissolution limited. More efficient scrubber
types can be used, such as packed towers and tray towers. Venturi
scrubbers provide excellent S02 removal, although at substantial
energy penalty. The process operation is somewhat more complex than
lime and limestone scrubbing processes.
Double alkali FGD systems are currently being offered and designed to
achieve high removal efficiency in both industrial and utility appli-
cations. The process has achieved greater than 90 percent SO- removal
during prototype testing on a coal-fired utility boiler. The first
full-scale coal-fired utility application is scheduled to start up in
1979. The system is designed to meet performance guarantees of 95 per-
cent S0~ removal on 5 percent sulfur coal. Construction of two addi-
tional units is planned.
Magnesium Oxide Scrubbing
As previously indicated, the magnesium oxide slurry scrubbing process
has been demonstrated to be feasible on full-scale coal-fired boilers
and is capable of SO- removal efficiencies greater than 90 percent,
although the reliability of these installations must be improved. A
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120 MW unit is currently undergoing testing and has been designed to
achieve 90 percent S0~ removal from 2.5 percent sulfur coal. The
magnesium oxide process operation is more complex than lime and lime-
stone scrubbing.
Sodium Sulfite (Wellman Lord) Scrubbing
The Wellman Lord recovery process has demonstrated high SCL absorption
efficiencies on oil-fire boilers and industrial plants. A 115 MW
installation on the coal-fired Mitchell Station of Northern Indiana
Public Service has been completed and is currently undergoing a com-
prehensive one-year demonstration program. This is the first applica-
tion of the process on a coal-fired boiler. The installation was
designed to meet performance guarantees of 90 percent SCL removal from
flue gas generated by 3.5 percent sulfur coal and has demonstrated
greater efficiencies. Two additional units are under construction.
The process operation is more complex and costly than the lime and
limestone scrubbing processes.
EFFECT OF COAL PROPERTIES ON FGD SYSTEMS
The major coal properties affecting FGD system design and operation
are heating value and sulfur, ash, moisture, and chlorine content.
The effects include:
• Heating value of coal. Affects flue gas flow rate —
generally higher for lower heating value coals which
also contribute a greater water vapor content to the
flue gas
• Moisture content. Affects the heating value and con-
tributes directly to the moisture content and volume
of the flue gas
• Sulfur content. The sulfur content together with the
allowable emission standards determines the required
S02 removal efficiency, the FGD system complexity and
cost, and also affects sulfite oxidation
10
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• Ash content. May affect FGD system chemistry and
increases erosion. In some cases it may be desir-
able to remove fly ash upstream from the FGD system
• Chlorine content. May require high alloy metals or
linings for some process equipment and could affect
process chemistry or require prescrubbing
The importance of these factors is described in this section.
Coal Heating Value and Moisture Content
Because a power plant using a low heating value coal must fire at a
higher burn rate to generate the same amount of power, such coals
produce a larger volume of flue gas and greater SO emissions per
unit of generated power. The effect on the FGD system is twofold.
First, the flue gas handling equipment, including the scrubbers, must
be of a larger size to accommodate the greater gas volumes. Typically,
power plant flue gas volumes may range from 5,000 to more than 7,000
3
m /hr/MW (about 3,000 to 4,000 acfm/MW), depending on the coal compo-
sition, boiler heat rate, gas temperature, and power plant elevation
(or gas pressure). Secondly, the increased SO emissions mean that on
a megawatt basis the FGD system must treat proportionally larger
quantities of SO-. On a megawatt basis, therefore, the FGD system
(as well as the power plant) equipment capacity is greater and capital
and operating costs are higher for coal with lower heating value — for
a given coal sulfur content and SO- removal efficiency.
A characteristic of lower heating value coals and coals of high moisture
content is a flue gas with a greater proportion of water vapor. This
leads to smaller amounts of water evaporation in the scrubbers, which
in turn affects the temperature to which the gas is cooled. The over-
all effect is that SO- absorption takes place at slightly elevated
temperatures. This could affect absorption efficiency, depending on
the chemistry of the particular process.
11
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Sulfur Content of Coal
The sulfur content of the coal together with the allowable emission
standards determines the absolute removal rate of SO in pounds per
hour. For a given absorption efficiency the sulfur content of the
coal directly affects the design of almost every piece of equipment
in the FGD system.
For example, a lime or limestone system designed for high rather than
low sulfur coal would have:
• Scrubbers with capacity for greater SO removal
• Higher L/G's and therefore bigger pumps and piping
and higher pumping energy requirements
• Bigger fans and greater energy requirements if the
improved scrubber design results in higher gas pres-
sure drop
• Larger sized alkali storage, preparation and feed
equipment
• Greater lime or limestone feed rates
• Larger scrubber recirculation tanks to maintain
residence time for increased L/G's and to provide
additional time for increased S0_ absorption load
0 Greater capacity slurry solids separation equipment
• Provision for disposing of the larger waste volumes
• Increased power requirements for the larger equip-
ment loads
The result is that for higher sulfur coals the lime and limestone FGD
systems are more complex and have higher capital and operating costs.
Other FGD processes are similarly affected by the sulfur content of
the coal. For systems using regenerable absorbents (double alkali,
magnesium oxide and Wellman Lord processes) , the capacity of the
12
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regeneration section is directly proportional to the sulfur content.
With high sulfur coal the overall cost of these sections (capital and
operating) represents a large portion of the total cost for the system.
With recovery processes there is relatively little waste but a large
by-product processing cost, although the greater amount of by-product
produced helps to offset these costs.
The amount of sulfite oxidized to sulfate in scrubber solutions is
proportional to the relative amounts of oxygen and S0~ absorbed. It
also depends on the pH and temperature of the liquid as well as the
composition of particulate emissions which may contain iron or copper
that act as catalysts for the oxidation reaction. In general, however,
as the gas SO- concentration becomes smaller, the fraction of sulfite
oxidation tends to increase. For this reason, when lime or limestone
scrubbing systems are used for low sulfur coal or for boilers operat-
ing on high excess air they may experience high sulfite oxidation and
produce waste solids that are mainly gypsum. This can be a desirable
feature since gypsum solids are more easily dewatered due to faster
settling rates and higher final settled densities. Conversely the
lower oxidation observed with high sulfur coals can lead to solid
wastes high in sulfite and difficult to dewater.
Ash Content of Coal
Most coals fired in U.S. utility boilers contain 5 to 30 percent ash.
After combustion, part of the ash falls to the bottom of the furnace
and the remainder is carried upward with the flue gas. The fraction
of the ash that is carried overhead is a function of the boiler design
and combustion parameters. With pulverized coal firing, 85 percent or
more of the ash appears as fly ash; in cyclone boilers about 20 to 30
percent of the ash goes overhead.
Fly ash can be removed upstream of the FGD system by a precipitator,
fabric filter, or prescrubber,- or integrally within the FGD system
13
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itself. Not all FGD processes are suitable for combined removal. Even
when fly ash is removed upstream, residual ash becomes entrained in the
process liquor.
Fly ash is invariably abrasive; some is chemically inert, and some is
highly acidic due to SO adsorption. Fly ash can cause excessive ero-
sion, scaling and plugging of equipment. It contributes to the waste
volume of throwaway processes, the loss of absorbent for regenerative
processes, and may contaminate the byproduct of recovery processes.
Certain coals from Wyoming, Montana, and North Dakota produce alkaline
fly ash with large amounts of reactive calcium, magnesium, sodium, and
potassium oxides. With combined removal of alkaline fly ash and SO ,
major reduction in the alkali makeup requirement can be realized. The
presence of calcium alkali in the ash can, however, aggravate wet-dry
interface problems by producing hard insoluble deposits.
In general, only processes using nonregenerable absorbents (lime, lime-
stone, soda) can be used for the combined removal of fly ash and SO .
The fly ash is then disposed of together with the spent absorbent.
Lime and limestone processes can better tolerate this fly ash and are
sometimes used for combined removal. Venturi scrubbers are often used
for this purpose at the expense of increased pressure drop over other
absorption systems. However, the fly ash contributes to solids buildup
at the wet-dry interface and causes erosion of pipes, pumps, spray
nozzles, and scrubber internals.
Chlorine Content of Coal
The small amounts of chlorine in coal are converted to gaseous chloride
in the boiler. The chloride is absorbed from the gas by wet scrubbing
processes. Its presence provides the potential for chloride stress-
corrosion, requiring in some places the use of high alloy equipment
wherever rubber or other protective coatings are not applicable.
14
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In wet scrubbing processes, dissolved chloride replaces active calcium,
magnesium or sodium alkalis by their chloride salts, which are inactive
in the absorption process. The alkali associated with the chloride is
then lost as dissolved solids in the water portion of the waste sludge.
From a cost standpoint this is particularly objectionable for magnesium
and sodium based processes (or magnesium enhanced lime and limestone
processes), because these alkalis are relatively expensive. For such
processes, prescrubbing may be used to absorb chlorides from the flue
gas upstream of the FGD system. This minimizes both alkali loss and
chloride stress-corrosion problems. For lime and limestone processes,
an equivalent amount of calcium is used up by the chloride (the amount
is small relative to that used for SCL absorption) , but the calcium is
relatively inexpensive.
REHEAT OF SCRUBBED FLUE GASES
Purpose and Need for Reheat
Flue gases are normally discharged from the power plant air heater at
120 to 150°C (250 to 300°F). The temperature is selected to remain
above the dew point of the traces of H SO normally present in order
to reduce corrosion and permit carbon steel to be used for fans, ducting,
and stack lining.
When a wet scrubber is inserted between the air heater and stack for
SO- removal, the flue gas exiting the scrubber is saturated with water
and cooled to the saturation temperature of about 50 C (125 F). Dis-
charge of the cool, wet gas to the stack can lead to:
• Condensation of water vapor and sulfur oxides, result-
ing in the acidic water corrosion of downstream ducts,
fans, and stack lining
• Impaired plume rise and, hence, poorer dispersion of
residual pollutants for a given stack height
• Deposition of scrubber residue on downstream fan
blades, resulting in imbalance
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0 A visible plume as water vapor condenses
• Stack rain, or mist droplets, that can settle around
the power station
To correct the above undesirable aspects of wet scrubbing, the treated
gas may be reheated to a higher temperature before discharge.
l
Methods of Reheat
Flue gas can be reheated in many ways, and several approaches have
been developed. The basic differences in reheat methods are the energy
sources used and the methods of transferring that energy to the flue
gas. Reheat methods currently in use include:
• Direct inline reheat — using steam or hot water heat
exchangers
• Direct combustion reheat — using gas or oil in either
inline burners or external combustion chambers
ft Indirect hot air reheat — using steam to heat air
which is then mixed with the scrubbed gas
• Bypass reheat — bypassing a portion of the untreated
hot flue gas to mix with the scrubbed gas
In the U.S., the scrubbed gas is generally reheated by 15 to 40 C
(30 to 100 F). Except for bypass, the energy penalty for reheat may
range from 1 to 5 percent of the heat input to the boiler system.
Direct Inline Reheat. Inline steam reheat is the most prevalent method
in the United States, although a few systems use hot water. An inline
reheater consists of a heat exchanger installed in the flue gas duct,
and is generally simple in design and installation. For a given degree
of reheat, the energy consumption is lower than for other types of
reheat, except bypass. The major problems encountered have been plug-
ging, corrosion, and vibration of the heat exchanger tube bundles.
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Plugging occurs from entrainment. Once the scrubber liquor deposits
on the reheater, the dissolved and suspended solids bake onto it. This
deposit continues to grow, blocking the gas flow, increasing the pres-
sure drop, and helping to induce corrosion from the localized high
temperature and concentrated salts. The effectiveness of the heat
transfer surface is progressively reduced as the deposit builds up.
To minimize problems, an efficient scrubber mist eliminator is essential.
Most direct inline reheaters incorporate a steam or air soot blower for
maintaining clean reheat surfaces. Corrosion and pitting have been
attributed to periodic acid conditions and to chlorides. Effective
design of the mist eliminator will minimize this. Operating experience
suggests that certain materials should not be used, such as carbon steel,
304SS, 316SS, and Corten. Structural design against vibration is essential.
Direct Combustion Reheat. The major advantage of this type of reheat
is operational reliability, especially if gas is used, because there
is no heat transfer surface on which fouling can occur. The main draw-
back in the United States is the limited availability and cost of the
oil or gas required. Where oil is used, problems have occurred in
attempting to maintain the flame within the main flue gas stream. This
saves space, but typically does not work well. An external combustion
chamber of adequate size is essential. Refractory failures have
occurred in the combustion chamber from flame impingement, attack from
condensation during downtime, vibration, and too rapid heating. Careful
specification of refractory and subcomponents is essential and provi-
sion must be made for the combustion chamber to be heated up slowly.
Indirect Hot Air Reheat. Indirect hot air reheaters have had fewer
problems than inline types. One advantage of this type of reheat is
that it provides desirable dilution for moisture content and residual
pollutant concentrations in the stack gas. Disadvantages are higher
capital investment, higher steam consumption for the same degree of
reheat, and increased stack gas volume. The temperature of the hot air
17
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before mixing is higher than 200 C (400 F) and can destroy the usual
coatings used to protect ducts and scrubber walls. Hot air must be
prevented from entering the system without cold gas flow during startup
and shutdown. For the same degree of reheat, indirect hot air reheat
has the highest energy requirement. However, for the same amount of
energy consumption, it may have equal or better benefits than other
types of reheat.
Bypass Reheat. Bypass reheat has the advantages of low capital invest-
ment, negligible operating cost, and simple, reliable operation. How-
ever, the maximum degree of reheat obtainable is limited by the overall
SC>2 removal requirement versus the S02 removal capability of the FGD
system. Separate fly ash removal is required to ensure that the by-
passed flue gas is sufficiently low in dust content to meet particulate
emission standards. Operating experience with bypass reheat in the
United States is limited to only one installation, but additional FGD
systems are under construction with provision for bypass reheat.
ALTERNATIVES TO REHEAT
A number of alternatives to reheating are available. Whether or not
they are feasible must be considered on a case by case basis. To the
extent that excessive ground concentration of residual pollutants is
a problem due to reduced plume buoyancy, one alternative to reheating
is to build a taller stack. Because there is no energy penalty, a
taller stack could be more economical than reheating even though it
involves a high capital cost.
To limit corrosion, one may either select materials that are inherently
resistant to corrosion or use coatings to cover materials subject to
corrosion. If the purpose of reheat is to protect a downstream fan,
an alternative is to place the fan upstream of the scrubber, although
this requires a precipitator to remove erosive particulate matter. Wet,
or washed, fans have also been used.
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Using reheat to overcome the effect of liquid entrainment from the
scrubber is costly and not necessarily the best answer to such prob-
lems. The use of more efficient mist eliminators would be the pre-
ferred alternative. One form of liquid emission that would not be
affected by better mist elimination results from liquid condensate
forming inside the stack. Such an effect can be reduced or eliminated
by the combination of insulation on the stack so as to reduce condensa-
tion likelihood, plus the use of a lower velocity stack.
There is very little, other than reheat, that is effective in elimi-
nating a visible vapor plume. However, plume appearance and, in
particular, the length of a visible plume are strong functions of
atmospheric conditions. When the gas leaves the stack, water vapor
condenses in the cooler atmosphere forming a visible plume. As the
plume disperses, condensed vapor evaporates at a rate depending on the
ambient humidity and temperature. With high external humidities early
in the day, the visible plume may travel long distances before disappear-
ing. In a desert environment at mid-day, on the other hand, the visible
plume vanishes rapidly. If the purpose of reheat is a cosmetic one,
one approach could be to use variable reheat. That is, reheat could
be limited to those periods of atmospheric conditions during which a
plume of objectionable length would otherwise occur.
Reheating should not be considered as a necessity, but as one of a
number of approaches for consideration in optimizing sulfur dioxide
absorption systems. Because of the high cost of reheat installation
and operation, some FGD system operators have selected a "no reheat,"
or "wet-stack," design.
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TECHNICAL REPORT DATA
(Please read lnuniclioiis on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-030a
2.
3. RECIPIENT'S ACCESSION-NO.
4.TITLE ANDSUBTITLE Flue Qgg DCS ulf urization Systems:
Design and Operating Considerations
Volume I. Executive Summary
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C.C. Leivo
8. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
Bechtel Corporation
50 Beale Street
San Francisco, California 94119
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2616, Task 2
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 EPA project officers are J.E.Williams (IERL-RTP,
and K. R. Durkee (OAQPS/ESED, 919/541-5301).
. ABSTRACT The repOrf. describes flue gas desulfurization (FGD) systems and the design
and operating parameters that are monitored to ensure proper operation. It explains
how these parameters are varied to accommodate changing boiler loads and fuel char-
acteristics, and describes the control of parameters to prevent such problems as
scale buildup. It describes effects of designing and operating FGD systems for 90% or
greater SO2 removal efficiencies, based on current testing program data. It describes
effects of coal characteristics on FGD performance, along with operating and design
techniques used to compensate for coal property variations. It describes the purpose,
need, and methods for exhaust gas reheat, downstream of FGD systems. It discusses
alternatives to exhaust gas reheat.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATl field/Group
Air Pollution
Flue Gases
Desulfurization
Coal
Reheating
Alkalies
Scrubbers
Calcium Oxides
Limestone
Sulfur Dioxide
Dust
Scale (Corrosion)
Air Pollution Control
Stationary Sources
Alkali Scrubbing
Particulate
Venturi/Spray Towers
Mist Eliminators
13B
21B 07B
07A,07D 08G
2 ID
ISA 11G
11F
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report/
Unclassified
21. NO. OF PAGES
26
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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