&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Technology Transfer
Summary Report
Sulfur Oxides Control
Technology Series:
Flue Gas Desulfurization
Lime/Limestone
Processes
-------
Technology Transfer EPA 625/8-81-006
Summary Report
Sulfur Oxides Control
Technology Series:
Flue Gas Desulfurization
Lime/Limestone
Processes
April 1981
This report was developed by the
Industrial Environmental Research Laboratory
Research Triangle Park NC 27711
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Scrubber with additive feed and reaction tank in foreground. Cane Run No. 5
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Introduction
Wet lime/limestone flue gas
desulfurization (FGD) processes
(Figure 1) employ a scrubbing
slurry of lime or limestone to remove
sulfur dioxide (S02). As a side
benefit, these processes also remove
fly ash and chlorides.
Lime and limestone FGD processes
are similar. Both are nonregenerable.
Their operation is based on the
ability of an aqueous slurry of slaked
lime [Ca(OH)2] or wet ground
limestone (CaC03) to absorb S02
from flue gas. Absorbed S02 is
removed from solution by a chemical
reaction that forms a calcium sulfite
and calcium sulfate [(1 — x)CaS03
• xCaS04 • ViHjO] solid solution
and insoluble calcium sulfate
dihydrate (gypsum, CaS04 • 2H20).
These salts precipitate in a holding
tank. A continuous bleed stream
removes part of the slurry from the
holding tank to be concentrated and,
as an optional step, stabilized. It
is common practice to dispose of the
resulting solids in ponds or as
landfill.
Because lime/limestone processes
are nonregenerable, they may
consume large quantities of feed
material and produce large quantities
of waste solids. These characteristics
could place them at a disadvantage
compared with regenerable
processes. Regenerable processes,
however, still require disposal
of waste fly ash and chlorides by
environmentally acceptable methods,
and these waste products amount
to as much as 50 percent of the
volume of solid waste produced
by lime/limestone processes.
Lime/limestone systems are
usually less complex than regenerable
systems, and they cost less to
install and operate than other
FGD processes. Consequently,
lime/limestone FGD processes are
the most widely used FGD systems
in operation. As of June 1980,
Key
Flue gas/off-gas
Cleaned flue gas
Absorption liquor
Sulfur products
Other systems
Desulfurized
flue gas
Plant
boiler
Disposal
Figure 1.
Major Components of Lime/Limestone FGD Processes
-------
58 lime or limestone slurry scrubbing This summary report is intended Institute and the U.S. Environmental
systems were in use to remove to provide a basic understanding Protection Agency (EPA).2 The
S02 from power plant flue gas; 71 of the lime/limestone FGD processes manual provides the design engineer
more were under construction or in to those unfamiliar with FGD with detailed guidelines and specific
the planning stage.1 technology. More detailed informa- procedures to select a lime-based
tion appears in the literature cited. FGD system. EPA is also preparing
A new manual, Lime FGD Systems a manual on limestone FGD, to
Data Book, was sponsored jointly by be available in 1981.
the Electric Power Research
-------
Process Description
Lime/limestone FGD processes
consist of four steps:
• Feed material processing
• Absorption
• Solids precipitation
• Solids concentration and disposal
Figure 2 illustrates the process
flow for a typical lime/limestone
installation.
Flue gas enters the absorber, where
it comes in contact with the
circulating scrubbing slurry contain-
ing calcium ions from dissolved
lime or limestone. Sulfur dioxide,
fly ash, and chlorides contained in
the flue gas are removed by the
circulating slurry. Alkaline species in
the liquor neutralize the absorbed
S02, promoting the formation of
ions of sulfite (S032) and sulfate
(SO^2). Water droplets are removed
from the cleaned flue gas as it
leaves the absorber. The clean flue
gas is reheated, if necessary, then
exhausted through the stack to
the atmosphere.
The scrubbing slurry—which may be
supersaturated with calcium sulfite
and sulfate solids [(1 — x)CaS03
• xCaS04 • 1/2H20] and gypsum
(CaS04-2H20)—flows to an effluent
holding tank or precipitation vessel.
In the holding tank fresh makeup
lime or limestone is added, and
reaction products are precipitated.
One effluent stream from the holding
tank is recycled to the absorber;
another is bled off for concentration
and disposal of waste solids.
Key
^^H Flue gas/off-gas
I _J Cleaned flue gas
[ I Absorption liquor
Sulfur products
Other systems
Lime
or
limestone
Feed
preparation
i
i
Process
water
Bleed
stream
Solids
concentration
Waste
solids
to disposal
Figure 2.
Typical Lime/Limestone FGD Process Flow
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\ Li
conveyor
Convey or-elevator
Key
From process water
storage tank
Flue gas/off-gas
Cleaned flue gas
Absorption liquor
Sulfur products
Other systems
To holding
tank
I Agitator
(a)
Slurry
feed tank
From process water
storage tank
To holding
tank
Rail or truck
OZD
Y
Hoppers, feeders, and conveyors
Elevator
(b)
Slurry
feed tank
Figure 3.
Reagent-Processing Systems: (a) Lime and (b) Limestone
Solids in the bleed stream may
be concentrated in a thickener, filter,
or centrifuge, or may be sent
directly to a holding/settling pond.
Clarified process water is returned
to the process. Concentrated solids
may be disposed of in ponds or
used for landfill. The waste solids
are sometimes stabilized, or they
can be processed for commercial use
in gypsum or Portland cement.
Feed Material Processing
Feed material commonly is prepared
on site for lime/limestone FGD
processes. In a lime system (Figure
3a), pebble lime from a calcination
plant is stored in bins, and then
conveyed to a slaker that produces
a slurry containing about 25 percent
solids by weight. The slurry is
diluted to 15 percent solids with
recycled process water, and is
pumped to a slurry feed tank.3
The chemical reaction for slaking
can be represented as:
CaO+H20
Ca(OH)2
(1)
In a limestone system (Figure 3b),
limestone—usually 0.75 inch
(1.9 cm) or less—is delivered by
truck or rail, dumped into hoppers,
and conveyed to a 30-day storage
pile. The limestone is ground
(usually to 70 percent minus
200 mesh) in wet ball mills, and is
stored as a 60-percent (by weight)
solids slurry in a slurry feed tank.
Any dust resulting from limestone
feed preparation must be controlled
with dust collectors.3-4
Both slaked lime and limestone
dissolve in the slurries to produce
calcium ions. The reaction for slaked
lime is:
Ca(OH), - Ca+2 + 20rT
(2)
4
-------
For limestone the reaction is:
CaC03 t^ Ca+2 + C032
(3)
Slaked lime dissolves more readily
than limestone, resulting in a higher
pH for lime slurry than for limestone
slurry. The typical operating pH
range for a lime system is 7.0 to 8.5,
compared with 5.0 to 6.5 for a
limestone system.
Carbide lime, an impure slaked lime
byproduct of acetylene manufactur-
ing, also has been used success-
fully as a feed material.
Absorption
Absorption of S02 takes place
in a wet scrubber (Figure 4a). Flue
gas enters the scrubber and, in most
cases, flows countercurrent to a
scrubbing slurry. As the circulating
liquor makes contact with the
flue gas, a pressure drop occurs
across the scrubber and is overcome
by the use of either induced- or
forced-draft fans.
Sulfite/Sulfate Reactions. Sulfur
dioxide is removed from flue
gas by both absorption and reaction
with the scrubbing slurry liquor.
Reactions initiated in the scrubber
are completed in an effluent holding
tank. Specific details are still
disputed;35 however, the reactions
in Equations 4 through 9 generalize
the process.
The S02 is absorbed in water,
reacts with water to form sulfurous
acid (H2S03), then dissociates to
form sulfite ions (S032).
S02(g) ^ S02(aq) (4)
S02(aq)+H20 ^ H2S03 (5)
H2S03 ±; H+ + HSOJ ^
2H+ + S032 (6)
Dissolved lime or limestone (see
Equations 2 and 3) and other alkaline
species in the scrubbing liquor
neutralize the absorbed S02, driving
the reactions in Equations 4, 5, and
6 to completion.
Interior of induced-draft booster fan
Some of the sulfite ions are
oxidized in the system to sulfate ions
(SC-42):
S032 + 1/202 ±; SOI2
(7)
Some of the sulfate and most of the
sulfite eventually coprecipitate
with calcium as a solid solution:
+ (1 -x)SOj2
+ !/2H20 H (1 -x)CaS03
• xCaS04 • y2H20 1
Excess sulfate eventually pre-
cipitates with calcium to form
gypsum:
(8)
high as 90 percent has been
observed in systems treating dilute
S02 gas streams.6 High con-
centrations of unprecipitated sulfate
in the scrubber feed liquor increase
the probability of scale formation
in the scrubber.
Carbon Dioxide Transfer. In lime
scrubbers, carbon dioxide (C02)
absorbed from the flue gas can
react with the slurry to form CaC03,
thereby reducing the availability
of Ca+2 ions.
2H20 ±;
CaS04 • 2H20
(9)
C02(g) ^ C02(aq)
C02(aq) + H20 r; H2C03
H2co3 ±; H+ + HCO; ^
The mechanism of oxidation is
not well understood; however, the
rate is known to be a function of
the ratio of S02 and 02 con-
centrations in the flue gas and of
scrubbing liquor pH. Levels of
natural oxidation can range from
near 0 to almost 40 percent
for high sulfur coals. Oxidation as
C032
CaC03
(10)
(11)
(12)
(13)
Carbon dioxide absorption can be
minimized by proper pH control.
In limestone scrubbers, carbon
dioxide is liberated or desorbed.
The reaction sequence is repre-
sented by the reverse reactions
given in Equations 10 through 13.
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Flue gas/off-gas
Cleaned flue gas
Absorption liquor
Sulfur products
Other systems
Off-site
disposal
Settling pond Waste solids
Figure 4.
Lime/Limestone FGD Process: (a) Absorption, (b) Solids Precipitation, and (c) Concentration and Disposal
Mist Elimination and Stack Gas
Reheat. All wet scrubbers require
mist elimination, and most require
reheat of the cleaned flue gas.
As the flue gas exits the absorber,
it passes through a mist eliminator
where entrained liquid is removed.
After mist elimination, high pressure
steam heat exchangers, direct fired
reheaters, or indirect air or flue
gas reheaters may be used to reheat
the gas, which was cooled to
saturation temperature in the ab-
sorber. Stack gas is reheated to:
• Eliminate condensation in
downstream equipment
• Eliminate visible plume
• Provide enough plume buoyancy
to minimize ground-level
contaminant concentrations
• Prevent acid rain in the immediate
vicinity of the stack
The amount of reheat needed is
specific to the site.
6
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Solids Precipitation
Effluent holding tanks or precipita-
tion vessels may be used, singly or
in series, for solids precipitation,
scrubber feed addition, and lime or
limestone dissolution.
Slurry from the scrubber flows
into the holding tank (Figure 4b).
In the tank the slurry is mixed with
recycled process water and system
makeup water from the process
water storage tank, and with
fresh feed material from the slurry
feed tank. An agitator keeps the
slurry uniformly mixed. The slurry is
recycled to the scrubber to be reused
as scrubbing liquor. A bleed
stream is drawn off simultaneously
for dewatering, solids concen-
tration, and disposal.
The holding tank is sized to provide
sufficient residence time to complete
the reactions (Equations 5 through
9) and to precipitate the reaction
products. Seed crystals of copre-
cipitate (calcium sulfite/sulfate)
and gypsum in the slurry provide
nuclei for solids deposition and
precipitation. Inadequate residence
time in the holding tank can lead
to nucleation of coprecipitate
and gypsum in the scrubber, and
scale may form as a result.
A material balance for the holding
tank can be calculated by assuming
that streams to and from the
scrubber form a closed loop. Liquid-
to-gas (L/G) ratio in the scrubber
is varied by adjusting the liquid flow
rate in the loop. The combined
flow rates of the remaining incoming
streams (feed material, makeup
water, and recycled process water)
match the flow rate of the bleed
stream and compensate for water
lost by evaporation in the scrubber
and water added as mist eliminator
wash. The ratio of feed material
to water is adjusted to maintain a
slurry concentration of 8 to 15
percent solids in the holding tank.
It is important to maintain the
solids concentration high enough to
provide sufficient seed crystals
for precipitation, yet low enough to
avoid erosion problems in the
scrubber.
The incoming material/bleed stream
flow rate is proportional to that
at which S02 is removed in the
scrubber. In theory, 1 mole of calcium
must be added for every mole of
S02 absorbed. In practice, however,
more feed material is used, usually
more in limestone systems than in
lime systems because of the lower
values of limestone utilization
(moles S02 removed per mole
limestone added).
Recycled scrubbing slurry and the
bleed stream contain solid and
dissolved calcium sulfite/sulfate,
gypsum, chlorides, unreacted lime or
limestone, inerts, and possibly fly
ash. Dissolved lime or limestone
in the bleed stream is returned
to the system as a part of the total
dissolved solids in the recycled
process water. Eventually, undis-
solved lime or limestone is disposed
of with the waste solids.
Solids Concentration and Disposal
One of the main disadvantages of
the lime/limestone process,
compared with regenerable
processes, is the need for a waste
pond, landfill, or other disposal area
of sufficient size to receive the large
quantity of waste solids produced.
Dewatering and possibly stabilization
may be desirable to minimize
this need and to produce a more
environmentally acceptable waste
material. Specific methods vary
depending on the application or the
type of disposal.
Several solids concentration
and disposal systems may be used
(Figure 4c). Usually a thickener is
used for primary dewatering of the
effluent holding tank bleed stream.
Vacuum filtration or centrifugation
can sometimes be used for further
dewatering. Interim pond disposal
is an alternative for secondary
dewatering, although it is used
infrequently.
Concentrated waste solids may be
disposed of in an on-site pond,
or they may be transported to a
landfill area. Methods are available
commercially for stabilizing waste
solids to a structurally sound,
leach resistant material, which can
be disposed of in either a pond
or a landfill area.
Clarified process water from the
various solids concentration systems
may be recycled to a process water
storage tank. The water is pumped
as needed from the storage tank
to the effluent holding tank and to
the feed-material-processing area.
Makeup water may be added to
the storage tank to compensate for
system losses; however, fresh
makeup water used for mist
eliminator washing, pump seals,
and lime slaking is usually sufficient.
Integrated System
Figure 5 shows how the four
processing areas—feed material
preparation, absorption, solids
precipitation, and solids concentra-
tion and disposal—are related
to form the complete lime/limestone
FGD process. Process design and
operation are influenced strongly by
the relationship of each process unit
to the others. For example, solids
precipitation in the holding tank
affects the design and operation
of the solids concentration and
disposal subsystem.
-------
Steam or
oiedin
fuel/air
Limestone
Key
^^^H Flue gas/off-gas
^HH Cleaned flue gas
^ I Absorption liquor
I 1 Sulfur products
I I Other systems
Off-site
disposal
Vacuum filter I i \
or centrifuge I f~*\
Makei
wate
sup /
\
Pump
Settling pond Waste solids
Figure 5.
Lime/Limestone FGD Process Flow
8
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Design Considerations
A complete discussion of the
design considerations involved in
the construction and operation of
lime/limestone FGD systems is
beyond the scope of a summary
report. This section contains
sufficient information on design
considerations to permit a macro-
scopic analysis of the process,
including details on:
Feed material processing
Absorption systems
Scale control
Mist elimination
Solids dewatering and disposal
Fly ash and chloride effects
Feed Material Processing
As a rule the choice between lime
and limestone as feed material is
based on economics and availability.
Among such factors as capital
investment, operating costs, utilities
requirements, land use, feed utiliza-
tion, S02 removal efficiency,
and reliability, the relationship is
quite complex.7 Although limestone
is much less costly per unit weight
than lime, limestone is usually
less efficient than lime in S02
removal. This characteristic increases
operating costs because more feed
material must be added and more
waste solids are produced. Operat-
ing costs for limestone systems
are increased further because the
feed material must be ground.
Measures to improve utilization,
therefore, are most important for
the economics of limestone
systems. Typically, lime systems
have operated at around 90 percent
utilization, although they can be
designed to operate in the 95 to
100 percent range. Typical utiliza-
tions for limestone systems are
60 to 80 percent; however, more
recent process designs can achieve
utilizations as high as 85 to 95
percent.
Utilization is related to the solubility
of the feed material. Limestone
dissolves less completely than lime
at pH levels appropriate for S02
absorption. It dissolves more com-
pletely at reduced pH levels, but
S02 absorption efficiency is
reduced.8 A two-stage scrubber has
provided a compromise; the first
stage is operated at low pH for
limestone solubility and the second
at a higher pH for efficient S02
absorption.9'10 In another compro-
mise approach organic acids are
added to the scrubber liquor to
buffer the pH as an aid both to
limestone dissolution and to S02
absorption. Benzoic and adipic acids
have been especially successful.11'12
The following approaches also
improve limestone utilization
without decreasing S02 absorption
efficiency:8'13
• Grinding to increase limestone
surface area
• Using multiple holding tanks
in series instead of a single tank
• Using two-stage forced oxidation
for limestone systems
Absorption Systems
Various absorption systems have
been employed for lime/limestone
FGD processes. Factors controlling
selection of an appropriate system
include flow rate and S02 content
of the flue gas, desired efficiency of
S02 removal, allowable pressure
drop, turndown capability, and system
reliability. The volume of flue
gas to be treated, in part, determines
the physical size of the scrubbing
device. Because of size limitations
for the various types used, however,
a modular approach is usually
taken. Spare modules may or may
not be included, depending on the
degree of conservatism.
-------
Mobile bed sulfur dioxide scrubber system
Types of scrubbers that have been
used successfully to remove S02
include:
• Venturi scrubbers
• Spray towers (horizontal and
vertical)
• Grid towers
• Mobile bed (turbulent contact)
absorbers
• Packed towers
• Perforated plate towers
Each of these types will serve for
both gas absorption and particle
removal, but there are differences in
S02 and particle removal efficiency,
gas velocity, L/G ratio, gas-side
pressure drop, resistance to plugging,
and turndown capability. Per-
formance characteristics are given
in Table 1 for four scrubber types
in a limestone system.614
Sulfur dioxide removal efficiency
is based on both the scrubber type
and the ability of the scrubbing
slurry to absorb S02. Absorption
efficiency may be improved by
increasing:
1.15
Number of scrubber stages
Contact area in each stage
Scrubber L/G ratio
Scrubber liquor pH
Available alkali
Particles are removed by impinge-
ment. Turbulent flow and high
gas-side pressure drop indicate good
particle removal capability. A
venturi scrubber exhibits both
characteristics and commonly is
used for primary particle removal in
conjunction with a spray tower
for improved S02 absorption.
Minimum and maximum gas
velocities vary widely among
scrubber types. All but the venturi
operate in a range of 5 to 25 ft/s
(1.5 to 7.6 m/s). The extremely high
gas velocities associated with the
venturi, 125 to 300 ft/s (38 to 92 m/s),
result from the small diameter of
the venturi throat and do not
10
-------
Table 1.
Comparison of Scrubber Types for a Limestone Wet Scrubbing System
Scrubber type
Parameter
S02 removal efficiency
Particle removal efficiency
Gas velocity (ft/s)
Turbulent
contact
absorber
Good
Good
9 to 1 3
Venturi
Fair
Excellent
1 25 to 300
Grid
tower
Good
Good
6 to 11
Spray
tower
Good
Fair
5 to 25
Typical liquid/gas ratio for S02 removal
(gal/1,000 stdft3) 50 to 75 20 to 50
Gas-side pressure dropfortypical liquid/gas
ratio (inches H20) 6 to 8 8 to 20
Resistance to solids plugging Good Excellent
50to100 70to110
1 to 7
Good
1 to 3
Excellent
SOURCES: Robert H. Borgwardt, EPA, Research Triangle Park NC, personal communication,
Jan. 1978. Ottmers, D. M., Jr., J. C. Dickerman, E. F. Aul, Jr., R. D. Delleney, G. D. Brown,
G. C. Page, and D. 0. Stuebner, Evaluation of Regenerable Flue Gas DesuKurization Processes,
2 vols., EPRI RP 535-1, Austin TX, Radian Corporation, July 1976.
necessarily imply a greater gas-
volume-handling capability. The
resulting shorter residence times
reduce the S02 removal capabilities
of the venturi.
The L/G values in Table 1 represent
typical operating ranges for existing
units. Turbulent contact absorbers
provide greater surface area for
transfer of S02 at lower L/G ratios
than do spray towers. The L/G
ratios are also limited because the
scrubbers tend to flood if the liquid
pumping rate is too high. This
flooding occurs at different L/G ratios
for the various scrubber types.
The volume of slurry circulated is
critical and depends on the gas flow
and the S02 content of the gas.
In applications of low L/G ratio and
high S02 concentrations, the
slurry can absorb too much S02 per
unit volume, resulting in high levels
of supersaturation. Under these
conditions, precipitation will take
place in the scrubber as well as
in the holding tank, causing scaling
in the scrubber.
Slurry reactivity also influences
the L/G ratio in the absorber. In
general, L/G ratios must be higher in
limestone systems than in lime
systems to compensate for the lower
reactivity of a limestone slurry.
Pressure drop across the scrubbers
is a function of gas velocity, L/G
ratio, scrubber design, and scrubber
size. Gas pressure lost in the
scrubber is compensated with forced-
or induced-draft fans. In some
applications, especially in retrofit
installations, it may be desirable to
design a system for low gas-side
pressure drop to reduce the number
of fans needed and, therefore,
capital and operating costs.
Resistance to plugging is important
in system reliability. The open
configurations of the grid tower and
the spray tower give a lower gas-side
pressure drop and make these
scrubbers less susceptible to
plugging than are the turbulent
contact absorber and the packed
tower.
Scale Control
In a lime/limestone scrubbing
system, it is important to control
gypsum and calcium sulfite/sulfate
coprecipitate scale. If scaling
conditions exist for significant
amounts of time in any part of the
system, chemical scale will be de-
posited on equipment and the system
eventually will have to be shut
down for cleaning.
Gypsum presents a greater scaling
problem than does the calcium
sulfite/sulfate coprecipitate.
Gypsum forms a hard scale that is
difficult to remove. Sulfite/sulfate
coprecipitate scale can be removed
easily by a lowered pH, which
causes the scale to dissolve.
If the scrubbing system can operate
with less than 1 7 percent oxidation
of sulfite to sulfate, most calcium
sulfate coprecipitates from solution
with calcium sulfite as (1 — x)CaS03
• xCaS04 • 1/2H20. Under these
conditions, gypsum concentration
are kept continually below saturation,
and scaling problems are held to a
minimum.5
Several approaches will reduce the
probability of scale formation:6'14
The scrubber L/G ratio can be
increased to prevent formation of
more highly supersaturated calcium
sulfite/sulfate solutions. Higher
L/G ratios allow lower S02 pickup
per unit volume of scrubber solution
and, thus, lower supersaturations.
Sufficient gypsum and calcium
sulfite/sulfate coprecipitate seed
crystals should be recirculated in
the slurry to provide surface area
for precipitation. Most systems
operate in the range of 8 to 15
percent solids by weight.
Holding tank volume should allow
for adequate residence time for solids
precipitation. The scrubbing
liquor will then be sufficiently
desupersaturated with calcium
sulfite/sulfate. This variable is
important in system design because
changes in the holding tank
volume usually represent expensive
equipment modifications.
Use of magnesium or other additives
may reduce the scaling tendency
by reducing the relative concentration
of calcium salts.16
11
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Mist Elimination
Reliable mist eliminator operation
has been a major problem for
limestone scrubbers. Mist eliminators
have operated in lime scrubbers
with more success.
All wet scrubbers introduce mist
droplets in the gas. The mist must
be collected and removed to
prevent corrosion and scaling on
downstream equipment. Mist
elimination also reduces the energy
requirement for flue gas reheat
to evaporate excess moisture.
Because mist droplets from the
scrubber have relatively large
diameters, usually 40 /Jim or greater,
they can be removed effectively by
simple impingement devices such
as baffle plates, chevron blades, or
similar devices that alter the
direction of the gas flow.
Problems with chevrons have
included inefficient mist removal and
plugging of the chevrons with
soft deposits and scale. Mist elimina-
tion has been more efficient when
chevrons are mounted in a slanted
or vertical position instead of the
usual horizontal position. This
arrangement permits the liquor to
drain off and prevents it from being
reentrained in the gas.
Plugging and scaling of mist
eliminators can be prevented by
washing these components with a
mixture of fresh water (usually
about 35 percent) and clarified
liquor, supplemented if necessary by
intermittent washing with fresh
water.14 Scaling can be eliminated
by operating the system at high
S02 removal efficiencies and
high reagent utilizations. High
scrubber S02 removal efficiencies
result in lower S02 concentrations in
the gas passing through the mist
eliminator and, consequently,
reduced S02 absorption. Higher
reagent utilizations result in
lower reagent concentrations in the
carryover. Both factors reduce scaling
by reducing calcium sulfite/sulfate
supersaturations in the mist
12
eliminator.4 Plugging and scaling
usually can be eliminated when
systems are operated at utilization
levels above 85 percent.8
Wash trays and wet electrostatic
precipitators (ESP's) also have been
used as components of mist
elimination systems. A wash tray is
placed under a horizontal chevron
to remove solids in the entrained
mist and to collect wash liquor
flowing off the chevron. Wet
ESP's remove both mist and residual
dust in the flue gas leaving the
absorber.
Solids Dewatering and Disposal
Solids are dewatered to concentrate
them for ease of handling and
disposal and to lower transportation
costs. Choice of the best dewater-
ing method depends on the disposal
method (i.e., wet disposal in
ponds or dry disposal as landfill
or for potential use as commercial
gypsum); however, the composition
of the solids and the availability of
dry fly ash to supplement dewater-
ing also are important.17
Dewatering Methods. Currently,
thickening and vacuum filtration
are used in lime/limestone solids
dewatering on commercial-sized
units, and interim ponding also
has been used. Centrifugation was
tested, but filtration was found
more effective.
Clarifiers or thickeners are used
commonly for primary dewatering of
slurries with a low solids content
(10 to 15 percent solids). Typically,
these devices can achieve 30 to 40
percent solids. If solids dewater-
ability and ultimate disposal plans so
warrant, solids content may be
increased further using vacuum
filters. These devices achieve 50 to 85
percent solids, depending on
the system.
Solids dewaterability depends
on the relative amounts of sulfites
and sulfates that form in the desul-
furization process. Generally,
dewatering is improved by a higher
ratio of sulfate to sulfite. Calcium
sulfate can coprecipitate with
calcium sulfite as (1 — x)CaS03
• xCaS04 • 1/aH20 or can precipitate
asCaS04- 2H20. In forced-oxidation
systems, however, only gypsum
solids are formed because all of the
sulfite reacts with the available
oxygen. Coprecipitate solids are
usually plate shaped, 0.5 to 2.0 jurn
thick and 2 to 4 /Am long. Gypsum
solids are usually large, bulky crystals
1 to 100 jLim or larger.18
Dewatering characteristics also
are influenced by crystal size, which
is affected by the precipitation
conditions in the effluent holding
tank and the amount of solids
recirculated in the system.19'20
Solids from a forced-oxidation
system, which contain essentially
only calcium sulfate, can be
dewatered to about 80 to 90 percent
solids using filtration or centrifuga-
tion.13'21 To obtain a better product
for disposal, the Sherburne County
FGD systems (of Northern States
Power) have incorporated forced
oxidation into the overall systems
before clarification.22
Stabilization Processes. Solids
stabilization is optional in system
design. Stabilization lowers
permeability, reduces leaching, and
improves the structural stability of
the solids. Untreated solids are
difficult to handle and transport.
Moreover, untreated solids disposal
has caused concern about con-
tamination of ground water with
leachates and removal of large
areas of land from productive use.
Solids from FGD processes usually
contain some fly ash, a major
source of trace elements in the
leachate. Unstabilized solids high
in calcium sulfite are also difficult to
dewater, and are thixotropic. Un-
stabilized solids cannot be used
as a load-bearing material because of
their poor structural properties.
-------
At least 1 6 vendor companies
currently offer waste solids fixation
processes, but only two processes—
Dravo's Calcilox and ID Conver-
sion System's (IUCS) POZ-0-TEC—
have been developed and tested
sufficiently to be commercially
feasible for use with FGD waste
solids.
In the Dravo process, Calcilox—a
product derived from basic glassy
blast furnace slag—is added to
FGD solids. The only full-scale
Dravo fixation operation is at
Pennsylvania Power Company's
Bruce Mansfield plant.1
The IUCS process employs vacuum
filter dewatering of FGD solids,
then adds lime, dry fly ash, and
other substances to produce a dry
product called POZ-0-TEC, which
can be used as landfill. Fourfull-scale
systems are currently in operation:1
• Columbus and Southern Ohio
Electric Co., Conesville Plant
• Commonwealth Edison Co.,
Powerton Station
• Duquesne Light Co., Phillips
Power Station
• Duquesne Light Co., Elrama
Power Station
A definite increase in solids stability
has been demonstrated when
fixation processes are used. This
improved stability allows the
landfilled area to be used produc-
tively. The leaching of contaminants
from the stabilized material is
reduced but could still be an
environmental problem.23
Fly Ash and Chloride Effects
The fly ash content of the flue gas
affects scrubbing system design.
Unless fly ash and chlorides
are eliminated upstream, they are
removed by the S02 scrubber.
An important design decision for
coal-fired system applications is
whether to remove particles up-
stream of the scrubber. The current
trend in the utility industry is
to install a high-efficiency precipi-
tator upstream. Low-efficiency
precipitators (90 to 95 percent
removal) or mechanical collectors
may be considerably cheaper to
operate, but the scrubber must still
be designed to remove residual
particles.
Some scrubber types (venturi or
mobile bed) can control both
particles and S02 effectively.
Although the capital cost may be
kept to a minimum, there are
several significant disadvantages
associated with removing particles
in the FGD scrubber:24
• The extent to which dry fly ash
is available as an additive for
solids fixation is reduced. The
importance of this factor depends
on the solids disposal method.
• There is a consensus that
ash causes erosion in the scrubber;
on the other hand, some degree
of erosivity may be desirable
to keep the internal surfaces free
of scale and deposits.
• Particulate emission regulations
may not be met by the scrubber
alone. And, if the scrubber is
shut down, bypassing it may be
impossible without exceeding
the regulations.
• Fly ash cannot be marketed
unless collected dry upstream of
the scrubber.
• Particle scrubbing results in
an increased pressure drop,
which in turn increases power
consumption and, consequently,
operating costs.
The alkaline content (CaO, MgO) of
some fly ashes (e.g., that from lignite)
may be used for S02 removal. The
behavior of magnesium content is
similar to that of magnesium
additives.16
Chlorine may be present in the flue
gas as hydrogen chloride (HCI).
Chlorides enter the S02 scrubbing
liquor unless a prescrubber is
used. Their presence in the slurry
can cause corrosion and may alter
system chemistry. Some of the
chlorides are removed in the water
disposed of with wastes, but there
still may be a serious buildup,
depending on the chloride content of
the fuel combusted. An additional
scrubbing liquor purge may help
to alleviate this problem by producing
a concentrated chloride stream
for disposal.
13
-------
1,250-horsepower pump for sulfur dioxide absorber
14
-------
Environmental
Considerations
The ability of lime/limestone
scrubbing systems to remove over
90 percent of the flue gas S02
has been demonstrated successfully
for brief periods at full-scale
commercial installations. For
example, the S02 removal efficiency
at the Louisville Gas and Electric
Company, Paddy's Run Station,
Boiler No. 6, has been greater than
90 percent when the boiler burns
coal containing 3.7 percent sulfur.
The unit uses a carbide/lime
slurry. Sulfur dioxide removal
efficiencies have been highest when
the carbide/lime slurry contains
significant amounts of magnesium.
High particle removal efficiency
(99 percent and greater) can be
obtained without major operational
problems, as long as calcium
sulfite/sulfate scaling control is
not obstructed. Wet scrubbing of flue
gas can reduce flue gas particle
loadings to environmentally
acceptable loads at reasonable
L/G ratios.6
The major disadvantage of lime/lime-
stone wet scrubbing is the large
volume of solid waste produced.
Scrubber waste can contain
calcium sulfite/sulfate precipitate,
gypsum, limestone in a limestone
system, unreacted CaO in a lime
system, chlorides, inerts, and fly ash.
Usually the waste is disposed of in
ponds or used as landfill after
adequate dewatering, and leachates
from these solids constitute a
possible environmental problem.
Therefore, an impervious liner,
chemical fixation, or some other
environmentally acceptable solution
may be needed.
A limestone scrubber for a 500-MW
boiler burning 3.5-percent-sulfur
coal produces about 61 tons/h
(55 Mg/h) of fly-ash-free waste
after concentration to 50 percent
solids by weight, assuming 79-
percent limestone utilization and
upstream particle removal. For
a 5,260-h/yr loading, the waste
stream would produce 320,000
tons/yr (290,000 Mg/yr),6 requiring a
disposal area of 73 acres (30 ha).25
A lime system operating under
similar conditions produces 54 tons/h
(49 Mg/h) of fly-ash-free solid
waste, assuming 86-percent lime
utilization. A plant operating 5,260
h/yr produces 283,000 tons/yr
(257,000 Mg/yr) of waste,6 requiring
a disposal area of 53 acres (21 ha).25
The EPA has conducted a number of
studies to determine the effective-
ness of various FGD waste stabiliza-
tion and disposal techniques.
These studies examined leachate
migration, run-off characteristics,
and the physical stability of solid
wastes. Stabilized and unstabilized
solids are being tested both in ponds
lined with clay and in those lined
with synthetic materials. Research
to date indicates that chemical
stabilization increases physical
stability and reduces permeability
of solid waste, but that it does
not eliminate the leaching of trace
elements. When lined ponds are
used for disposal, the migration of
leachates is restricted.26
In Japan, land use considerations
have resulted in process modifica-
tions to produce a more useful
byproduct. Fly ash and chlorides
are eliminated from the flue gas
before it enters the absorber, and
the bleed stream from the holding
tank is oxidized to gypsum before
concentration. Disposal problems are
avoided because the purified
gypsum is sold to the wallboard
industry.27
A method of oxidation similar to
that used in Japan has been
demonstrated on solid wastes con-
taining fly ash and chlorides.
Currently, EPA is conducting re-
search to study forced oxidation
and fly-ash-free limestone scrub-
bing.10'13
15
-------
Status of Development
Lime/limestone scrubbing was
used first about 40 years ago in
England to control S02 emissions
from commercial boilers on a pilot
scale. Success led to the construction
of full-scale scrubbing plants
that proved effective in removing
S02 and dust from stack gas.
The process was also the first
stack-gas desulfurization technology
used in the United States. The trend
toward lime/limestone scrubbing
for S02 removal is strong today
owing to rapid progress in solving
process problems and a clearer
understanding of process chemistry.
As of June 1980, over 58,000 MW
of electrical generating capacity in
the United States had been com-
mitted to operating lime/limestone
scrubbing systems. Fifty-eight
facilities were in operation (Tables
2 and 3) and 71 were under
construction or in the planning stage
(Tables 4 and 5).1 The proceedings
from EPA's most recent FGD
symposium2829 contains papers
describing the performance of
many of these operational U.S.
installations and of foreign installa-
tions.
Problems in operating lime/limestone
scrubber systems have been
encountered in the following areas:
• Scrubber and pipe plugging
• Chemical scaling
• Erosion and corrosion
• Mist eliminator/reheater operation
• Solids disposal
Many of these problems have been
solved or alleviated as a result
of research and development
efforts.62829
In general, scrubber and pipe
plugging has been eliminated by
design simplification. Internal
scrubber design has been refined.
Incidence of pipe plugging has been
reduced by eliminating unnecessary
piping bends, valves other than
gate valves, and obstacles in the
piping system, and by maintaining
high slurry velocity. Plugging is no
longer considered a serious obstacle
to process reliability.
Plugging, scaling, and corrosion
have occurred frequently in mist
eliminators. Studies at the EPA
Alkali Scrubbing Test Facility—at
the Tennessee Valley Authority's
Scrubber system, Cane Run No. 4
16
-------
Table 2.
Lime and Lime/Limestone FGD Systems Operating in U.S. Utilities as of June 1980
FGD units
Process, utility, and station3
Size (MW) No.
Gas volume
treated
(1,000 stdft3/min)
Fuel
Type
%S02
removal
(design)
Startup
date
Lime:
Arizona Public Service:
Four Corners 1 (R)*
Four Corners 2 (R)*
Four Corners 3 (R)*
Big Rivers Electric: Green 1 (N)
Columbus & Southern Ohio Electric:
Conesville 5 (N)
Conesville 6 (N)
Cooperative Power Association: Coal Creek 1 (N)*
Duquesne Light:
Elrama 1-4 (R)
Phillips 1-6 (R)
Kansas City Power & Light:
Hawthorne 3 (R)
Hawthorne 4 (R)
Kentucky Utilities: Green River 1 -3 (R)
Louisville Gas & Electric:
Cane Run 4(R)
Cane Run 5 (R)
Mill Creek 3 (N)
Paddy's Run 6 (R)
Minnesota Power & Light: Clay Boswell 4 (N)* . .
Minnkota Power Coop.: Milton R. Young 2 (N)*. .
Monongahela Power: Pleasants 1 (N)
Montana Power:
Colstrip 1 (N)*
Colstrip 2 (N)*
Pennsylvania Power:
Bruce Mansfield 1 (N)
Bruce Mansfield 2 (N)
Bruce Mansfield 3 (N)
Utah Power & Light:
Hunter 1 (N)
Hunter 2 (N)
Huntington 1 (N)
Lime/Limestone: Tennessee Valley Authority:
Shawnee 10A (R)
Shawnee 10B (R)
175
175
229
242
411
411
327
510
408
90
90
64
188
200
442
72
475
185
618
360
360
917
917
917
360
360
366
10
10
2
2
2
2
2
2
4
5
5
2
2
1
2
2
4
2
NA
2
4
3
3
6
6
6
4
NA
4
350b
350b
458b
484b
882
882
654b
1,840
1,778
222
222
256
490
431
1,232
225
950b
1,124
1,236b
1,148
1,148
2,267
2,270
2,270
1,248
720 b
1,248
24
24
Coal
Coal
Coal
Coal
Coal
Coal
Lignite
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Lignite
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
0.75
0.75
0.75
3.75
4.67
4.67
0.63
2.20
1.92
0.60
0.60
4.00
3.75
3.75
3.75
2.50
0.94
0.70
3.70
0.77
0.77
3.00
3.00
3.00
0.55
0.55
0.55
2.90
2.90
67.5
67.5
67.5
90
89.5
89.5
90
83
83
70
70
80
85
85
85
80
89
75
90
60
60
92
92
92
80
80
80
1979
1979
1979
1979
1977
1978
1979
1975
1973
1972
1972
1975
1976
1977
1978
1973
1980
1977
1979
1975
1976
1975
1977
1980
1979
1980
1978
1972
1972
aN = new. R = retrofit. Asterisk (*)= lime/alkaline fly ash.
bEstimated: stdft3/min = 2,000 X MW rating.
'Experimentally controlled.
Note.—NA = data not available.
SOURCES: Smith, M., M. Melia, and N. Gregory, EPA Utility FGD Survey: October-December 1979, EPA 600/7-80-029a, NTIS No. Pb 80-176-811,
Jan. 1 980. Smith, M., et al., EPA Utility FGD Survey: April-June 1980, EPA 600/7-80-029c, July 1980.
(TVA) Shawnee steam plant—show
that deposit formation was reduced
significantly when feed utilization
was increased above 85 percent in a
limestone system.8 Reduced gas
velocity, increased spray droplet
size for spray towers, and increased
distance between the scrubber
and the mist eliminator decrease
maintenance requirements by
keeping to a minimum slurry carry-
over from the scrubber. Reliability
is also improved when the mist
eliminator is oriented in a vertical
or sloped position so that captured
mist and wash water can drain more
effectively. With proper washing
techniques and control of stoichi-
ometry, mist eliminator plugging
is no longer an obstacle.14
17
-------
Table 3.
Limestone FGD Systems Operating in U.S. Utilities as of June 1980
Process, utility, and station3
FGD units
Size (MW) No.
Gas volume
treated
(1,000stdft3/min)
Fuel
Type
96 S
% S02
removal
(design)
Startup
date
Alabama Electric Coop.:
Tombigbee 2 (N) 179 2 476 Coal 1.15 85 1978
Tombigbee 3 (N) 179 2 464 Coal 1.15 85 1979
Arizona Electric Power Coop.:
Apache 2 (N) 97.5 2 570 Coal 0.55 85 1978
Apache 3 (N) 97.5 2 570 Coal 0.55 85 1979
Arizona Public Service:
Cholla 1 (R) 119 4 678 Coal 0.50 92 1973
Cholla 2 (N) 264 4 1,401 Coal 0.50 75 1978
Central Illinois Light: Duck Creek 1 (N) 416 4 1,002 Coal 3.30 85 1976
Colorado Ute Electric Association: Craig 2 (N) 447 4 894b Coal 0.45 85 1979
Commonwealth Edison: Powerton 51 (R) 450 3 900b Coal 3.53 74 1980
Indianapolis Power & Light: Petersburg 3 (N) 532 4 1,350 Coal 3.25 85 1977
Kansas City Power & Light: La Cygne 1 (N) 874 8 1,705 Coal 5.39 80 1973
Kansas Power & Light:
Jeffrey 1 (N) 540 6 1,080b Coal 0.32 50 1978
Jeffrey 2 (N) 490 NA 980b Coal 0.30 NA 1980
Lawrence 4 (R) 125 2 311 Coal 0.55 73 1976
Lawrence 5 (N) 420 2 1,036 Coal 0.55 73 1971
Northern States Power:
Sherburne 1 (N)* 740 12 2,115 Coal 0.80 50 1976
Sherburne 2 (N)* 740 12 2,115 Coal 0.80 50 1977
Salt River Project: Coronado 1 (N) 280 2 560b Coal 1.00 82.5 1979
South Carolina Public Service:
Winyah 2 (N) 140 1 300 Coal 1.70 69 1977
Winyah 3 (N) 280 NA 560b Coal 1.70 NA 1980
South Mississippi Electric Power:
R. D. Morrow 1 (N) 124 1 290 Coal 1.30 85 1978
R. D. Morrow 2 (N) 124 1 290 Coal 1.30 85 1979
Southern Illinois Power Coop.: Marion 4 (N) 184 2 523 Coal/refuse 3.50 89.4 1979
Springfield City Utilities: Southwest 1 (N) 194 2 455 Coal 3.50 80 1977
Tennessee Valley Authority: Widows Creek 8 (R) 550 4 1,100b Coal 3.70 80 1977
Texas Utilities:
Martin Lake 1 (N) 595 6 1,492 Lignite 0.90 70.5 1977
Martin Lake 2 (N) 595 6 1,490 Lignite 0.90 70.5 1978
Martin Lake 3 (N) 595 6 1,490 Lignite 0.90 70.5 1979
Monticello 3 (N) 800 3 2,354 Lignite 1.50 74 1978
aN = new. R = retrofit. Asterisk (*) = limestone/alkaline fly ash.
bEstimated: stdft3/min = 2,000 X MW rating.
Note.—NA = data not available.
SOURCES: Smith, M., M. Melia, and N. Gregory, EPA Utility FGD Survey: October-December 1979, EPA 600/7-80-029a, NTIS No. Pb 80-176-811,
Jan. 1 980. Smith, M., et al., EPA Utility FGD Survey: April-June 1980, EPA 600/7-80-029c, July 1980.
Much effort has been spent on
development and design for scale
prevention. High solids concentra-
tion in the circulating slurry (up to
1 5 percent), increased L/G ratios,
and longer residence times in
the scrubber holding tank have
helped to alleviate scaling problems.
A number of commercial-size
installations have demonstrated
scale-free service during contin-
uous operation.1
A disadvantage of using high
solids concentration to avoid scaling
is the abrasive effect of the solids
on spray nozzles, pumps, and
piping. The current trend is to use
stainless steel, Stellite, refractory,
or other hardened materials for
spray nozzle construction. Soft
rubber or neoprene-lined carbon
steel can be effective for pump and
piping material under abrasive
conditions at temperatures up to
175° F (80° C). Erosion and sig-
nificant weight loss of the spheres
have been noted in turbulent
contact absorbers.
To minimize erosion and corrosion,
surfaces in the wet scrubbing system
that come in contact with wet S02
or acid scrubber liquor must be
constructed of acid- or abrasive-
resistant materials. Stainless
18
-------
Table 4.
Lime and Lime/Limestone FGD Systems Planned or Under Construction in U.S. Utilities as of June 1980
Process, utility, and station3
FGD units
Size(MW) No.
Gas volume
treated11
(1,000stdft3/min)
Fuel
Type
% S02
removal
(design)
Startup
date
Lime:
Arizona Public Service:
Four Corners 4 (R) 755 NA 1,510 Coal 0.75 NA 1982
Four Corners 5 (R) 755 NA 1,510 Coal 0.75 NA 1982
Big Rivers Electric:
D. B. Wilson 1 (N) 440 NA 880 Coal NA NA 1984
D. B. Wilson 2 (N) 440 NA 880 Coal NA NA 1985
Green 2 (N) 242 2 484 Coal 3.75 90 1980
Cincinnati Gas & Electric: East Bend 2 (N) 650 3 1,300 Coal 5.00 87 1980
Cooperative Power Association: Coal Creek 2 (N)*.... 327 4 654 Lignite 0.63 90 1980
East Kentucky Power Coop.: Spurlock 2 (N) 500 NA 1,000 Coal 3.50 90 1981
Grand Haven Board of Light& Power: J.B.Sims 3 (N) 65 2 130 Coal 2.75 NA 1983
Los Angeles Department of Water & Power:
Intermountain 1 (N) 820 NA 1,640 Coal 0.79 NA 1986
Intermountain 2 (N) 820 NA 1,640 Coal 0.79 NA 1987
Intermountain 3 (N) 820 NA 1,640 Coal 0.79 NA 1988
Intermountain 4 (N) 820 NA 1,640 Coal 0.79 NA 1989
Louisville Gas & Electric:
Mill Creek 1 (R) 358 NA 716 Coal 3.75 NA 1980
Mill Creek 2 (R) 350 NA 700 Coal 3.75 NA 1981
Mill Creek 4 (N) 495 4 990 Coal 3.75 NA 1981
Monongahela Power: Pleasants 2 (N) 618 4 1,236 Coal 4.50 90 1980
Montana Power:
Colstrip 3 (N)* 700 NA 1,400 Coal 0.70 NA 1983
Colstrip 4 (N)* 700 NA 1,400 Coal 0.70 NA 1984
West Penn Power: Mitchell 33 (R) 300 NA 600 Coal 2.80 95 1982
Lime/limestone: Tampa Electric: Big Bend 4 (N) 475 NA 950 Coal 2.35 90 1984
aN = new. R = retrofit. Asterisk (*) = lime/alkaline fly ash.
""Estimated: stdft3/min = 2,000 X MW rating.
Note.—NA = data not available.
SOURCES: Smith, M., M. Melia, and N. Gregory, EPA Utility FGD Survey: October-December 1979, EPA 600/7-80-029a, NTIS No. Pb 80-176-811,
Jan. 1 980. Smith, M., et al., EPA Utility FGD Survey: April-June 1980, EPA 600/7-80-029c, July 1980.
steel or rubber-lined carbon steels
are now being used for scrubber
shells and internals, and glass
flake epoxy-type materials have been
used for scrubber shell and tank
linings. Various other corrosion re-
sistant materials have been used
for scrubber pumps and piping.8'28'29
For many systems, reheating
presents design problems. In cases
where heat exchangers are placed
in the duct, materials passing through
the mist eliminator may plug,
scale, or corrode the reheater sur-
faces. The problem may be kept
to a minimum by proper selection
of materials and efficient mist
removal. Direct-fired in-line reheaters
exhibited poor combustion in the
past because of the quenching
effect of the cool gas stream. Recent
design improvements such as
external combustion chambers,
however, make these systems
operable.8 Indirect reheaters
(i.e., those that heat air externally
for mixing with the flue gas) are
probably the least troublesome and
most reliable; they may also be
the most expensive.
Problems associated with solid
waste disposal are receiving in-
creased attention as problems more
critical to system reliability are
solved. Currently, waste solids are
stored in ponds or stabilized and
used as a landfill material. Both
unstabilized and stabilized solids
are susceptible to leaching of
trace elements. Lining waste ponds
prevents migration of leachates,
but limits the dewatering capacity
of the pond.30'31
19
-------
Table 5.
Limestone FGD Systems Planned or Under Construction in U.S. Utilities as of June 1980
FGD units
Process, utility, and station3
Size (MW) No.
Gas volume
treated6
(1,000 stdft3/min)
Fuel
Type
%S
%S02
removal
(design)
Startup
date
Arizona Public Service: Cholla 4 (N)
Associated Electric Coop.: Thomas Hill 3 (N)
Basin Electric Power Coop.:
Laramie River 1 (N)
Laramie River 2 (N)
Central Illinois Light: Duck Creek 2 (N)
Colorado Ute Electric Association: Craig 1 (N)
Deseret Generation & Transmission Coop.:
Moon Lake 1 (N)
Moon Lake 2 (N)
Hoosier Energy:
Merom 1 (N)
Merom 2 (N)
Houston Lighting & Power:
Limestone 1 (N)
Limestone 2 (N)
W. A. Parish 8 (N)
Indianapolis Power & Light:
Patriot 1 (N)
Patriot 2 (N)
Patriot 3 (N)
Petersburg 4 (R)
Iowa Electric Light & Power: Guthrie 1 (N)
Jacksonville Electric Authority:
New Project 1 (N)
New Project 2 (N)
Lakeland Utilities: Mclntosh 3 (N)
Michigan South Central Power Agency: Project 1 (N)
Muscatine Power & Water: Muscatine 9 (N)
New York State Electric & Gas: Somerset 1 (N)
Northern States Power: Sherburne 3 (N)
Pacific Gas & Electric:
Montezuma 1 (N)
Montezuma 2 (N)
Plains Electric G&T Coop.: Plains Escalante 1 (N) . . . .
126
670
570
570
450
447
410
410
441
441
750
750
492
650
650
650
530
720
600
600
364
55
166
870
860
800
800
233
NA
4
5
5
NA
4
NA
NA
1
1
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
2
NA
2
NA
NA
NA
NA
NA
252
1,340
1,140
1,140
900
894
820
820
882
882
1,500
1,500
984
1,300
1,300
1,300
1,060
1,440
1,200
1,200
728
110
332
1,740
1,720
1,600
1,600
466
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Lignite
Lignite
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
0.50
4.80
0.81
0.81
3.30
0.45
0.50
0.50
3.50
3.50
1.08
1.08
0.60
3.50
3.50
3.50
3.50
0.40
3.00
3.00
2.56
2.25
3.00
2.20
0.80
0.80
0.80
0.80
NA
NA
90
90
NA
85
95
95
90
90
NA
NA
82
NA
NA
NA
NA
NA
NA
NA
85
NA
94
90
NA
NA
NA
NA
1981
1982
1980
1981
1986
1980
1984
1988
1982
1981
1985
1986
1984
1987
1987
1987
1984
1984
1985
1987
1981
1982
1982
1984
1985
1989
1990
1983
20
-------
Table 5.
Limestone FGD Systems Planned or Under Construction in U.S. Utilities as of June 1980—Concluded
FGD units
Process, utility, and station8
Gas volume
treatedb
Fuel
Size(MW) No. (1,000stdfr7min)
Type
%S02
removal
(design)
Startup
date
Public Service Indiana: Gibson 5 (N)
Salt River Project:
Coronado 2 (N)
Coronado 3 (N)
San Miguel Electric Coop.: San Miguel 1 (N)
Seminole Electric:
Seminole 1 (N)
Seminole 2 (N)
Sikeston Board of Municipal Utilities: Sikeston 1 (N) .
South Carolina Public Service:
Cross 1 (N)
Cross 2 (N)
Winyah 4 (N)
Southwestern Electric Power: Henry W. Pirkey 1 (N). .
Springfield Water, Light, & Power: Dallman 3 (N)
Tennessee Valley Authority:
Paradise 1 (R)
Paradise 2 (R)
Widows Creek 7 (R)
Texas Municipal Power Agency: Gibbons Creek 1 (N).
Texas Power & Light:
Sandow 4 (N)
Twin Oaks 1 (N)
Twin Oaks 2 (N)
Texas Utilities: Martin Lake 4 (N)
Utah Power & Light:
Hunter 3 (N)
Hunter 4 (N)
650
280
280
400
620
620
235
500
500
280
720
205
704
704
575
400
382
750
750
750
400
400
2
2
4
NA
NA
3
NA
NA
2
4
2
6
6
NA
3
3
NA
NA
NA
NA
NA
1,300
560
560
800
1,240
1,240
470
1,000
1,000
560
1,440
410
1,408
1,408
1,150
800
764
1,500
1,500
1,500
800
800
Coal
Coal
Coal
Lignite
Coal
Coal
Coal
Coal
Coal
Coal
Lignite
Coal
Coal
Coal
Coal
Lignite
Lignite
Lignite
Lignite
Lignite
Coal
Coal
3.30
1.00
0.60
1.70
2.75
2.75
2.80
1.80
1.80
1.70
0.80
3.30
4.20
4.20
3.70
1.06
1.60
0.70
0.70
0.90
0.55
0.55
NA
82.5
NA
86
NA
NA
NA
NA
NA
NA
99
95
NA
NA
NA
NA
75
NA
NA
NA
NA
NA
1982
1980
1988
1980
1983
1985
1981
1985
1985
1981
1984
1980
1982
1982
1981
1982
1980
1984
1985
1985
1983
1985
aN = new. R = retrofit.
bEstimated: stdft3/min = 2,000 X MW rating.
Note.—NA = data not available.
SOURCES: Smith, M., M. Melia, and N. Gregory, EPA Utility FGD Survey: October-December 1979, EPA 600/7-80-029a, NTIS No. Pb 80-1 76-811,
Jan. 1980. Smith, M., et al., EPA Utility FGD Survey: April-June 1980, EPA 600/7-80-029c, July 1980.
21
-------
System Requirements Raw Materials and Utilities
Lime and limestone scrubbing
systems have larger raw material
requirements than do regenerable
FGD processes, but, as a rule, for
limestone systems the raw material
cost is relatively low. Both lime
and limestone FGD processes have
low energy requirements compared
with the regenerable processes.32
These energy requirements include:
• Pumping energy to move the
scrubbing slurry through the
process equipment
• Electric powerforflue gas booster
blowers (forced- or induced-draft
fans)
• Stack gas reheat (assumed
to be indirect steam for this
analysis)
• Electric power for auxiliary equip-
ment, such as agitators, feed
preparation equipment, and
dewatering equipment
Table 6 shows system raw material
and energy requirements of lime/
limestone processes for three
sizes of new coal-fired power plants,
based on a recent TVA study.33 Many
variables in system design and
operating conditions affect these
requirements, and must be con-
sidered before the information in
Table 6 is applied to a specific
installation. The table assumes
that pebble lime is purchased in a
form suitable for slaking; therefore,
energy for calcining limestone to
produce lime is not included in the
lime system energy requirements.
As plantsize or coal sulfurcontent in-
crease, however, the extra revenue
requirements for lime with on-site
calcination decrease. The break-even
point for coal containing 3.5 percent
sulfur is 1,150 MW. For coal
containing 5 percent sulfur 750 MW
is the break-even point for econom-
ically feasible on-site calcination.33
The large quantity of lime or
limestone required for S02 removal
and the associated disposal of the
large volume of waste solids produced
are major expense components
for the process. Limestone systems
usually require substantially
more reagent than do lime systems
because of limestone's lower
reactivity.
Table 6.
Estimated Annual Raw Material and Utility Requirements for Lime/Limestone
FGD Processes
Component
Boiler size (MW)
200
500
1,000
Lime scrubbing system:
Raw materials: lime (1,000 tons) 28.1
Utilities:
Steam (109 Btu) 1 99.7
68.6 131.6
Process water (106 gal) .
Electricity (106 kWh)
Limestone scrubbing system:
Raw materials: limestone (1,000 tons).
Utilities:
Steam (109 Btu)
Process water (106 gal)
95.1
19.6
488.4
232.6
47.0
944.2
503.5
90.3
65.5 159.3 305.2
Electricity (106 kWh)
200.3
100.1
22.5
489.8
243.4
946.8
527.0
54.2 104.2
Note.—Midwest plant operating 7,000 h/yr. Stack gas reheat to 175° F. 3.5% sulfur coal. 79% S02
removal. Meets emission regulation of 1.2 Ib S02 per 106 Btu. Pond disposal 1 mile from FGD
facilities.
SOURCE: Anderson, K. D., J. W. Barrier, W. E. O'Brien, and S. V. Tomlinson, Definitive SOX
Control Process Evaluations: Limestone, Lime, and Magnesia FGD Processes, EPA 600/7-80-001,
NTIS No. Pb 80-196-314, Jan. 1980.
22
-------
Lime systems usually operate at
higher utilizations and, therefore,
lose less reagent in the waste solids.
The unreacted species in a fly-ash-
free system represent 11 percent
by weight of the lime solids and
1 5 percent by weight of the
limestone solids. Limestone systems
can be designed to obtain higher
utilization by a number of pro-
cedures, and these techniques are
the subject of continuing experi-
mental work.13
Although lime utilization is higher
than that of limestone, lime systems
are usually more expensive to
operate. Lower feed material require-
ments often are outweighed by the
higher price of lime. But under
conditions such as small plant size,
low-sulfur coal, and low heat
rates the lime process is more
economical to operate than the
limestone process. Slightly below
the 200-MW power plant size, with
3.5-percent-sulfur coal, lime has
lower annual revenue requirements.
Lime also becomes more economical
for a 500-MW power plant when
coal contains less than 1.5 percent
sulfur.33
The sum of the liquid-side energy
requirement for pumps and the
gas-side energy requirement for fans
usually remains fairly uniform
for most types of scrubbers. For
example, fan power needed to over-
come the high gas-side pressure
drop in a packed-bed absorber
(e.g., mobile bed absorber) is nearly
twice the slurry pumping requirement.
Scrubbers with an open configura-
tion (e.g., spray towers) are charac-
terized by lower gas-side pressure
drops and higher liquid flow
rates, and therefore require less
energy for fans and more energy
for pumps.6
Pumping energy requirements for
scrubbers are lower for lime systems
than limestone systems. Operation
at lower L/G ratios in lime sys-
tems reduces the slurry pumping
requirement.
As a rule, pumping requirements
are low for transporting waste solids
from the scrubber area to the
disposal area if on-site interim ponds
are used for secondary dewatering.
Systems with vacuum filters or
centrifuges and those with more
distant disposal sites require
more energy.
Installation Space and Land
Installation space and land require-
ments for lime/limestone FGD
systems vary depending on site-
specific factors: size of the plant,
type of scrubber, number of effluent
holding tanks, and type of solids-
dewatering system. To compare lime
and limestone systems, a typical
installation for a new 500-MW
boiler burning 3.5-percent-sulfur coal
will be considered. Figures and
dimensions have been adapted from
a TVA study.3
The same scrubbing system may be
used with both FGD systems.
Figure 6a shows the total estimated
land requirement for a 500-MW
lime FGD system—1.04 acres
(0.42 ha), of which the process
control and storage area accounts
for 0.54 acres (0.21 ha).
Figure 6b shows the total estimated
land requirement for a typical
limestone FGD system—2.5 acres
(1.0 ha). Of this total, the storage
and process control area accounts
for 1.76 acres (0.71 ha).
Although the absorber systems for
the two processes require the
same area, the total area for the
limestone system is twice that of
lime. The difference results from the
need to store limestone in greater
quantities because of its lower
utilization values in the absorber
systems. An outside pile of pelletized
limestone, approximately 1 65 ft
(50 m) in diameter, is used along
with a line of hoppers and conveyors
(Figure 6b).
A large additional area is needed
for waste solids disposal, on or off
site. A lifetime pond (assuming
a lifetime of 14.5 years or 127,500
operating hours) for a lime system
would require an area of 188 acres
(76 ha) with an initial depth of
40 ft (12 m). A limestone system
would require a pond 40 ft deep (12m)
with an area of 206 acres (83 ha).
Fly ash disposal in either scrubber
system (or with no scrubber system)
requires an additional pond area of
130 acres (53 ha).
23
-------
198 ft
(a)
Paniculate venturi
Weigh belt
Slaker / Storage bin
Key
Flue gas/off-gas
Cleaned flue gas
Absorption liquor
Sulfur products
I I Other systems
125 ft
Participate venturi
198 ft
Wet ball mills
Bins
o
Slurry Weigh belt
feed
Limestone
pile
Hopper
82 ft
tank
Process
control
.41 1 ft.
Conveyor
187 ft
Figure 6.
Land Requirements for FGD Systems (500-MW Boiler Size): (a) Lime and (b) Limestone
24
-------
Costs
Because full-scale lime/limestone
scrubbing systems have been
installed on a number of utility
boilers, capital and operating costs
can be calculated with reasonable
accuracy for specific base cases.
The estimated and actual costs
of an FGD system can vary widely
depending on the assumptions
made, conditions of operation,
options included, and degree
of redundance, among other factors.
Cost estimates for lime and lime-
stone FGD processes were pre-
pared by TVA.3-33
Tables 7 and 8 present specific
components of 1980 annual operat-
ing costs for a lime and a limestone
FGD system, respectively. The
tabulations assume installation on
a new 500-MW boiler burning
3.5-percent-sulfur coal, and providing
79 percent S02 removal. The annual
operating costs for a lime system
are about 6 percent higher than
for a limestone system, primarily
because of the higher raw material
cost (0.823 mill/kWh for lime
versus 0.319 mill/kWh for limestone).
The raw material cost accounts for
about 19 percent of the annual
operating cost for a lime system
and about 8 percent of that for a
limestone system.
The requirement for 90 percent S02
removal, compared with the 79
percent removal assumed in Tables 7
and 8, has little effect on the annual
Table 7.
Annual Operating Costs for a Lime FGD System on a New 500-MW Coal-Fired Boiler
Costs
Component
Annual quantity
Unit ($)
Annual
operating
($1,000)
Mills/kWh
Direct costs:
Conversion costs:
Operating labor and supervision 25,990 man-hours 12.50/man-hour 324.9 0.093
Utilities:
Steam 488.4 X 109 Btu 0.002/1,000 Btu 976.8 0.279
Process water 232.6 X 106 gal 0.12/1,000 gal 27.9 0.008
Electricity 47.0X106kWh 0.029/kWh 1,363.2 0.389
Maintenance, labor and material 1,691.9 0.483
Analyses 3,760 man-hours 17.00/man-hour 63.9 0.018
Total conversion costs 4,448.6 1.270
Delivered raw materials: lime 68,600 tons 42.00/ton 2,881.2 0.823
Total direct costs 7.329.8 2.093
Indirect costs:
Capital charges:
Depreciation, interim replacements, and insurance at 6% of total
depreciable investment 2,587.6 0.739
Average cost of capital and taxes at 8.6% of total capital investment. . . 3,897.4 1.113
Overhead:
Plant, 50% of conversion costs less utilities 1,040.4 0.297
Administrative, 10% of operating labor 32.5 0.009
Total indirect costs 7,557.9 2.158
Total annual operating costs 14,887.7 4.251
Note.—Midwest plant, operating 7,000 h/yr. 1 980 revenue requirements. 30-yr remaining plant life.1.5 X 106 tons/yr coal burned, 9,000 Btu/kWh,
3.5% sulfur. Stack gas reheat to 175° F. Pond disposal 1 mile from plant. Investment and revenue requirement forfly ash removal and disposal excluded.
Total direct investment, $23,960,000; total depreciable investment, $43,130,000; total capital investment, $45,320,000.
SOURCE: Anderson, K. D., J. W. Barrier, W. E. O'Brien, and S. V. Tomlinson, Definitive SOX Control Process Evaluations: Limestone, Lime, and
Magnesia FGD Processes, EPA 600/7-80-001, NTIS No. Pb 80-196-314, Jan. 1980.
25
-------
Table 8.
Annual Operating Costs for a Limestone FGD System on a New 500-MW Coal-Fired Boiler
Costs
Component
Annual quantity
Unit ($)
Annual
operating
($1,000)
Mills/kWh
Direct costs:
Conversion costs:
Operating labor and supervision 25,990 man-hours 12.50/man-hour 324.9 0.093
Utilities:
Steam 489.8 X 109 Btu 0.002/1,000 Btu 979.6 0.280
Process water 243.4 X 106 gal 0.12/1,000 gal 29.2 0.008
Electricity 54.2 X 106 kWh 0.029/kWh 1,571.5 0.449
Maintenance, labor and material 1,832.3 0.523
Analyses 3,760 man-hours 17.00/man-hour 63.9 0.018
Total conversion costs 4,801.4 1.371
Delivered raw materials: limestone 159,300 tons 7.00/ton 1,115.1 0.319
Total direct costs 5,916.5 1.690
Indirect costs:
Capital charges:
Depreciation, interim replacements, and insurance at 6% of total
depreciable investment 2,813.9 0.804
Average cost of capital and taxes at 8.6% of total capital investment. . . 4,209.1 1.203
Overhead:
Plant, 50% of conversion costs less utilities 1,110.6 0.317
Administrative, 10% of operating labor 32.5 0.009
Total indirect costs 8,166.1 2.333
Total annual operating costs 14,082.6 4.023
Note.—Midwest plant, operating 7,000 h/yr. 1 980 revenue requirements. 30-yr remaining plant life. 1.5 X 106 tons/yr coal burned, 9,000 Btu/kWh,
3.5% sulfur. Stack gas reheat to 175° F. Pond disposal 1 mile from plant. Investment and revenue requirement forfly ash removal and disposal excluded.
Total direct investment, $26,120,000; total depreciable investment, $46,900,000; total capital investment, $48,940,000.
SOURCE: Anderson, K. D., J. W. Barrier, W. E. O'Brien, and S. V. Tomlinson, Definitive SOX Control Process Evaluations: Limestone, Lime, and
Magnesia FGD Processes, EPA 600/7-80-001, NTIS No. Pb 80-196-314, Jan. 1980.
operating costs for both processes.
Limestone system annual operating
costs are increased by 3 percent,
while costs for the lime process,
with its higher raw material cost,
are increased by 5 percent.
Capital and annual operating costs
for scrubbing systems vary de-
pending on several site-specific
factors such as application,
fuel, plant life, and efficiency of S02
removal. Table 9 shows the effect
of various combinations of these
parameters on the cost of lime
and limestone FGD systems. Specific
situations should be compared with
the bases used to estimate the
costs in Table 9. Some reevaluation
will be required for each location.
Tables 7 through 9 assume absorber
waste disposal in an earthen-diked,
clay-lined pond 1 mile (1.6 km) from
the FGD facilities. The waste settles
to 40 percent solids, and the
supernatant is returned to the
FGD system. If pond disposal of
limestone slurry is not practical, fixa-
tion and landfill disposal can be
used; however, this alternative
would increase the annual operating
costs by about 15 percent because
of higher labor and materials
costs.33 Conventional limestone
systems (not force-oxidized systems)
produce more waste solids than
do lime systems; therefore, the extra
costs for fixation and landfill
reduce the difference in annual
operating costs.
26
-------
Table 9.
Estimated Capital and Operating Costs for Lime/Limestone FGD Processes
~ . .... Total capital Annual
System characteristics H . h
investment8 operating costs"
Fuel Plant
Type
% S (yr) rem°Val
Lime
200
200
500
500
500
500
500
500
1,000
1,000
Existing
New
Existing
New
New
New
New
Existing
Existing
New
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Coal
Coal
3.5
3.5
3.5
2.0
3.5
3.5
5.0
2.5
3.5
3.5
20
30
25
30
30
30
30
25
25
30
S
S
S
S
S
90
S
R
S
S
22.8
22.8
46.5
36.9
45.3
46.9
50.3
35.8
71.1
67.6
114
114
93
74
90
94
101
72
71
68
7.6
7.2
15.5
11.7
14.9
17.4
25.4
23.9
5.42
5.15
4.43
3.35
4.25
4.96
3.63
3.42
Limestone
200
200
500
500
500
500
500
500
1,000
1,000
Existing
New
Existing
New
New
New
New
Existing
Existing
New
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Coal
Coal
3.5
3.5
3.5
2.0
3.5
3.5
5.0
2.5
3.5
3.5
20
30
25
30
30
30
30
25
25
30
S
S
S
S
S
90
S
R
S
S
25.1
25.5
50.4
39.8
48.9
50.6
54.8
38.6
75.1
71.7
126
128
101
80
98
101
110
77
75
71
7.5
7.1
14.8
11.7
14.1
14.6
15.9
11.6
23.1
21.8
5.34
5.11
4.22
3.32
4.02
4.15
4.54
3.30
3.30
3.11
"Project beginning mid-1977, ending mid-1980. Average cost base for scaling, mid-1979. Minimum in-process storage; only pumps are spared. Pond
disposal 1 mile from facility. FGD process investment estimate begins with common feed plenum downstream of electrostatic precipitator. No
overtime pay.
b1980 revenue requirements. Power unit operating 7,000 h/yr.
CS = meets emission regulation of 1.2 Ib S02 per 106 Btu. R = meets allowable emission of 0.8 Ib S02 per 106 Btu.
Note.—Midwest plant. Stack gas reheat to 1 75° F. Investment and revenue requirement for fly ash removal excluded.
SOURCE: Anderson, K. D., J. W. Barrier, W. E. O'Brien, and S. V. Tomlinson, Definitive SOX Control Process Evaluations: Limestone, Lime, and
Magnesia FGD Processes, EPA 600/7-80-001, NTIS No. Pb 80-196-314, Jan. 1980.
27
-------
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July 1980.
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tion. Rev. draft rep. Vol. I.
Austin TX, Radian Corporation,
Nov. 1977.
24Slack, A. V. "Lime-Limestone
Scrubbing: Design Considerations."
CEP74(2):7-\, 1978.
25Princiotta, Frank T. Sulfur
Oxide Throw-away Sludge Evalua-
tion Panel. Vol. I. EPA 650/2-75-
01 Oa. 1975.
26Leo, P- P., and J. Rossoff. Control
of Waste and Water Pollution
from Power Plant Flue Gas Clean-
ing Systems: First Annual R and
D Report. EPA 600/7-76-01 8,
NTIS No. Pb 259-211. Oct. 1 976.
27Ando, Jumpei. "Status of S02 and
NOX Removal Systems in Japan."
In Proceedings: Symposium on
Flue Gas Desulfurization, Holly-
wood, FL, November 1977. Vol. I.
EPA 600/7-78-058a. Pp. 59-79.
Mar. 1978.
28U.S. Environmental Protection
Agency. Proceedings: Symposium
on Flue Gas Desulfurization, Las
Vegas, NV, March 1979. Vol. I.
EPA 600/7-79-167a. July 1979.
29U.S. Environmental Protection
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on Flue Gas Desulfurization, Las
Vegas, NV, March 1979. Vol. II.
EPA 600/7-79-1 67b. July 1979.
30Fling, R. B., W. M. Groven, P- P-
Leo, and J. Rossoff. Disposal of
Flue Gas Cleaning Wastes:
EPA Shawnee Field Evaluation-
Second Annual Report. EPA
600/7-78-024. Feb. 1 978.
31 Leo, P. P., R. B. Fling, and J.
Rossoff. "Flue Gas Desulfurization
Waste Disposal Study at the
Shawnee Power Station." In
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FL, November 1977. Vol. II. EPA
600/7-78-058b. Pp. 496-536.
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and D. H. Brown. "Raw Material
and Utility Requirements for
Flue Gas Desulfurization Processes."
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33Anderson, K. D., J. W. Barrier,
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29
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This summary report was prepared jointly by the Radian Corporation of
Austin TX and the Centec Corporation of Reston VA. P. B. Hulman and
J. M. Burke of Radian are the principal contributors. Michael A. Maxwell is the
EPA Project Officer. Photographs were taken at Louisville Gas and Electric
Company's Cane Run Power Plant.
Comments on or questions about this report or requests for information
regarding EPA flue gas desulfurization programs should be addressed to:
Emissions/Effluent Technology Branch
Utilities and Industrial Power Division
IERL, USEPA (MD-61)
Research Triangle Park NC 27711
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, Research Triangle
Park NC, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the U.S. Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
COVER PHOTOGRAPH: Reaction tank with additive feed tank in background
30 * U.S. GOVERNMENT PRINTING OFFICE : 1 981--758-895
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