CD A U.S. Environmental Protection Agency Industrial Environmental Research
•il f^ Off ice of Research and Develnnmflnt Lahnratnrv
u.9. environmental rroncnon Agency industrial tnvironmental Research PDA fiOfi/7
Off ice of Research and Development Laboratory cr^-OUU/ -
Research Triangle Park. North Carolina 27711 MaFCh 1978
CONTROLLING SO2 EMISSIONS
FROM COAL-FIRED
STEAM-ELECTRIC GENERATORS:
WATER POLLUTION IMPACT
(Volume I. Executive Summary)
Interagency
Energy-Environment
Research and Development
Program Report
z
z
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-045a
March 1978
CONTROLLING SO2 EMISSIONS FROM
COAL-FIRED STEAM-ELECTRIC
GENERATORS: WATER POLLUTION
IMPACT (Volume I. Executive Summary)
by
R.L Sugarek and T.G. Sipes
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
Contract No. 68-02-2608
W. A. 10
Program Element No. EHE624A
EPA Project Officer: Julian W. Jones
Industrial Environmental Research Laboratory
Office of Energy, Minerals and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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TABLE OF CONTENTS
Pag
1.0 INTRODUCTION 1
2.0 CONCLUSIONS 3
3. 0 DISCUSSION 4
3.1 Effects of NSPS Alternatives on
Water Requirements 4
3.2 Effects of NSPS Alternatives on
Effluent Quality and Quantity 13
3.3 Effect of SOx Control System Wastewaters
on Receiving Streams 17
3.4 Water Treatment Technology Applicable to
SOx Control Systems 18
ATTACHMENT A 24
ii
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1.0 INTRODUCTION
This study was funded by the EPA's Office of Air Quality
Planning and Standards (OAOPS) at Research Triangle Park, North
Carolina. It is one task in a comprehensive program to review
the New Source Performance Standards for S02 emissions from coal-
fired steam generating plants. The comprehensive impacts of two
alternative revised standards and the existing NSPS are being
examined. The existing NSPS allows an emission rate of 0.52 ug
S02/J (1.2 Ib S02/MM Btu) of heat input. One alternative standard
requires 0.22 ug S02/J (0.5 Ib S02/MM Btu) of heat input. This
standard has the same form as the existing NSPS and thus allows
a credit for physical coal cleaning or use of low-sulfur coal.
The second alternative standard requires 90 percent removal of
S02 from stack gases, regardless of original sulfur content in
the coal.
The analytical objectives of the study were to compare
these alternative NSPS strategies in terms of their effect on
(1) quality and quantity of power plant wastewater effluents,
and (2) amount of plant makeup water required (water consumption).
In addition, alternative SOX control systems were to be compared
with respect to these two factors. The potential effect of S0x
control effluents upon the environment were also to be evaluated
and alternative treatment processes discussed.
A set of 108 model plant systems was defined by OAQPS
for performing these evaluations. These model systems allow a
comparison of the impacts of the three alternatives NSPS strategies,
accommodating the following variables:
Flue gas desulfurization (FGD) technology
(five types)
-------
Coal ultimate analysis (five types)
Plant size (four types)
Additional sulfur removal by physical
coal cleaning
A detailed Task Report, describing the results of this
study, is being published separately.
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2.0 CONCLUSIONS
The main conclusions of the study may be summarized
as follows :
The added water demands imposed by SOX
control increase total plant makeup require-
ments by 8-117o, depending on the process used.
For a 500 MW plant, this amounts to 500-700 gpm.
Adding a physical coal cleaning step raises the
increase in total plant demand from 870 to 127«,
when paired with lime or limestone scrubbing.
For a 500 MW plant, physical cleaning adds 300
gpm to total plant water demand, in addition to
the scrubber's needs.
Stricter NSPS standards have little effect
on water demand.
Requiring 90 percent sulfur removal across
the board has little effect on water demand.
Volume and quality of wastewater streams from
SO control systems are affected very little
by alternative NSPS regulatory strategies.
All effluent streams can be treated to accept-
able levels using proven, commercially avail-
able technologies.
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3.0 DISCUSSION
s
3.1 Effects of NSPS Alternatives on Water Requirements
Defining Parameters
The impact of new regulatory strategies to control
S0x emissions depends potentially on three groups of factors:
Coal type
Sulfur control technology
Plant size
A thorough comparison of these strategies calls for a systematic
review of the effects these factors have, singly and in combina-
tion. Representative values within the available range were
identified for use in making this comparison.
Table 3.1-1 summarizes the representative coal types
chosen for this study. The ultimate analyses used in calculating
were derived from actual coal analyses. Average values or repre-
sentative values were used.
The sulfur removal technologies chosen included five
viable flue gas desulfurization processes and a physical cleaning
process which mechanically removes pyrite from coal. The FGD
processes identified by EPA for this study were:
Lime wet scrubbing
Limestone wet scrubbing
• Wellman-Lord sulfite scrubbing
• Magnesium Oxide slurry absorption
• Double Alkali wet scrubbing
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TABLE 3.1-1
REPRESENTATIVE COAL TYPES
Coal #1
Ultimate Analysis; 0.8% £ (dry basis); 8,000 Btu/lb (AR basis); 6% ash;
30% H20
Represents; Western low-Btu subbituminous coal/lignite (Wyoming, North
Dakota)
Coal #2
Ultimate Analysis; 0.8% S_ (dry basis): 11,000 Btu/lb (AR basis); 6%
ash; 30% H20
Represents; Western high-Btu subbituminous coal (Montana)
Coal #3
Ultimate Analysis: 3.5% ^ (dry basis); 12,000 Btu/lb (AR basis); 12%
ash; 2.6 H20
Represents; Midwestern high-Btu coal (Pennsylvania, Ohio, Kentucky)
Coal /M
Ultimate Analysis; 7.0% _S (dry basis); 12,000 Btu/lb (AR basis); 12%
ash; 5.7% H20
Represents; Midwestern high-sulfur, high-Btu coal (Ohio)
Coal #5
Ultimate Analysis; 2.0% 1; 11,000 Btu/lb; 6% ash; 15% H20
Represents; Product coal from physically cleaning Coal #3
Coal 96
Ultimate Analysis; 4.0% S.; 11,500 Btu/lb; 6% ash; 15% H20
Represents; Product coal from physically cleaning Coal #4
-------
Physical coal cleaning can be accomplished by a. large number of
processes and operations. The choice depends largely on the amount
of sulfur removed and its form within the coal. These cleaning
processes may consume between 1.5 percent and 27 percent of the
circulating water flow, but most values lie between 1.5 percent
and 5.0 percent. An average value of 3.3 percent was chosen to
represent physical coal cleaning in this study, as reflecting
realistic future water management practices.
Plant sizes selected as representative were:
• 1,000 MW
• 500 MW
• 100 MW
• 25 MW
These cover sources ranging from new power plants to older in-
dustrial and utility boilers.
Defining Comparative Cases
An exhaustive comparison of all possible combinations of
regulatory system, technology, coal type and plant size would
require a huge effort. Therefore, EPA's Office of Air Quality
Planning and Standards specified a smaller set of combinations
to be analyzed in this study. Table 3.1-2 summarizes these com-
binations. An additional system was also evaluated, consisting
of existing NSPS applied to a 500 MW plant burning 3,5 percent
sulfur coal, with 40 percent sulfur removal by cleaning and 39
percent by FGD. These systems yielded a total of 108 cases.
The first alternative standard — continued use of
NSPS — serves as a baseline for evaluating new alternatives.
This alternative allows low-sulfur coals to be burned without
scrubbers or coal cleaning. All five FGD systems are evaluated
6
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TABLE 3.1-^-2
EPA/OAQPS ALTERNATIVE CONTROL SYSTEMS FOR MODEL PLANTS
Plant Sizes to
Be Considered. MW
25; 100; 500; 1000
25; 100; 500; 1000
25; 500
25; 500
500
25; 100; 500; 1000
25; 100; 500
25; 500
25; 500
25; 500
FGD Systems
To Be Considered
Lime/limestone
Lime/limestone
Lime/limestone
Lime/limestone
Lime/limestone
Lime/limestone
Alternative Standards and Model Plant Systems
The existing NSPS of 0.52 yg S02/J (1.2 Ib S02/MM
Btu) heat input.
a. ^80 percent S02 removal on a plant burning a typical
coal of 3.5 percent sulfur.
b. A plant burning a typical 7 percent sulfur coal with
about 90 percent S02 removal by FGD.
c. High and low heating value western and eastern low
sulfur coals without FGD for a typical eastern
plant.
d. High and low heating value western low sulfur coals
without FGD for a typical western plant.
e. 40 percent sulfur removal by coal washing of a 2.0
percent sulfur coal, and 40 percent removal by FGD.
a, 90 percent S02 removal by FGD on a typical coal of
3.5 percent sulfur and a typical coal of 7 percent
sulfur.
b. 90 percent S02 removal by FGD on a plant burning
typical high and low heating value western coals
of 0,8 p'ercent S (western plant).
0.215 yg S02/J (0.5 Ib S02 emission/MM Btu) heat Input.
a. 70 to 75 percent SO removal on a plant burning
typical high and low heating value western coals
of 0,8 percent S (western plant).
b. 40 percent sulfur removal by coal washing of a 3,5
percent sulfur coal and 85 percent removal by FGD.
c, 40 percent sulfur removal by coal washing of a 7
percent sulfur coal and 95 percent removal by FGD.
The five systems to be considered are lime, limestone, magnesium oxide, double alkali, and Wellman-Lord,
-------
for this alternative (la) and for the alternative of 90 percent
sulfur removal by scrubbing for all coals (2a). This was done
to display any variations in impacts of the alternative FGD sys-
tems. To limit the total effort, only lime and limestone systems
were used for the remaining cases. These are the predominant FGD
systems now, and are expected to continue to be in the near future.
Similarly, the full range of plant sizes was examined for only some
of the 108 cases. All permutations, however, considered a 500 JMW
plant, which permits comparisons between all the alternative
standards.
Calculations
For each of the 108 cases, the amount of makeup water
required for SOX control and for all other plant operations was
calculated. This yielded a total makeup water requirement
for the plant. The greatest single- plant water requirement is
for cooling. Thus, the proportional demand increase incurred
when SOX control is added depends largely on the cooling mode.
Water management practices also influence total makeup needs.
Total plant make-up requirements, except for SO control equip-
X
ment, were calculated for four types of cooling and water manage-
ment systems. The results, for a 500 MW plant firing 3.5 percent
sulfur, 12,000 Btu coal at 37 percent efficiency, ranged from
4,000 gpm (zero discharge) to 214,000 gpm (once-through). To
evaluate the 108 cases, an intermediate system was chosen. This
system employs recirculatory cooling at five cycles of concen-
tration and 50 percent recirculatory ash handling, and recycles
general service water blowdown to the ash handling system. In
the model 500 MW plant, it requires 6,000 gpm of fresh make-up
water.
The water requirements of the five FGD systems were
calculated as the sum of several components, differing between
8
-------
systems. Table 3.1-3 summarizes the results of these calculations.
The table also includes water requirements for converting S02 in
product streams from Wellman-Lord and Magnesia systems to sulfuric
acid. For all the FGD systems, evaporative losses in the pre-
scrubber or absorber account for most of the makeup requirements.
These requirements are independent of the amount of sulfur removed.
They are also essentially the same for all five processes.
TABLE 3.1-3
V CONTROL SYSTEM MAKEUP WATER REQUIREMENTS3
m3/s
Physical Coal Cleaning 0.015 240
Evaporative Loss 0.030 480
Cooling Water System:
Wellman-Lord Sulfite Scrubbing 0.014 220
Sulfuric Acid Production 0.008 130
Occlusion in Solid Wastes 0.005 75
Prescrubber Slowdown 0.003 54
aThe example requirements given in table are for a base case 500 MW power
plant, operating at 37 percent efficiency, burning 3.5 percent sulfur coal
with an average heating value of 12,000 Btu/lb.
Lime, Limestone and Double Alkali processes produce
sludges in which large amounts of water may be occluded. The
amount of sulfur removed affects the amount of sludge produced.
All three systems, however, lose similar amounts of water for a
given amount of sulfur. Prescrubbers applied to the Wellman-
Lord and Magnesia Slurry systems also remove water in the
form of a prescrubber blowdown stream. Again, all
-------
of the systems lose the same amounts. These amounts are indepen-
dent of the amoijint of sulfur removed, since prescrubbing takes
place before sulfur removal. The Wellman-Lord and Magnesia Slurry
systems also require S02 conversion. If sulfuric acid is made,
substantial makeup is required for the product-acid cooling water
system. This quantity is sensitive to the amount of sulfur re-
moved. In addition, the Wellman-Lord process itself has a sub-
stantial requirement for cooling; it is also sensitive to degree
of sulfur removal.
Physical coal cleaning also produces a sludge in which
water is occluded. Drying results in some additional water loss.
Results
The results of evaluating the 108 cases are presented
in Attachement A to this report. In Figure 1, these results
have been reduced to a form which facilitates comparison of the
NSPS strategies investigated.
Figure 1 displays the absolute amount of makeup water
required by a 500 MW plant, using Lime wet scrubbing, as a func-
tion of coal type and of NSPS strategy. The effects of using
physical cleaning under those strategies allowing such credit
are also shown. The amount of water required by the sulfur control
system is graphically displayed both as an absolute requirement
and as a proportion of total plant makeup.
The existing NSPS alone would permit burning low-sulfur
coals (Numbers 1 and 2) without SO control. This would amount
<2x
to a savings of 8 to 11 percent in total plant water requirements,
depending on the FGD process used. For a 500 MW plant using Lime
wet scrubbing the amount of water saved would be about 500 gpm.
10
-------
TOOOgpm -
6000 -
UJ
111
K
5
o
Ul
E
0.
Ul
<
z
<
o
6000 -
4000 -
3000 -
2000 -
1000
COAL COAL
»3 14
A=600A=600
CASE I
PRESENT NSPS.
BY FQD
COAL COAL COAL COAL
II 12 13 14
A=600A-500A=600A"600
CASE II
90% SO2 REMOVAL
BV FQO
FOR ALL COALS
6600 6600
6800
5BOOI
COAL COAL
II 12
A=500A-500
CASE III
STRICTER NSPS.
BY FQD
6600
5800
COAL
COAL
COAL
COAL
COAL
COAL
»1=O.B%S
»2 = 0.8%3
'3= 3.5%S
»4-=7.0%S
16 = 2.0%3
»6=4.0%S
COAL COAL
• 6 16
ArflOOA-flOO
CASE IV
STRICTER NSPS.
FQD A COAL
CLEANING
COAL
»6
A=700
CASE V
PRESENT NSPS.
FQD A COAL
CLEANING
FIGURE 1. EFFECT OF ALTERNATIVE SO2 CONTROL STRATEGIES
ON TOTAL WATER REQUIREMENTS OF A 500MW PLANT
USING A LIME OR LIMESTONE FGD SYSTEM
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The new Clean Air Act Amendements of 1977, however, preclude this
option. In the future, all new sources will require either FGD,
FGD plus coal cleaning, or an equivalent form of SOa control
technology. Under these circumstances, it is clear that an
NSPS strategy which gives credit for coal cleaning could
result in the use of more water. Tightening NSPS and requiring
90 percent sulfur removal across the board have essentially the
same effects on water use. Both require less water than the paired
FGD/cleaning systems. For a 500 MW plant using Lime scrubbing,
the difference in water requirements between FGD alone and paired
FGD/cleaning is 200 gpm under existing NSPS and 300 gpm under the
tighter NSPS.
The choice of SO control technology also has a significant
X
effect on incremental water requirements. The relative ranking of
the technologies is:
Double AlkaliR"7 plant. Neither coal type nor NSPS strategy affects the relative
rankings or the spread of values between technologies. This in-
sensitivity reflects the fact that most of the major water losses
in SO removal are independent of the amount of sulfur removed.
H
Plant size affects the absolute amount of makeup water
required for SO control, but not the proportional increase in
2£
plant water requirements. These always range from 8 percent
(Double Alkali) to 11 percent OWellman-Lord) . A combination
of physical coal cleaning and Lime wet scrubbing increases
the proportion to 12 percent. Using any of the other FGD
processes with coal cleaning would also increase the propor-
tion, to more than 12 percent for Limestone, Magnesia Slurry
or Wellman-Lord.
12
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3.2 Effects of NSPS Alternatives on Effluent Quality
and Quantity
The wastewaters generated by S0x control vary between
processes. The effluents of those processes having a discharge
to the environment are characterized in summary form in Table
3.2-1.
The Wellman-Lord and Magnesia Slurry FGD systems
require a pre-scrubbing system blowdown. This stream has a
high chlorides concentration, but otherwise has the same
composition as fly ash sluice water. It has approximately 1 per-
cent of the flow rate of the fly ash sluice water. The high
chlorides concentration is usually diluted in the ash pond, be-
fore discharge to a receiving stream.
The Wellman-Lord Sulfite Scrubbing Process and the
sulfuric acid plant require a cooling water system blowdown.
This blowdown is equivalent in composition to the power plant
cooling system blowdown, and is 3 to 5 percent of the flow rate.
The Double Alkali Wet Scrubbing Process and the Mag-
nesia Slurry Absorption Process may require small purges. These
purges cannot be discharged directly to a receiving stream be-
cause of their very poor quality, but water treatment technology
is available. Reuse or discharge is possible after treatment.
The Lime/Limestone Wet Scrubbing Processes should
have no wastewater streams in normal operation. A catastrophic
condition, loading at less than 50 percent of design capacity,
or operator error may require a purge. Water treatment tech-
nology is available to handle this stream to allow reuse or
di scharge.
13
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TABLE 3.2-1
CHARACTERISTICS OF EFFLUENTS FROM SOV CONTROL SYSTEMS
Intermittent Discharges
Purges
Regular Process Wastewater Streams
Prescrubber
Slowdown
Cooling Hater
Slowdown.
Lime/Limestone
Wet Scrubbing
Occurs; Catastrophic
situations; <50Z of
design loading.
Composition: Calcium
sulfite/sulfate to
saturation; Ma and
Cl in high amounts
Volume: Small
NONE
NONE
Wellman-Lord
Sulfite Scrubbing
NONE
Composition;
Chloride: 10,000-
20,000 ppm
TSS: -X.5Z
Trace impurities
Volume; 'vlX fly
ash sluice water
requirement (3 gpm)
Composition; Same
as main plant cool-
ing blowdown
Volume; *v>SZ plant
blowdown rate
(250 gpm)a
Magnesia Slurry
Absorption
Occurs: Periodically
to prevent corrosion
or scaling; sulfate
build-up (possibly)
Composition; 1.2Z
MgSOj; 15Z MgSO,,;
Trace impurities
Volume; 1 gpm for
a 500 MW plant
Composition; As
above
Volume: As above
NONE
Double Alkali,
(Tec Scrubbing
Occurs; Possibly
to prevent corro-
sion or scaling
Composition; High
concentrations of
Ca, SOz/SOa, Na, a,
other impurities
Volume: small
Kane in normal
operation, may be
required for very
high chloride coals.
Composition and volume
would be as above.
NOME
Sulfuric Acid
Production
NONE
NONE
Composition; As
above
Volume: ^32 plant
blowdown rate (ISO
gpm)a
Pldw rate calculated for a base-case 500- MW ppwer plant.
14
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Physical coal cleaning plant water systems are usually
operated as closed loops. There are no direct wastewater streams
from these plants.1 Similarly, producing elemental sulfur from
S02 product streams of Wellman-Lord and Magnesia Slurry systems
creates no wastewater streams.
The lime, limestone, and Double Alkali FGD processes,
and the physical coal cleaning processes are all assumed to operate
with closed-loop solid waste disposal systems. Wastes are
impounded in slurried form. -Recycling water from waste ponds will
have a variable influence on total plant makeup requirements. The
total amount of this recycled water, however, will be small, compared
to overall plant needs. Therefore it has been assumed for
calculation, in interest of consistency, that all SOx system
makeup is obtained from outside sources.
In some areas, annual rainfall exceeds evaporation and
the waste pond tends to gain water. This situation need not
involve an aqueous discharge from the pond, however, since excess
water is normally recycled from the pond to the process to supply
process makeup demands. Although the amount of water available from
waste disposal ponds varies with rainfall, total SOx system
makeup requirements are constant. Thus, external water intake may
be reduced, when rainfall adds to the recyclable supply from
waste ponds. Some treatment of recycled water, however, may be
necessary to prevent corrosion or scaling. In areas where a
very large annual net gain by rainfall is expected, modified
design may be necessary and better solid/liquid separation before
disposal will reduce the size of impoundment needed to contain
Runoff from solid waste disposal piles may contain sulfuric acid,
sulfates , manganese, and iron from a few to several thousand mg/2..
Since these contaminants arise from solid waste, however, they
are not considered in this task.
15
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solid wastes. The net water gain is thereby reduced, relative to
system requirements. The pond itself may be designed to contain
input from individual heavy rainfall events, so that emergency
overflow is not needed.
Sludges associated with the Lime/Limestone and Double
Alkali processes may have some effect on water quality. These
impacts were not included in the scope of this program. They
are being studied for OAQPS under separate contract by Aerospace
Corporation.
Table 3.2-1 shows typical flow volumes for FGD waste
streams from a 500 MW plant. The impacts of the alternative NSPS
strategies on any of these flow rates will be small and, in the
context of total plant operations, negligible. The only waste
streams of appreciable volume will be the additional cooling water
system blowdown required by the Wellman-Lord process and the pro-
duction of sulfuric acid from the waste streams of either the
Wellman-Lord or Magnesia Slurry processes. The quantity of blow-
down is sensitive to the amount of sulfur removed. These additions
to the plant's overall cooling water system blowdown rate total
to a maximum of 8 percent of the rate without SOX control. While
this quanitity is appreciable--up to 400 gpm for a 500 MW plant—
the alternative NSPS strategies using FGD along change it by only
a few percent. This is very small compared to the total plant
rate. The use of a physical coal cleaning step with existing
NSPS, however, might reduce the blowdown rate of the Wellman-Lord
and Magnesia Slurry systems appreciably by cutting the amount of
sulfur removed.
16
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3. 3 Effect of SOV Control System Wastewaters on
Receiving Streams
None of the waste streams listed in Table 3.2-1 will
enter the environment in the form they leave the S0x control sys-
tem.
The scrubbing liquor purges for the Magnesia Slurry
Absorption, Double Alkali wet scrubbing, Lime, and Limestone scrub-
bing processes should not be discharged directly to a receiving
stream. They will be treated to acceptable levels before dis-
charge. The Double Alkali system sulfate purge stream will gen-
erally be recycled to the process after treatment.
The prescrubber blowdown is a wastewater source of
high chloride concentration. The normal procedure is
to route this stream to the ash pond. The chlorides are diluted
to 70 mg/£ (ppm) in an ash pond overflow of 0.13 m3/s (2000 gpm)
for the base case. The additional impact on the receiving stream
is expected to be minimal, but in site-specific instances treat-
ment of the concentrated stream may be required.
The Wellman-Lord condenser cooling water system and
the sulfuria acid plant product cooling water system require
blowdowns. These streams will be treated for discharge together
with other plant cooling water blowdown. Therefore, the addi-
tional impact of this wastewater on receiving stream water qual-
ity is expected to be negligible.
Because adequate water treatment is available, no
SO control system effluent need be discharged at concentrations
harmful to the environment. The degree of treatment will be
determined, for the individual plant, by the combined federal
effluent discharge limitations and the water quality standards
17
-------
placed by the state on the receiving water. Thus, no adverse
water quality impact should result from the implementation of
any of the alternative NSPS strategies.
3.4 Water Treatment Technology Applicable to S0x
Control Systems
Methods of Treatment, by Waste Stream
Magnesia Slurry Process Purge - Economics make
MgSOi* recovery from the purge stream desirable. The following
treatment techniques have been proposed:
1) Sending a sidestream to a deadend pond;
2) Concentration of the mother liquor until
MgSOi» precipitates before sending to a
deadend pond, or treating;
3) "Dissolving MgS03-6H20 slurry with a minimum
amount of sulfur dioxide, filtering the in-
soluble impurities, then reprecipitating sul-
fite with makeup MgO. The resultant crystals
would be filtered and returned to the system;
the mother liquor would be evaporated to re-
cover MgSOi» and the supernatant of soluble
impurities discarded."
Conventional treatment techniques, such as reverse
osmosis, vapor compression distillation, flash evaporation, or
softening-ion exchange, could be used to treat the waste stream
from the recovery processes.
18
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• Double Alkali Sulfate Purge - Several methods for
sulfate removal have been suggested:
1) Precipitation of sulfate as
with the addition of lime (This method
applies only to dilute double alkali
systems) ;
2) Co-precipitation of sulfate with calcium
sulfite in a mixed crystal or solid
solution;
3) Addition of sulfuric acid;
4) Formation of H2SO^ in an electrolytic
cell;
5) Limitation of oxidation.
With the first two methods , sulfates are removed in
the regeneration operation and a sulfate purge is not required.
With methods (3) and (4) , the purge treated for sulfate removal
can be returned to the system. With method (5) , the purge is
discharged with the solid waste. If a purge is necessary to
maintain a desired level of soluble nonsulfur/ calcium species,
the constituents remaining after sulfate removal can be removed
with developed water treatment technology.
Prescrubber Slowdown - Recirculatory systems will
become predominant as a national zero -discharge goal approaches,
Although presently discharged to the ash pond, it will be in-
creasingly desirable to recycle this stream. Developed water
treatment technology can be applied.
19
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System Slowdown - Recirculatory practices
and treatment applicable in power plant cooling systems can be
applied to this stream as required.
Possible Lime/Limestone Purge - Aerospace Corpor-
ation has reported that conventional lime-soda treatment will
allow reuse of this stream within power plant water systems.
If followed by a reverse osmosis treatment, the stream would
be suitable for discharge and use in public water supply. Other
water treatment technologies are applicable but less favorable
economically.
Existing Water Treatment Technologies
There are five water treatment technologies currently
in use which could be applied to S0v control systems:
X
Lime-soda softening
Reverse osmosis
Ion exchange
Vapor compression distillation
Multistage flash evaporation
Not all are equally applicable for the different FGD processes
and waste streams.
Lime-Soda Softening
This process can be used to decrease the concentration
of calcium and magnesium ions in purge liquors from the Lime,
Limestone, Magnesia Slurry, and Double Alkali processes. It can
also be used as a pre-treatment step before reverse osmosis or
ion exchange processes. Calcium, magnesium, and heavy metals are
20
-------
precipitated by the process. Other dissolved solids, such as
sodium and chlorides, will not be removed, however. Thus, the
product water may have to be further treated by reverse osmosis
or ion exchange before it can be recycled to the process. Lime-
soda softening processes are in commercial operation.
Reverse Osmosis
Reverse osmosis could be used to decrease the con-
centration of dissolved solids in the prescrubber blowdown
from the Magnesia Slurry or Wellman-Lord processes, cool-
ing tower blowdown from the processes requiring it, or purge
streams from the Magnesia Slurry, Double Alkali, or Lime/Limestone
Processes. Because the waste stream produced from reverse osmosis
would be large in volume (around 25 percent of the feedwater),
another process, such as vapor compression distillation, would
have to be used in conjunction with reverse osmosis to treat this
waste stream. The purge streams would contain relatively high
concentrations of calcium and/or magnesium ions and would have
to be treated (perhaps by lime-soda softening) to decrease these
concentrations before the streams could be treated by reverse
osmosis. The concentrated waste stream from reverse osmosis unit
will be relatively large in volume. The actual volume will de-
pend on the amount of feedwater recovered. This waste stream
can be further concentrated by vapor compression distillation
or, in some applications, sent to an evaporation pond.
Reverse osmosis units are commercially marketed by a
number of companies. They have been used to treat cooling tower
blowdown water to recover dionized water for reuse, and to pro-
duce drinking water from sea water and inland brackish water.
21
-------
Ion Exchange
"%F~
Ion exchange is a commercially available water treat-
ment process that has been suggested as a possible means for
treating wastewater for FGD processes. Because of the high con-
centration of dissolved solids in these streams, however, treat-
ment by ion exchange may be prohibitively expensive. It has
been estimated that processes such as reverse osmosis would be
more economical than ion exchange for treating water with an in-
let TDS concentration of 1000 mg/£ (ppm) or more. This concen-
tration is typically exceeded by all SO control system effluents
Vapor Compression Distillation
Vapor compression distillation can be used to further
concentrate the waste stream from a reverse osmosis unit. It
can also treat the prescrubber blowdown from the Wellman-Lord
or Magnesia Slurry processes; cooling tower blowdown from the
processes requiring it; or purge streams from the Magnesia
Slurry, Double Alkali, or Lime/Limestone processes.
Approximately 90% of the inlet water can be recovered
for reuse when treating water with an inlet TDS of 10,000 mg/fc
(ppm) (comparable to the water quality of the prescrubber blow-
down) . The brine concentrate, which will be about 10% of the
original stream volume and contain most of the dissolved solids,
can be sent to an evaporation pond or mechanical drying system
for final disposal.
Vapor compression distillation processes are commer-
cially available. They have been installed in electric power
generating stations in the western and southwestern states to
recover deionized water from cooling tower blowdown. Vapor com--
pression distillation is an energy-intensive process requiring
22
-------
approximately 90 kw-hr/1000 gal of water processed. Most of this
energy goes into driving the vapor compressor.
Multistage Flash Evaporation
Multistage flash evaporation could be used to treat
the prescrubber blowdown from the Wellman-Lord or Magnesia
Slurry processes, cooling tower blowdown from any of the
processes, or purge streams from the Magnesia Slurry, Double
Alkali, or Lime/Limestone processes. The product water will
have a low concentration of TDS (less than 50 ppm), and is suit-
able for reuse in the system (even as boiler feedwater) or for
discharge. The remaining concentrated waste can be sent to an
evaporation pond or mechanical drying system for final disposal.
Multistage evaporators have been used in the chemical process
industry for many years and have also been used for desalting
sea water to produce drinking water.
23
-------
ATTACHMENT A
24
-------
MODEL PLANT SYSTEM WATER REQUIREMENTS
N>
Ln
Case
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IB
19
20
21
22
23
24
25
26
27
28
Power
Plant
Capacity
HH
1000
1000
1000
1000
1000
500
500
500
500
500
100
100
100
100
100
25
25
25
25
25
1000
1000
500
500
100
100
25
25
so*
Control
Strategy
Lime
Limestone
Hellman-Lord
Magnesium Oxide
Double Alkali
Lime
Limestone
Hellman-Lord
Magnesium Oxide
Double Alkali
Lime
Limestone
Hellman-Lord
Magnesium Oxide
Double Alkali
Lime
Limestone
Hellman-Lord
Hagnealum Oxide
Double Alkali
Lime
Limestone
Lime
Limestone
Lime
Limestone
Lime
Limestone
Z Sulfur
Removal
76
76
76
76
76
76
76
76
76
76
76
76
76
76
76
76
76
76
76
76
SB
88
88
88
88
88
88
88
Coal "
Type
13
13
»3
13
13
13
13
13
13
13
13
13
13
13
13
13
13
13
13
13
14
14
14
14
14
14
14
14
System 13
Power Plant
Makeup Hater
Requirement
m'/s
0.76
0.76
0.76
0.76
0.76
0.38
0.38
0.38
0.38
0.38
0.076
0.076
0.076
0.076
0.076
0.019
0.019
0.019
0.019
0.019
0.76
0.76
0.39
0.39
0.76
0.76
0.020
0.020
(8PO)
(12,000)
(12,000)
(12,000)
(12.000)
(12,000)
(6.100)
(6,100)
(6.100)
(6,100)
(6,100)
(1,200)
(1,200)
(1.200)
(1,200)
(1,200)
(300)
(300)
(300)
(300)
(300)
(12,000)
(12,000)
(6,200)
(6,200)
(1,200)
(1.200)
(310)
(310)
SOX Control
Strategy
Makeup Hater
Requirement
m'/s
0.069
0.069
0.095
0.082
0.069
0.034
0.034
0.048
0.042
0.034
0.0069
0.0069
0.0095
O.OOBB
0.0069
0.0017
0.0017
0.0024
0.0023
0.0017
0.079
O.OB2
0.039
0.040
0.0082
0.0082
0.0020
0.0020
(gpm)
(1,100)
(1,100)
(i.soo)
(1.300)
(1,100)
(540)
(540)
(760)
(670)
(540)
(110)
(110)
(150)
(140)
(110)
(27)
(27)
(38)
(37)
(27)
(1.250)
(1.300)
(620)
(640)
(130)
(130)
(31)
(32)
Total
Model System
Makeup Water
Requirement
m'/s
0.82
0.82
0.88
0.82
0.82
0.42
0.42
0.43
0.43
0.42
0.082
0.082
0.088
0.088
0.082
0.021
0.021
0.021
0.021
0.021
0.82
0.82
0.43
0.43
0.082
0.082
0.021
0.021
(gpm)
(13,000)
(13.000)
(14,000)
(13.000)
(13.000)
(6.600)
(6.600)
(6.800)
(6.800)
(6.600)
(1.300)
(1.300)
(1,400)
(1.400)
(1.300)
(330)
(330)
(340)
(340)
(330)
(13.000)
(13,000)
(6,800)
(6.800)
(1,300)
(1,300)
(340)
(340)
(Continued)
-------
MODEL PLANT SYSTEM WATER REQUIREMENTS (Continued)
N>
CTi
Case
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
SO
51
52
S3
54
55
56
Power
Plant
Capacity
KM
500
500
SOO
25
25
25
500
SOO
25
25
500
500
1000
1000
1000
1000
1000
500
500
SOO
500
SOO
100
100
100
100
100
25
SO,
Control X Sulfur
Strategy Removal
_
-
-
-
-
-
-
-
-
-
Coal Cleaning/Line
Coal Cleanlng/Llnestone
Lime
Limestone
Uellnan-Lord
Magnealua Oxide
Doubl* Alkali
Lime
Limestone
Hellman-Lord
Hagnealum Oxide
Double Alkali
Line
Limestone
Uellnaa-Lord
Magnesium Oxide
Double Alkali
Line
H/A
H/A
H/A
N/A
H/A
H/A
H/A
H/A
H/A
H/A
40/39
40/39
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
Coal *
type
11
12
n
fi
12
13
11
12
fl
12
IS
15
13
13
13
13
13
13
13
13
13
13
13
13
13
13
13
13
System 13
Power Plant
Makeup Hater
Requirement
«•/«
0.37
0.37
0.38
0.018
0.018
0.020
0.37
0.37
0.018
0.018
0.37
0.37
0.76
0.76
0.76
0.76
0.76
0.38
0.38
0.38
0.38
0.38
0.076
0.076
0.076
0.076
0.076
0.020
(8P»>
(5,800)
(5,800)
(6,100)
(290)
(290)
(310)
(5,800)
(5,800)
(290)
(290)
(5,800)
(5,800)
(12,000)
(12,000)
(12.000)
(12,000)
(12,000)
(6.100)
(6,100)
(6,100)
(6,100)
(6,100)
(1,200)
(1.200)
(1,200)
(1,200)
(1,200)
(310)
SOX Control
Strategy
Makeup Hater
Requirement
•'/•
0,049
0.049
0.070
0.070
0.095
O.OBB
0.070
0.035
0.035
0.049
0.044
0.035
0.0069
0.0069
0.0095
0.0088
0.0069
0.0017
(BP»>
H/A
H/A
'H/A
H/A
H/A
H/A
H/A
H/A
H/A
H/A
(770)
(770)
(1,100)
(1,100)
(1.500)
(1.400)
(1,100)
(550)
(550)
(770)
(700)
(550)
(110)
(110)
(150)
(140)
(110)
(27)
Total
Hodel System
Makeup Hater
Requirement
•'/•
0.37
0.37
0.38
0.018
0.018
0.020
0.37
0.37
0.018
0.018
0.41
0.41
0.82
0.82
O.B8
0.82
0.82
0.42
0.42
0.44
0.43
0.42
0.082
0.082
0.088
0.082
0.082
0.021
<8P«0
(5,800)
(5,800)
(6,100)
(290)
(290)
(310)
(5.800)
(5.800)
(290)
(290)
(6. SOO)
(6,500)
(13.000)
(13,000)
(14,000)
(13.000)
(13.000)
(6.600)
(6,600)
(6,900)
(6.800)
(6,600)
(1,300)
(1,300)
(1,400)
(1.300)
(1,300)
(340)
(Continued)
-------
MODEL PLANT SYSTEM WATER REQUIREMENTS (Continued)
Case
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
7B
79
80
81
82
63
84
Power
Plant
Capacity
HW
25
25
25
25
1000
1000
1000
1000
1000
500
500
500
500
500
100
100
100
100
100
25
25
25
25
25
500
500
500
500
S0x
Control
Strategy
Limestone
Hellaan-Lord
Hagnoslun Oxide
Double Alkali
Lime
Limestone
Uellman-Lord
Magnesium Oxide
Double Alkali
Lime
Limestone
Wallnan-Lord
Hagnealun Oxide
Double Alkali
Line
Limestone
•Uellman-Lord
Hagnealun Oxide
Double Alkali
Lime
Limestone
Uellman-Lord
Magnesium Oxide
Double Alkali
Lime
Lime
Limestone
Limestone
Z Sulfur
Removal
90
90
90
90 '
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
Coal a
Type
13
13
13
13
14
14
14
14
14
*4
14
14
14
14
14
14
14
14
14
14
14
14
14
14
11
12
11
12
System 13
Power Plant
Makeup Hater
Requirement
m'/a
0.020
0.020
0.020
0.020
0.76
0.76
0.76
0.76
0.76
0.39
0.39
0.39
0.39
0.39
0.076
0.076
0.076
0.076
0.076
0.020
0.020
0.020
0.020
0.020
0.37
0.37
0.37
0.37
(gpm)
(310)
(310)
(310)
(310)
(12,000)
(12,000)
(12.000)
(12.000)
(12,000)
(6.200)
(6,200)
(6,200)
(6.200)
(6,200)
(1.200)
(1.200)
(1,200)
(1.200)
(1,200)
(310)
(310)
(310)
(310)
(310)
(5,800)
(5,800)
(5,800)
(5.800)
SO, Control
Strategy
Makeup Hater
Requirement
m'/a
0.0018
0.0024
0.0022
0.0017
0.082
0.082
0.11
0.11
0.82
0.040
0.040
0.056
0.054
0.040
0.0082
0.0082
0.011
0.011
0.0082
0.0022
0.0023
0.0031
0.0029
0.0022
0.035
0.034
0.035
0.034
(gpm)
(28)
(38)
(35)
(27)
(1,300)
(1.300)
(1,800)
(1.700)
(1 . 300)
(630)
(640)
(890)
(8SO)
(630)
(130)
(130)
(180)
(170)
(130)
(35)
(16)
(49)
(46)
(35)
(550)
(540)
(550)
(540)
Total
Model System
Makeup Water
Requirement
•'/a
0.021
0.022
0.021
0.021
0.82
0.82
0.88
0.88
0.88
0.43
0.43
0.45
0.44
0.44
0.082
0.082
0.088
0.088
0.082
0.022
0.022
0.023
0.023
0.022
0.40
0.40
0.40
0.40
(gpm)
(340)
(350)
(340)
(340)
(13.000)
(13.000)
(14,000)
(14.000)
(13,000)
(6,800)
(6,800)
(7.100)
(7.000)
(6,800)
(1.300)
(1.300)
(1.400)
(1.400)
(1.300)
(350)
(350)
(360)
(360)
(350)
(6.300)
(6.300)
(6,300)
(6,300)
(Continued)
-------
MODEL PLANT SYSTEM WATER REQUIREMENTS (Continued)
to
00
Case
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
'coal fl
coal 12
coal 13
coal 14
coal 15
coal f6
Power
Plant
Capacity
HH
100
100
100
100
25
25
25
25
500
500
500
500
25
25
25
25
500
500
25
25
500
500
25
25
: 0.8Z Si
t 0.8Z S;
i 3.5X Si
t 7.0Z Si
I 2. OX Si
I 4.0X Si
Control
Strategy
Lime
Lime
Limestone
Limestone
Lime
Lime
Limestone
Limestone
Lime
Lime
Limestone
Limestone
Lime
Lime
Limestone
Limestone
Coal Cleaning/Lime
Coal Cleaning/Limestone
Coal Cleaning/Lime
Coal Cleaning/Limestone
Coal Cleaning/Lime
Coal Cleaning/Limestone
Coal Cleaning/Lime
Coal Cleaning/Limestone
19 Ml/kg (8,000 Btu/lb) i 6X
26 Hi/kg (11.000 Btu/lb) i 6X
X Sulfur
Removal
90
90
90
90 •
90
90
90
90
70
70
70
70
70
70
70
70
40/85
40/85
40/85
40/85
40/91
40/91
40/91
40/91
ash; 30X
ash; 1SX
28 HJ/kg (12,000 Btu/lb) i 12X aah| 2.
28 KJ/kg (12,000 Btu/lb) i 12X ash; 5.
26 HJ/kg (11.000 Btu/lb) | 61
27 HJ/kg (11,500 Btu/lb)! 6X
ash; 1SX
aah[ 15X
Coal •
Type
fl
f2
fl
12
fl
12
fl
12
fl
12
fl
12
fl
n
fi
12
15
15
f5
15
16
f6
16
16
UiO
HZ0
6X HjO
7Z tttO
H20
H,0
System 13
Power Plant
Hakeup Water
Requirement
m'/e
0.073
0.073
0.073
0.073
0.018
0.018
0.018
0.018
0.37
0.37
0.37
0.37
0.018
0.018
0.018
0.018
0.37
0.37
0.018
0.018
0.37
0.37
0.018
0.018
(gP»)
(1.150)
(1,150)
(1,150)
(1.150)
(290)
(290)
(290)
(290)
(5,800)
(5,800)
(5,800)
(5,800)
(290)
(290)
(290)
(290)
(5.800)
(5.800)
(290)
(290)
(5,800)
(5,800)
(290)
(290)
m
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
SOX Control
Strategy
Hakeup Water
Requirement
'/a
.0069
.0069
.0069
.0069
.0017
.0017
.0018
.0017
.034
.031
.034
.032
.0017
.0015
.0017
.0016
.050
.050
.0025
.0025
.052
.052
.0026
.0026
(gpm)
(110)
(110)
(110)
(110)
(27)
(27)
(28)
(27)
(540)
(490)
(540)
(500)
(27)
(24)
(27)
(25)
(790)
(790)
(39)
(40)
(820)
(830)
(41)
(41)
Total
Model System
Hakeup Water
Requirement
m'/s
0.082
0.082
0.082
0.082
0.020
0.020
0.020
0.020
0.40
0.40
0.40
0.40
0.020
0.020
0.020
0.020
0.42
0.42
0.021
0.021
0.42
0.42
0.021
0.021
(gpm)
(1.300)
(1.300)
(1.300)
(1.300)
(320)
(320)
(320)
(320)
(6,300)
(6,300)
(6,300)
(6,300)
(320)
(310)
(320)
(320)
(6.600)
(6,600)
(330)
(330)
(6,600)
(6.600)
(330)
(330)
-------
TECHNICAL REPORT DATA
(Please read faurucrions on the reverse before completing)
1. REPORT NO.
EPA-60Q/7-78-045a
3. RECIPIENTS ACCESSION-NO.
4. TITLE AND SUBT.TL* controlling SO2 Emissions from Coal-
Fired Steam-Electric Generators: Water Pollution
Impact (Volume I. Executive Summary)
5. REPORT DATE
March 1978
S. PERFORMING ORGANIZATION CODE
7. AUTHaR(S)
8. PERFORMING ORGANIZATION REPORT NO.
R. L. Sugarek and T. G. Sipes
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-2608, W.A. 10
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 ffiRL-RTP project officer is Julian W. Jones, Mail Drop 61,
919/541-2489.
is. ABSTRACT
gives results of one task in a comprehensive program to review
the New Source Performance Standards (NSPS) for SO2 emissions from coal-fired
steam -electric generating plants. The results compare two alternative standards
to the existing NSPS (1.2 Ib SO2/million Btu of heat input): (1) 0.5 BJ SO2/million Btu
of heat input, allowing credit (as does the existing NSPS) for physical coal cleaning
or use of low sulfur coal; and (2) 90% removal of SO2 from stack gases , regardless
of original coal sulfur content. The comparisons are in terms of their effect on the
quality and quantity of power plant wastewater effluents and on the amount of plant
water consumption. Potential effects of SO2 control system effluents on the environ-
ment are evaluated, and alternative treatment processes are discussed. A total of
108 plant systems were disc-ussed, including combinations of three NSPS, five flue
gas desulfurization (FGD) systems, five coal types, four plant sizes, and sulfur
removal by coal cleaning. Volumes and quality of wastewater streams varied very
little from one alternative NSPS to another; all streams can be treated adequately
using commercially available technologies . However , the alternative standards
increase total water consumption 8-11%, depending on the FGD process used. Physi-
coal cleaning plus lime/limestone scrubbing increases total water consumed 8-12 /o.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Sulfur Dioxide
Flue Gases
Desulfurization
Water Pollution
Coal
Waste Treatment
Combustion
Steam-Electric
Power Generation
Calcium Oxides
Limestone
Wastewater
Pollution Control
Stationary Sources
13B
07B
21B
07A,07D
08G,21D
10A
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS
Unclassified
21. NO. Of PAGES
20. SECURITY CLASS (Tiia page I
Unclassified
22. PRICE
EPA Farm 2220-1 (9-73)
29
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