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

-------
                 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.

-------
                                   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

-------
                        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

-------
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.

-------
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.

-------
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

-------
                                 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

-------
                                              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

-------
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

-------
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

-------
                                     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

-------
           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

-------
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

-------
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

-------
           •  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

-------
                     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

-------