EPA 450 9 73 001
                           FLUE GAS
                   DESULFURIZATION

                             Answers
                                   to
                      Basic Questions
            US ENVIRONMENTAL PROTfCTION AGfNCY

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                          EPA-450/9-73-001
   FLUE GAS  DESULFURIZATION
   Answers to  Basic  Questions
Emission Standards and Engineering Division
  ENVIRONMENTAL PROTECTION AGENCY
 Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
             October 1973

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This report is published by the Environmental Protection
Agency to report information of general  interest in the field
of air pollution.  Copies are available free of charge to
Federal employees, current contractors and grantees, and
nonprofit organizations - as supplies permit - from the Air
Pollution Technical Information Center,  Environmental
Protection Agency, Research Triangle Park, North Carolina
27711.
            Publication No. EPA-450/9-73-001

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          FLUE GAS  DESULFURIZATION
          Answers to Basic Questions

                    INTRODUCTION
     In the  late 1960's, many state and local jurisdictions
enacted regulations to curb 5)0*2 emissions from coal- and
oil-burning  power plants.   The effect of such  regulations
was  a  trend toward the use of low-sulfur oil and  coal, and,
where  possible, of the cleanest fuel,  natural gas.

     With the  Clean Air Act of 1970,  limits for SO2  emis-
sions from fuel-burning sources became more widespread
as state plans were adopted to achieve national ambient
air quality standards. At  the  Federal  level, new-source
performance standards were enacted to limit S02 emissions
from new  steam generators  of power  plant size. Because
of shortages of natural gas  arid of low-sulfur coal and oil,
these limitations cannot be met solely  by  switching to low-
sulfur  fuels. It is apparent that coal  of medium-to-high
sulfur  content will have to be  burned in  increasing quan-
tities by power plants to meet growth requirements  and  to
safeguard an adequate supply of clean  fuels for residential,
commercial, and industrial use.

     The burning of such sulfur-bearing fuels in steam-
electric power plants causes appreciable SO2 air pollution.
Generation of electricity in 1970 produced about 20 million
tons of SO2,  which was approximately 55 percent of the man-
made SO2 emissions to the nation's atmosphere in 1970. If
not controlled, annual SO2 emissions from power plants
could rise to as high as 80 million tons  in the year 2000.

   In the next 10 years, the principal alternative to the com-
bustion of low-sulfur fuels will be the use of flue gas desul-
furization  (FGD) systems. Such systems can be used in con-
junction with all types of fuels but they  are particularly

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appropriate for cleaning gases  from  the  combustion of
medium-to-high-sulfur coals, which constitute the largest
segment of the nation's fuel reserves.  The power industry,
with some exceptions, has been slow to install FGD systems,
maintaining that their effectiveness and applicability have
not been  proved.  This contention has been the principal
basis on  which standards have been challenged in the courts.
A recent  opinion of the U.S. Court of Appeals, however,  up-
held EPA's new-source performance standard for coal-fired
steam generators of power plant size.  In so doing,  the Court
found that FGD technology has been adequately demonstrated
and that the promulgated standards are achievable.
   The purpose of this publication is  to provide a better
understanding  of flue  gas desulfurization and to
answer questions raised throughout the country concerning
its applicability,  cost,  effectiveness, and  operation.

   More  detailed technical discussions are available in such
publications as the Federal interagency (SOCTAP)  report,
Projected Utilization of Stack Gas Cleaning Systems by
Steam-Electric Plants~"(APTD-l"569) . Copies of the latter
report are available  from:

       National Technical Information Service
       5285 Port Royal Road
       Springfield, Virginia  22151
       Price $4.85
   Further publications on this subject are listed in "Air
Pollution Technical Publications of the U.S. Environmental
Protection Agency," which is available, along with the publi-
cations, from:

      Air Pollution Technical Information Center
      Research Triangle Park, North Carolina 27711
                          IV

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              FLUE GAS DESULFURIZATION


                Answers to Basic Questions




Q.  What is a flue gas desulfurization (FGD) system?

A.  FGD systems selectively remove sulfur dioxide  (SO2)
    from gas streams through physical and/or chemical
    action.  Most present-day FGD systems use wet scrub-
    bers as the S02 removal device. Alkaline materials in
    the aqueous media react chemically with 502 to form
    salts, primarily sulfites and sulfates.



Q.  Why is flue gas desulfurization  important?

A.  FGD systems provide an immediate, proved method for
    controlling SO2 emissions from  the burning of high-
    sulfur  coal, which is the nation's most abundant natural
    fuel resource.  Oil and natural gas are in short supply,
    coal gasification is still under development, and alterna-
    tive energy sources offer only long-range solutions.
    Hence, flue gas desulfurization is the only readily avail-
    able alternative to the use of low-sulfur fuels, which
    are scarce,  costly, and often available only from foreign
    sources.
Q.  Has the Clean Air Act of 1970 imposed hardships on the
    power generating industry in terms of time required to
    develop, finance, and install FGD systems?

A.  While the widespread adoption of regulations by states
    under the 1970 Act has required appreciably increased
    pollution control action by utilities, the need to control
    SO2 did not come as a surprise to anyone.  Projections
    made  by the power industry (1964, 1966,  and 1970) have
    indicated a continuing and increasing dependency on
    coal-generated electricity.

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Q.  Have electric utilities in the United States had much
    experience with FGD systems?

A.  Pilot plant studies were conducted over 20 years ago at
    Tennessee Valley Authority plants and have been con-
    ducted more recently by Detroit Edison and Wisconsin
    Electric.  Operation of full-scale FCD systems was initi-
    ated in 1967 and 1968 by the Union Electric Company at
    a station in St.  Louis, Missouri, and by the Kansas
    Power and Light Company  (KPL) at  its Lawrence, Kan-
    sas, station.  Both of these companies  installed limestone
    scrubbing systems on steam electric generators of
    greater than  100-megawatt capacity.  KPL, and the
    designers of the system, have incorporated many im-
    provements into the Lawrence station  and  most of the
    process problems have been solved.  During 1972 and
    1973, several additional systems have begun operation.
    The attached table lists 37  FGD systems that either have
    been installed or ordered  in the United States.  They
    represent a total of about 14,000 megawatts, or about
    9 percent of the current U.S. coal-fired electricity-
    generating capacity.

Q.  What other countries besides the United States have been
    investigating flue gas desulfurization?

A.  The first FGD systems were operated in England prior
    to World War  II  and some of these  are still in operation.
    More recently,  pilot and prototype installations have
    been operated in Japan and in Sweden and other Euro-
    pean countries.  The greatest effort has been in Japan,
    where successful systems are in operation and more
    are being installed.  A lime system has been success-
    fully used in Sweden since 1969 and has achieved high
    SO2-removal  efficiency together with  reliable operation.

Q.  What FGD  methods are available?

A.  Many processes are available, but only four are con-
    sidered sufficiently developed to make a potentially
    significant contribution  to the control  of S02 from power
    plants within the next 5 years:  wet lime/limestone
    scrubbing; magnesium oxide scrubbing with regenera-
    tion; catalytic oxidation; and sodium sulfite scrubbing
    with regeneration. Most scrubbers that have been in-
    stalled in  the United States and abroad have utilized
    lime or limestone base slurries that  react with SO2 in
    stack gases to form manageable residues  (slurries) .

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Q.  Is the technology of FGD more complex than that of most
    industrial chemical processes?

A.  No.  FGD systems employ relatively simple process
    operations requiring far fewer interrelationships than
    most chemical processes.  They include some of the
    same unit operations that have been used for years in
    the chemical industry. Problems that have been en-
    countered in the application of FGD systems to power
    plants are similar to problems  routinely solved by the
    chemical industry.

Q.  How much of the sulfur dioxide in flue gases can be
    removed with available FGD systems?

A.  Most of the systems being installed in  the United States
    and abroad are  designed  to achieve 70 to 90 percent or
    greater SO- removal.  Though almost any efficiency can
    be achieved,  economics dictates a  cutoff.  Reasonable
    S02~removal efficiencies of the four developed FGD
    processes are:  80 to 90 percent for wet  lime/limestone
    scrubbing; 90 percent for magnesium oxide scrubbing;
    85 to 90 percent for catalytic  oxidation; and 90  percent
    for  regenerable  sodium sulfite scrubbing.   The  above
    efficiencies have been achieved on  a long-term basis at
    the Mitsui Aluminum plant near Omuta, Japan,  and at
    the Japan Synthetic  Rubber plant near Chiba, Japan,
    with the lime and  regenerable sodium  sulfite processes,
    respectively.  An  efficiency of 90  percent has been
    achieved with a prototype magnesium  oxide  system at
    Boston Edison's  Mystic plant  (Massachusetts) .

Q.  What is  the cost of installing and operating an FGD
    system?

A.  Capital costs for new or retrofit installations generally
    range from $30 to $65 per kilowatt as compared with the
    capital cost of a coal-fired steam electric plant of approx-
    imately  $250 per kilowatt.  Capital costs for retrofitting
    systems to existing generating plants in most  cases are
    expected to be in the range of $45 to  $65 per kilowatt.
    For some retrofitted plants, installation costs  have been
    estimated as high as  $80 per kilowatt or  more. Some
    contractor estimates are:   $63 for TVA (Alabama); $27
    for Northern States Power  (Minnesota);  $40 for Kansas
    City Power and  Light (Missouri); and $39 for  Boston
    Edison (Massachusetts) .

    The estimated annual costs for  FGD range from 1.2 to
    3.2 mills per kilowatt-hour, with a mean of about 2.0

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    mills per kilowatt-hour. By comparison, the average
    national consumer cost  for power is about 18 mills per
    kilowatt-hour. Assuming FGD costs are passed on,  con-
    sumer rates for electricity would increase by about  11
    percent for that portion of  the utility system for which
    FCD is required.  Few utilities will be required to equip
    their entire network of  steam generators with FCD sys-
    tems.

Q.  Why is the cost of retrofitting existing plants greater
    than the cost of installing FCD systems on new  plants?

A   In general, it is more expensive to retrofit FGD systems
    than to include them in  new construction because of
    limited space at existing sites and the  need to move
    existing  facilities (railroad sidings,  tanks, etc.)  to
    install extraordinarily strong footings and other ancil-
    lary  equipment.   Some utilities  have reported retrofit
    costs in excess of $100  per kilowatt.  These generally
    represent very difficult installations and should be
    considered atypical.

Q.  Do rate structures set by public utility commissions
    affect the installation of FGD systems?

A.  Besides installing FGD systems, utilities can meet SO2
    standards by converting coal-fired plants to  low-sulfur
    oil or by securing low-sulfur coal. To many utilities,
    low-sulfur fuel alternatives appear more attractive than
    FGD systems  because they  involve relatively small capi-
    tal investments and shift a  potential capital cost to an
    operating cost.  In a number of states, utilities are now
    able to pass on to the consumer most of the incremental
    operating costs of higher priced fuels by means of "fuel
    adjustment" provisions. The fuel adjustment charges
    may be passed directly  to the consumer via the monthly
    bill without further action by  the regulatory commission.

    On  the other hand,  increases in generating costs  result-
    ing from the acquisition of capital equipment  and  the
    higher operating costs  of  FGD systems usually can be
    compensated  for  only by rate increases that require
    action by utility  commissions.   Not only do utilities
    have to wait for  this compensation until the regulatory
    commissions  act,  but they sometimes have to   "absorb"
    a portion of  the  additional costs.  Presently,   many
    commissions  treat capital  expenditures  and operating
    costs incurred for pollution abatement  devices in  the
    same manner.

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    Recent legislation in some jurisdictions provides incen-
    tives for the use of air pollution control equipment
    by allowing for automatic rate adjustments that compen-
    sate for pollution control equipment as well as for the
    cost of fuel changes.

Q.  Has the utility industry supported or conducted research
    on air pollution control in general and sulfur dioxide
    control  in particular?

A.  The utility industry  has not given a high priority to
    research and development  (R & D), but will be required
    to spend considerably more on R  S D in the future.  For
    the past decade,electric utilities have been supporting
    R S D at a level estimated to be equivalent to approxi-
    mately 0.25 percent of gross electrical revenues.  In
    1971, the utility industry reportedly spent $99 million
    for R S  D.  Approximately $40 million was spent for air
    pollution control, of which at least $23 million was allo-
    cated for the control of SC>2 emissions.

    The Electric Research Council Task Force on R & D
    estimated that R S D  expenditures by utilities, manu-
    facturers, and the Federal  government will rise to
    $1. 209 billion in  1977.  Roughly 75 percent of the pro-
    jected R S D will be for improved energy conversion,
    about 15 percent for transmission and distribution, and
    only 9  percent for environmental  needs.

Q.  Have designers solved the principal difficulties experi-
    enced with lime/limestone systems?

A.  The problems  with existing systems can be grouped into
    process and materials problems.  The process problems
    include scaling (formation of calcium salts on  scrubber
    surfaces), and plugging of boiler passages, scrubbers,
    packing, demisters, and reheaters.  Materials problems
    are mainly corrosion  and erosion of principal equipment.
    Some materials problems are inherently connected  with
    process problems.  For instance, in some systems  it has
    been difficult to control pH, so that the solution becomes
    highly acidic, causing considerable corrosion. Refine-
    ment of the process  to the point that pH can be kept with-
    in the noncorrosive range will prevent much of the  mate-
    rial damage.  The continuing development of corrosion-
    resistant materials is diminishing the importance of acid
    corrosion.

    Solutions to both materials and process problems have
    been found although all process parameters have not been

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    optimized. In spite of difficulties encountered with them,
    lime/limestone systems will probably be the primary
    scrubbing system used in the immediate future. For the
    longer term,  regenerable systems producing marketable
    byproducts  may predominate.

Q.  How long does it take to design and install an FGD system?

A.  Commercial units have generally taken  less than 2 years
    to install but  in the future may take  somewhat longer if
    demands exceed the production capacities of vendors.
    A magnesium oxide scrubber at Boston  Edison's Mystic
    Station took 21 months from issuance of contract to start-
    up.  A lime scrubber  installed at Mitsui Aluminum in
    Japan needed only 10  months from completion of specifi-
    cations to completion of construction. A difficult retrofit
    of a limestone scrubber at Commonwealth Edison's Will
    County Station (Illinois) took just under 2 years from the
    time scrubbing was first considered to  time of startup.

Q.  How long is a boiler out of operation when a scrubber  is
    being installed?

A.  A period of 4 to 6 weeks is normally required to tie in  a
    scrubber to a utility power boiler.  In some cases, the
    period may be somewhat longer.  Everything but the
    final connecting duct  is completed; then the boiler is
    shut down and final duct connections are made as
    quickly as feasible.

    Each boiler has a normal  maintenance downtime of at
    least 2 weeks every 12 to 18 months. Maintenance down-
    time can be used to tie in the scrubber, holding the net
    boiler firing time  loss to about 3 to 4 weeks.

Q.  What kind of guarantees are offered by  vendors of FGD
    systems?

A.  In general, vendors will  guarantee S02 removal under
    specified conditions agreed upon  with the operator,  and
    they will guarantee the mechanical parts of the system
    for 1 year. These conditions are  consistent with guaran-
    tees offered on boilers, steam turbines, and other equip-
    ment purchased by the electric utility industry.  Not
    only do they  offer written guarantees,  but these com-
    panies have reputations to uphold and expect to derive a
    significant portion of their revenue  in the future from
    the installation of FGD systems.

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 Q.   How much sludge is produced from lime/limestone
     systems?

 A.   Ten pounds of coal containing 3 percent sulfur will pro-
     duce 2 to 3 pounds of sludge, excluding fly ash,  assum-
     ing that the sludge contains 25 to 50 percent water.


Q.  What can be done with the solid wastes from lime/lime-
    stone scrubbing processes?

A.  Most of the presently operating lime/limestone systems
    dispose of sludge materials in ponds on the site.  If
    sufficient land is available, the pond is designed  to store
    wet sludge material over the lifetime of the power plant.
    When land  is not available at a plant site,  the solids can
    be dewatered with clarifiers, filters, or centrifuges and
    transported,  as  sludges, by barge, truck, train,  or
    pipeline to a landfill site.

    Chemical fixation processes are available that will re-
    lieve problems that can  result from  the nonsettling of
    some sludges, although the costs of such fixation  are not
    well  established at this time.  Such processes generally
    involve pozzolanic (cementitious) chemical reactions
    with fly ash and an additive such as lime;  these reactions
    lead  to the formation of a dry, solid, chemically inert
    material that is acceptable for landfill purposes.

Q.  What potential water pollution  problems are associated
    with FCD systems?

A.  Liquids in alkaline scrubbing  systems  contain  dissolved
    and suspended salts, some of which are reducing com-
    pounds,  i.e. , they  remove oxygen from the liquid.  The
    resultant liquid  has an appreciable  chemical oxygen
    demand (COD) and  is deleterious to aquatic plant and
    animal life if allowed to enter rivers, lakes, etc.  In
    addition, ground water and watercourses  could be
    contaminated by seepage from sludge ponds. The possi-
    bility of water pol lution is more apparent with  lime/
    limestone systems than with regenerable sodium and
    magnesium base systems.  There is little potential water
    pollution from dry processes  and from  the catalytic oxi-
    dation process.
Q.  How can ground water and watercourse contamination
    from lime/limestone sludge disposal ponds be prevented?

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 A.  Water contamination can be prevented by operating lime/
     limestone wet scrubbing systems in a closed loop.
     Closed  loop means that all liquor entering  the pond is
     recycled to the scrubber circuit; no sludge liquid is
     released to any watercourse.

     To avoid seepage of liquor through the walls and floors
     of the disposal ponds, a sealant such as  clay, tar, or
     plastic can be used if necessary.  Present  information
     indicates that ponds tend to seal themselves as sludge
     builds up.

Q.  Why can't we use nuclear power and eliminate the incon-
    venience of FCD  systems?

A.  There have been numerous delays  in the  siting and con-
    struction of nuclear plants.  In addition,  there are un-
    resolved environmental problems involved  in these
    operations.  Although it  is expected that  nuclear plants
    eventually will replace fossil fuel plants, no resultant
    reduction in SO2 emissions is expected until after the
    year 2000.

Q.  Don't FGD systems intensify the fuel  shortage?

A.  FCD will, in fact, lessen the fuel crisis by enabling us to
    employ high-sulfur coals and thus to utilize more of our
    very  large coal reserves while conserving  oil  and gas,
    which are in short supply. Furthermore, it is estimated
    that,  because clean fuels are in short supply,  FCD sys-
    tems will have to be applied to  some 50,000 megawatts
    of existing electric generator  capacity if  air quality
    standards  are to be met by  1977.

Q.  Have  any power  plants achieved particular success in
    operating an FGD system?

A.  The lime scrubbing system at the Mitsui Aluminum plant
    in Omuta, Japan, has demonstrated an  enviable record
    since it was first put into operation in March 1972. Other
    systems installed on oil-fired boilers in Sweden and
    Japan have been as successful, but the Mitsui system is
    significant inasmuch as it has been operated continuously
    for more than  1 year on a coal-fired unit. The Mitsui
    scrubber was designed by an American chemical engi-
    neering firm that markets the same process in the
    United States. It serves a  156-megawatt  coal-fired instal-
    lation that generates electricity for a primary aluminum
    plant and also sells electricity to a neighboring utility.

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Q.  Can the Mitsui scrubbing system be used on U.S. power
    plants?

A.  The system is considered applicable to U.S. power
    plants for the following reasons:

        1.  The  inlet SO2 concentrations in the Mitsui scrub-
            bing system are quite similar to those found in
            plants throughout the U.S.


        2.  Carbide sludge (calcium hydroxide) used at the
            Mitsui plant and various grades of U .S . lime
            react similarly in scrubbing systems.
        3.  The Mitsui plant operates with a nearly constant
            electrical  output, but has been subjected to
            enough variations in demand and flue-gas SO2
            concentration to demonstrate that the scrubbing
            system can handle varying stack-gas volumes.
            The majority of the newer and  larger U.S. power
            plants are not subjected to widely fluctuating
            loads.
            Most future American applications  of lime scrub-
            bing systems  should  involve steam generators  as
            large or larger  than  the  156-megawatt Mitsui  in-
            stallation.   These can use multiple scrubbing
            units (modules)  .  It does not appear  than  any
            modules with  greater than about 150-megawatt
            capacity will be utilized.
        5.   Fly ash removal at the Mitsui plant is accompli-
            shed with a relatively efficient, previously exist-
            ing electrostatic precipitator .  Similar equip-
            ment already exists at many U.S.  power plants.
            The Mitsui calcium sulfite/calcium sulfate efflu-
            ent bleed disposal system is designed to operate,
            and has operated, as a closed recycle loop be-
            tween the  scrubbers and the disposal  ponds.
            The recycle liquor has been totally saturated
            with sulfate for extended periods of time  (months)
            without the occurrence of significant scale build-
            up or other deposition in the scrubbers.

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Q.  Has the Mitsui type of flue gas desulfurization system
    been installed at any U.S. plants?

A.  Similar systems are being installed at  utility plants in
    two Pennsylvania locations.  The first of these  will be
    put into operation  in  late 1973 at the Philips station of
    the Duquesne Light Company.
                              10

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SULFUR DIOXIDE STACK GAS CLEANING SYSTEMS INSTALLED AT
  OR ON ORDER FOR U.S. ELECTRIC GENERATING STATIONS
Plant
1. Kansas Power and Light
Lawrence #4
2. Kansas Power and Light
Lawrence #5
3. City of Key West
Stock Island #1
4. Kansas City Power and Light
Hawthorne #3
5. Kansas City Power and Light
Hawthorne #4
6. Louisville Gas and Electric
Paddy's Run #6
7. Commonwealth Edison
Will County #1
8. Boston Edison, Mystic #6
9. Illinois Power, Wood River
10. Kansas City Power and Light
La Cygne
11. Detroit Edison Company
St. Clair #6
12. Arizona Public Service
Cholla
13. Duquesne Light Company
Philips
14. Northern States Power
Company
Sherburne Company #1
15. Northern States Power
Company
Sherburne Company #2
16. Nevada Power Company
Reid Gardner #1
17. Nevada Power Company
Reid Gardner #2
18. Nevada Power Company
Reid Gardner #3
19. Philadelphia Electric
Company
Eddystone #1
20. Potomac Electric and Power
Dickerson #3
21. TVA, Widow's Creek #8
22. N. Indiana Public Service
Company
D. H. Mitchell #11
Processa
L

L

L

L

L

L

L

M
C
L

L

L

L

L


L


S

S

S

M


M

L
S


Capacity,
MW
125

430

37

130

130

70

175

150
100
820

180

115

100

680


680


125

125

125

120


100

550
115


Start-up
date
12/68

11/71

10/72

11/72

8/72

4/73

2/72

4/72
10/72
5/73

12/73

4/73

6/73

5/76


5/77


6/73

6/73

75

6/73


7/73

5/75
7/74


Fuel
Coal

Coal

Oil

Coal

Coal

Coal

Coal

Oil
Coal
Coal

Coal

Coal

Coal

Coal


Coal


Coal

Coal

Coal

Coal


Coal

Coal
Coal


% Sulfur
in fuel
3.5

3.5

2.8

3.5

3.5

3.5

3.5

2.5
3.3
5.3

3.8

1

2

1.2


1.2


1

1

0.8

2.5


3

3.7
3.5


                          11

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      SULFUR DIOXIDE STACK GAS CLEANING SYSTEMS INSTALLED AT

        OR ON ORDER FOR U.S.  ELECTRIC GENERATING STATIONS

                             (Continued)
Plant
23. S. California Edison and
S. W. Utilities
Mohave #1
24. S. California Edison and
S. W. Utilities
Mohave #2
25. Indiana and Michigan
Electric
Tanners Creek
26. Ohio Edison and Others
Bruce Mansfield #1
27. Ohio Edison and Others
Bruce Mansfield #2
28. Public Service of Indiana
Gibson Company
29. Potomac Electric and Power
Dickerson #4
30. Potomac Electric and Power
Dickerson #5
31. Potomac Electric and Power
Chalk Point #3
32. Potomac Electric and Power
Chalk Point #4
33. S. California Edison and
S. W. Utilities
Navajo #1
34. S. California Edison and
S. W. Utilities
Navajo #2
35. S. California Edison and
S. W. Utilities
Navajo #3
36. Montana Power Company
Colstrip #1
37. Montana Power Company
Colstrip #2
Process^
L


L


D


L

L

L

L

L

M

M

L


L


L




L

Capacity,
MW
160


160


150


880

880

650

850

850

630

630

750


750


750




720

Start-up
date
73


74


74


75

76

76

76

77

75

76

3/76
to
3/77
3/76
to
3/77
3/76
to
3/77


6/75

Fuel
Coal


Coal


_


Coal

Coal

Coal

Coal

Coal

Oil

Oil

Coal


Coal


Coal




Coal

% Sulfur
in fuel
0.5


0.5


-


4.3

4.3

1.5

2

2

_

_

0.8


0.8


0.8




0.8

al_ - Limestone/lime scrubbing.
 M - MgO scrubbing.
 C - Catalytic oxidation.
 S - Sodium-base scrubbing.
 D - CuO adsorption, dry process.
                                   12

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