EPA-650/2-74-I26-Q



DECEMBER 1974
Environmental Protection  Technology  Series


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                                 EPA-650/2-74-126-0
           PROCEEDINGS:
            SYMPOSIUM
ON  FLUE GAS  DESULFURIZATION
   ATLANTA,  NOVEMBER  1974
              VOLUME  I
             ROAP NO. 21ACX-AA
           Program Element No. 1AB013
             Chairman: E.L. Plyler
           Vice-Chairman:  W.H. Ponder

               Sponsored by

           Control Systems Laboratory
        National Environmental Research Center
         Research Triangle Park, N. C. 27711


               Prepared for

       OFFICE OF RESEARCH AND DEVELOPMENT
      U.S. ENVIRONMENTAL PROTECTION AGENCY
           WASHINGTON,  D.C. 20460

               December 1974

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                        EPA REVIEW NOTICE

This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication.  Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency , nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
                    RESEARCH REPORTING SERIES

Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have'been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology.  Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields.  These 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

          9- MISCELLANEOUS

This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series.  This series describes research performed to
develop and demonstrate instrumentation,  equipment and methodology
to repair or prevent environmental degradation from  point and  non-
point sources of pollution.  This work provides the new  or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.

                 Publication No. EPA-650/2-74-126-a
                                 11

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                              PREFACE
     The development of technologies to control sulfur dioxide emissions is
an issue of national importance.  Indications that the use of sulfur-containing
fossil fuels to generate electricity will increase by 50 percent by 1985,
recognition that more than half of all sulfur dioxide (SC^) emissions are caused
by electric power generation, and documentation of the deleterious effects
caused by such emissions make the acceleration of development to commercial
application of SC>2 control technology one of the most important goals of the
U.S.  Environmental Protection Agency (EPA).  The Control Systems Laboratory
(CSL), as part of EPA's Office of Research and Development, has accelerated
the development of flue gas desulfurization (FGD) technology so that it is now
in the process of commercialization.  Each year, CSL sponsors a Symposium which
brings together users and developers of the technology for open exchange and
discussion of their experience and results.  The 1974 Symposium was held on
November 4-7 at the Sheraton-Biltmore Hotel in Atlanta.

     Commercial application of full-scale FGD processes  was the primary topic
of the Symposium which provided a means to transfer the  latest information
on the status, development and assessment of current FGD processes to developers,
vendors, potential users, and those concerned with regulatory deadlines and
enforcement.  The Symposium was attended by more than 600 national and inter-
national representatives of utilities, vendors, government, and universities.
One-third of the presentation was assessment and status  reports from utilities
which are utilizing full-scale FGD systems.  Information from small- and
large-scale pilot testing of alternate FGD systems, developments in FGD
by-product disposal and utilization, and cost studies of FGD application
completed the extensive overview of FGD technology.

     In concluding remarks, it was noted by an international FGD technology
consultant that the Symposium is recognized as the world's most significant
conference on S02 pollution control by FGD technology.  The growth of the
FGD Symposium to this latest, widely attended, in-depth  information exchange
forum supports the conclusion that FGD is the only viable near-term alternative,
other than the burning of clean fuels, that will permit  compliance with current
regulatory requirements.

     The contents of these Proceedings are comprised of  copies of the
participating authors' papers as received.  Although the papers have been
reviewed and approved for publication by the Environmental Protection Agency,
approval does not indicate that the contents necessarily reflect the views
and/or policies of the Agency.  The mention of trade names or commercial
products does not constitute endorsement or recommendation for use.

     As supplies permit, copies of the Proceedings are available free of
charge and may be obtained by contacting the Air Pollution Technical
Information Center, Environmental Protection Agency, Research Triangle
Park, North Carolina  27711.
                                    111

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                             CONTENTS

TITLE                                      '                       PAGE

                             VOLUME I

                          OPENING SESSION

Keynote Address - THE ROLE OF ENVIRONMENTAL HEALTH ASSESSMENT
IN THE CONTROL OF AIR POLLUTION
     John Finklea, Environmental Protection Agency,
     National Environmental Research Center,
     Research Triangle Park, North Carolina ...........     1

FLUE GAS DESULFURIZATION AND OTHER ALTERNATIVES FOR PRODUCING
ELECTRICITY FROM COAL
     S.J. Gage, Environmental Protection Agency,
     Washington, D. C ..... . ................     5

STATUS OF FLUE GAS DESULFURIZATION SYSTEMS IN THE
UNITED STATES
     T.W. Devitt and F. Zada, PEDCo-Environmental, Inc.,
     Cincinnati, Ohio  ......................    } 7
STATUS OF FLUE GAS DESULFURIZATION TECHNOLOGY IN JAPAN
     J. Ando, Chuo University, Tokyo, Japan ...........  125

COST COMPARISONS OF FLUE GAS DESULFURIZATION SYSTEMS
     G.G. McGlamery and R.L. Torstrick,
     Tennessee Valley Authority,
     Muscle Shoals, Alabama   ..................
                 NON-REGENERABLE PROCESSES SESSION

EPA/RTP PILOT STUDIES RELATED TO UNSATURATED OPERATION OF
LIME AND LIMESTONE SCRUBBERS
     R.H. Borgwardt, Environmental Protection Agency,
     Research Triangle Park, North Carolina ...........  225

LIMESTONE AND LIME TEST RESULTS AT THE EPA ALKALI
SCRUBBING TEST FACILITY AT THE TVA SHAWNEE POWER PLANT
     M. Epstein, Bechtel Corporation,
     San Francisco, California  .................  241

OPERATIONAL STATUS AND PERFORMANCE OF THE ARIZONA PUBLIC
SERVICE COMPANY FLUE GAS DESULFURIZATION SYSTEM AT THE
CHOLLA STATION
     L.K. Mundth, Arizona Public Service,
     Phoenix, Arizona ........ . .............  307

WET SCRUBBER OPERATING EXPERIENCE AT LA CYGNE
STATION UNIT NO. 1
     C.F. McDaniel, Kansas City Power and Light,
     Kansas City, Missouri  .................. .  319

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TITLE                                                             PAGE

DUQUESNE LIGHT COMPANY, PHILLIPS POWER STATION,
LIME SCRUBBING FACILITY
     S.L. Pernick, Jr. and R.G. Knight,
     Duquesne Light Company,
     Pittsburgh, Pennsylvania 	  329

THE HORIZONTAL CROSS FLOW SCRUBBER
     A. Weir, Jr., J.M. Johnson, D.G. Jones,
     and S.T. Carlisle, Southern California Edison,
     Rosemead, California 	  357

OPERATIONAL STATUS AND PERFORMANCE OF THE LOUISVILLE
FGD SYSTEM AT THE PADDY'S RUN STATION
     R.P. Van Ness, Louisville Gas and Electric
     Company, Louisville, Kentucky   	  389

DISPOSAL OF BY-PRODUCTS FROM NON-REGENERABLE FLUE
GAS DESULFURIZATION SYSTEMS
     J. Rossoff, R.C. Rossi, L.J. Bornstein,
     The Aerospace Corporation,
     El Segundo, California

     J.W. Jones, Environmental Protection Agency,
     Research Triangle Park, North Carolina 	  399

AN OVERVIEW OF DOUBLE ALKALI PROCESSES FOR
FLUE GAS DESULFURIZATION
     N. Kaplan, Environmental Protection Agency,
     Research Triangle Park, North Carolina 	  445

INITIAL OPERATING EXPERIENCES WITH A DUAL-ALKALI
S02 REMOVAL SYSTEM
  PART I  - PROCESS PERFORMANCE WITH A COMMERCIAL
            DUAL-ALKALI S02 REMOVAL SYSTEM
     T.T. Dingo, General Motors Corporation, Parma, Ohio  ....  517

  PART II - EQUIPMENT PERFORMANCE WITH A COMMERCIAL
            DUAL-ALKALI S02 REMOVAL SYSTEM
     E.J. Piasecki, General Motors Corporation,
     Parma, Ohio	  539

EPA-ADL DUAL ALKALI PROGRAMINTERIM RESULTS
     C.R. LaMantia, R.R. Lunt, J.E. Oberholtzer, E.L. Field,
     Arthur D. Little, Inc., Cambridge, Massachusetts

     N. Kaplan, Environmental Protection Agency,
     Research Triangle Park, North Carolina 	  549
                                 VI

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TITLE                                                             PAGE

                             VOLUME II

                   REGENERABLE PROCESSES SESSION

NEW ENGLAND S0? CONTROL PROJECT FINAL RESULTS
     G.R. Koehler, E.J. Dober, Chemical Construction
     Corporation, New York, Nexj York	671

ASSESSMENT OF PROTOTYPE OPERATION AND FUTURE EXPANSION
STUDY - MAGNESIA SCRUBBING MYSTIC GENERATING STATION
     C.P. Quigley, J.A. Burns, Boston Edison Company,
     Boston, Massachusetts  	  709

MAG-OX SCRUBBING EXPERIENCE AT THE COAL-FIRED DICKERSON
STATION, POTOMAC ELECTRIC POWER COMPANY
     D.A. Erdman, Potomac Electric Power Company,
     Washington, D.C	  729

POWER PLANT FLUE GAS DESULFURIZATION BY THE
WELLMAN-LORD S02 PROCESS
  PART I  - THE DEAN H. MITCHELL STATION
     E.L. Mann, Northern Indiana Public Service Company,
     Michigan City, Indiana 	  739

  PART II - CONTINUING PROGRESS FOR THE WELLMAN-LORD
            S02 PROCESS
     E.E. Bailey, Davy Powergas, Inc.,
     Lakeland, Florida  	  745

THE CAT-OX DEMONSTRATION PROGRAM
     E.M. Jamgochian, The Mitre Corporation,
     McLean, Virginia

     W.E. Miller, Illinois Power Company,
     Decatur, Illinois  	  761

THE SHELL FLUE GAS DESULFURIZATION PROCESS
     J.B. Pohlenz, Universal Oil Products Company,
     Des Plaines, Illinois  	  807

STATUS REPORT ON CH1YODA THOROUGHBRED 101 PROCESS
     M. Noguchi, Chiyoda International Corporation,
     Seattle, Washington   	  837

               FLUE GAS DESULFURIZATION BY-PRODUCT
                    DISPOSAL/UTILIZATION PANEL

FLUE GAS DESULFURIZATION BY-PRODUCT DISPOSAL/UTILIZATION
      - REVIEW AND STATUS
     H.W. Elder, Tennessee Valley Authority,
     Muscle Shoals, Alabama	   85.1.
                                VII

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TITLE                                                             PAGE

LIME/LIMESTONE SLUDGE DISPOSAL - TRENDS IN THE
UTILITY INDUSTRY
     C.N.  Ifeadi and H.S.  Rosenberg,
     Battelle, Columbus, Ohio 	  863

ENVIRONMENTALLY ACCEPTABLE DISPOSAL OF FLUE GAS
DESULFURIZATION SLUDGES:  THE EPA RESEARCH AND
DEVELOPMENT PROGRAM
     J.W.  Jones, Environmental Protection Agency,
     Research Triangle Park, North Carolina   	  887

FGD SLUDGE FIXATION AND DISPOSAL
     W.H.  Lord, Dravo Corporation,
     Pittsburgh, Pennsylvania 	  929

UTILIZING AND DISPOSING OF SULFUR PRODUCTS
FROM THE GAS DESULFURIZATION PROCESSES IN JAPAN
     J. Ando, Chuo University,
     Tokyo, Japan 	  955

TVA-EPA STUDY OF THE MARKETABILITY OF ABATEMENT
SULFUR PRODUCTS
     J.I.  Bucy and P.A. Corrigan,
     Tennessee Valley Authority,
     Muscle Shoals, Alabama 	  969

THE PRODUCTION AND MARKETING OF SULFURIC ACID FROM
THE MAGNESIUM OXIDE FLUE GAS DESULFURIZATION PROCESS
     I.S.  Zonis, F. Olmsted, K.A. Hoist, D.M. Cunningham,
     Essex Chemical Corporation, Clifton, New Jersey  	 1003

                 SECOND GENERATION PROCESSES SESSION

SECOND GENERATION PROCESSES FOR FLUE GAS
DESULFURIZATION - INTRODUCTION AND OVERVIEW
     A.V.  Slack, SAS Corporation, Sheffield, Alabama  	 1029

PILOT PLANT TESTING OF THE CITRATE PROCESS FOR S02
EMISSION CONTROL
     W.A.  McKinney, W.I. Nissen, D.A. Elkins and
     J.B,  Rosenbaum, Bureau of Mines,
     Salt Lake City, Utah	1049

TVA-EPA PILOT-PLANT STUDY OF THE AMMONIA ABSORPTION -
AMMONIUM BISULFATE REGENERATION PROCESS
     C.E.  Breed, Tennessee Valley Authority,
     Muscle Shoals, Alabama

     G.A.  Hollinden, Tennessee Valley Authority,
     Chattanooga, Tennessee 	 1069
                                Vlll

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TJILE                                                             PAGE

DESCRIPTION AND OPERATION OF THE STONE & WEBSTER/IONICS
S02 REMOVAL AND RECOVERY PILOT PLANT AT THE WISCONSIN
ELECTRIC POWER COMPANY VALLEY STATION IN MILWAUKEE
     K.A. Meliere and R.J. Gartside, Stone & Webster
     Engineering Corporation, Boston, Massachusetts

     W.A. McRae and T.F. Seamans, Ionics, Inc.,
     Waltham, Massachusetts  	 1109

CALSOX SYSTEM DEVELOPMENT PROGRAM PRESENTED AT
THE EPA FLUE GAS DESULFURIZATION SYMPOSIUM
     R.E. Barnard and R.K. Teague, Monsanto
     Enviro-Chem Systems, Inc., St.  Louis, Missouri

     G.C. Vansickle, Indianapolis Power & Light Company,
     Indianapolis, Indiana	1127

WESTVACO ACTIVATED CARBON PROCESS FOR S0x
RECOVERY AS ELEMENTAL SULFUR
     F.J. Ball, G.N. Brown, A.J. Repik, S.L. Torrence,
     Westvaco Corporation, North Charleston,
     South Carolina	J ! 51
                                IX

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THE ROLE OF ENVIRONMENTAL HEALTH ASSESSMENT
      IN THE CONTROL OF AIR POLLUTION
              Dr. John Finklea
                 Director
   National Environmental Research Center
           Research Triangle Park
       Environmental Protection Agency
               Presented at
   Symposium on Flue Gas Desulfurization
               Sponsored by
         Control Systems Laboratory
    U.S. Environmental Protection Agency
             Atlanta, Georgia
            November 4-7, 1974

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             THE ROLE OF ENVIRONMENTAL HEALTH ASSESSMENT
                   IN THE CONTROL OF ALR POLLUTION
                             ABSTRACT*
     Existing legislation requires that air pollution be controlled
to protect public health.  The health assessments required to evaluate
air quality standards and to support decisions on the control of mobile
and stationary source emissions present a series of complex scientific
challenges.

     Assessment of the health-related air quality standards reveals
no reason for abruptly changing these air quality goals.  However,
vexing uncertainties in the scientific information base remain.  Thus
there are often rather large differences between upper and lower
boundary estimates of a threshold for adverse health effects.  In
addition, there is a substantial body of evidence that fine particulate
aerosols like the acid-sulfate aerosols are injurious, but the broad
scientific information base necessary to establish aerosol standards
is lacking.

     Assessment of the health effects of increasing sulfur oxide
emissions is likewise difficult because of the uncertainties involved
in our scientific information base.  However, present rough estimates
conclude that substantial excess adverse health effects can be
expected each year if clean air requirements are not met:  thousands
of premature deaths, millions of days of illness among susceptible
segments of the population, hundreds of thousands of needless acute
lower respiratory illnesses in otherwise healthy children and hundreds
of thousands of chronic respiratory disorders among adults.  If the
health impact of short-term fumigations prove greater than expected or
if regional effects occur in the western power regions, the calculations
of excess adverse effects given here may prove overly conservative.  It
is important to remember that the present ambient sulfur dioxide
standards would be about what is necessary to protect public health from
effects attributable to acid sulfate aerosols if dispersion conditions
were good and if acid-aerosols did not intrude from up wind sources-
One should also recall that the sulfur oxides criteria document recog-
nized the problem of acid aerosols but that the knowledge at that time
led one to believe that long range transport of aerosols was not a
major constraint for air quality.
     *Full  text to be published in Advances in Environmental_Science &
Technology, Volume 7, published by Wiley-Interscience, John Wiley &
Sons, Inc., New York, after July 1975.

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     Assessment of the health impact of equipping light duty motor
vehicles with oxidation catalysts demonstrates that these emission
control devices are at best a mixed blessing.  Emissions of a
number of pollutants capable of adversely effecting public health
including carbon monoxide, phenols, aldehydes and polynuclear
aromatics are dramatically reduced by these devices.  Likewise,
catalytic converters will reduce other hydrocarbon emissions which
are not known to affect health adversely but which are an important
precursor of photochemical oxidants that do adversely affect health.
Unfortunately, oxidation catalysts will also alter emissions patterns
so that sulfates and sulfuric acid emissions will be greatly increased
and worsen a public health problem whose dimensions are net completely
understood.  The degree of public controversy engendered by the health
assessments just described is a function of the scientific uncertain-
ties contained in each particular assessment.  Another major deter-
minant of the amount of controversy involved is whether or not the
decision affects a vested industrial, environmental or governmental
interest that is politically and economically potent.  Since control
costs usually rise exponentially as one approaches an emission or
ambient standard, uncertainties about exposure response relationships
can result in violent controversy and cause major economic problems.
In general, the amount of scientific information demanded seems
directly related to the degree of public controversy.  Despite
attempts to augment the scientific information base for air pollution
control, it is unlikely that scientific uncertainties will be
sufficiently resolved to prevent disruptive disputes among reason-
able persons for another decade.

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FLUE GAS DESULFURIZATION AND OTHER ALTERNATIVES
      FOR PRODUCING ELECTRICITY FROM COAL
                Dr. Stephen Gage
                Acting Director
            Office of Energy Research
          Environmental Protection Agency
                   Presented at
       Symposium on Flue Gas Desulfurization
                   Sponsored by
               Control Systems Laboratory
         U.S. Environmental Protection Agency
                   Atlanta, Georgia
                 November 4-7, 1974

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     Since the last symposium on flue gas cleaning, there have
been a number of developments of immense proportions in the energy
area.  Some of these developments have significant implications
for this meeting and, more specifically, for the subject of my
presentation.

     In June 1973, the President committed the nation to a much
expanded Federal research and development program on energy supply
and use.  An interagency study chaired by the Atomic Energy Commission
recommended in December 1973 that $10 billion dollars be spent
over the next five years on energy R&D.  The AEC's report, "The
Nation's Energy Future," placed greatest emphasis on coal and
nuclear power.  The general thrust of the report was adopted
by the Office of Management and Budget in formulating the FY
1975 energy R&D budget which nearly doubled the FY 1974 level.

      To bring improved efficiency to the Federal energy R&D
effort, the Administration proposed in July 1973 that an Energy
Research and Development Administration be formed to provide
centralized management of nuclear, fossil fuel, and other R&D.
The ERDA act xvas passed in October 1974 and soon the Atomic Energy
Commission and some programs of the Department of Interior and
National Science Foundation will be merged in the new organization.

      October 1973 brought the Arab oil embargo which was followed
by the gasoline crisis, Project Independence, and the Federal
Energy Administration.  The long queues of cars at gasoline stations
and the higher prices posted on the pumps brought home the realization
of how vulnerable we were becoming to international political
blackmail.  Project Independence committed us on a course to
reduce that vulnerability by increasing our capability for energy
self-sufficiency.  That course, as the "Project Independence
Blueprint" will tell us soon, is a complex one requiring many
different types of actions  demand reduction, increased use
of coal, offshore exploration for oil and gas, etc.

               Perspective on Energy Self-Sufficiency
     Research and development on new energy resources and new
energy conversion technologies will unfortunately have little
impact for a good many years on our capability for energy self-
sufficiency.  The only significant advances toward this national
goal will come from application of technologies and practices
which either exist now or which have been under development for
a number of years.

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      Near the top of any reasoned agenda for energy policy
actions is energy conservation.  We are making energy conservation
work today and, of course, are being helped considerably by the
significant increases in the prices of all forms of energy during
the past year.  Not only oil but coal, natural gas and electricity
have increased sharply in price.  We are using energy less profligately
and also more efficiently.  Smaller cars with fewer power-consuming
options, less wasteful use of energy in heating and cooling of
homes and offices, more efficient use of energy in industrial
processes  all confirm that energy conservation is an alternative
and a practical and necessary one at that.

      On the supply side of the equation, we can anticipate increased
use of nuclear power, domestic oil and gas, coal, shale oil, geothermal,
and solar energy.  Nuclear power expansion through the middle
1980's, however, is tied to established construction schedules;
there will be at most slight accelerations or delays from those
schedules.  Rapid development of additional oil and gas supplies
is probably limited to expanded drilling near existing fields
and gathering systems and to advanced recovery techniques applied
to existing wells.  There is undoubtedly much more oil on the
Alaskan North Slope and in new offshore areas but exploration
for and development of those resources will require years.  Shale
oil, geothermal and solar will provide some new supplies but
within the coming decade their contribution will be marginal
at best.  That leaves one major near-term alternative to imported
oil: combustion of coal in utility and industrial boilers  boilers
which are either operating or are already under construction.

      The serious implications of expanded coal consumption for
the nation's air quality brings us back to the subject of this
symposium.  In my opinion, there are no alternatives to the use
of both high and low sulfur coal.  Both must be used to meet
the serious and continuing fuel supply crisis which faces the
nation.  But both must be used in ways which do not seriously
jeopardize human health and welfare.  The question then is how
we use the nation's different types of coal in environmentally
acceptable ways..

      Although generally of higher heating quality, coal from
the eastern and central part of the nation typically has higher
sulfur content.  Coal from the Interior Province of Western Kentucky,
Illinois and Indiana often has a sulfur content of three percent
or greater, thus requiring sulfur oxides control greater than
80 percent to meet New Source Performance Standards and many state
regulations.  Appalachian coal varies considerably from metallurgical

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quality coal with sulfur content well below one percent to medium
quality coal with sulfur content between two and three percent.
Recent estimates of low sulfur Appalachian coal reserves have, however
indicated much larger reserves than previously thought.  The
Geological Survey has estimated that'there are about 100 billion
tons of coal with sulfur content less than one percent in the
Appalachian fields, primarily in southern West Virginia, eastern
Kentucky and western Virginia.  Much of this coal will meet NSPS
and if the rest is washed it too can meet the most stringent
emission standards in middle central states.

      Because of the increased price of coal following the oil
embargo, I am confident that increasing amounts of this high
quality eastern coal will be produced for use in both utility
and industrial boilers. Today's differential between production
costs and selling price of coal is sufficient to provide for
full reclamation of strip mined areas and adequate health and
safety devices in underground mines.  Thus much of the boiler
fuel required in the industrial heartland will be low sulfur
coal from the prime Appalachian fields with acceptable levels
of impacts to the air and land of the region.

      Poorer quality Appalachian and nearly all Interior coal
will require sulfur control.  This fact, of course, underlies
the raison d'etre of both the Environmental Protection Agency's
flue gas desulfurization R&D program and the Department of Interior's
(soon to be ERDA's) synthetic fuel R&D program.

      Further justification for the massive Federal R&D effort
on synthetic fuels arises from the limited degree to which coal
can be substituted for other fuels.  To make the point abundantly
clear, use of the vast reserves of Western coal depends to a
considerable extent on the development of technology to convert
that low sulfur Western coal to alternative fuel forms  clean
liquids and gases  and, not incidentally, on the development of
technology to remove the ash and sulfur in the process.

      Western coals, typically low in both sulfur and heat content,
are not, I'm afraid, the panacea that some believe.  In the next
five years, Western coals will provide important new supplies
but they are not a widely applicable solution to coal supply
and use east of the Mississippi River where most of America's
heavy industry is located.  Transportation of the coal from the
Wyoming and Montana coal fields to Chicago and points east is
expensive and consumes valuable and scarce diesel fuel.  Adding
$10 to $15 or more per ton to the price of coal for transportation
will in many cases tip the balance toward eastern coals with
sulfur control measures.

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      There are other problems with using Western coals in existing
Midwestern boilers.  Use of western coal in many of these boilers
would result in the derating of the boilers by 10 to 15 percent
because of limits on bulk handling.capabilities of the entire plant.
With up to 30 percent lower heat content and higher ash and moisture
content, western coals would cause a much more serious reduction
of reserve generating margin than stack gas scrubbers.  There are
operational problems with western coals, such as preheater fires
due to carbon carryover and overloading of particulate collection
devices.  Finally, a significant fraction of the western coals
will not meet the more stringent emission standards and in some
cases the New Source Performance Standards.

      Western coals, I believe, will be important but will only
begin making significant contributions when they can be used as
feedstock for coal gasification and liquefaction process.  Now
let me turn to those processes.

           Alternative Technologies To Stack Gas Scrubbing
      In the paper which I delivered before the last Flue Gas Desulfur-
ization Symposium  (May  1973),  I discussed in detail the precombustion
cleaning processes which might be considered as alternatives to
flue gas desulfurization.  I also mentioned the potential of fluidized
bed combustion as an alternative but, because of the low level
of R&D activity in this area at  that time, I did not expand on
fluidized bed systems.

      The political and economic climate influencing the development
of alternative technologies has  changed drastically in the past
year and a half.  In the FY 1975 budget, $350 million were made
available to the Office of Coal  Research and Bureau of Mines for
coal utilization R&D. The two technologies which appear to be the
most direct competitors of flue  gas desulfurization  low-Btu
gasification and fluidized bed combustion  received the greatest
proportional increases over FY 1974. Low-Btu gasification R&D received
$52 million and fluidized bed combustion R&D received $37 million
in the FY 1975 budget.  These funding levels are comparable to
the $35 million allocated to the Environmental Protection Agency
for stack gas cleaning R&D in FY 1975.

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      Research and development, however, must proceed apace.
Adequate resources are a prerequisite for orderly progress in an
R&D program, however, progress depends on many other factors.
The advance of a project through the R&D stream cannot out-run
ideas, manpower, and construction schedules.  Thus, while it
appears likely that low-Btu gasification and fluidized bed combustion
will receive adequate support, actual as opposed to paper progress
in those alternatives has been slight.  Further, there have been
few technical developments in the R&D on liquefaction and high-
Btu gasification not fully anticipated a year and a half ago,
even though those two processes have also received marked funding
increases.

      Before discussing low-Btu gasification and fluidized bed
combustion further, let me put liquefaction and high-Btu gasification
in perspective relative to electric power generation.  There
appears to be an emerging consensus that both liquefaction and
high-Btu gasification will produce fuels that will be too expensive
for use under utility boilers.  Production costs for liquid coal
products range from $1.10 to $2.50 per million Btu while costs
for high-Btu synthetic gas range from $1.20 to $1.80 per million
Btu.  When these synthetic fuels become available in any quantity 
and that will be in the 1980's  I believe that they will be
bid away from the utility market by industrial, commercial, and
residential markets where clean liquid and gaseous fuels will
seek premium uses.

      From the point of view of resource conservation, it also
makes more sense to utilize the clean fuels derived from these
two processes in high efficiency end uses such as residential
heating.  Coal liquefaction, it is estimated, will be 60 to 70
percent thermally efficient while high-Btu gasification will
be 55 to 65 percent efficient.  It would be illogical to waste
60 percent or more of the remaining heat value in the cleaned
fuel by converting it to electricity.

      Of the various clean fuel alternatives, these two are the
most advanced.  The hydrogasification pilot plant being tested
by the Institute for Gas Technology in Chicago has had several
long successful runs in the past few months.  The carbon dioxide
acceptor pilot plant operated by Consolidated Coal Company in
Rapid City, South Dakota has also had numerous successful runs,
exceeding the design specifications of the gasifier.  The synthane
and BIGAS pilot plants are under construction in Bruceton and
Homer City, Pennsylvania, respectively.  The most advanced coal
liquefaction process  Pittsburgh and Midway's Solvent Refined
Coal process  will soon be tested in a pilot plant near Fort
Lewis, Washington.
                                   10

-------
      R&D efforts for both low-Btu gasification and fluidized bed
combustion lag those for high-Btu gasification and liquefaction.
The development of a 5-year fossil fuel R&D program by the Interior
Department's Office of Research and Development during summer 1974
helped to clarify some of the goals and program thrusts for these
two technologies but many questions remain.  The program plan calls
for a low-Btu gasification demonstration plant in 1978 and fluidized
bed combustion demonstration in 1979  goals which I submit are
probably impossible to meet, given the state of the technology
and the managerial and technical expertise supporting the efforts.

      One of the toughest questions to be answered in both R&D
programs is which way(s) to go.  With the realization that sulfur
control measures will be required for electrical power plants and
that these may be alternatives to stack gas cleaning, there have
been a plethora of proposals on candidate processes.  So much so
that in the area of low-Btu gasification the number of candidates
is overwhelming and the adequacy of the screening process  that
is, selection criteria based on technical knowledge  is frankly
underwhelming.  Hopefully, these organizational problems will soon
be overcome so that both programs can move ahead.  One good sign
is the development of a National Fluidized Bed Combustion R&D Plan
designed to define the program goals, translate these into research
plans, and spell out the roles of the various agencies.  EPA is
participating in the development of the plan because of the agency's
important contributions to the early development of fluidized bed
boilers and because of the agency's continuing role in the environmental
assessment of these combustors.

      The advantages of low-Btu gasification and fluidized bed
combustion have been widely touted in the past year.  Both techniques
have the potential for improving the thermal efficiency of electrical
power production.  Used in a combined cycle configuration, i.e.,
with a gas turbine topping cycle, the overall plant efficiency
may go as high as 45 percent.  But such high efficiencies will
be achievable only in second or third generation plants.  Early
low-Btu gasification efficiency and early fluidized bed boilers
will probably not achieve over 36 to 37 percent. And those efficiencies
assume success in the single most critical R&D element  hot gas
cleanup.  Thus it is likely that early low-Btu gasification and
fluidized bed combustion plants will use coal with approximately
the same efficiency as a modern steam boiler with a low pressure
drop stack gas scrubber.

-------
      Another obvious point which must be made is that since the
low-Btu gas plant, the fluidized bed boiler, and the conventional
boiler with stack gas scrubber are all located at the central electrical
generating station they are all faced with the common problem of
sulfur.  Assuming that technologies will develop to the point where
the sulfur can be removed from the coal, the nagging problem of
sulfur by-product disposal remains.  If dolomite, limestone, or
lime is used to remove the sulfur, then landfill techniques or
expensive and unproven regeneration techniques must be used to
handle the by-products.  If, from the reducing environment of the
gasifier, the sulfur can be removed as hydrogen sulfide it can
then be converted to elemental sulfur in a Glaus process. Advanced
flue gas desulfurization processes, to which I'll return later,
also have the potential for producing elemental sulfur.  The problem
of disposing of the elemental sulfur may not be trivial, however.

      Predictions of low production costs for both low-Btu gasification
and fluidized bed combustion have also been touted by their proponents
as justification for rapid development and deployment.  Estimates
of low-Btu power gas production costs have gone up in the past
year, reflecting more the rising estimates for high-Btu gasifiers
than detailed economic analyses of low-Btu gasifier designs.  Estimates
of incremental costs for power gas production range from 50 to
80 cents per million Btu based on a 90% plant factor.  Although
proponents of fluidized bed combustion claim that the process may
in fact be less expensive than conventional pulverized coal-burning
combustion, such cost savings could not be approached for the first
several generations of combustors, that is, until late in the 1980's.
One component of FBC costs which I believe has been seriously underestimated
is the waste disposal or regeneration of the reacted dolomite.
Those of you who have been working on stack-gas scrubber waste
disposal should certainly appreciate that fact.

     Finally, I should make a categorical statement about the trend
of estimated costs of almost any new technology as the technology
moves from the bench scale to the pilot plant to the demonstration
plant  the estimated costs invariably go up and they go up more
rapidly as the demonstration phase is approached.  There is nothing
mysterious about this  it's human nature.  In the early days
of nuclear power the wiser and experienced engineers always multiplied
the cost estimates of new reactor concepts by a factor of three.
The more mathematically oriented French engineers, apochrapha has
it, always multiplied by IT.
                                  12

-------
      Certainly low-Btu gasification and fluidized bed combustion
are important and will undoubtedly provide important sources
of clean energy in the 1980's.  The Environmental Protection
Agency will be encouraging substantial R&D effort on these two
technologies and will be providing back-up engineering and environmental
assessments to ERDA and private efforts.  But if we're serious
about Project Independence  and we must be for the sake of our
economic security and our independence in foreign relations 
then we must turn to increased use of all of our coals as soon
as possible.  And to protect public health and welfare, this means
using scrubbers on many boilers burning high sulfur coal.
                 ORD's Stack Gas Scrubbing R&D Program

      After arriving in Atlanta last evening, I took a cab downtown
in search of a restaurant.  Just a few blocks away from the hotel,
I noticed a crowd of people entering a church.  The sign in front
of the church indicated that Mozart's "Requiem in D Minor" was
being performed inside. Well, after the recent on slaught of anti-
scrubber advertising by American Electric Power, there is little
that surprises me but this frankly did.  I do find it hard to
believe that Donald Cook would have commissioned the performance
of Mozart's Requiem in that nearby church just to throw a pallor
over this conference.  The utter ingenuity of the man!

      As I'm sure you're aware, the Environmental Protection Agency
views scrubbers much differently from Donald Cook and American
Electric Power. And I think you agree or you wouldn't be here
at this meeting.  Far from being the requiem mass for scrubbers,
this gathering is much more a celebration of life.  I offer my
voice to the choir.  Stack gas cleaning of high sulfur coals offers
the greatest single contribution, consistent with environmental
protection, to the goal of energy self-sufficiency.  I feel that
if Donald Cook really believed in Project Independence and the
need to protect human health from sulfur oxides and metallic acid
sulfates he would support the use of scrubbers with high sulfur
coal in those parts of the AEP service area where air quality
is worse than ambient primary standards.

      Problems remain with scrubbers.  There has never been a
technological innovation which didn't require a shakedown phase.
Nuclear power the future mainstay of the electric industry 
is still confronting and overcoming problems, 14 to 15 years after
                                  13

-------
the first civilian demonstration power reactors were started up.
We must continue to improve reliability of the non-regenerable
(lime/limestone) scrubbers. We must continue to develop improved
sludge disposal methods and to evaluate their environmental impacts.
We must continue to reduce the capital and operational costs of
flue gas desulfurization systems.  Finally we must develop regenerable
systems which are capable of producing elemental sulfur as a by-
product at a reasonable cost.

      I'm sure many of you are aware that EPA's Office of Research
and Development has come under serious criticism during the past
few months.  A variety of problems have been pointed out by a
National Academy of Sciences panel, the Senate Public Works Committee
and others. ORD has already begun to take measures to correct
its shortcomings and I'm sure many additional actions will be
taken once a new Assistant Administrator is named and confirmed.
The major action taken to date is the establishment of a new program
management office  reporting directly to the Assistant Administrator 
which would have responsibility for all of EPA's R&D relating
to energy.  The Office of Energy Research, of which I'm now serving
as Acting Director, is faced with the challenge of meshing EPA's
research on health and ecological effects of pollutants from energy
plants with EPA's R&D on control technology for those same plants 
an imposing challenge but one which I feel the agency must confront
head-on.

      One of the features of the partial ORD reorganization is
that the Office of Energy Research would concentrate on strategic
planning and management, abrogating to the laboratories increased
responsibility for detailed project management.  This is directly
responsive to many of the criticisms.  Such a division of responsibility,
however, can work only if both parties fully do their jobs.  My
job begins with setting strategic energy-related goals for EPA's
laboratories and I want to begin that job here today with setting
goals for the agency's R&D on flue gas desulfurization.

      -   First, ORD will conduct an advanced lime and limestone
          test program on our flexible test facility at TVA's
          Shawnee plant.

This program calls for further-testing and evaluation of the recently
demonstrated reliable operating modes and of the "unsaturated
gypsum" mode recently discovered in EPA labs.  The testing program
will also focus on four additional factors:  (1) achieving maximum
S02 removal efficiency consistent with reasonable operating costs,
(2) maximizing alkali utilization thus minimizing sludge production,
(3) identifying mist eliminator and wash systems with more reliable
operation, and (4) evaluating sludge disposal methods, including
those offered commercially by Dravo, I.U.C.S., and Chemifix.
                                 14

-------
          Second, to provide an alternative to lime/limestone throw-
          away systems, ORD will initiate a full-scale demonstration of
          a Double Alkali FGD System.

This demonstration will be conducted on a 100-200 MWe coal-fired
utility boiler burning high sulfur coal.  Selection of the vendor
and utility will be done on a competitive basis.   ORD will provide
up to half of capital and operating costs incurred during the
test program.

         Third, to provide an alternative to sulfur-producing
         synthetic fuel processes, ORD will initiate a full-scale
         demonstration of a regenerable FGD system which produces
         by-product sulfur.

This demonstration will also be conducted on 100-200 MWe coal-
fired utility boiler burning high sulfur coal.  Selection of both
the process and the vendor/utility will be done on a competitive
basis.  Again EPA will cost-share up to half of both capital and
operating costs.

      Those three goals define the Office of Energy Research's
agenda for stack gas scrubbing.  We will be doing our best to
ensure that both financial and managerial support required to
achieve these objectives is provided.  We expect ORD's Control
Systems Laboratory and other supporting laboratories to move vigorously
to meet the challenge.  And we invite you to help us meet our
obligation to the American public to provide the means for using
our domestic coals in environmentally acceptable ways.  Now is
the time to do it.  We can't keep putting off tomorrow.  All too
quickly tomorrow becomes yesterday.
                                  15

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            STATUS OF FLUE GAS

          DESULFURIZATION SYSTEMS

           IN THE UNITED STATES
                Prepared by
    Timothy w.  Devitt and Fouad K. Zada

   PEDCo-Environmental Specialists, Inc.
         Suite  13,  Atkinson Square
          Cincinnati, Ohio  45246
       Prepared for Presentation at
    Flue Gas Desulfurization Symposium
Sponsored by the Control Systems Laboratory
   U.S. Environmental Protection Agency
             Atlanta, Georgia
           November 4-7, 1974
                   17

-------
                          ABSTRACT

     Data are presented  on  the number and total MW of flue
gas desulfurization  (FGD) systems installed, under construc-
tion and planned  for U.S. utility application.  The reli-
ability of operating systems is briefly described.  Case
histories describe FGD operations at four plants: Hawthorn
Power Station  (Kansas City  Power and Light), Will County
Power Station  (Commonwealth Edison), Lawrence Power Station
(KCPL), and Reid  Gardner Power Station (Nevada Power Company)
Description of the FGD process at each installation is
followed by an account of system performance, with emphasis
on problems encountered, solutions developed, and plans for
future operations.
                         CONTENTS                    
                                                       Page
      Status of Flue Gas Desulfurization Technology
        in the United States                              19
      The Lawrence Power Station                         30
      The Will County Power Station                       38
      Hawthorn Power Station                             48
      Reid Gardner Power Station                         57
      Information Sources                                62
      Appendix A--Flue Gas Desulfurization System
        Status Report, October 1974                       63
                               18

-------
             STATUS OF FLUE GAS DESULFURIZATION
               TECHNOLOGY IN THE UNITED STATES

     In March 1974, PEDCo-Environmental Specialists was
awarded a study by the U.S. Environmental Protection Agency
to evaluate the status of flue gas desulfurization (FGD)
technology in the United States.  This study will have two
outputs.  The first will be a series of reports .on indi-
vidual FGD facilities.  These reports will present values
for pertinent process design and operating parameters and
describe the operability of the unit from start-up to the
time of the plant survey.  To date we have visited nine
installations; we are scheduled to visit another five
facilities by February 1975.
     The second study output is a series of monthly reports
over the one year study period.  These reports include a
summary of the operability  (reliability) for each utility-
size FGD system over the preceding month and a complete list
of all FGD units which are either under construction or
planned.  A copy of the October monthly report is attached
as Appendix A.
     As shown in Table 1, there are 19 operating FGD systems
on utility-size boilers, 17 units under construction and 62
units planned.  The planned units include those for which
there has been a contract awarded, a letter of intent signed
or the utility is presently requesting or evaluating bids.
Of the operating systems, 13 are lime or limestone based
(including limestone injection), two are magnesium oxide
scrubbing, two are sodium carbonate, one is double alkali
and one is catalytic oxidation.
                             19

-------
        Table 1.  NUMBER AND TOTAL MW OF FGD SYSTEMS
Status
Operational
Under construction
Planned
Contract awarded
Letter of intent
Requesting/evaluating bids
Considering only FGD systems
Total
No. of
Units
19
17

12
4
9
37
98
MW
3,291
6,777

6,640
905
3,751
16,472
37,836
     Figure 1 illustrates the projected increase in the
number of megawatts of power production equipped with FGD
systems.  By 1975, approximately 7000 MW of capacity will be
installed of which 50 percent will be retrofit applications
and 50 percent will be on new power plants.  By 1980, ap-
proximately 35,000 MW of capacity will be installed of which
30 and 70 percent will be retrofit and new installations
respectively.
     Figure 2 illustrates the magawatts of capacity that
will be controlled by the FGD process.  In 1974, approxi-
mately 80 percent is controlled by lime and limestone
scrubbing processes; in 1977, over 90 percent will be lime
or limestone scrubbing.
     Sulfur dioxide removal efficiencies for the operating
units range from approximately 70 to  90 percent and partic-
ulate removal efficiencies generally  are above 99 percent
for those units designed for particulate removal.  Instal-
lation size varies from about 30 MW to over 800 MW.  FGD
systems have been applied to both low  (0.4 to 1.0 percent)
and high  (6.0 percent) sulfur coals.  The non-regenerable
systems have used a variety of methods for sludge disposal
                             20

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    38_
    36
    34
    32
         LEGEND
 30



 28



 26



 24



 22



 20



 18



 16
            NEwl-
        RETROFIIi-
           TOTAL	
                                               T
o
o
o
Q_

-------
 16,000
 14,000
 12,000
          LEGEND

           (1)   LIMESTONE  SCRUBBING
           (2)   LIMF. SCRUBBING
           (3)   LIME/LIMESTONE SCRUBBING
           (4)   OTHERS (NOT SPECIFIED)
           (5)   WELLMAN LORD
           (6)   LIMESTONE  INJECTION
           (7)   CATALYTIC  OXIDATION
                                           (8)  SODIUM  CARBONATE

                                           (9)  MAGNESIUM OXIDE
                                           (10)  DOUBLE ALKALI

                                           (11)  LIME INJECTION
                                   f
 10,000
  8,000
  6,000
  4,000
  2,000

 1,000
                                        /
      68
70
         72
76        78
 YEAR
80
Figure 2.   Present  and  projected  capacities  of  FGD processes.

-------
 including ponding,  dewatering  by  vacuum filtration  and  land-
 filling, and  fixation  followed by landfilling.   The regen-
 erable  systems  have been  limited  to  date to  recovering  sul-
 furic acid  although a  sulfur recovery unit is being installed.
     The total installed capital costs  of these  systems  have
varied from about $20/KW to over $100/KW.  This cost picture
is clouded,  however, because of a variety of factors which
influenced final installed costs.  In some cases, the system
designer shared the installation cost and much of the system
modification cost with the utility; in other cases there was
very little cost sharing.   The total installed cost for FGD
systems over about 200 MW in capacity is estimated to be in
the range of $60 to $80/KW.
     Pertinent data on the operating systems are presented
in Table 2.
     The reliability and availability of FGD systems has
been a major question.  During our plant inspections, it was
apparent that most plants had overcome  the "chemical"
problems; most operators felt they could control the process
chemistry and hence minimize or eliminate scaling and
related problems.  However many units are still faced with a
number of mechanical problems  (e.g., frozen venturi throat
drives, fan vibration).  While most of these problems are
not major in that they occur on an infrequent basis, they
do lead to lower unit availability.
     Availability data of any sort and particularly on a
common basis are scarce.  Some limited data for Paddy's Run
and Will County are shown in Figure 3.   The availability
factor was calculated as hours of FGD system operation
divided by hours of boiler operation.  Such a definition,
however, can be misleading.  For example, on a peaking unit
like Paddy's Run, the FGD system may be bypassed for short
boiler runs even though the system was available for use;
thus the availability factor would be lower than the actual

-------
Table 2.  DESIGN AND OPERATING  DATA FOR OPERATIONAL FGD SYSTEMS



FCO Proceaa/
Power Station


Ar 1 tor a Public Service
Choi la no. 1
City of My weat
Key "ett Po^er Plant
Connon wealth Mlaoa
will County He. 1


La Cygno *'o. 1

Line ScribMnq
Duqueine Mfht
Phillips
LouiavllU Cat t
Electric
Paddy! (tan Ko. f
Southern California
UUon
Hohave #o. 2

LiMatone Inlectioo
Sweat Cily Power t
Light
ewUiocn Ho. 4

xeneae City Pcwer t
Light
Hawthorn No. 3

Klfiiai Pe>u*r 1 Light
Lawrence No. S
Keneas Power i tiaht
Lawrence e. 4
Liaa In'tctlon
CttiryUfld power - Coop
AIM Station
yj*e/t,l*tcne
Tenne**ee Valley
Authority
Shawnee Ho. 19

HoO ScrubbijMj
Voaton Cdlaon
My a ti


It


P.



R



P.


n








ii


*

*
K
It


R


>



Siie of
rco unit
KM



115
33

1(7


120



410


IS

110




100



1*0


400

" 12$


to



30


ISO

100

123
125


32


111



Statue
(Start-
up Datel



10/73
10/72

2/72


t/73



10/73


/

11/73




1/72



11/72


11/73

12/tl


/T*



4/72


4/12

/7J

11/1J
11/11


1/14


If/Tl



Typ.




Co*l
Oil

Coal


Co*l



CM!


Co.1


Co.l



Cokl



COAl


Coal

Co.1


CMl



Col




CMt
Co.1
Cool


Cxi


CMl
rut
t Ach




&-1S


10.0


K-]



11


14






14



14


11. S

11.9


12- JO



11-1!




10




KK


10
% S




0.4-
1.0
1.7S

2.0


(.0



2.1


3.7


O.J-
O.f


).TS



I.7S


>.4

1.4


1.0-
l.J


1.0




1.0

O.I


M


l.i

rtlcult
Control
Koch







Ho


Ho



T..


*>


Ho



Ho



Ho


No

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T.I



No




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I.
*


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tit







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NO


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rlu* c..
VolUM
ACPH






770.000


2.100.000



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2.100.000



44S.OOO



44S.OOO


990.000

110,000


.



10.000




211.000
471,000
471,000


X*


1.111.000
r

(Vanturl) It 11 KA 10 01 21-24 21-24 12 22 - f 4 HA 1 10 (Vntril 1 t (TOV.D NA Ml;e up Ib jola S0j 730 ISO NA MA 170 170 n A M 420 - ftn M 0 190 KA F.aocnt ttan % 99 71 HA A 100 HA M NA " <2 MA (0 100 100 100 100 NA rcc >ete H( (icicftcy lUrnuval t 99 to S 9)* 9f.3 99 " 99 99 99 99 - O* 39.1 99 99 >t 503 * 90 IS 10 10 10 10 ~ 70 70 75 73 70 90-95 90 10 IS HA 11 Caa (InilUectt fittaa* (indirect! Stran Cflditect plui hot air} Oil .Burnera Caa Pired Icnlter Direct Hot Air Stean I Indirect! ItflUI {Indirect) Not Water Hot Hater Hot Applicable etaa* (Indirect) (Direct Hot A,c NA M Sludge H.U104 OB Fond Per-a FonO Pond VACUUM Pll- t.r A ntul pimd Fond Fond Fond Food Fond Fond Acid Fl*nt Acid Fltnt Fond oc Dry L*k Fonl Act FlMit rco Coat. 14 /* m.l/ra Ml/m 170-7.9/01 IS7/XV U9.o/n> 119.0/DI N NA NA n iio/i. . I7S/W 071/


-------
K)
Oi
                  LEGEND
                   (1)  WILL COUNTY  MODULE  A
                   "2   WILL COUNTY  MODULE  B
                    3   PADDY'S RUN  MODULE  A
                    4   PADDY'S RUN  MODULE  B

                    a)  UNIT SHUT DOWN,  DEMISTER  &  REHEATER
                        PROBLEMS

                    b)  MODIFICATIONS,  & LIMESTONE  BLINDING  PROBLEMS

                    c)  DEMISTER, REHEATING PROBLEMS,  FREEZE UP OF
                        VENTURI THROAT  AND  LOSS OF  BUILDING  HEAT

                    d)  DUE TO LOW DEMAND FOR  ELECTRICITY, BOILER RUNS
                        WERE OF TOO  SHORT DURATION  TO  JUSTIFY OPERATION
                        OF THE FGD MODULES
100



80
>H
E-
H
^
H 6C
a
j
H
<
>
< 40
M
2
W
u
K 9ft
w zc
PU






































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\
\

















S'

( 9 \
\ *_ 	

















\
\
\
\
\l
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V|



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a /
S~\
JAN. MAR MAY AUG. NOV.
U_ 	 107? 	 	 	 J

























-4
^^^
/
.X /



\ '
\ /

A I /

FEB. MAY A
-* 	 1 Q7


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[
/

/

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"-
^V / ! '
V O }
^



^^_r_,
^^^




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f
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t
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^(D


























































































































JG. NOV. ,FEB. MAY AUG. .
3 	 4* 	 1 Q7A 	 M
                                  Figure  3.   FGD  system availability

-------
availability of the unit.  On the other hand, units with no
bypass capability would have a high availability factor
since the boiler would be down when the FGD system was in-
operative.  Since complete data were not available and could
be misleading if not adequately qualified, we have presented
a qualitative description of recent performance for all the
operating systems in Table 3.
     The FGD systems at the Lawrence, Will County, Hawthorn
and Reid Gardner installations are described in the fol-
lowing sections.  These systems were selected since they are
not covered in other papers presented at this symposium.
                             26

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                             Table  3.   OPERATING SUMMARY FOR  FGD  SYSTEMS
Utility and Unit Name
                         Status
Arizona Public Service
  Cholla No. 1
Boston Edison
  Mystic No. 6
Commonwealth Edison
  Will county No. 1
Dairy Power Co-Op
  Alma Station

Duquesne Light
  Phillips Station
General Motors
  Parraa Plant
Illinois Power
  Wood River
Since start-up in October 1973,  the FGD system  availability has been consistently
above 90 percent.  There have been a few mechanical  problems, the most persistent
being vibration in the reheater  section.

Scrubber availability reported for 1973 ranged  from  73 percent in August to 13 per-
cent in December.  The decreasing availability  was due to deterioration and subsequent
overhaul of process equipment.  Recent availability  figures are: March 87 percent,
April 81 percent, May 57 percent and June 80  percent.  This system  is down with no
immediate plans for restarting since the EPA  demonstration program  is completed.
Boston Edison is evaluating the  data collected  during the demonstration period to
determine the course of future action.

Availability of Module A has increased in the past several months.  It was 72-percent
in April, 93 percent in May, 54  percent in June,  95  percent in July, 91 percent in
August and 85 percent in September.  Module B was removed from service until all
necessary modifications are made to Module A  to permit reliable operation.

This is a demonstration project where lime mixed  with water is injected into the
boiler.  The longest test run was less than two days.

At present, only flue gas from Boilers 2, 3 and 4 (about 40 percent of the station
capacity) is treated because fly ash from the inefficient precipitators overloads
the clarifiers.  Operating hours for Modules  1  through 4 between  3/17/74 and 6/30/74
were 1756, 762, 815, 1707 respectively.  The  plant tries to run Modules 1 and 4
continuously.  The outage hours  for these units is primarily  for  inspections.

System availability has been essentially 100  percent sinde 4/74.  However the
availability figure has little meaning since  only two of the  four modules were
operating at any time because of low demand.

The unit operated only 700 hours during the past  two years.   Primary reason for the
downtime was the delay in converting the reheaters from natural gas to fuel oil
firing.  The unit is scheduled to restart again in late November.

-------
                                Table 3   (continued).   OPERATING SUMMARY FOR  FGD  SYSTEMS
          Utility and Unit Name
                         Status
oo
          Kansas City Power and Light
            Hawthorn No.  3
          Kansas City Power and Light
            Hawthorn No.  4
          Kansas City Power and Light
            La Cygne
          Kansas Power and Light
            Lawrence No.  4
          Kansas Power and Light
            Lawrence No.  5
          Louisville Gas and Electric
            Paddy's Run
          Southern California Edison
            Mohave No.  2
The FGD system has undergone several major  modifications.  Availability has since
increased from 30 percent in 1973 to as  high  as  70 percent recently.  Plant
operators were on strike between July and October 1,  1974, and during that time
the FGD system was down.  The system was restarted on October 1st.

This unit was converted from furnace injection to tail-end scrubbing.  The plant
has experienced more problems with this  unit  (both mechanical and chemical in
nature) than with Unit 3.  The operation can  be  characterized as "fair."

Initial problems included fan deposits,  demister and  nozzle pluggage, reheater
failure and screen pluggage.  Many of the original problems were attributed to
poor pH control.  Recently the unit has  had about 80  percent availability and
there are no outstanding problems.  However it is necessary to remove each module
from service once a week to clean out accumulated solids.

The system has undergone a number of process  modifications.  At present the system
is capable of sustained operation although  SO, removal efficiency is limited to
only 75 percent and the demisters must be washed daily  (automatic washing).  Manual
washing of the demisters is required every  two weeks.  The unit is badly corroded
and will be replaced by a new electrostatic prccipitator and FGD system in 1977.

This unit has encountered many of the same  process problems as Unit 4.  In addition
there is poor gas flow distribution between the  eight modules and within each
module; measures are being taken to correct the  distribution.  The boiler burns
natural gas whenever it is available so  it  is difficult to assess FGD system avail-
ability.

FGD system availability is near 100 percent.  However since the system is installed
on a peaking boiler there are many occasions  when the boiler's run is too short to
justify start-up of the FGD system.

This is an experimental unit.
ability above 80 percent.
It has operated quite  successfully with an avail-

-------
                               Table 3   (continued).    OPERATING SUMMARY  FOR  FGD  SYSTEMS
          Utility and Unit Name
                        Status
          Nevada Power
            Reid Gardner No. 1
          Nevada Power
            Reid Gardner No. 2
          Potomac Electric and Power
            Dickerson No. 3
The FGD system started-up  in March -1974 and has had an availability of over 90 per-
cent when there was  sufficient trona (impure form of sodium  carbonate).  The lack
of trona has limited the operation of this unit.   The system has operated only 900
hours since April  1974.

The FGD system started-up  in March 1974 and has had an availability of over 90 per-
cent when there was  sufficient trona (impure form of sodium  carbonate).  The lack
of trona has limited the operation of the unit.  The system  has operated only 900
hours since April  1974.

There is no record of FGD  system's availability for the period prior  to August 1974
since the unit was down frequently for process modification,  equipment repairs, etc.
Availability since August  is about 34 percent.
N>
vo

-------
THE LAWRENCE POWER STATION
Power Generating Facilities
     The Lawrence Power Station of Kansas Power and Light Company
is located in a lightly industrialized area on the outskirts
of Lawrence, Kansas.
     The plant operates two steam boilers which are equipped
to burn coal, natural gas supplemented with oil, or a combination
of these three fuels.  Boiler 4 is the oldest of the two units.
It was first placed in service in 1959 and operated as a cyclic-
load boiler.  The maximum electric-generating capacity of this
unit varies with the type of fuel being burned:  with natural
gas the output can be as high as 143 MW; with coal plus natural
gas output decreases to 125 MW.  Retrofitting of this boiler
with an FGD system in 1968 introduced additional pressure drop
in the flue gas system and further reduced the boiler capacity
to 115 MW.
     The second unit at the plant is Boiler 5, with a rated
capacity of 400 MW when burning coal plus natural gas.  The
unit together with the FGD system, was placed in service in
1971.  Like Boiler 4, it is classified as a cyclic-load
unit.
     Both boilers at the Lawrence Power Station were built by
Combustion Engineering, which also designed and installed the
FGD systems on these boilers.  These FGD systems consist of
limestone furnace injection with flue gas wet scrubbing.
     The present grades of coal burned at the Lawrence Power
Station has a gross heat content of 12,000 BTU/lb.  Average ash
                             30

-------
and sulfur contents are 12 percent and 3.75 percent, respectively,
The company is in the process of switching from this high-sulfur
Kansas coal to Wyoming coal which contains 0.4 to 0.8 percent
sulfur and 10 percent ash, with a gross heating value of 10,000
BTU/lb.  This change was necessitated by the curtailment of
strip mining operations at the Kansas coal supply site.
FLUE GAS DESULFURIZATION SYSTEM
FGD Process Description.  The flue gas desulfurization systems
on Boilers 4 and 5 are identical in basic design and operation.
The FGD system on Boiler 4 has undergone several major modifica-
tions since its start-up in November 1968, many of which were
later incorporated into the design of the FGD system on Boiler 5.
     The FGD system associated with each boiler incorporates
facilities for storing, pulverizing, and injection of finely
ground limestone rock into the boiler's furnace chamber, where
the bulk of it is calcined.  The calcined limestone, along with
the fly ash, is transported by the flue gas to the tail-end
wet scrubber modules, where the S02 in the gas reacts with the
scrubbed'lime/limestone in a recirculated slurry and is substan-
tially removed, along with the fly ash, from the gas stream.
The cleaned gas is then demisted and reheated  (to prevent conden-
sation in the downstream equipment) and finally discharged from
the stack by induced-draft fans.
     There are two FGD modules on Boiler 4 and eight FGD modules
on Boiler 5.  The 10 modules are identical in size, and each
is designed to handle roughly 150,000 scfm of flue gas.  A typi-
cal module is shown in Figure 4.  A single stage of 3/4-inch-
diameter glass marbles is contained in a bed about 3 to 4 inches
thick, fitted with overflow pots to collect and drain the liquor
from the top of the bed.  The scrubbing liquor is sprayed through
nozzles located below the bed.
     Each of the two modules on Boiler 4 is connected  (through
an I.D. fan) to a separate 120-foot stack; gases from all eight
                              31

-------
             WATER
               SEAL
 FROM AIR  HEATER
                            TO STACK
ID  FAN
    HOT
    H?0
   REHEAT
   DEMISTER
   MARBLE B
                     SOOT BLOWER AIR
                      WATER WASH LANCE
         (2)
Wj'^^y^Vr^.i'^fy^^rA
fe^v'^^?*^':^::?^1
."": '"''' '' :":v -:v::^
                                 OVERFLOW
               RECYCLE TANK  (1)
                 (ENLARGED)
                    DRAIN  TANK
      LAWRENCE NO.  4
             CE-APCS
        OCTOBER 1972
        SCRUBBERS (2)
(ENLARGED DEPTH - 4')
                                                   CLARIFIED FROM POND
                        TO  SOLID
                        DISPOSAL
                        POND
         Figure  4.   Sketch of a  typical FGD module
               at the Lawrence Power Station.
Source:   Kansas  Power and Light Company
                                32

-------
modules on Boiler 5 are discharged through a common stack, 375
feet tall.
     Originally, all modules were fitted with bypass ducts
and hydraulic seal dampers.  Because of extensive corrosion
and pluggage problems with the two modules of Boiler 4, the
bypass ducts on these modules were removed.
     Spent liquor from the scrubber tower drains into a recycle
tank, which allows 30 to 40 minutes retention time to ensure
complete conversion of the scrubbed S07 to calcium sulfite and
calcium sulfate.  Spent liquor from this tank overflows to a
drain tank, from which it is pumped to sludge disposal ponds.
     There are three sludge ponds on site, covering areas of
4 acres, 16 acres, and 28 acres.  The sludge first enters the
16-acre pond and overflows into the 4-and 28-acre ponds.  Approx-
imately 800 gpm of sludge containing 9 percent solids, is fed
to the unlined ponds.  Because the sludge contains unreacted
lime as well as fly ash (ingredients which are usually added
to stabilize limestone sludge), it sets up very hard, like
concrete, without additives.
FGD System Performance.  Several major modifications completed
by Combustion Engineering and Kansas Power and Light Company
on Unit 4 appear to have significantly improved the performance
and availability of that unit.  Both FGD modules on Boiler 4
have recently performed reasonably well.  Availabilities close
to 100 percent were reported for July and August 1974.  The
S0~ removal efficiency has been around 65 percent, which is
sufficient for the plant to comply with the applicable pollution
control regulation.  S0? removal efficiencies as high as 85
percent were achieved over a short period, but only at the
expense of an accelerated rate of scale formation in the scrubbers
     Because recent operation of Boiler 5 has been on natural
gas, the FGD modules have not been subjected lately to severe
operating conditions.  When the boiler is coal-fired and the
                             33

-------
FGD system is in operation, problems experienced are similar
to those encountered with the modules on Boiler 4.  Currently
the main problem with Unit 5 is improper distribution of flue
gas to the eight modules.  Combustion Engineering is performing
tests on Unit 5 to alleviate this problem.
     Analysis of the problems encountered during and since start-
up reveals that nearly all were due to improper control of process
chemistry.  In limestone furnace injection, it is difficult
to achieve satisfactory control of the degree of limestone cal-
cination as well as the amount of lime/limestone carried in
the flue gas to the tail-end scrubbers.  This situation is further
aggravated when the boiler is operating as a cyclic-load boiler
and is fired with variable combinations of coal, natural gas,
and oil.
     As mentioned earlier, the FGD system on Boiler 4 underwent
several major modifications which are briefly described in this
section.
     When the FGD system initially started operation in 1968,
the configuration of each of the two modules was as shown in
Figure 5.  This design presented many operating problems, which
included  (1) scale buildup and plugging of the hot gas inlet
duct,  (2) erosion of the scrubber walls and corrosion of the
scrubber internals,  (3) plugging and scaling of drain lines,
tanks, pumps, marble bed, demister, and reheater and  (4) scale
build-up on I.D. fan rotors, which resulted in fan imbalance
and vibration.
     In addition to the problems just mentioned, the S02 re-
moval was quite low because of everburning of limestone in the
furnace and dropout of the lime with the ash in the bottom of
the scrubbers.
     After the first few months of operation, the scrubbers
were modified, as shown in Figure 6, to include  (1) addition
of soot blowers in the gas inlet duct and under the reheater

-------




LAWRENCE NO. 4
CE-APCS
..XTO STACK DECEMBER 1968
^OFflN SC<2. ^ 
WATER. SEAL } ^ HOT
^rtr-
a.
FROM m
AIR i- -"- 	
HEATER

ORAI
TANK
^/VVVVWVWVVt"" 	 WlD
*W\AA/-X/WVW- - ..  "fc^
REHEAT
to
///////////////, DEMISTER 2
:u-T-,:.T-^-i MARRLF RED co
rifTIT^ CLARIFIED FROM POND FROM
^/
Y
N 1 *1
: _d >ei 	 , 	 ^ ^
btAL f^H
p&-


> HIK r"  '^-'
HEATER





^^/\AA/>/ViAA AA^
K'vWAAvsAA'^
Ill/lltllflllll
A 1 JL 4X1
''T' '-"Ti>"
T T T T
\/
HOT
t - H20
REHEAT
LAWRENCE NO. 4
CE-APCS
OCTOBER 1969
SCRUBBERS(2)
SOOT BLOWER AIR
DEMISTER
VERHEAD'PRAY
MARBLE BED


4 oa
=r
V 5
1 OVERFLOW . ?>
:*._

x:
ICLARIFIED FROM POND


(2) 	 TO SOLID
-j^\ n T c r>f*c R i
H) (2) SOLID DISPOSAL POND RECYCLE TANK DRAIN TANK PQND
(1) (1)
               Figure  5.
                                                                                Figure 6.
WATER,
  FROM
   AIR
HEATER
                JO STACK
                ID FAN
                       HOT
                      REHEAT -
                   DEMISTER
                   OVERHEAD SPRAY
                   MARBLE BED
                                      LAWRENCE NO.  4
                                             CE-APCS
                                         OCTOBER 1970
                                          SCRUBBERS(2)

                                      SOOT BLOWER AIR


                                            CLARIFIED
                     OVERFLOW.
(2)   RECYCTTTATlK
        (1)
                                      POND
                              DRAIN
                               TANK
                                                  TO
                                                SOLID
DL
FROM"
AIR J
HEAJEK~
i
WATER
SEAL
-ir


^xTvTO S
ypffio F
''VWAA/VA^A^S
SAAJW*A/V\A/>
?
^

^
' -i" f -r
y
0
M

TACK
AN
HOT
 H20
~ REHEAT
EMISTER
ARBLE BED
-OVERFLOW

LAWRENCE NO. 4
CE-APCS
OCTOBER 1972
SCRUBBERS(2)
(ENLARGED DEPTH* 4' )
SOOT BLOWER AIR
* WATER WASH LANCE
CLARIFIED
FROM POND
	 i TO
(2) SOL ID
-0 nrspnsfti
(2)   RECYCLE TANK  (1)
      (ENLARGED)
                                                                                         DRAIN TANK     POND
               Figure  7.
                                                                                Figure 8.

-------
bundle to prevent plugging (2) raising of the demister to reduce
carryover of solids, (3) directing the overflow liquor from
the pots to the pond, and (4) installation of a large recycle
tank and pump to catch the highly alkaline underflow and recir-
culate it to the marble bed.   Other modifications to combat
corrosion and pluggage were installation of a new type of spray
nozzles and lining of the bottom section of the scrubber tanks
with gunite.
     Most of the problems were reduced but not eliminated by
these modifications.  The new recirculation system did improve
the S02 removal efficiency of the scrubbers.
     In an effort to further  minimize corrosion, erosion, scaling,
and plugging, additional revisions were made during the summer
of 1970.  The configuration of the scrubber in October 1970
is shown in Figure 7.  The major revisions were the following:
     1.   Sandblasting and coating the interior of
          the scrubbers with  two coats of glass flake
          lining.
     2.   Replacement of all  internal steel pipes
          with plastic and fiberglass.
     3.   Replacement of the  stainless steel demisters
          with fiberglass demisters.
     4.   Addition of a ladder vane under the marble
          beds to improve gas distribution.
     5.   Modification of the pot overflow drain piping
          to allow the liquor to return to the recycle
          tank for a semiclosed liquor loop operation.
     6.   Removal of the original copper fin tubes of
          the reheater coils, which because of close
          fin spacing, caused the reheaters to plug
          easily.  Also, the  fins were flattened by the
          soot blower jets.   The copper units were re-
          placed with a carbon steel tube fin coil.
     Demister pluggage continued to create serious problems.
Manual washing every other night was required to maintain the
output required of the unit.
                             36

-------
     In the summer of 1972 the scrubbers (on both Units 4 and
5) were modified to operate using a high solid slurry crystalli-
zation process to control saturation and precipitation of scale
within the scrubber.  These latest major modifications, shown
in Figure 8, included enlargement of the liquor recirculation
tank and replacement of many components, such as piping, nozzles,
pumps, and mixers.  Also, the demisters were replaced with a
new two-bank fiberglass unit fitted with high-pressure wash-
water lances.
     Operation of the two FGD systems since the fall of 1973
has been most successful to date.  Some of the remaining problems
are isolated areas of corrosion, failure of expansion joints,
fouling of the demister, rapid wear of slurry pumps, and failure
of valves.
     Future modifications of the FGD systems on each boiler
will be concerned primarily with alleviating problems inherent
in furnace injection with limestone.  Therefore, Unit 5 will
be converted to a tail-end, wet limestone scrubbing process
by fall 1975.

     The current schedule for revisions on Unit 4 is as follows:
     a)   By January 1975, construction of two 2-stage
          scrubbers  (venturi followed by spray) will
          be started.
     b)   By January 1976 the two new scrubber modules
          will be operational.  The present scrubbers
          will be kept in service while the new scrubbers
          are being built.
     c)   By January 1977 the present scrubbers will be
          razed and an ESP will be installed.  It is
          anticipated that the ESP/venturi/spray flue
          gas cleaning system, will be operational by
          January 1977,  The new system will have forced
          oxidation via aeration to produce sulfates.
                             37

-------
THE WILL COUNTY POWER STATION
Power Generating Facilities
     The Will County Power Station of Commonwealth Edison Company
is located on the Chicago Sanitary and Ship Canal near the town
of Romeoville, in Will County, Illinois.  Delivery of coal and
limestone to the Will County Power Station is primarily by
barges using this canal.
     The station has four electric-power generating units with
a total rated capacity of 1147 MW.  Only Unit 1 is retro-
fitted with a flue gas desulfurization system.
     Unit 1 has a wet-bottom coal-fired boiler producing
167 MW of electricity.  The boiler was manufactured by Babcock
and Wilcox and was installed in 1935.
     The coal presently being burned has an average gross heating
value of 9463 BTU/lb; ash and sulfur contents are 10 and 2.1
percent, respectively.
     The boiler is fitted with an electrostatic precipitator,
having a 79 percent actual particulate collection efficiency.
Normally, the precipitator is not used except when the FGD
scrubbers are out of service.
FLUE GAS DESULFURIZATION SYSTEM
FGD Process Description.  The wet limestone flue gas desulfuri-
zation system was placed in service on February 23, 1972.  The
system consists of limestone handling and milling facilities,
two FGD scrubber modules  (identified as A and B), and a sludge
treatment and stabilization unit.  Each FGD module consists
of a booster fan and a Venturi scrubber followed by a turbulent
                             38

-------
contact scrubber  (TCA) SO- absorber tower. Operational problems,
described later in detail, have caused  shutdown  of Module  B
and modification of Module A.
     The FGD process is described in terms of the three major
operations: limestone milling, particulate and SOp scrubbing,
and sludge treatment and disposal.
     The limestone milling system consists of a  limestone  rock
conveyor, two 260-ton-capacity limestone storage silos, two
wet ball mills, and a slurry storage tank.  The  total storage
capacity of the two silos is equivalent to 48 hours of the FGD
requirement of limestone at full load.  The limestone is 97.5
percent calcium carbonate, 0.99 percent magnesium carbonate,
and 0.48 percent silica.  It is received as coarsely ground
particles (about 1/2 inch diameter or less) and  is finely  ground
to 95 percent through 320 mesh.  Grinding is accomplished  in
two wet ball mills, each rated at 12 tons per hour.  The lime-
stone is discharged from the mills in the form of a water  slurry
containing 20 percent solids.  The slurry is piped to a 4-hour
capacity, 62,500-gallon storage tank, which supplies the lime-
stone for the scrubber modules.
     The two scrubber modules on Will County Boiler 1 are
shown in Figure 9.  Each module was designed for 385,000 acfm
throughput at 355F, each handling 50 percent of the 167-MW
boiler's flue gas load.  The liquid and gas flow through a typi-
cal module is shown in Figure 10.  The flue gas emerges from
the boiler,  passes through an electrostatic precipitator and
is directed to the venturi scrubber.  The gas is forced through
the rectangular venturi throat and comes in contact with jets
of slurry sprayed from high-pressure nozzles located on each
side of the throat.  The scrubbing efficiency and consequently
the pressure drop in the venturi are regulated by actuating
a drive mechanism that varies the width of the venturi gap.
     The quenched flue gas mixed with slurry droplets exits
from the venturi throat and turns through the sump, in which
                             39

-------
-R-
o
                                                                                                          LIMESTONE
                                                                                                          BUilKER
                                                                               RECYCLE AND
                                                                              MAKE-UP WATER
                                                                                                            BALL
                                                                                                    MILLED   MILL
                                                                                                   PRODUCT
                                                                                                    TANK
                                                           ABSORBER
                                                         RECIRCULATION
                                                            PUMPS
                                                      JO SETTLING
                                                          POND
               Figure  9.   General flow diagram of  the FGD system  at Will County  Unit  1.

-------
TO SLUDGE
  WASTE
  POND
           VENTURI
            PUMPS
                             FLUE GAS
VENTURI
   VENTURI
RECIRCULATION
    TANK
                                                     CLEAN  GAS
                                                    TO REHEATE.R
                                            SUMP
                                                                ABSORBER
                                                           ABSORBER
                                                         RECIRCULATION
                                                             TANK
                                                            FROM MILL
                                                             SYSTEM
                                                   ABSORBER
                                                     PUMPS
               Figure  10.   Flow diagram of a typical FGD module,

-------
a great reduction in flow velocity causes the slurry droplets
to fall out of the gas stream into the venturi circulation tank.
     The gas then flows upward through the S09 scrubber tower,
                                             ^>
and passes through two perforated trays, which are wetted with
a shower of limestone slurry circulated from the SO- scrubber
tank.  These trays provide an extensive contact surface for
absorption of S0_. from the circulated slurry.
     The scrubbed gas, now essentially free of fly ash and S0~ ,
rises up the tower and passes through a two-stage Chevron-type
demister.  The fine mist droplets of liquid carried over with
the gas coalesce on the demister's vanes, and the resulting
large droplets fall through the tower by gravity.  The demister
is equipped with two sets of wash water lances.  It is washed
continuously from below by 120 gpm of fresh water and also
intermittently from above by 1000 gpm of pond water for 30
seconds every 2 hours.  The demisted gas then enters the reheater
unit, where its temperature is raised from 128F to about 200F.
This temperature increase imparts buoyancy to the gas and prevents
condensation in the fans, ducts, and the brick-lined steel stack.
     The bare-tube reheater is divided into three sections;
the first is made of 304 stainless steel and the other two of
corten steel.  Each reheater has four soot blowers to maintain
tube cleanliness.  The heat is supplied from Unit 1 boiler as
350 psig, saturated steam.
     To compensate for draft loss across each scrubber module,
an induced-draft fan boosts the pressure of the heated gas and
delivers it to the suction side of the boiler induced-draft
fan.
     There are two slurry tanks for each module: the S02 scrubber
circulation tanks, to which fresh limestone and make-up water
are added, and the venturi scrubber circulation tank, from which
the spent limestone slurry  (or sludge) is discharged.  These
two tanks are interconnected in such a way that the spent liquor
                             42

-------
from the SO  scrubber tank overflows into the venturi circula-
tion tank.  Each tank is fitted with agitators and pumps.  The
slurry recirculation rate in the SO^ scrubber is about 8750
gpm.  The recirculation rate through the venturi is 5800 gpm.

     The sludge treatment and disposal system used at Will County
is illustrated in Figure 11.  Spent slurry from all the venturi
tanks is discharged to a 65-foot-diameter clarifier tank.  During
emergencies or when the clarifier or stabilizer unit is inoper-
able, the slurry can be discharged to a small clay-lined holding
pond. Overflow from the clarifier is returned to the process;
underflow is stabilized in a facility built and operated by
Chicago Flyash Company under contract with Commonwealth.  About
200 pounds of lime and 400 pounds of fly ash are used per ton
of dry solids of sludge.  The fixed sludge is transported by
concrete mixing trucks to a small pond on site for solidification.
The stabilized sludge solidifies in about 1 week, after which
it is hauled by Material Services Company to an offsite dump
for use as landfill.  Recently, this contractor obtained State-
EPA permit to develop an offsite land for sludge disposal.
FGD System Performance.  As mentioned earlier, the FGD modules
at Will County 1 were plagued with numerous problems since
February 1972.  Many of these problems have since been solved,
and others have become manageable.   Improved operation of the
FGD system is reflected in increasingly higher availability
figures for Module A in 1974.  When Module B is modified on
the basis of experience gained with Module A, its performance
and availability should be comparable to those obtained from
Module A to date.  The monthly availability factors for each
module are presented in Table 4.  A. brief chronology of the
major problems encountered and their solutions is given below.
     1972 - Demister plugging was a constant problem, mainly
because of heavy accumulations of limestone on the bottom of
the demister, which were partly due to low wash-water pressure
                             43

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                                                                          SCRUBBER SLUDGE POND
                                             THICKENER UNDERFLOW
HOPPER
                               DTD ON-SITEO
                               DISPOSAL BASIN
                                                                           RECYCLED THICKENER OVERFLOW TO MODULES
              Figure  11.   Limestone  sludge stabilization facilities.

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Table 4.  FGD SYSTEM AVAILABILITY FACTORS




       FOR WILL COUNTY UNIT NO. 1
Period
Month/year
March, 1972
April
May
June
July
August
September
October
November
December


Availability , %
Module A
0
33.99
69.48
8.44

78.65
0
0
0
21.77


Module B
35.4
13.68
31.82
30.91

20.60
29.48
0
0
29.69


Period
Availability, %
Month/year Module A
January, 1973
February
March
April
May
June
July
August
Septen>er
October
November
December
0
21.
64.
6.
0
0.
51.
19.
0
32.
50.
0

94
79
17

96
36
23

00
80

Module B
0
24.26
10.69
13.08
0
0
0
0
0
0
0
0
Period
Availability, %
Month/year Module A
January ,
February
March
April
May
June
July
August




1974 0
0
20.98
72.27
93.12
54.50
95.75
91.25




Module B
0
0
0
0
0
0
0
0





-------
caused by leaks in the pond-return bypass.  Because of plugging,
Modules A and B were out of service for several days each month
during March, April, June, and July 1972.  The modules were
also out of service from September 26 to November 21, 1972,
because the boiler was down during that period.
     As a means of solving the demister problem, the scrubbers'
slurry nozzles were lowered and the slurry circulation system
was left out of service to keep the demister clean.  Because
this change gave no improvement, the demister elements were
hand-washed, a procedure that decreased demister plugging but
increased difficulties with the venturi nozzle because broken
elements from the demister entered the slurry system.
     Because the reheater of Module B vibrated excessively during
high rates of gas flow, Module B was taken out of service in
April for reheater modifications.  These modifications included
rebracing of the reheater tubes and installation of a baffle
plate to reduce vibrations.
     Other reasons for outages in 1972 were erosion and plugging
of spray nozzles, internal and external buildup of deposits
on venturi nozzles, corrosion cracking, sulfite blinding, and
fan vibrations.
     1973 - Demister plugging continued in 1973.  Furthermore,
the demister on Module B broke loose from its mountings and
the resultant carryover of wash water plugged the reheater,
also leaked because of chloride pitting corrosion.  Module A
was down from April 24 to May 24, 1973, and Module B has been
down from April to date.  No scrubbers were in operation from
August 27 to September 26, 1973.
     As a further step toward resolving the pluggage problems,
the system of continuous underspray and intermittent overspray
was installed in Module A to wash all the demister compartments.
Extra nozzles were added and a clean water supply was maintained.
The reheater bundle was also retubed.

-------
     1974 - This year to date only Module A is in operation.
Although plugging of the demister and reheater has not been
completely eliminated, the improved washing system has provided
a partial solution.  The other significant problems are freeze-
up of the venturi throat drive mechanism, tank screen blinding,
duct corrosion, and vibrations.  Loss of building heat caused
extensive damage and kept the scrubber down the entire month
of January 1974.
     Some components of Module B, such as reheater bundles have
been cannibalized for use in Module A.  Modifications of Module
B are not expected to begin until performance of Module A is
satisfactory.
                             47

-------
HAWTHORN POWER STATION
Power Generating Facilities
     The Hawthorn Power Station of Kansas City Power and Light
Company is located in a heavily industrialized area on the
north bank of the Missouri River in East Kansas City, Missouri.
     The plant operates five coal-fired boilers.  Boilers
1 and 2 are considered peak boilers, each rated at 100 MW.
Boilers 3 and 4 are cyclic boilers.  When burning natural
gas, each is rated at 140 MW; when burning coal the capacity
of each boiler drops to 100 MW.  These four boilers were built
and placed in service in early 1950.  Boiler 5 was placed
in service in early 1970; it operates as a base-load boiler
at a rated capacity of 500 MW.  All these boilers are dry-bottom,
pulverized-coal-fired units, designed and manufactured by Com-
bustion Engineering.
     Two grades of coal are burned: the coal with higher ash
content typically contains 14 percent ash and 3 percent sulfur,
with a heat content of 11,400 BTU/lb; the lower-ash coal contains
11 percent ash and 0.6 percent sulfur, with a heat content
of 9800 BTU/lb.  Natural gas is also burned occasionally.
     Of the five boilers at the Hawthorn plant, only Boilers
no. 3 and 4 are fitted with flue gas desulfurization  (FGD)
equipment.
FLUE GAS DESULFURIZATION SYSTEM
FGD Process Description.   Initially, the FGD systems on both
boilers were designed to operate by injection of dry limestone
into the furnace, followed by tail gas scrubbing of both the
SO,, and the furnace-calcined limestone (as well as the fly ash)
                             48

-------
from the flue gas stream.  Because of tube pluggage in Boiler
4, attributed to limestone injection, this mode of operation
was modifed.  Ground limestone is no longer injected into the
furnace but instead is introduced into the flue gas near the
gas inlet to the tail scrubber tower.  The FGD system on Boiler
3 continued to operate as originally designed.  Both systems,
however, have undergone minor modifications to overcome such
difficulties as build-up of sediment and pluggage of various
components.
     The FGD system on each boiler consists of two identical
modules, each capable of treating 250,000 acfm of flue gas at
300F.  Bypassing of the modules is possible through a system
of ducts and dampers around each module.
     Details of a typical module are shown in Figures 12 and 13.
Each scrubber module is 18 feet wide, 26 feet long, and 56 feet
high.  The lower 16 feet of the module is the reaction tank,
in which the materials have time to complete their chemical
reactions to remove sulfur dioxide.  Two mixers are installed
in the tank to provide thorough mixing and to keep the reac-
tants and the fly ash in suspension, one on the lower back
wall and the other on the upper front wall.
     A sloping, perforated plate near the top of the reaction
tanks acts as a strainer to catch large solid objects, such
as scale, mud, or marbles, and funnels them to the mouth of
a jaw crusher.  Periodic operation of this equipment reduces
these pieces to fine particles, which are discharged in a slurry
to the fly ash pond.
     As the flue gas enters the absorber tower above the liquid
level in the reaction tank, it comes in contact with slurry,
which is sprayed through 81 nozzles on 18 headers located under
a marble bed.  The marble bed consists of a 3- to 4-inch thick-
ness of 3/4-inch-diameter glass marbles, retained on a perforated
plate.  Quenched flue gas and the sprayed slurry bubble through
                             49

-------
                                                                                                    STACK
     LIMESTONE
     HOPPER
      CRUSHER
Ul
o
                                               BYPASS
                                                SEAL
                                                                                                      i i
                                                                                                      r i
                                                                                                      i t
                                                                                                      I  i
                   FURNACE
                                     AIR

                                             DRAIN
LEGEND
	 AIR POLLUTION  CONTROL SYSTEM
	 NOT APCS EQUIPMENT
                                                         Li I 111 III
                                                    DEMISTER SPRAYS
                                                     SCRUBBER  CELL

                                                     OVERFLOW  POTS
                                                   YYYYYyvvvYY
                                                    UNDERBED SPRAYS
                                                   j i '  i .'  ' <'  f i if
                      ' ~ XT -i        '*
,		( I.D.U	
                     'FANS/'
                       .. -'

                TO DEAERATOR


                FROM DEAERATOR
                FROM WATER  SUPPLY PUMP
QKhHtATERS

l-

                                                                                                         DRAIN  FROM
                                                                                                         BYPASS SEAL
                                         TO BYPASS SEAL
                                            TO DEMISTER
                                               SPRAY
                                         TO GAS DEFLECTOR-*
                                               SPRAY
                                          TO MAKEUP

                             Figure 12.   Process  flow  diagram  of a  typical  FGD module,

                                      similar to  those  used on  Boilers 3 and 4,

-------
                                             STACK
 PULVERIZER
                                                               FAN
                                               STACK GAS
                                               SCRUBBER
                                                   RECYCLE
                                                    PUMP
                                                                                    TO ASH DISPOSAL
                                                                                    POND
Figure  13.   Sketch of  a  dry limestone  furnace injection system with tail end scrubbina.

-------
the marble bed, giving the marbles a spinning motion.  The pur-
pose of the moving marbles is to provide a large amount of sur-
face area within a relatively small volume and thus to facilitate
contact of the reactants. The liquid level above the marble
bed is 10 to 13 inches high.  The liquid overflow from the bed
is discharged through 48 drain pots.  The scrubbed flue gases
flow upward 10 feet to a double row of Chevron separators designed
to remove water vapors carried by the flue gases.  The gases
then pass around horizontal fin-tubed heaters that reheat the
gases to about 175F before they are discharged to the stack
by the induced-draft fans.  Gases from all modules on Boilers
3 and 4 are discharged to the atmosphere through a common
stack 200 feet high.
     Spent liquor from the reaction tank of each module is dis-
charged to a 115-foot-diameter clarifier tank.  The overflow
from this tank flows to a clear well tank, where make-up water
from the Missouri River is added.  The discharge from this tank
satisfies the water requirements of the FGD system.  Distribution
of the water is shown in Figure 12.
     Sludge in the underflow from the clarifier tank is untreated.
The thickened sludge is pumped to a 160-acre pond, which is
also used for disposal of fly ash from the other boilers.
     Inlet and outlet dampers are provided on each scrubber
module to route the gases either through or around the module.
To ensure passage of gases through the scrubber when it is in
operation, a large U-shaped bypass seal is filled with water
to positively close the bypass.
     The demister wash system uses a set of eight water lances
that turn on automatically to wash mud from the demisters when-
ever the dampers close.  The lances are located four above and
four below the demister vanes.
     The reheater tubes are cleaned by two steam lances placed
below the finned tubes.  The heating medium is hot water from
                             52

-------
the suction of the boiler feed pumps, delivered at 150 psig
and 325F.
FGD System Performance.    Modifications recently completed by
Combustion Engineering and Kansas City Power and Light Company
apparently have significantly improved operation of the FGD
systems.  Module 3B on Boiler 3 recently operated for 550
hours with an availability factor of over 75 percent.  Continu-
ous monitoring equipment showed sulfur removal efficiency in
the range of 85 to 95 percent.  Particulate removal efficiency
was 98 to 99 percent.
     As a result of the recent modifications, the overall avail-
ability factor for the two modules on Boiler 3 has increased
from about 30 percent to 70 percent.  Availability of the FGD
system for Boiler 4 has lagged because of the many problems
attributed to dry limestone injection.  Apart from those entailed
in switching of Boiler 4 from furnace injection to tail
gas injection, the major problems encountered with the two FGD
systems at the Hawthorn Power Station have been identical.
Analysis of the problems encountered during and since starting,
reveals that nearly all were due to mechanical design rather
than process chemistry.
     1.  Sediment^ BuiIdup:  The reaction tank of each module
is equipped with two mixers to keep the 10 percent solids in
suspension.  The original 15-hp mixers did not do this job
properly, since buildup of hard mud, 6 to 8 feet high, developed
in the corners of the reaction tank.  Replacement of the original
mixers with 25-hp units gave no significant improvement.  The
most recent modification aimed at eliminating sediment buildup
consists of rounding off the bottom corners of the tanks by
welding triangular steel plates, as shown in Figure  14.  Fur-
ther, a new make-up water piping system was installed, with four
1-inch nozzles located on the walls about 6 feet from the base
of the tank and oriented to promote circulation and  prevent
settling of solids.
                             53

-------
                    MAKE-UP WATER  NOZZLES
Figure 14.  Sketch of the  reaction tank showing
  the rounding off of the  tank's  corners and
  the installation of make-up  water,  sediment
               flushing system.
                        54

-------
     2.  Pluggage of the Marble Bed:  In the initial construc-
tion, the drain pots above the marble bed drained into horizontal
headers that penetrated the module walls and emptied into the
reaction tank.  These horizontal headers plugged soon after
the system was placed in operation.  The headers were removed,
and sloping headers were placed inside the reaction tank.  Al-
though these did not plug as fast, pluggage was still a problem.
An additional problem occurred frequently when drain pots lifted
off the marble bed allowed marbles to fall into the reaction
tank.  Both of these problems have been solved by installation
of new stainless steel drain pots wich expanded metal covers;
a 3-foot rubber sock allows each drain pot to drain directly
into the reaction tank.  The pots are held in place by "J" bolts
that attach to the marble bed.  No pluggage of the new drain
pots has occurred.
     Pluggage in the marble bed has been alleviated also by
an operational change.  Increasing the liquid-to-gas ratio from
21 to 26 gallons per thousand cfm has increased the flow of
liquid sufficiently to ensure that all parts of the marble bed
are washed by at least two nozzles.
     3.  Excessive Wear of Spray Nozzles;  Orifices of the spray
nozzles were severly worn by abrasive action of the fly ash.
The initial nozzles lasted only a few days; replacement was
required because the enlarged orifices caused buildup of mud
in the marble bed, overloading of the recycle pump, and clogging
of the demister.  Although KCPL installed a series of nozzles
of different materials from different vendors, the longest life
obtained from any of those was about 3 weeks.  Since these nozzles
are very expensive, KCPL designed a nozzle that could be made
in the shop from pipe parts.  These nozzles also lasted only
about 3 weeks, but their cost was only 5 to 10 percent of the
cost of vendors nozzles.  Recently new ceramic nozzles were
installed, and after 550 hours of operation they exhibited no
signs of wear.  Although this is not an exceptional service
                             55

-------
time for nozzles/ it is by far the best performance to date,
since all other nozzles were completely worn in an equivalent
amount of time.
     4.   Demister Pluggage:  During sustained operations the
scrubber modules were taken out of service every 3 days to
allow the hosing of mud from the demisters.  Pluggage has been
controlled by adding retractable water lance blowers under the
demister and by moving the rotary water lance blowers from below
the demister to between the rows of demister vanes.  With these
modifications the demister wash system now performs satis-
factorily.
     5.   Bypass Seal Pluggage:  During periods when the flue
gas is bypassed around the module, the drained-out water seal
acts as  a mechanical dust collector, accumulating fly ash.
When the module is returned to operation and water is turned
on, the fly ash in the water seal turns into mud, hampering
operation of the bypass seal.  Pluggage in this seal was elimi-
nated by changing the flushing sequence within the seal.
                             56

-------
REID GARDNER POWER STATION
Power Generating Facilities
     The Reid Gardner Power Station of the Nevada Power Company
is located near Moapa, Nevada, about 50 miles north of Las Vegas.
The station has two electric power generating units  (Reid Gardner
1 and 2), each rated at 126 MW.  The units are identical in
design, and both operate under base load conditions.  The coal-
fired boilers were manufactured by Foster Wheeler.  Reid Gardner
1 was placed in service in 1965, and Reid Gardner 2, in 1968.
Average gross heating value of the coal burned is 12,450 BTU/lb;
average ash and sulfur contents are 9 and 0.6 percent, respec-
tively.
     Reid Gardner 3, with design capacity of 125 MW, is under
construction, with start-up scheduled for the spring of 1975.
Reid Gardner 4, also a 125-MW unit, is in the planning stage,
with operation expected in 1978.
FLUE GAS DESULFURIZATION SYSTEM
     The sodium carbonate base flue gas desulfurization (FGD)
systems on Reid Gardner 1 and 2 were manufactured by Combustion
Equipment Asssociates and placed in operation during March and
April 1974.  The design of these systems was based on data
gathered from operation of an 8000-acfm pilot plant, which
operated at the Reid Gardner Power Station during 1971 and 1972.
FGD Process Description.  The FGD system on each boiler consists
of a single module, designed to handle 473,000 acfm of gas at
350F.  The module is made up of a twin variable-throat venturi
scrubber followed by a single-stage S02 scrubber tower.  The
FGD modules on both boilers share a common trona  (sodium car-
bonate ore) storage and beneficiation plant.  Bypassing of each
                            57

-------
module is possible through a guillotine-type bypass valve.  As
shown in Figure 15, the hot flue gas from the boiler passed first
through an existing mechanical collector (multicyclone), where
about 75 percent of the fly ash is removed.  Pressure is then
boosted by an induced-draft fan before the stream splits as it
enters the twin variable-throat venturi scrubber.  The hot flue
gas is quenched by a shower of circulated sodium-base liquor,
sprayed from tangential nozzles located on the walls of the
venturi.  The gas-liquid mixture then passes through the venturi
throat and exits into the sump, where the reduction in velocity
causes the liquor droplets to fall and separate  from the gas
stream.  A liquid-to-gas ratio of 10 gallons/ 1000 acfm and
a pressure drop of about 15 inches of water are  maintained in
the venturi for efficient removal of SO- and particulates.
The scrubbed gas then enters the SO2 scrubber tower tangentially.
The centrifugal force created causes the finer droplets to
coalesce near the tower's wall and separate from the gas stream.
The scrubbed gas, which is now essentially free  of fly ash and
of most of its sulfur dioxide content, rises through the tower
and bubbles through the 3/8-inch-diameter holes  of a single
sieve tray.  The tray is flooded with clear water from the ash
pond at a rate equivalent to 1 gpm per 1000 acfm of gas and
is intermittently washed with fresh water from below.  More
SO2 is absorbed in the clear water tray and the  pH of the liquid
effluent drops to about 5.  The cleaned gas continues up the
tower and passes through the radial-vane-type mist eliminator,
where the liquid droplets carried over with the  gas are trapped
and removed.
     The gas is reheated by direct contact with  hot air to pro-
vide buoyancy and to prevent condensation of the gas on duct
walls or in the stack.  Ambient air is drawn in  by a separate
fan and steam-heated in a shell and tube heat exchanger before
it intermixes with the scrubbed wet gas in the outlet duct of
the module.  The combined gas stream, which is now warmer, enters
the 200-foot-tall stack and discharged to the atmosphere.
                             58

-------
TRONA  (SODIUM CARBONATE)
     WATER FROM
      ASH POND
\D
                  TRONA
                   SILO
 BOILER
                                              CYCLONE
                                          /   V
\/
                                  CLARIFIER
 STACK


WATER FROM
 ASH POND
                                                                                       TO SLUDGE POND
                                                                  MODULE 1  OR  2
                       Figure 15.  Simplified flow diagram  of  the FGD system on  each of

                             Reid Gardner 1 and 2 electric  power generating units.

-------
     The S02 scrubbing reagent in the FGD systems is trona,
an impure form of sodium carbonate.  It is mined by Morrison
and Weatherly Chemical Products Company from Owens Lake in
California and shipped to the Reid Gardner Power Station as
a powder.  The trona is transferred pneumatically to a tall
silo having a 48-hour-supply storage capacity.  It is then trans-
fered to the day bin from which it is conveyed by screw conveyor
to a slurry tank and mixed with fresh water to dissolve its
sodium carbonate content.  The slurry, containing such impurities
as sand and sodium chloride, is pumped into a clarifier, where
the insoluble impurities settle out.  The clarified sodium car-
bonate liquor is then pumped to the modules recirculation tanks.
The effluent from the FGD system is made up of three sources;
the slip stream of spent liquor discharged from the recirculation
tank, the acidic effluent from the clear water tray, and the
alkaline clarifier underflow which serves to neutralize the
pH of the combined liquor before it is discharged to the sludge
settling ponds.  The spent liquor is pumped to a small 6-acre
pond, from which overflow can flow to a 45-acre pond.  Because
operation of the FGD system has been limited and the evaporation
rate from the 6-acre pond is high, no liquor has yet trickled
to the larger pond.  The water system operates on an open loop,
with no liquor recycled to the modules from the ponds.
FGD System Performance.  Since their start-up in early 1974,
both modules at the Reid Gardner Power Station have performed
satisfactorily.  Because of difficulties in obtaining sufficient
quantities of trona, however, operation of the modules has been
subjected to frequent interruptions and the flue gas has been
bypassed to conserve trona.  The longest continuous operation
was on Module 2, for 18 days.  The FGD system has never had
a forced shutdown due to problems originating in the equipment,
and thus can be considered as essentially 100 percent avail-
able, with operations interrupted only by the trona shortage.
Since start-up, each module has operated for 900 hours.
                             60

-------
     Since the major problem preventing continuous operation
of the FGD modules has been and still is the inadequate supply
of trona,  the Nevada Power Company has been experimenting with
the use of sodium carbonate brine.  One tank truck shipment
of brine from Green River, Wyoming, has been delivered and will
soon be tested on Reid Gardner 2 unit.  Larger quantities cannot
be received, since the brine freezes at ambient temperature
and the plant lacks the proper facilities for storage.
     The system experienced the usual minor start-up problems,
such as rubber liners on recirculation lines becoming loose
as a result of poor fabrication, freeze-up of instruments,
plugging in bypass lines of some control valves, and leakage
in the mechanical seals of the recirculation pumps.  Further
freeze-up problems were experienced with the louver type bypass
dampers, which were later replaced by a combination of louver/
guillotine-type dampers.
     As expected, this soluble-base FGD system has not experi-
enced such problems as equipment scaling, demister plugging,
erosion, corrosion, which are normally associated with lime/
limestone FGD systems.
                             61

-------
INFORMATION SOURCES

     Much of the information reported here concerning FGD systems

operation was obtained recently by visits to plant installations
and discussions with plant personnel:

               Hawthorn Power Station       June 6, 1974
               Will County Power Station    June 20, 1974

               Lawrence Power Station       August 13,  1974
               Reid Gardner                 October 8,  1974

   In addition, the following reports are cited for further

references :
1)    Palermo, Joseph V.  "Operating Experience on S02 Scrubbers,
     Hawthorn Units 3 and 4" Report to Missouri Valley Electric
     Association at Kansas City, Missouri on April 18, 1974.

2)    Gifford, D.C.  "Will County Unit 1, Limestone Wet Scrubbers,
     Description and Operating Experiences: November 30, 1973.

3)    Gifford, D.C. "Will County Unit 1, Limestone Wet Scrubber,
     Waste Sludge Disposal"  Paper presented at the Electrical
     world Symposium in Chicago, Illinois on October 30-31, 1973.

4)    Green, Kelly.  "Operating Experience with Limestone Injection-
     Wet Scrubbings Stack Gas Treatment"  Paper presented at the
     Frontiers of Power Technology Conference at Stillwater,
     Oklahoma on October 10-11, 1973.
                             62

-------
                  APPENDIX A




FLUE GAS DESULFURIZATION SYSTEM STATUS REPORT




                 OCTOBER 1974
                      63

-------
JiGAATfiTu5J?.P-0.l51.lo/7'+.

 I .0. I\)UKHER AMU COMPANY
                                             TABLE  1
                                       Su,-iHA!JTUCKY	b-T) .....	6
      IjCNO OHIu                       1-77        b
                                     .10-72	:i_
                                       6-78
                                                                         FA^WICJGTOW
                                                   NLXICO
   FARM1UGTON  NEW MEXICO
.... wHEATLAKD WYOMING	
             WYOMING
             WYOMING
                                                                    . _ CR*IG  COLORADO
                                                                       HAYOE.N COLOiiAUO
                                                                               COLORADO
                                                                                   OHIO
                                                                                   OHIO
 30.
 3i
_32
 "53
      CO'1.V.
      _0 A 1 K_r_ L A h D . . t C  t.H_t_U Of
      DC.TPOIT CIUSCN
       GcI-.'lAAL
 37
 39
 "40
       I'MOln^Al'OHS  POWLK AND LIGHT
      JS Ai\SA.S..C I I.y_['OwEIL.fi.jL,I.i.HT __
       KANSAS CITt POwlIK X LlOHf
           AS CITY I:'_C.^EK a LIGHT
                     "
 ALNA
 SI.CLttIR  NO
 ELUAMA..	
 PHILLIPS
_CiiE\/r
-------

FGD STATUS RrpoRT IU/7'
I.t'. MUMiER AL CU.'-'iFAlJY WANE

43 KANSAS POlnCR & LIthT
44 KAf.SfiS PO.JLR Z LIGHT
45 MINFUCKY J1 ILITIES
46 LOllif.VILLC 6AS ?, ELECThIC
47 LuUiSV ILLC l>fj i LLi.CTh.il.
*(> LouirviLLr CAS x ELECIKIC
49 LOUISVILLE t.AS A LLELTnlC
50 LOuisviLLF GAS f. ELECTRIC
fil LOIHSVJLLE HAS X ELIOMC
b? LiH'isviLLr GAS i ELECTRIC
53~ Lt'uisv JLLL G.sS X ELLClrxIc
54 LUIilSVHLF. GAS  tLLCTKIC
-Jfi uOUIS'J It-Lc GAb ^ El.LCTKlC
5f. LuuisviLLi t./.5. f. ELECTRIC
57 tlDlgTAIi'A f'fiwLK
to NO^TA'-IA PtiuEK
62 'LV ;">!'> A Pf)-*tR
tJ fiv^J i-oii<
65 Nlw F. JOLA'-iU LLFC bYiiTEh
66 ?;>)IUliLKN IKOIA^-A I'llli SLMVIcE
67 NOrtTl.EPi-J JtiLUA'lA 1MB SERVICE
f.P .^uRTHKRii lijI'JA.-.A Pijii SCiJVICE
70 i.iiRT.ir.'H'j j.lAif;, f'0>Li<
71 PKVNStLVA"];; f"1!^ c-'' CO.
72 PtMiStLVA-'iiA F'OxEi* CO.
73 PLNivSYL VA'fi A 1'fV.ti? CO.
74 I'MILtilEUP-a/, ELF.ClHlC
75 ii)Tr,-ac ELF.CTKIC j. PC^.'LK
76 PuC( fC Sf'itvICtl cK jNOI,vu/\
77 1-urLlC SLHVlCt OP f. L> I^LXICO
7fc KiuLlC SCiiviCE Or r,Lx ^|LXICO
79 PUBLIC StHVICC OF i.;Ew hLXlCO
fio PUBLIC SERVICE CF NEW .^.EXICO
fll >. CA'<(iLI,'lA F-U'i SEKV AUTHOHTY
f-2 biLT riJVCH PKGjFCI
03 S.\LT HIVtK P-'Oji'.CT
fi4 Sf\LT rtJVF.". !':"10JECT
1. OPrKATlOljAl. Ui.lTS 4.
2. U;;ITS ui^nER co^STHucrio.^i 5.
3. PLr.v-icn - coNThftcT AV.AKUEQ 6.
TABLE 1
SUM AH Y OF KGO SYSTEMS

UNIT NA^E

LAi-JKENCE NO 4
LAWhEEs.'CE Ii0 5
GKEtU KlVEi< 1283
C(. JL KUN NU 1
CiMt HUK NO 3
CA'JE RUN NO H
CAUL KbN 'NO 5
Cji'JE. NUN NO b
f-ULL CHLEK NO l
ISiLL CKhEK l'0 2
HILL CKLLK NO 3
rtiLU LtttH-is NO 4
PAODYS KU^ NO 6
COLSTR1P NO 1
COLa'FKlP iJO 2
CUI.ilKIH I-J0.3
COLiTNIP ;-ji),4
K^lu bAHU'-JER MO 1
ht.li) brtKrK'JLR t)0 2
KLlU ijiiKO^t-R NO 3
RElu (jA^U'^LR NO 4
UKAYTUi-J POINT Nu.3
UAILY NO. 7
BAILY fgO.8
MJTUHS.LL NO 11
SrlCH jLlni<,[. !JO 1
ShCKliOKNL i'^0 2
bnuCE -'-lAiJlif- itLU MO. 1 .
bKUCE MATgSf- IELD t;0. 2
l^rtui-E MATJSf IELD MO. 3
EijIJYSTCNL MO 1
DiCKcHSOfj NO 3
GlobOf: NO. 2
S/v 1 OUAfv NO 1
S:i JLIAN NO 2
Sn J JOAN MO. 3
SA'I OUAN i-JO.4
GLOKGEFOwN NO 2
NAV/.JU NO 1
NAVAOC NO 2
tJ.tVAuO MO 3
PLAilivufj - LETTER OF INTENT SIGt-J
PLMNi-JECi - RilQUESTING/EVALUATING
COJfSlOERING ONLY f-G'J SYSTEhS


LOCATION

LAWRENCE KANSAS
LAURENCE KANSAS
SOUTH CARL10N KENTUCKY
LOUISVILLE KLN1UCKY
LOUISVILLE (vE^fUCKY
LOUISVILLE hEMUCKY
LOUISVILLE KENTUCKY
LOUISVILLE KENTUCKY
LOUISVILLE KENTUCKY
LouISVIuLE KENTUCKY
LOUISVILLE KLi-JlUCKY
LOUISVILLE KENTUCKY
LOUISVILLE KENTUCKY
LoblsVILLE KENTUCKY
COLSTRIP MONTANA
COLSTKii' MONTANA
COLS1RIP KOUTANA
MAOPA l-jLVAL-A
MAOPA UEVADA
SOHLRSLT MASSACHUSETTS
CMESTEKTON 1NUIANA
GAKY 1,'jOlAijA
fcECKEIi MINNESOTA
t3LLC.Ei< MINNESOTA
SMlPPI.-iGfliKT PENNSYLVANIA
SiilrHINGPoUT PENNSYLVANIA
SHIPPINOPORT Pt-HNSYLVANIA
EOOYSTONE PENNSYLVANIA
OICKCI'SOIJ f-iARYLAMU
Hhli.CETOwN INDIANA
WAIEKFLJh NEW f'.LXICO
WATLRFLOW NEW MEXICO
WATERFLOW NEW MEXICO
iCATERKLOv. NEW MEXICO
GEORGETOWN SOUTH CAROLINA
PAGE AK120NA
PAGE ARIZONA
PAGE AhliOKA
ED
BIDS


START UP DATE

12-68
11-71
4-75
fc-60
6-00
6-80
6-75
6-76
6-77
6-79
6-78
6-77
6-79
4-73
5-75
5-76
7-78
0-79
12-73
12-73
6-76
0- 0
0- 0
0- 0
6-75
b-7fa
3-77
6-75
6-75
6-78
12-71
9-73
5-75
10-77
1-77
b-76
5-80
5-77
3-76
10-76
3-77




STATUS

l
i
2
6
6
6
3
6
6
6
6
3
b
1
2
b '
6
1
1 .
2
4
6
6
6
2
2
2
2
2
6
2
1
2
3
3
6
6
5
6
6
6



-------
                                          TABLE  1
                                   .yjMMARY Or I-GO SYSTEMS
I.D. NUMnER  AMD COMPANY
                                           UNIT NAME
LOCATION
START UP  DATE    STATUS
05
B6
67
ft*
69
91)
91
92

Ob
96
<)7
98
9CJ
SOuThL'KiM CALIKORi.U LljlSON
S')UT>if.Ff' CHf- 1'Ki'jI A EUISOw
bUJlHt.nr-1 CAl.lF.-'k.'jI;, LJlSON
c..)UTr-LRN CtLIKORiviA E013CN
MHITlttUM .llSblSSil'Pl PVvK COUP
SOUTh-El-U ' ISslSSlPpl PhK COOP
SJliT.,-Jf SHK'J PliHLlC SCKVJCL
SPKriuf-'lL'Lu liTll. iTy 80AKD
TC'-ii-'CSSEr V/ALU'Y AbTnOKlTT
T :?,:::>? E VALLt Y AuTnOklTY
IcX/iS Ijl Jl.lTUS
TEXAS liTlLlTlc-S
TEXAS UTILITIES
Tr.XAS UTll.iTlLS
TCXAS UTILITILS
MOHftVt i0 1
MUMAVE tiO 2
MOnAVE NO 2
MAT 1 lESIjURo NO.l
IIATflLSaURG NO. 2
HAKIIiTON NO 1
SOUUULST fJO i
SitAwNLE WO. 10
wi'JO.
-------
  C--('.';,Y                                STATUS  OF  Fob STSTtl'-iiJ  QUkIi-,o

  FtW/E/i ST/sTIO^'                                                   Cl'KkENT  MOM H

 I.D.  fiU.'-'LLh     1	              	  Ih^fALLMl IO,N  OF  A  FLUL  G/\S  UESULFUKlZATION  SYSTEM. IS  faEl.NG  CONSIDERED.
 A!.A(:A:-A_[..l.c;c.IL<.Lk_C^_c	I("  'V
 i>!G:;i.tl :..L y                                 HK^
    ;>b   -.-...- j.tlv.... ._. 			
 CO..L   0.;,-  1.5  JTKCLf.T  SULFUR
 f:iUT  SCLLC TFr, /;	''__		_			_	_   ...   		
 Li'vti>ro:a st'>ui'bi.;b
 _S_T ft i< T UP	1/20	'				

 I.r..  :-i-:.::>  ..,.2.._._		I.'-.ornLLATICu.OF. A . Fl.OL  GAS  L'C.SULH'UKIZ AT ION  SYSTE.^ IS  5EING  COW
 AL/.b-.' r,  i.L:C7.-lC  COOi'                 "   Ir  A  SYSTEM  IS  I i-jS T ALLEiJ,  II  ILL P.-iObAbUY  ts ThE LT  LlMESlOi\L  S
 IO- :"L .'iO. ? ...		
    2ti>  ''/ -  :,L'.-.'
 CO At.	U . ( -  1.5 JJj. i< C cf J  S U._P Ui<	
 KOT "f.t'Lf C rt'i
 L i ,"tl>Tu\L _ '<(. :-Uij!iI:.'.o_   _  .._		  	 _	            _     _           	                 _
 STA'.Tuf- '  "l/7r     '"	""  "	         	" ""	

 j.r:.' ..!;>;,.L;-  ""$""	"""	"	'      ..--..	-	-	  _
 A.!i j.o.r_-';__LLt:_cj '-ic  pQft.i.ij	
 A^'ALHL "it?"
    i:')0  -, -  :,LW	     	   _   LETTER OF_jrjTE;-.T_TO_ INSTALL AN FGD SYSTEM  WAS ISSUEO  TO KESEAKCH COTTRCLL.
"CC'.L  '('.'{,- u.; VfK-LL'.T  SOl_FJ:\'
 KCSE ';>  COTT-'ELL               __                  	
 LI-'C>IC-:.L st"os:;r:j    "	""	       	"
 U-^'-1'    ./?'	      	.	

 I . u. ! L ' L. i-1-    _<4   __            	
"AiU/JO'iA  LLFCT'ilC  Fui.l -.        	    LCTTcR OF ' 1UILMT "TO  If-iSTALL ArJ FGD SYSTEM  WttS ISSUED  TO RESEARCH COTTRELL.
 APtCMt JJL *,                         	
    '{ J ^   :*.-' L W
 COAI     0.~-  , . {  Pi,-CL?.T  j'^Lf-oK   	          _	                               _
 .^.^.-CM  \ cvf-CLL                                  "   ""    	                	       ~"  "~	          	 	 " '
 Ll'-LiTG'.: .;C.^'.;'a::.G
 STi'.r'iui'    *,/!?
  "   ~  ~  ~          -.   fc,    ^  -             ^."       *  *  ^  "^-i  ^..*^,^  ^  ^  ,^  -.^.^
 I.U. .!i-f-.-.J.!<     5	~   	        jOlii  MODULES  V.LKE  If;  SLRVlCL  CUKI.^u THL CAST  3U  UAYS,  EXCEPT FOR O.ME  DAY
 ArflJy: (i  f L'-I-JC _Sr^-ulf L___	''Lrt  -VJLULE:  1U  COr\, ".;: i ' ' "   ""  "~             ~     "i7..LL;il luk "v/F""LiAr^^.L  ^L.>1 L'i In:' Trie.' IULL I' (JUCT'TO  EACH HLHATLR~Yb  OAKPEM
    ll'j   '  .. -  : timrii XT              _       fh^  vi;-KAHO.\,  is  CO-jSi^CrtLu A >-->TIAL  SuCCi-SS oY  AP6.   h GU  SYSTEM  AVAIL-
 CO.'.L.    l.-.  ;--i.;-CC-:i .Si-i r'l/rf         "      oiLiTY  K/.S  93  Pt.r
-------
                                                         T;-.bL 2
------- cc- ;,.;.rr     ------------------------ ~     STATUS  DFTGIT SYSTEMS uURii.5~" io"/7<+

      l;C;-:i< SUTIi-i    " ...... " ...... "" ...........        .....       CURhEIjT  riONTH '"      '   ------- '"

 '- I.P.  r;i!Pj-rp- ' " "& --------------- ~~~~ --- CC.'jTtfACT "TO"ir.:STALir FGD SYSTEM ~OI\rCHOLLA~'NCT~3~>iAS BEEN AWARDED "TO --- ~
     AKIZl.i A f"j".LTC SEiUTCE                   REolVrcCh  COriTTnELL .
     C""'CLL". TvC;"2         .....
       2i>;;   ::,-.  - ' cu
    "COAL.    0 .-*;. ;;:; CET-.-T" SI'i r\ji-.    '          ...........            ~"~ ......    '       "       "    ~~"    ~            '   '
     i'.L i:.r!.Cn COT 1 'JU SGML PROPOSALS  HAVE  BEEN
" ....... AKI^O'iA ! v.'-LTC SERVICE ------------- KECE1VLO  ANO "ARE SiCING EVALUATED. ""' ........ -----------    ' ............. ---------- ......
     C:;vi!_LA .'.0  3
       c?DO   !;"- ..>.                               ' .......        - ""                    ..........            ...........
     CUAj_    0.^ ! i. f.1 C L ; ; 7 SL \_F(jn
     ;-:oT~sn riirj                          ;
     Lir.csroi-'i.  SC'-;.IB,-H';G
     STAHTUF    (i/V<5       '    ~ .....             .  .      --    ..... --  -  - ..... - .......... -  ..... ...... - ..... -  -- -   - .....      ......  -  ..
           " ^                    -.        ~                .                    -.  .              _
------ l.D.  ."IT-' -.(".   " &  .......  ......  ...............  ?L..:5 i-CK $02  COfJTKOL" SYSTEM  iKE  IN TilF  EAHLY  STACiE."  flPS  IS CURRENTLY
     ;.i  "t-.'-wL ......    """  ......... " "~ ..... "   ~  .......... ........ ~ "' ................... "" ..... --                     -      .....      
 00   ;;.!  :>rLi cTti.                       _ _
    "Li-.u-STfijt.  ^.o-onSiU,   ..... ..... " "     "   '         ......    " '"    ' " ..... ""     ..............................
     S! A'HiJr     f- /l~i

     I.f.   :i. " . ;'    9                          LXi'jflKu  SCKuntillixi ic  UPGRADED TO  CCISF-CY  ,,-ITH  APPLICABLE  502 REGULATIOI-.S.   "
     (-GUK  CCH ...f-S  ,.(, 1
       175   " ,  - i, i-.TKOi- IT ..... ~         ....... ~     '        - -  -         - ..... -    .......... - ........               .......
     C',AI.    Ci . ,-i  f i 'CE^,l  SLI riiri
     CfLM-.r- ......                                                          .....
  _ L!.vi.  .,1 !-.:..'!  .1.
     ;>T,i<>7' '   * C: / V .          -    - .                                                      ......    ......
     ^  """"^ *.-^    w    ^**.*_B.W._MH ^_~^^<*v^^^w^V^^W^H^^.B^*l^a>^^v^^>*v^^B^^^^^^v^^^^^a^^^^^a
     I.D.  M;:-'. f>   iu  ......... .......  EXISTING 'SCKUIiflErtS REMOVE AtiOUT 30  PERCENT OF  THE SO;:. "'THE  VEuTUKIS WILL
_ A^I^C';A , u:'LTC oE^IU.                   BE  JHOKAbEO TO  COf-.PLY  w!7ri  APPLICABLE  S02 REGULATIONS.
     F OUR  rCf
     STArtf'.it'

-------
         	TABLL 2_	     	      	
  'C'Cvtt'A'f:?   "                          STATUS  OF  h~G if'SYSTEMS  u'UKii\!fci  Iu/74

  PUULK siAiioi  "  "	                    ---              CURRENT  isofcfH

 i'."b."fiU!:c"i:K"  " ii                         EXISTINGscKUObfiiks REMUVE ABOUT so  PERCENT  OF THE  sua.  THE.  VENTURIS WILL
 /. I? I cON i'_rllJL'j-J^_.'lVlt.E	bC_JJG*ADE.y TO CJhPLY _wl T_H_ .af.PL 1_C Aj4l^_Sp_2_RGULAJ IONS.	
 F>~H'I< COK;\f.Ki;  .40  3
   22v _.( .-..KtTrvQriT.	.	. .._  _	... ..	   ._	-      		
 COAL   r.d  PE'.
 Cl^-'.-_... P..
 CHtHI CO
 Ll^f. SC
 STARTUP    4/77

 1.P. >AVOi   J3                         LSH'i, ArtE USED FOH PAKTICULATF. Ei-.lSSION CONTROL.'   FGu SYSTEM IS STI'LL IN
 AK] 7.\s.;t-  r\'.f\ ,][C__
 f-HjK C (;:<.,;. "f.  ;:(;
   600. ..''.-.  - hK
 C<-'AL   0..}  f'r^CEMT
 NOT Sr.LLCTLli  ....
 LIivt/i. If't.S
 S.TAHTlip	(>/7J			

 UP. !U*'..(.;<   j<*  		 iHt uOhPANY IS EVALUATING  hLl EM-1AT1VE PROCESSES FOR  S02 EMISSION  CONTROL.
 MASH, LLt'tlrii:  "         '"          "  '  "LI.itlSTOf.L SCRUbrUUG  IS THE  MOST L1KCLY PROCESS TO BE SELECTED.  THE  FINAL
 HlSSOUt'I  ^asti NO 1		DEClilOfJ  WILL BE ..MAUt  IN A  FEW MONTHS...._...      	._
   bbu  f'w  - ;;c_w
 C')AL  	
      LLfcTri.
      lOr.t  ^C;vJli>ri..b_	
       ip  ' ' b/T3      "    "        "    "	" ""  "	""	

 i.l). i.i.rLtli,   ~15                   ""'    THel COnPAlMY IS EvALUATliJG  ALTERNATIVE PKOCESSES FOK  SOg" EMISSION  CONTROL."
 tt A 5- nv_i: L LCTPTC	L_I rt E S_TO I'JE_S CKU_B3lNG  Is THE  MO ST LIK E L Y PROCESS JT03E SELECT ED.  THE  FINAL
          ~HASi^ HO *                     DEC I SI ON  WILL UC MA~DE  IN A  f-EW MONTHS".
           _~ IlElr'   _     		     		     	     	
                	""    "              "  ""   "          '   -----  -	          --	-     		--
 MOT StLfLTfl^                        _			     	    	
"LlNtSTGNc  SC''                ""  	"""                 	        " "~  "" ""    "	
 STAKTUP    6/f.O

-------
                                                            TAULL 2
	TTJMFrriTf	SIM USTIJFT GIT S YSTePS~DUR IT-it1077t*'	

       PG.JIK STnTltiVT"	    CUHrtENT MONTH

      l.D."':U-'-;:VE.~'<    16__       THL COiM,(l;,jy  i S ~E" VALUAT i.jl,  ALT Ek.MAT 1VE HuOCESSLS FC,5 S02 'EMISSION  CONTROL."
      iV.SU:  LLLCTr TC                             Ll^L^TOl-Jt  SCKUbUlfJo  IS THE KGST LIKLLY  PKOCLSS TO  BE SELECTED.  THE  FINAL
      vIK.?T51jSr"TfiirrirTTO~3                       LCLlSJCOK"~UTLL"riL~>!'J'f <-(;_    '                      ~      ------  	-  -          	-	-.--   	-
	STrtnlUf  _  r/l?_i	  	  _____                     _                   __

	I.C.  iM^t-cH    17	1-t.U SYSTEM IS  uOtaig  WllH  MO I fit- Ll;I Al F. PLANS  F-"OK KESTAHTlivG UtCAuSE i-PA
      i-iOSTuf. TOiKO:.'                              FUi-:i)il_ t'YSllr fvC  fc	    COi-.t'ArjY.   THL  uTiLITY IS  EVivLUj\T If<(, THL OftT,\  LOLLECTLD  uURI.-JG i HE OclNON-
        i?o   i**" -'^rfft'oFiT                 "" ""STKAfn>iJ"i'L"riiOij" to  otTtKMUvL  THL "COUKSL OF  PUTUKE  ACTION.
	UIL     ^. j |'r"!_Irly	                     __   	   _                      	   _
      Sff.n I'..;-    14/7,1:

     "I.L. 'ul.; ;.ijv ' "ifi "~      	              lh^' ui-OIT'  lS""f-jC)'*"u-jJjLK 'cUJgSTKUCTlON  A NO  IS SCHtUULtlO FOR  COMPLETION IN
	  Ct-MKf'L  i L L 1 -.. 0 IS _L i_b_H T__ C t.	.MA'1 CnPftClTY  IS HDQJ-1W,  BUT  FLuE  GAS HR_OH OMLY  IQQ MW	
    "T)'-.rC^" (.'^"("i A i <:.).!    '       '"""     "        W'iuL  LiL TKtiJT'Ei'D "lui'T I ALLY"."     "       "          	     "" '   "         	
	    1UU   f-',A  - -,:.,:
      C"
      <]
O
    	STAK^UP	3/7_o	

_    I.L.  l-l-:.!.(    19       _	bluS  hAVL  atlLN  TAKLN_ ON  LIKE  AMD LIMESTONE  SCKUbBEKS AND AKE  NOW  BEING
      C !.'-T'; A L  iLL'l.A. F.S "UMI'I'C" "liUhV       "    " LVAL'UAl CO .'  "" "	    "	"
 _   .,L*TO', ;:(. . 1                    _                                  _
        t--j-i   >..  -  r: v	"              	 	""   	  ' '  "	   "   	  "	"
	 C.I/H.  .?c-j. r'F. i\C_Ci -1 o t i L F L' K	         		
      :'!!  bt Li't I EC
_  __ Lii'-'E/Llf-f STl/-1 J  .SC'IoiiM'-JO     	
      STAtiTUI-' '   5/7?    "" "  	 ~           ""  ~	 "	  " ""	
            -             __   ^   *        _           ^___  ^__  __  ___,___^..*a _.  ^_^.*,^^www  ^^
      I.L'.  '.U'-Lff    ?u        "	~	         THL. CO,"'.PM.NY  is'PKESENTL'Y  ObiAiNi.Mb  co^siKUcTior* 'AND OPE Ajj  Fo_u  SYSTEM.	
     'ii/iS'T ":-L:'iTiVi."  i"	"
        L> ij u   ."  .<   " t. 'A
      COAL    0.'.'- >';.*   PLKCL';T'                         	"	*"" "
      f-.OT  SLLFCTfu     _       _
      NOT '           ""   "~
      STAKT'.JP

-------
                                                      TABLE. 2
        lMY                               STATUS U>  I-~GD  SY"Sft>|5>

  powti'i* 'STATIC^         .......                                ..... " ...... c'UHhLwf >idftifH     ..... ""       ..... "  " ............ "

 I.U.  NUi'-I.tlK   2~1                                  .........          ......... "  " "     ....... .......... ~
 C1N.CIKN/>T I __Q,\S  ANf) ELECTRIC ___________________________________________
 ivilAlVl ~FO~hr  NO H
   boo  i";w_- S.EW.   ______ _ ____ _ ____ _ _____
 COAL    3.^"~PE'.&
 ST/iRLUP _ 1/12. ________________________________________ ________________ . ____ ...... _____ ..... ___ ___

 I.Ll.  UUf-'.oEK   ??. ________  PLmlT  HAS  'JtU-J SHUT DU*f4 SIUCE SEPT  J9TH  BLCAUSf.  OF  A BOILLR  I 0 FAN NO-
 ClTY  OF  Kt.Y -tlsT                           1GK FAILURE.  THtY HOPL  TO  i)c OPERATIONAL THE  WEEK  OF OCTOBER  ^IST.  MCCH-
 KY  Wt.ST  POl-fH  f'Ltv/.J _____________________ AracAL rAlLUKES  IH THf. FCi^  SY-STC'1  itKL  FIXLJ.FGD  OPE'^S10:-,^ SCn.i->i;j&...___ ___________________    ....... ___ ...... ._   _____
 STAi..f.B   p3                          AS i-;ITh h,-,yUEU 1  ^ "2 HOIH LiMl-STOiML  A'  Sr^nO'  f-'O.)                        WI1n  A-I'|UM. yO  HEKCt.uI  EFf . UlLL  hf. Kt'GUlrtED  10  MELT THE 1^70 COLORADO
    H'JI.  .'.-, - ii. ...    __ ..... ____________________ __  i>0^ Lv'l^ilCn-l. ! CF '.  I'jOPP.'i.  i'.ilTH SLuOGL  OlSPOSAL IN A MIME SITE.
 ,/iOT  Sf.LLLTL'o ... .  __.. ______ . _____________ .......  ........ ____________
 Llt-'ilbTOIIt  SCRUCtJl'IU
 STAiUM.r ____ b//f! ____________ . ..... __________________ ..... .......  _________ . __ ____  _. ______ ..... _  ___     __
  - --- - -- -....-.._.... -- __________..__  __.._.-..__........__  ________ __.__....__...._-.__.  -.   .    _   -.^__,.  .^  _w_w.  
 .1.1!.  .,!.;, ., -.;<   n      ______________________ .....  flS viill. h/.YJE'i \  I S  bUTH LlKLSTOIJL  A'iU bOulUrl CAKOON.VTE  SYSTEMS Arffl ijEING
 f JLO.--.,-:'.:;  'Ti. iliCTnlC                    LVMLJ.iTLO.   USl/.-ti fl.E  AiiTIt.iPAtf.L.  U.45  PLKCLMT  SULFuK COAL AN  FbD  SYSTEM
 Ci-.-iK-  ST;;TIO: i.-C.,,  ..... ......... _____________ v.if-1  APHKOX. 70  Ht.hCt.Nl  EKF..WILL  bC RFUUIi( 'Cf .Hj;_^H_FuP ____ SL^'NL'  J>C(   2r'j                           CGLU.vAUU UTL Is  PKvjCLLJIUG  w!Tri L i%; G I f-; L f >. 1 lid  EVALUATION  OF oOTH LIMC-
 CvLt;.-./ir^  jr>_rLt.CThj(.__ ___ sjo--tu. _i;oi;_iu.s_c,v!
-------
                                                   l.AoLL  i
                                               ur  F'uL"SYSTcf"iS"bUKl.Mb  iU/7<4
"I.U. TjUi'ift.rt '  ?fa           "             CGi_OKAUU OIL  IS HI-UCLl" LiliMti  ,-. ITH LN& 1 i-^l T\ I ivo  EVALUATION  OF 1>OTH  LIMC-
 COLOrtAUO JTL LlCCTklC                   STo.Jc. & SODIUM CAKbCfAT L SYSTEMS. UblijO THL  PRESENT 0.<*b PERCENT
~H't\\ uLT: "*iC~;>	                       SULruii CUAL AVFbu  U.MT"w'lTrt" APMC*.  7"o PEnCE.i>il  c.FFy~'*GULD } "i\
_  2bo__  (-.  - RETROFIT	TO  -U;LT The; i9?a_coLCKAijO soa EMISSION KEGS  OF  isppfVi.  IT is
 COAL    OiHb P-RCLNT"SUi.FUR             PHuHrtHLE" THAT A "LI ;S:STOi\iE""SCRUdbEr<  vJlLL'bt CHOSt'N""wn ri  DISPOSAL""

           ~scr>UHbrMG                     	                    "~      "	               	


 1.0. r;lif:t,c.K   ?;7    	            U.o.P. IS PntSKWTLY  ^  THE  LNGIMELh i.'JG DLSIGh!  AUD PHOCUKtHEfJT STAGE.
 CJLJi'-'^LS 4" 't>i'in M fill", OHIO                "CONSTRUCT IO.'M  lS~ SChEDuLEO lu  START  :-1ACH 1975.	   "	"
J.yM-.'SVIl.Lt. ,,0 b

 CuAL	
            OR PHOn

            i/7'    "         "~	" '  "  "       "~	"

"i.L. 'f.'U,--oL'n "  ?i)  	                   ViOixK  Oij" UuIT  t^O.'b HAS bbL'N  ULLAYE.C  Fuk AbOUl A  YEAR,  CONSTRUCTION IS ;^0w
 LOLUFj-l'S ;% S.luTilCRlv OHIO	SC'iCUULEL. Tu  STfthT  JANUARY  197?.  U.4IT NOW ScHtOULEO  FOR COMPLETION IN

   37b   f.,.  - NLU	
 COAL ""	.-.-    -   -   -   - -    - .      -       	    -.-	           	   ^
            OR P"0;\uCT_S	



.1.0. fiUf.L.Lt)   ?9	hOu.JLL A WAS  UOWN 3  TIt-;|S LAST  hONTiU  Oi^Lc TO  CLEAN DEPOSITS FROM  THE.
 coMofjui/;'_TH"I'ui'smj"       "            "VEUTURI THROAT  AND  IUKC'DUL  TO BOILER RELA^O  THOUHLLS.  UCMISTER conoi-
 WILL. COU'.TY uO  1      	      	       Tlu.l  CjETL[UOR(VTEu SLIGHTLY  A^U  WILL  HAVE. TO  BL  HAND WASHED DURING  SCHEO-
   Ib7""f.^.  - L"51'OFl'f"                   UL-t_i,  Ul.iLR OUTAbt..   OP^nAliOf.  MOiT  Of THL 'iC.jTH 'AS  ^ITri A  ,vifL,Iu|u; SULFUR
 COAL 	0_.fj-o.y  l-'E.KLCl-1  SULFuR	CO,\L  liLHJ-Ju._  AVA1L<\;3_IH f Y AS ft5 PLuCEi-T.  fiUUuLL_B IS  STILL UOvJN,	
 t'At^CuC'*  (.  '.- It CO
 LIMLbTGf-L  SCi-.'Jr-t Ii'-ly	     _
 STARTUP    2/-12

 I.D. fTuMTjLR  ~3"o"  "                     "'LXHLIf-iLNTAL  WfT LI^L FUHWACE INJECTION SYblEM  WITH WO  TAIL  ENL  SCRUBBING
 sAiKYI.Aj_ii.  pfi',L\> _ctipjp	is  user,.  OUTSTANDING HKOBLEHS  ARC.  FL-KMACE TULE  PLUOGAGL WHICH  CJECESSI-_

    60   f:A  - ,.Zli;OilT               _    _ KErtJ'v'AL LFKiClEi'-iCY  "AS  FRO.-; 25  TO 4J  PLRCE'^T.   THE f-G J  SYSTEM OID  .MOT KL/N
                                           MOiNt:  TH/.N T.-.O DAYS  AT A Tlr;c.  AVAILABILITY  SIrjCE STARTUP NLVEh  EXCEEDED
                    _	      _ 25
 LIML INJLCTIO-I
 STARTUP    f,/7l

-------
              T/.-JLE
"sf';fus "OF" Fob
                                                                             /74
  POwL;'  STATlfni

 I.U.  MUf-MER    *1   	    "	        	IMSTALLAT lOiJ  OF 1 HE  HGU  SYS f El*  IS LSSLN TI ALLY COMPLETE.   A FAULTY iNSTRU-
 ()LT'!On_ L.._!	MLMT  I'A'-ILL  ..HIGH v^\J, 1 :--ER~  15 TH."
         ;-.v., -  ;-LV    ?*                          Fuu  oYjTL;-:  LUuSjiTS  Of  1  T/.0  STAGL  i\ljD J OijL STAGE VEi'jTURi SCKU'iBEr^S. '  AT
  ;:.r: it S.'   LM-:!	 r-hcSLM, y.'LY  FLUE <3AS  Fi-'O'-: tiOILERS  2.3 A-.D 4 (AoOUT HO-1*  OF THt. STATION
 , -ii:.i 1}-S " 	   "                 ~   Cia-ACITYJ" ,\r.L   I!-.' SLKVICE  dLCAUSC t-LY .^h fKCM INEFFICIENT ESP  S OVERLOA'JS
   slO  .-', -  ,.-LT'<0! i"i  _                   Tii;.  cLfiMK ii'RS.  OPLRAfl'-Ju hOL'Hii FOR MOuUL..S 1 THROUGH  H  bt.T/-  ?.ft ' f'i.r-tl.f-iT  bUi.FUfi	   Af-ij  0/30/74  lr.;LKE 17bfa 7o.',                          TC.L  t-Gl, i,YiTt'.r': nS i.)Lt..-J  uour.1  i>I;.AS UAiSAGEO bY  SOLIDS
    .-icj  ,. -  . TROT IT                      BUiLuUp ii<  THL GLAR  box.   KLPAIKS TO T(,t. CLARIFLER AS ^ELL AS  TO OTHER
 C!>iH.	ir_.^  iT '<(. f.}'l _S_^LUI'.	rtlivuii HRbliLt.i-'.S To  _1_HE SYSTLvi  ^ILL (jr. HAuE UUH1N6_THIS SHUTDOWN,  THE FGD_
V:;CH~"""	     " ""               SY-iTL.-:" Ii> i-.oh!-jit;G  "A'T HALF CAPACITY  (Si.'.Ci- i-iAKCn)  DUE TO" LOlr. HE'AT OEHAl'.'DS.


    -'"~'1--                   _    *                -. _    -.  _. _   wv. *-MW_WWMf.KVH.M>VWWMW_>w_ WWM.*V.*.W _   . v a.v . 
 I.U.  !)(.:: ;..r.(<    20           " ""            FIVE  HROPOS^LS FOR FGO  SYSli.r-,S  HAVE  BEElj RECEIVED AND A  DECISION WILL BE.

~HU'-U.~C~I TY  '. r.."$                           DEbJLr'uHi^ATio.'v' IS ALSO  BE~Ii';6
   e>'jO_  f .- -  r t ;
 Cf'i'
-------
                                            	TABLE. _2.	
                                             STATUS Of  Ft>U SYSTEMS  DURING  l'J/7t
      t'OrtL'K  Sl/,TJn;-i                                                   CURRENT  MONTH

     i'.rf.'TiuYiTLK"'~~i'f>                           THE" Viiu u7uT"HAS  s_!;> Mi	I?11- !::_-  i'ETrtCf IT_	MA JUr<_KLPAlRS CONSIST  OF K.li\iF OKCLnLMT  Of- THE STRUCTURAL STEEL SUPPORT
     COAL    2,'i-  3.? "p'i'hCLNTS.UI.KUR          TO THE!  HIGH  TEMPERATURE STAINLESS  STEEL OUCTlgOnK  AND fttPAlK  OF THE  ACIO
     SONS Ay "1.0 ..f.'-'VllU) Ci,iLM...SY_STLf-iS	COULER.. UAFFLES...... JHE _uNI_T IS  SCHtpULEO . Tp KLSTART  BY i\iOVEMoER_ 22...197H.
                            	

                            _. ...... * _ _ . .  __---  -.-  -  --- ^ - _._,___.^_  -.    ..              -             -    ^-  
     i.C.i. r:ur.,(_)<_   37	IWjI_AiJAPOLiS  POwLI< AfD_UIGl^r  HAS  f,LT WITH SOME! VEIVOOKS  IN AN  EFFOKT  TO
     l^LilA-V.l'(.L!s"''CA.'F.'< A^ui  LIGHT             OLilAiN  MORL "COMPLLTE BIDS.  "THLY" AKt" fiO^ "AWAITlfJG  REPLIES.
                  1-0 ._3	_..._____	...					 	
                 -  -iL'W
	LOf'.L	_3. l"-3_._fj_Pl^!_4,_ I 1GH!	bLR iSJ .  pUKIMG  UiJS  PLRIUIJ  THE  bUlLEtUi,  -  ,-(i.T:'<0! IT    _         	      UiMlTa  l.'EKL t:OWIi  DUKl:it THtl  SlKIht.   TH  F&U  UI-J i T  KflMAKTCD OCTOBER  1ST
 -o   C'AL    I .i,-  ,'.0 fTKCi  ~1  S'L-I Fo!<"~"        o:\,u iiAb btLi  i(;Oi5                                                               i
	ST."1/''.'.. W/7v:_...	;							  _			  	
     ^~  "   '  _       ^^^_   .    ,      ^^_.. ^_,   ..    ..  --  ^.^^  .  ^  -w  ^.,  *  *    ^**  ^  ^^-^  -"'  ^
 	  I.L-. :.Uf.r,t  i<    ^     _	  KCl'L hAU A L;\fiC/!<  S1HIKL AT  THE PL/iNT x'HICH LASTED  Fi<0f-'.  JUL t-,TH TILL  OCT
     * .,'.';,,  C 1 T Y' -JJi-f. r<' e. "LlMil ""  '""       "   "1ST. "  bUKI.Vti  THIS  PLKIoi; THE  UOILEKS '.Vf.KE OPEK/ifEO dY TM (.WAiM ' S   SU-
 _   n.'./rnor;  >  :-  u                     _         pui E l< / J L D  ;. IT H  A.r.UUT  BU PEKCENT " AVAlLAiilLl T Y"
       f-20   v.  -  ' ;.*                  _    _     LH;i'AJOK  OUTbTAKUli^ PRObLEMS.  iiOWLVE.K,  PHE-
     CuAL    b.^- r-fi-CE'iT SuLFUK  ""    ""   "    VE.-liVf. MAl^T EI-s/n'.CL. PRACTICE  KLuUlKLS  TM/lI ONE MODULE OE TAr^EfM COWW  Oi'JCE
     OAhCOCh A  *IlCOX          _             _A  ir.HEK  FOR 6  IIOUKS OF  LLEArtJkG A'^U WASHING OF SOLIDi bUILiJUi>,
     LlHe.STC:'it.  S'      	"	
                 b/73

-------
		    JAI.'LL  2
     "CO riP AT-Y    "                          STATl/i  O'i- Kii> SYSTtrli

      f-OivLli S'JaTK'l                              ~                     CUKiHtNT MONTH

~	 l.D. NUMBER """TENTATIVE AGREEMENT  HAS  UELlM  kL'ACHtO WITH CCKbUSTIO.vl ENGINEERING TO  DO
	 KANSAS PC/.VFK  ^ LIGHT	PKLLjn\INjuRY_Fj7jj_j;YST^^^^
    "OF FR.ivV  i.u.  V                             wouh," OU~T'HE Rib "sYsYLr-~~AKTOP	o/7_o	,	.	

 	  I.D. n\Jt-i>r.n    nZ	_TE.\iTATIVt AGREE.^Eix.T  HAS  BELN  KL,\CHEO WITH CUMhiUSTION ENGINEERING TO  DO
   ""KA.r'.sas'PiVEf-~A LIGHT""       "   "       HKL-LIIII^AKY FGD svsi Lr, "OESIG^ FOR  T^IS  UIVIT AS  PAKT  OF  THEIR CONTINUED
 _   Ji.'Ff:LHY  ;.").  ?	   W.UK11 9'^  TML FGU SYSTEM  rij_ THE LAWHf.'.'CE  PLANT_.
        7uo  ;-.'.  -Y.r.V   	"



   """SIAKTUP    f,/yj

     i.i... ,iUrr-!:H  ""43  	"	~  	      "L-OM i-'oi) rtOiie'-.ris',-ific  'i'^' OPLIUTION  xiTtt "ESSENTIALLY  100  PERCENT  AVAIL-'

     I ,i-.:i.;.u: '":o"~                             i-.LLr.s."~ >"A.-J^<-U' ci.V/jjijp""of:"~KL~rit".AtEK "coiL'Ts'Now  DUE'  AFTER

 Ui  C'jAu   o.r>  r-'i_>H i.'.'rt  Si/Li-Ui',
     Cf'!'.i)U.ST J .  E:ooIi:tC

	5j.rVvH.'P....j2/,'.					

	!.h. , V.',,>.:    (.4	  hCiLLK  t> M/.i  btf.X  uf'EKAT iftl'j Cr. C0,\!_  Sli/Ct OCFOuER l^TH.   POOR  GAS  DISTRI-.
    " K/-.f S.;'-: '..,.:.,-.  ^. LL.iiT  "          "       ;,.l/[Iw\i  ThiiOOGJi .(.H  U.'-c.  OF  THE 6 .^ojULLi  AS KELL AS  ,''iOiviG ThE  riOUJLh'S  IS
     L'.-.'u ..I'.i .i.i  ',                          __  ST^Lu A  Pr'Oui. ,';.   COf;uuS f Iu,-j  ENGINEER If'iG  MAS  COMPLETED  GAS DISTRIBUTION
        uOu  ''* -  :!                           IE^TS /jjo is  CU!'.;*E>TLY  ^OOIKYL-JG TP..?Y.STLh'^. jJjJt.Ji.All.OJGJ'ERIENCED  IN THE	
     '&'>  :i~o                      lJE.'Li"v.KY OF"sT"KULTun"AL""stEi;C.""" t'Of-JSTHUC TlON' stAHTED  A06uT"SEPTEMBER' 1ST
         o4  f i. -  KETM>riT              _.     rtNy COMPLET ICfl. IS  UUE lit MAHCH i97'j.      	     _.. ..  	  	 	
     f.OJiL   i..-)  t'fi'CL'-JT  SlllfuK

-------
                                                   JAOLt  if
                                            S"bV"^i"u"SYiiT

 f-0L'K  Sl.tTIcii               	            '"	"""	    	  "CUKKENT MONTH 	--

1.0. "f:Ur iiili'uti'                         A 'uOr:r'LI/Ujf ~ ,'j  \           ~                  niv t-'uu  M Si :.iv>.
  110   ::* -  KLlROfriT                                                                           .._...			  	
COM.	
NO I
L"lME
STAUTUP	S/JjO	
MVW____.._V..V_..4V______V..V_       ^^...   w^   """"-""^"^""^""""""'""^
j.n.  ; b::; t:iv    n't                         A tuhHLiANCt:  scnLuuLt  HAS BLCN subr-'jTT;o TO  THE JEFPLKSUN COUNTY AIR
Li'l'l.>V ! L.Lf.' o'.."> "i ' (.LLCTjJ'l'C" "	          POL-XuTloiv CONTKOu 'UlSTrcICT 'wlTH 6/6U "tISTAliLlSifLu AS  THE STAkTUH 'DATc FOK'"
C^.-vL  f.'i;.'  :;  ?                             Ai; >"i>0  SYS1CF-.    __
  107   ;-;; - 'rxii'Tft'OKii    ~               "          "" """          ~'	""  "     	 "       "	""
COAL    5.\->-  ii . 0  PEKCLIvT SUL^UK	
           j r	
           >niijG                   	           	
           1S/-.C  ~-                      --  -	    --  -- '-      	

I". D.  ;'uv:-:.'.  ',{>	A'C-Jf-iPLlANCtT'SCIiELiuLL" 'riS"b"-"t;W SUGMTTED ' TO  THE "JEFFLRSON COUNTY AIR POLL
          -: br.6 ; r.LLi.iiiic               UTIO,M  COI\TKOL UISTKICT iTn  &/ao tisTAiiLiSHED AS THE  STAKTUP  DATE FOR AN
          TaTT
           -  HLT0!-lT
         .ri-"<". o  Pf KCCF,
ICT  J>fl.t(.Trii        __   _      	
L1:VK  Sc'-L1 u-.iViu         "~" "   	
STf.iUL.f-1 	^-/J-^		

I.D.  i.uNt-r.ry    u9                         LOUISVILLE &AS  AIJD ELLCTKIC  HAS JUST  RECEIVED A CERTIFICATE  OF CONVEM-
LOaiS\/IlU: GflS I'fLECTUIC"	Ei-JuC'FF^Oh THE PUBLIC  SLRVIttl  COMMISSION" TO CONSTRUCT THE tlOlLER.   APPHO.
CA'a  tU.'. .-^  u                             VAL  OF  TH. COMPLIANCE  SCHEDULE FOU  THE  INSTALLATION  OF THE FGD SYSTEM  IS
  1 7tf  ' , -  i:LTr.''i>'<'i(v- ""nff."Vil"rr.;';                                                  "
LK-L  SCriT "FOR "CONSTRUCTION OF "THE "FGD' SYSTEM "WAS DISAPPROVED  BY THE KEN-
LOUISVILLL l.-AS ^ f.LLCTKlLTUCKY  PUBLIC  SERVICE  CUHrtlSSION.  HOWEVER.  THE ISSUE HAS NOT BLEN  FINALLY

                  Gi-iT
CUAL  "  O. T;-w.Lib"        ''       " "     "
r;or  SELLCTCU
LIME YCHLbLUufr
STAHTUH   fc-/7b

-------
                                                   TAEJLi-  2
                                                                      _
 ~Cb"iVP/U~Y  '                          '  sTA"fuS"oF~ FCu  SYSTEMS  jUKII-.t.   iu/7<
      R  SATION          .                                       CURRENT  NONUI
                 51                         A  r-dKMlT >OR COSTRUCTION  uF  TuL FfcO SYSTEM  WAS DlSAI-PROVEU  BY TnE
                                            Yciy..Hut-.Lic_.stLCt>T  SU
"Tjof'SLLEl.TEU
 Ll^f. SCr'L',(r Jr-ft   .........
 I.L.  > U.' , T.r< ..... 53 .....        .......... " ""   A  COi-iPLlANCt: SCMt-GuLt HAS  lidEt-i SUbl'iiTTEiO TO  THC OEFFLHSON COUNTY AIR  POLL-
 LUOISVlLir G/,S  S. ..FLL_LT_M_IC _ UT10,-j CO^TKuL, ulbTKlCT wjjjj fe/7a__tSTABL ISHLD flS THE ..SjARTJJP  DATE FOR  ftN
 MILL "CHELK iiO  ?     -    -                p^ gYSTtK.

   33C   r/. ..- ..kd'ThOJ: IT _____________________________ ....... __  ____________________ .......... __   _____ .....
 COAL    ;s.o- q.C fi.KCt.tjT ibLFU'<
 fiOT StLLClEL  .  _____  ______       . ..... _  ..    . ______________ _ ... 
 LI H;_  SCr.,..:;;,i;-,:.
 1.0.  ?JU'-..tt_' ___ bt _    _ _ _ ______ CUi-jTKACT  wAS /UAKUED To  AMLKICAh  AlK FlLTEK.   SYSTEM WILL  OPERATE  CLOSED
 LOLlSVILLd u'fkS  i' H.LC'ihlC"   "     "     LOoi'" 01-, WAiLK AfJD  SLUUbE  WILL UE  ST A
 MILL  CHtLK l-id  3
   ^b   ... - HdT^o'm
      __ j . '->- u_. o ,r'r^C[ "T  SULFUR
      ICiAi ;>Ii< ML I CM
 I.U.  jL.;-.:.-EH""5i     ...........             A  Lr)>,f'LlAfjCE "'SCHEDULE. HAS  HEEN SUbMITTED  TO  THL JEFFERSON" COUNTY AIR  POLL
 L 0 L' I !a V I L I . j. uAb J. J^LL C T K j L ___ UT10:>I CONTKOL OlSlHICT V.I_TH &/79 _AS  JHE_STARTuP DATE FOK  AN  FGD SYSEM.
 "'"   '''   '                               "~                   "      ...... "           '   "
                               _
 COAL    3.i>- t+.O  PLKLcl:T  SULFui<
 IJC)T SfLt'CTEn
 STARTUP   fe/79

-------
                                                   TBLL~  2
                                       STffTUS''OF~TCVO' SYSTlT-iS "SiOFiTwG"" I077V
  POKE" 57. \TIoD   ----------- ..... -------------- ................ "  ~    CURREwT f-,OWTli
'I. P. <'l.',"in.t( ----- So ------------------- F-'GO'SYSTL.N OPERATING  SAT ISf- ACTuF-'uO"PCRc.E1vr"SlJGnDR ----- TriT rXrSri.VG' ROTtt^Y' VACuoil FILTERS' A'lTH~iVO fiLIfVOlrtG^CF'FiLTcIR CLOTH." '
 L i
 STAKTOP    4/73
 1.0. .H.'^-uP   ^7                         h'tu  SYSTLi-1 UNDcR CONS! KUCT 10M  *1TH HO MAJOR DELAYS.   ANTICIPATE COMPLET-
'.xo ;T/.:;A" p;^r;r                           i^G'  COKST RUCTION "Of; SCFIEDULCT
 COLSTP.Jr' .if. 1    ____  _________   _    _____ _ ________________
   ObC)   vh - "f.i-.^"    ..... "      - - -                         -     .   _   _                 _
         ('.{' f-'c1 i^CL.'JT SLLFI'K
 C'0r j-iuST ! uMTT.'J f PT~7TS?OtTA~rS
 I.r. :io;,:-::rt "  '!>: ......                "~" "F-SJ" SYSTth" Ur-;CCir"COijSTrrLrc.'Efi _  _
 .'*h"\ bCLtC.TFU
 STAKTUt;    0/79

-------
    	   TABLL 2
  C'C^'PATY                               STATUS UH""Fob  SYSTh>;S

 "POWL'K" STATION""	~"	CURME.NT'  MONTH

 I.b.  liUr.i-LK 	61                           FGu  JYSfL,'! PL'KHOKKMICL IS SATISFACTORY Will) MO  OUTSTANDING  MECHANICAL  OH
 'jrfLyADjL lJl'.iJf:j<	?KUCL>S PKUoLE'VS 1U  HtPutU,   HOiwlVl '<,  THE.  PLA^l. IS. LXHEn I LUC I';'O  /,'<< If" ACE.-..
 Vs/ib" <.-A';i>,t K ;;c  i            "             UUHTL but'FLY or  TKOKA tsouiuf'. CA^IJO^ATE. ot /.HICH KLSULTL.L)  IN FKLUJEMT
   12t> .'*_- i-'ETKOFJ T	IMt_i IN  1>L  OPLKATiO.Ni Of  1 hC  FG(j SYSTEM,   NtVAcA PCViER IS  SUIf-iG
 CCAI.  "'o.ij-~l .0~ Pt'.HCLivT b'Jl FUk   "      THt.  i,lJPPLIc.i< FOK bKL'ACH OF  COfgnflT ISF AC-1 OKLY lITH !-JU  OUTS7/\NOINo  KL'
'"[ V;-,LiA t-'C-^ri."       "  	   PKCCi.-.bS H'OMLE'-.o TU  K:.Pu:U.   Hi;.-I-V'"L J-^'-^LY of  I;;O:IA (b^jiuc- c,i!i/PP.LIE1K FOK HKr.ACji uF  COMkACT AC40 ALSQ_JS  KRLbfcNTLY  TLsTlMGL _SO_DIUPI
 coi'-'fiusTib.i~f:r,uip. rtSM-ciAitS            CAKGONATE"CU'!u;  ,,-.".i\    6i
 :v(, V /(f.A. (."i' ; H	FG0  SYSTt^i ISUt-DLH ..CONSTRUCT IUii,
 'KL u  or,<,,.;; f< .0  3
    I'f.^-  >-.-<  - KuTKOK 11    _ 	 	_..	 .				    _._   ..   _	_ ..,	__
 COAL    0.;>- 1.0  PI. rtCt. UT 5ULl-Ul?
 CO/-:)US.TH,;, t'^'il'.. /\S!?Oc.lA,Tf.S		_		 _._..	_	
 SOC'-IUf: C;.! O-.-.-.Tt  SLKUl uliMG
 b"l .".1'TiM'	r,/_y j	

 1.0.  t;l'f|.:.>;    r'  _           	la.VAjA PUViEK COMPANY HAS  SIOt.EO  A LETTLH Of INTENT n IT H CO^HUSTION ECJU1P-
"        ^ov.rx         	        "~        nc^r ASSOCIATLS FOK  Tut coKbTKucTiou  ue AU FGU  SYSTEM  OH RLID ^AHDIMEH  NO.
         ,l.;jt.i! 'iO 4                  	   >*.   rnio  UI/IT  is SCHEDULED  FOP<  COHPLLTIOW. ifj iy?6.
         i-.-  - ,.<-,j                                 ....                            .	     ....
 C'/AI.	Li-'.)- J . f.  _Hr .'..CI.i^^S-.LaFlJn.	
 Cl/;iM'.CI Al L^
 SCi'.UII- C,.-<..-..ATE  SCKuerli;^	
 S I AK I IJK     fe/7-

 I.D.  iH!:'hlH    bl>       	             UKlVLHSAL  OIL HKODbCTS IS CO!-jDUCT IUG  PKELIMlNnKY DESIGN wOkK Or,  A  QHY  FGO
 MLW_C.r C-LA':r- H.fC_SXS_T_Ej!.	UMT_W1TH  SULFUR HtCOVi-KY.    MCIEJOrj_TO__bE_ MA_DL_AROUivp_f;,0_V_ 1 WHETHER TO	
 iiKivY rd'i  torn "?:o'. i   "   "           "     s'u.";-i AN  trJoiNu'tniv^u  CO.TKACT".
    f-bo  -.,   - \LT;
-------
                                                            TAbLEl  2                       	
       C07TF7.K7	STTTTDS"UF~GG~'SYSTL>TS~unR71J5~' i0/75

      'FOV.TR  STi-.Tfir-'J	"                    ' "	~" "  '	CUkRLuT  fiONTil

      f.C'.  r;i-I"C; Uv;I7.
      :;GK1,uM.  I.MJii-.  -  l.'LrhOFjT	4^1	             	      _
      C'GM. '6"PL'KCt.iTr'SuCFTJIT"             "      '  ""     ""       "          	               ""	"'
      HOT bf LLLTtt'i _ _	    ___  	   _      	
            U'CTF.l'  "  ""   '                         ""    "~'~   "'          " '"' "" '  ~	   ""        ~"
              -    U/_0		    	
      .       .*.  _.._  .,  _  fc,  *.   *.._.n<-~ *. _     .>>  .__..  ^^_   __^  _^_                
      1.0.  (ilM',u":i    67                          COl.SiOLuIiVG A LI fit. OK  LlMEblONC  SC.^OBljI^G UNIT.
	XOPTI.ER.-:  I.Mi'iAfM TuLTSfRTIce	ALiU'WAITING' FOR  CLRFOR.'lAXCt. OF  UtLUMAf-i  LORC.  UNIT
      tjAlLY NO.,,                                 ONutK  c^NiSTKUcT 1 OK A^T^Tj-lt-IH  DH. MITCMLLL NO.11
        (^jij  -^^                                                 "	            "   "	"
	C^AL  ^  'll_l
     VjT"i,E'L"rC"f'
    _.\'.)1 Sr.LLCt
      M>.i:/..  -  nCIrifjFjT	
00  " CuAL  '  ^.^-"i';'b'>ui--'C[TV""SULFUK  "    ""  """	  ""	-"     ---.
    OAVY  rtii-L'n-AK    __	
    "             '!'"""
                  e-ATj^	

      I.O.  tlJ'V.U*    (?	 Kfcij bYsTLX  UUULH  COMsT'"f(iw"Li'.:                    SCivUu-jfll^S .vLRL  f'L;.CHG  1,,  EA^t-V  19 7j..  iXCCtWT  SCi;L ELtC'iUCAL
      C'^.L    J.ij > ? >'Ci.:;T__Suf. FUH		..    _	
     "CO.v."r~iii,'T I'U.TL":",", !:"!?>. ii'sC"                       ""    "       "            "" "	"      	
      Lnvf.STCft.  SC^'JbbliL-	
      STAHTtJP    _/7o	        	"   	"	"	"
         ~*+  ~~   f ~  *.   ~~  ^~ ~ff.^  ^ ~~ ^.^^^~~^~~.^^~.~  ~~~^M.~   ^~~m.m.^^~m.^~~*,^.m.~~^~.^ ~    ~ ~<~  im  ~~  ~, 
      1.0.  IU"i  L>?    '711'"'"                      f-u^' JYSTLi*.  uWCE:<  CO.'ib TnL/CT lOfC wITn  ,jO |--AuCi<  DLLAYS.
      .v.iiTAJ[l_SJ\V,.Lj<	SCuUriiit-lS Lt\L  PL;,Ct'U  Iu  E^I^LY  iy?i.  KECLiviT  SCHUuBtk  bESIGiJ  CHAIvGES  HAVE_
      'S.^i.ki-'C^i'-"''; i!  ^> "   ~"                      ~CAJs't-"d"c.LUlPi'i'Eiv.T ~L,Li.IVL::
-------
      	
  COMPANY                               STATUS  OF"FGU""sfs'l LMS DURIiVs  l~6/7<

  POv.LH  ST,VT"i"f,v.i'                         ~~	     	CUKKLNT C-IOMTH

~I .[). ' ?iL'f:<:E.f>	71  	                    FGo i.YSrtM UNDER  CGf jSTrtUCT i ON ,  bUTENCOUNTERING SIX  MONTH  UELAY  IN STRUC-"
 P{ 'JJ'SJLV /;<)! n  PDWEK _CQ.	iy*'>LJ2TLE^ A.^^^v-s%yr_'^.^iJL!=iil_'	
 biuJCE V.i'rsFirLp MC.  i                      """"   """	"
   p.^O   M,. - 'jLv.	     _     	                 	    _          __....       	
 COAL"   4.J PEKCENT  SULFUK            "                 	         	"""            '   	"
 CHCiMcO	.	_	  . 	 ..._
 LIME scKiiHtut'G
            P./.7.5	_	___	

  ,U. .':Uy.'EK    72	 FGu_SYS_TLM uNDL'R  CONSTRUCTION:,  uUT _L'fJCOUNTtIiV(i SIX  MOf-jTH  DLLAY  IN STRUC-
  t NvIblLV.'.-''I;, "i'tiWEN  Cc.~        ~     ""  ""VUftAL STLL" ANiQ  VLSSLL  OELIVEKY.
          rSFlfLO "'0.  ?	        .	...  _	-.._
         iy. - ,Vc*	"	  ~  "    "		"'
 COAL	4 .3 F'F.iiCEINT  SULFUK	
 ciicraco
 LIML SCHOtlAfilL  UEfJTUKI  SLKUdbLH  FOK S02  KLMOVAL) .   TIE IN  OF MODULES TO  THC
 Ef.oYsicitJt.t-ti  i             	   	bOiLLK n,vs ST,-\I AND  is  DOL  FOR COMPLKTIOW  &i OLCEK^LK  isr.   THL' SYSTEM
   320   ,v,,; - -)LTHOr;f"""	 ~      ~	WILL bt. Tt'STL'O iiTH WATEi^  FOS  PART 1CULA TL  KLMOVAL  ANO UtBUGliIiiiG  CUI.  PQi-.^	U.A [Eh_ { .OLLC.UE.O. B Y_ A_Sf.COUD. y EN FUK I STA.G....FUK  SQ2. SCHUBf" I.NG_ 
-------
                                                    TABLE  2
    wLH  STATION
 STATUS  OF FGU  SYSTEMS UUHIkb

	      ""                CUKKLNT f-.Of.iTn

     UlMlf""MOr2  SHOULD  "f>L "COMPLETED  BY
           il.^J^t-Tjr  if-/_Ob1nIiMfv3 COyJ
            U'UIT" 'CAPACITY  is"bsVi-Vr.-".""
                 76
                                                                                          1975 .   UTILITY IS EXPERIENCING
                                                                                                            CHMlCALS_. __
                                                                                                            " .....
       i  r-iu. 2
   650   |X -
"COAL ""  .":>" 'K:!JT~
 NOT_SELEC.TEO ___  _
"                 ~
                    _
         '-1E.STO>;L" SCHOBfa'lNG
 STARTUP   5/75
 I.C.  fiUr-:;,LH   _J7 ____ _
"/'UcfLIC" St^Vlc'E "OF17E17" MEXICO
                                            KGu  HKOJLCT  IS PKCCtLOlNG ACCORDING TO  PLAN UlTH NO  MAJOR PROBLEMS.
                                            L'aun-.1c.fv,f "is'PKESLiiTLY  atlkt," FrfCCUKED. "' CO'NSTKijCTIGrt TO BEGIN IN AUGUST
   37-   rC"
_C.O AL _ 0_. n
 DAVY POXI.'U
                    r  SULFUH
                _
           it/77"
                 7'3
                                                 CKOJLCT  Ib PrtuCL'LOIKo ACCCLINO TO
                     rtv. ? LXIO
                                                                                               WITH NO  MAJOR
                                                                                                         rO QE_GlN I_N AUGUST
 SJM JUA;.; i.n  ?
	340 _  ,">. - .n,_k.JKOL 1.1
 COAL"  ~  o.jVVn -
                 .;T SU.LFl.jH
 :-"JT  iri.
 SI ;i< '. r1
"I.C. '"'ii. >.;.''. I'  ""p"o
 ^UHLlC ?i^
-------
__     __  __ _________       _  TAtSLE  2                     _  _______   _     ___
      "euf'if'VuY"  ~"             '  "          i 7 AT US "OF Hli ' 'SYS7 fc>ii>" tiUKlNii"  10774" .....

      l'0'.vt_l< SI AT ION                             ""   .........     CUKKEivT  MONTH  '      " ......... __.-....
     -  ^-  ^      - ^  ^   ----   -*.  ^  ^-^  -^^^-   ---  ^.-   *.  ^*,tww*.-  ^^w,^.^*.^fc  ^^^*^^*
     r.D.  UUhiU.H   "si             .....         Vi,i.)UK  NOT SEtCCICU,   blUS  ARE  OUt  IN  OCTOBER  7<4,   THE STATION CAPACITY  IS
_ s._ CACCLMft  POM srpv AUTHORITY _ 2uu_  .'u. _ ALTEKI-JATJIVE  oios_jiA_yE_^iEj:i\i_ RE&ULSTED  FOH THE TOTAL  aao m CAPAC-
     GEOf<"OETPf-rij|' 2                           ITY'TNtl A i~. 9S ~SULFUh ~COAU.
__   mu  .vw  -  t.-Eu ___      _   __  ______    _     _  ___ _        _                     _  _             ....  ... ___ ____
     CUAU   i.u  pt-.hCFiJT SULFUK"
_____ NOT  sn.fcrf.fi ......... ........ ________________ ____________ ...... ._ ..... ..  _______  ..  __  _____________ ......   ......... _________ ........ _..
     L 1 ML /L I f--t -STur, E SCMibfi I i-'.G
___ STAHPJE-    5/77 _________________________
        ^^._  ___^  ____   __  _^_  _^   fc  ^  __  w_to  _  _   ,fc___      _^^^ ^.^ ^_  fc  ___^^^    wwww-.  ,,_ w  w^  ^^...^^^ ^^ ^^^.^^.^^^ ^ .,
 __ I. P.  r4U/,i..i:fi_  82 _____ AWAITING TEST KJ.SUt.TS OlSt  HOKIZOwTAj. AND  VLRTICAv, _SCRUBBING_SYSTE_MS_AT
     SALT  tuvL-T PROJECT         '             "MOMAVE.  coMfR'ACi~'wiLil' E  AWAKDED 6/1/75. """ ...........   ~ ....... " ..... ~ "
____ CiAVAjO kO  i    ________________ _________________________ ..  ____     ...... ____ ..... _ ..... ..... . .......... ______ ..._ .....  _  ..... ______
       7-j(j
__ C.)  '-.v. -  >
Co   C*'"''t    0..;-  (. . n
^ ...,f'i>T. Sr.Li.LT;'^
            l'vt STliirh
           nVn  Iti PKOGHESS  AT  IHE fiohAVt"  ST AT'lQN,
       6'tl;  iv-^  - .nL7R.PF.lT  ______   _     ______________ _______________________   ______ ....... __ .....      ._            _    __  _        __
     COAL    0.5-  n.fl P.KCL>\.T  Sui_FUR                  ~              ........... ~~ ....... ""   ""    .....
     MOT .Sr.LEL.TFl.  .  ____ ..  _                      ________                           _
                                                              ""   '   "    ...... """  "               ""
     STARTUP    f./V?

-------
              	  	           TAbLE  2
      CCrlPV.h.'Y         ""                   ST
      1 iU. '< riuVt -tl'l<   *V .....                ~     THt 'iTGi\L  i>LKOHMl!':0
      I.i;.   .U't.fHv    07                          THL  TEST l'. !;::1L\- '  J. 1 / 7 i
      i.e.. ' MI>!',.U? " " Vd ......       ......           THL  TOTAL' CAPACITY  OF buitLn is  auo *<>.  LXISTING EXPELMKLNTAL KGO
      SOuTMLPi!  CALlFOKf^lA CDlSOfi              WIuL  TRL'AT  ONLY  IbO MW.   Fli\,Al- SELECTION OF  THE PROCESS IS  PENUlNG  THE
~  SCTJ/WE'FF"? ----- OD7clIl^L''^"ntf5>T~7liJuS'1iurnti;~ PR6&r I-SSiSSiPK-rPMrc'GTjP          bUrCJi  e> McuOtiNLL L , ' IS PKLStUTL Y  PhtlPA^ I ^G SPECIFICATIONS FOR  BIDS
            <,;,L-ij
     "COAL  "
      NOT St
      STARTUP    f-/79

-------
                                                               i!
                                                      t'-OC  iYSl

                                                                      C'JKKLwT  r.Oi'.'Th

 J.L).  rjUH,LI>    91   	'"	        	""PLu'MT IS UNULK  CUUST i	._	_...__	

 l.U.  flb^tt-K    <;2    _	      _     1HL  riOlLl-K IS UMULK COf,STHuCT lOf-J.    INSTALLATION  OF FbU SYSTEM  WILL  SI AKT
"SPCII-.C-FULUUriLiTY  "IT  .HKOCoKEWtfiT SlAtiL...    	  . .. ..  	  ..	
   200  f .v  - r-L'.v;
 CCflL    		
 u'p..IVH'.Si;'L'"C'TL~PlU...;UcTS
 Liiv.r.S'Of%F.  ^L-"ir.c;I.':y     .  .   ._.. 	   _.    .,   .    	 ....          	      .  		
             b/7o  	  	      	   -    -      	-

 l.U.  f-Ut'-c't-M    93    	         	ThXb  IS  Ail LXPLR1HLUTAL  SY5TE.K >UNOLO BY  USfclPA.  THE.KL At THRCL TYHLS
 Tr.f:'JLi^E._L_ V/.I.Lf T_/.UTjjC'f'n_V_	OF SLKbtJuLrtS  f 10 j-;,. .y.V'iy.A'-j-.^l-.r A.CHJ_ "riL.1J^A_^A^.^ATLy_U.kjjLR___&...VAi(.LUi.Y .AUl:,
 Ll^L/l. I vc.HTu -a  Sf.niut;.4


 1.1-.  .  Ur., t.t<    V4             _ _          f.LL  ,:AJOK  f->HOCLSii  LCUlrr.L^I  HAS BCE;;!  I'UKCH;,SEU.    IN-LINE
 TL^r.LV^'V.f.  v'i.iLi*Y" ,->"i I K'r.'li 'if'"        '     AKJ  JlhuCT ULAT   iYbTtM  IS  Iu DLSIuN STftiiL.
 A It .y/.i C ; :.'L' '  '"?  >'	 _. 	  .   ._			    . .  -
   t=hO   ...  - -X T.'U')r IT
 CnAL	.^tj_ r_;L'Ct.-1! 1	SULf_\.\t-.
             V/il  Lf Y~Au"Tt-UHlTY
             SCi^'toI'iO   __         .				 ...  	.             	
             1/77

 I .0.  MLV | Lrt    'J-J
 Tr_X/,S J.'T iwlTij.bL	.	.
 rt,\rTPi L/KK :-j.  I                          r\iL  bYSTt;,":, LHtlCI llvG UOILEK.  CONTRACT FOK  FGU  SYSTLh AhARuLD.
   7 . .'-,..- ;,ti%  	  		  			 . ._.	  _   ...      _	  	......
 COAL    U.'* |'f 
-------
               	          2	
       CUHPANY                              STATUS OF  FGti SYSTEMS  DUMMi

       POwtK  SlAT"lC)ij~	                  .-          	-	 cUKrtEi'JT  MONTH

      I.ii.  liuf'i7t_k ~~"SC>
     JCX/VS V]_lL n_B-___	
     "M'nhTIiT'L/.hL  i.O.g"                         Ivtrf oYSTEM,"ERECT ING BOILER.  CONlkACT  FOK FGU SYSTEM AWARDED
        7^3   !'*_- J;F-W			
      COAL  U.UH  H.:/  -  i\L:l-." "         "            """"   "         "    ~"~'  '	'
      COAL  n.Hu  PLi^crNT  SULFUR	





      hA'k'Tlfi T/-.r,l. "i 0.""4                          (."L'y "laYSTLTlTTTkLt'i n7G~bUrLERT""COf7iPANY~liS"OUf"Fo"R^lDS~oTi~FGTr~SYSTEM.
        791   ij'i.  -  f.tU-		
^    COAL  O."iq  f'L.JCrrJT  oULFUK
      KLS!T/;HCH COTIH^LL
      L l%i'.i> lOiii,  StKUhi^l'sG
 	_5.l'u<'_?-l...._iVwal^*B.__VBk_Mv^M..B.W
 	I.C..  Mihi i      '^9	  _ IIWiTl lOfi  rOK  biUS ON  FGO SYSTEM I'AVE  bEiv  SENT OUT  rtNU  SOE
     "TF./nS OtiLiTlES       	      '  "	hAVf. bLLb KLCL 1VLD." "1 MC'Cu.-iHANY  "IS' PHCtJLfjTLY'  STUOYlfMG AND
 	HOmiCHLO 1.0 3    _     	   _  	  _  	THtlSE  PROPOSALS.   _  _    __	

 	COAL    o.,;-  i.o  pfHci"T  suo'u.n
      >T6'f"""
 	  L) ?.
      STARfuP

-------
     	__^	
PEHFORMAfvCt" SUMMARY  FOrt OPLKAt'10I\lAL FbU SYSTtffiS"10/7<+
                 NO.      17
 UTILITY  M
                                        EQISON
 UfJlT  tJAMC
 UMI T  LOCATION
                                 L V LK L T T  h ASS AC rilli>L T TS

                                  150 fiw	   	
 FUEL  CHARACTERISTICS  OIL    2.5  PERCENT SULFUR
 PIIOCLSS
	NEW_OR_RrROFIT

	sT A ij j_ UP . OATE

	F6D STATUS	
         _L'LU.Clf.'vC.y...	
          f'AKUcULftTES"
  S02
                                          h.  OXIPtL
                         RLTROFIT
                         bU PERCtl^T
                                 90 PERCENT
 WATLr!  'VKL UP
 SLUUOr. DlSPOSflL
       cosr
 OPEH/.TICMAL
   EXPLKIEMCF
                                                    MLS/KIH OP
FGu SYbTLJI  IS  UO>N__WIT_H M0_
                                                                             S FOK  REbTAKT ING_13ECAUSE_EPA_
                                 FU.\L)lI-o  KAS EXPIKEL,  AUU THE CALCIMNG >'LAt\iT  IS  .MOW btlUG USED  BY ANOTHER
                                _CO'vif A^.L?	TH.E- uLiLiiY__is_Evy\LUATi'v'G TH. DATA^ COLLLCTEU DURING  THE DLMOM-
                                 STRATIOf-J  PER'lOi; TO ULTEKMIigE THE  COURSt: OF FUTURE ACTION. "	"

-------
      	TABLE  6	
       PERFOH.1Ar.iCE SUMMARY f-OR  OPt-KATIOfviAL FbD  SYSTEMS
                       ,'-!  N'O.
                          22
        UTILITY MAME
                         CITY OK KEY
        UNIT
                         KEY WEST  POWER PLANT
UNIT  LOCATION
                                 KEY WEST  FLORIDA
                                   67
FUEL  CHARACTERISTICS   oIL	2. H  PERCENT  SULFUR

FGD
                                    iM AlH  SYSTEMS
        NEW  CK K'i. TPOFIT
        FGb  STATUS
00
00
        EFf-!(.IENC_Y,
        "        '
                    "UP
                                  RATE ESTIMATED 100  GPKi "~
        UNIT  COST
                          _
                         1 jr<
                                J.'l|r_Aj_i_l_hMA  iii^Ei;  SHUT liOxh  Sl_M(.L SEP1  ly'hi  BECAUSL  OF  A BOlLLH  I 0 FAN  MO-
                                      "" ~" r'uL'Y" 'n"o>'c"~TO P-'t- "OPLKftT'l OK/'.L" "T fit. '"ELK"bH UC"Tl;aCR" "slVf . " 'MLc'S-
                                                 o  iU Tf-E F&D SYbTLN  fcLKE' HXLC.FcD  OPLhAILD  ABOUT A  WEEK
                                     A" HAlf UtFO-  THL FiiESEWl BCILLK ShUlCOW^.  UUHIN'G SHb J DOWN THE  EX-
                                _P_Aijt510t\j_ jOliuTS  O.M  THE DUCT^.OKts JO  THE SCRC'tibEK WEKE  REPLACED  FOR THE  2Np_
                                 Tii-iLl"  SOHE VLiJGblijG KEnOVEU AT  SltbTDOUig.     .....  " ""  "     ....... ..... ""

-------
                    TABLE  3	
             SUMMARY FOR  OPERATIONAL F-'GO SYSTEMS  10/7"t
_ID E ;f T I. F lA_Tl Or^_NO_.	_2 S_	

 UTILITY J;AME	COMMONWEALTH EUISON
                        _ W_I L L _C QU WT Y_N_0_ 1
 UMT LOCATIOM
                          ID? r--w
 FULL CHA^ACTDUSTICS   COAL    O.b-3.0 PERCENT SULFUR
f-GCJ V'CNLiOR
PHOCLS5-.
};& C;< f-ETT-OFIT
START UP DATE
FGD STATUS
ErFlLlf.f-.CY.
oo (Vt;n ico: ATES
VO ' ll.V.w'41 C.O
SO?
BABCOCK X ^ILCOX
Ll^'iuSTuML SCKUtiBlNG
kUKuFU
2/72
Of-ERAT10|.;AL

9fc PLHCLKT
7t/-oO PEKCt^T-AViRAGL
WATLi-,
             UP
o t-AL/LD  KOLL S02
 SLUUGt.  DISPOSAL
                                     SLO'jGE  DISPOSCC  l?-i  CLAY LIt-jLD
                                                      OP
                                                           lL':gJt.f* _OUCF. TO CLE/ii;  ULPOSIFS  FKUh THE
                                                           biULLi<~ KLLTL/ ThO'JbLLii.
                         Vf ;tid  ihnuAT A(.U  tvIC
                        ..T.iUi\ ..CETI.KIOKATLu) SLIGHTLY  MU  WILL HAvL  TO bt. HANU  CASHED DURll-,^ SCHED-
                        "llLLO""o"clLLK "OurAGC.  "DHLKATIO^  MOST OF  THE MONTH WAS WITH A  MEDIUM SULFUR
                        ..C_9.AL_.lJLEM3. ____ A.yAl_L/jBl_LIJ.L_wAS_.65 PEKCEfMr .__ MODULE  B  IS_STILL_ DOWN.    _  _

-------
PLKKOKMAf.cL SUMMARY FOK OPLHATIGhAL  Ki>U SYSTEMS   10/71*
 inCM irlcATIOMi-U''Kt UP
     L'Gt. i. lil'JOS/,L
 UfllT  COST
 ORE*.'. T I()f:AL
~TxTrL ~if.i..CE
                            .L_hlrth  '>c-! L1I!ii  FuRfg?CE: _lf)Jt:c~not>l SY?Tt:!!! ^ITI) N9  TA.IL ENt?  SCRUBBING
                         "Ti"uaLu'.  uuts'l Ai<0i.'lfa~ pii UjQ U/tYS AT  A TiHE.   AVAlLA8iLlTY  Sl^CE STARTUP NCVER_ EXCEEDEO__
                          ?5~PLKCtf%T.   ""         "      "     """	  "~"                  	

-------
      ilAnct  SLMC.AHY FUK  UPLKAllUUflL  FJO SYSTEMS   1C/7H
 IDENTIFICATION NO.	33.	

 UTILITY N-AHE	pbQULSNE LIGHT
 Ut.qj
PHlLLIPS
_ut:.I T_..kQCAJ_lQJi.

 UNIT HAT TUG
SOUlh  HEIGHT Pc.NI-.iSYL.VAN_lA_
 FUEL CHARACTtUlSTlCS	COAL	1.0-  2.6 HERCENT  SULFUK

 0 J/LI>i(.Lg5	CM.-.

 PKCCL.SS	Ll>it:
_!! W-iiL RL_TJ? 9.FJJ	H CJ K pf_l_T

                          7/.T3

                         (,P[.;E VEIJfURI  SCRUBbLRS.   AT
  E.XPLKH riCC
PfUSt.MT. ONLY  f-LUc GAS KKOM  bOILLRS 2ii  ANU u  b/.^0./7H *Er
-------
                   TAliLL  -6
        ^c^TjT^VKTn^GT<~ciF'"CH^TrcrirAr~rb"j~sY"i>'Ti:H's  lu/'f'T
JUSTIFICATION N-0.
UTILITY
REIV-LHAL NOTOkS
UMIT ,'Jfl,v.
CHLVkOLET  FAKtffc 1 2 3 &  H
     LOCATlOt-j
l-'AKhA OHIO
UNIT KATjIVG
FUEL cH/uAClTY" ('SliMCE" ;SAKCh)" DUE~7u ~LOw MEAT""

-------
                                                     _ _	
                                                  FbD "SfS'TLf'iS   10/7H


                           NO.	3b			

         UTILITY fyai^E:	ILLINOIS  t'0*E.K	

                                               . i\io.. t  .._	

                                            (if4

         UfilT  RflTT'v'G	110  hh

         PUE:L_CHAT^AC?EKIisrics  COAL	2.9-_3.^__pt;hCi:NT soL.F_yh.

         FGO  yt;^ijr;i*	MOiMS^uTO  LI\VIKO  CHE.M..SYSTEMS

         f'HOCLS?     	CA_TXLYTIL OXl_Q;iT10M
         FGQ
U)
             !(.! tf-cy.
          P/KT ICiJI. A
         W/iTtlic f*f-rt.il up
               COS!
i73/Kl'. C/'-l'l l<--L**t ,-;lLLb/Kv%H  Of
                                          i,  u:.J lHA.Sit.L"i'v
                                 TriL  IJA.SI_6C DAYS TO  I'CKFOKn SLR\/LRAL  HLPAIRi,
                                itf' !-.K l(.K>b~lN 1 rit~Klitlt./>T t  bUHLjtH  L)OME~HA
               RE.r-.aHi>  TO i>LFi< ALToH Y LliJl.u  DUCTS  IS Ifj  PKOOKLSS.   OTIitK
                           uF  [iLt.SS  bTLEL  OUCT'/JOHK Ar.O KLPAIH OF  THL  ACID
                                     ""  iArr-'CCS"."" THL U.-jiT" IS  LCHtDjLuD  TO RESTART f'Y ' NuVL'Mutu 22. 19'7'i"

-------
                           TABLE  3
him
             MAL
                                                          _ __
                                                           T07TH
                        NO.
        UTILITY  NAME
   KANSAS  CITY POWER S, LIGHT
        UftJlT  HAKE
   HAV. THORN  NO 3
        UNIT  LOCATION
           CITY MISSUORI
        UMIT
    mo  MI
        Fut'L  CHAijACTEKlSTlCS   COAL   0.6- 3.0  PERCENT SULFUR
                                LlMLSTONE IfviJEcTiOM SWET ScRUo
        WtW  oi<  RU
   RETROFIT
        START  UP_ L)ATjf_


        FGC  STATUS
vo
                                99~pE7icEi\;r
                                70 PLRCCKT
                UlSPCSAL
U,MSTulLI2L(j  SLUuGt DISPOSED  IN
                                              PONQ
         EXPLHTET'Lt
                                                .;j  MLS/KWh OP~
                                KCPL HAk A LAbOH  SFKIKL AT ThL  PLAK'T WHICH LASTED  FROM JULY JjTH  TO  OCTO-
                                             STAFF.   hOWLVLHt  btcAUi OF THE KAr-iHOwL'< ixiOHTttGt*  Hit.
                                   !& WERE "DGW.g  BURINS THE Si f-, IKE."  T'dC'FGD J^lf  KE5TARTEO"OCTOi>tK" 1ST
                                    h^.S b 1-E.'-iK U/
-------
          _  _  __ TAbLL _i
~FO7FTTS7TA'MrL' 5UfihArS_Cl 7.X ...N I.S

                            100 M>
 FUEL CHARACTERISTICS  COAL    o.t-  3.0 PEhCErgr  SULFUR

 FCip ML'*JL>OK__ _______ cOi-ijjbSl ICU KfJGI_'JLEH.I)v_G

 H; Oci; S_S ___ L l^.t'.bTQNL, lU JLCj lOi'"

_ :-it V ___0j.<... ^"TPQE.IJ ______ ^tj '^V I T .....

 ST

 hf-

.LF.
  F


  SG2 __ 70


         /.".t; UP                "~    ~  "


         CTSHCSftL. _ ut.STABj^LI ^t. L; $LU uGt  UISPQSED  IW U U LJJ[4Eu__P OUg


          _                    ~~d:.2 MILS/KWH OP        .....
  Ot EPATICf at
                                '".0. A  LABuH _STRIKE AT _T_H_L  PL/>.NT WHICH LASTED  FKOM JUL  dTH TILL  OCT
                          l'sf.  "Ut~r<"l'i-^'"fHlS PLRlOu "THf "ijOILLKS WLKE OPEKATLD 13Y" THE  COMPANY'S   SU-
                          PLKVISOKY STAFF ._ hOkLVLKt DUE  TO THL  KANPO^LK_ SHOHTA6E i THE_ FGQ UNITS
                          AKE  ~u6*fj juRi.jb TH 'STKI'KE. " "THL'FGo'uraT HAS "WOT" RES'TARTLO BECAUSE. THE"
                          f-OILLR IS_UCiN TO OVERHAUL TH?;  TUt
-------
      	
PiLRFtftilAf.ct. Su;-n.AKY h'uTT~ijPLKAVTOI-mL Kbfj  i>YSTilMiT  10/74


 IDENTIFICATION NO.	|*_0

 UTILITY NiAf^E	KANSAS  CITY POWEK e, LIGHT

 1'.N1J_JAI^E	y

 U.'.iIT  LOG AT IOM	LA   _

 UNIT  KATiMb	620

 FULL  c H A aACTE: i: isTir.s	COAL	

 FGD  v'-^OOK              B&UCOCK i WILCOX

                             .CSTOr-JE

                             _   	

                             73	

                             .:  r-i"H"KT"L!F'"                    "                                                  	


 SLULibL UlSPOSAL	UN S TA B_1JL 12 L[.i SLUuGE L)I SHOSEp  I h  U f>i L_I W-U_ jPO kg	


 U::lT"COST              i'Vi/i'-K  Ci'.Hl [ At"      	          '   "	   	"


 OPLRATIU-jAL	KCPL HA A LAPP*  _STRIK_E  AT THE. PL^M WHKH UASTEU_FROM JULY  BI.H.TILL OCT.
   EXPLrUCNCE             liil-   t/UMljfc This P Lhl'OU "T ML  bOlLLK~WAii  OHtHAt L j "nV" 1 HL "CUMI'ANV ' '5>'~"SUPEK-
 	ylSl.HY S1AFK.   THE! FGO  SYSTEM OI'LrtATLU WITH ABOUT  f,0 r-tKCLliT AVAILABILITY
                         ""LioKir.O OCIUL'CR.   TMtlKL" AKE.' NtThAJOK OUfSfAKuIwu PKObLLKS.   HUWEVLK,  F'KE-
                          VL^TIVE: \-\t\\^VL\*^\tc. PRACTICE  UCCOIKIIS THAT CUE :ODULL BE  TAKEW  OOVJN  ONCE
                         ",V "jtr\ "FCK o H'uUKS" OF" CLtAM'NG AfvD  /.'Aihi^b OF

-------
                                    6
                       ___                ___ _
      l.rU OKMAf-.CE  SliF.VuvY  FuH "uPLK AT 1 Of/AL FbU  S'YSTLMii   10/Vt
       ItJl'f.l IFICATIOM  NO. ____ 43

       in iLiTY .yAriti            K AI\_SAS__PU_ u E. '<_
      _UN'IT  LOCATION _____________ LAUI'.ENCE .K/iNS

       IJj;. It_:tflT_ijG               12 5  l*
       FUEL _.CHAi<.'*cTj:.\J LLS,__ A N  _ IN _ 0_P E ? M T I 0>_i> .1 T H  .LS S E N T I A L L Y_ 1 Q 0 E K C E N T_ AV A I L -
                                                                                                       "  ' "
                                                                                              _                      _
        EX.JtiUi.f:CE              AfulTf. J-iA.vUAi.  ^ASll-UH  Or Di.^:13TCnS  IS PERFORMED ABOUT  Oi"\)Ct. '  EVEKY  TvJO
           ____ _____ __. __________  '*fc.!\>._.  >,Af^AL  CLt*,r;LP pF_KF.h-:/>TLi( COIL IS  NOW. OUL  AFTC_K MOKE,..THAfJ.  12
                                  |--.CNTr:S  Or              "            "                     - - ......

-------
           	TABLL'  3	
  KF OiMiAUCL SUf-'MMHY  FbH  OI-'LK A1 I GNAL Fbi) SYS1CMS   10/7<+
_I [: E i: jj F_I CA T IOM f>)0.

 UTILITY  DAME
MJAS  POWt.K *  LiGHT
                                    c NO 5
                            LA*KLNCC KANSAS
 FUEL  CHARACTERISTICS   CO_AL___3.5_P.K<._:;T  SULFUK

 FGn_VK_M(jOK	COMBUST ION  ClMGlUtEKING	

      t~S                   Livi:STO.'Jt  I'JJLuT J.0f-i a'.JE
 f.t'U  C'< |       _		

 STAiU  Lii'_y_Aj_E	L1"!?..1.  _  	

 PGP  STATUSOPE NATIONAL

                  	
                        "   yj ^LKtLf.T


  SO?      	(zcj Ht.KCE.NT


      ~M7.i\r~up                  	


      or ;;j-;t--jsf.u.	b..sr.v,,iLi^L	       _	


UTTiTTcsf                          	                                     	          	''


                            iU.iLI r<_ -_h,-,i nuC.._CHE.: "TuL H  i'lUJjULLi " AS~ i^tLL 7,5'. "AI--IU'I\G' ~1 HL  MuuULLS  IS
                            STiLL  >;  r-iAS 0 I ST ri IbUl I ON
                            ILST5' ;;i:L.  lb> CoKKLi.i'LY  :'1UDI F Y I i JO  Int.  G(1S  f LOJ  PATTLKU THROUGH  TnL
                            f;U !.'S  OPEKATING HUUKS OK  SYSTEM
                               '""""  " ""  "       "  ""      '

-------
                         _	
            SUMMARY FUK UPi.kAliUNAL  FGD SYSTLMS  10/7H
ipcy J.

UTILITY  .VAKC
                        LOUISVILLE.  GAS a ELECTRIC
UUIT  ijAMF.
UN I T_ LOG A.! L?y

UhlT  K
 H OCLS S
STA.K.I .u

FSfl  S
EFF 1 L.I ft i_c_Y_,
                        PAuDYS RUN  M0__b __


                        ku I S V.I LL E.JK EN Tit CK Y_
                                3.5-ir.O PLHCEM
                              S CUJ E &UJ
                         V  *?.
 S02
_. ^
SLUUC-L  uispcs.a.
                                             E  LI SMC SEJ.  in ONL i r-j E y _P o i-j
UuIT  COST
                             W CA['I1L
                         I.-.O.
                         F.'-.CL
                         J.HE
                                               _           ci> ILY._TH|.  P/.ST  3 ;.,Xo Or.  Li'lcSTG^E  (UhlT OF_F_
                                         r,ii;j,L K.JI.S AKL  i-.toe.  FOK  AKO f ur.(,ru I*Y cc-MiusTiofc "L.'-JGINELR-
                               ,,y,Ml-MniuI f Y  WAS t-SSL/jT lALLlr  100  PEKCtl^T wlTn t\(0 PrtOtfLtKS  LXPtRI-
                               1IJ  AioY  PAKT OF ThL SYSTLn.  TriL  L i,v.ESTOfi. SLUDGE IS LiLWATLHED IN
                                       ROTAKY  VACJOM  TILTCHS  '1TH  r;o CLIPPING OF ULIER CLOTH.

-------
         	I/you:  3	
         PLIU uh.S/HjCi- Sur.hAt'Y  F-UK  GPLKA1 lUNAL  Fbf) SYSTfclMS   10/74
                           c i-jo.       &i
           UTILITY  !>;AC:L             NEVADA POwtK
           LICIT  rjfPt:                 REiU  GARDfcEK  NO i
           UNIT  RATji.'G               12
           F'jEL  LHAKACTEHISTICSCOAL
                                      SOUIUM CAKbOXArt"  SCKOBblf-JG
           iv W  CK RfTPOFlT         Rj-lTKUFlT
           FGD  STATUS               CPLKATICNAL
M         Lf-f-IClEt-'CY,
O         >-AKT:C^...Ti
            S02
                        UP
           bLUCGF.
          ""Ur\,iT' COST
           OFri-,,T!C::,-,L _ FC;;  btSTL/: F'LtiK:j:<.v;.!-;CL  13  SA I IS^ AC! OKLY  WITH  f;0  OuTbl ANDII-.o I'iLCHAi-JILAL  OR
          "TX'P L.":< IL'-Ct              "P i-UL"tT^J~r'i'iOVJ'Lc. ..' ~TC.'""f LXPLi
-------
Pc.rf ui !/.( r.fc.  SUrti-.AKY  FU<  Ol'L'AATIONAL  KuU  SYSrCNS   10/7U
                ._..L'1. _______ 62

           :..\f:E. _ N-E.VAL-A
 oT-JIT IJANr	  Ktll)  oARuWtK  NO

 uM I T . I. ..LA f I ON	," A Or A .J.E V AU_A.__	
__CS^ _ COAL_  ..0.5-  1.0 f'EKCLNT .SUL_FUk_

 t-GC .vi::.:;,fK_ ........ __________ CCJ.-'i.iuSTIor.1 _CQUIP.  ASSOCIATES ____

J-^ClS                   SOb 3 LS CAH^O.'I;. i   SCKU
 lit w L,'<  'TTJ-'OF J_'l_   _  __ KL. 1 1- yf- IJ_

 STA1  U"  iltJC            12/73
                                !<;n iOl;AL
      |-. TIC- '-.;> L              Fli   SYbl Lf-'.  'LKK)[-'.;.i\CE 1 S   A 1  b FA C T OH L Y WITH NOOUTS1 AivDIgb MECANICAL
               _ _                                      _                  _
   t Xf-t iflE :.C"r              PKULt':J:r?;(A POWLK  IS  SUIriG
                         _   T--L.  Sj.:rl_lL'<  FJ.;<  ortLACfi  OF  Cui.lxACI  ANU ALSO  IS PrtESLNTLY  TJLSTlNo  SOOJtUM
                             C;.K:jO. ,\rj" biMI-.c-  PUKCHAiLO  FI
-------
                              TT/U3LL 3         	          	
                      SunY-AK'YS!L''v' ^AS  OPLrt/,lL[J Ft>0;-i OCTCl-.Lft i^D  TO Tiiti  itTH.   >'H[1SENT
                                   i_Y  THf. SYSTTK is  OOv.'fi'TO f\f'AlH LL.AI\S LN Tr.L F1"i (;ULHt-T LEVATOl.   &
-------
               	             	
       T^rrT. Suvi-.EPY  ru!;Pf.7\Tm;i,!AT~FTJiJ  Sf'STtTTS
 niF.t.,1 J,FIcA_TIO^_Ip.	67_	   	


 UTILITY  c.'AME             SUblHS.KN  Cc.LI FuKNl A EDISON
_yfo i T_rir_c	MO_HA_V L _Mo,_i


.yl*:I1_..lrP^Al I.?^	LAUt
 FljE!L...CHA'.  Civ  i.L"i>TiJi\t KOH i-uJJT  Tv.'O  LLKb \\\  OCTUbLk.  THE.  yi'lT  IS WOW bACK 01, HME,
                            int. Avt.iv/.CE:  AVuILAlsILI IY  OF  Ih.lS  f- vJ  SYSTE-rt SIf,CL  ITS IMTiAL  START UP
                            iij  JANUARY  1974  is ABOUT  eo  PLKCLNT.

-------
        TALLL 3
S u -: r-. i\;-. 7~~F C/H
                                                 ___
                                                 7TS   10/7t
 LL)Er''-T

 UTILITY t-j^.
                       VALLLY  AUTHORITY
 uwIT f.'AME
                     NO.  10
 uri f_ LOG AT ION


 U ,] T K
            PAUUCAH KENTUCKY
              EI'ISTICS   COAL
 FC-D VLNL/OR
            TN;JLSSEL' VALLEY AUTHORITY
_ST_AR T_UF _yATE


 FGO STATUS
                         ,< E T K c F1 T
             H/72
            OHLKATIONAL
 C.FFIL1LI..CT,
""PAMICU""	
  S02
     r, y'ftrtL  UP'
 SLUDOL
 UilIT COST
 OPfK /
            Thlb  IS /,N LXPLKlMLfMTflL  SYSTLh FUtJUEU bY  USEPA. THCKL  A^tTHHE-E  TYPES
                         " Q 0~T-ra~LTJj I V ALLMTACh )  OL I "fTG~n7"ATUATE:"irTI^UL'R A
                         OF OPtKATlOI-iAL  H

-------
                      K  Ai'U  TOT;iL  i\*  Of FGU SYSTc.hii
                       STATUS                         ,'JU.UF
                       			UNITS
                           I 0, i-Tix-C I lo.j                le         c.677
       _      _  	       .       .    f .
 o  ""	
 ^	    COf-j5l.'J.L..t.'!.i.G._o.'''iLY...F.Ou SYSTLr.S 37

	       TO TAJ	__^._	__2S.

-------
                                        I'AtiLt b
                                       'JF  FliD SYSflMS
                                                       UY  COMPANY



TOT






AL GPLKr.T IONAL




co;, STRUCT i










COHlhACl LHTE.K
AUAROEU IN1ENT
UtTLlty
AL;(.>f-'A LlCClMlC COOP
iiRI^ljt-/-. Kl.i'.CTKlC PQI-.U;
:V
CIuCIU-i. i 1 f/iS /V'G LlFClKlC
CITY oi- KtY ,-:F.SI
tULUf-'.U.C (>IC fLt'CTKK
C0"r/ ^'.vf-l^r^u'.; !lIU
 A I n Y L A i , ;, t ' 0 ..&'. C O 0 f '
DIMKolT FT ISO,-'
Q Gti!. KAt -'OTf.ivS
ON fjl.l.L'-.'.L" i'1'i 1 if. "L'Tl'L'n i'Li.
__ iLLrr.is ce,L!i_ _ 	
 Ii:li I Ai.Mi'TiL 1 5 t'O.'if.lv 'Vi..;i LlSHt
l\.;;S;\i> C1JY i'f.i-'L'l' .< Llf-Hf
rtAuSfcS rOV. i K X LK-liT
	 LOUISVILLE. lliU.
li'l).
1UO.
obO.
"Inn!
<; 2 b 0 .
1600.
bt:0.
4472.
0
0
0
J
c
i
0
0
0
1
0
fj
1
1
0
1
0
1
f)
3
0
1
0
0
0
0
o"
0
1
0
u
0
0
1
0
0
0
1
0
MU
0.
0.
lib.
0.
11)0.
0.
u.
0.
37.
0.
u .
loV.
60.
0.
410.
0.
llu.
'" " o .
1060.
b2b.
0.
"6b.
0.
G!
U.
0.
0.
0.
100.
0.
0.
C.
0.
160.
0.
0.
0.
0.
NO.
U
u
u
u
u
1
u
0
0
u
u
0
0
1
1
0
	 o
u
	 o
0
0
1
2
i.
u
1
2 1
. ^ .._
1
U
1
u
0
u
1
0 ""
1
1
1
u
PIW
0
0
u
0
u
100
u
0
u
0
u
0
0
100
bio
0
0
u
0
0
0
u
0
113
ol>U
120
0
6bO
0
0
16U
0
343
You
bbO
0
r-iO.
0
0
1
0
0
0
0
0
0
0
0
. " "0
0
o
0
	 	 o
o
. "" o
0
0
0
2
0
. " " u
0
0
o
. 0
0
. u
0
2
0
u
o
0
0
0
0
. " 	 "2 "
KM
0.
U.
" "250.
u.
0.
0.
0.
0.
o.
u.
7bJ.
U.
" 0. ""
0.
0.
u." ~
0.
" ' (J. '
0.
u.
0.
603.
0.
0.
0.
0.
0.
0.
0.
0.
71b.
Q.
C.
0.
0 .
0.
0,
0.
NU,
0
u
0
0
0
u
0
0
u
0
0
0
0
0
u
u
0
iT "
0
0
0
u
u
1
u
u
0
' 0
c
0
u
u
0
0
0
0
0
u
I
"o " 









OF KEQULSTING/
EVAL. BIDS
MW NO. MW
0.
40b.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0 
" ' 0.
__ 0.
c.
0.
0.
0.
0.
0.
u.
0.
0.
0.
0.
0.
0.
0 
0.
o.
0.
0.
0.
0.
0.
0
0
1
0
0
0
1
1
0
0
0
0
0
0
0
0
1
0
1 '
0
0
0
0
c
0
0
0
0
0
u
0
1
0
0
2
0
0
0
3
0.
0.
0.
o.
0.
600.
bOO.
0.
0.
0.
0,
0.
o.
0.
0.
650.
o.
515.
0.
1400.
0.
0. "
0.
o.
0.
o.
0.
0.
o.
0.
0.
0.
140.
0.
o.
446.
0.
0.
0.
2386.


CONSIDERING
Fr,0 SYSTEMS
NO. Kw""
n c.
3
0
n
0
i
0
4
n
n
n
0
n
0
0
n
0
n
n
0
fl
y
D
1
y.
n
i
n
n
n
y
n
y
0
n
0
0
"o
165C.
0.
0.
0.
bOO,
Q.
0.
0.
0.
0.
0.
o.
0.
0.
0.
0.
0.
0.
" 1899.
14UO.
0.
590.
0.
800.
0.
0.
0.
1000.
0.
22SO.
1280.
0.
0.
0.
0.
0.
TOTALS
                                   95  3/961.
19 _ 3291.
                                                              16    6677.
3904.
530.
13   6U87.    37   16472.

-------
                                                   TAoLL b
                                      SO'-.V,AKY OF  FGu  SYbTti-lS BY  VLuUOR
                                                      	-	STATUS
                                               "TOTAL     OPLKATIONAL   c
                                            hst.I.-'b      	   1    3-r3.      0.     U.       1   343.
                iL  Jt-:JLCrioli  isisLT  SCHUb      4    7ob.      4    76b.       0      0.
              . ;, . SrKu;.iP.Ii..C.			_2,_13bO.	0	 C.		2..1360.
      TOTAL,  Co-IfUiM I0i-j  Ll.oJr.tLMMa        &   2bi5.      b    63u.       3  1703.
     COi-iiL-ST KM  L..-UII">.  M^SOClATc'S
       U.I.M.  SC-..l---t.Ji.:.-.    ...        	   2    72u,__   0	0.       2    72C.
       ScSiL-r-  C-i't-^:^.TL  bCi'C'vUlisi;          3    i7b.     " 2    250.       1    12b.
     TOTAL,  CO-ii-U'-. TlG\  tOi'lPj^ASSyCl	 b  _10^r),	  2	250,	3    645.

     DAVY rciViH&r-s	                                        	
           .--./.r.' I.OPO                           1    ii_.      0      o.       i     115.
      TOTAL,  0;.JY .PGv L_Rr,,%S.	1	lib... 	0 	0.	1	111)..


       L1.VL  H.^r.CTjU';                         1     oO,      1     60.       0       0.
      TOTAL,  FQSTLM W^ETLKK	i	ajij	i	&&_	o	QJ_
KOCH
iJOUbLE ALKAl i
TOTAL, K( CM

1
1

3.J.

1
1

....32!

U
0

0.
o.
                         Ci.t''-  SYSILf'S
       CATALYTIC  OXlPATIUf*                   1    11U,       1    110.       U       0.
	TpJ_A_L.,  iv.Lj'.S.A.f-..Tp_E 1V..IRO _C!it-i^_SYb _  	1_  liO.	1.  _110.	0       0.

-------
TAoLL i-
SUMf.n
KY Uh
FG[j oYSTfiS UY VLWOOK
TOTAL GHEKAT
M Af'il'F AC Tuf-.EK /PROCESS

NO.

riU

1,0.
--bTMUS 	 '-
lOkAL CONSTRUCT 1C-N

hW

NO.

Ml-.


f.OT SEL.EI.TF.L)
LJNE./Lir,f.ST O.Mf SCXliL bl|.;G
TOTAL , l-if f Sf Lf CTLu
1
1
bbU.
b JU .
0
0
0.
0.
1
1
650.
650.
PLAbGCY t.MKIr.'U. iUMC;
LIKESTOI-.-E, SU'UHtilNG
T'JTALi !!LAbOnY Elf'.T.iriL EHIIvli
a
i
180.
loO.
0
0
0.
u.
1
1
180.
180.
PESF.'/ifJCH OOTTKf L I.
LliM.STC-.'.E ?.f HUMMING
TOTAL, KlSD-i'CH CCiTTKElL
i
115!
1
1
lib.
lib.
0
0
0.
0.
TILEY STC KE R/c.NVIKU.NEEING
LlNESTOUi; Sr.i^UboI"'^
TOTAL, R1LLY STOKf K/Ll''V IHOMEEH I
i
i
100.
100.
0
0
0.
0.
1
' 1
100.
ICO.
M SCF/ SUii.; KiVol'K
Oo L 1 .'. E b C f\ ' Jf. r I  ' G
TOTAL' ScL/ .SltKlj OGf k
TE'Jf-'ESSEL VALLEY /.u HiOiuT Y
LIhL/L l-.l-.S'l Ci-C SC^UhrH-ib
LIKL'STO; L Sr.K
I'iAGNESIbi-' OxirE SCiU.-r.bINO>
TOTAL, UhlTEti ENM!
LIMESTONE Sr.^UbfilliG
TOTAL, Zuf(|\ Alfi SYSTEMS

i
i

i
i
2
1
1
2
^
1
1
37
IbU .
IbO.

oO .
bDU.
boa.
liO.
-^T^O.
3oO.
SoU.
37.
07.
101b6.
1

1
0
1
0
0
0
0
1
1
19
IbO.

30.
0.
30.
U.
0.
0.
0.
37.
37.
3291.
0
0

0
1
1
1
1
2
2
0
0
IB
0.
0.

0.
550.
b50.
120.
120.
3bO.
360.
0.
0.
fa877.

-------


TA:lLL
SUM- ARY UF f bU S
	 . ._,^ CAPACITY (t-.'O.'
7
YS.Tt.Mii bY P
OF' PLAI-nS)
K

GCLSi,
N(_ft Ul< Gl'CKAl IUNAL COI.bTKUCTlON CONTRACT
P'UlCKbS M. llLS !.
K
Llf't/Ll'lfSTCNE 'X CF TOTAL *'.: f-
F\
NO. r-iw
J 0
4 715
U (J
AJ
o Iib7
5 647


l(j . li1?^.
u ti
o D
1 32
0
~ 4
0
0
D
U
0


 *
0.
0
J
(J
0
u
J
0
0
0
1
0
0
c
~o.


Mki
0
0
c
0
0


400.
0.
0
0
0
0
0
' 0
0
0
0
u
12b
0
a
0
530.
o . - "
76
U




HEQULSTIliu/
tVAL. tUUS
NO. Mrf
0
0
4
- 0
0

"12
0
0
o'
" 0"
c
0
c
0
0
1
0
0
0
0
0
13
0


0
0
1755
U
" 44B2
0

;' 6237. 	
0.
0
" " 0
0
0
0
0 '"
0 "
0
fabo
0
c
0
0
c
. 63B7.
0.
0


CONSJ
FGU S
NO.
1
13
3
1 "
0
2

12."
U
0
"d '
0
0
0
0
0
4
5
' 4'
' 5
lb.
21.



ICtRlNR
;YSTLM' "
MW
BOO
4333
2250
tiod"
3372

6b3i.
0
0
0
0
0
0
0
0
2500
1915
2500
6922.
"7550.
72
75




TOTAL NO,
OF PLANTS
NO.
7
21
3
26
10

34.
0
1
0
1
0
3
0
0
5
' ' 	 I
3
1
2
50.
49.

HW
6275
14oU
13012

y/44.
0
110
0
32
0
37c
0
0
315Q
375
375
455
24V60.
13001.
85
75
-*

-------
                                 1 rt'iiLL             FGJ/.-iw   STAUTUI'   LXt-'LhlENCtl < MO. )
                 CATALYTIC OXIDATION
        WOOD  hlVLK NO <*                         110     10-72                2t
                                                 110.
                 L'L;Uf,Lt: ALKALI
                   _?.RMA l  2  3 a t	3.2	3z.?J*	7.

                                                  32.,	7...
o       ALMA  srATjOrg                             ao      6-7i                HO

                                                  on.                          HO
                 L1?T  SCjivJi'nIN0
       _HUHAV. NC  2 _______ ifeJJ _ 11~7.3 __ 11
                 U'N i^o &                         " &s      "4-73               ' ie"
        PHILLIPS ___     _ HIO      7-73
                                  SCKUbOl.'JG
        SHAUNLE NO.  10                           iJ      4-72                 30
                                                  30.                           3C
       _HAwTHoKfi _r,0_ 3	iHy	11-72	23
                 f r 0 "'                           iUO     ""S-72"~"              26
                   r.O H	_^__	i<:'J	 12-bfl	70
       ~"LA'A;f
-------
                      HP
                                   1IVK  UiMlTS  />;> OF  10/7C'K U b h I"I
1
-------
                                         TAbLfl  9
                           OF
                                                 "-"-'SCUuGE--       --SlbuGL'~      -PDi^D---   "  "-- -PONU-"'
                                                            J     Ui'MSI AblLI^klD          LlfvLD
                   E SCHUBBING
                  O 2                                     ibo
               S  KUN hO  (,              ~                      "              55                                   65"
                 N                                        410
                TOTAL                                     t)70.               fab.                 0.              bib.
        "TiATt"i-iof<"~iv'cr""3                                                     mo"                            ~    i'u
         hA'-' 1 Hlii'^j t-jO  '*                                                     100                                  100
                   fjQ b                                                     i+ 0 0                                  H U 0
                       _   _         ______ __^ _
                    l                                                        i'b                           ~~     1 1 5
          __      ___       ______ ____   __    ___        _                   _____
to       "LA LY'jfitf i^U T   "   -    -            _...-.  .........       .- ^.^ ......... -. ...... -.-.         .        620

                ^^IUi^1 _________ ...... __________   ____ 167_  _     __________   ......... _____   ,lb7 ..... ...

                T;iTAL                                     167.             1700*              167.             1737,

-------
                    1Ar.L  10	
                       OF  t-Gij inATEK LOOT'  PKAC
                       	     	K is. (U 1A L
                                        OPE:*"   cLcst'j
            CATALYTIC  OXIL-AT10N
wuco  KiVL'K ?.G  4                           o         a       no
                                            0         0       110
            LOUfjLF LrtAlI
           PA.\-fiA 1 2  b  * ^U062
LI--E: I^L-CTION
ALftA STftilOh 0

0
M
M
rtCHAVL" ivu 2 0
P/VuiJfS F-:oM f.:0 ft 0
PHILLIPS o

0

0

0

0
C
4lu

410

BC

oO

160
o5
0

225
LI^-E/L Ir LSTor-.L. SCKul-.L'I^'tJ
SKAS.MLL MO. 10 0
U
LIESTGf.E INJECT I0;j iwc!T StKOu
MAWTl-Ohr.: NO 3 0
HAUTHOr'l'i ijQ H 0
LAW(
-------
                       T_Ar:
                            _
                          OF  FGO  WAIE* LOCP  PRACTICES
                                                       HART 1AL ______
                                 ...... ....... OPtiiJ  " Cli/SLO  " CLOSED
CMCLLA  MO  1                                 IIS          0          0
KiJY  UtST I'0*K .PLAnT	  	  37.  	  .0	0
LA  CYl-.KL .iO  1                                 0       -21)          0
-.vILL C(a.'i-.1Y  1-0  1	0	167  	   U
                                                          907		p__
lUCKLi'SO,.;  ,\:0 i                                CO        ICO
      C  r.-c....b			.		u		_u
                                                ..0	0
              i-n'JlU-'  CA^i'C/.'/JE  i>CKUbb!.\'L-

Kt'lL' r,flKr,jth i.;o  l~ ~ ..... """" ............ "~l2b "~      'o   ..... ~~" 0
Kt lu. GAi;;i<(:F>, f.O.  .? __________________ ..... ._l*i>. ______ 0 ____________ 0..
                                                            0 _ p

-------
                  	TAbLE  11	
                   OPERATIONAL FGU  SYSKf'iS  AS OF  10/74
             UT'lL I fY" CO^'7;fi~Y~           "Ktu  OR   S12E OF FGD   PROCESS/VENDOR                     FULL  CHARACTERISTICS
              POUF.'< STATION	KLTKOFJT    UNIT
              PUBLIC SERVICE                K         115       RESEARCH COTTRLLL                 COAL    0.44 PERCENT SULFUR       10/73
     .ChpLt.A j\0__l.			_.._		Lli-H-STOWE. SCKUbBluG	   _	__

                                                       .150	CHtf.lCO         	OIL	2,5 PERCENT.SULFUR  	  .4/72
     MYSTIC NO  6                                                MAGNESIUM OXIDE
     CITY Gf KEY  fcCST                       N          37       ZUl(N  AIK bY-SIEMS                  OIL     2.4 PERCENT SULFUR
     KLY_'EST  p(),tR PL.A'Vl	Llf.t-STOt-jE SCKU^ulMo _.	      	

     _CONrcrvLALTvj_ EP.ISGjVi.			R	..167	t-AbCOtrt N UILCOX  	 _  COAL	0.6-3,0  PL'RCiNT  SULFUR     2/72
     ILL CGu-JTY  I-.Q 1                                           Ll.'-iESI CJ.NiL S(
      LJAIKYLAI:!.'  1'CHER COOP                  R          60       FOf.TL'r-.  wHELLER                     COAL    3.0- 3.5  PLKLF.NT  SULFUR    6/71
  	ALMA STATIOM	  	Li*>-  I^4JEc^lo^J	

	i)OViUtS!'t._ LItHT	ii_..		"410	ChtMCO				COAL ___! ..0-. .2 . 0  PERCENT  SULFUR    7/73
                                                                  KcxH                                COAL    2.b PERCENT SULFUR         3/74
                                                                  OOUULE  ALKALI
""   ...iLLlf^'iS, .POv.ER.  		R		....110.	MjflSAr.TO LliVIHU ChUi'l  SYSTEMS.    COAL,.  2.9- 3.2  PERCENT  SULFUR   10/72
         u luvi.K  vc it                                            CATALYTIC uxii;;,no.v
      hA|.;SA.S CITY i'0'.JFU  H LT&r.l             N         620       is/.tiCUCK i UILCGX                  CCAL    5.2 PERCENT SULFUR         6/73
     .LA  CYC-I'JL  FJO i	                  	  L^.LSIOJJE ^c
      KAI;S>;S CITY POCH _*. L TGnT	 	  K	1.00	COf.UUST 10,'j f hGI TJLEKIMG            COAL    0.6- 3.0  PERCENT  SULFUR    8/72
     "HAxThOK;-j  >jo"~4	"         	    ""        LIML.STO.-JE  i.N JL CT IG-'-J i'.vET SCKU&"
             CjTY PCVir.i  H LjGuT             h         140       CC.vibLi 11 Jfj f'.iTGIIit-LKl.'Jb            CCAL    O.o- 3.0  PERCENT  SULFUR   11/72
             '-i  HO 3                                              L i:'.LS JUI'-JL PiJLCTlOu iV.ET  SCKUii
      KA1.SAS >;.')>. E.<.S_L_I_l.HT	(A? Pi;ufi< X LIGHT                  R         12b       CGI'.bUSTlOU ENG I^LtKIi-iG            COAL    3.b PERCET-JI SULFUR        12/68
     AA.WH.E.f.CL  '-0.4.							.__ Ll!'LSrO!JE ifJOECTIUu  iii-ET SCRUB..__.

      LDJISVlLI.r.  f-iS^^LLCTPJC	H	&b	CG.v.bLST I OiJ t tjb INLEH !'.&            COAL    3.b-4.0  PERCENT  SULFOR     4/73
      PAOBYS u^  r-o ^      "    "              	  "   "         LIM                    	~	
      NEVADA FOWLS                           K         12b       CO:-.bUST 10.J EOUlP. ASSOCIATES     COAL    O.b- 1.0  PERCENT  SULFUB   12/73
      KEIU GAKDf.LR HO.I                                          SOUIU.S  CAKbONATE SC

-------
              	TM'LL  11      	
               OPfcP/.Tlul-.f'L  PTil/"SY~STC,'"S  AS UF-'  J.t//7H~
         UTILITY" CtiKPiJ'iY
          POWrK STATION
 l.tV/u A
 HLID  &AKUM.H  N'O 2
 p o T o f. A c_j y. c rji i c
        SOii r-,0" 3 "
 bOJ I MtMf, CAI.IFONM1A
 HC'H/JVE  f.'J  2
"sH~fc:>('L '-o.  fo
 fvC*  OR   "SIZE  OK F'tiD   HHO(.i.S&/VLrvDi;K
RETROFIT    UNIT
                                                  FULL CHARACTERISTICS
                                                                                      MO/YR
~ii-3
               ICO
               160
                                                      30
                                             ." A'SsC'c'iATtTS     c'oA'L    u.b'-  i.b  PC."MCENT  SULFUR  "i"a/7j"
                                i  CAKbONATt  SCRUbU ING
                          CHCMCO
                                   i'c 'GXIDt SCHUSiHlNS
                          LIME  SCRUBBING
                                              /iUTHOiL _  2.0 PEKCLNI  SULFUR          9/73



                                                TUAT.    O.b-  O.J~"PE"WE'ffT~~SULFUR"   ff?"73~



                                                 COAL                                  t/72
                          L i .':' /L i HCS'J oi\ie "s

-------
                        TABLE:
                  SYSTEMS
                STATfCf.'
                                               _          _
                                          I r07T'flS~OF  10/71*
                               ~KWOK "SIZE" OF  FGD
                               RETROFIT   UMT 
                                                                                              ' FutL CHAKACTERISTICS
                                                                                                                                 MO/YH
CtHi R KLl LL 11 K> 1 b T.16I1T Cu.
'O'JCK CREEK  NO.l
L'ETkC>lT
          LI(,HT
 KCN1UCKY UTILITIES
                                                          ~RYLL T"5TOK D^TLTiVI R"CiRt
                                                                    C SCHubtilMG
                                                                                          CUfeL 2.5-3.0 Ht.RCtNT  SULFURJT7&
                                              ItiO
                                                       PtAbOUY LN
                                                                                              COAL3.7 PERCE:NTSULFUR
                                              bit)
                                                          ~CR C n ICT3	
                                                           LIMt.  SCKUUbING


                                                           A Mi-: f< 1C AN AIR FILTLK
                                                                                          COAL    3.a PEKCENT  SULFUR
                                                                                                                                 11/74
S77T
    i ATA POH<
                                                 iibu
                                                 360
                                                       COMHUbTIOIj ECUIP.  ASSOCIAESCOAL00 PCKCENT  SULFUR
                                                                                                 "
                                                  115U/;V
                                                                                           cvn.
                                                                                          COAL
                                                                                                                              5/7&
                                                                                                                                  5/75
                                                                                                         - 3-5
     iiiJ-. 5-TAT( S i'Cwti-:
                                                 GOO
                                              fcrt'J
                                                                                                      i.c
                                                                                                                                   /75-
                                                                                                                        SULFUR    6/7b
                                                                                                                                  5/76
                                                                                          CAL-.-.  1i PERCENT  SULFUR
                                                                                                                                  3/77
! i ? TLT A 
               p c v7L" K ctrr
 UhUCC M;,..SFICLU '10. i:
                                                                                                                                 "5775"
                                                           CKL.MC.O
                                                                                              COAL _ i.j PLKCENT  SULFUR
      UL\HHi,,  rLi-'Cl K I'tT
 EUorsTor,t  t-o  i
"G"UsO";i r.o.'?"

"SCCTTiLTn  C.i7
                                                  650
                                                       KAG'.-fc.i>iof, OXIDE


                                                       I-.OT  SELLC7LD
                                                       ' Lir'.L/Ll>'.LS ICN:L
                                                                                         "COAL    2T5~P i K cT N r~s 0 LF u R~
                                                                                              COAL
                                                                                                                                 12/71*
                                                 TTb'iT
                                                                 ' 0'IL VROuuC

                                                                  SCKUEBIiJG

-------
            	     TAbLil  1.2	
             Ft Li .SYSTO.S  UMIEK cowslTUcTToN AS OF  10/71*
        UTILITY" CONPAHY
         POWER STATION
     b'k   SIZE:  OF'TGU
HLTROFIT	UNIT JHW>
      CHAKACTERISTICS
MO/YR
 SOUTllWESTEKN PUbLlC SLuVlCL
     iNETon NO i	
_SPKINGFI CLP UTILITY
 S"OUTnWE".sT NO 1
                  AUTHORITY
 WIOQkS CHEEK NO
                       COf-bUil lOi'j
                                    f: SCKUbBUvG
                                               b50
                       U(vIVE.SaL_OIL _
                       LI.v.tSTON: SCRUBBING
COL   0.5 PtKCENT  SULFUR


COAL
                                 VALLEY  AUTHOKITY
                                 SCRUBBING
COAL   3.7 PERCENT  SULFUR
 6/76


 6/76
 1/77

-------
                                  13
      ~PLAI."f  FGD  VLt^uOK/PKocEss
                                                                                                       FUEL CHARACTERISTICS
                                                                                                                                          KO/YR
                    CONTRACTS
      LOU ISV H LE  f\flS..8__LLLC_TKl_C_
      CA;-JE  RuY. jjjo "
                                            178
                . ,lR  F.1LTL'H_
             i>CHUbtiI!'J&
_CO.AL____5,.b-!..g5__P_ERCENT. SULFUR   ..6/75	
      COLUi-ipUi> a.  SOUTHEMv  OnIO
	CCr-iLSVlLLE_N9_.5	
                                            37b       UlilVLrtiiAL  OIL PRODUCTS
                                               	LJME. SCRUbbING    	__
                   sou THERM  &hio
                   7ii' 6
                                      	J7b   	UlvIVtriSflL  OIL PROpucTS
                                                      LIME.
                                                                                                      COAL
                                           COAL
                                                                                1/76
                                                                                1/76	
      LOUISVlLLt  GAS S LLE.CTIUC
      ;-'ILL CKC;:*  :-.-o 3        	
                                                                 1R FILTLK
                  .
      CitOLLA i.O  2
                                                         2bO
                                                                                         COAL    3.b-  ^.0 PE1KCE.NT SULFUR    6/77


                                                                                        _COAL	0._H^  PE_RCEhlT...SULFyR
      TEXAS UTILITIES
                                                      KtbLAiTIOI(
                                           COAL
                                                                                                                              6/76
  	GLNlf'.AL  PUi-LlC _Ujj'.n IF S
                                            bbO
                                                      NOT SLLECTLD
                                                                                         COL 2.8  PERCEfJT  SULFUR	Jt/77	

-------
                  	T/MiLL  13	
                   PLANNLU rsii SYSKNS AS OK  10/74
               POUPR STATION
                                         NEW OR    SIZE OF FGO   VENDOR/PROCESS
                                                      KUEL  CHARACTERISTICS
                                                                                                                                   KO/YR
      ARIZONA  PUbLlC SERVICE
     __Q HO L L A_jj 0 .3.	
                                                     250
                   NOT SLLEC1EO
                              SCRUHBINr, __________
      COAL   o.1*'*  PERCENT SULFUR
                                                                                                                                     6/78
	C L NT_R AL  ILL J.N0IS CUULlC  SCRV
      ME.WTOW IvO.l
                                                    _600
                   lyOT_ SLLEC1EO
	COAL 2.8-3,2..PLRCE:NT_.SULFUR _	  3/77 ._.
      1N01ANAMOLIS fOWEH ANf)  LIGHT
      t'ETLRSt'UKG MO 3   	
          515
                                                               NOT  SLLLCILO
                                                               LIflL/LlMLbTOME:  SCKUDUIMG
      COAL  3.0-3.5  PLRCENT SULFUK
                                                                                                                                     H/77
 _   KANSAS POh'l.H  S LIGHT    	        f.	70g	COMiUSTIUU
  " ~JEf-Fr.RY 'IIP. 2"  '              "                 ""       'LIE-.LSIONC s
                                                                                                 .COAL
                                                                                       . 6/79
                MISSISSIPPI  PWH  COOP
	HATT ICSBU.RG ..MC . 2	
                   PUB SERV/
          223
                                                               NOT  Sc-LL'ClLO
                                                                        . SCRUBBING
                                                     COAL
                                                                                                                                     6/79
N	140	f.OT  SLLLCTLD     .  . 	COAL   1.0. PERCENT  SULFUR 		  ...5/77.
                   L I'1/L IKEil ONE
     TEX.S UTlLlTlF S

N5
0 _ T*AS UTILIJirS
       "  fJ  LAKE  NO.'s"
                                                      793
                                                                KESLAnCH COTTKLLL
         _793
                                                                RESEARCH CGHKLLL
                                                               'L SCRUublNG
      COAL O.H4 PERCENT SULFUR


      COAL 0.44 PERCENT SULFUR
                                                                                        12/79


                                                                                        12/78
      SOUtl.r-.\  i'lSilSSlf-PJ  P^H LOOP
          .S  UTILITIES
                  f;~0 ~3
                   Ivul  i>LLCC~!LD
                   LlfLbTO.'ab: SCKUl'BING
                                                                                                 COAL
          600
                                                              _IJOT  SELtCTLU
                                                               LiNESioNL SCRUUB'ING
      COAL   O.b-  1.0  PERCENT SULFUR   12/78
                   CPNSILLKlr.G F
      . L&Uisy iLLE r.a_s z._i LI cjnu_c_
      Chi-iH  h'Ui,  MO 1
         _11C	kuT  StLECTLU
                   Lir''E  SCKUbblNG
                                                                                                 COAL   3.5-  4.0  PERCENT SULFUR    6/60
      COLORADO
      CCLuliAijt:  l.'U. fLfCT
            'Sl'/iT'jcV;' f.O.i"
                   fiOT  SLl.L'CIEU
                   Llf'LSUiiL SC

                   ;-.OT  SLLLCFLfJ
                                                                                                 COAL   o.*b  PERCENT SULFUR

                                                                                                 COAL 0.45 PERCENT SULFUR
                                         6/78
                                                                                                                                     6/78
      COLORADO L'U
      CRAIG  STATION fM0.2
              .-.TI (AS_AU,_LLf_CTRlC_
      'EAST  DE-'."ij"r".V."i
                        SLLLC1EO
                       'SLwLC TLD
                                                                                                 COAL 0.45  PERCENT SULFUR          6/78


                                                                                                 COAL   O.b-  0.8 PERCENT SULFUR    6/79

-------
                                 13
                  _        ______
                   PLANNLU FGU bfSTLHS  AS OF  11J/71*
                                              "OR	SrZE~OFTG"D  VlNDCR/PKOCESSFULL' CHARACTERISTICS            HO/YR
                     STATION             RETRGf-ir    UtJIT
            'A LLEC1HIC COOKi5         225       MjT StlLTCTL"BC0"L    O.b-
      BIGBEE NO  3                                               LIML'SIOUE SCRUBBING
      BASIN ELECTRIC                        N         550       NOT  SELECTED                      COAL
     HlaSOljFl  BASTN'NO  2                              '         LTMES1 0,'j SCRUBBING"
      l3ASIii ELi-CIK 1C                        l'i         550
      MISSOURI  E/vMN NO  3                                       Ll^'LSlONE SCRUBBING
      BASIN ELECTRIC                        N         550	   r.uT  SELECTED                      COAL                                 6/79
     -MISSOOK !"~Q'AiriTr~N"fr~i	LTMLSI ONC
                  !-AS f. LLLLTRit                     fZ5       TUT  SLuCCTCD"
      MLL Cf'EEK  r-0 4                                           LIKE
      LOUISVILLE  CAS &  ELECTRIC            K         330       IvCT  SELECTLO                      COAL    3.5-  "*. 0  PERCENT  SULFUR
                  fTO~l                                           L"1HE '!>cr;OT  SLLECTEC)                      COAL    14.3 PERCENT SULFUR         8/78
                             ?               h         rrs       cun-vjco  "                        covru    o".s~PF>\cci'rr SULTJR        i2'/7i6"
      FCUK cOK-ifl-.S i.'O  ?                                         LOT
            iA  PUtiLjC SERVICE	t<	229	   ChEF'ICO        	                COAL    0.6 PERCENT SULFUR         3/77
           CCft'hEK? NO  3                     "                 '   "Ll'i'iL          """  "               ""
      : . 0H I HLi<:. ~I T-. r > iA:t  Pub SEnVICL         R         T51;       TTOT
      15AILY  -JC.7                                                NOT  SttLCTED

-------
               ___ _
                HLArif._.U~ F"(,U
                                       S  AS  01- l~J/7t
             "UTILITY  COfiHA'iY"
               POVE.K STATION
                                        IV'E.*  OR "  "SlZL Of FGD  VEfcUdh/PKUCESS
                                      RETROFIT    UNIT (M*!>
                                                           FULL  CHARACTERISTICS
                                                                                              MO/YR
                         PUb
                                                     uoo       NUT SLLECTLD
                                                    	  N-OT SL.LCCTLO
     . AKIZO..:A.. PUbl_..C .St_j..V.ICL.
      FGUr<  COh JI.HS  MO  H
__ K __________ 6QO
                                                               .CHEMLG
                                                               LIFE  bC
                                                          COAL  3 PEKCtNF  SULFUR
                                    ..COAL  _u.<.  PtKCtNf  SULFUR
                     FLECTHIC
             203
                                                               r:uT  SLLECTLD
                                     COAL   0.<4b  PLKCEf.T  SULFUR
                                                                         O/  0
                                     1/77
                                     6/78
              -ANTI CI.FC SY-.Jt;.L	_r<	(,5^	ncT  SLLLCTLD                       COAL  0.3 PLRCE.NT  SULFUR            o/ o
               PCI..T  l.o.'i 	" "	"      	      MOT  SLLECli-O	"
        jfi.i  PUiUlC  SCKV1CF.                H         17b       Li-.LMCU
	FOUR  CQ^'-'ES .L.f!P_!			L I'"'t.  bC
                                                                                                      COAL    0.0 PEKCEWT SULFUR
              .
      CGLSTFlC COOP
      LIOnCL  ;.-.) 2
                           SLLECILlJ
                               -'.Elv'"r!E. SCKW(.;>_KiG
                                                                  r  SE.LLLTLD
                                                                i.-.tS iO.;C i>CKUbb'l:G
                                                                        10/76

                                                                         7/7Q

                                     COL   3b-  M.O PEKCENT SULFUR6/80

                                     COAL _o,7  PERCENT  SULFUR          0/79

                                                    	                  6/77"
              SLKVKC  OF ULW  f-iLXlCO
      SA;J  JUAI. MO.J
   PL'i.LIC  S.Crt
   SA'j  jL.'\
                       P.F_.(vL>'_j_'LE_X_lC_0_
             sou

             500
 I.UT vSLLLClt-U
 I:OT SLLECILO

 :'IOME

-------
                                  i a                	


                                     	IvE,~OR -sm-OF  FGiy  VO\;>G,\/P,
-------
        STATUS OF FLUE GAS DESULFURIZATION TECHNOLOGY IN JAPAN
                              Jumpei Ando


                  Faculty of Science and Engineering

                           Chuo University

                       Kasuga, Bunkyoku, Tokyo
The regulations on S02 emission have become increasingly stringent in
Japan, forcing industry to install flue gas desulfurization (FGD) units.
Major power companies have decided to install full-scale FGD plants for
utility boilers with capacities larger than 30MW.  All of the large plants
will use wet processes by-producing gypsum.  The present paper will
comprehensively describe wet lime-limestone processes and double
alkali FGD processes.  In addition, three new processes, the Mitsui
Miike limestone process, the Kurabo ammonium sulfate lime process,
and the Dowa aluminum sulfate limestone process will be described in
some detail.
                                125

-------
        STATUS OF FLUE GAS LESULFURIZATION TECHNOLOGY IN JAPAN
I  Foreword

The oil crisis of late 1973 and the serious inflation resulting from it
has affected considerably Japan's energy and desulfurization policies.
Efforts more strenuous than "before are to be made for the development of
atomic energy and the import of LNG and coal.  Imported crude oil which
has supplied more than 70% of the total energy needs of Japan and has
been the major source of S02 emission is expected to continue increasing
at an annual rate of 7% as against the 20-30% in the past.  On the other
hand, construction of many plants for hydrodesulfurization and gasification
desulfurization of oil to reduce sulfur contents to below 0.3% which was
planned eagerly in early 1973 wa-s postponed or given up because of the
inflationthe investment cost which was about 30 million dollars for
a plant has nearly doubled.

The regulations on S02 emission have become even more stringent and have
forced industry to install flue gas desulfurizers.  Major power companies
have finally decided to install full-scale S02 removal plants for
utility boilers with capacities larger than 300MW.  All of the big plants
are to use wet processes by-producing gypsum because the reliability of
the processes has been well demonstrated and the demand for gypsum is
growing.  Most of the large units are to be located outside city limits,
because even 90% removal of S02 may not be satisfactory in the future
in urban areas.  Tokyo Electric Power, for example, has started to burn
a considerable amount of LNG which gives off no S02 although it is
expensive.  Another reason for using LNG is the low NOX emission involved.
NOX has aroused serious concern in Japan recently because of photochemical
smog which has plagued big cities for the last few years.  Simultaneous
removal of S02 and NOX has been enthusiastically studied by many
organizations although there seems to be much difficulty involved in
the process.
II  Introduction
At the FGD symposium of EPA last year, the author reviewed seven major
processes in Japan, namely those of Mitsubishi-JECCO, Chemico-Mitsui,
Chiyoda, Wellman-MKX, Kureha-Kawasaki, Showa Denko and NKK.1'  The
present paper will describe comprehensively the technology and problems
of wet lime-limestone processes, double alkali type processes and others.
Some detailed description will be given on three new processes which
might be of interest for application in the U.S.A., namely, the Mitsui
Miike limestone process, the Kurabo ammonium sulfate lime process, and
the Dowa aluminum sulfate limestone process.
                                126

-------
Ill  Wet lime-limestone process

S02 removal plants using wet' limelimestone processes  with a capacity
larger than 20MW equivalent are listed in Table 1.   The Mitsubishi-JECCO
process has been used most widely' for oil-fired boilers,  iron-ore  sintering
plants, etc. while the Chemico Mitsui and Mitsui -Miike processes have
been applied to coal-fired boilers.   Five other processes have  also been
used mainly for flue gas from oil-fired boilers. Many of the plants use
lime to obtain a high SC>2 removal efficiencymore  than 90%which is
required in many districts in Japan.   Limestone scrubbing removes
85 to 90% of the SC>2 at 0.9 to 1.2 stoichiometry by using a scrubber
nearly twice as tall as that using lime.

A flow sheet common to most processes except the Chemico-Mitsui and the
Mitsui -Miike processes is shown in Figure 1.  Types of scrubbers and
examples of operation parameters are listed in Table 2.
               Cooler
                           Scrubber
                                 tOC
                                       '.Vater    After  burner
                                 r -

                                 y_	}20C
   Waste-
    water


6-
j
1



Demister
Oxidizer
k






<- f\r*. t- Y*f

il 1 or>
A



Centri





                                                           "Air
.-'liter
                           Neutralizcr
                                                                       V
                                                                   Gyosum
        Figure I  A Schematic  of  the wet  lime-limestone r-rocoar-
 Cooler  Flue gas from the electrostatic precipitator is first led into the
 cooler or prescrubber where the gas is sprayed with water.  The cooler, which
 is not usually used in the United States, has two functions.  (1) Cooling and
 humidifying the gas in order to aid in the prevention of caking in the
 scrubber.   (2) Removal of dust and other impurities in the gas which were
 not  caught  by the  electrostatic precipitator.  This is useful in obtaining
 high purity by-products with good commercial value.
                                 127

-------
                    Table 1  Sulfur dioxide scrubbing installations in Japan (lime-limestone scrubbing)
00

Process developer
Mitsubishi- JECCO
n
n
11
n
it
it
ti
n
it
it
tt
11
it
it
it
it
it
11
n
Chemico-Mitsui
Mitsui- Miike
ii
11
Bahco-Tsuki shima
Babcock-Hitachi
11
Ishikawa j ima-TCA
Sumitomo-Fuji Kasui
Chubu-MKK
"

User
Kansai Electric
Onahama Smelter
Kawasaki Steel
Kansai Electric
Tohoku Electric
Tokyo Electric
Kyushu Electric
Kawasaki Steel
"
n
Kansai Electric
Teijin
Mizushima Power
Niigata Power
Kyushu Electric
"
n
11
Chugoka Electric
"
Mitsui Aluminum
ii
"
Elec. Pow. Dev.
Yahagi Iron
Chugoku Electric
"
Chichibu Cement
Sumitomo Metal
Ishihara Sangyo
Mitsubishi Gas

Plant site
Amagasaki
Qnahama
Chiba
Hainan
Hachinoe
Yokosuka
Shinkanda
Mizushima
n
Chiba
Amagasaki
Ebime
Mizushima
Niigata
Katsura
"
Ainoura
it
Oase
"
Omuta
M
tt
Takasago
Nagoya
Mizushima
Tamashima
Kumagaya
Kokura
Yokkaichi
"
a Actual for boilers and equivalent gas flow for

Absorbent
Ca(OH)2
tt
ti
it
n
CaCOj
Ca(OH)2
11
11
"
"
"
11
CaC03
11
M
"
"
Ca(OH)2
"
"
CaCOj
11
"
Ca(OH)2
CaCOj
"
Ca(OH)2
n
CaCOx
Ca(OH)2
others (at
A Vl
MW Type of plant
30 Utility boiler
29 Copper smelter
37 Sintering plant
150 Utility boiler
125 "
130 "
175
232 Sintering plant
279 "
130 "
125 "
83 Industrial boiler
192 Utility boiler
117 "
250 "
175
250 "
250 "
375
375
119 Industrial boiler
25 "
175C
250 Utility boiler
26 Sintering plant
104 Utility boiler
500 "
62 Diesel engine
32 Heating furnace
77 Industrial boiler
22 "
1900scfm per MW).
Year of
completion
1972
n
1973
1974
"
"
"
"
1975
11
"
"
11
11
11
1976
"
"
11
it
1972
1974
1975
1974
1971
1974
1975
1972
1974
"
11

Gypsum
(tons/day)
20
450
16
22
53
20
77
130
100
30
42
93
105
47
75
50
105
105
365
365
d
22
220
220
28
28
385
24
28
55
13

b Boilers are oil-fired unless noted.
c Coal -fired.
d Waste sludge of

calcium sulfite.











-------
                Table 2  Example of operation parameters of FGD plants "by-producing
                         gypsum and calcium sulfite

Process developer
Wet lime-limestone
Mitsubishi-JECCO
it

Chemico-Mitsui
Kitsui Miike
Babcock-Hitachi
Chubu-MKK
I shikawaj ima
Sumitomo-Fuji
Absorbent,
precipitant
(stoichiometry) lj
process
Ca(OH)2 0.9-1
CaCO^ 0.9-1
j
Ca(OH)2 1-1.05
CaCO* 0.9-1
x
CaCOj 1-1.2
CaC05
Ca(OH)2
Ca(OH)2 1-1.2
Capa-
city
Type of
Slurry or
solution
.OQOscfm absorber pH conv.%

210
230

210
44
180
150
60
37

GPa)
GP

Venturi
Venturi
ppb)
Screen
TCA
ppb)


5-6

7
6
6.2
6

6

15
12

3-5
5
7-8
10
2
10
L/G Space
gal/ velocity
L,000scf ft/sec

30-50
50-70

80-100
80-100
50
70
50
70

10
10



12
12
10
12
pressure
drop S02 Ppm
inches in

6
5

16

20
3

18

1,000
250

2,000
2,000
500
1,500
700
1,000
out

80
20

200
200
60
200
50
50
Moisture
% of
gypsum

10
8-10


10-15
8-10
10-12
10-15
10-12
Indirect lime-limestone process
Kureha-Kawasaki
Showa Denko
Nippon Kokan
Chiyoda
Kurabo
Dowa
Hitachi-Tokyo Elec.
Na/jSOzjCaCO;,
Na2S03,CaC03
(NH4)2S03,CaC03
dil.H2S04,CaC03
(NH4)2S04,Ca(OH)2
Al2(S04)3,CaC03
Carbon, CaC03
230
255
90
466
3
82
250
GP*)
Cone
Screen
Tellerette
Tellerette
Tellerette
Packed
7
6.8
6
1
3-4
3-4

20
25
30
2-4
10
10

7-15
7-15
14
200-300
40-70
20-60



10
3
6
4
1.5
8

10

2
4
19
800
1,400
700
600
1,500
600
500
20
40
30
50
80
20
80
5-6
7-8
10
6-8
8-10
10-12
10-12
a)  Grid packed                  b)  Perforated plate

Pressure drop includes that of absorber and mist eliminator

-------
 Scrubber  The type of scrubber is a plastic grid packed tower for
 Mitsubishi-JECCO, a venturi for Chemico-Mitsui and Mitsui Miike, a TCA
 with polyethylene balls for Ishikawajima, a Bahco type for Tsukishima,
 a stainless steel screen type for Chubu-Mitsubishi Chubu-MKK (CM), and
 perforated plates for Babcock-Hitachi and Sumitomo-Fuji Kasui processes.
 The reliability of the Mitsubishi-JECCO and Chemico scrubbers has been
 well demonstrated in Japan.  The former has less pressure drop.  The
 TCA scrubber has a high S02 removal efficiency but presents the problem
 of wearing of balls.  The Bahco and screen type scrubbers might be more
 susceptible to scaling.  The perforated plate scrubber for the Sumitomo-
 Fuji Kasui process (Moretana type) is designed to give extreme turbulence
 producing foam layers 15-20 inches thick; a high SC>2 removal efficiency
 is attained while heavy mist is formed.

 For the Chemico-Mitsui and Mitsui Miike processes,which use no cooler,
 the scrubber is operated with a dilute slurry at a large L/G ratio to
 prevent scaling.  The by-product contains a considerable amount of
 impurities as will be described in the author's other paper at the
 present symposium.2)

 Water balance  In most plants, the mist eliminator and by-product gypsum
 are washed with fresh water.  The wash water is then fed mainly into the
 scrubber system and partly into the cooler.  Some fresh water is also fed
 into the cooler.  The amount of total input water more or less exceeds
 the output, i.e. water volatilized and taken into gypsum as water of
 crystallization and moisture.  Therefore, a portion of an acidic liquor
 from the cooler is sent into the watertreatment system, neutralized
 with lime to precipitate heavy metals and other impurities, filtered,
 and then purged.  The water balance is thus maintained.  The use of
 fresh water and the purge of some wastewater help in the prevention of
 caking and corrosion.

 It would be possible to apply a closed loop which would release no water
 from the system and yet not cause scaling.  The accumulation of chlorine
 in the system, however, would cause corrosion problems.  Also, the use
 of highly resistant materials would add considerably to the cost.  Tohoku
 Electric Power Co. first planned to use a closed system for a 125MW plant
 based on the Mitsubishi-JECCO process, but the investment cost increases
 with the closed system; Tohoku finally changed the plan so that some
 water is purged after being treated.

 Oxidation  The rotary atomizer invented by JECCO has been used for
 the Mitsubishi-JECCO, Babcock-IIitr.chi, a;ic Chubu-MKK processes because
 of its high efficiency and reliability.  Different types of oxidizers
 have been developed for other processes.  Low pH (55~40) is desirable
 for oxidation of calcium sulfite slurry.  This is attained with a pH
controller by adding a small amount of sulfuric acid as is being done
at many plants, or by using flue gas and a catalyst as in the Mitsui Miike
process.  The facilities to produce gypsum, pH controller, oxidizer and
centrifuge, occupy about 40}o of the total investment cost.  Nevertheless,
the production of gypsum has been growing in Japan,  Mitsui Aluminum Co.
                                 130

-------
                               Table 3  Indirect lime-limestone processes (double alkali type)
\I
LJ


Process developer
Nippon Kokan
Chiyoda

ii
n


"

"
Kureha-Kawasaki

n
Showa Denko

"
Showa Denko-Ebara
"
n
11
n
"
11
Tsukishima
"
Kurabo Engineering
"
D
-------
which has been producing waste calcium sulfite sludge will also change
the process to by-produce gypsum as will be described later.  By-
production of calcium sulfite sludge and its stabilization as it is being
done in the United States might be of much interest in the future in
Japan when there is an oversupply of gypsum.
IV  Indirect lime-limestone process (double alkali type)

Many double alkali type processes that use lime or limestone as a
precipitant have been developed in Japan including those which use an
acidic solution or acid as the absorbent.  The Hitachi-Tokyo Electric
process uses activated carbon as the absorbent and limestone as the
precipitant.  All of those processes are classified in the category of
"indirect lime-limestone process".  The installations with a capacity
larger than   20MW equivalent are listed in Table 3  The operation
parameters are shown in Table 2.

Wet process  The various processes use different absorbents; a sodium
sulfite solution is used for the Showa Denko, Kureha-Kawasaki, and
Tsukishima processes, an ammonium sulfite solution for the KKK process,
an acidic ammonium sulfate solution for the Kurabo process, an aluminum
sulfate solution for the Dowa process, and a dilute sulfuric acid with
iron sulfate for the Chiyoda process.  The pH of the solution is 6 to 7
ammonium and sodium sulfites, 3 "to 4 for ammonium and aluminum sulfates
and 1 for sulfuric acid.  The L/G ratio is 7-15 (gal/1,OOOscf) for the
solutions with pH 6-7, 20-70 for the solutions with pH 3-4 and .200-400
for the acid at pH 1.  The more acidic the solution is, the less the
S02 absorption capacity, the lesser the problem of scaling, and the easier
the reaction with limestone.  Limestone can be reacted with a sodium
bisulfite solution, as in the Showa Denko and Kureha-Kawasaki processes,
but the reaction occurs slowly requiring large reaction vessels.  Lime is
used for the Tsukishima, NKX, and Kurabo processes.

For the Chiyoda, Dowa, and Kurabo processes, the liquors which absorbed
S02 are contacted with air to oxidize SOj   '. uto 864,"*""  Lir-esume
or lime is then added to precipitate gypsum.  For other processes,
limestone or lime is added first to precipitate calcium sulfite which
is then oxidized into gypsum.  By the double alkali type process,
gypsum usually grows in larger crystals than with the wet lime-limestone
process.  Moisture content of the by-product gypsum after centrifugaliza-
tion ranges from 6 to 12% as compared with 8-15% fr the wet lime-limestone
process.

The liquor from the gypsum centrifuge is returned mainly to the scrubber
system.  Softening of the liquor which is usually needed to prevent
scaling, is not necessary when an acidic solution at a pH below 4 is used.
                                 132

-------
At most plants, a small portion of the liquor is purged to maintain
the concentrations of chlorine, magnesium and other impurities under a
certain level.  Calcium sulfite obtained "by the slow reaction of limestone
and sodium bisulfite grows into fairly large crystals which are not
difficult to handle,2;  On the other hand, lime reacts rapidly with a
sodium bisulfite solution to give very fine crystals of calcium sulfite
like those prodiiced by the wet lime-limestone process,

Carbon absorption  Another type of the indirect lime-limestone process is
dry activated carbon absorption which is used in the Hitachi-Tokyo Electric
process.  The carbon which has absorbed S02 is washed with water to
give a dilute sulfuric acid of 15-20% concentration.  The acid is treated
with powdered limestone to produce gypsum, which is centrifuged to 10-12^
moisture.  The process requires large absorption towers because low gas
velocity (l,5 ft/sec) is used to obtain 85-90% removal of the S02
Hitachi has recently operated a If700scfm pilot plant in which S02 is
absorbed with a carbon slurry.  The resulting sulfuric acid is treated
with limestone to obtain gypsum.
V  Other processor
There are about one hundred relatively small sodium scrubbing plants in
operation by-producing mainly sodium sulfite and some sodium sulfate,
Those processes were reviewed last year!) and there has not been much
progress since then.  Major plants using other processes are listed
in Table 4,

Wellman-Lord process  Many plants using the Wellman-Lord process have
been constructed by Mitsubishi Chemical Machinery Co, (MKK) and also by
Sumitomo Chemical Engineering Co. (SCEC),  The reliability of the process
has been well demonstrated,  A main problem in the process is the oxidation
of sodium sulfite into sulfate which does not absorb S02.  The sulfate
has to be removed from the system, resulting in the loss of sodium and the
need for wastewater treatment.  At Nishinagoya Plant of Chubu Electric
(220MW), 7 tons/day sodium hydroxide have been used for make-up giving the
equivalent amount of sodium sulfate,  SCEC uses an oxidation inhibitor to
reduce the sulfate formation to below half.  The inhibitor, however, might
give some trouble in wastewater treatment by disturbing the oxidation of any
reducing component in the water.

Magnesia scrubbing  Two plants are in operation and one is under construc-
tion with different magnesium scrubbing processes, by Mitsui Mining,
Onahama-Tsukishima, and Chemico-Mitsui,  A common feature of these
processes is the production of large MgS04'6H20 crystals (200 microns
or so) which are much easier to filter and dry than are the small
MgS043H20 crystals.  Both the Mitsui Mining and Onahama plants have no
problem in the filtration and drying steps which were troublesome at Boston
Edison Co.  A nearly completed Idemitsu Kosan plant based on the Chemico-
                                 133

-------
                     Table 4  Sulfur dioxide scrubbing installations in Japan which by-produce
                              sulfuric acid and sulfur


Process developer Absorbent TTser
Wellman-MKK Na9SO,
^ j
n it
it ti

n it
ii ii
n 11
it n
it 
n n
Wellman-SCSC "
n n
(-
 n 
it ti

n n
Onahama-Tsukishima MgO
Mitsui Mining "
Chemico-Mitsui "
Sumitomo Shipbuilding Carbon
Shell CuO
Mitsubishi-IFP (NE^^SO:
TEC-IFP 
Japan Synth.
Rubber
Chubu Electric
Japan Synth.
Rubber
Toyo Rayon
Mitsubishi Chem.
Company K
Kurashiki Rayon
Company KKK
Company SKD
Toa Nenryo
Sumitomo Chiba
Chem.
Fuji Film
Sumitomo Chiba
Chem.
Sumitomo Chem.
Onahama Smelter
Mitsui Mining
Idemitsu Kosan
Kansai Electric
Showa Yokkaichi
* Maruzen Oil
Fuji Oil

Plant site
Chiba

Nishinagoya
Yokkaichi

Nagaya
Mizushima
Kawasaki
Okayama
Kashima
Yokkaichi
Kawasaki
Chiba

Fuji
Chiba

Niihama
Onahama
Hibi
Chiba
Sakai
Yokkaichi
Shimozu
Chiba

MW*
70

220
150

103
186
217
127
400
124
25
120

50
180

50
28
25
162
53
37
14
3

Year of
By-product
Type of plant completion (tons/day")
Industrial boiler

Utility boiler
Industrial boiler

"
ti
"
it
n
n
Glaus furnace
Industrial boiler

ti
n

n
Copper smelter
1*2804 plant
Glaus and boiler
Utility boiler
Industrial boiler
Glaus furnace
"
1971

1973
1974

it
it
11
it
11
it
1971
1973

1974
1975

11
1972
1971
1974
1971
1974
"
"
H2S04

11
"

n
n
11
11
it
n
S
H2S04

Liquid S02
H2S04

n
it
ii
S
H2S04
S
S
S
44

88
44

50
88
110
66
120
60

55

13
88

25
240
18

17



a  Actual for boilers and equivalent gas flow for others.  Boilers are oil fired.

-------
Mitsui process is to return the recovered S02 to a Glaus furnace for
sulfur production;   the other plants by-produce sulfuric acid.

Dry carbon process  By the Sumitomo Shipbuilding process, the S02 absorbed
on activated carbon is expelled by heating it in a reducing gas, to release
S02 gas of 10-20% concentration which is used for sulfuric acid production.
Moving beds are used for both absorption and desorption.  The operation
has been carried out smoothly but there is no further plan to build
larger plants, presumably because of the requirement of large absorbers and
the considerable consumption of carbon.

Shell process  In the Shell process, S02 is absorbed with copper oxide to
form copper sulfate, which is then reduced with hydrogen to expel S02
A commercial plant started operation several months ago at Yokkaichi.
The process seems fairly costly requiring a large absorber and hydrogen
although it has the advantage of a dry process which requires no
reheating of treated gas.

Ammonia scrubbingIFF process  The Mitsubishi-IEP process uses ammonia
scrubbing with the thermal decomposition of ammonium sulfite and sulfate
to regenerate S02, which is then reacted with H2S in an IFF reactor to
produce sulfur.  A plant at Shimozu started operation several months ago.
A similar plant has been recently constructed by Toyo Engineering for
Fuji Oil.  The process is not simple and may need further improvement
before satisfactory operation is attained.
VI  Mitsui Miike limestone gypsum process
Outline of process  This process has been developed by Mitsui Miike
Machinery Co. (.1-1, 2-chome, Nihonbashi Muromachi, Chuo-ku, Tokyo).
302 is absorbed with a limestone slurry containing a catalyst which
promotes the reaction.  The resulting calcium sulfite slurry is oxidized
into usable gypsum by further contact with flue gas and air.  The catalyst
also promotes the oxidation.

State of development  Mitsui Miike constructed the desulfurization unit at
the Omuta plant of Mitsui Aluminum Co. which has been operated successfully.
The disposal of calcium sulfite sludge, however, is a considerable problem
because of the poor nature of the sludge.  In order to by-produce usable
gypsum, Miusui Miike has developed a new process based on a patent by
Dr, S* Akimoto using a catalyst that promotes both the reaction of S02 and
limestone and the oxidation of calcivm sulfite.  After tests with a pilot
plant with a capacity to treat coal-fired flue gas at 2,500NmVhr
(l,500scfm), a larger test unit (75OOONm5/hr of coal-fired flue gas)
was completed in September 1974 at Omuta.  A commercial plant at the
Takasago Station of the Electric Power Development Co. with a capacity
of treating 800,OOONm3/hr flue gas from a coal-fired utility boiler
(250MW) will be completed in late 1974.  Mitsui Aluminum will install a
552,OOONm3/hr unit (175MV) in 1975-


                                 135

-------
 !r_oc.ess description  A flowsheet of the process is shown in Figure 2.
 'lue gas is treated in two venturi scrubbers in series with a counter-
 current flow of limestone slurry containing a metallic catalyst.  The
 resulting calcium sulfite slurry is then fed into a pH controller where
 the slurry contacts a portion of flue gas'(5-10% of the total) to lower
 the pH and to complete the reaction of limestone with S02.  The slurry is
 then pumped into an oxidizing tower into which air is blown from the
 bottom to convert the sulfite into gypsum.   The gypsum slurrv is centrifugec
Most of the liquor from the centrifuge is used to prepare a limestone
 slurry.  A small portion of the liquor is sent to a wastewater treatment
 system to prevent the accumulation of impurities.  Gypsum grows into large
 crystals of 50-200 microns in size and can be used for wallboard and cement.

The catalyst prevents the formation of a calcium sulfate coating on
 calcium sulfite and carbonate and thus promotes both the reaction of the
 carbonate with S02 and the oxidation of the sulfite into sulfate as shown
 in Figure 3 and Table 5 which are based on the pilot tests.  There is
virtually no loss of catalyst into gypsum because gypsum can be washed
 well.  In the above-mentioned wastewater treatment, the catalyst can be
 precipitated in the form of hydroxide by raising the pH and returning
 it to the absorbing system.

 The capital required is about 50/6 higher for the lime-calcium sulfite
 sludge process.  The pH controller and oxidizer add about 20% to the
 cost.  If about 80% oxidation is satisfactory to improve the settling
 property in the disposal pond, as in the partial oxidation of the sulfite
 sludge, then the oxidizing system can be greatly simplified.  The pond
 should be sealed to prevent the leakage of water containing the catalyst.

          Table 5  Example of the composition of by-product (%)

                   (stoichiometry 0.95)

            Absorbent
                                   QQ p
        CaCO} -f Catalyst           J

        CaC03 only                 71.0          15.3       12.3


Advantages  High S02 recovery is attained with limestone  slurry.
Oxidation of calcium sulfite occurs rapidly.  S02 in flue gas is used
for pH adjustment instead of using sulfuric acid.

Disadvantage  The facilities for oxidation add considerably to  investment
cost.
                                  136

-------
Flue    ",",     scrubber
                          After burner
                  1
                  1
                                               Mill
iD^i U
-, '
i,v




I U UtJI
(-
1

I
1 1
1
1
* 1









1




.-,
1
r y






V
(  
1
1
l 	

iitack




Tank





i






^


^










^









  pH
controller
                TOxidizer
                  Air
                                        Gypsum
 Figure  2   Flowsheet  of  Mitsui  Miike  limestone  gypsum process
        o
        5 90
        Q)
        (M
        O
             0.9      1.0       1.1
            StoichiometryC for  inlet
                                          1.2
        Figure 3   Effect of catalyst on
                   removal efficiency
                               137

-------
                                           4)
VII  Kurabo ammonium sulfate gypsum process
Outline  This process has been developed by Kurabo Industries, Ltd.
(2-41, Kitakyutaromachi , Higashi-ku, Osaka).  S02 is absorbed by a
slightly acidic ammonium sulfate solution at pH 5-4.  The solution is then
oxidized by air to give an acidic ammonium sulfate solution, which is then
treated with lime to precipitate gypsum and to recover aqua ammonia which
is returned to the absorbing system.  Ammonium sulfate can be produced,
if desired.

State of development  Kurabo has built several small ammonia scrubbing
plants in addition to many sodium scrubbing plants.  Plume formation,
the greatest problem for the ammonia process, has been fairly well solved
by the use of a cold, dilute solution but this method may not be suitable
to larger plants.  Kurabo has recently developed a method to use an
acidic ammonium sulfate solution as an absorbent to eliminate the plume
and has successfully operated a 2MV equivalent test unit.  Two commercial
plants are presently under construction (Table 3).

Theory of absorption with ammonium sulfate solution  Plume can be
eliminated by the use of an acidic absorbing liquor because the vapor
pressure of NH3 is less than Ippm with a solution at a pH lower than 4.
The acidic ammonium sulfate solution has a larger capacity of S02
absorption than plain water or a saturated calcium sulfate solution as
shown in Figure -t because of the smaller pH drop due to the following
equilibrium in the ammonium sulfate solution:
The minimum L/G ratio (liter/Nm?) required to remove 95% f the S02 is
shown in Table 6.  The relationship of L/G to S02 removal efficiency is
shown in Figure 5  Basic data for the design of S02 absorbers
obtained through the pilot tests are shown in Table 7

           Table 6  Inlet 302 concentration and minimum L/G
                    (gal/1, OOOscf, 60C, 95% S02 removal)

     _ Absorbing liquor _     Inlet S02 concentration, ppm

     Composition         Initial pH     1,000     2,000     3,000

     CaS04'2H20 - H20        7.0          98       148       191
     0.25 mol/1 (^4)2804    3.5          43        51        66

     0.5        "            5.5          36        41        50
     1.0        "            3.5          29        38        44
                                138

-------
VO
                         NH^Cmole/liter)
                       302 + HSO," (  mole/liter)
Figure
                       Relationship of 302 + HSC5

                  concentration to partial pressure

                  of S02 (  60C)
                                                                   100
                                                                 o
                                                                 c
                                                                 o>
                                                                 H
                                                                 O
                                                                 H
                                                                    90
                                                                 o
                                                                 E
                                                                 0)
                                                                 O
                                                                 CO
                                                       80
                                                                      30
        L/G
Inlet S02

O
O
550ppm
BOOppm
1 ,000ppm
PH 3.7,60C
                                                                    50          70

                                                                 sal./l,000scf)
Figure 5  ^Oa removal efficiency

    at the test unit (2,950scfm)


    Tower diameter 3.3ft

    Height of packing 6.6ft

    Packing  Netring HA-18

    Space velocity  4-5 ft/sec

-------
                  Table 7  Design base of S02 absorber


                                         Pressure     Space     Height of
                             L/G         drop         velocity  packing
          Packing       (gal/1,000scf)   (inches Aq)  (ft/sec)   (ft)
     Tellerette L type        56             4           6        12

     Netring HA-lb            56             4           4.5       9


Process description  The flowsheet of the process is shown in Figure 6.
Flue gas is first led into a KBCA scrubber and then into a packed tower
absorber.  The main function of the KBCA scrubber is to cool the gas to
60C and to concentrate the absorbing liquor (ammonium sulfate solution).
More than 90% of the S02 is removed.  The gas is then reheated by the
afterburning of oil.  The liquor from the packed tower absorber is sent to
the  KBCA unit,  concentrated,  and then led into  an oxidizer.   The pH of the
liquor in the oxidizer is adjusted to from J to 4 by adding dilute aqua
ammonia and the sulfite in the liquor is oxidized into sulfate by small
bubbles of air formed by introducing a jet stream of circulating liquor
accompanying air into a pool of the liquor.  About five times the stoichio-
metric amount of air is used.  Tests have shown that Fe++ catalyst gives
an optimum oxidation rate at pH 4 and Mn   at pH y (Figure 7).  Actually
no catalyst is added for oxidation because it occurs fairly rapidly at a
rate of 0.8-1.Okg mole/m^/hr? presumably a small amount of vanadium and
iron derived from the fuel helps the oxidation.

Most of the liquor from the oxidizer is returned to the absorber, and
a portion is sent to a set of three reactors where the liquor is treated
with milk of lime to precipitate gypsum.  In order to raise the concentration
of the slurry and to increase the retention time of gypsum for better
crystal growth, a portion of the slurry is sent to a liquid cyclone.
The gypsum is returned to the reactor and the liquor which contains some
gypsum is sent to a thickener.  The overflow from the thickener is sent
to an aqua ammonia tank.  The sludge from the thickener is returned to
the reactor, and the other portion of the slurry is sent to a centrifuge.
The liquor from the centrifuge and wash water are sent to an aqua ammonia
tank, and the aqua ammonia js sent to the oxidizer.

The concentration of the absorbing liquor is normally about 0.5 mole  of
ammonium sulfate per liter at L/G 56.  It can be raised to 2.5 moles at the
same L/G ratio without appreciable decrease of S02 removal efficiency.
The oxidation rate decreases slightly at the higher concentration.  The
amount of water added to the system, namely lime dissolving water
and gypsum wash water, is usually less than that volatilized in the cooler.
Therefore, some water is introduced into the cooler to maintain the water
balance.  Occasional purging may be required to prevent buildup of chloride.
The by-product gypsum contains about 9% moisture with a bulk density of
about 1.06 and pH 8.  Average crystal size is 40 to 60 microns.  The
gypsum can be used for both wallboard and cement additives.
                                140

-------
Flue gas
   I
    V.'ater
Cleaned gas
    A
      Ca(OK)2
           >Vater
       Air
      nin
    j
            i  f   ^  /
            '  1   \  I
                    i
 .Vater

Gypsum
   1_T^
                                             8
   1 K3CA scrubber
   2 Cxidizer
   3 Absorber
   k Slaking tank
   5 Seactor
            6 Liquid cyclone
            7 Centrifuge
            3 Thickener
            9 Aqua ammonia tank
  Figure 6   Flowsheet of Kurabo  ammonium
            sulfate gypsum process
                            (  mole/liter)
                                             Ki-jurc 7  Oxidation rate of
                                                  sulfite ion  ( WC)
                                               (HSO/) < 10^ mole/liter
                                               ( M++) ^xlo'*mole/liter

-------
Ammonium sulfate can be obtained easily by concentrating the solution
from the oxidizer.  In this case, a nearly saturated solution (2.5-3
moles/liter) is used as the absorbent.
Cost Estimation  An example of cost estimation is shown in Table 8,
               Table 8  An example of cost estimation
                                     59,000 scfm
                                     1,590,000 gal/year
                                     2.8%
                                     8,500 hours/year
                                     54.0 million
Plant:
Oil consumption:
Sulfur content:
Operation hours:
Construction cost:
    Material
25% aqua ammonia
Oil for reheating
Industrial water
Power
Quick lime
Recovered gypsum
Subtotal
Depreciation
Interest
Labor
Maintenance, etc.
Total
Desulfurization cost
(l dollar =250 yen)
         Unit cost.
       30.3 cents/gal.
       22.7     "
        7.6     "
        2.0 cents/kW
        0.9 cents/lb.
        0.4    "
 Annual cost
   6,000 dol.
 112,400  "
   1,680  "
  96,000  "
  63,000  "
-114,600  "
 162,800  "
 515,000  "
 160,000  "
  24,000  "
  64,000  "
 925,800  '
 5.9 cents/gal.oil
Advantages  There is no plume and no scaling.  Both oxidation and crystalli-
zation of gypsum are made at 50-60C without external heating.  The pH of
liquor is kept over 3 to prevent corrosion.  All steps are carried out at
atmospheric pressure.  A closed system can be achieved.  Ammonium sulfate
can be produced easily, if desired.  The softening step of the circulating
liquor is unneeded.
                                 142

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Disadvantages  The process is less simple than the wet lime process.
Limestone cannot "be used.
VTII  Dowa aluminum sulfate process
Outline of the process  This process has been developed by Dowa Mining Co.
(8-2, 1-chome, Marunouchi, Chiyoda-ku, Tokyo).  Dowa is one of the biggest
nonferrous metal manufacturers in Japan and owns many smelters and sulfuric
acid plants.  The aluminum sulfate process has been developed to
desulfurize waste gas from smelters, roasters and sulfuric acid plants.
The principle of the process is as follows:
S02 is absorbed in a solution of basic aluminum sulfate,
to form 112(304) ^12(503)3.  The liquor is oxidized by air into
Al2(SO^)^, which is then treated with powdered limestone to precipitate
gypsum and to regenerate the basic aluminum sulfate solution.
     Absorption:  A^SO^'A^O^ + 3S02 =

     Oxidation:   A12(S04)5A12(S05)5 + 3/202 =

     Neutralization:  A12(S04) ^'A^CSO^j + JCaCO^ + 6H20

                                            3(CaS042H20)
State of development  After tests with a pilot plant with a capacity of
lyOscfm, a small commercial plant (2,000scfm) was constructed at Taenaka
Mining, Mobara Works and started operation in October 1972 to treat waste
gas from a molybdenum sulfide roaster containing 7500ppm S02 at 100 G.
A larger pilot plant with a capacity of treating l,700scfm tail gas from
a sulfuric acid plant has also been in operation.

Two commercial units, each with a capacity of treating  140,OOONra'/hr
(82,000scfm) tail gas from sulfuric acid plants, started operation in
June 1974 at Okayama Works of Dowa.  Mitsui Shipbuilding Co. has joined
Dowa for further development of this process.

Absorbing liquor  The relations between the composition of basic aluminum
sulfate liquor (Table 9) and S02 absorbing capacity and the boiling point
of the liquor after the S02 absorption are shown in Figures 8 and 9


          Table 9 Composition of solutions in Figures 8 and 9

                   Al20j (grams/liter) in solution

       No,
       I

       II

       III
                                 143
Free
34.4
40.0
45.5
Combined
66.1
58.2
53-2
Total
100.5
98.2
98.7
Basicity (%)
34.2
40.8
46.1

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120
         120
                              IIA
                              113
   0   2   ^   6   8   10
      S02(f/0 in waste gas

Figure 8  302 absorbing capacity
         of the liquors
                           80  100
                content in 1 liter
            of liquor (gram)
        Figure 9  Boiling point of
        the liquor containing
     Cleaned gas
              A
         1 Absorber
         2 Tank
         ~5 Oxidizer
k- Reactor
5 Thickener
6 Tank
7 Centrifuge
8 Tank
         Figure 10  Flowsheet of Dowa aluminum sulfate limestone
                    process
                                144

-------
An optimum concentration as well as basicity of the absorbing liquor is
selected, according to the SC>2 concentration of gas and the removal
efficiency required.  Normally liquors at pH 3 to 4 which are more
dilute than those shown in Table 9 -are used.

Process description  The flowsheet of the process is shown in Figure 10.
For the small commercial plant of Taenaka Mining, a TCA scrubber is used
to recover more than 90% of the 302 at L/G 35 (gal/1,OOOscf).  For the
pilot tests (l,700scfm) with tail gas at 85C from a sulfuric acid plant,
a packed tower (800mm in diameter) was used to recover more than 95% of
the S02 at L/G 20.  The liquor from the absorber is led into a tank to
which make-up aluminum sulfate is added.  The liquor from the tank is
sent to an oxidizer where aluminum sulfite is oxidized into sulfate by
small bubbles of air.  The oxidizer, which has no moving parts, has been
developed by Dowa.  Twice the stoichiometric amount of air is used.
Most of the oxidized solution is returned to the absorber, a portion is
sent to a neutralizer and treated with powdered limestone (mostly under
200 mesh in size) under a condition suitable for the crystal growth of
gypsum.

The slurry from the neutralizer passes through a thickener and is then
centrifuged.  All of the liquor from the thickener and the centrifuge
as well as the wash water of gypsum are returned to the absorber.  The
chemical composition of the by-product gypsum from the pilot plant
(l,700scfm) is shown in Table 10.  A small amount of aluminum is contained
in the gypsum.  The consumption of aluminum is about 1 Ib (as Al) for
1 ton of gypsum.


        Table 10  Chemical composition of by-product gypsum (%)

                 No.     CaO     803     Al     Moisture

                  1     32.80   46.65   0.05      10.0

                  2     32.34   46.43   0.05      12.1
                  3     32.03   46.61   0.04      12.0
                  4     32.24   45.68   0.06      10.8
                  5     32.88   45.86   0.05      12.8
                  6     32.07   46.48   0.05      11.8

Operation experiences  The small commercial plant of Taenaka has been in
operation since October 1973*  There is no appreciable problem of scaling.
Cleaning the pipings once every several months is enough to remove soft
deposits.  Continuous operation of the pilot plant (l,700scfm) for several
months also produced no appreciable scaling.  The operation of the new plants
(82,000scfm) has also been satisfactory.
                                 145

-------
Advantages  (l)  Limestone is used for neutralization because of the low
pH of the liquor.  (2)  The L/G ratio is relatively small.  (3)  The
oxidation occurs fairly rapidly.  (4)  There is essentially no scaling and
no wastewater.  (5)  A fully automatic operation can be achieved,

Disadvantage  Aluminum sulfate is consumed although in a small amount.
IX  Evaluation of the processes
Dry processes  Now there are three dry processes, each being used for a
prototype plant.  Those are two activated carbon processes by Hitachi-
Tokyo Electric and by Sumitomo Shipbuilding, and the Shell copper oxide
process.  In addition, pilot plants using the dry sodium absorption
process followed by the decomposition of the resulting sodium sulfate
has been operated by Tsukishima Kikai Co. and also by the National Research
Institute of Pollution and Resources.  There is no plan, however, to install
a commercial plant using any of those dry processes,  Mitsubishi Heavy
Industries and Chubu Electric Power have recently given up the activated
manganese process because of the difficulty of achieving J0% recovery and
the economical disadvantage.  The advantage of the dry processno reheating
of gasmay not compensate for the disadvantagesthe need for a large
absorber and an expensive absorbent or reducing agent.

Problems common to wet processes  Numerous plants using wet processes are
in operation or under construction.  Still, the wet processes have some
problems in common.  One is reheating and the other is wastewater.  For
reheating of gas, afterburning  of oil has been used exclusively in Japan,
The oil consumption is about 5?4> of that for power generation, indicating
that when the 863 removal efficiency by scrubbing is 90% overall efficiency
would drop to 85%.  The addition of S02 and some dust to the gas is going to
present another problem as the regulations on SC>2 and dust become more
and more stringent.  Studies on the use of the heat exchanger have been
started recently.

It is common in Japan to purge some water from the system in order to
maintain the concentration of impurities in the circulation liquor under
a certain level.  Among the impurities, chlorine derived from fuel and
input water is most troublesome because it causes corrosion.  Particularly
when the multitube heat exchanger is used for reheating, the corrosion
problem becomes significant.  It may be more logical to purge some water
after treating it thoroughly than to use expensive corrosion resistant
materials.  Where no water at all is allowed to be purged, some means of
removing chlorine from the circulating liquor may be desired.

Wet lime-limestone processes  Wet lime-limestone processes are most
promising in Japan as in the United States.  The reliability of the
                                  146

-------
Mtsubishi-JECCO process has been well demonstrated.  However, most plants
based on this process have treated gases with a low S(>2 concentration
(300-1,OOOppm) except for a plant of the Onahama Smelter which treats
waste gas from a converter containing 25,000ppm S02  Two full-scale plants
to treat flue gas with about l,600ppm S02 from oil-fired utility boilers
(375MW each) will start operation early in 1975.  The operation performance
should be watched for further evaluation.  The Chemico-Mitsui process has
also gained some fame from the successful operation of the Omuta plant
of Mitsui Aluminum Co. using coal-fired flue gas.  There has been much
argument concerning the reason for the scale-free operation.  Whether the
circulation liquor is saturated or unsaturated with gypsum is a point
which has not been made clear yet.  However, there is no doubt that
careful operation control is one of the keys to success.  For example,
the pH of the slurry is measured manually because an automatic pH meter
might not be quite reliable.

The Mitsui Miike process has the advantages of attaining high S02 removal
with limestone and of pH control without sulfuric acid.  The Mitsui Miike
process as well as the MitsubishiJECCO process may be useful also in the
U.S.A. if there is any use for the by-product gypsum.  The Mitsui Miike
process may be applicable also for discarding the by-product, if the
partial oxidation, which is required to improve the property of the sludge,
can be done in a simple way without much cost.

For evaluation of other wet limelimestone processes, a longer operation
period or operation of larger plants may be needed.

Double alkali type processes  Among the double aLkali type processes, the
Chiyoda process and sodium-limestone processes of Showa Deriko and
Kureha-Kawasaki have been used widely.  Smooth operation and use of
limestone may be the reason for the use.  The Chiyoda process is simple
and the plant operation is most easy, although it requires a big absorber
and a high L/G ratio.  The operation of a pilot plant of Gulf Power Co.
in Florida which  will  commence  shortly using the Chiyoda process should
be watched for evaluation of the applicability to flue gas from coal-
fired boilers.

The sodium-limestone processes are rather complicated including the
decomposition step of sodium sulfate.  The processes would need a large
land space and relatively high investment cost.  On the other hand, sodium
consumption is lowabout onefifth of that required for a plant the size
of the WellmanLord process plant which does not use an oxygen inhibitor.
If further crystal growth of calcium sulfite is attained, the process
may be useful in the United States to by-produce the sulfite whether it is
used for some purpose or discarded.

Both the Kurabo and Dowa processes use absorbents with an intermediate
pH (3-4) and a moderate L/G ratio (20-40).  Operation of commercial plants
is about to start for both processes.  Although both seem interesting, a
better evaluation can be made when the new plants have produced some
operating data.
                                 1A7

-------
Nippon Kokan (NKK) uses an ammonium sulfite solution at pH 6.8 as the
absorbent.  Therefore, NKK uses a much smaller L/G ratio than does Kurabo,
"but it is not easy to eliminate plume, which has been a problem common to
ammonia scrubbing processes.  The Kurabo.process might be advantageous
where there are strict regulations on plume.  Both NKK and Kurabo processes
may be useful also for the production of ammonium sulfate where there is
a demand for it.

Other processes  Among other processes, the Wellman-Lord process has been
most widely used except for the sodium scrubbing processes to by-produce
sodium salts.  The process is reliable and is easy to control.  A main
drawback of the process is the high consumption of sodium which necessitates
the emission of a considerable amount of wastewater.  Further improvement
may be desirable before application in the U.S.A. where the restrictions
on wastewater are much more severe than in Japan.

It is questionable which is better for sulfuric acid production, the
Veil man-Lord process or the magnesia scrubbing process.  The latter would
give much less wastewater but needs a larger amount of energy for the
decomposition of magnesium sulfite and sulfate.  Further improvements are
desired also in magnesia scrubbing for better operation and less consumption
of energy.

Sulfur by-producing processes seem costly except for refineries which
have large Glaus furnaces to which the recovered S02 can be charged.
If an oversupply of other desulfurization by-products causes problems,
the sulfur by-producing process may become more popular.
                              References


l)  Jumpei Ando, Proceedings of Flue Gas Desulfurization Symposium (l973)
    pp 69-102 and 875-890

2)  Jumpei Ando, Utilizing and Disposing of Sulfur Products from Flue Gas
    Desulfurization Processes in Japan, EPA FGD Symposium (Nov. 1974)

3)  C.P. Quigley, Proceedings of Flue Gas Desulfurization Symposium
    (1973), PP 605-618

4)  Masao Endo, Sekko to Sekkai, No. 131, 168-172 (1974)

5)  Y. Yamamichi and J. Nagao, Sekko to Sekkai, No. 130, 125-129 (1974)
                                 148

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COST COMPARISONS OF FLUE GAS DESULFURIZATION SYSTEMS
         G. G. McGlamery and R. L. Torstrick
              Tennessee Valley Authority
                Muscle Shoals, Alabama
            Prepared for Presentation at
         Flue Gas Desulfurization Symposium
  Sponsored by the Environmental Protection Agency
                  Atlanta, Georgia
                 November ^-7,
                         149

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          COST COMPARISONS OF FLUE GAS DESULFURIZATION SYSTEMS1

                   G. G. McGlamery and R. L. Torstrick
                        Tennessee Valley. Authority
                          Muscle Shoals, Alabama
                                ABSTRACT
          This paper describes the results of an EPA-sponsored cost
appraisal of the five most advanced flue gas desulfurization processes.
Using data available in late 1973 from demonstration-scale systems
in progress and a representative set of design and economic premises,
detailed, highly visible capital investments and operating costs were
estimated for the limestone slurry scrubbing, lime slurry scrubbing,
magnesia slurry scrubbing - regeneration to acid, sodium solution
scrubbing - regeneration to sulfur, and catalytic oxidation processes.

          Itemized capital costs are presented for a base case system
(new 500-MW unit burning coal with 5.5$ sulfur, 30-year life - 127,500
hours operation, 90$ S02 removal, fly ash removal included) for each
process assuming proven technology, a 3-yeax construction schedule  (1972-
1975t midpoint of activity - 197^)> no overtime, and an experienced
design and construction team.  Energy costs reflecting recent worldwide
escalation are applied to the operating costs.

          In addition to the detailed base cases, numerous supplementary
estimates are given to cover such variables as unit size, fuel type,
sulfur content of fuel, plant status (new vs. existing), onsite versus
offsite solids disposal and S02 removal.  The five processes are ranked
according to the results; the accuracy of the estimates is also discussed.

          Using results from recent in-house evaluation studies,
additional less-detailed comparisons are presented for limestone scrub-
bing with benzoic acid, two lime scrubbing options, sodium scrubbing with
      production, and two double-alkali processes.
1 To be presented at the Flue Gas Desulfurization Symposium, Atlanta,
  Georgia, November ^-7>
                                   150

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          COST COMPARISONS OF FLUE GAS DESULFURIZATION SYSTEMS
          After several years of intensive process development, several
power plant stack gas S02 removal "systems are now advancing from the
pilot-plant stage to demonstration-scale applications.  With the in-
stallation of these larger demonstration-size facilities on power units
around the United States, it should now "be possible to more accurately
predict their costs so that utility executives can "better choose be-
tween alternatives.

          Since the Air Quality Act of 1967 and later the Clean Air Act
of 1970, the Federal Environmental Protection Agency has funded research
and development on S02 removal processes including several conceptual
design and cost studies.  In these earlier efforts, many design assump-
tions were necessary and cost estimate accuracy was questionable since
technology was in a state of "flux" and available design data were
limited.  Equipment costs were sketchy since most vendors had yet to
fabricate and erect the large gas scrubbing devices required for full-
scale systems.  Furthermore, very little corrosion data were available
to predict materials of construction for the services involved.  In
many cases, optimism of the process developers tended to maximize
process potential and to minimize problem areas such as erosion, scaling,
solids disposal, sulfite oxidation, mist elimination, gas reheat,
operational turndown, and pH control.

          Finally, after many pilot-plant tests and both encouraging and
disappointing experiences, five processes have emerged from the many pro-
posed as the initial systems for installation.  These are the limestone
slurry process and the lime slurry process, both of which are throwaway
systems (no salable byproduct), and the magnesia slurry - regeneration
to sulfuric acid, sodium solution scrubbing - S02 reduction to sulfur,
and catalytic oxidation - 80$ sulfuric acid processes.  In cooperation
with participating utilities and process developers, EPA is currently
funding large-scale test and demonstration projects on each of these
processes.  The processes and the associated projects are shown in
Table 1.

          Now that many of the unknowns for these systems have surfaced,
remedies been prescribed, and large-scale projects started, more accurate
assessment of process costs should be possible.   The objective of an EPA-
TVA study completed in early 19T** was to prepare a set of highly visible,
detailed capital and operating cost estimates for comparison of the five
leading processes on a common,  uniform basis.   Unfortunately, the rapid
construction cost escalation experienced during recent months has once
again made it difficult to accurately project total costs; however,
comparative costs should be relatively assessable.
                                   151

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            Table  1.    EPA-SPONSORED STACK GAS DESULFURIZATION DEMONSTRATION SYSTEMS
EPA-sponsored process
(byproduct )
Limestone slurry scrubbing
(sludge)
Lime slurry scrubbing
(sludge)
Magnesia slurry scrubbing -
regeneration
(96$ sulfuric acid)
Catalytic oxidation
(80% sulfuric acid)
Sodium scrubbing -
regeneration
Cooperating
utility
TVA
T7A
Boston Edison
Illinois Power
Northern Indiana
Public Service
Process
developer
Bechtel and
others
Chemico,
Bechtel, and
others
ChemicoBaic
Monsento
Davy powergas
Allied Chemical
Location
Shawnee unit 10
Paducah, Ky.
Shawnee unit 10
Paducah, Ky.
Mystic Station 6
Boston, Mass.
Wood River Station U
East Alton, 111.
D. H. Mitchell
Station 11
Unit size
and type
10 MW
coal
10 MW
coal
150 MW
oil
110 MW
coal
115 MW
coal
Expected
startup
Under way
Under way
Completed
**
Late 1T5
(sulfur)
Co.
Gary,  Ind.

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PROCESS DEFINITION

          A brief description of these five processes and the organiza-
tions supplying representative system data are given "below.  The process
data represent  the state of technology in late 19T3-

   1.  Limestone Slurry Scrubbing.   Stack gas is washed with a recircu-
       lating slurry (pH of 5.8-o.U) of limestone and reacted calcium
       salts in water using a two-stage (venturi and mobile bed) scrubber
       system for particulate and S02 removal.  Limestone feed is wet
       ground prior to addition to the scrubber effluent hold tank.
       Calcium sulfite and sulfate salts are withdrawn to a disposal area
       for discard.  Reheat of stack gas to 175F is provided.  Design is
       based on data taken from EPA-TVA-Bechtel Shawnee test program.  A
       flow diagram and layout drawings are shown in Figures 1 and 2.

   2.  Lime Slurry Scrubbing.  Stack gas is washed with a recirculating
       slurry (pH of 6.0-8.6) of calcined limestone  (lime) and reacted
       calcium salts in vater using two stages of venturi scrubbing.
       Lime is purchased from "across the fence" calcination operation,
       slaked, and added to both circulation streams.  Calcium sulfite
       and sulfate is withdrawn to a disposal area for discard.  Reheat
       of stack gas to 175F is provided.   Design is based on data pro-
       vided by Chemical Construction Corporation (Chemico).  The
       representative flow diagram is shown in Figure 3 and layouts are
       shown in Figure 4.

   J.  Magnesia Slurry Scrubbing - Regeneration to HPSQ4.  Stack gas is
       washed using two separate stages of venturi scrubbingthe first
       utilizing water for removal of particulates, and the second
       utilizing a recirculating slurry (pH T-5-8.5) of magnesia (MgO)
       and reacted magnesium - sulfur salts in water for removal of S02.
       Makeup magnesia is slaked and added to cover only handling losses
       since sulfates formed are reduced during regeneration.  Slurry from
       the S02 scrubber is dewatered, dried, calcined, and recycled dur-
       ing which concentrated S02 is evolved to a contact sulfuric acid
       plant producing 98/0 acid.  Design is based on data supplied by
       Chemico-Basic Corporation.  Shown in Figures 5 and 6 are a flow
       diagram and layouts of the scrubbing area.

   k.  Sodium Solution Scrubbing - SOP Regeneration and Reduction to Sulfur.
       Stack gas is washed with water in a venturi scrubber for removal of
       particulates and then washed in a valve tray scrubber with a recircu-
       lating solution of sodium salts in water for S02 removal.  Makeup
       sodium carbonate is added to cover losses due to handling and
       oxidation of sodium sulfite to sulfate.  Sodiujt sulfate crystals
       are purged from the system, dried, and sold.  Water is evaporated
       from the scrubbing solution using a single-effect evaporator to
       crystallize and thermally decompose sodium bisulfite, driving off
       concentrated S02.  The resulting sodium sulfite is recycled to the
       scrubber and the S02 is reacted with methane for reduction to ele-
       mental sulfur.  The regeneration and reduction areas are designed

                                    153

-------
                                                                   srtt* n>o*
Ui
                                Figure 1.   Limestone  slurry process.   Flow diagram.

-------
                                    t'
                                                  I
           f Li I f'iA'JCir*

               jjii
                            1"
                                         .*]"
                                         y
                                  ! ",   ' I

                                   !
                                   t
                               PLAN
             MTIAM HI Ml Ml H
                     . J
   nit
            'r"" p \
            !  I     !\L
               i null' 'i \j
        INI IT -

        I'.fMIM
   rv;!i_^.;T
            i
           . i--*
	\H { NIMA'VJMjMI
     4 rtflAl/H
          i 1 _
          T : "
    ^>ui i mi" i
     Mli  :\'
         1  - '-'/ I     \
        :i^-,.  	L^r_... U  j.,\
         ~>t-
                          ELEVATION
Figure 2.    Limestone slurry process.  Venturi and mobile

   bed scrubber system - plan and elevation  - base case.
                               155

-------
                rvtin
Figure 3.   Lime  slurry process.   Flow diagram.

-------
                             ELEVATION
Figure *4.   Lime slurry process.  Two-stage venturi scrubber system
                   plan and elevation - base case.
                                157

-------
Ln
00
                                                                    	    w          1  o~    =-=
                                                                    I    -"-        I  ,, ,   .        ^J
                                                                     .'STT;S r"""^'     I       '       n
                                                                      \<* t'it j  a^r^sl  ^5i ^  "^    * jri SH	
                                                                    T-ittz-  """"        r^  ^^   cr3
                  Figure 5    Magnesia  slurry - regeneration process.  Flow  diagram.

-------
                          ELEVATION
Figure 6.   Magnesia slurry - regeneration process.  Two-stage
   venturi scrubber system - plan and elevation - base case.
                              159

-------
       for 100/6 of power unit load.  Design for the scrubbing -
       evaporator - crystallizer system is provided by Davy Powergas
       Inc. (Wellraan-Lord process) and data for the S02 reduction unit
       are provided by Allied Chemical Corporation.  Figures 7 a&d 8
       describe the processing steps and scrubbing area layout.

   5.  Catalytic Oxidation,  Stack gas is first cleaned of particulates
       by a high-temperature electrostatic precipitator; then, the S02 is
       catalytically converted to SOa and available excess heat is re-
       covered.  The SOs reacts with moisture in the stack gas to form
       H2S04 mist which is scrubbed in a packed tower using a recircu-
       lating acid stream to yield Qo% acid.  Mist is removed by a Brink
       mist eliminator and the clean 25^F gas is exhausted to the stack.
       Design is based on data supplied by Monsanto Company, developers
       of Cat-Ox process.  Shown in Figures 9-H are a flowsheet and the
       process equipment arrangements for a new unit installation.

          In the EPA-TVA report, representative flow diagrams, material
balances, control diagrams, plant layouts, and equipment arrangements are
included for the base case (new 500-MW coal-fired unit, 3-5$> S in fuel,
90% S02 removal) of each process.  Together with detailed equipment
descriptions, this background defines the systems estimated.
MAJOR COST FACTORS

          From previous economic studies, the following factors are con-
sidered to be the most important:

   1.  Project schedule and location.  Project assumed to start in mid-1972
       with 3-year construction period ending mid-1975-  Midpoint of con-
       struction costs mid-1971* ; Chemical Engineering Cost Index - 160.2.
       Startup - mid-1975.  A midwestern plant location is assumed.

   2.  Power unit size.  Costs for three unit sizes200, 500, and 1000
       MW---are projected.

   3.  Fuel type.  Systems for both coal- and oil-fired units are costed
       coal 12,000 Btu/lb, 12% ash, oil - lS,500 Btu/lb,  0.1% ash.

   1*.  Sulfur content of fuel.  Costs for three sulfur levels are evaluated
       for each fuel2.0, 35, and 5-0$ for coal; 1.0, 2.5, and h.0% for
       oil.

   5.  Plant status.   Although systems for both new and existing power
       units are evaluated, only a simple, moderately difficult (scrubbing
       system installed on vacant space beyond the stack ) retrofit is
       estimated since such systems can vary over such a wide range of
       configurations and restrictions.  New units are designed for a 30-
       year life, 127,500 hours of operation.  Costs for new and existing
       systems are not directly comparable.


                                   160

-------
                                 .Lx-
                                J^
Figure 7.   Sodium solution  - SOg  reduction  process.   Flow diagram.

-------
                                                             	1- $TtCf
                            ELEVATION
Figure 8.   Sodium solution - S02 reduction process.  Venturi  and
   valve-tray scrubber system - plan and elevation  - base  case.
                                162

-------
                                                 JW*V>>WJ_
U>
                                                                                                  J:
                                                          9O>t,in fTxn*ra>
                                                          fOt UlMltUUff
                                                      f 0 rut
  snwnr trr*u
f		
                                 Figure 9    Catalytic Oxidation  process.   Flow diagram.

-------
Figure 10.   Catalytic oxidation process.  S02 conversion and absorption system layout - plan  - "base  case.

-------
Lfl
N>UMW;
COHOCNMTt MCJTtH  ' I
CMOIumON CIO COOLDC 	 '

 2S3 rr ioii

f

\^FV
^ COOLM





	 	 \T^?TT
^
rtU 1AMt












^

              Figure 11.   Catalytic  oxidation process.   SQ2  conversion and absorption system layout -
                                              elevation  - base  case.

-------
 6.  S02 removal.  Since all five processes are capable of 90$ S02
     removal and future demands for .-mission control may exceed
     present standards, 90^ removal is specified as the base value.
     For those processes in which cost effective design changes could
     be identified, 80^ removal is also projected.

 7.  Particulate removal.   Costs are included for 9%.7% particulate
     removal (to meet EPA standard of 0.1 Ib/million Btu heat input)
     on new coal-fired systems except Cat-Ox which requires 99.9$
     removal for process reasons (restricted to 0.005 gr/scf prior to
     entering converter).   Existing units are assumed to be already
     equipped with 93-7$ electrostatic precipitators.  Because of
     this provision, the investment and operating cost results for
     existing coal-fired systems appear lover than for new units.   To
     cover this disparity,  a special case is examined where full
     particulate removal must be added to an existing unit.  Oil-
     fired units do not require dust removal facilities.  Existing
     Cat-Ox installations require incremental additional precipitator
     to reduce loading to 0.005 gr/scf.

 8.  Raw materials and catalysts.  Assuming startup in 1975> mid-
     western 1975 delivered prices are projected and sensitivity
     analysis is used to evaluate variance.

 9.  Labor.  1975 midwestern operating labor rates are projected.
     Sensitivity analysis is used to evaluate overall operating labor
     cost variance.  Operating labor is escalated over the life of the
     project for only a few special cases to show effect.

10.  Utilities.  Recent energy cost escalation is recognized and 1975
     values are projected.   Values used in operating cost estimates for
     utilities supplied by power plant cover all costs for generation
     including return on investment, depreciation, and income taxes.

11.  Maintenance.  Various levels are analyzed by sensitivity analysis.

12.  Capital charges.  Regulated (profit and taxes included) economic
     basis is used.  'Annual operating cost estimates utilize  a base
     value of 1^.9$ of fixed investment (10$ cost of money).  Level
     is varied by sensitivity analysis.

13.  On-stream time.  Annual operating costs are projected for
     operating times of 7000, 5000, 3500, and 1500 hours per year.
     Later, these values are used to project a lifetime cost over a
     predefined 30-year declining operating schedule.

1*4.  Solids disposal.  Both onsite ponding and off site disposal costs
     are evaluated for limestone and lime processes.  Onsite ponding
     includes prorated costs for calcium solids to cover pumping and
     piping to and from the pond, plus a k0-foot-deep, clay-lined
                                166

-------
       pond sized to meet requirements over the remaining life of the
       power unit.  Offsite disposal includes proration of a thickener,
       filter, piping, pumps, cake conveyors, and loader at the power unit.
       Offsite charges are levied-on a fee per ton of wet solids basis
       assumed to cover all contractor expenses for hauling, treatment,
       and final disposal.  Sensitivity analysis is used to evaluate
       variance.

  15.   Net sales revenue.  Base values$3/ton 100$ HS04 as 98$ H2S04,
       $6/ton 100^> H2S04 as 80$ H2S04, $25/short ton for sulfur, $20/ton
       for sodium sulfate are used.  Variances are covered by sensitivity
       analysis.

          Other important design and cost assumptions defined for con-
sistent evaluation are:

   1.   Fly ash disposal facilities proration (ponds, pipes, pumps) not
       included.  Water balance is based on closed-loop operation.

   2.   System design assumed not "first of kind;" no redundancy is in-
       cluded; only pumps are spared; experienced design and construction
       team is assumed utilized.

   3.   Stack gas reheated to 175 F except Cat-Ox process.

   k.   Product storage - 30 days except for Na2S04 - 7 days.

   5.   Equipment, material, and construction labor shortages with
       accompanying overtime pay incentive not considered.
PRESENTATION OF RESULTS

Capital Investment

          In the detailed cost study, several methods are used to present
the results.  For investment data, the following types of displays are
presented for each process:

     Equipment list, cost, size-scale factor, and data source--presented
     for base case  (new 500-MW coal-fired unit burning coal with 3-5^ S).
     See Table 2 for an example.

     Summarized process area equipment and installation cost breakdown
     presented for base case and existing 500-MW limestone system.  See
     Table 3 an<3. k for examples.

     Case variationsarea investment summaries presented for each of the
     16 case variations.  See Tables 5-10 for examples.

          Shown in Table 11 is a summary of total investment for the 16
case variations of the five leading processes.  The relative ranking of
the processes for new coal-fired units (3-5$ S) in order of increasing
investment is as follows:

                                   167

-------
                   Table 2.    LIMESTONE SLURRY  PROCESS
                                   BASE CASE
Airj I  Mjlcrul lldndling


Item 	 	 No
1. Unloading 1
hopper No 1


2 Limestone 1
feeder No 1
Ivibialing)

3. Conveyor j
(bell) No 1





4 Conveyor I
(bell) No 2


5. Hopper.' 3
under pile

6. Limestone 3
feeder No. 2
(vibrating)

7. Conveyor 1
(belli No. 3


8. Tunnel 2
sump pump


9. Elevator I
No. I



10. Bin 1


11. Car shaker 1

12 Dust 1
collecting
system No. 1

13 Dust 1
collecting
system No. 2

14 Bag filter 1
system







S

	 Oesitirumn __
Cjp.icity 94 II '; g'-
4" side; 2 -4 "bot-
tom. 3 deep, carbon
steel
210 tonv/hr.42"
wide x 5 long pan.
ue-cosl
scale
fjclor
06K



0 58


I'ac lor Hase
source cost
diem. Enjjr 3-24-69 1.700
CulHiie


Chem Engr 3-24-69 2.691
Outline
	 . 	
Hjvccost Date
source of cost
Caulylic 1973
Inc


Rk-hjidsun Engr 1971
Services
"Projected 1974
equipment cost
each tola)
2.000 2.000



3.300 3.300

2'/i hp vibrator included.
carbon steel
210 lons/hr, 250 ft/
mm. 24" bell. 10'
long. 2'/j hp motor
included . caibon
steel


210 lons/hr. 250 ft/
mm. 24 hell. 172
long. 20 hp moioi
steel
7 '-4" top. l'-4"
botlom. 3* deep.
carbon steel
100 tons/hr. 18"
uide % 3'//long pan.
1 hp vibrator included.
caibon steel
250 fl/min. 18"belt.
1 35' lung. 3 hp moior
included , carbon
steel
5, gpm, 10' head.
V* hp motor included.
caihon steel.
neoprene lining
100 tons/In ("' 85 Ib/
ft3. 16" x 8" x 8V.
bucket, 235 ft/min,
15 hp motot included.
carbon steel
5.000 ft*. 3/8"
carbon steel plate.
plus structural sleei
Railroad trackside
vibrator
2,000 cfm inertial
separator. XO cyclone.
2 dust hoppers, fan,
and drive
6.000 cfm inertial
separator. XO cyclone.
2 dust hoppers, fan.
and drive
14.000 cfm. automatic
fabric dust collectors.
bag support, shaker ys'
lem. isolation damper,
external shaker motor
and drive, dust hopper,
fan and motor for bag
filter system (VJ in feed
preparation area)

081




0.65

081



068


058



065

081


F:und. of Cost Engj. 1.887
1964



Oirm. Sup. 3-M-9
Guthrie
1 und of Cost Kngr 8.948
1964

Cnetn. rngr 3-24-69
Gulhrie
Chem. Engr 3-24-69 1.300
Gulhrie

Oiem. Engr 3-24-69 1.550
Guthrie


Chem. Engr 3-24-69 11.250
Gulhrie
Fund, of Cost Engr.
1964
Depends on gpm and head 560
requirements resulting in changes

TVA work 1964
order O05C30





TVA work 1962
order D05P353


Oiem Engt - 1969
3 24-69. Guthrie

Kichardson Engr 1973
Services


Chem Engr.- 1969
3-24-69. Guthrie


Catalytic 1973
Inc

2.900 2.900






13.700 13.700



1.700 5.100


1.700 5.100



14,800 14,800



600 1.200

of motor and impeller si7.es

083




068




0.80



0.80



0.68-









Chem. Engr. 3-24*9 8.765
Gulhrie



(Them. Enp 3-24-69 1 2.650
Guthrie

4.866

Chem. Engr 3-24-69 2.392
Cuthrie


Chem. Engr 3-24-69 4.724
Guthrie


Cbem. Engr 3-24-69 7.926
Guthrie








TVA work 1964
order D05C30



TVA work 1964
order D05C30

TVA work 1965
order IXJ5C30
Richardson Engr 1973
Services


Richardson Engr. 197.3
Services


Richardson Engr 1973
Services








13.300 13.300




19.200 19.200


6.600 6.600

2.600 2.600



5.100 5.100



8.500 8.500







	
 .Subtotal
                                                                         103.400
                                      168

-------
        Table 2.    LIMESTONE  SLURRY PROCESS (Contd)
                          BASE CASE
 ?  1 red



1



2



3


4




5




6





7



8



9





10



11.




12.



13.

14.



Item 	
Mm discharge
fi-cdci


Urigh feeder



Gyralory
cnisher

( lrva>r
No 2



Wet hall
mill



Mills
product
lank

1 ihmg

Agll.ltor.
mills
product
tank
Pumps, mill*
product tank


Slurry feed
lank



Lining
Agilalcu.
slurry
feed
Unk
Pumps, slurry-
feed lank



Dust
collecting
system

Moist

Hag filter
system
S

No 	 Description,
1 2'.'i Inns/Ml. I0~
2 v-idc x 2 '/i long pan.
vibrator included.
i. iilvin steel
2 C'l iims/hr. 18"
bell. 14' Innp. IV,
hp Ulolor included.
carbon sleel
- 1 2'.i|lnns/tH. 0 x l'/i
to ' . 25 hp motor
included
7 12V, lonv'hr. K5 lb/
fi3, 2.1 .s li/inm. 24'
etrs. 6" x 4" \ 4',."
binkel. 1 lip motor
uu In ded
1 3CHI luns/d.u . 8' dia
x 1 2' long, from ',."
to 200 mesh
2 450 hp molors for
hall mill
1 1.920 gal. 8'diam-
etet x 5" high.
vertical svilh open
lop. caibon sleel
Neoprene lining for
mill produc 1 tank
1 1 hp. neoprcne
coated


2 96 gpm. 58' head.
centrifug.il. wuh
variable speed drive
and 3 hp motor, carbon
1 46,080, p.il. 6.1 60 fl3.
17 -4 ' Jijmrler x 27'
high, vertical svith open
lop.<41 l'-V v.ule
baffles, carbon steel
Vt" neoprene lining
1 10 hp. neoprene
coated


2 96 gpm. 5H' head.
centrifugal, svilh
variable speed drive
and 3 hp motor, carbon
steel, neoprcnc lined
1 8.000 cfm, mental
separator, XQ
cyclone, 2 dust hoppers
fan and drive
1 5 Ion electric

1 14.000 cfm, auiomalic
fabric dus( collector .
/e-cost
si air 1 act or
aitor _ source
0.5K ("hem 1 ngr ).~>ij,~il 	 e.ich
Richardson iKnjfr. 1973 600
Services


Catalytic I97J 8200
Inc


Denver Fquip 197? 1 1 .100
C'o

Chem 1 ngr 1969 2.400
3 24*9. Guthne



Denver Kquip 1973 108.150
Co

V.eslm(jhou 1973 14.20(1

CATX 1971 2.500



CATX 1971 ROO

Mixing [quip 1971 1.200
C'o.. Inc.


Denver Kquip. 1973 2.200
Co


GATX 1971 19.200




GATX 1971 17.000
Mixing 1-quip 1971 5.600
Co . Inc


Denver ! quip 197.S 2.200
Co



Richardson l.ngr 1973 6.400
Services


Richardson i-lnftr. 1973 19.000
Services
Richardson Knpr 1973 8.500
Services
' 1974"
con
_ total
" T.200



16.41X1



22.600


4.KOO




216.3(XJ


2.400

2.500



800

1.200



4.400



19.2IN1




1 7.000
5.600



4.400




6.400



19.000

8.500

hap support. sh.iKer ystcrn.
isolation d.irnpcr. c\ ernal






dusi hopper, motor nd
fan for bap Tiller sys en
area)












Subtotal
                                                                 17K.700
                                   169

-------
                   Table  2.      LIMESTONE  SLURRY PROCESS   (Contd)
                                               BASE  CASE
Area 3- Paniculate Scrubbing
	hem
 I. Tank.
   paniculate
   scrubber.
   effluent
   hold
   Lining
 2. Agitator,
   effluent
   hold tank
 3. Pumpi.
   recycle
   slurry
 4. Venturi
   scrubber
 5. Venturi 4
   MBA sump
6 Sool
  blowers

  Subtotal
No.
4





4

Sue-coil
icale Factor
Description fictor source
25,700 gal. 3.435 fU. 0.68
13 diameter x 26*
high, open top. (4)
1 wide baffles.
carbon steel
V* neopjene lining
Shp.neoprene 0.26
coated
Chem. Kngr. 3-24-69
Guthrk




r-und of Cost k'.ngi
1964
Base Bate cost
cost source
13,500 GATX




10,000 GATX
3.400 Mixing Rquip.
Co
Pi ejected 1974
Dale equipment coil
of coil each toll!
I97J 16.300 65.200




1971 12.000 48.000
1971 4.000 16.000

6  4.900 gpm. 144'
   head, centrifugal,
   bell drive, 300 hp
   motor included, carbon
   steel, neopicne lining

4  With variable throat.
   36' long x 5'wide x
   20'high. conveying
   section & thioat
   carpenter 20. remainder
   W" carbon steel with
   neoprene lining
4  28'long x 41* wide
   x 13'high. V."
   carbon steel, ncoprene
   lining (Win SOj
   scrubbing area)
                                      0.50   Chem. F.ngr. 3-24-69
                                         _,   Cuthne
                                         Depends on gpm and head
                                         requirements resulting In
                                         changes of motor and
                                         impeller size
                                       060
                                             Universal Oil
                                             Products
 13.440  Denver Fquip.
        Co
133.000  UniverulOil
        Products
                        1973    1OOO   87.000
                                                                                         1971   150.000  600.000
                                      068   Chem. Engr  3-24-69
                                             Gulhrie
                                                                  49.500
                                       I 00   TVA
        Products
                                                                   3.500 Widows Creek-
                                                                         TVA
1971    57.500  230.0<




1971     4.000   80.000

              1.126.200
                                                      170

-------
                     Table  2.      LIMESTONE  SLURRY  PROCESS  (Contd)
                                                   BASE-  CASE
Area 4  SO_j Scrubbing	
     llem  	No__   Description^	
    K'A scrubber  4   SO, jhvoiher" mo-
                    bile bed. with
                                      >i;e-cost
                                       scale
                                     _facloj_
                                        OHO
                    driinslrr. 4 I' long x 16'
                    wide > 4 I1 high; V,"
                    cjibon stfcl wuh
                    nti'prenc lining.
                    316 S S  Krids. hlj!h
                    density poly . spheres.
                    I HP spray headers.
                    (hi-vron  v./ne mist
                                  I acloi
                           	   source
                           UnivWsll Oil"'~
                           Products
                             Base      It.ise cost
                           	 cost       source
                           ~22"7.<)0b" iimver'i.i OiF
                                    Products
                      "Tiate"
                        of
                       COSl
                       1971"
           1974"
           lost
 eaih      ''?l_
300.000 \.200.000
                                                                                                   'Tnijeiled
                                                                                                   equipment
 2 Venlurl &
   MBA sump
3 Tank.        4
  absorber
  effluent
  hold

  Lining
4 Ajilalor.  SO, 4
  absorber
  hold lank
5 Pumr. SO,   10
  absorber
  recycle
  slurry
 6 Pumps.
   makeup
   water
 7 Soot
   blowers
   Subtotal
                 1
28' long x 41*
wide x  I 3' high. Vt"
carbon  steel, neoprene
lining (Vj in paniculate
si'rubbinp area)
240.000 pal. 32.0R8
ft 340'diameter x
26 high, open lop.
field elected.
carbon  steel
Vi  neoprene lining
50 hp. neoprene
coated


I l.500ppm. 105'
head. Centrifugal,
neoprene lined, belt
drrre. 500 hp motor
included
l.240gpm, 150'
head, vertical
multistage  turbine.
100 hp molor
included
                40
                                        068
                                        068
                                        O.SO
                                              Oieni. Ingr 3-24*9
                                              (lulhrir
                                               (Tiern Fnpr
                                               C'.uthne
                                                          3-24^,S
      Oiem \nfi  3-24-69
      Gulhrie
Depends on ppm and head
requirements resulting in
changes of motor and
impeller si/e


Depends on ppm and head
requirements resulting in
changes of molor an-4
impeller si?e


1.0(1    TV A
                             49.500 Unwerul Oil
                                    Products
                                                                      .is. .127 <;ATX
32.000 C.ATX
!2.245 fatjlvt
       Inc
                                                                      23.000  Allen. Sherman.
                                                                             Hoff
                                                                      2.369  Richardson Kngi
                                                                            Sen-ices
                                                                      3.500  Widows Creek
                                                                            TV A
                                                                                             1971    57.5OO  230.00O
                                                                                             1972    45.100  180.400
                                                                                             1972
                                                                                             1973
                                                                                             1971
                                                                                             |97?
                                                                                             1971
 3H.600  154.400
 1.1.250   53.000


 27,100  271.000
                                                                                                      2.600    5.20(1
                                                                                                      4.00O   160.000
                                                         171

-------
                 Table  2.      LIMESTONE  SLURRY  PROCESS  (Contd)

                                           BASE CASE
Aira 5 Reheat
     Item
1  1,21.
  re heater
2 Snol
  hloueri

   Suhlolal
                       Size-cost
                         cale         Factor
	_No _ _  Description _   _faloj         oui
       Tuiie type. 2.028 f(T
       I3.900lb. Viof
       tuhrs nude of mconel
       625 and remaining Vi
       made of cor-len
                                   O.tJO
Cheni
Culhrie
  Bate
	cpjl _
 70^000 '
Base cost
 source
              20
                                   1 00   TVA
                                                                  TVA
                    3.500 Widow; Orek
                         TVA
                                       Dale   Piojrclcd  1974
                                        of  cqutpmcni   cost
                                       _cot	?'ch  	(ouj	
                                       1971    82.MIO ~ JJO.OOO
                                                                      1971     4.000   80.000

                                                                                    410.000
Area 6-Ga) HandIjn^	
     llcm
I. Han


No,
4









Description
41"1.200rpm.
2.905 hhp. 3.250hp
molor included with
insulation (Cojl ij
difference between
4l"and 15" fan
Remainder is
allocated to boiler,)
Si/e-cost

-------
               Table 2.
LIMESTONE  SLURRY PROCESS  (Contd)
        BASE CASE
AreaJ? Solids Di^posaj	
SizeM

Hem No.
1 Pond Iced 1
tank




Lining
2 Aptlaloi 1

3 Pumps, pond 4
feed tank3


4. Pump*. 1
recycle pond
water3



Subtotal

Description
63. 000 gal. field
erected, 8,42.1 ft3.
21 diameter x 26 high.
veilu'jl vvilh open top.
carbon tie el. 1 - 8"
x 2h' bafflei
V nroprfne lining
7V) hp. nettprene
coaled
I.128f:pm (' 75'
head, neoprene
lined with 50 hp
motor
I.OOOppm ("' ISO'
head, multistage
turbine, cast iron
bowl, stainless steel
impellers, with 75
hp motor

scale Kiclor Rate
factor source cost
0 68 Chem. Fngi .1-24-69 20.000
Gulhrie




16,120
050 Chem Engr 3-24-69 4.717
0.47 Fund of Cost Fngr 1964
Depends on gprn and head 1,850
requirements resulting in
changes of motor and
impeller lize
Depends on gpm and head 1.100
requirements resulting in
changes of motor and
impeller size



Due
Bate coil of
lourcc cost
GATX 1 97 1





GATX 1971
Mixing Fquip. 197 1
Co.. Inc
Denver Fquip. 1973
Co


Richardson Kngr 1973
Services





Projected 1974
equipment coil
each 
-------
                  Table 2.     LIMESTONE  SLURRY  PROCESS   (Contd)
                                            BASE CASE
Aie 9- Scivicrt



i

2

3



4



5




Item
PiylOider

Plant
vehicles
Maml &
instrument
 hop-
equipment
Service
buildmg-
equipinent

Slorei-
cqulpment
Subtoul


No Description
1 C.a'.olinc type.
2yd-1
- t.ll.H-.mm)

- Office, ma June
tools, and
machine shop
equipment
Equipment for lab..
locker room, motor
contiol room.
reslrooms
Office equipment.
shelving, etc.

Size-cnit
scale
filCIOt
_














                                                I'actor
                                                source
  Hue     Hmr cost
_ co
-------
Table  J.    LIMESTONE SLURRY  PROCESS  -  TOTAL CAPITAL INVESTMENT REQUIREMENTS
         BASE CASE8  SUMMARY  -  PROCESS  EQUIPMENT AUD INSTALLATION ANALYSIS
(Thousands
Raw
irulerub
nandlini
DvrfiCaa
Equipment
Material
Ubor
Aptnf tnd insutiDOB
Material
Uboe
Ductwork, chute*, aad supports
Material
Ubot
Concrete foundations
Material
Ubor
Excavation, ote prrp&nuon.
railroads, roads, and pond
SITU aural
Material
Ubot
Eketncal
Milenal
Ubot
Instnjmnts
Material
Ubot
Paint and mtKeOanoous
Material
Ubot
Suildmrs
MatenaJ
Ubot
Uad
Conjunction facilities
Subtotal direct investment
Indiffft Cotll
Enpneenni; deurn and supervision
Construction field expense
Contractor fees
Contingency
Subtotal faed investment
AJiovtnce for nartup and modiiVtDora
Interest dunni construction
Tout capital investment
Percent of totaj capital investment

10)
2<

i
i

15
1

14
II



II
10

)9
1)

1
4

1
5


.

_
419

)l
46
21
<2
566
45
45
656
26
Feed
preparation

379
57

14
IS

t
6

7
it

-

.
-

St
9J

49
23

1
6

65
67
I
-
999

II
99
45
90
1.214
97
97
1,408
56
Fartxulatc

1.126
114

102
95

7JJ
512

12
41

.

94
31

61
7)

77
31

)
15

.

2
,
).20)

298
)32
160
)20
4.)23
346
)46
S.01S
199
SO,

2JM
335

Ml
)l)

)77
411

24
II

.

95
41

101
112

162
11

)
15

-
-
2
.
4.745

427
522
237
474
6.40S
51)
SI)
7.4)1
295
of
Reheat

410
M

II
20

-
-


-

-

.
.

1
|

21
11


1

-
.
-
.
556

SO
61
29
56
751
60
60
871
)S
Dollars )
Fans

2&5
34

-
_

146
5)

4
21

.

.


Ill
155

15
7


1

.
_
-
-
954

77
94
4)
95
1.15)
92
92
1,337
5)
Soddl
dupostl

60
3

M
71

-
-

1
5

3.021


2

SO
184

II
5

2
13

-
-
395
-
3.92J

)5)
4)2
IK
)92
S.J*S
424
424
6.144
244
Uolitan

-
-

6
II


-

-







10
10

16
1

)
)

-
-
-
-
67

6
1
3
7
9!
7
7
11)5
04
Services

107
2)

.


.
-




)39





.

-
.

,
-

II)
40
14

6)1

57
70
32
64
961
69
69
m
40
Cons true DOB
(acililiei
5t Total

4.724
677

561
54

U77
1.067

62
274

3J67

180
91

4S3
710

359
179

I)
59

I7|
107
420
765 765
765 16.069

69 1.446
84 1.768
)l *03
77 1.607
1.03) 21.693
12 1.735
12 1.7)5
1,197 1316)
41
Percent of
direct

294
42

jj
)4

79
64

04
| 7

210

I |
06

21
44

22
1 1

01
04

1 1
07
26
48
1000

90
no
50
100
:>so
101
101
1566

Percrtu of
total capita/

III
27

2J
2J

] 1
4.1

OJ
1 1

134

07
04

II
11

14
0.7

01
0.2

O.I
04
II
30
63.9

17
1.0
3.2
64
K.J
(9
69

1000
     SOO-MW new coftJ-fi/eiJpowrt unit. ) i% S tn fucJ.90% SO) removal. OfHBtc MUdi dupou!
     Suck fji reheat lo I 75 F bv indi/tct iteun reheat
     DuptxJl pond located 1 Rule ffom po*er pUnt
     MKjvnE pu/it locjiUoft (tptfWMi ptoji Ixipnntnj m.d-1977. endinf mid-197$ Arrrift cott bam Tor icaJtn|. mid-1974
     M^n/mjm 01 peocrtt florist, only pumpi &/t tpiied
     (mntmrni rrquircmenu foi otupoAl of fit lift (tcludfd
     Conitruction UbOf ihmt not conodered

-------
Table k.     LIMESTONE  SLURRY  PROCESS  - TOTAL  CAPITAL INVESTMENT  REQUIREMENTS
    EXISTING CASE8"  SUMMARY -  PROCESS  EQUIPMENT AND INSTALLATION  ANALYSIS
                                     (Thousands  of Dollars)

Ra
Construction
materials Fd

Equipment
Maura)
Labor
Flpint, and tnsutstioa
Material
Labor
ftictwork, chute*, and supports
Us nil
Labor
Concrete foundations
Material
tabor
EJtcava&on. site preparation.
rajjoada. roada, and pond
Structural
Material
Labor
DcctrlcaJ
Material
Labor
Instruments
Material
Labor
hint and nbceuaMout
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
/idirrcf Cotn
Engineering desujn and supervision
Construction Held expense
Contractor fees
Contingency
Subtotal fixed Investment
Allowance for iiarrup and modiftcanons
Interest dunng construction
Total capital investment
Percent of total capital investment
Handling

105
17

1
I

1)
10

14
103

.

11
13

40
105

1
5

1
7

-
-
6
-
4S2

49
63
)4
S3
681
54
54
7S9
J.4
preparation

390
72

14
36

6
1

7
41

-

_
-

59
117

SO
32

1
8

66
15
1
-
1. 000

100
130
70
no
1.410
11)
113
1.636
7.1
SO,
scrubbing

2JIO
42t

353
403

363
37

24
103

-

M
52

102
142

165
103

3
19

-
_
2
-
3.243

324
612
367
577
7.393
592
592
J.577
371

Reheat

186
2)

9
27

-
.

_
1

.

-
-

1
II

35
16

-
_

-
.
_
-
)23

32
42
22
36
455
36
36
527
23

Fans

430
14

_
_

311
386

7
39

_

-
_

135
196

15
9

_
1

-
_
_
.
1.710

171
222
120
188
2.411
193
193
2.797
12.1
Solldi
disposal

67
4

7
99

-
_

1
6

2.7)4

-
3

51
233

11
6

2
16

-
_
291
-
3.611

361
469
153
)97
5.091
407
407
3 90S
256

UUl/oei

31
57

12
19

-
_

1
7

4

-
-

52
67

20
12

4
7

-
.
_
-
3)5

34
44
23
)7
473
)!
)8
549
24
facilities
Strokes 3%

101
32

_
_

-
_

-
-

4J2

.
-

_
-


.

-
-

'l!4
50
14
672
740 672

74 67
96 87
52 47
81 74
1.04) 947
8) 16
83 16
1.209 1.099
52 48

Total

3.847
735

476
385

772
791

54
301

)J02

97
68

447
m

304
183

11
38

ISO
1)5
314
672
14.116

1.412
I.85S
968
US)
19.904
IJ92
IJ92
23.088

rVrcent of
dvrct
nveitment

272
52

34
4 1

5.5
56

04
2.2

217

07
0.5

32
62

21
1 3

0 1
04

l.J
09
2 2
4 8
1000

100
13 0
1 0
II 0
141 0
11 )
11 3
16)6

rVrcentof
total capital
investment

16 7
3Jt

2.1
2J

3J
34

0.2
IJ

139

04
OJ

1 >
3(

1.3
01

01
02

06
06
1 4
29
61 1

6 1
SO
43
6 7
862
69
69

1000
                alinf coJ-firsd power oroi. 3 5%^ tn fud.90% SO] rcmovkl. on-atc tobdi dupoui.
          Stjck |i rtheit to I ?5 F by direct oil-feed reheil
          DupOul pond Ioc*ted I tnJe from power pUnt
          Mxlwett pU/tt locibon rfprfienti project brfutnirtf m)d-l972,ntdtn{ miA-l^IS Avtrtft cot bins for
          Mini mum m proccti ttottf.oniy pump* are fpued
          Rrm.u/)in| U/e of pow vnit. 23 jrf.
          IrrvfiUTunt rtqu(/f-nTft for removal tnd dupoul of Oy uh excluded.
          ConitmtUon labor ihortutt with ucompanymf overttmt pty incmine rvoi conj*derd

-------
                       Table  5-     LIMESTONE  SLURHY  PROCESS
                      SUMMARY OF  ESTIMATED  FIXED  INVESTMENT8
                       (50O-J-W new  coal-fired power uiilt, }.'j% S In fuel;
                            9Q% SO;, removal; onoite solids disposal)
                                                           Investment,  $

LJroeatotie receiving and storage  (hoppers,  feeders,
 conveyors, elevators,  and Mns)                                1*19,000
Feed preparation (feeders, cruisliere,  elevators, ball
 mlllo, tanks, and pumps }                                        899,OOO
Partlculate scrubbers and  Inlet  ducts (t scrubbers
 Including common feed plenum, effluont hold tanks,
 agitators, and pimps)                                        3,20},OOO
Sulfur dioxide scrubbers and ducts  (i scrubbere
 Including mist eliminators, effluent hold tnnks,
 agitators, pumps, and exhaust gas  ducts to Inlet of
 fan)                                                         I^T^.OOO
Stack gas reheat (U Indirect steam  reheaters)                    556,000
Fans (U fans including exhaust gas  ducts and dampers
 betveen fan and stack gas plenum)                               85'i,000
Calcium solids disposal (onelte  disposal facilities
 Including feed tank, agitator,  slurry disposal pumps,
 pood, liner, and pond water return puraps)                    3,923,000
Utilities (instrument air  generation  and supply system,
 plus distribution systems for obtaining procests steam,
 water, and electricity from the power plant)                     ('7,000
Service facilities (buildings, shops, stores, site
 development, roado, railroads,  and valkways)                    638,000
Construction facilities                                         765,000
     Subtotal direct Investment                               l6,069,OOO

Qiglneerlng design and supervision                             I,14|i6,000
Construction field expense                                    1,768,000
Contractor fees                                                 803,000
Contingency                                                   l,fO7,000
     SubtotaJ. fixed Investment                                21,693,000

Allowance for startup and  modi fications                        1,735,000
Interest during construction (8Jk/annum rate)                   1,735,000

     Total capital Investment                                25,163,000
Percent  of subtotal
 direct  Inventojnt
        2.6

        5.6


       19-9
       29-5
        3-5

        5-3
        It.O
        J..8
      100.0
        9-0
       11.0
        5.0
       10.0
      135.0
       10.0
       10.8

      156.6
a Basin:
    Stack gas reheat to 175F by Indirect  cteaa  reheat.
    Disposal pond located 1 mile from power  plnnt.
    Midwest plant location represents project beginning mid-1972, ending mid-1975-   Average
     cost basis for scaling,  mid-igr^.
    Minimum in process storage;  only pumps are spared.
    Investment requirements for disposal of  fly  ash excluded.
    Construction labor shortages with accompanying overtime pay Incentive not considered.
                                             177

-------
                         Table  6.     LIME SLURRY PROCESS
                       VENTURI  -  VENTURE SCRUBBING SCHEME
                     SUMMARY  OF  ESTIMATED FIXED  INVESTMENT"
                       (500-MW new coal-fired ;>ower unit, J-5# S in fuel;
                           90$ GO;, removal;  onslte oolldn disposal)
                                                          Investment, $

Line receiving ana storage  (bins, feeders, conveyors,
 and elevators)                                                795,OOO
Feed preparation (conveyors,  slakers, tanks, agitators,
 and pimps)                                                    387,000
Partlculate - sulfur dioxide  scrubbers and Inlet ducts
 (li r.crubbers Including  conraon feed plenum and pumps)          I*,017,OOO
Sulfur dioxide scrubbers and  ducts (*< scrubbers
 Including mist eliminators,  pumps, find exhaust gas
 ducts to Inlet of fans)                                     5,153,000
Stack gas reheat (14 indirect  steam reheaters)                   $142,000
Fans (U fans Including exhaust gas ducts and dampers
 between fan and stack gas  plenum)                              767,000
Calcium solids disposal  (onsite disposal facilities
 Including elurry disposal  pumps, pond, liner, and
 pond water return pimps)                                     3,356,000
Utilities (instrument air generation and supply
 system, plus distribution  systems for obtaining
 process steam, vater, and  electricity from the
 pover plant)                                                   67,000
Service facilities (buildings, shops, stores, site
 development, roads,  railroads, and walkways)                   552,000
Construction facilities                                         682,000
     Subtotal direct Investment                              lU,318,000

Qngineerlng design and supervision                            1,289,000
Construction field expense                                    1,575,000
Contractor fees                                                7l6,OOO
Contingency                                                  l.lQg.OOO
     Subtotal fixed investment                               19,330,000

Allowance for startup and modifications                       1,5^6,OOO
Interest during construction  (8^/annum rate)                  1,Sli6,000

     Total capital Investment                                22,^22,000
Percent  of  subtotal
 direct  Investment
        2.7

       28.1
       22.0
        5.8
       23-
        0.5

        3.8
        it.8
      100.0
        9.0
       ia.o
        5.0
       10.0
      135.0
      156.6
a Basis:
    Stack gas reheat  to 175F by Indirect steam reheat.
    Disposal pond located  1 mile from power plant.
    Midwest plant location represents project beginning mid-1972, ending mid-1975.   Average
     coat basis for scaling, mid-197tt-
    Minimum In process  storage; only pumps are spared.
    Investment requirements for disposal of fly ash excluded.
    Construction labor  shortages vlth accompanying overtime pay Incentive not considered.
                                            178

-------
                          Table  7-     LIME  SLURRY  PROCESS
                       VENTURI  -  VENTURI  SCRUBBING SCHEME
                      SUMMARY  OF  ESTIMATED  FIXED INVESTMENT0
                     (5OO-HW existing coal-fired power  unit, 3.5$ In fuel;
                               SOp removal;  onslte solids dlspoDal)
                                                                          Percent of subtotal
                                                         Investment, $     direct Investment
Lime receiving and  storage  (bins, feeders, conveyors,
 and elevators)
Feed preparation  (conveyors, sjjikers, tanks,  agitators,
 and pumps )
First stage  sulfur  dioxide  scrubbers and ducte (k
 scrubbers Including common feed plenum, pumpe,  and
 all ductwork between  outlet of supplemental  fans
 and the scrubbers)
Second stage eulfur dioxide scrubbers and ducts  (1.
 scrubbers Including mist eliminators, pumpc, and all
 ductwork between scrulibers and stack gas plenum)
Stack gae reheat  (U direct  oil-fired reheutere)
Fans C* fans including ducts and dampers between tie-
 in to existing duct and Inlet to supplemental fan)
Calcium solids disposal (onslte disposal facilities
 including slurry disposal  pumps, pond, liner, and
 pond water  return  pumps)
Utilities (instrument  air generation and supply  system,
 fuel oil storage and  supply system, and distribution
 systems for obtaining process water and electricity
 from the power plant)
Service facilities  (buildings, chops, stores, site
 development, roads, railroads, and walkways)
Construction facilities
     Subtotal direct investment

Brglneerlng  design  and supervision
Construction field  expense
Contractor fees
Contingency
     Subtotal fixed investment

Allowance for startup  and modifications
Interest during construction (8^/annum rate)

     Total capital  investment
   676.COO
 It, 565, COO

 3,797,000
   305,000

 1,1143,000

 3,01.9,000


   335,000
   6149,000
   758,000
15,913,000
 1,591,000
 2,069,000
 i,ui,ooo
,1,750,000
22, i 37, 000
  5-5

  2.7


 28.7
 23-9
  1.9

  7-2
 19-1
  2.1

  14.1
  14.8
100.0
 1,795,000
 ,1.795,000

26,027,000
163.6
  Basle:
    Stack gaa  reheat to 175F by direct oil-fired reheat.
    Disposal pond  located 1 mile from power plant.
    Midwest plant  location represents project beginning mid-1972, ending mid-1975.   Average cost
     basis for scaling, mid-19714.
    Minimum In process storage; only pumps are spared.
    Remaining  life of power unit, 25 yr.
    Investment requirements for removal and disposal of fly  ash  excluded.
    Construction labor shortages with accompanying overtime  pay  Incentive not considered.
                                             179

-------
             Table  8.     MAGNESIA SLURRY  -  REGENERATION PROCESS
                      SUMMARY OF  ESTIMATED  FIXED  INVESTMENTS
                       (500-MW neji  coal-fired power unit, 3. 5J& E In fuel;
                            905Ts02 removal; 15-8 tona/hr 100% H^SOj


                                                           Investment,  $

Magnesium oxide and coke receiving  and  storage (pneumatic
 conveyor and blower,  hoppers,  conveyors, elevators, and
 storage olios)                                                 192,000
Psed preparation (weigh feeders,  conveyora, elevators.
 Blurry ing tanX, agitator,  and pumps)                            238,000
Particulate ocrubbero  and Inlet ducta  (U scrubbers
 including common feed plenum,  effluent bold tanks,
 agitators, pumps,  and fXy  aoh neutralization facilities)      3,966,000
Sulfur dioxide scrubbers and ducts  C  scrubbers
 includJrag ndot elJmJnatorc,  piznpc,  and exhaust gas
 ducte to Inlet of  fan)                                       2,592,000
Stack gaa reheat (lj Indirect  steam  reheatere)                    509,000
Fans (*4 fans Including exhaust gas  dueta and dampers
 between fan and stack gae  plenum)                               71*1,000
Slurry processing (screens, tanks,  pumps, agitators and
 beating colls, centrifuges,  conveyors, and elevators)           711,000
Drying (fluid bed dryer, fans,  combustion chamber, dust
 collectors, conveyors, elevators,  and MgS03 storage silo)       972,000
Calcining (fluid bed calclner,  fans, weigh feeders,
 conveyors, elevators, waste beat boiler, duct collectors,
 and recycle /feO storage silo)                                1,1O8,OGO
Sulfurlc acjd plant (complete contact  unit for sulfurlc
 acid production including  dry gas  purification systejn)        J,197,000
Sulfurlc acid storage  (storage and  shipping facilities
 for 30 dayo production of  H^SO-j)                               278,OOO
Utilities (instrument  air generation and supply oystem,
 fuel oil storage and  supply  system, and distribution
 systems for obtaining process steam, water, and
 electricity from power plant)                                   269,000
Service facilities  (buildings,  nhops,  stores, site
 development, roads, railroads, and walkways)                    78},OOO
Construction facilities                                         778,000
     Subtotal direct Investment                              16,3311,000

Qiglneerlng design  and supervision                             1,797,000
Construction field  expense                                     1,797,000
Contractor fees                                                 817,000
Contingency                                                   1.633.000
     Subtotal fixed Investment                               22,378,000

Allowance for startup  and modi flcatlonc                        2,238,000
Interest during construction (8^/annum rate)                   1,790.000

     Total capital  Investment                                26,'i06,OOO
                                                                          Percent of subtotal
                                                                          direct Invegtnent
                                                                                 1.2

                                                                                 1.5


                                                                                21.. J
                                                                                15.9
                                                                                 3-1
                                                                                 "-3

                                                                                 5-9

                                                                                 6.8

                                                                                19-6

                                                                                 1.7


                                                                                 1.6

                                                                                 U.8
                                                                                100.0
                                                                                n.o
                                                                                ll.o
                                                                                  5-0
                                                                                10.0
                                                                                137.0

                                                                                13.7
                                                                                11.0

                                                                                161.7
a Basis:
    Stack gas reheut to 175F by  Indirect  steam reheat.
                                                                                   Average
Mldweot plar.t location represents projects beginning mid-1972, ending mid-1975-
 coot basis for scaling,  mid-l97ti.
Minimum In proceoo storage;  only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first  stage.
Investment requirements for disposal of  fly aeh excluded.
Construction labor ohortufieo with accompanying overtime pay Incentive not conaidered.
                                              180

-------
               Table  9-     SODIUM  SOLUTION  -  S0a REDUCTION  PROCESS
                         SUMMARY  OF  ESTIMATED FIXED  INVESTMENT
                       (500-MW jneu coal-Tired power unit, 3.5^ 8 In fuel;
                              90? SOj  removal; It.7 tong/hr sulfur)
Soda ash and antloxidant receiving,  otorage, and
 preparation (pneumatic conveyor and blower,
 feeders, mixing tanX,  agitator, and pumps)
Particulate scrubbers and Inlet  ducts  (1*  scrubbers
 Including common feed plenum, effluent bold tanks,
 agitators, pumps,  and fly ash neutralization
 facilities)
Sulfur dioxide scrubbers and ducts  (It  scrubbers
 Including mist eliminators,  pumps,  and exhaust
 gas ducts to Inlet of fan)
Stack gas reheat (It indirect steam  reheatero)
FBJIB (1* fans Including exhaust gas  ducts  and dampers
 between fane and stack gas plenum)
Purge treatment (refrigeration system, chiller-
 crystalllzer, feed coolers,  centrifuge,  rotary dryer,
 steam/air heater,  fan, dust collectors,  feeders,
 tanks, agitators,  pumps,  conveyors, elevator, and
 bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
 heaters, condensers, strippers, compressors,
 desuperheater, tanks,  agitators, and  pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for
 JO days production of molten sulfur)
Utilities (instrument air generation and  supply
 system, and distribution systems for  obtaining process
 steam, water, and electricity from power plant)
Service facilities (bulldingSj shops,  stores, site
 development, roads, railroads,  and walkways)
Construction facilities
     Subtotal direct Investment

Bigineerlng design and supervision
Construction field expense
Contractor fees
Contingency
     Subtotal fixed Investment

Allowance for startup and modifications
Interest during construction (8^/annum rate)

     Total capital Investment
                                                           Investment.  $
   225,000
 3,8li6,ooo
 14,269,000
   539,000

   889,000
 1,1473,000
 2,717,000
 2,921,000

   227,000
   195,000

   662,000
   898.000
18,861,000

 2,075,000
 2,075,000
   9113,000
 1.886,000
25,81(0,000

 2,58^,000
 2,067,000

30,1491,000
                 Percent of subtotal
                 direct Investment
                        1.2
 20. U



 22.6
  2.9

  14-7
  7-8


 lU.U
 15-5

  1.2


  1.0

  3-5
  U.8
100.0

 11.0
 11.0
  5.0
 10.0
137.0

 13-7
 11.0

161.7
  Basis!
    Stack gas reheat to 175F ^ Indirect steam reheat.
    Midwest plant location represents  project beginning mid-1972, ending mid-1975-   Average
     cost basis for scaling, mld-197't.
    Minimum In process storage;  only pumps are spared.
    Fly ash slurry neutralized before  disposal; closed loop water utilization  for  first stage.
    Investment requirements for  disposal  of fly ash excluded.
    Conetructlon labor shortages with  accompanying overtime pay Incentive not  considered.
                                                181

-------
                    Table  10.     CATALYTIC OXIDATION  PROCESS
                                                                          o
                     SUMMARY  OF ESTIMATED FIXED  INVESTMENT
                       (500-MW
new coal-fired power unit, 3-5/6 S In fuel;
t ROP removal;  15-7 tong/br 1OO% H5O4)
                                                          Investaentf ft

Converter and abnorber startup bypass ducts and
 danpers                                                       !'91,000
Electrostatic precipl tators  and  Inlet, ducts (U
 high temperature electrostatic  precipltutors
 Including cotncicm feed plenum)                                 8,736,000
Sulfur dioxide converters  and ducto  C* converters
 Including catalyst sifter,  hopper,  etoro^e bin,
 conveyors, and elevatorc)                                     2,1^5,000
Heat recovery and ducts (^ stean/alr heaters and k
 flujd/alr beaters Including ducts betveen
 economizers and air heaters, and combustion air
 ducts and dampers between poverhouoe and sir heaters;
 Investment credit for uoe of smaller air heaters
 included)                                                    1,1<75,OOO
Fane (Ij ID fans including  exhaunt gas ducto and
 dampers betveen 3D fane and stacX gas plenun)                 1,|JL?,000
Sulfurlc acid absorbers and  coolers  (2 absorbers
 Including mist eliminators, coolers, tanXe,
 pumps, and ducts and  dampers betveen air heaters
 and ID fans)                                                 8,917,000
Sulfurlc acid storage  (storage and shipping
 facilities for 30 days production of H^SO.,)                    ^09,000
Utilities (instrument  air  generation and supply
 system, and distribution  systems for obtaining
 process steam, vater,  and electricity from power
 plant)                                                         57,000
Service facilities (buildings, shops, stores,  site
                                               Percent of subtotal
                                               direct Investment
                                                      1-9
                                                      8-5
                                                      5.8

                                                      5-6


                                                     35-2

                                                      1.6


                                                      0.2
development, roads, railroads, and walkvays)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed Investment
Allovance for startup and modifications
Interest during construction (Si^/annum rate)
Total capital Investment excluding catalyst
Catalyst
Total capital investment
518,000
1,208,000
25,368,000
2,790,000
2,Y90,OOO
1,268,000
2,517,000
3Mw,ooo
3^75,000
2,780,000
111, 008,000
1,728,000
1*2,736,000
2.0
14.8
100.0
11.0
U.n
5.0
10.0
137.0
1J-7
11.0
161.7
6.8
168.5
a Basle:
    Midwest plant location  represents project beginning mid-1972, ending mid-1975-
     coot baols for scaling, mid-1971*.
    Only punpo are spared.
    Investment requlremento for disposal of fly aoh excluded.
    Construction labor shortages vith accompanying overtime pay  Incentive not considered.
                                          182

-------
                            Table 11.     SUMMARY  - TOTAL CAPITAL INVESTMENT  REQUIREMENTS
           Case

Coal-fired pover unit

90j S02 removal; onsite solids  disposal
    200 MW new, 3.5$ sulfur
    200 MW existing, 5-5* sulfur
    500 MW existing, 3.5$ sulfur
    500 MW new, 2.o sulfur
    500 MW new, 3.5% sulfur
    500 MW new, 5.0* sulfur
   1000 MW existing, 3.5$ sulfur
   1000 MW new, 3.5% sulfur
    SOg removal; onsite solids disposal
    500 MW new, 5.5^ sulfur

    S0j> removaJ ; of fsite solids disposal
    500 MW new, 3.5% sulfur
90% S02 removal; onsite solids disposal
  (existing unit without existing
  participate  collection  facilities)
    500 MW existing, 3.5% sulfur

Oil-fired pover unit

90$ SOg reaoval; onsite solids disposal
    200 MW new, 2,5 sulfur
    500 MW new, 1,0? sulfur
    500 MW new, 2.5i sulfur
    500 MW new, ^.0^ sulfur
    500 MW existing, 2.5$ sulfur
   1000 MW new. 2.5* sulfur
Years
life
30
20
25
50
30
30
25
50
50
30
Limestone process
._ .,.* ._..
13,031,000
11, 3^,000
23,083,000
??,6oo,ooo
25,163,000
27,3^3,000
55,133,000
.57,725,000
21* ,267, 000
20,532,000
s /VU
.r/_K.7
65.2
56.7
U6.2
1*5.?
50.3
^.1
35.1
37.7
k8.5
1*1.1
Lime
1
11,71*9
13,036
26,027
20,232
22,1*22
21*, 272
38,133
32,765
21,586
18,323
process

,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
|/kW
58.7
65.2
52.1
1*0.^
1*1*. 8
1*8.5
33.1
3?.3
1*3.2
36.6
Magnesia process
$
l!,139,000
I1*, 572, 000
26,026,000
22,953,000
26,1*06,000
29,355,000
38,717,000
38,865,000
25,568,000
_
J/kW
70.7
71.9
52.1
1*5.9
52.3
53.7
58.7
33.9
51.1

Sodium process
$
16,198,000
17,11*9,000
31,208,000
26,706,000
50,1*91,000
33,709,000
1*7,721,000
1*5,832,000
29,127,000

$/kW
31.0
85.7
62.1*
53.^
6l.O
67.1*
1*7.7
U5.8
58.3
^
Cat-Ox process
$
19,557,000
17,735,000
37,907,000
Ii2, 520,000
1*2,736,000
1*2,923,000
62,913,000
69,889,000
-

$AW
97.7
33.7
75-8
35.0
35-5
35.9
62.9
69.9
-
>
25   29,996,000   6o.O   26,090,000  52.2  32,213,000  &*.!  37,957,000  75-9 !*3,8l6,OOO  87.6
30
30
30
30
25
30
3,263
12,935
15,^73
17, -31
13,657
23,331*
,000
,000
,000
,000
,000
,000
M.3
25.9
50.9
35-0
37.3
23. *
9,1*82,000
15,961,000
13,11*3,000
19,361,000
21,317,000
26,31*1,000
1*7. 1*
31.9
36.3
39-7
1*3.6
26.3
8,361,000
12,695,000
l6,oGo,000
13,765,000
20,376,000
23,656,000
U4.3
25.1
32.2
37.5
1*0.3
23.7
10,32l*,OOO
15,196,000
18, 9^9, 000
21,893,000
2l*,'*1*5,000
28,765,000
51.6
30.fc
37.9
1*3.8
1*8.9
23.8
13,069,000
28,067,000
23,277,000
23,1*1*9,000
32, 821* ,000
1*6,356,000
65.3
56.1
56.6
56.9
65.6
*6.l4
 a Midwest  plant location represents project beginning mid-1972, ending mid-1975.  Average cost basis  for  scaling, mid-1971*.  Minimum la
   procesc  storage; only pumps are spared.   Investnent  requirements for disposal of fly ash excluded.  Construction labor shortages vith
   acconpanying overtice pay incentive not  considered.
   All Cat-Ox  installations require particulate removal to  0.005 gr/scf prior to entering converter.   Because existing units are assumed
   to already  =eet EPA standard!) (0.1 lb particulote/MM Btu of heat Input).  Only incremental additional precipitator is required.

-------
   1.  Lime slurry

   2.  Limestone slurry

   3.  Magnesia slurry - regeneration

   ^.  Sodium solution - S02 reduction

   5-  Catalytic oxidation

Shewn in Figures 12 and 15 are the effects of unit size and sulfur con-
tent, of coal OP. investment for installations on new units.  In comparing
these rankings, it should "be pointed out that the lime slurry process
does not provide facilities for calcining limestone, and includes a
minimum of facilities for storage of the calcined material.

          An important result derived by comparing the investment pro-
jections in this study is the relatively minor investment savings
realized (3-2-^. 5 A") in designing for So^- S02 removal as compared to 90/s.

          The projected investments for limestone and lime slurry pro-
cesses designed for offsite solids disposal represent savings equivalent
to approximately lS>% of the projected onsite investment.  Hovever, these
projections do not include the capital for offsite waste treatment
facilities.

          Accuracy.  In reviewing the capital investment estimates for
these five processes, it should be understood that the base case process
definitions and estimates represent a generalized cost.  As an indication
of how the project scope and corresponding investment could vary, the
effect of "add ons" to the limestone slurry process base case estimate
is shown in Table 12.  Such "add ons" as delays in equipment delivery,
physical space limitations, additional redundancy requirements, taller
stacks, inclusion of a closed-loop fly ash disposal pond, and overtime to
accelerate the project completion schedule could more than double the in-
vestment for the limestone slurry process.  Excluding these additional
costs, but considering only the data available for this appraisal  and the
depth of investigation,the estimated investment accuracy for each of the
processes is given in Table 13.


           Table 13.   PROJECTED INVESTMENT ESTIMATES ACCURACY
            BASED ON AVAILABLE DATA AND DEPTH OF INVESTIGATION
               	Process	      range

               Limestone slurry                 +20 to  -5
               Liine slurry                      +20 to -10
               Magnesia slurry - regeneration   +25 to -15
               Sodium solution - regeneration   +25 to -10
               Catalytic oxidation (Cat-Ox)      +20 to -10
                                   184

-------
                   100
00
Ln
                P
                w
                o
                o

                -P
                c
                0)
                s
                P
                w
                +5
                H

                C!
                     25
                      0
Limestone Slurry Process  X

Lime Slurry Process  A

Magnesia Slurry-Regeneration Process  0

Sodium Solution-S02 Reduction Process Q

Catalytic Oxidation Process  n
                               S in coal

                              S02 removal
                       0
        200
^00         600         800


     Power unit size, MW
1000
                        Figure 12.   New coal-fired,  units  -  the effect of power unit size on

                                    unit investment cost, dollars  per kilowatt

-------
                   100
            Limestone Slurry Process  X
            Lime Slurry Process A
            Magnesia Slurry-Regeneration Process  0
            Sodium Solution-S02 Reduction Process Q
            Catalytic Oxidation Process  


            90% SQS removal
00
-P
W>
O
O

-P
c
IP
a
P
w
OJ
               H

               P
                    50
                    25  -
                     o
                       0            1           2           3          ^            5

                                                   Sulfur in coal, %

                       Figure 13    500-MW new coal-fired units - effect of sulfur content of
                                           coal on unit  investment cost

-------
                        Table 12.     LIMESTONE  SLURRY PROCESS  INVESTMENT  WITH MODIFIED  PROJECT  SCOPE
                                                                                                                  Investment,
                    BASE INVESTMENT - LIMESTONE SLURRY PROCESS (including Fly Ash Removal But Not Disposal)

                    500-MW new coal-fired unit burning coal with 3-5% S,  12% ash, 90% S02 removal, 30-year life
                    127,500 hours operation, onsite solids disposal,  proven system,  only pumps spared, DO
                    bypass ducts, experienced design and construction team,  no overtime, 3-year program, 5% per
                    year escalation, mid-197U cost basis for scaling                                                 50-30

                    A.  Overtime to accelerate project or cover local demand requirements
                          (50% of construction labor requirements)                                                    3-20

                    B.  Research and development costs for first of a kind process technology
                          (as allowed by FPC accounting practice)                                                     5.00

                    C.  Power generation capital for lost capacity (normally covered by appropriate
                          operating costs for power used in process)                                                  'JO
oo
-^                  D.  Reliability provisions with added redundancy of scrubbers, other equipment,
                          ducts and dampers, instrumentation for change over (assumes no
                          permission to run power plant without meeting S0$ removal  emission
                          standards at all times)                                                                     T.OO

                    E.  Additional bypass ducts and dampers.                                                           1.00

                    F.  Retrofit difficultymoderate, space available beyond stack,  less than
                          three shutdowns required for tie-ins, field fabrication feasible                            10.00

                    G.  Fly ash pond including closed-loop provisions                                                 5-50

                    H.  500-ft stack added to project cost                                                            6.00

                    I.  Air quality monitoring system, 2-15 mile radius,  10 stations                                  0-70

                    J.  Cost  escalation of 10% per year instead of 5$                                                 b.oO

                    K.  Possible delay of up to 2 years in equipment and  material deliveries
                           (1977 completion instead of 1975 )                                                          1?/.

                              Total                                                                                  W'

-------
Allfji.-1?I Operatin~ Costs

          For the annual operating costs covering 7000 hours per year
operation, the following types of displays are used for each process:

     Su~.7iarized effect of individual process areas on total costs--
     presented for base case and existing 500-MW limestone case.  See
     Tables 1^ and 15.

     Case variationsoperating cost summaries presented for each of
     the l6 case variations.  See Tables 16-21.

          Table 22 presents the total average annual operating costs for
the l6 case variations of all five processes excluding credit for any by-
products produced.  Corresponding to new 3.5 S coal-fired units, the
relative ranking of average annual operating costs for the processes
(base case) is as follows:

   1.  Limestone slurry

   2.  Lime slurry

   3-  Catalytic oxidation

   k.  Magnesia slurry - regeneration

   5.  Sodium solution - S02 reduction

          Some important effects are not readily seen in comparing the
ranking of processes for only one plant size and sulfur level.  As
determined in this study, the relative ranking of operating costs of the
various processes is sensitive to changes in the assumed sulfur content
of the fuel.  As an illustration, a 500-MW, 1/6 S oil-fired power unit
using the catalytic oxidation process has the highest operating cost of
the five processes; but for fuel oils with sulfur contents greater than
^.O/o, this process has the lowest cost.  Although the sodium process is
not the lowest cost process for any of the cases presented in this study,
it becomes more competitive for low-sulfur fuel oil-fired units.  Further-
more, at the expense of small additional investment, its operating cost
could be lowered by designing the process with multiple-effect evapora-
tors thereby reducing the overall energy requirements about l8/c.

          In all of the projected annual operating cost estimates,
capital charges are the most significant components followed by mainte-
nance, energy, and raw material costs in varying orders of importance.
For the magnesia and sodium processes which require thermal energy for
regeneration of absorbent, steam or fuel oil are the second most signifi-
cant components.  Lime cost (which requires thermal energy in preparation)
is the second most predominant item for the lime slurry process, whereas
maintenance is second in predominance for the limestone slurry and
catalytic oxidation processes.


                                   188

-------
                        Table lU.     LIMESTONE SLURRY  PROCESS  - TOTAL AVERAGE  ANNUAL OPERATING COSTS
                                           BASE CASEa SUMMARY -  AREA CONTRIBUTION  ANALYSIS
CO
VO




Mwrtrai
zrmMM
AattMl qwwttfy. tow
AMU! cert. S
MMi n MMI COM
Aural IJ 017. *
AoDoal COM. S
UttlM
ATLi <)u.air. M ft
AanlooM.I
rroomwmr
Am  fetal Mk4 M*wW)
totMt of o*ct MI imMl
Anulootf.1
Alym
AaoMi omMtttty. br
Anorfoott.1
S^ionl ujiam na
  '
Ann* oonl duc|> 11 14 9
ofeiDflil milml
OrrtxW
Ptut. 20oreaonmmco*a
Aaiwunnt. 10% of
opontmt boat
idtoul imlnct OOM>
Tom n.d oofct COM
r*oM of Ml a-ul oond^ c
1U-
Hrtak
Total Hndluw
16,069,000 419,000

4OO/B.
175.000
700.000
700.000
4.170
))/00



0.01/Mpl


ooio/un
190^300
3^00

(
23JOO
\ioon*
ISM
11.200
18.200 (2JOO
7IUOO (2JOO

97.700

jjtm njoo

JJOO
3/00 I11JOO
7JI.JOO I75JOO
1 9.37 2JI
r-t
prrpttnooa
899.000





6.470
51.700







5.150JOO
51JOO

1
71JOO



174 JOO
174 JOO

209.800

14.800

S^JOO
249.800
4 24.000
SJO
rwtkJib>
KTUbbmt
1.201.000





4^00
39JOO







.440X00
(4.400

10
320.000

7(0
9,100
4)2.700
432.700

747.400

MJOO

3.900
837.800
1J70JOO
U-.9
SO,
mubbtri
4.143000





40
39 JOO




174.700
14.000

!2J 30.000
225 JOO

11
322.000

1.140
13,700
814.200
8I4JOO

1.107.000

1(2^00

1,900
1.273.800
2.018.000
27.11

KtlMWI
556.000





1J50
10.000

492 JOO
345400







*
44 JOO



399 JOO
399JOO

129 JOO

79.900

1,000
210.100
1 10 JOO
792

Fui
854.000
1.337.000




IJ50
10.000







43.0W.OOO
430.MO

8
MJXM



508.800
5MJOO

199 JOO

101 .WO

1.000
302.000
810.WO
10J)
CilaB
dupouj Ubltlte* SCTTKC*
3.911.000 61000 631.000
6.143.000 105.000 999.000




JJ40
24.700




7S.WO
(.000

700.000 2)0.000 220.000
7.000 2JOO 2JOO

(
2)5.000

)80
4,(00
279.300 2.300 2.200
279JOO 2JOO 2JOO

915.300 15/00 148.900

55.900 500 400

!,700
971.900 16.100 149.XW
1JJJJOO 11.400 151JOO
1(27 OJ4 1.97
Tout Too*
faalitia qmt)bM dolUn i
765000


175.000
7oaooo
700X100
2*J
2IOJM

492JOO
345^700

ISO JOO
10 JOO

71.740.000
717.400

1
UUJOO

3JOO
45/00
2/93,700
JJ93.700

171 JOO 3.749JCO

53J.700

21.000
171 JOO 4J09.000
178 JOO 7.702.700
2J2
2Z,
BOWuf OOM




tat
tm

in


4U


tJ*


MJQ


l(*9


OJ9
3497
440*

44 U

(9

0-27
55.94

moo
DoQjui/to* Catiymifikn OoflMVtOB
cod bunMd WiBiAWIi Bra hal Bt^at wtfur renra*d
t )4J
"
1)* 61






                                              >l.90JO,
                        KonMnmf ttfc of pow piiAt. 30 rr.
                        Col bunol. 1 J12JOOtlooVrt. 9.000 tra/in
                        Suet (Mrctwst 10 175*P
                        Pow atvl cmumu 09*. 7jOOO br/yr.
                        M^f) pbuit loeaoott. 1973 opran| coct*.
                        Silttt mxL 35 J80 lofu/rr nuiU dupoM. 206.000 tooVn
                             t Kid OOW1OBC cxM for dl^towl of fly h
todlm omrt T*1 -

-------
Table  15.     LIMESTONE SLURRY PROCESS  -  TOTAL AVERAGE ANNUAL OPERATING  COSTS
                 EXISTING  CASEa SUMMARY  - AREA  CONTRIBUTION ANALYSIS

Toul
Dtrecl capital uwncmcnt. $ 14.116.000
Total capital ur-nfmeal. I 21088.000
0DTC* Corn Htm
M-TT-1 TIT Tnnmal Ulu< Cotl- * li
Lunotonc 4 00/tos
Annual quantity, torn 178.900
Annual con. 1 711600
Subtotal raw material coal 711400
CuU'tiuoo com
Operating, labor and Jper*taw>ai I OQfma4tf
Annual quantify, mtn-tu
Annual coit, S
Fud 04 (So 6J 0.21/pl
AnnualtivaaatT.pl
Annual con. S
rroorm-aw 008/n pi
Aa/iual qua/>urr. M sal
Annual coit. S
EtectTKirr 0010/VWb
Annual quantity. a Wo
Annual con. S
Maintenance (labor tod wper*mof)l
Percent of direct urvcatrneat
Annual con. S
Analyiea UOOfttt
Aonualquaaary.hr IJ20
Annual con. S 18200
Subtotal cooeruoa ceeta 18.200
Subtotal direct com 7] 1400
ttutrret Cao
A*craf capital charfc* at 1 1.3%
of cipttAl t/neftzncat
Rant. 20% of cofrrtmon cocta 1400
Adnunstribve, 10% of
open tai| Ub.OOU








6480
11.400







SJ60.000
12.600

8
so.ooo



1M.OOO
IM.OOO


UOJOO
37JOO

1.100
292.800
478.800
607
so,
tc nibbing

1.577.000








t.760
70.100




17^400
IOOO

U.010000
2JOJOO

12
Jt 213






907
907



l.M


12.1]


OJ


831


I4JI


0-Sa
)t 2t
J>


44 75
7U

on
5267

100.00
DoOan/toa Crou/millkMi DoQan/UM
coa/ burned KOU/lMl
qur*al*nt total otat oomtins coat 188 224
Brti (leal input uti/uf rtmo*d
2411
211 17
  309-I4V eiQAf co^n/cd poJ. 16^-40 totiVyt. oUii dupouL IlOiOO totW)T ulcium totkU in^fudlni ontr h
  lirvntPiail

-------
                     Table  l6.     LIMESTONE SLURRY  PROCESS
                                                                                          
TOTAL AVERAGE ANNUAL  OPERATING  COSTS -  REGULATED  UTILITY  ECOIOMICS
                      (500-MW new coal-fired power unit, 3.5 8 in fuel;
                          90?t S02 removal; onalte solid*  disposal)
            Direct Costa

Delivered raw material
  Limestone
     Subtotal raw material
                                  Annual quantity    Unit cost, $
       175.0 M tons  U.OO/ton
Conversion coats
  Operating labor and
   supervision
  Utilities
    Steam
    Process water
    Electricity
  Maintenance
    Labor and material,  .08 x l6,o69,OOO
  Analyses
     Subtotal conversion costs

     Subtotal direct costs
    26,280 m*n-hr    8.00/man-hr
   1492,800 M Ib
   250,300 M gal
78,7l!0,COO kWh
 0-70/M Ib
 0.08/M gal
0.010/kWh

Total annual
cost, $
700,000
700,000
210,200
3^5,000
20,OOO
787,^00
1,285,500
2,693,700
3,393,700
Percsit of
total Jnnual
operatic cost
9. OS
9-09
2.73
U.1.8
0.26
10.22
16.6?
W..06
          Indirect Costs
Average capital charges at I1.95t
of total capital investment
Overhead
Plant, 20^ of conversion costs
Administrative, lO'jt of operating labor
Subtotal indirect costs
Total annual operating costs
Dollars/ton
coal burned Mllls/kHl
Equivalent unit operating cost 5-87 2.20
3,7'<9,300
538,700
21,000
i, 309, ooo
7,702,700
Cents/million
i Btu heat input
21.. 145
1.8.68
6-99
100.00
Dollars/ton
sulfur removed
211.. 68
  Basis:
    Remaining life of power plant, 30 yr.
    Coal burned, 1,302,500 tons/yr, 9,000  Btu/kWh.
    Stack gas reheat to  175*F.
    Power unit on-stream time, 7,OOO hr/yr.
    Midwest plant location, 1975 operating coets.
    Total capital investment, $25,l63,OOO; subtotal direct Investment, $16,069,000.
    Working capital, $572,600.
    Investment and operating cost for disposal of fly ash excluded.
                                           191

-------
                          Table  17.     LIME SLURRY  PROCESS
                        VENTUKT  -  VENTURI  SCRUBBING  SCHEME
  TOTAL AVERAGE  ANNUAL  OPERATING COSTS  -  REGULATED UTILITY  ECONOMICS*1
                      (50O-MWnew coal-fired power unit, J.5% 3 in fuel;
                                  removal; onslte solids rilspoial)
                                Total annual
_Annual quantity    Unit coat,	$    cost, ?
            Direct Coats

 Dellverci  raw material
   Lime
     Subiotal row material

 Conversim costs
   Operating labor and
   supervl a Ion
   Utilises
    Stcnn
    Process water
    FJ.ec',rlclty
   Mslnteinnce
    Labor  and material, .08 x I1* ,318,000
   Analyses
     Subtotal conversion costs

     Subtotal direct costs
      81.2 H tons   22.00/ton
    22,}20 man-hr    8.00/man-hr
   li90,OOO M Ib
   2l 1,900 M gal
7>4,100,000 XWh
178,600
                                                                                  Percent of
                                                                                 total annual
                                                                                operating cost
             22.03
             22.05
2.20
0.70/M Ib
0.08/H gal
0.010/kWh



3I'3,000
19,!400
71U,000
I,ll45,l400
36!500
2,1463,900
!i, 250, 300
14.23
0.2li
9.15
Il4.ll4
0.145
52. '46
           Indirect Costs

Average capital charges at I1*.9^
 of totfl  capital Investment
Overhen
  Plant, 20^ of conversion costs
  Administrative, lO^- of operating labor
     Sibtotal indirect costs

     T'taJ annual operating costs
                                  3,3140,900

                                    1492,800
                                     17,900
                                  3,351,600

                                  B,101,9OO
            1OO.OO
Equivalent unit operating cost
                                         Dollars/ton             Cents/million    Dollars/ton
                                         coal burned  Hllla/kWh  Btu  heat Input  sulfur  removed
                                            6.17
                                 25.72
           225.61
  Basis:
    Remaining life of power plant, 30 yr.
    Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
    Stack gas reheat to 175F.
    Power unit on-stream time, 7,OOO hr/yr.
    Midwest plant location, 1975 operntlng costs.
    Total capital Investment,  $22,1422,000; subtotal  direct investment,  $l*i ,313,000.
    Working capital, $714|4,000.
    Inveotmcnt and operating cost for disposal of fly ash excluded.
                                            192

-------
                            Table 18.     LIME  SLURRY  PROCESS
                         VENTURI -  VENTURI SCRUBBING SCHEME
   TOTAL AVERAGE ANNUAL OPERATING COSTS  - REGULATED UTILITY  ECONOMICS
                                                                                               a
                    (500-MW ex 1_ctlna coal-fired power unit, 3-5^ 6 In  fuel;
                              "S0p  removal;  onslte solids disposal)
             Direct Cocts

Delivered raw material
  Lime
     Subtotal rnv material
                                   Annual quantity
                                        83.0 M tone
Conversion  costc
  Operating labor and
   ou}x.-rvlsion
  Utilities
    Fuel  oil  (No. 6)
    Process water
    Hectrlclty
  Maintenance
    Labor and material, . OS x  15,913,000
  AnnlyneB
     Subtotal conversion costo

     Subtotal direct costs
                                      22,320 mun-hr

                                   14,236,000 gal
                                     2'eratlng  labor
     Subtotal  Indirect coetB

     Total annual operuti nf. cor.tr-
EqulvaJent  unit oj yr.
    Coal burned, l,3'il,7OO tone/yr, 9,200 Htu/kWh.
    f!tnck pno reheat to J75F.
    Power unit on-ntream time, 7,OOO hr/yr.
    Midwest plant location, 197';  operating costs.
    Total capital investment,  $26,027,000; eulitotal direct Inveutment,  $1';,91>,OOO.
    Working capital, $863,300.
    Jnventraent and operating cost for removal find  dinpocal of fly aoh excluded.
                                              193

-------
            Table 19.    MAGNESIA  SLURRY  -  REGENERATION PROCESS

 TOTAL AVERAGE ANNUAL  OPERATING  COSTS  -  REGULATED  UTILITY  ECONOMICS*"
(50O-MW now conl-flred power unit,  3.51k 3 in
   9O% SOa removal j  110, kOO tons/yr
                                                                fuel;
             Direct Costs

Delivered raw material
  Lime (1st  stage neutrnll zation)
  Magnesium  oxide (96%)
  Coke
  Catalyst
     Subtotal raw material

Conversion coats
  Operating  labor and
   supervision
  Utilities
    Fuel oil (No. 6)
    Steam
    Heat credit
    Process  water
    Electricity
  Maintenance
    Labor and material, .0
  Analyses
     Subtotal conversion costs

     Subtotal direct costs
           Indirect Costa

Average  capital charges at  I
 of total  capital investment
Overhead
  Plant, 2O?t of conversion  costs
  Administrative and marketing,
   U.% of  conversion costs
     Subtotal Indirect costs

     Total annual operating costs
Equivalent unit operating cost  83.


Annual quantity
;ion) 15*1 tons
1,036 tons
763 tons
1,800 liters

39,200 man-hr
5,356,000 gal
^0,000 M Ib
20,300 MM Btu
2,207,500 M gal
71,060,000 XWh
: 16,35^,000

.a

.*
ists
>


108 tS
Dollars/ton Dollars/ton
10O% HpSO* coal burned


Unit cost, $
26.00/ton
155-00/ton
15.00/ton
1.65/liter

8.00/raan-hr
0.25/gal
0.70/M Ib
-0.60/KM Btu
0.0^ /M gal
0.010/XWh











Total annual
cost, 
3,500
168,300
n, 'too
3.000
186,200
313,600
1,231,900
300,000
(12,200)
88,500
710,600
I,lli3,l400
'102,' ooo
5,885,600
"4,071,800
5,931',500
777,100

U27,'iOO
5,159,000
9,210,8oo
Cents/ml Ulion
HlUs/kWh Btu
heat Input
Percent of
total annual
opt-mtlng cost
O.C^
1.85
0.12
0.05
2^02
3.-0
13-39
3.3^
(0.13)
0.96
7.71
12. tl
1.11
2.19
I.1..81
1.2.71
8.W

ij.6i
55.79
100.00
Dollars/ton
sill fur removed
                    7-02
2.63
29.
255. "O
8 Basis:
    Remaining life of power plant, 50 yr.
    Coal burned, 1,512,500 tons/yr, 9,000 Btu/kWh.
    Stack gas reheat to 175*F.
    Power unit on-streara time, 7,000 hr/yr.
    Midwest plant location, 1975 operating costs.
    Total capital Investment, $26,06,OOO; subtotal direct Investment, $l6,331* ,OOO.
    Working capital, $721,000.
    Investment and operating cost for disposal of fly ash excluded.
                                           194

-------
            Table  20.     SODIUM SOLUTION  - S02  REDUCTION  PROCESS
  TOTAL AVERAGE ANNUAL OPERATING  COSTS -  REGULATED  UTILITY  ECONOMICS"
                      (50O-MW new coM-rired power unit, J.5f 3  In  fuel;
                                  removal;  >2,7OO ton/yr sulfur)
             Direct Coats

l>e!1vLTcd  raw mnterlala
  Lime (1st  sta^e neutralization)
  Soda esh
  Antloxidant
  Catnlyst
     Subtotal re" materials
                                 __Annun_l__g_t]n_tltjj^_   Unit c
     13^.1  tons
     9,300  tons
   317,100  Ib
Conversion  costs
  Operating labor and
   supervision
  Utilities
    NaturaJ. gas
    Steam
    Heat credit
    Process water
    Electricity
  Maintenance
    Lnbor and material,  .06  x  l3,86l,000
  Analyses
     Subtotal conversion costs

     SubtotaJ direct costs
    1*6,5CX) ronn-hr

   509,500 mcf
 2,137,800 M Ib
    62,900 MM Btu
 9,955,''00 M gal
7^,190,000 kWh
                                               Pel cent of
                                Total  annual   total annual
                                  cost,  $     operating coet
26.00/ton
52.00/ton
2.00/lb


8.00/mfin-hr
1.00/mcf
0.70/M Ib
-0.60/KM Btu
O.O2/M gal
0.010/kWh



3,500
** ?3 ,600
6 JJ< , 200
I-?, 000
1,133,300
372,000
509,500
1,^96,500
(37,700)
199,100
7^1,900
1,131,700
109,900
^,522,900
0.03
1|.17
5.^7
0.10
9.77
3-21
'.59
12.90
(0.33)
1.72
6.39
9-75
0. 9^
3T.98
                                                                   5,656,200
                                                 ^8.75
          Indirect Coats
Average capital charges at 1<< . 9^-
cf total capital investment
Overhead
Plant, 20^ of conversion costs
Admin' strative and marketing
Subtotal Indirect costs
Total nnnual operating costs
Dollars/ton
product sulfur
Equivalent unit
operating cost 35'4.79
!, 5^3,200
9o1',6oo
^97^500
5,9"5,500
11,601,500
Dollnra/i,on Cents/ciill ion
coaj. burned Mills/kWh Btu heat input
8.8U 3.31 36.83
59-16
7.3o
51.25
100.00
Dollnrs/ton
sulfur removed
323.31'
  Basis:
   Remaining life of power plant, 30 yr.
   Coal tmrned,  1,312,500 tons/yr, 9,000  Btu/kWh.
   Stack gas reheat to 175F.
   Power unit on-atream  time, 7,000 hr/yr.
   Midwest plant location, 1975 operating costs.
   Total capital investment, $30,^91,000;  subtox.nl direct investment, $18,361,000.
   Worklns caoital, $1,015,500.
   Investment nd operating cost for disposal of fly ash excluded.
                                             195

-------
                    Table  21.     CATALYTIC  OXIDATION PROCESS
 TOTAL AVERAGE ACTUAL OPERATING  COSTS -  REGULATED  UTILITY  ECONOMICS
                       (SOO-MW new, coal-fired power unit, 3-5* 3 In  fuel;
                          yo* S0e  removal; LOy.VOO  tono/yr 1(M% H;,SO )
                                                                  Toted annual
             Direct, Custs
IVflivered  raw ma'
  Catalyst
     Suttotal rav ir.U-rial

Conversion  costs
  C-p<>rntin<< labor and
   sup'.'.-vis ion
  Utilities
                                   _Atimjal quantity    Unit cost,  $ _ coatj
                                        i,700 liters    1.65/liter       17JU3.
man-hr    B.OO/man-hr      63,100
                                                                                  Percent of
                                                                                 total annual
                                                                               operating cost
                                                                                    1-95
                                                                                    0-71
Steam 179,000 H Ib
Heat credit 967,000 MM Btu
Process water 312,000 M gal
Electricity 90, ^O, 000 KWh
Ma! nt enance
Labor <0 coal burnKii
Equivalent unit operating cc>st iJ0.7t> 6.1(<
0.70/M Ib 125,300
-0.60/MM Btu (592,200)
0.08/M gal 25,000
0.010/kWli 90l',1tOO

l.Ol't.TOO
'i^jOOO
1,5:53,300
1,761,100


6,367,700

317,700
ijT^oo
7, 11? 366
fl,fl73,900
Cents/million
Hills/kWh Btu h.-8t lujiut
2.5,
1.1*1
(6.67)
0.28
10.19

H.^3
0. Mi
177B9
19.9k


71.76

5-59
'i.B?
8o-16
100.00
Dollars/ton
sulfur removed
*7.*
* Basis:
    Remaining life of power plant, 50 yr.
    Coal  burned, 1,31.,(XX) tonfl/yr, 9,000 Btu/kVfti.
    :>tnck pan reheat to 17!;<>F.
    l\jwer unit on-ntreir/yr.
    Hliiwr:nt p] nnt location, J'TT.'  npcrntlnff coats.
    Totiil cnpltn] jnvefltmcnt,  JJi?,73f>,OCX); subtotal direct investment,
    Working capita], JV.'^,700.
    Jnvcstmont and operating fdst for dlapoaa]  of  fly aah excluriati.
                                             196

-------
                               Table  22.     SUMMARY - TOTAL AVERAGE ANNUAL OPERATING COSTS
                                                                                                                       a
                                                            Excluding Credit for Byproducts
          Case

Coal-fired power unit

9Ot SOa reioval; onsite solids disposal
    200 HW new, 3.5J sulfur
    20C KV existing, 3-5* sulfur
    500 KW exls'lr^, 3.51 sulfur
    500 KV aev, e.Ot sulfur
    500 MV aev, 5.5it sulfur
    500 KW nev, 5.04 sulfur
   1000 MW existing, 3-5J sulfur
   1000 KW oev, J.5J sulfur

3o% 302 reaoval; oa.lte solids disposal
    500 KW new, 3.5* sulfur

9Ot SOj ressoval; offsite solids disposal
    500 MW nev, J.5J sulfur

Set 3O2 reaoval  (existing unit
without existing particulste
collection facilities)
    50C W existing, 3-5* sulfur

          pover  unit
                                         Years
                                         life
30
20
25
30
30
30
25
30
50


30



25
Llae stone
Total annual
operating
^oat, $
3,921,500
3,367,100
7,392,600
6,77'. ,700
7,70S,?00
3,522,200
12,752,900
11,371., 100
process

Mills/
XWh
2.30
2.76
2.26
l.QA
2.20
2. ''3
1.32
1.70
Lime process
Total annual
operating
cost, $
k, 163, 900
U, 322, 000
9.612.UOO
6,915,100
3,101,900
9,170,100
15, 301,'' oo
12,553,100

Mills/
kwh
2.97

2.75
1.93
2.31
2.62
2.19
1.79
Magnesia
Total annual
operating
cost, $
li, 776,300
5,091,200
9,607,900
7,523,'' oo
9,210,300
10,763,500
15,1.31,900
l<" ,31.7 ,000
process

Mills/
iwh

3.6k
2.75
2.15
2.63
3.03
2.21
2.05
Sodlua process
Total annual
operating
cost, $
5,971,700
7,377,700
1^,653,000
9,101,700
11,601,500
13,?35,500
25,113,500
13,391.300

Kills/
kVh
k.27
5.27
k.19
2.60
3-31
"..00
3.59
2.65
Cat-Ox process
Total annual
operating
cost. $
'",232,700
5,3ii9,koo
12,599,600
3,301,200
3,373,900
3,91.0,500
2i,'.6o,3oo
13,957,600

Mill*/
kUb
5.02

J.Jk
2.51
2.51"
2.55
3.07
1.99
7,373,000


3,576,500




9,573,1.00
2.11


2.39
                           7,306,900


                           3,#U,000
2.23


2.1.7
3,739,700    2.51   10,331.,300     3-XO
                    2.71.    9,723,300     2.73   U,227,300    3.21   16,389,200     !>.68   X5,593,300     3.39
5OJ SOa retsjval; anslte solids disposal
ZjQ KW new, 2.;i sulfur
5CO ;, 269,200
5,35^,700
3,305,100
10,6*0,500
10,261,600
13,636,200
5.05
1.67
2.57
5.0k
2.93
1.96
2,750,100
5,71.3,600
5,677,500
5,565,100
11,126,100
3,911,900
1.96
1.6^
1.62
1.59
3-13
1.27
 *  ?3vr ur.lt on-streaa tloe, 7000 hr/yr.  .Midwest plant location, 1975 operating costs.   Investment and operating cost for disposal of flj  ash excluded.

-------
          The effect on annual operating costs of designing for 80$ S02
removal as compared to 90% is relatively small.   Operating cost savings
range from 3-6 to k.2% of the projected operating costs at 90% removal
for the limestone and lime slurry processes.

          The effect of excluding product credits from the annual
operating cost estimates is illustrated in Table 23 which compares the
projected annual base case operating costs for the five processes with
the revenue from sale of byproducts.

      Table 23.    COMPARISON OF PROJECTED ANNUAL OPERATING COSTS AND

  PRODUCT CREDITS FOR BASE CASE ESTIMATES AT 7000 HOURS ANMJAL OPERATION

Process
Total Net annual
average annual Annual credit operating
operating cost, $ for byproducts, $a cost, $
Limestone
Lime
Magnesia
Sodium
Cat -Ox
a
7,702,700
8,101,900
9,210,800
11,601,500
8,873,900

1
883
,077
659
,200
,500
,^00
7
8
8
10
8
>
)
,
,
,
702
101
327
52*4
2lU
Corresponds to credit of &3/ton 100$ H2S04 as 98$ H2S04
magnesia slurry process; $25/short ton sulfur, $20/ton
Na2S04 for the sodium solution process; and $6 /ton 100$
17 O/^ .  Q 
-------
                          Table  21*.    LIMESTONE  SLURRY PROCESS.  500-MW NEW COAL-FIRED  POWER UNIT,
                              3.5$ SULFUR IN  FUEL,  90% SOP REMOVAL, REGULATED  COMPANY ECONOMICS
                                                       FIXED INVESTHENT'
                                                                           25163000
VO
vO
YEARS
AFTER
POKER
UNI t
START
1
2
3
4
1
6
7
a
9
1 fl
1 1
12
j 3
14
J C
16
17
n
1 9
?n
21
22
23
24
j e
26
27
26
29
in
TOT
ANNUAL
OPERA-
T1CN,
XW-HR/
Kk
7000
7000
7COO
7COO
	 JDDQ-.
7000
7COO
7000
7000
20.0.0.
5000
5COO
5COO
5COO
5nr.n
35CO
3500
3500
35CO
35J1Q
15CO
1500
1500
1500
ISQA
1500
1500
1500
1500
-15QQ-
127500
LIFETIME


PGKER UNIT POkER UNIT
HEAT fUEL
REQUIREMENT, CONSUMPTION
MILLICN uu
/YEAR
3I5CCOCO
315CCOOO
315COOCO
3150COCO
	 315000.00. 	
315COOCO
315000CO
31500000
3150COCO
^15[j^0p3
225COOO?
225CSOCC
225CGOOO
225CCOCO
22S.CC2Cfl_ 	
1575UOCO
157500CO
1575','OGO
15750000
	 1525. rQCQ
6750000
67500CC
675000C
6750000
hIS.CQ.Ul-
6750000
6750000
67500CO
675COCO
	 6J5.GOO.O.
573750000
AVERAGE INCREASE
UOLLA8S
TONS COAL
/YEAR
131250C
1312500
1312500
1312500
1 3 L25.3Q
1312500
I31250C
1312500
1312500
1 31 2 50*3
937500
937500
937500
937500
3 J A5D*^
*56200
656200
656200
656200
65.L2 CO.
2f 1200
2312CO
261200
ie\2'lr>
2&L2.QQ.
0f.nnn
206000
206000
206000
206000
206QOQ
147100
147100
147100
147100
14 jir.n .,
I03COO
103000
103000
103COO
ininnn ,
44100
44100
44100
44100
	 	 ,.44100. , -
44100
44100
441CO
44100
- - - dtlOJ) _
3751500
NET REVENUE
/TON

WASTE
SOLIDS
0.0
0,0
0.0
0.0
n.n
0.0 .
0.0
0.0
0.0
Q.P
0.0
0.0
0. 0
0.0
Q-.0. _
0.0
0.0
0.0
0.0
Q.l)
0.0
0.0
0.0
0.0
o.n
0.0
o.c
0.0
0.0
. 	 C - fi

TOTAL
OP. COST
INCLUDING
, REGULATED
ROI FOR
POkER
COMPANY ,
l/Yf AR
10320500
10146000
9971600
9797100
. . 9622f>Qn
9448200
9273700
9099200
89247CO
B 7. 50 300
7640900
7466400
7292000
7117500
	 6J4JQCD-
6029900
5855500
5681COO
55C6500
5332100
4074300
3899800
3725400
355090C
33 7. 64QQ
3201900
3027500
2653000
267H50C
y Sfi4 | po
193110500
NET ANNUM
TOTAL INCREASE
NET (DECREASE!
SALES IN COST OF
REVENUE ,
t/YEAR
0
0
0
0
n
0
3
0
0
a
0
0
0
0
n
0
0
0
0
Q
0
0
c
0
n
0
0
0
0

0
POKER,
t
10320500
10146000
9971600
97971CO
}}tan
944(200
9273700
9099200
8924700
a I$Q 3CO
7640900
7466400
7292000
71 17500
fclilOQG
60299CO
5855500
56B1000
5506500
51121 O2
4074300
3899800
37254CO
35509CO
332fcfcQQ
32019CO
3027500
28530CO
26785CO
2S.Q41QQ
193,110,500
CUMULATIVE
NIT INCREASE
(DECREASE 1
IN CLST OF
POkER,
i
I032C500
20466500
30438100
40235200
&9. AS. 7 AOO
59306000
68579700
77678900
(6603600
9.5153.9.00
1029948CO
110461200
117753200
124870700
1 lldl 1700
137843600
143699100
149380100
154686600
1,0?H jno
1642930CO
168192800
171916200
175469100
1 7 f fl4 5.5Qft
U2047400
U5074900
1*7927900
190606400
19 1110 500

1 IN UNI T 3PEIAT1NC COST
CTAL BURNEO


MILS PER K UtkAIT-HCUli
CEM< PER MILLION


PD3CFSS COST
DULLAdS
OISUUMEO T
PER TCN !)F
BTl HEAT INPUT
SLLFUR ,E1'JVE
10- CX T!l IS) I!At Yf A* , D

0
"UAtS



t .08
3.03
33.66
295.50
78439900
0.0
0.0
0.0
0.0
0
8.08
3.03
33.66
295.50
78.439,000





                  LEVEII2EO IfiCfcfASE  IDECRCASEI IH UNIT  'JPfesTIHG CCST (CUIVAICNT  TO DISCCUNTEO SUCCESS CCSI OVER LIFE OF POKfR UN 11
                                (/CU'RI PEB '2N OF CfAL BORNE j                                  7.63      C.O        7.63
                                XULS PE K IL^kATI-MiUH                                        2.86      C.O        2.86
                                CENTS PER "1LLICN BTL HEAT  1SPUT                                31.77      0.0       31.77
                                COLLARS PER I UN OF SULFUR AMOVED                              278.85      0.0      278.85

-------
                          Table  25.     LIMESTONE  SLURRY PROCESS,  500-MW EXISTING COAL-FIRED POWER UNIT,
                                3-5# SULFUR  IN  FUEL,  90$  S02  REMOVAL,  REGULATED  COMPANY  ECONOMICS
                 YEARS ANKUAl
                 f IfB OPESA-
                 PLUfcK TICN,
                 UMT  Xw-HR/
                 START
                        K*
      UNIT
   HEAT
REQUIREMENT,
MILL I PS- UU
  /YEAR
      UNIT
    FUEL
CtlNSUMPT H'N,
 TCNS  COAL
  /Yf AR
                                                         SULflU
    8Y
 PCLLUTION
  CCNTR3L
  PSuCtSS,
TONS/YEAR
INVESTMENT I

  PY-PRGOUCT
    RATE,
  EQUIVALENT
   TCNS/YEAR
                                                                      SOL IDS
                                                                                  230i>eooD
NET  REVENUE,
    t/ION

    WASTE
    SLLIDS
  TOTAL
 Df>.  COST
INCLUDING
RECULAIEO
 CO I  FUR
  POWER
 COMPANY,
  i/YEAR
 TOTAL

 SAL! S
Rfvfiue,
$/YEAR
NET  ANNUAL
 INCREASE
IOECREASEI
III  COST CiF
 PCE,
 CUKULAT IVE
NET  INCREASE
 (DECREASE!
 IN  COST or
    POWEI,
     t
NJ
o
o
b
7
a
t.
1 'i
11
12
1 1
_ii
16
1 7
la
19
22
21
el
2 i
24

26
21
2t
2"
3D.
7CCO
icco
7COO
7COO
	 2CQO 	
5COO
50CO
5COO
5CCO
35CO
35CC
35CO
35CO
i < r Q
15GC
1SGO
15CO
1500
	 liCL 	
15CO
1*00
15CC
ISCC
1 trn
322C0003
322,C,COC1
322C3COO
322CIOCJ
32 2 GC OCa
< J3CCOCO
; joccoco
23CCCOCO
3GCOOCG
iticcoc;
uiccorc
UKCXO
161CCOOO
1 i I ' "QfiQ
bocroc;-
69CCOCC
69CC7C7
6c:occ
._-tSCiO-. 	
bircoce
t 9 C oC C C
69( ^Ot <.
69CUOC-C
bSCCQCD
1 34(700
1 34170C
134170'J
13417'. 0
A 34 1 7/rt3
9567-51!
56 3"H
95630P
956 JOO
67080C
67C8C.O
67050
(-7GCOO
< ?DP ^^'
2^7500
29 7500
2C75CO
2f ^ -3
-2i.liOJ 	
<  7500
2 t 75 OC
28 750C
!t ?5^0
2 * 7 5 f T
367QO
3b73C
3673C"
367UO
3.^2 QC
262DC
2<>2 30
26230
210600
21CbOO
210600
210bOO
^1 n API
I504CO
15C400
150400
0.0
0.0
C.O
0.0
o n
0.0
0.0
0.0
2620P 150400 O.G
18300
lf3CO
18300
18300
i\ on
7-OC
7930
7900
7930
1D5300 0.0
1053CO
105300
105)00
insip.Q

45100
45100
45100
0.0
0.0
C.O
_CUQ
0.0
0.3
0.0
0.0
10293700
lOldfcCG
99C9500
">71 7400
t**? S40 Q
82t27CO
PC7C600
78765CO
76H6400
64658CO
6273700
608I6CO
5869600
t ^ o 7 
Ll.Fu 'fJVEO
8.67
3.32
36.13
316.95
7055GCCO
TO OISCLUNTEO PROCESS COST OVER
9.C7
3.09
33.61
295.06
C.
0.
0.
G.

Lift
C.
0.
0.
0.
0
0
0
0
0
Of
0
0
0
0
8.67
J. 32
36. 1 3
316.95
7C55C-000
POWER UNIT
8.G7
3.09
33.61
295.06

-------
   Table  26.     SUMMARY  -  CUMULATIVE  DISCOUNTED PROCESS  COSTS AND  EQUIVALENT  LEVELIZED  UNIT  INCREASE
                              (DECREASE)  IN COST OF  POWER  OVER THE  LIFE OF THE POWER
                                                            Including Credit for Byproduct!
         Case

Coal-fired power unit

903 S02 resooval; onslte solids disposal
    200 KW new, 5.5$ sulfur
    200 MW existing, 5-5* sulfur
    500 K' existing, 5-5$ sulfur
    500 KW nev, 2.0* sulfur
    500 MW oev, 3.5f sulfur
    500 K new, 5.0J sulfur
   1000 KW existing, 5-5$ sulfur
   1000 Ktf new, 3.51 sulfur

Sot SOz reaoval; onslte solids disposal
    500 MW nev, 3.5* sulfur

90$ SOa reeovttli offsite solids disposed
    500 MW new, 3.5$ sulfur

90$ SOj reaoval (existing unit without
 existing pertlculate collection
 facilities)
    500 MW existing, 3.5$ sulfur

Oil-fired power unit
                                             Lisestone process
                                                                   Lime process
                                                Magnesia
                                                                                                           Sodiua process
                                                                                                                                Cut-Ox process





Years
life
30
20
25
50
30
30
25
JO
30
30
Cumulative
present
worth net
Increase
(decrease)
In cost of
power, |
I'D, H2, 800
29,067,800
70,550,000
69, J^, 200
73,1-39,900
86,ii 26,900
111, 935, 'OO
120,015,500
75,259,300
90,l<26,200
Levelized
Increase
(decrease)
In unit
operating
cost,
Blll/XVflic
3.66
^.73
J.09
2.53
2.36
3-15
2.U5
2,19
2.T1*
2.93
Cumulative
present
worth net
Increase
(decrease)
In cost of
power, b $
"1,112,500
Jfc, 979,000
814,117,600
68,709,000
79,593,300
89,293,900
130,977,300
121,789,900
76,687,900
30,903,300
Levellzed
Increase
(decrease)
In unit
operating
cost,
oma/XHh
3-75
5.69
3-69
2.50
2.90
3.25
2.37
2.22
2.80
2.95
Cumulative
present
worth net
increase
(decrease)
In cost of
b *
power, $
M ,860,500
}6,106,200
78,292,200
71,503,600
31", 21-9, 500
95,621,900
121,1.56,200
126,808,000
3l,n9,Soo
_
I/evellzed
Incrense
(decrease)
in unit
operating
cost,
niUs/kWh0
"<.09
5.37
3."'5
2.6:
3.07
>.'*<)
2.66
2. 31
2.96
_
Cucule tlve
present
worth net
Increase
(decrease )
In cost of
b *
power, t
55,0><5,000
i'3,56B,joc
11J, 965,500
95,60^,900
1C*, 2?2,}00
121,660,300
iSS^et^OO
l6o,375,?00
96,2l>5,000
_
Levellzed
Increase
(decrease )
In unit
operating
cost,
aUls/y.Wac
5.02
7.90
5.00
3.12
3.30
k.iO
"-
2.92
3-59
_
Cumulative
present
worth p.et
Increase
(decrease)
In cost of
power,1" t
ill", 323, 500
"<2, "423, 000
106, 607, 900
95,730,300
S1-, 520, 900
92,305,500
IS 1,012 ,700
1^3, U7, 600
-
^
Levellzed
Increase
(decrease)
in unit
operating
cost,
ClllS /XW
">.o3
6.90
1-.67
3.1,0
3.U
 3.53
3.77
2.70
-
.
25
57, 1^3,300    3.92     8l.,92,200     3.72
93,875,800
                                                             130,715,900
5.73    119,12'', 300
                                                                                                     5.22
90? SOj reaovai; onslte solids disposal






a




0
c
200 KW nev, 2.5* sulfur 30 28,231,000 .58
500 MW new, 1.0$ sulfur 30 ue.lO^SOO 1.69
500 KV new, 2.5J sulfur 30 5l(,7'<3,900 2.00
500 KW new, U.oJ sul^a 30 6l,3o3,l<00 2.25
500 W existing, 2-5^ sulfur 25 53,353,300 2.56
1000 KV aev, 2.5* sulfur 30 37,171,700 1.59
Basis:
Over previously defined power unit operating profile. 30 yr life;
Hldwest plant location, 1975 operating costs.
Icvestaent and operating cost for disposal of fly ash excluded.
Constant labor cost assuoed over life of project.
Discounted at 10$ to Initial year.
Equlvalri* o discounted process cost over life of pover unit.
33,612
56,505
66,727
7<<,929
70,126
103, 'U

7000 hr -





,500
,800
,200
,500
,200
,900

10 yr,





3.06
2.06
2.1.3
2.73
3.07
1.33

5000 hr





30,089,900
11 ',030,300
55,673,'' 00
65,572,300
61,393,300
85,962,i<00

- 5 yr, 3500 hr





2.7^
1.61
2.03
2.59
2.69
1.57

- 5 yr,





39, l1^, 900
55, 025, '"00
7i ,20k, 600
91,337,900
32,952,700
US, 705, 700

1500 hr - 10 yr.





3.57
2.01
2.70
3.35
3-63
2.16







29,653,300
63, 57S 000
61,591,500
59,2-9,500
?6, 505, 200
96,399,300







c.
2.
2.
2.
!..
1.







"0
52
25
16
22
77








-------
           Table 27.   LIFETIME BYPRODUCT PRODUCTION AND CREDIT

      Base Case, 500-MW New, Coal-Fired, 3.5$ S, JO Yrs Remaining Life
                                              Net
                         Equivalent         revenue,   Cumulative revenue
                     lifetime production    $/short                Dis-
	Process	   Product     Short tons    ton     Actual $   counted $

Magnesia slurry -
 regeneration      100% H2S04a   2,011,500    8.00   16,092,000  6,923,300

Sodium solution -    Sulfur        595,000   25.00
 S02 reduction       Na2S04        2J7,000   20.00   19,627,500  3,^6,300

Catalytic                    ,
 oxidation         100^ H2S04    2,002,500    6.00   12,015,000  5,163,900


 As 9% H2S04.
  As 80^ H2S04.
                                    202

-------
           o
           B
           (U
           3
           w

           G
           O
           -P
               800
               600
             Limestone Slurry Process   X

             Lime Slurry Process A

             Magnesia Slurry - Regeneration Process

             Sodium Solution - S02 Reduction Process

             Catalytic Oxidation Process D


             35# S in coal

             90% S02 removal

             127,500 hr lifetime operation
                                                                 0
                                                                                               22.0
                                                                                    16.5
                                                                                      H
                                                                                       03
                                                                                       O
                                                                                       O

                                                                                       c
                                                                                       O
                                                                                      P
                                                                                                     -ea-
N;
O
U)
P
OT
O
o


W)
G
H
-P
0)

o

-P
rH
G
^400
                                                                                    11.0
               200
                                                                                     5.5
                    -p
                    co
                    O
                    O

                    bO
                    G
                    H
                    P
                    cd
                    M
                    0)
                                                                                                     -P

                                                                                                     rl
                                                                                                     a>
           a>

           0)
                                                                                          a>
                 o
                   0
                   200
                            400         600         800

                                 Power anit size, MW
1000
                     Figure I1*.   New coal-fired units  -  the  effect of power unit size on

                              levelized unit operating  cost - regulated economics

-------
   12
H
(0
o
o

c
o
-p
-p
CO
o
CJ
a

-p


a>

&

-p
H
q
'd
a;
O)
   10
   8
         Limestone Slurry Process  X

         Lime Slurry Process A

         Magnesia Slurry-Regeneration Process   0

         Sodium Solution - S02 Reduction Process

         Catalytic Oxidation Process  Q
         90$ S02 removal

         127,500 hr lifetime operation
                                                                     3.75
                                                                          H
     -P
     OT
     o
     o

     bO
     c
     H
     -P
     cd

     QJ
3.00
                                                                     2.25
                                                                          c!
                                                                          3
                                                                          o;
                  23            14            5

                             Sulfur in coal, $>


      Figure 15.   500-14W new coal-fired units - effect of  sulfur  content
        of  coal  on  levelized unit operating cost - regulated  economics
                                    204

-------
TVA IN-HOUSE ESTIMATES

          In addition to the more detailed estimates prepared for EPA, a
series of in-house studies have also been undertaken by TVA to determine
the attractiveness of several process options.  These include limestone
scrubbing using benzoic acid as a slurry dissolution promoter; lime
scrubbing using a venturi - mobile-bed contactor rather than two venturi
stages; lime scrubbing including a limestone calcination unit; sodium
scrubbing with sulfuric acid production rather than sulfur; and two
double-alkali systemsone using ammonia scrubbing, the other sodium
scrubbing.  Because the date available for the double-alkali process
evaluations were limited, the accuracy of these estimates is less than
the others.

          Seven TVA case estimates were prepared.  When evaluating lime
scrubbing with a mobile-bed contactor, both a new and a retrofit case
(500 MW, 3-5% S in coal) were estimated to determine the merit of using
such a single-stage device for S02 removal.  For the other five process
options, only new systems were evaluated.  Except for specific process
requirements, the same criteria used to prepare the EPA estimates were
used for these evaluations.   The summarized investment and operating
cost results are given in Table 28.   Additional comparative details are
given in Tables 29-^1.
CONCLUSIONS

          Conclusions derived from the EPA-TVA detailed study results
are as follows;

Investment

   1.  For coal-fired systems, the lime scrubbing process has the lowest
       investment and catalytic oxidation has the highest.  Because lime
       process definition specjfies venturi scrubbers and two stages are
       required  for S02 removal, the limestone and magnesia processes
       become comparatively less expensive on oil-fired units; limestone
       investment is the lowest and magnesia investment is very close.
       All four  wet scrubbing processes are within 21% of each other.

   2.  As sulfur content of fuel increases, the relative investment
       ranking of the wet scrubbing processes changes; lime is still
       lowest for coal-fired units but for oil-fired units, limestone
       or magnesia investments are the lowest.  Although these invest-
       ments are very close throughout the range, magnesia investment
       is slightly lower for the low-sulfur oil, and limestone investment
       is slightly lower for the medium- and high-sulfur oils.
                                   205

-------
Table 28.    INVESTMENT AND OPERATING  COST RESULTS  FROM TVA IN-HOUSE STUDIES5
                Process
Limestone-benzole acid alurry process
    500 MW new 3.5$ sulfur

Lime slurry process ;  veaturi-mobile bed
 scrubbing scheme*5
    500 MW new 3.5$ sulfur

Lime alurry process;  mobile bed scrubbing
 scheme01
    500 MW existing,   3-5 sulfur

Lime slurry process;  venturl - venturl
 scrubbing scheme with onsite calcination
    500 MW new, 3.5$ sulfur
Sodium solution - HaSO^ production process
    500 MWjww, 3-5 sulfur

Ammonia-limestone/lime double-alkali
 process
    500 MW new 3.5$ sulfur

Sodium- limestone double -alkali process*1
    500 MW new 5.556 sulfur
Years   Capital investment
life   . ._. $ . _'     $/kW~
                                                                              Average annual
                                                                              operating costs
 30    23,^73,000     1*6.9    T,i39,000    2.13
 30    23,363,000     1*6.7    8,11*6,000    2.33
 25    20,327,000     1*0.7     8,270,600    2.36
 30    27,'52,000     5J-9    8,101.900d   2.31d
 30    30,139,000     60.3    11,05^,800    3.16
 30    31,087,000     62.2     9,669,300    2.76
 30    30,759,000     61.5     9,51*5,300    2.73
a Stack gas reheat to 175*F.  Midwest plant location represents project beginning mid-1972,
  ending mid-1975'  Average cost basis for scaling,  mid-1971*.  Operating costs based on power
  unit on-stream time of 7000 hours; costs correspond  to  1975-  Minimum in process storage;
  only pumps are spared.  Investment and operating  coat for disposal of fly ash excluded.
.  Construction labor shortages with accompanying overtime pay incentive not considered.
  Limestone raw material cost, $l/ton; lime raw material  cost, $22.00/ton.  Onsite disposal
c pond located one mile from power plant.
  Assumes 93.7% effective electrostatic precipitator already installed.
  Same as operating cost for lime slurry process in EPA study, since EPA study utilized esti-
  mated production cost to establish purchased, cost of lime.

-------
           Table  29-     LIMESTONE  -  BENZOIC ACID SLURRY  PROCESS
                                                                           a
                     SUMMARY  OF ESTIMATED  FIXED  INVESTMENT
                      (50O-MW new coal-fired power unit,  5.5$ 8  In
                          9O% SOP removal; onslte olld disposal)
8 in fuel;
                                                         Investment, $

Limestone receiving and  storage  (hoppers, feeders,
 conveyors,  elevators, and bins)                               It It 3,000
Feed preparation (feeders, crushers, elevators, ball
 mills,  benzole acid storage, conveyor, tanks, and pumps)      572,000
Partlculete  scrubbers and  inlet ducts  (!t scrubbers In-
 cluding common feed plenum, effluent  hold tanks,
 agitators,  and pumps)                                       3,203,000
Sulfur dioxide scrubbers and ducts  C4  scrubbers In-
 cluding effluent hold tanks, agitators, pumps, exhaust
 gas ducts to Inlet of fan and mist eliminators with
 closed-loop wash systems end trap-out trays)                14,170,000
Stack gas reheat (^ indirect steam reheaters)                  556,OOO
Fans (U  fans Including exhaust gas ducts and dampers
 between fan end stack gas plenum)                             85^,000
Calcium solids disposal  (onsite disposal facilities
 including feed tanX, agitator, slurry disposal pumps,
 pond, liner, and pond water return pomps)                   3,772,000
Utilities (instrument air generation e.nd supply system,
 plus distribution systems for obtaining process steam,
 water,  end  electricity  from the power plant)                  67,000
Service  facilities (buildings, shops,  stores, site
 development, roads, rallroada, and walkways)                  638,000
Construction facilities                                        7l'*,OOQ
     Subtotal direct investment                             I1*,939,OOO

Engineering  design and supervision                           1,31|9(000
Construction field expense                                   1,6^9,000
Contractor fees                                               719,000
Contingency                                                  l.^iOOO
     Subtotal fixed Investment                              20,235,000

Allowance for startup and roodlflcations                      1,619,000
Interest during construction (8J/annun> rate)                 l,6l9iOOO

     Total capital Investment                               23,^73,000
               Percent of subtotal
               direct investment
                      2.9

                      3.8

                     21.lt


                     27.8
                      5.7

                      5-7

                     25.2


                      O."t
                    10O. 0

                      9.0
                     11.0
                      5.0
                     10.0
                    135.0

                     10.8
                     10.8

                    156.6
  Basis:
    Preliminary estimate  from  recent TVA In-house evaluation.
    Stack gas reheat to 175F  by  indirect steam reheat.
    Msposal pond located 1  mile  from power plant.
    Midwest plant location represents project beginning rald-1972,  ending  mirt-1975-  Average
     cost basis for scaling, mid-1971*.
    Minimum In process  storage; only pumps are spared.
    Investment requirements  for disposal of fly ash excluded.
    Construction labor  shortages  with accompanying overtime pay Incentive not considered.
                                              207

-------
              Table 30.     LIMESTONE  -  BENZOIC  ACID  SLURRY  PROCESS
   TOTAL AVERAGE ANNUAL OPERATING COSTS  - REGULATED UTILITY  ECONOMICS
                      (500-MW new coal-fired power unit, 3-5$ 8 In fuel;
                           9O% ROP removal; onolte solids dlapunal)
            Direct Coots

Delivered  raw material
  Llncntone
  Benzole  acid
     Subtotal raw material
Annual  quantity
     l60. 1 M tons
     lilO.O tone
                                                      Unit coat,
  l).00/ton
600.00/ton
                                                                    Total annual
                                                                                   Percent of
                                                                                  total  annual
               coot,  t    operating cost
             61.0,1)00
             ?16,000
Convernlon  costs
  Operating labor and
   supcrvioion
  UtlllUen
    Steam
    Proceee water
    Electricity
  Maintenance
    Labor and material, .08 x  l'i,989,000
  Analyses
     Subtotal conversion costs

     Subtotal direct conto
   26,280 raan-hr
             886,1.00



8.00/man-hr   230,200
                               2.82
1)92, 800 M Ib
260,000 N gal
70,770 M kWh
10

0.70/H Ib
0. 08/H gal
0.010/kWh


31)5,000
20,800
707,700
1,199,100
1*5,600
2,528,1)00
3,1)11), 800
0.28
9-51
16.12
0.61
")5-90
            Indirect Coots

Average  capitnl charges at l'i.9^
 of total  capital Investment
Overhead
  Plant, 20$ of converolon coote
  AdmJnlntratlve, 10% of operating  labor
     Subtotal IndJreet conto

     Total annual operating costo
Equivalent  unit operating cost
                                 5,''97,500

                                  505,700
                                   21.000
                                 I), 021., 200

                                 7,1.39,000
                              1*7.02
                             100.00
                                         Dollare/ton            Cents/ml ULlon    Dollars/ton
                                         cooJ. burned  Hllls/KWh  Btu heat  input  sulfur removed
                                            5-67
                                 23.62
                            207-33
  Bao1o:
    Preliminary estimate from recent TVA In house evaluation.
    Remaining life of power plant,  JO yr.
    Cool burned, 1,312,500 tono/yr, 9,000 Btu/kMh.
    Stack  gao reheat to 175F.
    Power  unit onotream time, 7,000 hr/yr.
    Hldweat plant location, 1975 operating costs.
    Total  capital Inveotment, $23,1)T3,000; subtotal direct  Investment, $1'),909,000.
    Working capital, $581,700.
    Inveotment and operating cost for dlspooal of fly ash excluded.
                                             208

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                          Table  31.     LIME SLURRY PROCESS
                      VSNTURI  -  MOBILE  BED  SCRUBBING  SCHEME
                      SUMMARY  OF ESTIMATED  FIXED INVESTMENT
                      (500-MW new_ coal-fired power unit, 3.5$ 3 in fuel;
                          905^ SOj removal; onalte solida disposal)
                                                                           Percent of  subtotal
                                                         Investment, $       direct Investment
Lime receiving and  storage  (bins, feeders, con-
 veyors,  and elevators)
Feed preparation (conveyors, sinkers, tnnks, agitators,
 and pumps)
ParticulBte - sulfur  dioxide scrubbers and Inlet ducts
 (U scrubbers Including  common feed plenums, effluent
 hold tanks, agitators,  and punipa)
Sulfur dioxide scrubbers and ducts  (It scrubbers In-
 cluding  mist eliminators, effluent hold tanks,
 agitators, pumps,  and exhaust gas ducts to inlet
 of fans)
Stack gas reheat (li  Indirect steam reheaters)
Fans (li  fans Including exhaust gas ducta and
 dampers  between fan  and stack gas plenum)
Calcium solids disposal  (onsite disposal facilities
 Including slurry disposal pimps, pond, liner, and
 pond vater return  pumps)
Utilities (instrument air generation and supply
 system,  plus distribution systems for obtaining
 process  steam,  vater, and electricity from the
 power plant)
Service  facilities  (buildings, shops, stores, site
 development, roads,  railroads, and walkways)
Construction facilities
     Subtotal direct  Investment

Engineering design  and supervision
Construction field  expense '
Contractor fees
Contingency
     Subtotal fixed investment

Allowance for startup and modifications
Interest  during construction (8^/annum rate)

     Total capital  investment
   795,000

   387,000


3,203,000


It, 523,000

   695,000


 3,1.1.5,000


    67,000

   55?,ooo
   710,000
1't, 919,000

 1,3113,000
 l,61il,000
   7l"6,000
 1.'t 92,000
20,11(1,000

 i,6n,ooo
 1,611,000

23,363,000
  5.3
  2.6

 21-5
 30.3
  3.6
 23-1
  O.It

  3-7
  it. 8
100.0

  9-0
 11.0
  5-0
 10.0
135.0

 10.8
 10.8

156.6
8 Basis:
    Preliminary  estimate  from recent TVA in-house evaluation.
    Stack gas  reheat  to 175"F by Indirect steam reheat.
    Disposal pond  located 1 mile from power plant.
    Midwest plant  location represents project beginning  mid-1972, ending raid-1975.   Average
     cost basis  for scaling, mid-197't.
    Minimum in process storage; only pumps are spared.
    Investment requirements for disposal of fly ash excluded.
    Construction labor shortages with accompanying overture  pay  Incentive not considered.
                                            209

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                         Table 32.     LIME  SLURRY  PROCESS
                     VENTURI  -  MOBILE  BED SCRUBBING  SCHEME                    g
TOTAL  AVERAGE  ANMJAL OPERATING COSTS  - REGULATED UTILITY ECONOMICS
                      (500-MW new -joal-flred  pover unit, J.5? S in fuel;
                           90^ SOg reaiovnl; onolte eolido dleponal)
            Direct Cooto

Delivered row material
  Lime
     Subtotal rav material
                                   Annual quantity
                                        81.2  M tone
Conversion cootB
  Operating labor and
   supervision
  Utilities
    Steam
    Process water
    Electricity
  Maintenance
    Lnbor and material,  .08 x l'i,919,000
  Analyses
     Subtotal conversion coots

     Subtotal direct coots
    22,320 raan-hr

   1490,000 M Ib
   21(1,900 M gal
61,280,000 kWh
                                                      Unit  coot,
                     22.00/ton
                                 Total annual
                                   cost, $
            1.786,'i 00
            I,7tt6,'4 00
 8. 00/raan-hr   178, fOO

 0.70/M  Ib     3143,000
 0.08/M  gal     29,1(00
0.010/kWh      612,800

            1,193,500
               36,500
            2,38;5,8oo

            li, 170,200
                           Percent  of
                          total annual
                         operating  cost
                                                                                     2.19
                                                                                    51-19
            Indirect Cootg

Average capital charges et lU
 of total  capital Investment
Overhead
                                                                   3,l8l.lOO
Plant, J?0?t of conversion cootfl
Administrative, 10% of operating labor
Subtotal Indirect costs
Total annual operating coete
Equivalent unit operating cost
Dollars/ton
coal burned Millo/kWb
6.21 2.33
U76,800
17,900
3, 975, 00
8,1146,000
Cents/million
Btu beat Input
25- B>
5.85
0.22
THTBi
100.00
Dollnrs/ton
oulfur removed
227.0J
  Basle:
    Preliminary estimate from recent TVA in-house evaluation.
    Remaining life of power plant, 30 yr.
    Coal  burned, 1,312,500 tons/yr, 9,000 Btu/lcWh.
    Stack gas reheat to 175F.
    Power unit on-ctream time, 7,000 hr/yr.
    Midwest plant location,  1975 operating coots.
    Total capital Investment, J?3,j63,000;  subtotal direct Investment, $114,919,000.
    Working capital, $731,000.
    Investment and operating cost  for disposal of fly ash excluded.
                                             210

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                        Table 33.     LIME SLURRY  PROCESS
                           MOBILE  BED SCRUBBING SCHEME
                    SUMMARY  OF ESTIMATED  FIXED  INVESTMENT6
                    (500-KW existing coal-fired power unit, 3.5% S In fuel;
                     90^ SOg removal; onslte solids  disposal; pnrtlculates
                        removed by existing electrostatic preclpltntor)
Line receiving and  storage  (bins, feeders,  conveyors,
 and elevators)
Feed preparation  (conveyors, slaXera, tanks,
 agitators,  and pumps)
Sulfur dioxide scrubbers and ducts (^ scrubbers
 including common feed plenun, miot eliminators,
 effluent hold tanks, ngltntors, pumps,  nnd all duct-
 vork between outlet of supplemental fan and  stack gas
 plenura)
Stack gas reheat  C< direct  oil-fired reheaters )
Fans (i fans including ducts and dampers between  tie-
 in to existing duct and inlet to supplemental fan)
Calciuji solids disposal (onslte disposal facilities
 Including slurry disposal  pumps, pond,  liner, and
 pond water  return pumps)
Utilities (instrument air generation and supply
 systen, plus distribution  systems for obtaining
 process steam, water, and  electricity from the
 power plant)
Service facilities  (buildings, shops, stores, site
                                                        Investment,  $


                                                             876,000
                                                           l<, 96^,000
                                                             305,000

                                                           1,118,000


                                                           3,152,000



                                                             335, OCX)
                                                                          Percent of subtotal
                                                                           direct investment
 7.0

 5-5



39-9
 2.5

 9-0


25.1.
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct Investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed Investment
Allowance for startup and modifications
Interest during construction (8^/annura rate)
Total capital Investment
6^9,000
592,000
12, I 27, 000
l,2l3,000
1,616,000
870,000
1,367,000
17,523,000
1,1*02,000
1,1)02,000
20,327,000
5-2
C.B
10O.O
10.0
13.0
7.0
11.0
lljl.O
11-3
11. 3
163.6
8 Basis:
    Preliminary estimate from recent TVA  in-house evaluation.
    Stack  gas reheat to 175F by direct oil-fired reheat.
    Disposal plnd located 1 mile from power plant.
    Kidweat plant location represents project beginning mid-1972, ending mid-1975.   Average
     cost  basis for scaling, mid-1971).
    Hinimura in process storage; only pumps are spared.
    Investment requirements for disposal  of fly ash excluded.
    Construction labor shortages with accompanying overtime pay Incentive not considered.
                                         211

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                           Table  jU.     LIME SLURRY  PROCESS

                             MOBILE BED  SCRUBBING SCHEME
                                                                                              
 TOTAL  AVERAGE ANNUAL  OPERATING  COSTS  -  REGULATED  UTILITY  ECONOMICS
                     (500-m exiotlnK  cool-fired i>crwer unit, 3.5$ 8 In fuel;
                         90S GOP renoval; onslte solids  disposal;
                  partlculate removed  by existing electrostatic preclpltator)
                                                                    Total annual
                                                                                   Percent of
                                                                                  total annual
                                    Annual quantity     Unit cost,  $    coct, I     operating coat
             Direct Cooto

Delivered raw material
  Lime
     Subtotal rav material

Conversion coots
  Operating labor and
   supervision
  Utilities
    Fuel oil (Ho. 6)
    Proceoe water
    Electricity
  Maintenance
    labor and material, .08 x 12,1*27,000
  Analyceo
     Subtotal conversion costs

     Subtotal direct costs
  83.0 H tons     22.00/ton
           1.826,000
           1,626,000
22,320 man-hr
8. 00/man-hr   178,600
                             2,763,900
                                             ,22.08
                                             ' 22.OB
                                               2.16
1*, 236, 000 gal
21*7,300 M gal
56,056,000 kWh
,000
0. 23/gal
0.08/M gal
0.010/kWh

97l<,300
19,800
560,500
991',200
36,500
11.76
0. 2l*
6.78
12.02
                                                                                     55-50
             Indirect Costs

Average capital charges at 15-3$
 of total capital Investment
Overhead
  Plant, 20$ of conversion costs
  Administrative, 10$ of operating  labor
     Subtotal Indirect costs

     Total annual operating costs
Equivalent  unit operating cost
                             3,110,000

                               552,600
                                17.900
                             3,680,700

                             8,270,600
                            37.60

                             6.68
                           ._ p. 22
                           100.00
                                        Dollars/ton             Cents/million    Dollars/ton
                                        coal burned  Mlllo/XWh  Dtu heat Input  sulfur removed
                                           6.16
                2.36
         25-69
                       225-
  Basic:
    Preliminary estimate from recent TVA In-houae evaluation.
    Remaining life of pover plant, 25 yr.
    Coal burned, 1,31*1,700 tons/yr, 9,200 Btu/kWh.
    Stack gas reheat to 175F.
    Power unit onstream time, 7,000 hr/yr.
    Hldviest plant location, 1975 operating costs.
    Total capital Investment, ?20,327,000; subtotal direct Investment, $12,^27,000.
    Working capital, ?8OO,OOO.
    Investment and operating cost for removal and disposal of fly ash excluded.
                                                212

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        Table  35.     LIME  SLURRY  PROCESS  WITH  ONSITE  LIME  PRODUCTION
                         VENTURI  -  VENTURI  SCRUBBING  SCHEME
                       SUMMARY OF  ESTIMATED  FIXED INVESTMENT8
                      (500-MW now coal-fired power unit, 3.5^ S in fuel;
                           90% SOy removal; onaite solids disposal)
                                                        Investment,  $

 Limestone receiving and storage  (hoppers, feeders,
 conveyors, elevatore,  and  bins)                              751,000
 Limestone calcination (rotary kiln, fan, conveyors,
 elevators, dust collector,  and coal storage)               3,OUl,OOO
 Feed preparation (conveyors, slakera, tanks,  agitators,
 and pumps)                                                  387,000
 Pertlculate - sulfur dioxide scrubbers and Inlet ducts
 (I* scrubbers including common feed plenum and pumps)        ',017,000
 Sulfur dioxide scrubbers and ducts (!j scrubbers in-
 'luding mist eliminators,  puraps, and exhaust gas
 ducts to inlet of fans)                                   3,153,000
 Stack gas reheat C<  indirect steam reheaters)                 5^2,000
 Fans (14 fans including  exhaust gas ducts and  dampers
 between fen and stack  gas  plenum)                            767,000
 Calcium solids disposal (onsite disposal facilities
 Including slurry disposal  pomps, pond, liner, and
 pond water return puraps)                                   3,556,000
 Utilities (instrument air generation and supply
 system, plus distribution  systems for obtaining
 process steam, water,  and  electricity from the
 power plant)                                                 7',OOO
 Service facilities (buildings, shops, stores,  site
 development,  roads,  railroads, and walkways)                 607,000
Construction facilities                                       8}5,OOP
     Subtotal  direct  Investment                            17,530,000

Engineering design and  supervision                          1,578,000
Construction field expense                                  1,9?8,OOO
Contractor fees                                              877,000
Contingency                                                1.753,000
     Subtotal  fixed  investment                             23,6(>6,OOO

Allowance for  startup and modifications                     1,893,000
Interest during construction (Sjt/nnnum rate)                 1,893|000

     Total capital Investment                              27,!i$2,000
Percent of  subtotal
 direct investment
      17.3

       2. Z

      22.9

      18.0
       3-1
      19-1
       0.1.
       3-5
       "4.8
     100.0

       9-0
       n.o
       5.o
       10.0
     135.0
       10.8
       10.8

     156.6
  Basis:
    Preliminary estimate from recent TVA in-houae evaluation.
    Stack  pas reheat to 175F by indirect steam reheat.
    Disposal pond located 1 mile from power plant.
    Midwest plant location represents project beginning mid-1972,  ending mid-1975.   Average
     cost  basis for scaling, mid-1971'.
    Minimum in process storage; only pumps are spared.
    Investment requirements for disposal of fly ash excluded.
    Construction labor shortages with accompanying overtime pay Incentive not considered.
                                          213

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           Table  $6.     SODIUM  SOLUTION  - H^S04  PRODUCTION  PROCESS

                        SUMMARY  OF ESTIMATED FIXED  IW VESTMENT*1
                      (500-MW _Qw_ coal-fired power unit,  3.5%  3 In fuel;
                          9($ SO-, removal; 13.3 tons/hr lOOJt
                                                                           Percent of subtotal
                                                         Investment^ $       direct Investpent
Sods ash and antloxidant receiving, storage, end
 preparation (pneumatic  conveyor and blower,
 feeders, mixing tank, agitator, and punps)
Partlculate scrubbers  and Inlet ducts (I) scrubbers
 Including common feed plenum, effluont hold tanks,
 agitators, pumps,  and fly ash neutralization
 facilities)
Sulfur dioxide scrubbers and  ducts  (It scrubbers
 Including rolst eliminators,  pumps, and exhaust
 gas ducts to inlet of fan)
Stack gas reheat (i Indirect  stenm  reheetera)
Tens (** fans including exhaust gas  ducts and dampers
 between fans and stock  gas plenum)
Purge treatment (refrigeration system, chiller-
 cry stalllier, feed coolers,  centrifuge, rotary dryer,
 steam/air heater,  fan,  dust  collectors, feeders,
 tanks, agltntors,  pumps, conveyors, elevator, and
 bins)
Sulfur dioxide regeneration (evaporator-crystnllizers,
 heaters, condensers,  strippers, desuperheater, tanks,
 agitators, and pumps)
Sulfurlc acid plant  (complete contact unit for
 sulfurlc acid production)
Sulfurlc acid storage  (storage and  shipping
 facilities for 30 days  production  of h^SO*)
Utilities (instrument air generation and supply
 aysteo, and distribution systeus for obtaining
 process steam, vater, and electricity from pover
 plant)
Service facilities  (bulldlngo, shops, stores, site
  225, (XX)
3,81*6,000
"1,269,000
  5J9,ooo

  869,000
l,U73,ooo


2,622,000

2,793,000

  21*2,000



  195,000
                       1.2
20.6
22.9
 2-9
 7.9


1^.1

15.0

 1-3


 1.0
development, roods, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed Investment
Allowance for startup and modifications
Interest during construction (Sjt/annura rate)
Total capital investment
662,000
888,000
18,6*0,000
2,051,000
2,051,000
93?, 000
1.9&J.OOO
25, 5^1, 000
g.oio.ooo
30,133,000
3-5
l. 8
100.0
11.0
11.0
5.0
10.0
137.0
15.7
11.0
161.7
8 Basin:
    Preliminary estimate  from  recent TVA In-house evaluation.
    Stack gas reheat to 175F  by indirect steam reheat.
    Midwest plant  location represents project beginning  mid-1972, ending mid-1975-  Average
     cost basis for  scaling, mid-1971*.
    Minimum In process  storage; only pumps are spared.
    Fly ash slurry neutralized before disposal; closed loop  water utilization for first stage.
    Investment requirements for disposal of fly ash excluded.
    Construction labor  shortages with accompanying overtime  pay  Incentive not considered.
                                             214

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           Table  3?.      SODIUM SOLUTION -  H2S04  PRODUCTION PROCESS
   TOTAL AVERAGE  ANNUAL  OPERATING  COSTS  -  REGULATED  UTILITY  ECONOMICS'
                       (500-KW new coal-fired pover  unit, 3.5$ S In fuel;
                          90* S0? renoval;  92,890 tons/yr lOOSt H..SO.J
Annual quantity     Uiilt coat, $
                                                                     Total  annual
                                                                       coat,  $
             Direct  Cools

Delivered rav materials
  Lime (let stage neutralization)         ljh.1 tons
  Soda ar.h                               9,300 tono
  Antloxidant                          317,100 Ib
  Catalyst                               1,800 liter
     Subtotal ra Eaterlolo

Conversion coats
  Operating labor and
   supervlsion
  Utilities
    Steam                            2,137,600 M Ib
    Process water                   11,672,''00 M pal
    Electricity                     79,53'',000 kWh
  Maintenance
    Labor and material,  .06  x  !&,(>>>},OQQ
  Armlynec
     Subtotal conversion costs

     Subtotal direct costs
                    26.00/ton
                    52.00/ton
                     2.00/lb
                     1.65/11ter
  3,500
1483, foo
6.114,200
  ;, OOP
    45,8(0 inan-hr     8.00/inan-hr   366,900
                     0.70/M Ib   1,1)96,500
                     0.02/M gal    L>33,''00
                    0.010/kU-b      795,300

                                 1,118,600
                                   108,000
                                 i ,.U8,700
             Percent of
            total ftnrMJnl
            op'.Tatlty, cost
0.03
li.lT
5^7
0.10
                                                   9-77
                3.21

               12.90
                1.72
                6.39

                9-75
                                                  '48.75
             Indirect  Costs
Average capital  charges  at l!4.9^
 of total capital  Investment
Overhead
  Plant, 203^ of  conversion costs
  Administrative and marketing
     Subtotal Indirect costs
     Total  annual  operating cost
                                 (4,1490,600

                                   823,700
                                   ''97.5,00
                                 5,8.u,6oo
               39-16
                                                                                      100. CO
                             Dollars/ton  Dollnrn/ton             Cento/mi ]J.ion    Dollars/ton
                                   -.qo,,   coal burned   Mllls/KVIh  Btu heat Input   sull'ur removed
Equivalent unit  operating cost  119-01
                                              C.1'2
                     5.16
                                                                     35-09
            306. 57
  Baslo:
    Preliminary  eotitDate  from recent TVA In-house evaluation.
    Remaining  life  of  pover plant, 30 yr.
    Cool  burned,  1,312,500 tono/yr, 9,000 Btu/kWh.
    Stack gao  reheat to 175'F.
    Pover unit onstream time, 7,000 hr/yr.
    Midwest  plant location, 1975 operating coots.
    Total capital Inveotment, $30,138,000;  subtotal direct Investment, $l8,6li),000.
    Working  capital, $9)48,500.
    Investment and  operating coot for disposal of fly anh excluded.
                                               215

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     Table  38.     AMMONIA  LIMESTONE/LIME  DOUBLE  ALKALI  PROCESS
                   SUMMARY  OF ESTIMATED  FIXED  INVESTMENTa
                      (5OO-MVI now conl-fired  power unit, 3.5?i 3 In fuel;
                          90>i SOS removal; onalte solids disposal)

                                                                           Percent of subtotal
                                                        Investment. $       direct inveatment

Ammonia,  limestone,  and  lime receiving and storage
 (bins,  feeders,  conveyoro, elevators, and nmmonla
 storngn  sphere)                                              937,000              4.7
Feed prepnration  (feeders, crushers, elevators,  ball
 mills,  vaporizer,  conveyors, slaker, tnnko,  and pumps)        681,000              3.4
Participate scrubbers  nnc!  inlet ducts (^ scrubbers
 Including common feed plenum, effluent hold  tonka,
 agltntoro, and pumps)                                     3,846,000             19.4

Sulfur dioxide  scrubbers and ducts  (U scrubbers
 Including wire mesh mist  eliminators, effluent
 hold tanks,  pumpe,  and  exhaust gas ducts to  Inlet
 of fan)                                                    4,219,000             21-3
Stack gas reheat  C<  indirect steam reheaters)                 539,000              2.7
Fans (b  fans  Including exhaust gas ducts and  dampers
 between  fnns and stack  gas plenum)                           889,000              4.5
Regeneration  and  precipitates handling (thickeners,
 filters, tanks,  ogitatora, conveyors, and pumps)           3,581,000             18.0
Calcium solldo  disposal  (onsite disposal facilities
 Including slurry disposal pumps and pond)                  3,508,000             17.7
Utilities (Instrument  air  generation and supply
 system,  and  distribution  systems for obtaining
 process  steam, water, and  electricity from the
 power plant)                                                 67,000              0.}
Service facilities  (buildings, shops, stores, site
 development, roada, railroads, and valkways)                 633,000              3.2
Construction  facilities                                       9^5,000              4.8
     Subtotal direct Investment                            19,50,000             10O.O

Engineering design  nnd supervision                          1,787,000              9-0
Construction  field  expense                                  2,18^,000             11.0
Contractor fees                                               995,000              5.0
Contingency                                                1,935,000             10.0
     Subtotal fixed investment                             26,799,000             135-0

Allowance for startup  and  modifications                     2,1^,000             10.8
Interest  during construction (0%/annum rate)                 2,l1tl),000             10.3

     Total capital  investment                              31,037,000             156.6

a Bnclo:
    Preliminary estimate from recent TVA In-house evaluation.
    Stock gas reheat to  175"F by indirect steam reheat.
    Midwest plant location represents project beginning mid-1972,  ending mid-1975-  Average
     cost baols for scaling, mid-1974.
    Minimum in  process stornge; only pumps are spared.
    Syntem is designed for closed loop water  utilization.
    Investment requirements for disposal of fly  ash excluded.
    Construction  labor shortages with accompanying overtime pay incentive not considered.
                                           216

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       Table  59.    AMMONIA LIMESTONE/LIKE DOUBLE  ALKALI  PROCESS'
TOTAL AVERAGE ANNUAL OPERATING  COSTS  -  REGULATED  UTILITY  ECONOMICS
              (5OO-MW new  coid-fired power unit, J.5% S  In fuel; 90% B0a removal)
                                  Annual  quantity    Unit  cost.
           Direct Costs

Delivered  raw materials
  Limestone
  Lime
  Ammonia
     Subtotal raw materials
                                     1142.0 M  tons
                                      15O tons
                                     2,110 tons
  14.00/ton
 22.00/ton
150.00/ton
Conversion  costs
  Operating labor and
   supervision
  Utilities
    Steam
    Process water
    F-lectrlclty
  Maintenance
    Labor and material, .08  x  19,850,000
  Analyses
     Subtotal conversion coats

     Subtotal direct costs


           Indirect Costs

Averflge capital charges at lb.
 of total capital Investment
Overhead
                                    35,100  rr.nn-hr     8.00/can-hr
                                                                  Total annunl
                                                                    cost, ?
                                                                      566,000
                                                                      336,600
                                                                      271;,300
                                                                    1,173,"00
                                                                      230,800
                                                                                 Percent uf
                                                                                total annual
                                                                               operating cost
5-87
3.1.8
2.8U
                                                                                   12.19
                                 2.90
833,1400 H lb
26?, 000 M gal
63,200,000 KWh
^50,000
0.70/K lb
0.03/H gal
0.010/kWh

6l8,l400
21,000
632,000
1,583,000
51,700
3,191,900
6.140
0.22
16.142
35-01
                                                                                   145.20
                                                                    ii,632,000
Plant, 2O% of conversion costs
Administrative, 10^ of operating labor
Subtotal Indirect costs
Total annual operating costs
Equivalent unit operating cost
633,1400
23,100
5,293,500
9,669,300
Dollars/ton Cents/million
coal burned Mills/kWh Dtu hent Input
T-37 2.76 30.70
6.60
0.29
100.00
Dollars/ton
sulfur removed
p/", Q t It O
8 Basis:
    Prelloinary estimate from  recent TVA in-house evaluation.
    Remaining life of power  plant, 30 yr.
    Coal burned, 1,312,500 tons/yr, 9,000 Btu/KWh.
    Stack gas reheat to 175F.
    Power unit on-strearo time, 7,000 hr/yr.
    Mldweet plant location,  1975 operating costs.
    Total capital investment,  $31,087,OOO; subtotal direct Invest .,-
    Working capital, t71'6,100.
    Investment and operating coat for disposal  of fly ash excluded.
                                                                   i-ij, 850,000.
                                             217

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           Table  kO.     SODIUM LIMESTONE DOUBLE ALKALI PROCESS

                     SUMMARY  OF  ESTIMATED  FIXED  INVESTMENT8
                      (500-MW new coal-fired power unit,  }.5$ S  In  fuel;
                           9O% SO2 removal; onaite solids disposal)
                                                         Investment. $

Limestone, soda nsh,  and  antioxidant receiving end
 storage (bins, hoppers,  feeders,  conveyors,
 elevators, and pumps)                                         319,000
Feed prepnrntion (feeders,  weigh belts, agitators,
 crushers, ball mills,  tanks, nnd pumps)                        607,000
Partlculnte scrubbers and inlet ducts  (^ acrubbcjre
 Including common feed  plenum, effluent hold tnnks,
 agitators, nnd pumps)                                       3,8U6,000
Sulfur dioxide scrubbers  and  ducts  (l>  scrubbers
 including wire mesh  mist eliminators, effluent hold
 tanks, pumps, and exhaust gns ducts to inlet of fan)        l,36^,000
Stack gns reheat (l<  indirect  steam  rehenters)                  539,000
Fans (li fans Including  exhnuet pas  ducts and dampers
 between fans nnd stack gas plenum)                          1,170,000
Regeneration nnd precipitates handling (sulfnte
 reoctor absorber and thickener, filter, conveyor,
 Bteom coll, tnnk,  agitator,  nnd pumps)                      3,583,000
Calclura oolidn disposal (onaite disposal facilities
 including slurry disposal  pumps and ponci)                   3)551,000
Utilities (instrument air generation nnd supply
 system, nnd distribution systems for obtaining
 process otenra, water,  nnd  electricity from power plant)        72,000
Service facilities (buildings, shops, stores, site
 development,  roads,  rnllroods, and walkways)                  656,000
Construction facilities                                       9'j5,OOP
     Subtotal direct  investment                             1962,000

Engineering design and  supervision                           1,768,000
Construction field  expense                                   2,l6J,000
Contractor fees                                               982,000
Contingency                                                 l/jfli.OOO
     Subtotal fixed  Investment                              26,517,000

Allowance for startup and modifications                      2,121,000
Interest during construction  (B'J/annum rate)                 2,121,OOP

     Total capltnl  Investment                              3759,000
Percent of subtotal
 direct Investment
        1.6

        3-1

       19-6
       22.2
        2.7

        6.0
       16.2

       18.1


        O.'l
        3-3
        lj.8
      100.0

        9.0
       11.0
        5-0
       10.0
      135.0

       10.8
       10.8

      156.6
n Boels:
    Preliminary  estimate  from recent TVA in-house evaluation.
    Stack gns  reheat  to 175F by indirect steam reheat.
    Midwest  plant  location represents project beginning  mid-1972, ending mid-1975.   Average
     cost bnsis  for scaling, mid-1971".
    Minimum  in process storage; only pumps are spared.
    System is  designed for closed loop water utilization.
    Investment requirements  for disposal of fly nsh excluded.
    Construction Inbor nhortnp.es with accompanying overtime  pny  Incentive not considered.
                                           218

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              Table kl.
SOD1UI-;  LIMESTONE  DOUBLE  ALKALI  PROCESS
   TOTAL AVERAGE ANMJAL OPERATING COSTS.  - REGULATED UTILITY  ECONOMICS
               (500-MW_ncw coal-fired povcr unit,  3.5^ 3  In fuel; 905& S02 removal)
                                                                    Total  annual
                                                                                   Percent  of
                                                                                  totnl  annual
                                   Annual quan11 ty     Unit coot, $    coot, $     operating  coot
             Direct CootB

Delivered raw materials
  LImestone
  Soda eon
  Antioxldant
     Subtotal rav materials

Conversion costs
  Operating  labor and
   supervision
  Utilities
    Steam
    Process  water
    Electricity
  Maintenance
    Labor and material, .08 x 19,Wi?,OOO
  Analyses
     Subtotal conversion cofitu

     Subtotal direct coots
          177.5 M tons
          83(4.0 tons
          SliO.O M Jb
 li.OO/ton
V-00. ton
710,000

'=8oiooo
                          8.00/nuui-hr   260,800
'jOB.'iOO M Ib
260,000 M gal
82,8110,000 kWh
',OOO

0.70/M Ib
0.08/M gal
0.010/kWb


35S900
?o,too
828.1100
1,571, ''00
lifi.YOO
3,08(1,000
11,319,'tOO
3-T3
0.22
8.68
16.146
Ji?.
"5.25
             Indirect Costs
Average capital chargec at 1^.9^
 of total  capital Investment
Overhead
  Plant, 20$ of conversion costs
  Administrative, 10/6 of operating  labor
     Subtotal indirect costc

     Total annual operating cost
                                     it, 583, loo

                                       617,?00
                                        26,100
                             148.01
Equivalent unit operating cost
                                                     100.00
                                       DolJLars/ton            Conts/irJLlJon    Dollars/ton
                                       coal burned  Hlllr./kWti  Btu heat Input  Bulfqr removed
                                                       2-73
                                                                 30.30
  Basle:
    Preliminary estimate from recent TVA In-houre evaluation.
    Remaining life of power plant,  30 yr.
    Coal  burned, 1,312,500 tone/yr, 9,OOO Btu/kWh.
    Stack gaa reheat to 175f.
    Power unit on-etrcam time,  7,OOO hr/yr.
    Mldweot  plant location, 1975 operating costs.
    Total capital Investment, ?30,759,OOO; subtotal direct  investment, $19/Ji2,OOO.
    Working  capital, $739,200.
    Investment and operating cost for disposal of fly aoh excluded.
                                              219

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   3  The Cat-Ox process has the poorest investment economy of scale
       (unit size) of all five systems; however, for sulfur content of
       fuel, Cat-Ox has the best scale factor.   A reheat (existing)
       Cat-Ox system requiring full particulate removal facilities to
       .005 gr/scf was found to "be only 2.5$> higher than a new integrated
       unit.

   b.  Plant age is an important factor only in the limestone and lime
       processes where pond size depends on remaining plant life; older
       units can best use limestone or lime processes.

   5.  Removal of only Qo% of the S02 (which would meet Federal new
       source emission standards for 35^ S) instead of 90^> decreases
       investment by only 3 to 5%.
Operating Cost

   1.   For both 35$> S coal-fired and 2.5% S oil-fired power units under
       the premises used, limestone has the lowest annual operating cost
       and sodium the highest.   Even after credits for recovery products
       are applied, the lifetime operating costs are higher for the re-
       generable systems than for the throwaway systems.   Cat-Ox becomes
       competitive with limestone on new oil-fired units, especially
       for smaller units.

   2.   As sulfur content of fuel increases, the relative  operating cost
       for all five systems changes.  Cat-Ox lifetime operating costs
       go from highest at low sulfur levels to third on coal-fired units
       and first on oil-fired units with high-sulfur fuel levels.   These
       are some of the most interesting results of the study.   The heat
       credit for Cat-Ox becomes significant at high sulfur levels.

   3.   The lime and sodium processes rank high in raw material cost and
       magnesia and Cat-Ox are low.  Limestone has the largest range in
       cost of all the raw materials.

   ^.   Sodium scrubbing has the highest total labor cost  and Cat-Ox the
       lowest; however, labor is one of the smallest components (1-3/ of
       total) for all five processes.

   5-   Energy costs are significant for all systems; applications of
       sodium scrubbing on existing units require the greatest amount
       of energy (35$ f total operating cost).  If a double-effect
       evaporator-crystallizer is utilized in the sodium  system, overall
       energy costs could be reduced as much as 18$.  The magnesia
       process is also energy intensive; the Cat-Ox system uses the
       lowest amount (5/)

   6.   Although expense for antioxidant (sodium system) is high, it is
       justified to keep sulfate formation down and save  Na2C03 makeup.


                                   220

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   7.  Maintenance is quite significant ranging from 7$ of total operating
       cost for a Cat-Ox case to 17$ for a limestone case.

   8.  Capital charges are the largest individual component of operating
       cost for all five processes.  For new Cat-Ox systems capital costs
       are 12% of total.  For the other processes, capital charges are
       in the range of 39 to 50$>.  A change in depreciation rate or cost
       of money will obviously affect Cat-Ox the most.

   9.  Only about k to 5$ of total operating cost is saved when 80$ S02
       removal is provided instead of 90$.

  10.  A Cat-Ox process on an existing plant has a ^0$ greater operating
       cost than on a new system.  This is caused by the high energy
       required for stack gas reheat from 310 to 890F prior to conversion
       of S02 to S03.

  11.  As would be expected, the scrubbing steps of each process are the
       highest cost operations.

  12.  For the energy intensive processes (magnesia, sodium), oil-fired
       systems are at a disadvantage because of the high cost of fuel oil
       relative to coal ($1.53/MM Btu compared to $0.5**/MM Btu).

  13-  Sale of byproducts at the values assumed in the study would reduce
       the base case lifetime operating cost 7-2$ for the magnesia, 7-15
       for the sodium, and **.9$ for the Cat-Ox process.

  l*i.  Because of product revenues, the relative ranking of the magnesia
       scrubbing process on oil-fired units improves under lifetime
       operating costs until it is the lowest cost system above 800-MW
       size.

  15-  Labor cost escalation (7.5$ per year) over the project life would
       add about 7-10$ to total project cost.

  16.  Regardless of which process is utilized, the increase in the cost
       of power to consumers for the base case is projected to range from
       2.86 to 3.80 mills/kWh.   For all case variations, projected costs
       could range from 1.57 to 7-90 mills/kWh.

          Although there are differences in the depth and quality of the
EPA-sponsored evaluations and the TVA in-house estimates, some additional
conclusions can be derived from comparing all the base case results as
shown in Table ^2.

   1.  For limestone scrubbing, process savings from the addition of
       benzoic acid to reduce limestone stoichiometry  (and therefore raw
       material and solids disposal costs) are relatively small.
                                  221

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              Table  1*2.    COMPARISON  OF RESULTS  OF EPA-SPONSORED  EVALUATIONS  AMD TVA IN-HOUSE ESTIMATES
                      NEW  500-MW,  3.5# SULFUR COAL-FIRED UNITS, JO YEARS LIFE  (EXCEPTIONS NOTED)
                                                                                        Results
NJ
to
                             Process
Limestone
  Limestone slurry process
  Limestone-benzole acid slurry process

Lime
  Lime slurry process  (venturi-venturi scheme)
  Lime slurry process  (venturi-mobile bed scheme)
  Lime slurry process  (venturi-venturi scheme}*
  Lime slurry process  (mobile bed scheme)8
  Lime slurry process  with onsite lime production
   (venturi-venturi scheme)

Magnesia
  Magnesia slurry - regeneration process

Sodium
  Sodium solution - S0 reduction process
  Sodium solution - H2S04 production process

Cat-Ox
  Catalytic oxidation  process

Double alkali
  Ammonia-limestone/lime double-alkali process
  Sodium-limestone double-alkali process
                                                     EPA-sponsored evaluations          TVA In-house estimates
                                                     Capital      Average annual       Capital      Average annual
                                                   investment^ $  operating cost,  $   investment,$  operatingcost,  $
                                                            25,1^3,000
                                                            26,1*06,000
                                                            1*2,756,000
7,702,700
                                                                                             25,1*75,000
9,210,800
                                                            50,1*91,000       11,601,500
8,875,900
                                                                                             50,158,000
                                                                                             51,087,000
                                                                                             50,759,000
                                 7,!59,000
22,U22,000
_
26,027,000*
_
-
3,101,900
-
9,6l2,l*00a

-
_
25,565,000

20,327,000*
27,1*52,000
_
3, 1U6.000
_
8,270,600*
8,101,900
                                11,05^,800
                                 9,669,500
                                 9,5'*5,300
         8 Existing 500-MW,  5.5$  sulfur coal-fired unit,  25  years remaining life.

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2.  Costs for a two-stage venturi lime system and a venturi - mobile
    bed lime system on a new coal-fired unit are reasonably close;
    however, for an existing coal-fired power plant or oil-fired unit
    not requiring additional particulate removal facilities, the
    mobile bed scrubber option requires about 22% less capital and
        less operating cost.
3.  Production of sulfuric acid is slightly less expensive than
    production of sulfur when sodium scrubbing - regeneration is
    used.  Depending on prevailing market value of byproduct acid
    and sulfur, the expected revenues could determine which option
    is best (2.8 times as much acid as sulfur).

k .  Based on the "state of the art" at this time, the costs of the
    two double-alkali options are about the same, but at least 20-25/c
    more costly than lime or limestone scrubbing.
                                223

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             EPA/RTP PILOT STUDIES RELATED TO UNSATURATED

              OPERATION OF LIME AND LIMESTONE SCRUBBERS
                                  bv
                         Robert  H.  Borgwardt
                     Control  Systems  Laboratory
                 U.S.  Environmental Protection Agency
                National Environmental Research Center
                Research Triangle Park,  North  Carolina
ABSTRACT

     An oddity  of  lime  and  limestone  $2  scrubbers  is  the observation
that they can run  unsaturated with  respect  to  dissolved CaSO/-2H90
during closed loop  operation.  This fact  offers a unique opportunity,
if  the phenomenon  responsible can be  understood and controlled,  to
effectively reduce  scaling  potential  which  has persisted as one  of the
principal reliability problems of those systems.  In addition to eliminating
the potential for  scaling of absorber internals, unsaturated operation could
greatly increase the amount of clarified  liquor available for mist eliminator
washing.  Experimental  studies of the process  conditions necessary
to achieve unsaturated  scrubbing liquor are reported, and a mechanism
is proposed that accounts for it.  It is  shown that the sulfate  formed
by oxidation is purged, without crystallization, as a "solid solution"
within the precipitated CaSO,,.  The amount  of  sulfate that can be thus
incorporated is related to  tne sulfate activity in the scrubbing liquor
and the S02 precipitation rate in the hold  tank.  The effect of Cl~ on
suppressing sulfate activity and the  effect of Kg"*"1" on raising sulfate
activity are evaluated  and  correlated with  oxidation and saturation.
The observed superiority of lime vs.  limestone with respect to ease of
development of unsaturated  conditions  is  attributed to the higher
precipitation rates and low oxidation that  arc character!stic of lime systems,
                                225

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             EPA/RTP PILOT STUDIES RELATED TO  UNSATURATED
              OPERATION OF LIME AND LIMESTONE  SCRUBBERS
SATURATED  VS.  UNSATURATED MODES

      Calcium sulfate  is  generated in the scrubbing liquor when dissolved
S02 is oxidized  either  in the scrubbing  tower, where  the liquor is
exposed  to flue  gas containing about 5%  oxygen,  or in the ancillary
process  vessels,  where  it is exposed to  the air.   Unlike calcium sulfite,
the sulfate is not  precipitated from solution by the  rise in pH that
occurs in  the  hold  tank  and, consequently,  accumulates  in the scrubbing
liquor until it  is  supersaturated with CaSO^-2H20,  Calcium sulfate
crystallizes at  a slow  rate and its  accumulation in the liquor of a
closed-loop scrubbing system ceases  only when a  level of supersaturation
is reached that  yields a crystallization rate equal to  the total oxi-
dation rate in all  parts of the system - a  necessary  condition for steady
state operation.  Present methods for reducing the steady state super-
saturation thus  follow the crystallization  approach by 1) maximizing the
rate  of  crystallization  with high concentrations of seed crystals, and
2) providing maximum  residence time  for  the slurry in the hold tank
(crystallizer) before returning it to the scrubber.   Together, these
factors  can reduce  the level of supersaturation  of the scrubber feed
liquor sufficiently to prevent scale growth.   These principles were
successfully demonstrated by I.C.I,  at 1000 ppm  S02 scrubber feed
concentration, and  present practice  is based  largely  on their experience.

      The possibility  of  achieving saturation  levels close to, or even
below the  equilibrium solubility of  CaSO/'ZtUO in a lime scrubber liquor
was first  indicated by J. Martin of  Combustion Engineering, Inc. in
discussing the Louisville G&E operations at the  3rd EPA Symposium in
May 1973.   Since  subsaturated liquor is  contradictory to the accepted
crystallization  mechanism for sulfate purge,  the reported unsaturated
operation  was  initially  regarded as  evidence  of  either open loop
conditions or  total lack of oxidation.  It  is interesting to note that
the I.C.I,  scrubber data reported in 1935,  in which tests of super-
saturation were  conducted on a regular basis,  showed  several periods
of negative supersaturation.  No comment was  made on  the anomaly although
it sometimes persisted  for several days. Inspection  of the I.C.I.
reports  reveals  that  these values were generally associated with
periods  of low oxidation; 12-20%. It is a'lso significant that a
relatively short  hold-tank residence time was  used  in that system.

      In  addition  to the  I.C.I,  and L.G.5 E.  scrubbers, Mitsui appears to
be another full-size  unit that  has achieved unsaturoted conditions.  The
absence  of chloride in the scrubbing liquor of each of these systems is
ail important  factor they all have in common that,  as  will be shown, has
no doubt contributed  to  their success.   The use  of  lime feed in the latter
two cases  is another  factor.
                                  226

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     The capability of operating a limestone scrubber at steady-state
unsaturated conditions, in which loop closure could be proven by
material balance, was demonstrated in the EPA/RTP model in May 1973.
These tests involved a plug flow hold tank in which no air contacted
the circulating slurry, and oxidation .values were only about 10%.
Since no chloride was present, unsaturated liquor was clearly
evidenced by calcium concentrations of only 100-200 ppm, less than
1/3 the saturated concentration.  Material balances confirmed loop
closure at 62% solids and showed no unaccounted-for liquor loss.
Since that time, extensive experimentation has been carried out at
RTF with both limestone and lime scrubbers to define the process
conditions required to maintain operation in the unsaturated mode.
This report summarizes that work.

     The most important potential advantage of the unsaturated mode of
Operation is that it would allow virtually unlimited washing of the mist
eliminators - the critical component in the overall reliability of most
systems at present - with liquor that would not contribute to chemical
scaling of the mist eliminator surfaces.
MECHANISM OF SULFATE PURGE IN THE UNSATURATED MODE

     Proof of unsaturated operation in a closed loop scrubber requires
a mechanism of sulfate precipitation from the liquid phase that does
not involve crystallization.  Given the fact that the liquor is unsat-
urated, it follows that crystallization of calcium sulfate will not
occur and cannot account for the presence of sulfate in the solid.  It
is nevertheless observed that significant amounts of sulfate are present
in the solids when a scrubber is running unsaturated.  Furthermore, the
incorporation of sulfate within the solid is a necessary condition for
steady-state unsaturated operation since the sulfate generated by
oxidation cannot be purged in sufficient amounts any other way.  For
example, it can be shown that the maximum amount of dissolved sulfate
lost in the liquid purge from a closed loop scrubber (with filter cake
moisture) is equivalent to only about 0.2% oxidation when the chloride
level is 5000 ppm.

     A mechanism whereby sulfate can be incorporated by calcium sulfite
without crystallization was proposed by I-C.I. in 1951 to account  for the
unusual properties of the solid product from their Bankside scrubber.
Examination of those solids, which chemical analysis showed to contain
about 10% calcium sulfate, revealed no gypsum or anhydrite detectable
by x-ray diffraction.  It was postulated from this result and from
measurements of the degree of hydration of the calcium sulfate that
it was present as a homogeneous "solid solution" within the calcium
sulfite.  Laboratory experiments conducted at simulated scrubber
conditions confirmed that sulfate was brought down with the precipitating
      in amounts equivalent to a maximum ratio of 0.23 mole sulfate per mole
                                  227
    o
sulfite.

-------
      Tests similar to the above were carried out on solids obtained
 from the EPA/RTP scrubber during unsaturated operation.  These solids,
 which contained 10-15 mole percent sulfate by chemical analysis,  showed
 no  calcium sulfate when examined by x-ray diffraction in several  dif-
 ferent laboratories.   Stirring the solids with distilled water would
 not extract the calcium sulfate, confirming that it was not present as
 a separate phase.   Dissolution of the solid with HC1, followed by water
 extraction and recrystallization, yields pure gypsum in amounts expected
 from the chemical  analysis of  the  original solid.   The  characteristics
 of  the solid  conform  in all respects to those reported  by  I.C.I,  for solid
 solutions  and it was  concluded that the formation  of this  product
 constitutes the mechanism by which sulfate is purged from  scrubbers
 during unsaturated operation.   The I.C.I,  terminology has  been adopted
 here when  referring to  this compound although recent evidence  suggests
 that it  is  not a true solid solution in the thermodynamic  sense.

 OXIDATION  AND SATURATION

      When  a scrubber  is running unsaturated and  the sulfate  is  being
 purged entirely in the  form of solid solution, a material  balance
 shows  that  the rate of  solid solution formation  must equal the  overall
 rate of  oxidation.  If  this condition were not satisfied,  the  excess
 sulfate  would accumulate in the closed loop system and  the liquor
 would,  in  time,  become  saturated regardless of solid solution  formation:

           Input =  Output + Accumulation (or depletion)         (1)

 For  steady-state unsaturated operation,  accumulation =  0 and since
 sulfate  cannot leave  the system by any means other than solid  solution,
 equation  (1)  reduces  to:
                          oxidation
                                              1                 (2)
where ratio is moles sulfate precipitated as  solid  solution per mole
of precipitated sulfite.

     The relationship expressed by  equation  (2)  is  a  necessary condition
for unsaturated operation at any  level  of subsaturation.   If conditions
are such that equation  (2)  cannot be  satisfied,  CaSO,  accumulation will
occur and  the system must become  saturated.   Inspection of the equation
shows that this will happen if oxidation ex.ceeds  the  value corresponding
to the maximum limit of  the value of  ratio.

     Figure 1 is a plot  of  scrubber feed saturations  observed in the
EPA pilot  plant over the full range of  steady state oxidation values.
These data represent chloride-free  operation  with limestone feed,
consequently the calcium concentration  is a direct  index  of saturation,
with Ca =  630 ppm corresponding to  saturated  liquor.   The data show a
continuous increase in saturation from  about  l/6x at  10%  oxidation to
Ix at about 20% oxidation which,  according to the discussion above, is
equivalent to the maximum mole ratio  under the test conditions.  The
maximum mole ratio at 20% oxidation is  thus,  according to equation (2),
in agreement with the value determined  by I.C.I,  from lab data.

                                    228

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ecc
                                                                         1 -
                                                             T-
4CC-
                   / 
2 / ' SCL.C SC-LTICN
- ^ / .  SATo,AT,ON(,.U.
3  / ' ^^
? ,
-------
100000-
  ice

30
i i i i i i i ' 1 |
i:co
TOTAL DISSOLVED WAC,
1 1 1 1 1 I .1 1
coco
' p
ooc
   Figure  2.   Solubility  of  CaSOll-2H20 In Solutions Containing
              Chloride  and Magnesium.   Laboratory Measurements
              at  25" C.
                                 230

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 MAXIMUM MOLE RATIO OF SULFATE TO SULFITE IN SOLID SOLUTION

      When sulfite precipitates from a liquor containing dissolved
 sulfate,  it  is  reasonable to expect that the amount of sulfate incor-
 porated as solid  solution is dependent upon the concentration of sulfate
 in  the  liquor.  As shown by the solubility data of Figure 2,  the
 equilibrium  concentration of sulfate in solution can vary over two
 orders  of magnitude,  in lime/limestone scrubbers,  depending upon the
 steady  state concentrations of Mg"^1" and Cl~.  At a given chloride level,
 the magnesium concentration in a closed loop scrubber increases  with
 the amount of soluble magnesium fed, accumulating  primarily as MgSO/
 and to  a  lesser extent,  as CaSO,  and S0, = .

      Experiments  using limestone feed, to which varying  amounts  of Mg
 were  added (as MgO) to build up the concentration  of total dissolved
 sulfates,  confirmed that solid-solution mole ratios  exceeding 0.23
 could be  achieved by  operation at  high Mg"*"*" levels.   Similarly,  it was
 shown that either MgS04  or MgO addition to a lime  scrubber, which was
 initially operating saturated,  would force the system into the unsaturated
 mode.   From  these results  it was concluded that the  mole ratio of sulfate
 to  sulfite in the solid  is a function of the sulfate concentration in the
 liquor  from  which it  precipitates.

      The  presence of  chloride in scrubber liquors  is unavoidable in
 closed-loop  systems operating on coal-fired  power  plants that burn
 coal  containing chloride.   This chloride enters the  scrubber  with the
 flue  gas  as  HC1,  usually in concentrations less than 100 ppm.  It
 accumulates  in the scrubber liquor because,  unlike SC>2 and SO,,  it
 forms no  insoluble calcium compounds and can therefore leave  the system
 only  with the liquid  purge,  i.e.  filter cake moisture  or clarifier
 underflow.   Since the liquid purge from closed loop  scrubbers is small,
 high  steady  state levels of chloride must  be reached in  order for its
 purge rate to equal the  rate of chloride absorption  in the  tower.   At
 Shawnee-,  Cl~ is the most abundant  dissolved  specie in  the  scrubbing
 liquor.

     Many runs have now  been made  in the unsaturated mode with both
lime and limestone scrubbers, at varying levels of chloride, magnesium
and oxidation.  In Figure  3  the mole ratios'  of sulfate/sulfite in  the
solids are plotted against  the sulfate  ion activities calculated from
the average  scrubber  feed  liquor analyses  for  those runs.  It is  apparent
from Figure  3 that the value of ratio  increases in an approximately linear
manner with  sulfate activity.  This  correlation is significant in  two
respects:  1) an  increase  in ratio  as  any  function of sulfate activity is
sufficient condition  to  qualitatively  explain  the  formation of unsaturated
solutions  (given this  relationship,  the  existence  of an  unsaturated mode is
a predictable consequence);  and 2)  a quantitative  relationship between these
                                   231

-------
two variables will enable one to calculate the degree of subsaturation that
will result from any given levels of chloride, magnesium and oxidation.
This is accomplished through simultaneous solution of this relationship
with six other equations that define ionic strength, ion balance, sulfate
activity and saturation.  Using a simple power function to represent
Figure 3, these relationships are:
     Ion balance:
      Ionic strength:
     SO^,  act.  coeff.
          activity:
      Solid  Soln.
      formation:

      Saturation:
Ca =
v = 0
In c
su4
In SO
Sat.
*UL96
rso
5[24
-2
-- -t-
^- + 
,02
71
Ca
10
r
1+0.7 r
-2.227 -
64 24J
Me SO? . I
. _i_  .lii  	 * -+- -
6 16 3.
u
In
2.041
a
= ac- ~2'3
2
a
c
fS04
L96
}
0
rCa
[40


SO^]
95+ln ratio
.906
! 1
J 3.32x10
-5
(3)

(4)

(5)

(6)

(7)


(8)

[93
     For any given values of oxidation, Cl, Mg and S02 in  the scrubbing
liquor, the values of the other 8 variables can be determined from
equations  (2)  -  (9)  :  Ca, S04, u, C, a, S0^= activity, ratio, and
saturation.

     Solution of  these equations for a limestone scrubber  is shown in
Figure 4, where the Mg levels required for 0.8x saturation of the
scrubber feed are plotted against oxidation at several levels of chloride.

PRECIPITATION RATE

     In addition  to the values of oxidation and sulfate activity
another constraint must also be satisfied for a system to  operate in
the unsaturated mode.  The data shown in Figures 1 and 3 were all.
obtained at residence times of about 6 minutes, inlet S02  concentrations
of 3000 ppra, and  scrubber gas velocities of 9 ft/sec or more.  It is
observed that, when all other variables remain constant, an increase in
hold tank residence time to 12 minutes will cause a limestone scrubber
to operate supersaturated even though the oxidation, magnesium, and
chloride levels are maintained at values that yield unsaturated liquor
at the shorter residence time.  It is evident that solid solution formation
is not simply a function of the liquor composition, but kinetic factors
are also involved.  Table 1 compares steady state data from duplicate
limestone/MgO scrubber runs at different hold tank residence times.  The
scrubber ran supersaturated for 4 weeks at 12 rain, residence time, where-
                                   232

-------
    i.C-
UJ

<  O.I
                                                  LIMESTONE   
                                                    LIVE      A
   .Cl	
    .CO'
                                   I   I  I  I  I
                                           .01
                                   -cnviry ,   Z. ''OTVL so..;
                                                                        .06
  Figure 3.  Molfi Ratio of  Sulfate to Sulfltft  In  Pilot  Plant
             Solids, as a Function of the Sulfate  Ion Activity
             In the Scrubbing  Liquor.  SflturatIon<0.9x
                                  233

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 liOCC


 ICOOC



  900C



  ecoc-



" 7COC
 40CCr
  200or-
  iCCCr
                   10
                                               3C
5.   >
                           OXIDATlCS'
                                   ,  i. < r: f n I
    Figure  U .   Macneslun Rnqu I ro-n^n t for.O.Kx  Scrubber Feed
                Saturation,  as  a  Function of  Oxidation.  Values
                Calculated by Equations 2-9.
                                234

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Table 1,   EFFECT OF  S0?  PRFCI PI TAT I ON RATF ON CaSO. '2H-0 SATURATION
                     IN  LIMF.STONE/MeO SCRUBBER
   Inlet SO^  3000 pnn,  Flue  p;as  0-    U.6*;,  S02 absorption  95,
Hoi d tank
Hoi d tank
Scrubber
S02 feed
residence tine, mln.
vol. (slurry), liter
gas velocity, m./sec.
rate, Kr,./hr.
Precipitation rate, ng . S02/ml n . ( 1
Fl yash
Total sol
MgO feed,
Average F






Total oxl

Ids, ?,
r,./Kg. 1 Inestone
eed Linuor Conposl'nn
SO^ E./ 1 1 tnr
sr..
Cn
Me
Cl
PH
da t 1 on, !j
Apr.vaj
22-26
6
1.73
2.8
2.6
i t e r ) 6U
no
7
67
19.2
3.0
0.2U
7.8
6.2
5.5
2G
Saturation(b) n.i*3x
Saturation c
0 .Ux .
Sept .
3-6
12
1090
2.1*
2.3
26
no
10
62
38.8
1.9
0.614
10.6
2.05
6.2
20
1.27x
1.3x
Auf, .
12-16
12
1090
2.1*
2.3
21*
yes
8
62
1*0. 1
6.8
0.69
12.0
3.2
6.0
28
l.lGx
1.2x
Sent.
23-27
5.3
i*8U
2.1*
2.3
61*
yes
15
73
35.2
6.0
0.27
ll.i*
2.9
5.6
12
0. U5x
0.5x
Sept.
16-20
5.3
US'*
2.U
2.3
6U
no
10
73
36.1*
7.4
0.2S
11.1*
3.5
6.0
11*
O.U3x
O.i*'x
      (a) open hold  tank  for  Apr.  22-2G run,  all  other runs
          made with  sealed  tank.

      (b) calculated  at  50  C.  with Rccht e 1 -nod i f I ed Radian
          eou i 1 i b r i u-i cr,~in.iter pror-.ra-..
      (c) by solid CaSn^ -2H20  solubility  test  at  25"c.


                             235

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 as  reduction  of  residence  time  to  5.3  min.  resulted  in saturation levels
 of  0.4x.   This  level  of  subsaturation  was  maintained with and without
 flyash  addition.   The choice  of 5.3 rain, residence  time was  made  to
 provide the same  precipitation  rate that existed  during the  period of
 testing represented by the  data of Figures  1  and  3.   The precipitation
 rate  is defined  as:

      n    .  .    .          Amount of SO? precipitated in hold tank
      Precipitation rate  = T1 , .	:	7^~	^	j	r	;	:	r-r-
           r               Unit  time (unit volume  of  slurry in hold tank)

 where the  amount  of S02  precipitated in the hold  tank is determined by
 the scrubber  gas  throughput,  S,C>2 inlet concentration,  SC>2 scrubbing
 efficiency and oxidation.   The  value of the precipitation rate for the
 RTF scrubbers during  unsaturated operation  was 0.064  grams 50^/min.(liter)

 LIME  VS. LIMESTONE

      The effect of precipitation rate  is probably the most important
 factor  influencing the difference in CaSO^-Zh^O saturation levels
 between lime and  limestone  scrubbers.   The  SC^ precipitation  rate  is
 ultimately limited in the latter case by the comparatively slow
 dissolution rate  of limestone.  Lime scrubbers designed  to take
 advantage of its  rapid dissolution rate can operate  in  the unsaturated
mode  with hold-tank residence times at least as short as  1 minute.  The
high  precipitation rates that ensue from these short  residence times can
explain the following advantages of lime over limestone  scrubbers  that
have  emerged from long-term concurrent TCA  tests at  the  RTF  facility:

      1)   Operating at 5000  ppm Cl~ and without MgO addition,
         the limestone scrubber averaged 1.2 - 1.3x  saturation
         at 10 min. residence time, while the lime scrubber
         averaged l.Ox saturation at 2 min. residence time.

      2)   At 5000  ppm  Cl~, the amount of MgO addition required
         to achieve a given level of subsaturation in the
         lime scrubber was  about 1/10  that  required  for  the
         limestone scrubber.  The Mg"^" and  dissolved sulfite
         levels are correspondingly lower in the lime system  -
         an important consideration if subsaturated  liquor is
         to be used for washing mist eliminators where  oxidation
         will result  in a rise  in the  local saturation  level.

      Another important advantage is the lower oxidation  that  is
characteristic of the lime  system,  which is only 4%  in  our TCA scrubber
at L/G  50 in the  absence of Cl~.  The  lowest oxidation we have achieved
 in  the  limestone  scrubber is about 10%.  With Cl  present  these minima
are about 12% in  both cases.  As would be expected,   the  chloride  level
at which a lime scrubber can operate without becoming supersaturated is
much  higher than  that for a limestone   scrubber, when no MgO  is fed.  In
summary, the unsaturated mode is easier to  achieve and maintain in a
 lime  scrubber than in a limestone scrubber  for any given  set  of operating
 conditions.


                                 236

-------
 FACTORS AFFECTING OXIDATION

      Low  pH  increases  oxidation.   Our experience supports  this  conclusion
 for  both  lime  and limestone  systems.   The pH is, in  turn,  affected  by
 chloride.  In  systems  operating without chloride,  where  the  scrubber
 effluent  pH's  are similar  (5.6-5,7), the lime scrubber  yields lower
 oxidation  than the  limestone scrubber.   This follows from  the higher pH
 and  correspondingly lower  concentration of dissolved sulfite through-
 out  the lime system.

     Addition  of chloride  lowered  pH  throughout  the limestone scrubber.
 In the lime scrubber, where  feed pH is  controlled  at a set value, chloride
 caused a greater drop in pH  to occur  across  the  tower resulting in  a
 scrubber effluent pH lower (4.8-5.0)  than  the limestone scrubber
 (5.4-5.5).  This drop in pH  no doubt  results from  the common  ion effect
 of Ca++ on the solubility  of CaSO-,, the dissolution of which  is
 responsible for the SO^ scrubbing  action in  lirae systems operating  in
 the  tail-end-addition mode.   As  a  result, lime  scrubbers operating with  chloride
 must use higher L/G's to maintain  a given scrubbing  efficiency and  exhibit
 higher oxidation than lime scrubbers  operating without chloride.  For
 example, a scrubber with 4%  oxidation at L/G 50  without chloride showed
 12%  oxidation  at L/G 77 with  5000  ppm Cl.

     Oxidation in the hold tank has been shown to  contribute significantly
 to overall oxidation in the  RTF scrubbers.  Consequently, the hold  tanks
were sealed for all experiments related to unsaturated operation.   When
no MgO is fed  to the scrubber, oxidation  occurring in the filter/clarifier
loop is of no  consequence, because the  rate of SO-> circulation through
 that loop in the liquid phase is insignificant compared to the total S09
absorption (and purge) rate.   Thus, even if  totally oxidized, the S02
circulating through the filter would not affect  the overall oxidation
values.  When MgO is added to either a  lime or limestone system, the
equilibrium concentration of  dissolved  sulfite is  increased  (primarily
as MgSO^0) and oxidation in  the filter/clarifier can no longer be
ignored.  For  example, operating at 10  g.  Mg/liter and S'u solids, the total
dissolved S02 was 1.8 g./liter in  the hold tank.   After passing through the
 filter loop this SOo was over 90%  oxidized before  reentering  the hold
 tank.  This amounted to 11%  of the total S02 absorption rate in the
scrubber and 30% of the total oxidation in the system.   Raising the
percent solids proportionately lowers the  rate of circulation of slurry
 through the filter/clarifier  loop and operation  at 15% solids is
recommended to limit this source of oxidation.   This can be further
reduced by filtering only settled sludge.

     Oxygen in the flue gas averaged about 4.5%  in this work, representing
a coal-fired power plant at normal excess  air.   Increasing the oxygen content
of the flue gas raised the oxidation raLe  in the scrubber towor  and,
although the limestone scrubber lias been operated unsaturated with up
 to 6% oxygen,  it appears that unacceptable levels of oxidation may be
encountered at higher levels, especially in liwestone/MgO systems.

     Flyasli had no demonstrable effect  on oxidation in either the lime
or limestone scrubber.

                                  237

-------
 L.G.S E. SIMULATION

      In accordance with the rationale outlined above, the principal
 features of the Louisville Gas  Electric carbide-lime scrubber were
 simulated at RTF with the 3-stage TCA af 11.5 ft./sec. gas velocity,
 3000 ppm inlet S02 and no Cl".  Using ordinary pebble lime feed, which
 was slaked in filtrate liquor, the system ran unsaturated at 0.3x with
 only 100-200 ppm Mg in the scrubbing liquor (no MgO was added).  As
 long as chloride was not present in the scrubber, this saturation level
 could be maintained indefinitely.  It was concluded that carbide lime
 was not necessary to achieve the low oxidation characteristic of this
 mode, which in our case was only 4% at L/G 50.  A sealed hold tank with
 2~min.  residence time was used in which the pH was controlled at 7.5.
 Additional tests with this tank in series with a larger, 20-min. open
 hold tank showed that complete precipitation of the sulfite (to 60 ppm)
 was achieved in the smaller tank; the large tank served no purpose as
 far as  liquor saturation was concerned.

      Addition of chloride to this system sharply dropped the scrubber
 effluent -pH and the S0? scrubbing efficiency could be maintained only by
 raising L/G to 77.  The scrubber efriuent pH was not influenced by
 increasing the feed pH at this make-per-pass (560 mg.  SC>2/liter).   The
 oxidation increased and the system became saturated.  Unsaturated  operation
 at  a 5000 ppm level of chloride was again achieved by adding
 MgO to  the lime feed to provide 1000-2000 ppm Mg*+ in the scrubbing liquor.

 SUPPLEMENTARY  EFFECTS  OF MgO ADDITION

      Improvement  in S09 scrubbing efficiency as  a result  of  the
 accumulation of MgS040"and MgS03  in  the scrubbing liquor, and/or  the
 dissolution of MgO  in  the  tower,  is a generally  recognized fact  that
 is  confirmed by our experience with both lime  and limestone  scrubbers.
 For  example, operating  the limestone scrubber  as  a multigrid tower
 (4  grids,  65%  open  area) gave  95%  S02 removal with only  3.5 in.  water AP
 at  L/G  85, and 90%  removal at L/G  65.  The option of eliminating
 another  reliability problem - TCA  sphere deterioration -  is  thus
 indicatc-d.  These levels of efficiency required MgO  feed  rates of 1.7
 lb/100  Ib  limestone.  TCA scrubbers operating  at  normal pressure drops
 can  achieve 98% removal under these conditions.

      The high  equilibrium concentration of -sulfite  in liquor containing
 large amounts  of MgSO^0, makes possible both rapid  liquid-phase oxidation
 and  rapid  dissolution of solid CaSOo.  Using a pressure oxidizer designed
by M.W. Kellogg Co., we were able  to increase oxidation from 28% in the
 scrubber slurry to  99% in the product sludge stream.  As a result of this
oxidation, the settling rate was  increased from 0.07 to 0.8 cm/rain and
 the  final  settled volume reduced  from 340 to 190  ml per  liter of original  slurry.
The  final  settled density was 54% and the volume  of dry solid product
was  reduced by 40%.  It is our expectation that an unsaturated  limestone/MgO
 scrubber can be operated with such an oxidizer to achieve fully oxidized
product without affecting subsaturation in the scrubber loop.
                                   238

-------
     Magnesium must be added  as MgO  either  as  calcined  dolomite or
half-calcined dolomite (to limestone  scrubbers).   It has been shown  that
the MgCOo normally present in limestones  is  not soluble at  the pH levels
at which these scrubbers operate.  This magnesium  enters and leaves  the
scrubber as the mineral dolomite,'MgCOyCaCO^, without participating in
the scrubbing reactions.  In our  case, feeding limestone containing  5%
MgCO-} yields about 500 ppm Mg in  the  scrubber  liquor - about 10% of  the
level that would be obtained by complete  dissolution of the dolomitic
component.  The maximum CaCO-^ utilization obtainable from limestones of
high Mg content is necessarily reduced because an  equal amount of CaCO^
is tied up in this insoluble mineral  form.

CONCLUSIONS

     Uiisaturated operation is technically feasible in either lime or
     limestone scrubbers.   This  feasibility has apparently been
     demonstrated on full  scale  systems at Louisville G.5 E. and Mitsui.

     For any given set of operating conditions, subsaturated liquor
     is easier to achieve  in lime than in limestone scrubbers.

     The presence of chloride makes it more difficult to operate in
     the unsaturated mode.

     Addition  of magnesium makes  it  easier to operate  unsaturated.
     The magnesium concentration  can  be increased  by adding  MgO.

     High  SC>2  scrubbing efficiencies  can  be  achieved at  low  pressure
     drop  when magnesium concentrations of 10 g./liter or  more  are
     maintained  in  the scrubbing  liquor.

   >  Minimizing  oxidation  assists  in  maintaining unsaturated
     conditions.

   *  Short  hold  tank  residence times  (1-2  min.)  can be used  in lime
     scrubbers operating in  the unsaturated  mode.
 ACKNOWLEDGEMENTS

      The RTF pilot plant from which these data were obtained is operated
 for EPA by Monsanto Research Corp.   The contributions of this excellent
 group,  and of Mr.  Robert Opferkuch in particular, are gratefully acknowl-
 eged.   Helpful advice and comments  on this paper were received from
 Dr. Michael Epstein Of Bechtel Corp. and from Prank Princiotta and
 John Williams of EPA.  The computer program used for liquor saturation
 calculations was kindly provided by Charles Leivo of Bcchtel.
                                    239

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NOMENCLATURE

L/G

x

o
ratio
CaS04
Ca

MgS04

Mg
             liquid to gas ratio in tower, gal./lOOO cfm @ 125F

             times saturation

             activity coefficient of Ca   and S04~ in solution

             apparent ionic strength, assuming complete ionization
             of dissolved CaS04  and MgS04

             empirically derived factor for expressing activities
             in terms of total dissolved concentrations
             moles sulfate per mole sulfite in scrubber solids

oxidation    total moles S02 oxidized per mole S02 absorbed

             ion complex formed by Ca++ and S04 = in solution

             total dissolved calcium in scrubber liquor, g./liter

             ion complex formed by Mg"1"1" and S04~ in solution
sum of the concentrations of Mg
MgSOj0 excluded.   g. /liter
                                             +
                                               and
                                   240

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                    LIMESTONE AND LIME TEST RESULTS AT THE
                      EPA ALKALI SCRUBBING TEST FACILITY
                       AT THE TVA SHAWNEE POWER PLANT
                                          by
              M. Epstein, L. Sybert, S. C. Wang, C. C. Leivo and R. G. Rhudy

                              BECHTEL CORPORATION
                                   50 Bealc Street
                            San Francisco, California 94119


                                    ABSTRACT

The  limestone and lime reliability  testing at the Shawncc  facility has shown that scrubber
internals can  be  kept relatively  free of scale if the sulfatc (gypsum) saturation of the scrub-
ber slurry is kept below about 1 35 percent.  This can be accomplished with the proper selec-
tion  of percent solids recirculateci,  effluent residence time  and liquid to gas ratio. The only
significant  reliability problem  at the Shawnce facility has  been  associated  with  the scaling
and/or plugging  of the mist eliminator systems. The TCA utilizes a Koch Flexitray with  un-
derside steam sparging, in scries with a chevron mist  eliminator  which has provision for  un-
derside washing.  In a test run which is currently in progress, this mist elimination  system  has
remained essentially clean over  a 790 hour  period,  at a superficial TCA gas velocity  of  8.6
ft/sec and  14 percent solids  recirculateci.   The mist eliminator undcrwash  utili/es diluted
clarified  liquor (at a  ratio of three  parts raw water makeup to two parts clarified liquor) at
0.3 gpm/ft^ and the  Koch tray  is irrigated with the  remaining clarified liquor plus mist elim-
inator wash at 0.5 gpm/ft .  The spray tower  utilizes a chevron mist eliminator  with provi-
sion  for underside and topside  washing.  Opcrability  of this mist elimination system during
tests of up to three months has been demonstrated, at a superficial gas velocity of 6.7 ft/sec
and  8 percent solids recirculated, with  intermittent or continuous bottomsidc washing.  A
recent test with  intermittent  topside and bottomside washing has indicated that  opcrability
of this mist elimination system can be extended substantially beyond three months.
Presented at the
SYMPOSIUM ON FLUE GAS DESULFU RIZATION
Atlanta, Georgia
November 4-7, 1974
                                     241

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                    TABLE OF CONTENTS


Section                                                  Page

   1    INTRODUCTION                                   243

   2    LIMESTONE/ LIME RELIABILITY                  252
       TESTING CONCEPTS
       2. I   Scrubber Internals Scaling Potential          252

       2.2   Mist Eliminator Scaling Potential             255

       2. 3   Closed Liquor Loop Operation                256

       2. 4   Determination of Sulfate (Gypsum)            257
             Saturation

   3    LIMESTONE RELIABILITY TEST RESULTS        259

       3. 1   Performance  Data and Test  Evaluation        259

       3. 2   Conclusions                                  278

   4    LIME RELIABILITY TEST RESULTS               281

       4. 1   Performance  Data and Test  Evaluation        281

       4. 2   Conclusions                                  298

   5    PARTICULATE REMOVAL TEST  RESULTS        301

   6    REFERENCES                                     305
                              242

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                             Section 1





                          INTRODUCTION








In June 1968, the Environmental Protection Agency (EPA), through



its Office of Research and Development (OR&D) and  Control Systems



Laboratory, initiated a program to test a  prototype lime and limestone



wet-scrubbing system for removing sulfur dioxide and particulates



from flue gases.  The system is integrated  into the flue gas ductwork



of a  coal-fired boiler at the Tennessee Valley Authority (TVA) Shawnee



Power Station,  Paducah,  Kentucky.   Bechtel Corporation of San Francisco



is the major contractor and test director, and TVA is the  constructor



and facility operator.








The  major goals of the test  program are:  (1) to  characterize as  com-



pletely as possible the  effect of important process variables on sulfur



dioxide and particulate removal; (2) to develop mathematical models (o



allow economic scale-up of attractive operating configurations to full-



size scrubber facilities; and,  (3) to  perform long-term reliability testing.








The  test facility consists  of three parallel scrubber  systems: (1) a ven-



turi  followed by a spray tower;  (2) a Turbulent Contact  Absorber (TCA):



and, (3}  a Marble-Bed  Absorber.  Each system is capable  of treating



approximately 10 Mw equivalent (30,000 acfm @ 300  F) of flue gas con-



taining 1800-4000 ppm  sulfur dioxide and 2 to 5  grains/scf  of particulates.



The  test facility has  been described in detail in  References  1,  2 and 3.
                                 243

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The  following sequential test blocks were defined for the program:








     (1)  Air/water  testing



     (2)  Sodium carhonate testing



     (3)  Limestone wet-scrubbing  testing



     (4)  Lime wet-sc rubbing  testing








The  limestone and lime wet-sc rubbing test blocks have been divided



into  three genera] categories: (1) short-term (less  than  1 day) factorial



tests,  (2) longer term (over 2 weeks)  reliability verification tests, and



(3) long-term (4 to  6 months)  reliability tests.  The object  of the fac-



torial tests is to determine the effect  of independent variables (e.g.,



gas  rale) on SO-, removal for  the scrubber systems.  The primary



objective of the reliability verification tests is  to define regions for



reliable  (e.g.,  scale-free} operation of the scrubber systems.   The



object  of the reliability tests is to determine the long-term operating



reliability for the scrubber systems and  to develop definitive process



economics data and scale-up factors.   The test program has been



described in detail  in References 1, 2 and 3.








This report presents  the results  of the limestone and lime  reliability



tests at  the Shawnee facility from October 1973 through  October 1974.



Results  from the air/water,  sodium carbonate, limestone factorial and



limestone reliability verification testing  have been  presented in Ref-



erences  1,  2 and 3.
                                244

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The lime reliability tests  have been conducted on the venturi/spray tower
system and the limestone  reliability tests on the TCA system. '  Figures
1 and Z (drawn roughly to  scale) show the venturi/spray tower and TCA
scrubber systems along with the mist eliminator  systems selected for
de-entraining slurry droplets in the gas stream.  The spray tower
utilizes a chevron mist eliminator with provision for underside and top-
side washing.  The TCA employs a Koch Flexitray with underside steam

 sparging,  in series with a chevron mist eliminator which has provision
for underside washing.    Sections of the chevron mist  eliminators used
in the two  scrubber systems  are depicted, to scale,  in Figure 3.  The
system configurations used for the venturi/spray  lower  lime reliability
tests and the TCA limestone  reliability tests are  shown in Figures 4
and 5,  respectively.


In June 1974,  the EPA  initiated a two-year Advanced Test Program at
the Shawnee facility.  The advanced program will involve, primarily,
limestone  testing on  the TCA  system and lime testing on the venturi/
spray tower system.  The major goals of the advanced program are:
         To continue long-term testing with emphasis  on the demon-
         stration of reliable mist elimination operation.
  Testing on the Marble-Bed system has been discontinued since July  1973
  due to problems with  erosion of the bed spray nozzles and subsequent
  pluggage  of the marble bed.

  Underside mist eliminator washing was provided in July 1974 (sor
  Section 3. 1. 8).
                                245

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                                  GAS OUT
             CHEVRON MIST
              ELIMINATOR
       SPRAY TOWER
INLET SLURRY
          THROAT
  ADJUSTABLE PLUG
 VENTURI SCRUBBER
      WASH LIQUOR

      WASH LIQUOR
INLET SLURRY
                                                     I	1
                                                     APPROX. SCALE
                               EFFLUENT SLURRY
    Figure  1.  Schematic of Venturi Scrubber and Spray Tower
                              246

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                            GAS OUT
         MIST ELIMINATOR

          WASH LIQUOR
                                         CHEVRON MIST

                                          ELIMINATOR
                                         KOCH TRAY
INLET KOCH TRAY

 WASH LIQUOR
                       EFFLUENT  KOCH

                     TRAY WASH  LIQUOR
              STEAM SPARGE
      RETAINING GRIDS
            GAS IN
                          \
                             00 o0
                             00   O
                               _ -Q.Q-
 0 o o o

    Q_Q_o_


  o  ._ o
 O    O  Cf
   00  o
 O   O
& o_
                                          INLET SLURRY
                                         MOBILE PACKING SPHERES
                                                    51
                                                I	1

                                               APPROX. SCALE
                         EFFLUENT SLURRY
      Figure 2.  Schematic of Three-Bed TCA Scrubber
                             247

-------
SPRAY  TOWER
                   TCA
     t
GAS  FLOW
GAS FLOW
                                  6 in.
      Figure 3.  Mist Eliminator Sections
                 248

-------
                                                                                                                SEIRINC POND
O  Gas Composition
  Particulale Composition & Loadinq
  Slurry or Solids Comoosidon
_ -_  Gas Stream
  Liquor Stream
      Figure 4.   Typical Process Flow  Diagram for  Vo>nt:uri 'Spray Tower  System

-------
to
l_n
O
                                                                              1.0. FAN

UBBER



1 Tank

---fr
>}}>>
w \j w

-T.-s-r'-rx.
A A A
_ r. 	 1

AV.W.V
i '  ^
1 * * *1u* J 1












])




^




1
J
                                                                  X.  WATtK
                                                                  Bleed
               O   Gas Composition
S                   Particulate Composition & Loading
                   Slurry or Solids Composition
_ _  Gas Stream
_  Liquor Stream
                                                                                                                      RESIURRY
                                                                                                                        TANK
                                                                                                                                   I	
                                                                                                                                             SIACK
                                                                                                                                    SniLING POND
                                     Figure 5.   Typical Process Flow Diagram  for  TCA  System

-------
         To investigate advanced process and  equipment design varia-
         tions (p.p., operation with process slurry unsaturaled with
         respect to  gypsum) for the  improvement of system reliability
         and process economics.

     e    To perform long-term  (Z to 5 months) reliability testing  on
         advanced process and equipment design variations.

         To evaluate process variations for substantial increase in
         limestone utilization  with corresponding minimization of
         sludge production.

         To determine  the practical upper limits  of sulfur dioxide
         removal efficiency.

         To determine  the effectiveness of  existing technology for
         producing an improved throwaway sludge product.

         To evaluate system performance and  reliability without fly
         ash in  the flue gas.

         To evaluate the  effectiveness of three commercially  offered
         sludge fixation processes and untreated sludge disposal.

         To develop a computer program, in conjunction with T VA, for
         the  design  and cost comparison of full-scale limestone and
         lime systems.
The Advanced Test Program is described in detail in Reference 4.
This manual, although not prepared for widespread distribution, is

available upon  request from Bechtel Corporation.
                                  251

-------
                              Section 2

      LIMESTONE/LIME RELIABILITY TESTING CCXCEPTS


As mentioned previously, the major objective of the limestone/lime

reliability tests  at the Sha\vnee facility is to determine long-term

(4 to  (> months) operating reliability for the scrubber systems.  Major

reliability problems for limest one/lime wet - s c rubbing systems have

been  associated  with  scaling and plugging   of scrubber internals and
mist  eliminator  sxirfaces (a majority of mechanical problems  can be

solved by improved design).


2. 1   SCRUBBER INTERNALS SCALING POTENTIAL


The Shawnee limestone reliability verification tests have shown that

the scrubber internals can be kept  relatively free  of calcium sulfate

(gypsum) scale at high percent  solids  recirculated and/or at high

effluent  residence limes (see References 1  and 2).  The results have

also  shown that  scrubber scaling potential can be correlated with the

calculated degree of sulfate  saturation of the scrubber slurry,  i. e. ,

sulfate  scaling is likely  to occxir for a degree of sulfate saturation
  In this  report "scale" refers only to crystalling hard solids,  and
  "solids"  or  "soft-solids " refer to mud-like  slurry  solids.  "Plug-
  ging" refers to the accumulation  of mud-like slurry solids.  Also,
  scale refers to sulfate base scale, unless otherwise noted.
                                   252

-------
of the scrubber inlet liquor greater than 130 to 140 percent. '   In Fig-

ure 6, the calculated  sulfate saturations of the scrubber inlet liquor

for the TCA limestone reliability verification tests are shown as a
function  of percent solids recirculated and effluent residence time.
Figure 6 would indicate that,  in order to remain below 130 percent

saturated in a limestone system  at 1 5 weight percent  solids recirculated

and at a  liquid-to-gas ratio of from 64 to 80 gal/mcf,  the effluent resi-
dence time would have to be equal to or greater than 10 minutes.


Results from the lime reliability tests at the Shawnee  facility (to be

discussed in Section 4) have shown that the calculated  sulfate  saturations
of the scrubber inlet liquor can be similarly correlated with percent

solids recircxilated and effluent residence  time.  In addition,  the lime
testing has shown tha' the sulfate saturations are strong functions of
flue gas  inlet SO-, concentration  (SO?  absorption rate).
                 LJ


Results  from the EPA pilot facility  at Research Triangle Park
(Reference 6)  have shown that it  is possible to operate limestone and
lime wet-sc rubbing systems with liquors "unsaturated" with respect

to calcium  sulfate,  thereby completely  eliminating the potential for
gypsum  scaling.  This is accomplished by  controlling, within given limits,
the total oxidation of  sulfite to sulfate and  the amount of dissolved  sulfate.
   The Radian Corporation (Reference  5) has determined that the "critical"
   sulfate saturation at 46C is approximately 130 percent.  The calculated
   sulfate saturations (at 50C) in this  report were made with the use of
   the Radian Equilibrium Computer Program (see Section 2.4).

   TCA limestone reliability Run  526-2A (see Section 3) has been included
   in Figure 6.
                                  253

-------
210
200 -
110 --
100 
 90 --
 80
          I  I  I   I
                             I   T   1   I  I
                                         PERCENT SOLIDS RECIRCULATED = 8
                              PERCENT SOI LDS
                              RECIRCULATED = 15
 LIQUID TO GAS RATIO = 64-80 gal/mcf

 PERCENT SOLIDS DISCHARGED = 38


H	1	I	1	1	1	1	1	1	1	1	1	1	1	1	1I-
                                10             15
                          EFFLUENT RESIDENCE TIME, min.
                                                         510-2A
                                                             L 509-2A
                                                               502-2A
                                                               501-2A
                                                     20
25
Figure 6.   Calculated Degree of Scrubber Inlet Liqxior Sulfate
            Saturation from TCA Reliability Verification Tests
                                254

-------
Under these limits, the sulfate formed by oxidation is purged,  without



crystallization, as a "solid solution" within the precipitated CaSC^.



The amount of sulfate which can-be purged in this manner is  related to



the sulfate activity in the scrubbing liquor, which can be increased by



addition of magnesium ion (see Reference 6).  In order to keep the



required magnesium addition as low as possible it is desirable to reduce



overall oxidation.  Oxidation may be  reduced by (1) sealing the effluent



hold tank (with a CC>2 or N2  insulating blanket,  if necessary), (2) adding



oxidation inhibitors,  and (3) reducing liquor rate.  The required mag-



nesium addition for unsaturated operation appears to be higher for lime-



stone systems than for lime systems and also increases as the concen-



tration of chlorides in the process liquor increases.  The high  concen-



tration of chlorides in the Shawnee facility process liquors (see Tables 2



and 4 in Sections 3 and 4) are due to chlorides present in the coal which



are converted to HC1 and absorbed from the flue gas in the scrubber.







Operation in the unsaturated mode may also lead to improved process



economics, as operating conditions conservatively selected for  scale



control under supersaturated liquor  conditions can potentially be changed,



e.g.,  effluent residence time and percent solids recirculated may be



reduced.  Moreover,  the unsaturated process liquor may be used



effectively for the irrigation of mist eliminators and wash trays.







2.2   MIST ELIMINATOR SCALING POTENTIAL







It is theorized that mist eliminator scaling  is caused, predominently,



by SO absorption into process liquor adhering  to the mist eliminator



surfaces.  Calcium sulfate scale formation is subsequently caused  by



oxidation of the dissolved SO and the resultant  super saturation of the



liquor -with respect to calcium sulfate.  In addition, solids adhering to
                                255

-------
the mist eliminator surfaces can cause pluggage and may also act as



sites  for additional scale formation.  These problems may be alleviated,



therefore,  by: (1)  reducing the  sulfate saturation  of the mist eliminator



wash  liquor (e. g. ,  utilizing raw water  or  "subsaturated" process liquor);



(2) washing the mist eliminator  at a sufficient rate to remove all impacted



solids;  (3)  utilizing a wash tray  to reduce  the suspended solids concentra-



tion of the  droplets impinging upon the  mist eliminator; (4) reducing the



SC>2 concentration  in the vicinity of the mist eliminator; and, (5) using



mist  eliminators with improved draining characteristics (e. g. ,  sloped



mist  eliminators).   All of these concepts will be tested at the Shawnee



facility.







2. 3   CLOSED LIQUOR LOOP OPERATION







Results at  the Shawnee facility have shown that scaling potential



(reliability) is significantly affected by the quantity of raw water input



to the system, i. e., the greater  the raw water input, the lower the scal-



ing potential.  In order to obtain significant reliability  data, therefore,



the scrubber  systems must be operated in a "closed liquor loop" mode.



Closed  liquor loop operation is  defined as operation wherein the raw



water input to the  system is equal to the water  normally exiting  the



system in  the settled sludge and in the  humidified  flue gas.  Settled



sludge densities  in lime/limestone wet-scrubbing  systems  are normally



equal to or greater than 38 percent by weight of solids.  Closed  liquor



loop operation, of  course,  is also desirable from  a water pollution



standpoint.







The original test facility design included slurry pumps with water seals



(Hydroseals)  for bearing protection,  water quench sprays for gas  cooling
                                 256

-------
and dilute limestone slurry feed (10 - 20 wt% limestone).  The water input



under these conditions exceeded the makeup reqviirement for closed liquor



loop operation.   The systems operated, therefore, with partially open



liquor loops during the limestone factorial tests, i. e. , sludge with less



than 40  wt% solids had to be  discharged from the systems.   This was



not considered to be a serious problem during factorial testing for,  at



a specified scrubber inlet slurry pH,  SC^ removal is not significantly



affected by liquor composition.  However,  little information was gained



about the effect of scaling potential on reliability during this period.








The absorbent feed systems  were changed in November 1972,  to provide



slurry feeds with up to 60 wt% limestone concentration.  During the five



week boiler outage in February and March  1973, the Hydroseal slurry



pumps were converted to a Centriseal type (mechanical seal supplemented



with air purge) and the TCA  and Marble-Bed scrubbers were provided



with process  slurry gas  cooling system.  As a result of these modifications,



closed liquor  loop operation  has been maintained at the facility since the



beginning of limestone reliability verification testing in March 1973.








2.4   DETERMINATION OF SULFATE (GYPSUM) SATURATION








Three methods have been used at the  Shawnee facility to determine the



degree  of sulfate  (gypsum) saturation of the process  liquors.  These



will be  discussed below.








The most accurate  of the three methods is  a quantitative  determination



of the degree  of sulfate saturation by  the use of the Radian Equilibrium



Computer Program (Reference 7) and the laboratory  measured complete
                                257

-------
liquor composition of a process liquor sample.  The Radian Equilibrium



Computer Program calculates the activities  of calcium and sulfate ions,



based on the measured liquor composition and pH.  Hence,  the degree



of saturation is equal to the product of calcium and  sulfate activities



divided by the  solubility product of gypsum at the  specified temperature.



The  calculated sulfate saturations at SOC in this  report  were based



upon  a solubility product for CaSO.^- ZHgO  of 2. 2 x 10~5 gmole^ /liter  .








The  second method is  an approximate quantitative determination,  which



is less accurate but sufficiently rapid that it may  be used in the field



more easily to follow the scrubber performance.  The test compares



the concentrations of dissolved  calcium and sulfate  in the liquor sample



with concentrations at saturation.  The saturation concentrations are



determined after the liquor sample is agitated with  gypsum powder  for



a minimum of  two hours.  The degree  of saturation is  then calculated



as the ratio of the product  of calcium and sulfate  concentrations before



gypsum treatment to the product after  treatment.   This method assumes



that  the activity  coefficients of calcium and sulfate  remain unchanged



after the gypsum treatment.








The  third method is qualitative  in nature, and does  not involve any lab-



oratory analyses or calculations. Stainless  steel plates  or strips are



immersed in the process liquor in critical locations such as the effluent



hold tank  and Koch tray effluent surge  tank, etc. ,  to monitor the scal-



ing potential of the scrubber system.   These scale probes are examined



periodically for  scale  formation.  The scale growth rates can also be



quantitatively determined by periodically weighing the  probes.  This



method should  be useful in a full scale facility,  requiring a minimum



of cost and  operator attention.
                                 258

-------
                              Section 3





            LIMESTONE RELIABILITY TEST RESULTS








Performance and analytical data from the TCA system limestone re-



liability testing at the Shawnee facility are presented in this section,



along with an evaluation of each reliability test and the conclusions



drawn,  to date,  from the testing.








3. 1   PERFORMANCE DATA AND TEST EVALUATION








A  summary of the test conditions  and  results for each of the TCA



limestone reliability tests  is presented  in Table 1, along with the



run philosophies.  A summary of  the scrubber inlet liquor analytical



data for a majority of the tests is presented in Table 2, along with the



calculated percent sulfate saturations.  Essential operating data for all



of the TCA limestone reliability tests are graphically presented in



Reference 1.   The operating data  for the initial 480 hours of Run 535-2A,



which is currently in progress,  is graphically presented in Figure 7.



An evaluation and discussion of each test is presented below.








3.1.1    TCA Run 525-2A








On October 24, 1973, the initial limestone long-term reliability test



(Run 525-2A) was begun on the TCA system.  The objective of the test
                                 259

-------
                           Table 1
SUMMARY OF LIMESTONE RELIABILITY TESTS ON TCA SYSTEM
Pun No. !
SIAI-'- of- pyn D'r
;nd-o<-Run D.' ;
Ort S.'Cn,
I.oopCl^.urr. -. Solid. Di.chg.

Tot*l Diol\rd Solid*, ppfri |


.\P Bnf{r. in, HjO
O*mt*<*r 4. P RnRe. ta. H2O
>b.orbfru






StJirl-of-ftun


Method of Control

Run Phtlotophy






Sii-4A [ , f2.,-2>
10/24/7) ; ] 1/>1 /7S
U ' IS^7* I IMQ/74
M7 , Ht>o
?:.. 000 . 20. =-00
10. <- : S. t (
i;oo ' izoo '
 0 7.1
M-lf H- U. '
10 10
i . -> - 1 . i : 1.2-1.*
71 f ^
1 !itn-40f)Q 1 ! 00-4100
rj.tm  7^. ST
t.. i..-.. i . >.  ^- =.. "
 . 2-1-. S ' "i. 1 ...*
1=.- >0 ' l^-l-
ClUrifirr : CUrtft^r
11 -42 ! i^-47
MO MO
7o no. i., no I 7.oo.t)7Cio
^. ^-- . < 4. S-4. ?

2. J-2. 7 110/24-1 1 M2) 1 1. 0-2. \
2.7- , 1 (llMi-H'1^1 |
' 0. IS-0. Z<-
Lim<-,tn- ,!llrr.rd to '.> w-i *. L.rrtr.Ionr 3)UJ-rirrf 1 '-0 f '.
to Fnrr. to Cf(T.

pirKt"""a "


TPR hlf-pr.rr. plugRed Bottom of drmiittr 1 ^r.
to be prii" rv p robl*rn).
Hot torn of drmiater ''S*',
plURRfd.
^27-2A
1/18/74
1/24/74
IM
20. ^00
S.r,
1200
.... 7> ...
1 <>- li j
_. - .-.1 	 i
l.^-l.O
!.t '
2-00- JSOO |
r 0
7700-8000
4. '.-4.0

2. 1  J- 1
0. JO- 1. 00

ro EJIV.

>*rlo
1200
7)
14-It.
:\2
1.1.1. 41
7?
'000-4000
7o. <>;>
., 7. t,, Qt.
'=..2-^.',
10- !l>
CUrlfler
;i- ^3
no
4200-t>300
+. Q-i. J

2.0-2.2
0. It.-O. 20

to EHT.






crubbrr (oop. Dccrf*rd

fl*l2r
Inlrl pll* S^1-
Stoich. H*tio & 1. t.s




1o-
-------
                      Table 1 (continued)
SUMMARY OF LIMESTONE RELIABILITY TESTS ON TCA SYSTEM
Run No.
Start . of- Run Rite
End-of-Run nce
On Sireni Huuri


Liquor Rite, upni
L/C. R.l/mcf

Affluent ftendence Tfmr. min.
SlQKhiomctnc lUtio. mUi C*
roolei SO^ bi. /molr Ca *dd-d
Inlet SO^ Concentr*., on. ppm

Scrubbor Inlci pH R*nge

Prrcrni Sulfur O*;d*rd
Solid* Duposal System
LoopClo.ur... -, Sol.d, D.,chK.
Scrubber Inlrl l.tquor 6 =,0C

Demiilrr *nd Koch Tray. In. H2C
AP R*nc, in. H;O
Demi.t*r A P RnKc. in. H;O




Slrt-of- Run


Method of Control

Results



--
>

, 	 ___ J"
20. ,00
...



u
I. U- I. U
80
""

(, ;.(, ,j
- "..i.,.r- - ^
[H. 10
""" 1
10-47
no

4.1.* 1
1. 9.J. 1
0. IT-0. 2X
to EHT.
*ble cUi-ified J,,r>r l-l 4 Kp..


N" """"


Overrides;
Inlrl pHsV 9-i
Stoich. Raiioi |. ,.<,

liquor-
lolidi And flight scale buildup

dcmistcr 1 9r; plun^H.
^ JO-iA
Wed'74
4/17/74
4Ti
20. 'OO
...
i;oo
"
,4.1.-
i.1
!.:-,...
7 3
2200-4200
7S.H4

'-. l-<..4
li-il
CUr.hrr
[Crntrif'iRe only * f i r r 4'10i
10-4J
120
i lOO-t'- CO
4.9-.1
J.o-J. J
0. 17.0. 2*.
nd dded to EHT.

> tRes 14 firidil wtth ."
n. " P


5ra>d top nf EHT.
Inlet pH s ,. 91-
Stoich. Ran,)* 1. (^



ptibly cuird by low
di-rr to Kdch tr*>". Bottom
ot demnter 441". plu([R*d.
,,,...A
. ' 10 '74


JO. t-00

12 no

7.1
U
'i-1i:,'.;\'l'V.v.-.;.'^"'"'
j . 4 li , ,c
L 	 -. -- ' .' - 	

71.0.
V4...1 1
4.7... <
1 1.40
CUril.rr
l*.i.>
Ml
iv.OOO
t. ' - .'
-' ' ' ' :
*'"> "
ind Jddrd 10 RHT,
	


run.



SrlO-S/l 84:2".

topr<...d)c buildup on mis* rlim-

,,i.2A

ViO'74
J*H
JO. -00
*
1 :oo
104
7.3
1.'
>..-,.<.
?:
,'fifirt. 1 JjlO
Q,..Q
t. ' - , 0
-.2-V-

Clarififr
12 .-11
14.*
4-. .11)0.  :). 0,irt
4. ^-4. ^
1. *'.?. I
a. li.o. (>
nd *drffd t,, RUT.
 - - - 	 	

recycle liquor (pt\i 1 *> (ipni
P">- 	 



t S. 8;0, 2
i^,r;;r;,orPPrP
K.,ch.lrl.y'rrfVelf.|uep.
ppm Mg. Run fri-niinAtrd due
tloitom ,.f demiit.^ 1-2*1.

                             261

-------
                      Table 1 (continued)
SUMMARY OF LIMESTONE RELIABILITY TESTS ON TCA SYSTEM
Run No.
Staff- of- Run Dal*
Knd-.'f.Run t)-te
On 5. niolr* C
Av(j ", l.iniriionp ViiltMiun. 10o*

Prrerni SOj Hcmox*]
Scrubber Inlet ptl R*nKr
Scuibbt-r Cotr1 pit RanRr
Prrccrtl SuUu r Cxirtirrd
Solid* Dipo*i) ri>-*trn!
Loop Cl..Mirr. "- SUd. 0,,chR.
Sc rubber Irtln Liquor ^ =.r>"C
Tola! f)uolvrd Solid*, pprn

Orrni*l*r and Ktich Triy. '"- H^O
AP Rnr, in HjO
D^iniitf r AP K^ngp. in. ItjO


s"hb" '""'"


Method of Control





S1J-2A
8/r./T4
VZH?4
UJ
20. '-OO
8,r.
uoo
71
14. <--!=,. S
12
t. 1- l.<.,
Tt.
2000- J7SO
9^.90
1. 7-t.. 0
. J-S.t-S
IS-2J
CUrifirr
2q.i
1 i1.
^i. OOiJ.'-rt. 000


2,0<,. \. H*,
0.17-0.2S
*rtd Jddril l MIT.

r,rw TPR -phcri.
Sv*^*lehrd. (UpU^d
TPtt'.
at l.H'O. 2

CO2 blnhcl over EHT (.
PWHT. and mii elim. /KT
rrcyclr U>0p.

.^^.......y...^ s

1J4-2A
B/74
100
20. SOO
*.(.
1200
:i
10-12.*,
12
i. io-u to
82
2700- Jt;00
7S-00
S. t,^-^, 8^
S.2-S.4
IS- )0
CUrihrr
JO-<(J
1 )0
T'joo-S'.oa


I. 8^-2. 00
0. IS-O. JO
and artdrd lo F)1T.

run.
5y.ttmelr,*d.

t '-.l0.2



P ,

^>S-2A
9,M2/74
In Proj[rfti

20. SOO
8-fc
1ZOO
7)
12-IS
U(/12-q/27|. lM*rt
Stf.i-h. HAIIO* 1. 7
^Zt..2A.



hrnlrt. \Q n\ilt i^felr n
all Rrirta.




































                            262

-------
                                                                                         Table  2

                                  AVERAGE  SCRUBBER INLET LIQUOR  COMPOSITIONS AND  CALCULATED
                                     SULFATE  SATURATIONS  FOR  TCA LIMESTONE  RELIABILITY  RUNS
Run No.
525-2A
S26-2A
528-2A
529-2Ala>
530-2A(b)
S32-2A
S33-2A
S34-2A
535-2A(C)
Percent
Solids
Recirculated
14-16
14-15. 5
14-16
14. 5-16
14-16
7-9
14.5-15.5
10-12. 5
11. 1-15. 5
Effluent
Residence
Time, min.
10
10
12
12
12
12
U
12
15
Percent
Solids
Discharged
31-42
35-47
25-33
30-47
30-43
32-43
29-38
30-40
35-42
Percent
Sulfur
Oxidized
15-30
15-35
10-30
15-30
12-25
7-25
15-21
15-30
15-25
Scrubber
Inlet pH
Range
5. 5-6. 1
5.65-5.9
5.7-5.95
5.2-5.5
5. 1-5.4
5.2-5.6
5.1-fc.O
5.65-5.85
5.8-6.0
Inlet Liquor Species Concentrations, mg/1
Cat+
2100
2300
1400
1900
1730
570
us
2220
1850
MgtV
250
340
200
330
340
10,500
u.aoo
170
290
Na
80
60
30
120
50
60
GO
40
50
K*
50
140
120
520
120
no
no
180
70
so/
80
80
150
30
120
3000
2570
70
60
so4-
2000
1900
1600
2000
1900
38,700
17.200
1730
1800
(ppm)
CO/
70
210
260
ISO
320
30
200
90
80

ci-
3200
3700
1600
3300
2790
2400
1100
3540
3060

Total
7900
8700
5400
3400
7370
56,900
55.750
8040
7260
Calculated Percent
Sulfate Saturation
at 50C
UO
130
110
130
120
140
135
130
120
CO
               Note: Average concentrations are for steady-state operating periods.
                    Solids disposal sysbem: Clarifier only.

               (a)  Only one sample was taken during steady-state operation,

               (b)  Solids disposal systems: Clarifier only for first two-thirds of
                   lest, then centrifuge only.
(c)  Test run was started on 9/12/74 with 12 minutes residence time.  Residence
    time wag increased to 15 minutes on 9/27.  The run is still in progress as of
    10/lfc.  The values given in the table are for period ")fZ7 through 10/U>.
fd)

-------
 3
El
S '
  s
                                         1ION - - j    REHEAIiR BURNER CltftNINC --J INSPECTION  -J
                                                                                                      VSPJCTIQN .1
      1.SOO

      3000
      2.000

      I WO
                                                                                                                         3,000

                                                                                                                         7.VX

                                                                                                                         1.000
            \  |J  I
                                                                        I  9'N  I 9'M I  9 M- I 9'2? !  9'78 I 979 I  9,'X I ID'1 ]
                                                           CALEHUAR DA
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 si I
                                                                                                                -
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r 11.000

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a 9.000
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S 7.000
? 1.000
? 5000
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_  TOTAL DISSOLVED SOLIDS
<^> CALCIUM IC*"J

C SUlf AT( 1503 -1
A CHLORIDE ICI "I
NOTE SPECKSWMOSE
*~ CONCENTRATIONS ARE USS
THAN SOO Wf ARC WOT
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 -

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* * * *  1
.

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 A * * A - A -
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	 1 	 U 	 1  	 1 	 1 	 1 	 1 	 1 	 l 	 1 	 1 	
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10.000
9.000
1.000

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(000
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1,000
0
                                                           TEST TIME hou.t
                           .  | 9'1G I  MT I 9/16 ! 9/99 I  9/30 I  9>}l I 9/H I 9/2] I  9/74 1 9/75 I  917* I 9/77 I  97S  I 9/29 I  9rx  I 10/1
                                                            CALCNOJXROA
                   Gasflele- 20.500 aclm P 300 F
                   Liquor Rale * 1200 gprn
                   L/6  73 gal/mcl
                   Gas Velocity = 8.6 li/uc
                   EHT (Sealed) Hil)[nM Time  12 min(9/12-9/27).
                       15m.n(i)lleT9/27l
                   Thiee Stages. 5 in ipheres/slage
Percent Solids Redtculattd  i: 15 w %
Total Pre'^Te Drop. Excluding Qtmwtt
    ano Koch Tiay = 4.M.S in H,0
Serubbei Inlet Liquor Temperature =120-l2tSF
Liquid Conductivity 4.800-10.000 u  mhoi/cm
Discharge (Clarilier) Solids
    Concentration < 35 42 wt %
                   Figure  7.    Operating  Data   for  TCA  Run  535-2A
                                                          264

-------
was  to operate  cont imiously for  from four to six months.  The operating

conditions selected for (lie  run were based on the  results of the relia-

bility verification  tests (see Figure (>) and the tests conducted at the EPA

pilot facility at Research Triangle Park .  The major test conditions
were (see Table 1):
         Gas Velocity                            10. ^ ft/sec
         Liquid-to-Ga s Ratio                       (>0 gal/mcf
         Pe rcent Solids Reci rcula I ed               I ^
         Effluent Residence Time                  10 min.
         Percent SO^ Removal (controlled)         84
During this test,  the Koch Floxilray was irrigated  with  the available

raw water makeup plxis all the  clarified liquor at an approximate one

to three ratio,  with  the effluent irrigation liquor routed to the scrubber
effluent hold tank.  The mist eliminator, at that time,  had no provision

for underside wash and was  washed with liquid entrainment  from the

Koch tray.


For the first  time,  thermo-plasl ic - rubber (TPR) spheres, supplied by

UOP,  were tested in 'he scrubber.  They were used in the top bed  while

the bottom two  beds were charged with high density polyethylene (HDPE)
spheres,  also supplied by UOP.  The  original wire mesh  grids  (which

eroded during the limestone reliability verifications runs) had been

replaced  by sturdier bar-grids  for the long-term reliability runs.
 The velocities listed in this report are based upon scrubber outlet
 gas  flow rate at  12E>F.  Gas velocities listed in previous Shawnee
 reports have been based upon scrubber inlet  gas  flow rate corrected
 to 12SF.   The velocities  al the scrubber outlet conditions are approx-
 imately seven percent higher than at the  scrubber inlet  conditions,
 due  to moisture  pickup.
                                  265

-------
After 517 hours of operation the run was  terminated,  due to unusually

heavy solids bxiildup on the underside of the Koch Flexitray and scale

and solids buildup  on the bottom vanes of the  mist eliminator  (about 60

percent of the free area was plugged).  Numeroxis (over 200) half-spheres

of the TPR type were found  in the scrubber and slurry circulating system.

TPR half-spheres  were also found lodged in two of the four inlet slurry

spray nozzles.  It  should be  noted that the scrubber stages  (and bottom-

most grid) were essentially free of scale after the 517 hour operating

period, as was  expected,  since  the calcxdated scrubber inlet liquor sulfate

saturation was 140 percent (see Table 2).


It  is hypothesized that  the accumulation of soft solids below the Koch

tray was  due, primarily,  to  the partial blockage  of the  slurry  inlet, nox-

zles, resulting  in excessive  entrainment  of the fine slurry droplets.

This excessive  entrainment and the high  gas  velocity  (10. 5  ft/sec) most

probably  contributed to the mist eliminator pluggage.


3.1.2   TCA Run  526-2A


Run 526-2A was begun on November 21,  1973.  The TPR spheres in

the top  bed had  been replaced with FIDPE spheres , and the accumulated

scale and soft solids from Run 525-2A had been  removed.   The run

conditions were identical  to those for Run 525-2A, except that the gas

velocity was reduced to 8. (> ft/sec.  The  velocity was reduced because

more detailed investigation  of previous reliability verification runs
  It was planned to use TPR spheres in all three stages following the
  installation of strainers in the inlet slurry piping.
                               266

-------
(see References  1 and 2) indicated that long-term reliability for the



present Koch tray/mist eliminator configuration  could not be expected



at a  gas velocity of  10. 5 ft/sec.








On January 10,  1974, the run was interrupted after 1190 hours of on-



stream operation, to check the wear of the HOPE spheres in the three



beds (HDPE sphere  life had been estimated to be  less the 2000 hours).



Pressure drop across the chevron mist eliminator increased slightly



during the initial 800 hours of operation,  and during the last 400 hours



increased more rapidly to a final level about 1. 5  times the initial value



of 0. 18 inches H2O.








The  general appearance  of the  system was good.   Scattered  solids



deposits (up to 1 inch) and light scale (about 1/16  inch) was found on



the scrubber walls below the bottommost grid and on the wall areas



not in contact with the spheres. The four bar grids  were covered with



10-14 mil scale on the inactive surfaces  (i. e. ,  surfaces not in contact



with spheres).








A  heavy,  relatively uniform solids layer  covered  the underside of the



wash tray.  All four inlet slurry spray nozzles were partially  plugged



with debris, primarily with plastic covering from pipe insulation.



The  flange of the steam sparger underneath the wash tray was found



leaking.   Mist eliminator plugging was confined to the bottom two passes



only, reducing the free  flow area by about 15 percent.  Several small



pieces of solids fell  from the outlet  gas duct and  rested on top of the



center section of the mist eliminator.  The area  restricted by these



pieces was  insufficient to affect the  pressure drop across the mist



eliminator.
                                 267

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As with Run 525-2A, it is hypothesized that the solids accumulations



on the slurry  inlet spray nozzles and header,  on the adjacent scrubber



walls and on the underside of the Koch wash tray were primarily caused



by partial blockage of the  TCA slurry inlet spray nozzles by debris,



which changed the spray pattern and caused excessive entrainment  of



fine  slurry droplets.  Also,  the  blocked nozzles may have been a major



factor contributing to the mist eliminator pluggage observed.  It should



be noted that the accumulation of sulfate scale on the bottommost bar



grid (10-14  mils) was not  excessive, after the approximate 1200 hours



of operation.  This was to be expected, since the scrubber inlet slurry



was  only 130 percent saturated with respect to calcium sulfate (see



Table 2).







The  average percent weight  loss for the HDPE spheres in  the bottom



two beds was  approximately 32 percent, for 1707 hours (Runs  525-2A



and  526-2A) of use.







3.1.3  TCA Run 527-2A







Run  527-2A commenced on January 18, 1974, following the removal of



the soft solids from the walls (inlet slurry spray nozzles area) and  from



the bottom of  the Koch tray (the mist eliminator was not cleaned).   It



was  a scheduled  short-term run to determine whether certain  changes



in the scrubber internal configurations  could minimize the mist elim-



inator pluggage problem and to observe the effect of the  changes on



SC>2  removal and limestone utilization.  The  modifications included



raising the Koch tray outlet weir height from 2 to 3 inches, using two



beds (3 grids) with 71/2  inches of spheres per bed and the removal of
                                268

-------
the four  inlet slurry spray no/.zles for minimum spray generation with



open pipe slurry distribution.








The results of the  changes were  inconclusive and the run was terminated



after 133 operating hours.  The slxirry carryover to the Koch tray and



the mist eliminator appeared to be equal to or  greater  than the carry-



over observed dxiring Run 526-2A.








The mist eliminator plugging continued on  the lower vanes and the free



flow area was  reduced by an additional 50 percent (for  a combined total



of (-5 percent for Runs 526-2A and 527-2A).  It  shoxild be noted that



the Koch tray, inadvertently, was not irrigated for a 2 hour period



during the run.








An additional 20 mils of  scale formed on the scrubber walls below the



bottommost grid.








3.1.4    TCA Run  528-2A








Run 528-2A was started  on  February  6, 1974,  following a complete



cleaning of the system.  The  run was intended  to be of  short  duration



and was  made  using raw water only for Koch tray irrigation.  The



Koch tray  effluent  was routed to  the sewer.  The purpose of the run



was to observe the effect of irrigation with  raw water,  versus raw



water plus clarified liquor,  on the mist eliminator scale and  solids



deposition.  Scrubber  internal configurations were returned to Run



S26-2A conditions  (2 inch Koch tray outlet  weir height, use of inlet



slurry spray nozzles,  three-bed operation). The HDPE  spheres were
                                 269

-------
replaced with ne\v,  improved,  TPR spheres al 5 inches of spheres in

each bed.  A duel strainer (by Elliot Co. ) was installed in the  scrubber

feed slurry loop to prevent the inlet spray nox,/,les from plugging by

debris.


The run was terminated on February 26 after 425 hours of operation

and the appearance  of the system was generally good.  The top of the

Koch Flexitray was covered  with approximately 20 mils of dust type

solids.  The mist eliminator was free  of scale and solids with  only a

slight film of dust covering the inlet vanes.  The pressure drop across

the mist eliminator and Koch Flexilray had not increased during the

test.  The bottom of the wash tray was relatively clean.


Evidence  from this  test showed that the potential for scale and solids

deposits on the mist eliminator is decreased when the  degree of sulfate

satxiration of the Koch  Flexilray  wash liquor is reduced.


It  should be noted that  excessive weepage from the Koch  tray irrigation

water caused the test to be made with a slightly open liquor loop (average

discharged  solids of 29 percent). This explains  the relatively  low cal-

culated scrubber inlet  liquor sulfate saturation of 110 percent  (see

Table 2).
 The run was interrupted for about 40 hours (Febrxiary  11-13) due  to
 a No.  10 boiler maintenance outage.
                                 270

-------
3. 1. 5    TCA Run 529-2A


Run 529-2A was started  on Februa'ry 26,  1974.   The test conditions

were the same as for Run 528-2A, except that the Koch tray was ir-

rigated with the available raw water makeup plus all clarified  liquor

at an approximately  one  to three ratio.  The run was initially intended

to be a long-term limestone  test.  However, an inspection on March 7

revealed that the lower vanes of the  mist  eliminator were approximately

19 percent plugged with scale and soft  solids.  This was considered to

be significant after the relatively short period of time and  the run

was terminated after only 213 operating hours.


Nearly all the TPR spheres were dimpled.   Eight spheres had failed

(filled with slurry) in the bottom bed.


3.1.6    TCA Run 530-2A


Run 530- 2A was started on March 28,   1974, after a thorough cleaning.

The Koch tray was irrigated at  a constant rate of 1 5 gpm,  consisting

of about 8  gpm makeup water and 7 gpm clarified liquor, with the

purpose of achieving a high dilution  of Koch tray irrigation  liquor

and, hence,  minimizing  the mist eliminator and Koch tray scaling

potential (see Run 528-2A).
  This partially collapsed condition is considered normal by the supplier
  due  to pressure and temperature cycling between operating periods
  and  shutdowns.
                                 271

-------
The run was originally intended to be a long-term reliability test.



However, it  was terminated after only 476  operating hours when a



rapid increase in pressure drop across the Koch tray occurred.  An



inspection revealed heavy scale and solids  deposits on top of the Koch



tray.  A clarifier rake malfunction (which was  not discovered until



April 10) caused heavy solids  carryover in the  clarifier overflow for



about two days.  The solids carryover and  the lower (15 gpni) Koch



tray flush rate probably resulted in the settling of solids  on the Koch



tray.  Subsequent use of the centrifuge  for  slurry dewatering  resulted



in centrate containing about 0. 5 wt. % of solids,  which may have con-



tributed to further settling of solids on  the  Koch tray.








The mist eliminator was heavily plugged.   Inspection on April 9 (after



290 hours of operation)  showed an estimated overall restriction of



8 percent which then increased rapidly  in 186 hours to 44 percent at



the end of run.








Approximately 100 TPR spheres (0.4 percent of the total inventory of



the system) failed during the run.








3.1.7    TCA Run 531-ZA








Run 531-2A was  begun on  May  10, 1974, after a thorough cleaning.



Magnesium oxide was added to the effluent  hold tank in  an attempt  to



operate in the sulfate unsaturated mode.  Also,  the TCA  slurry header



was lowered four feet in an attempt to reduce the amount of slurry



droplet entrainment to the Koch tray.
                                272

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The  run was terminated after 1088 operating hours due to increasing



pressure drop across the mist eliminator, Koch tray and bottommost



TCA bed.  Inspection revealed considerable scale and solids deposits



on the Koch tray,  mist eliminator and bottom grid.  The mist eliminator



v/as  75 percent plugged at the inlet edge and within the first pass.  Scale



deposits were limited to the first two passed.







Heavier than usual solids buildup was observed on the walls between



the slurry  spray nozzles and the steam  sparger.  This could be due to



insufficient wetting of the walls by entrained slurry,  resulting from the



lowering of the slurry spray header.







The  run had never attained steady state (i. e. ,  the desired magnesium



ion concentration  of 10, 000 ppm was not reached) and the final mag-



nesium concentration of 5, 000 ppm  in the process slurry was  insuf-



ficient to attain unsaturated operation.







A total of 638 TPR spheres  (2. 4 percent of the starting inventory) had



failed during the run. The wear of the intact  spheres varied from



no measurable loss  in the top bed to a 6. 5 percent weight loss in  the



bottom bed for over ZOOO hours of operation.







3.1.8   TCA Run 532-2A







Run 532-2A was begun on July 17, 1974, after the system was cleaned.



Again, magnesium oxide was added to the  effluent hold tank in an attempt



to operate  in the sulfate unsaturated mode at a 10, 000 ppm level of



magnesium ion in the process slurry.  The scrubber recirculation



liquor rate was increased from 1200 to 1700 gpm.
                               273

-------
Also, a closed recycle irrigation liquor loop was provided for the Koch

tray/mist eliminator system which included provision for mist elim-

inator underwash (~ 8 gpm fresh water plus ~ 7 gpm recycle liquor).

The Koch tray recycle  irrigation rate was set at 35 gpm.  The clari-

fier liquor,  which had been used for Koch tray irrigation during the

previous tests, was routed directly to  the effluent hold tank.


Because of relatively high saturation (140 percent) of the inlet scrubber

slurry and the liquor in the wash tray loop,  an inspection was made  on

July 29,  after 258 operating hours.  About 200 mils thick scale covered

the walls below the bottommost grid and the top of the Koch tray was

covered  with 12 mils of scale.  The free flow area of the mist eliminator

was 1-2  percent plugged with solids, within the first and second passes.


About 4000 TPR spheres  (15 percent of the total inventory) were found

floating in the downcomer.  They had passed through the bottom grid.


In view of the above problems,  the run was  terminated.  Note that,  the

SC>2 removal efficiency for this test averaged about 98  percent, as com-

pared to 84  percent for the previous test, due to the addition  of mag-

nesium (see Table  1).


3.1.9    TCA  Run 533-2A


Run 533-2A was started on August 6, 1974,  after  a thorough cleaning

of the system. The recirculating slurry rate was reduced from 1700

to 1200 gpm,   the used TPR spheres  in the three beds were replaced
  The 11/2 inch TPR spheres can pass through the bar-grids supplied
  by UOP when they become dimpled  on both sides.

  The liquor rate was reduced because of increased erosion of steel
  piping during the previous test.

                                 274

-------
with new ones and  the percent solids recircxilated was increased from



8 to  1 S percent.  The Koch tray/mist eliminator  system was the same



as in the previous  test,  with a  closed recycle irrigation liquor loop



for the Koch tray and mist eliminator underwa sh.  The scrubber slurry



magnesium ion concentration was maintained at 10,000 ppm.   The



scrubber inlet liquor, however, was still  supersaturated with respect



to sulfate (see Table 2).








The  run  was terminated after 33Z operating hours when an  inspection



showed that the underside of the wash tray was covered with up to 60



mils of scale over 40 percent of the tray area.  The top surface of the



tray was coated with from 50 to 100 mils  of scale. The mist eliminator



was  12 percent plugged  with scale/solids  deposit, primarily in the



second and third passes.  Also, the walls between the steam  sparger



and  the slurry spray nozzles had up to 2 inches of solids  deposit.








3.1.10    TCA Run 534-2A








Run  534-2A was started on  September  3,  1974,  after the  system had



been cleaned.   It was decided to abandon,  for the time being, attempts



to operate in the sulfate unsaturated mode with the addition of mag-



nesium oxide,  until further exploratory tests were conducted at the



EPA pilot  facility  in Research  Triangle Park.  Therefore,  conditions



for Run  534-2A were chosen similar to those of Run  526-2A,  which  had



been in operation for 1190 hours,  with no apparent scaling  problem  on



the top of the Koch tray.  The underside of the mist eliminator was



washed continuously with  15 gpm diluted clarified liquor  (~ 8 gpm



makeup water  plus~ 7 gpm  clarified liquor) while the Koch tray was
                                 275

-------
irrigated with  the remaining ~ 8 gpm of clarified liquor plus the 15 gpm

mist eliminator wash.   The main differences between Runs 534-2A

and 52(>-ZA were, therefore,  the addition  of direct mist eliminator

unclerwash and the four feel lower elevation of the inlet slurry spray

header.   In order to reach the expected  steady  state chloride concen-

tration quickly, CaCl2 was added to the  system before startup.


Run  534-2A was terminated after 100 on-stream hours due to scale

buildup on the  Koch tray.  The top of the tray,  including the valve caps,

was almost completely covered with from  10 to 15 mils of scale.  About

2 percent of the mist eliminator flow area was  restricted by solids.

Also,  about  30 percent of (lie  Koch tray  underside surface was covered

with solids,  reaching a maximum thickness  of 1 1/2 inches.


As in the previous run, the  walls between  the steam sparger and the

slurry spray nozzles had up to 2 inches  of solids  deposit.


3.1.11    TCA Run 535-2A


Run  535-2A was begxm on September 12, 1974,  after the system had

been cleaned.  The  test conditions were nearly identical to Run 534-2A,

with the  added condition that a minimum clarified liquor flow rate of

15 gpm for Koch tray irrigation and mist eliminator wash  was to be
 It normally takes a number of weeks for the chloride level in the process
 slurry to reach a steady stale value, when beginning  a rxin with raw
 water.  The process slurry was dumped at the beginning (if Rxm 534-2A
 to dispose of the large quantity of magnesium  ion in the system.
                                276

-------
maintained.  In maintaining this rate,  the fluctuating bleed flow to the



clarifier resulted in,  at times, only 12-13 percent solids (as  compared



to the desired  15 percent) in the reci rculating sliirry.  Therefore, the



effluent residence time was increased from  12 to 15 minutes, in order



that the sulfate saturation of the scrubber liquor remain below 135



percent at all times (see Figure 6).  Also, about  12 percent more



make-up water was available for mist eliminator/Koch tray irrigation,



because of the  elimination of seal water from a flue gas cooling spray



pump.







After 158 hours of operation,  an inspection showed about 15 mils of



scale covering  about 25 percent of the top of the Koch tray and rela-



tively heavy solids accumulation (up to two inches thick in some areas)



on the underside of the tray.  The mist eliminator was about  5 percent



plugged with solids  (mostly fly ash) on the lower vanes.  The  walls



between the steam sparger and the slurry spray nozzles had up to 4



inches of solids deposit.  The run was  continued.







After 316 hours of operation,  a second inspection revealed that the



scale had disappeared from the top of the Koch tray and that the mist



eliminator was only 1-2 percent plugged with scattered solids (mostly



fly ash) on  the lower vanes.  The bottom of the Koch tray, however,



still had heavy solids accumulation.  At this time, it was found that



the steam pressure in the Koch tray steam sparger (see Figure 2) had



drifted to 50 psig from an original setting of 125 psig.   The steam



pressure was  reset and the run continued.







After 431 hours of operation,  a third inspection showed that the top



of the  Koch tray was still clean and that the  mist eliminator was
                                277

-------
practically clean (approximately one percent plugged with scattered



solids on the bottom vane).  The solids accumulation on the under-



side of the Koch tray had been substantially reduced, with 30 percent



of the underside clean to metal.  However,  solids buildup on the walls



between  the steam  sparger and the slurry spray nozzles had increased



to a miximum thickness of 8 inches in some areas.







After 786 hours of  operation, a fourth inspection showed that the top



of the Koch tray was  still clean and the mist eliminator  again prac-



tically clean (approximately one  percent plugged with scattered solids



on the bottom vane).  The solids accumulation on the underside of the



Koch  tray was  slightly increased, with 20-25 percent of the under-



side clean.  The  solids buildup on the walls between the steam sparger



and the slurry  spray  nozzles had further increased.  The maximum



deposit in one area had reached  15 inches in thickness.  Approximately



30 mils of scale had accumulated on the grids during the 786 hours of



operation.  There was no measurable increase in pressure drop across



the beds, Koch tray or mist eliminator.  The run was continued fol-



lowing the  786 hour inspection.







The average wear of  the  TPR  spheres,  tor l^uu nours ol operation,



was about 4 percent.







3. 2    CONCLUSIONS







3. 2. 1    Scrubber Internals Operability







Both the limestone  reliability verification and reliability test results



have shown that scrubber internals  can be kept relatively free of scale
                                278

-------
if the sulfate (gypsum)  saturation of the scrubber liquor is kept below

about 135 percent.   This can be accomplished with the proper selection

of percent solids recirculated,  effluent residence time  and liquid-to-gas

ratio (see Figure 6).  The data indicate that, at approximately 15 percent

solids recirculated, 10 minutes effluent residence time  and 73 gal/mcf

liquid-to-gas ratio, the scaling of the TCA internals will not  become a

problem to maintaining long-term system operation. For example,

the  four bar grids in the TCA were covered with only 10-14 mils of

scale after 1190 hours  of operation in Run 526-2A.



A significant recent problem in the TCA has been associated  with

solids buildup on the walls between the  steam sparger and the slurry

spray nozzles (see Runs 531-2A through 535-2A), which originated

after the slurry spray nozzles had been lowered by four feet.  It is

hypothesized that the solids  buildup is  due to insufficient wetting of the

walls by entrained  slurry.   The problem may be corrected,  therefore,

by washing the walls between the  tray and nozzles or by raising the

nozzles to their original position.



Until recently, a significant limiting factor in the long-term  reliability

of the TCA scrubber has been associated with the erosion  and subsequent

collapse of the UOP supplied HDPE spheres (sphere  life was  approxi-

mately  2000 hours).  The collapsed spheres eventually  filled with  slurry

and settled to the bottom of the support grids.  Starting  with Run 528-2A,

an improved type of UOP supplied TPR sphere was used in the TCA
           \
beds.  After approximately 2500 hours  of operation,  all the-spheres

were dimpled on one side, about 2. 4 percent failed at the seam and the

weightless averaged about  six percent.  It is estimated that these  TPR

spheres would not need replacement until after about a  year  of service.

The problem associated with dimpled  spheres falling through the bar-

grids (see Run 532-2A) can be solved by redesigning the grids.
                                279

-------
There has been no evidence of significant erosion of the bar-grids in



the TCA after more than 5000 hours of operation.








3. Z. Z    Koch Tray/Mist Elirninator Operability








The most significant reliability problem encountered dxiring the TCA



limestone reliability tests has been associated with scaling and/or



plugging of the Koch Flexitray and bottom vanes of the chevron mist



eliminator  (see Figures Z  and  3).








Run 5Z8-2A showed that the mist eliminator and top  surface of the Koch



tray can be kept relatively free of scale  if the irrigation liquor is low



in sulfate saturation (unsaturated).








Run 5Z6-ZA showed that the top of the Koch  tray can be kept relatively



free of scale  if it is irrigated with the available  raw water makeup and



clarified liquor, provided  the mixtxire is maintained below the critical



sulfate saturation level.   The run was terminated prematurely,  after



1190 hours, due to excessive wear  on the HDPE spheres and pluggage



(with debris)  of the scrubber slurry nozzles.








The present Run 535-ZA has been in operation  for over 780 hours



without any significant scaling or plugging of the top of the Koch tray



or mist eliminator surfaces.   The test conditions for this  run are



similar to those for Runs 5Z6-ZA and 5Z9-ZA,  with  the exception  of



direct mist eliminator underwash.  It is likely that  long-term relia-



bility of this mist elimination system -would be realized at the rxm



conditions tested.
                                  280

-------
                             Section 4

               LIME RELIABILITY TEST RESULTS


Performance and analytical data  from the venturi/spray tower system

lime reliability testing at the Sha\vnee facility are presented in this
section,  along with an evaluation of each reliability test and the con-
clusions drawn,  to date,  from the testing.


4. 1   PERFORMANCE DATA AND TEST EVALUATION


A summary  of the test conditions and  results for each of the venturi/
spray tower  lime reliability tests is presented in Table 3, along with

the run philosophies.  A  summary  of the scrubber inlet liquor analy-
tical data for a majority  of the tests is presented in Table 4, along

with the  calculated percent sulfate  saturations.   Essential operating
data for  all of the venturi/spray tower lime  reliability  tests are  graph-

ically presented  in Reference 1.  As  an example,  operating  data for
Run 604-1A  from June 6,  1974,  to  June 24,  1974,  is graphically pre-
sented in Figure 8.   An evaluation  and discussion of each test is pre-

sented below.
 The sulfate saturations and analytical data are for an average inlet
 gas SO2 concentration of Z800 ppm.  The effect of inlet gas SO2 con-
 centration on sulfate saturation is  discussed in the following sections.
                                281

-------
                Table 3
SUMMARY OF LIME RELIABILITY TESTS
  ON VENTURI/SPRAY TOWER SYSTEM
Run No.
Start-of-Run Date
End-of-Run Date
On Stream Hours
Gas Rate. acfmtp1 J30F
Spray Tower Gas Vel. fps @ 12<>0F
Vrnturt /Spray Tower
Liquor Rates. Rpm
Spray Tower L/>tomrirjc Ratio, molts Ca
added/molf SOj absorbed
Avg ~*0 Limestone Utilization. lOOx
moles SO^ abs, /mole Ca added
(rtlet SO^ Concentration, ppm
Percent SO; Removal
Scrubber tnlel pH Range
Scrubber Outlet pH Range
Percent Sulfur Oxidized
Loop Closure. *, Solids Oischfl,
Calculated *"- SuUale Saturation in
Dissolved Solids, ppm
Total A.P Pange, Excluding
Demister, in. HjO
Venturi A P. in. H2O
Demisier _%P. in. H2O
Absorbent

Mist Eliminator


Scrubber Internals


System Changes before Start
of Run



Method of Control
Run Philosophy
Results
',01 -IA
10/9/73
l/B/74
2m
2^.000
',.7
f.00/1200
r.O
7.T
12
Clartfier Only Clarif Jr Intermittent Clarifier . Filter
f 10/9-1 1/7) Filter 11 1/7-1 2. Ml) (12/lS-l/P^
I. 01- 1.28 J. 02-1. 18 '- 04-J. 1*1

If. 00- 3900 1 'jQO- 4000 2 1 00-4400
.8--9l 7S-91 7<-*
7.4-8. 5 7. *.*.. 7.7.R.4
4.7-S.S 4. 7-1. < 4.8-S. *
10-30 10- 30 10-10
20-2*. 20-27 42-12
110 120 ISO
1700-7SOO 4^.00-7300 9800-12. JOO
11.0-11.1 11.0-12.0 11.7-12. 3
009
0. SI- 0. 70 0. f.0-0. 90 0. 0- I. 61
to EHT.

10/9 - 12/11; Bottom washed with available makeup water
(^-14 gpml plus available clarified liquor \~Zt> gpm). Con-
tinuous wash rate of 0.8 gpm/ft2. 12/15 - 1/8: Bottom
washed with available makeup water |~*1 gprn) plus available









Scrubber inlet pH controlled at 8. 0 * 0. 2
Initially started as lime reliability verification test. Sub-
sequcnily. due to apparent reliability of the run. decision
was made (hat test continue as long-term reliability test.
Routine inspection on 11/7/74 showed system was generally
clean after 666 hours of operation with Clarifier only for
solids disposal. Run was terminated on 1/8/74 due to ID
fan vibration and rapidly increasing pressure drop across
demister. Sulfate based scale formed on most scrubber
walls *nd in slurry piping. Top of mist eliminator SO8".
plugged with solids that fell from outlet duct-work. Mist
eliminator top vanes heavily scaled ( 300 mils avg. ).
t-02 - 1A
J/1S/74
4/1/74
m
2S.OOO
*'. 7
(. 00/1200
r.0
7. $-0.1
12
Clarifier *< Filter
1. 02-). JS
91
2100-3800
R7-97
7. fa-8. 3
4. 9-S. 4
1-28
42-48
lt-5
9100
11.0-12.0
9
0. 61-0. 73

EHT.
Bottom washed! with available
makeup  00
11.0.12.0
<)
0. It.O. 72

EHT.
Bottom wished with ivailablr
makeup watr 1  5 Rpm' plus
available clarified liquor
(~2l j;pmt. Wash rate of 1
mtn ort/l-1/2 min off.

All noceles on 4 headers
zlej/header on top J headers.





Scrubber inlet pH controlled
at 8.0 t 0.2
Intended lonfj-lerm. Recir-
culate 1 We solids in attempt
to reduce degree of sulfale
saturation. EHT sald.
Degree of sulfale saturation
was reduced, but runu-as
terminated due to scale >0
mils avg. ) and solids buildup
nn the mist eliminator lop
vana.
                282

-------
            Table 3 (contirvued)
SUMMARY OF LIME RELIABILITY  TESTS




  ON VENTURI/SPRAY TOWER SYSTEM
Run No.
Start-of-Run Dale
End-of- Run Dale
On St ream Hour*
C*i Rate. cfm  3JOF
Spray Tower G.s Vel. fp @ I2SF
VMuH/Spray Tower
Liquor Rates, upm
Spray Tower L/C. gal/mef
Percent Solids Reci rculated

Solids Disposal Sy(cm
Stolchiomelric Ratio, motes Ca
*dded/mcrte SO2 absorbed
Avg % Limestone Utilization. 10 Ox
moles SO? abs. /mole Ca added
Inlet SO 2 Concentration, ppm
Percent SO2 Removal
Scrubber Inlet pH Range
Scrubber Outlet pM Range
Percent Sulfur Oxidised
Loop Closure. % Solids Dischg.
Calculated 7 Sulfate Saturation in
Scrubber Intel Liquor @ 50C
Dissolved Solids, ppm
Total AP Range. Excluding
Demisjter, in. H^O
Venturi A P. in. HjO
Demtster AP. in. M2O
Absorbent
Mist Eliminator
Scrubber Internals
System Changes Before Start
of Run
Method of Control
Run Philosophy
Results
<,0-i.lA
4/2t./74
7/1S/74
1828
2S.QOO
iV 7
min. <- 1001/1200
i.O
7. S-9. 0
17
Clarifier fc Filter
l.OJ-l, JO
88
2000-3800
70-92
7. 7.8.4
4. S-5.4
8-30
SO-60
130
11.600-1 J. 700
3. 3-3.8
Plug 100*, open
0.70-1.75
Lime slurried to 20 wt ^o with
scrubber downcomer.
makeup water (^S gprrO plus
available clarified liquor

mtn on/1 I/Z min off.
All nozzles on 4 headers
zlea/header on top 3 headefd.

Mist eliminator and outlet
provided with N*2 gas purge.
EHT overAow blanked. Lime
slurry makeup added to
JC rubber downcomer.
Scrubber inlet pH controlled
at 8. 0 t O.Z
Intended 2 wks. To obierve
sulflte oxidation and Degree of
BuUate saturation with lime
add'n to downcomer, minimum
slurry rate to ventui-I. sealed
EHT purged with NZ RA. and
8% solids rectrculated.
Degree of aulfate laturation
w*i about 130%' Solid* trorn
outlet duct fell to top of ml at
tied due to heavy ecale (500
mils avg. } and solid  buildup
on mist eliminator.
t.OS-lA
7/ JI/74
S/f/74
Ml
2^.000
-. v
mm. (-1001/1200
-.0
8. 0-Q. 3
17
Cl*ri(ier A Filter
1.10-1.17
A8
2^00-HOO
73-81
8.8-9. 2
4.9-S. 1
12-28
48-S2
IIS
b. 000-7. 400
J.2-3.9
PluR 100r oppn
0.80-0. 8S
Lime slurried to 20 wt -'ith

maVeup water only ( -S spmL
Wash rate of 0.4 (ipm/ft' on
off.

ties/header on top 3 headers.

System cleaned.
Scrubber it. let pH controlled
at 9. O i 0. 2
Intended long-term. Control
at higher pH in attempt to
reduce JM\ftte oxidation and
thereby degree of suHate
jaturation. Wash mist elim-
inator with water only.
Run was terminated due to
scale formation (vp to 1 $0
milslon cop mist eliminator

t.Ot.-lA
S/7/T4
8/ 14/74
170
2S000
".7
mm. ( -1001/1200
-0
7. 7. 4.0
1 7
CUrifirr
1. 10-1. 1">
8<)
2400- 1200
<.7-79
7. 8-8.2
'..O-S.Z
12-22
18-2)
120
1. 000-7. 000
J. f-1.7
Plug 100^ open
0. 78-0. 80
Lime slurricd to 20 wi**e wj^
scrubber dowrxcomer.
with IS ftpm (0. 1 Kpm/ft2)
raw water only. (Rate is
water).
All noitles on 4 headers
ties/header on (op 3 headers.



Scrubber inlet pH controlled
at 8. 0 i 0.2
ntendc-d short-term. Mist
eliminator wished continuous-
ly with T*W *H*T.&Mv Ut rate
greater than available makeup
u.-ater).
Run was terminated due to
scale formation (50 mils avg.l
on top mist eliminator vanes.
t.OS-lA
ft/21/74
Q/17/74
t,tO
2S. 000
r.. 7
'00/1200
f-0
7. 7.0. 4
12
CUrifirr \ Filter
I.OJ-1. 17
Rft
2000- J tOO
7<-. QA
7 . Q - S . 4
4.8-1. 1
1 1-24
43 - S*
MO
7. S00-9.*00
11. ^-12.0
9
0. 7<.-0. IT
Limr ?lurric
-------
                                                   Table  3  (continued)
                             SUMMARY  OF  LIME  RELIABILITY   TESTS
                                ON  VENTURI/SPRAY  TOWER  SYSTEM
Spray ToMi-rt-Cas  V.-J. fps ' 1-T^'f
   UiHf Spray Tow*-r
J.iqui>r Rates. p[>m
Spray Tower  L/C. j-al/
Percent Solids Reci rcul.ii
Effluent Residence Time.
Solids Disposal Sysieni
Slmchiomrtric Ratio,  moles Ca
   Ivdfmitle 5O2 absorbed
   K T, Limestone I'lili/aMon. tOOx
rnoJrs .SC2 abs, /rnolr Ca ftddrri
Inlel SC2 Concentration, ppn
Percent SO2
                 Vill
Scrvibbcr Inlel pH Ranpe
Scrubbrr Outlrl pll RanR
Percent Sulfur Oxidised
Loop Closure, *"? Solirijs Dischp.
CalculiH-(| "* Sulfatf Saiuraiinn
Scrubber Inlgi Liquor fi SOC
Total A P Kange. Ex
   nisler. in.  HgO
VeniuriAP. in. HgQ
DemislerAP.
Mist Eliminator
5crubtx-r Internals
System Changes  Before 55tar
Of Run
Method of Control
Run Philosophy
                                       Clarifirr '-  Filn-r
                                 i.in-n- slurried to 20
                                 rt lake up u>atr and ad
                                 scrubber duwnfomtr
                                 Bottom washed with makeup at
                                 2, 7 gpm/ft2 for ""ft min cw ry
                                 t hrs.  Simultaneous lop wa $h
                                 ^-ith remaining makeup at

                                 lozzle covering about  U ft^.
                                 Total makeup-v^ gpni  avp.
                                 All nozzles on 4 headers
                                 sprayed downward.  7 noz-
                                 iles/headcr on top 1 headers.
                                 *j nn/.xles on bottom header.
Misi eliminator and outlet duct
cleaned.  A single no/,zle in-
stalled to provide top wash for
one section of mist eliminator
and several holes drilled in
[he lop vanes of a second
 ection.
                                 Scrubber inlel pH controlled
                                 at 8.0 * 0.2
                                 Intended 2 wks.  To observe
                                 the effect of mist eltmin.Tior
                                 top wash (on one section) and
                                 the effect of increased resi-
                                 dence time on HuH.ite satur.i-
                                  ion.
                                  Run terminated as planned.
                                 Sulla I e saturation reduced to
                                   IO^,.  Mis! eliminator top
                                   an** clean M-here top washed
                                                                       284

-------
                                     Table 4

AVERAGE SCRUBBER INLET LIQUOR COMPOSITIONS AND CALCULATED SULFATE
      SATURATIONS FOR  VENTURI/SPRAY TOWER LIME RELIABILITY RUNS

Run No.

..ON! A1"'
,,01-1 A""
t.JJ-IA
t.04- 1A
i.O*-IA
i.OH- I A
..On-lA
Pi-rceni Effluent Percent
Solids Residence Solids
Kfcirculaled Tiou*. min. Discharced <
7--I 12 .70. 2i.
7-9 12 42-S2
11. 1-U-. 0 12 4f.-S4
7. <;-. 0 17 M)-i.O
.-". 2 17 4X-S2
7. =,-<>. I) 12 -U-iH
<-'' 24 4i. -=.2
^ercent Scrubber
Sulfur Inlet pll 	 1~^~| 	 1 	
Jxiili/.ed Ranpe Ca MR
10- !0 7. 4-. i. P'OO 140
10-30 7. 1.8. 1 MOO 200
12-22 7.8-8.2 2KSO 190
S-30 7. 7-S. 4 S200 400
12-2H H. H-'i. 2 2200 so
M-2-i 7. ,t C'alcuiat..,! l',.r.,-,,i
Sulfate Satu r.t i inn
K' SC ( SC., CC; CI' Ti-ta! at 1il"<:lrl""
HO "0 2000 20 2100 t400 1=.'!
230 '.0 2iOU 2S 4SOO 10.500 ISO
i!0 i.fl |i.70 S 4770 ii'icitj | tn
27'. ^0 2000 10 =i700 11.701) | -.0
IHO M> 14^0 ^ UJ70 Vi^i) 1J\
2 in 4-". 1'ijo 10 i
K3
00
Soli'ls disposal system: Clarifier and filler. pri'duct at SO"Cl. A solubility product for ("aSC.^ .'H,C ''' '* * "" ** ^ s
used (Radian Corporation. "A Theoretical Description of the J,imetone-
(a) Solids disposal system: Clarifier
(bl Solids disposal system; Clarifier and filler
inlet yas SC > concent ration of 2SOO ppm.
Injection Wcl Scrubbinu Process,' N'APCrA Keport. funi' 1. |
-------
 SSi
          .  RUN ecu IA CONTINUED
S'     90 -
                                                                   VEIMTum A SCHAV TOWfll
3. WO

3.000
2.bCC
2.000
1.500
^_
r^ ^ * 
3 SCO

3.000
,.*
J.ooo
1 ft>
         960      1.000      1.0*0      1.080      t.tio      1.160      .X      1.140      t.WO      i.3      '.iW      1.4OO
                                                            risr 7iMi. hou*t
             I  6,*6  I  WJ I  WB  I  6^ i  t'10  t 6,'n I  fe'U 1  t'*3 I  6/M I 6lb 1 6.16 I  6 >7 t 6/118 1  &')9  I 6-'7O t &-?l  I 6.7? 1  b ;j  1 &?
                                                            CALENDAR DAY
I'll ''
1 i 8~ ...
Ill ,,
:il I

j|l .0
il =
16000
| IS, WO
^ 14.000
13000
cc
o
3 11,000
^ 1Q.OOQ
~ s.cco
m BODO
S
 7.000
x 6-
o 5.0
I 'KX>
2 '.i00
S 1.000
o



-
-^^*^ *~^^  -^-- *  -^^-^^-- "^*^v-^ .___ ^..^_ __^  -\ _ ^ -
-
>^\ ^\ r\ r\
\ x^X ^ -A -^ \l \ J ' x^-/ ' "" "*" ^"
^x/^ % / V^V" ^' 	 i
  \^/ [NJ puct ovtit
L OVER tur J
'O CALCIUM (0 *) A CHLORIDE ICI-)  IESS THAN WO rt ARE NOT PlOrTl 0
  *

* * *

-
.
A
- A * * A* A* * *  A
* AA A* AAAAAA^
*
00^  0^><> o 00
O O4-' D O ^ 0
_ n G 0 fj
_oaODQDulJa n n o D D g
i i i . i i i t . i i
SO 1.000 1.0*0 1.080 l,l 1.160 1.300 l.2 1.3 1.JJO t.3so 1,400 1.4
TEST TIME, howt
1 8/6 1 6/1 1 6/8 1 8/9 | 0/10 1 &/1t 1 0/12 1 6/13 1 4M4 1 *"5 1 U1B 1 &/17 1 6^18 t 6/19 1 6/IO 1 6.T1 1 &/?2 1 6/73 1 &/?4 I
i J
1 ?
1 1
t,0
30
20
10

0
15.000
14.000
13.000
11.000
W.OOO
9.000
8.000

7,000
6.000
S.OOO
4.000
3.000
7.000
1.000

40


                    Gas Raic= 25.000 fm@ 330 F
                    Liquor Rate to Venturt B minimum (100 gpm)
                    Liquor Rate to Spray Tower = 1200 gpm
                    Venlim V/G  & gal/met
                    Spray Tower L/C  BOgal/mcf
                    Spray Tower Gai  Velocity  6.7 fi/rtc
                    No. ol Spray Headetj = 4
                    EHT (Sealed with  N, Purge) Residence
                        Time =  17 rn'in
Percent Solidt RedrCulated = 7.&-9.0wt*i
Venturi flu,; Position 1QQ% Open
Total Pressure Drop, Excluding Demiiter = 3.3-3.8 in
SciubbeilnM Liquor Temptraiuie - ;26-l32F
Liquid Conduciivity = 10.000-24.000 u  mhoi/cm
Discharge (Clarifier and  Filter) Solidj
    Concentration = 50-60 wl %
Lime addition to Scrubber Downcomer
Figure  8.    Operating  data  for  Venturi/Spray  Tower Run 604-1A
                                                           286

-------
4.1.1    Venturi/Spray Tower Run 601-1A


On October 9,  1973, the initial long-term reliability test (Kun bUl-I

was begun on the venturi/spray tower system.   The major test condi

tions  selected were (see Table 3):
         Spray Tower Gas  Velocity               6.7 ft/sec
         Venturi Liquid-to-Gas Ratio            30  gal/mcf
         Spray Tower Liquid-to-Gas Ratio       60  gal/mcf
         Percent Solids Recircxilated             8
         Effluent Residence Time                12  min.
         Scrubber  Inlet Slurry pH (controlled)    8
The  pH control level for the scrubber inlet slurry was chc-;en based

on results of lime testing at the EPA pilot facility in Research Triangle

Park,  which indicated  reasonable lime utilization and SO2 removal at

that  level.


During the entire test, the chevron mist eliminator  was washed  on the

underside both continuously (at a rate of 0. 8 gpm/ft  ) and intermittently

(at a rate of 1  gpm/ft ) with the available raw water makeup plus

clarified  liquor.  Also, the mist eliminator was washed on the topside

once per  week with  fresh water for 5 minute durations during  the last

four weeks  of the test.


Throughout the initial 666 hour portion of the run the clarifier was used

as the  final dewatering device and the average percent solids discharged
 Twelve minutes was the  minimum  residence time obtainable in the
 effluent hold tank for this run.
                                287

-------
was 23 percent,  which resulted in slightly open liquor loop operation.
An inspection after 666 hours on November 7 showed  that the mist
eliminator bottom vanes were clean while the top vanes were about 5
percent plugged with soft solids.   The scrubbers were generally clean,
with only a  thin layer of scale (20  mils) on the upper half of the spray
tower.

In order to  operate under  closed liquor loop conditions,  the test was
continued with the clarifier plus vacuum rotary drum filter  (or  centrifuge)
in series.   Problems with the filter cloth and mechanical difficulties
with the  centrifuge,  however, resulted in intermittent operation of these
pieces of equipment from November 7 to  December 15.  For the final
575 hours of testing (from December 15 through January 8), the filter
operated satisfactorily and the average percent solids discharged
increased from 23 to 47 percent and the total dissolved solids increased
from about  6500 to 10, 500 ppm (see Table 4).

Run 601-1A was terminated after a total of 2153 hours (3 months) of
operation, due to rapidly increasing pressure drop across the mist
eliminator.   An inspection showed that the top of the mist eliminator
was covered with solids that  fell from the  duct-work above,  plugging
about 80  percent of the surface.  In addition,  about 1/8 to 1/2 inch
thick scale  formed in the middle and top vanes and about 5 percent of
the bottom (inlet) vanes contained  heavy (1/4 to 3/4 inch) scale.  It
is hypothesized that the heavy accumulation of solids  in the outlet duct
occurred when slurry droplet entrainment through the chevron mist
eliminator wetted the duct walls during frequent reheater flame-outs.
 The venturi/spray tower system clarifier is undersized.
                               288

-------
Heavy scale had accumulated on the wall of the ypray tower below the



bottom header while  the middle section of the vessel was only slightly



scaled.  The venturi wall above the throat was clean, but scattered



scale covered the plug.  A  light scale covered the venturi wall between



the throat and flooded elbow and the entire flooded elbow was covered



with heavy scale.   Also,  the recirculating piping  was scaled, with



heaviest scale deposits in the pump suction areas.  Scale also formed



on the impeller eyes and tips of all the recirculating slurry pumps and



on the lining of the casing of some  of the pumps.  It  should be noted that



scale formation in the scrubbers,  circulating slxirry piping and  pumps



did not prevent continual operation of the system  or  necessitate termina-



tion of the run.







The formation of most of the scale on the scrubber walls and piping



occurred between December 15 and January 8,  when the system was



operating under closed liquor loop  conditions.   The calculated average



sulfate saturation of the scrubber  inlet liquor during this period was



180 percent.  This is contrasted with a calculated sulfate saturation of



150 percent for the initial 666 hours  of testing, during open liquor  loop



operation (see Table 4).







An analysis of the  test during the final 575 hours  of closed liquor loop



operation shows that the  calculated inlet  liquor sulfate saturations



are strong functions  of inlet gas SC>2 concentration (or SC>2 absorption



rate).  For example,  during test  periods where the inlet gas SC>2 con-



centrations averaged 3200 and 2500 pprn,  the calculated  sulfate  satura-



tions averaged 225 and 140 percent,  respectively.
                                289

-------
4.1.2    Venturi/Spray Tower Rvin 602-1A








In preparation for the  second lime reliability run, the system was



partially cleaned chemically (Na2 CO ^ /suga r /limestone/fly ash solution),



followed by mechanical cleaning.  All the stainless steel  spray nozzles



were replaced with identical,  full  cone,  stellite-tipped Bete nozzles



(ST 48-FCN)  and the original Hauck reheater, which was troublesome



throughout the previous run,  was replaced  with an external combustion



reheater (by Bloom Engineering Co. ).








Results  from the EPA pilot facility in Research Triangle Park had



indicated that sealing the effluent hold tank could reduce the sulfite



oxidation and, thereby,  the degree of sulfate saturation of the scrubbing



slurry.  In an attempt to duplicate this  mode of operation,  the  effluent



hold tank on the venturi/spray tower system was sealed prior to the



start of Run 602-1A.








Run 602-1A was started on March 15,  1974.  The mist eliminator



was washed  on the underside with the available raw water makeup and



clarified liquor  (in an approximate one  to  seven ratio) at  a  rate of 1



gpm/fl , in an intermittent operation (4 minutes  on/1  minute off cycle).








After  393 operating hours the run was terminated, when it  became



apparent that sealing the effluent hold tank in this facility was not



effective in reducing  the degree of sulfate saturation of the scrubber



inlet liquor.  Although the sulfite  oxidation had dropped somewhat (from



about  20 to 17 percent), the calculated  sulfate saturation at the termina-



tion of the test was 190 percent.
                                290

-------
An inspection showed that a uniform (aboxit 1/8 inch) scale covered most



of the top and middle vanes of the mist  eliminator.  The bottom  vanes



were relatively clean.  The walls-of the spray tower were covered with



a thin scale.  The wall of the venturi below the plxig was generally clean



and no scale was  deposited  in the flooded elbow.








4.1.3    Venturi/Spray Tower Run 603-1A








Run  603-1A was started on April 2,  1974,  after the mist  eliminator was



cleaned.  The solids content of the  reci rcxilaling slurry was increased



from 8  to 15 percent in order  to reduce the degree  of scrubber liquor



sulfate  saturation.   The mist eliminator was washed on the underside



with the available raw water makexip  and clarified liquor  (in an approx-



imate one to four.ratio) at a  rate of 1 gpm/fl  ,  in an intermittent oper-



ation (1  1/2 minutes on/1 1/2  minutes off).








After 395 hours of operation the run was terminated.  dxie to increasing



pressure drop across (he mist eliminator  (from 0. 55 inches 1T2O at



the start of the run to 0.70 inches  IIoO).  The  mist eliminator had



50-70 mils  of scale  on the outlet edge and  soft  solids  along the inlet



edge of the  top  vanes.  The middle and  bottom  vanes had  light deposits



of scale and soft  solids.  The  venturi scrubber contained about the



same amount of scale as before the start of the run, while there ap-



peared  to be slightly less scale  on the spray tower  walls  and in  the



suction piping of  the slurry pumps.  The calcxilated sulfale saturation



of the scrubber inlet liquor was 135  percent.   This was a significant



drop from the prcvioxis run's value of 180  percent saturation at  8



percent solids  recircxilated.
                                291

-------
4.1.4   Venturi/Spray Tower Run 604-1A








In order to decrease the quantity of soft solids buildup on the mist



eliminator which had  caused termination of the previous test,  it was



decided to drop back the percent solids recirculated from  1 5 to 8 per-



cent for this run.  To  reduce the scrubber slurry sulfate saturation



from the  expected  level of 180 percent (see Run 601-1A) (1)  lime was



added to the scrubber  downcomer (vs. the effluent hold tank),  (2) the



cffruent hold tank was  purged (blanketed) with N2, and (3) the venturi



scrubber was used only for gas cooling (venturi plug 100 percent open



with 100 gpm liqxior flow  rate).








It was theorized that the addition of lime to the downcomer quickly



increases the pll of the scrubber outlet liquor,  thereby precipitating



calcium sulfite before the sulfite can be oxidized to  sulfale in the liquid



phase (the solubility of calcium sulfite is lower af higher pll).  As



mentioned previously, a reduction of liquor phase sulfite oxidation



resxilts in a reduction  in sulfate  saturation.  It was further theorized



that reducing the liquor flow to the venluri with a minimum flue gas



pressxire drop would minimize liquid atomization, oxygen  absorption



and, consequently, oxidation.








Run 604-1A was begun on April 26, 1974, after the mist eliminator was



cleaned.  The mist eliminator was washed on the underside  with the



available raw water makeup and clarified liquor (at  an approximate



one to seven ratio) at a. rate of 1 gpm/ft , in an intermittent operation



(3 1/2 minutes on/1 1/2 minutes off).  The  efflxient residence time was



increased to 17 minutes,  since this was the minimum time obtainable
                                292

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at the  reduced total liquor  rate of 1300 gpm (the venturi liquor rate had

been reduced from 600 to 100 gpm).


The run was terminated after 1828 on-stream hours due to (1) increas-

ing pressure drop across the mist eliminator  (from 0. 62 inches H->O

at start of run to 1. 75 inches t^O), and (2) gas flow control problems

caused by  solids accumulation on  the ID fan inlet  dampers. The top

of the  mist eliminator was 75 percent plugged with  150-200 pounds of

loose solids which had fallen from the outlet duct.  There was about

1/2 inch of scale on the top vanes  and 1/4 inch of scale on the bottom

vanes.  Up to 2 inches of solids had accumulated  in the outlet gas duct

and six of  the 14 damper blades were  covered with  1-2 inches of solids.


The sulfite oxidation averaged from about 14 percent with NT2 purge over

the efflxient hold tank to about 19 percent without N purge (from May 29

to June 5).   The  calculated average  sulfate saturation of the  scrubber

inlet liquor, however,  was 130 percent.  This was  a significant drop

from the saturation level of 180 percent during the  closed liqxior loop

portion of  Run 601-1A.


As in Run  601-1A, an analysis of  the data showed that the calculated

inlet liquor sulfate saturation was a strong function of the SO2 absorp-

tion rate.  For example, during test periods where the inlet gas
 Oxygen concentrations in the effluent hold tank in the  vicinity of the gas/
 liquid interface ranged from 15 to 20 percent, as compared with 21 per-
 cent for air.  This suggests that sealing the tank and  N purging were
 not effective in reducing oxygen absorption in the effluent hold tank.
                                293

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concentrations averaged 2700 and  2900 ppm, the calculated sulfate

saturations averaged 120 and 150 percent, respectively.




Operating  data for Run 604-1A,  from June 6 to June 24, 1974, has

been graphically presented in Figure 8.




4. 1. 5    Venturi/Spray Tower Run 605- 1A




Run 605-1A was  started on July 31,  1974, after the mist eliminator

was cleaned.  The scrubber inlet liquor pH \vas raised  from 8 to 9,

in order to observe the effect of pH  on  sulfate  saturation.  The mist

eliminator was washed intermittently with raw water makeup at a rate
             o
of 0.4 gpm/ft  on a 1 minute on/4 mirmte off cycle.  As before, lime

was added to the downcomer and the venturi liquor  rate was set at 100

gpm with the venturi plug  100 percent open.




An  inspection after 141 operating hours showed relatively heavy (up

to 150 mils) scale on the top mist  eliminator vanes and the run was

terminated.  As  with the previously observed  patterns, there was a

moderate buildup of scale on the middle vanes (50 mils) and only a

light dust film on the bottom vanes.  No additional scale had formed

in the  spray tower during  the run.  The calculated average  percent

sulfate saturation of the scrubber  inlet liquor  was 115 percent. This

can be compared with a level of 130 percent for Run 604-1 A,  which

had a controlled  scrubber inlet liquor pll of 8. 0 (see  Table 4).




4.1.6    Venturi/Spray Tower Run 606-1A




Run 606-1A was  started on Axigust 7,  1974,  after the mist eliminator

had been cleaned.   The objective of the run, which  was intended to be
                                 294

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of short duration, was to investigate  scale formation  on the mist elim-



inator vanes with continuous washing on the mist eliminator underside



with raw water at a rate of 0. 3 gpm/ft  .  This raw water rate (15 gpm)



is approximately three times the quantity normally used during closed



liquor loop  operation, and, therefore, the test was  made under open



liquor loop  conditions (about 21 percent solids discharged).  The scrub-



ber inlet liquor pH was reduced from 9 to 8 for this test.








The run was terminated after  170 on-stream  hours.  About 95 percent



of the  trailing (top) surface of the mist eliminator vanes was  covered



with 30-70 mils of scale.  As usual,  there was light soft solids accumula-



tion on the middle vanes and the bottom vanes were relatively  clean.   It



should be noted that the scale growth rate on  the top vanes (~50 mils/



\veek) was about  the same for this test as for all of the previous tests,



in which mixture of clarified liquor plus raw  water were used  for under-



side washing.








4.1.7   Venturi/Spray Tower Run 608-1A








Run 608-1A was  started on August 21,  1974,  after the mist eliminator



had been cleaned.  The main objective  of the  test was to investigate



scale formation on the mist eliminator vanes with intermittent under-



side washing at high pressure (nO psig), using the available raw water



makeup at a rate of 3  gpm/ft  for about 9 minutes every 4  hours.  Also,



the venturi  scrubber was put back in  service  (at  600 gpm and  9 inches



H^O pressure drop),  in order to  investigate the  effect of venturi operation



(Runs  608-1A vs. 604-1A) and lime addition in the downcomer (Runs



608-1A vs 601-1A) on scrubber liquor sulfate saturation.
                                295

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The  run was terminated after 610 hours of operation due to increasing



pressure  drop across the mist eliminator (from 0. 75 inches H2O at



start of run to 0. 95 inches l^O).  About 80 percent of the trailing



surface of the top vanes was  covered with scale,  averaging 88 mils



in thickness and resulting in  approximately 3 percent pluggage of the



free flow  area.   The middle and bottom vanes were, as usual, essen-



tially clean (3 mils of dust coverage).  Note that, the average scale



growth rate on the top vanes  for this test (24 mils/week) was essen-



tially half the average scale growth  of the previous four tests.








The  condition of the scale on the walls  of the spray tower remained



essentially unchanged,  but the spiral tips  of most of the spray nozzles



were covered with 1/4-1/2 inch scale (scale  "whiskers").








The  calculated average  sulfate saturation  of the scrubber inlet liquor




was  130 percent (see Table 4),  This is the same as the calculated



saturation for Run 604-1A and about 50 percent lower  than the calculated



saturation for Run 601-1A.  Therefore, it may be concluded that, for



these run conditions, venturi  operation has little effect on sulfate



saturation and the addition of lime to the  downcomer (vs.  lime to the



effluent hold tank) significantly reduces the sulfate  saturation of the



process slurry.








4.1.8  Venturi/Spray Tower Run 609- 1A








Run  609-1A was started  on September 20, 1974,  after the mist eliminator



had been  cleaned.  The  primary  objective of the test was  to  evaluate



the effect of topside mist eliminator washing on the formation of scale
                                 296

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on the top mist eliminator  vanes.   The entire underside of the mist

                     9
eliminator and a 14 ft  area on the topside was washed at high pres-


sure (60 psig)  with makeup water at a rate of 2. 7 gpm/ft  for the under-


side and 1. 0 gpm/ft^ for the topside  for about 8 minutes every 4 hours.


Only a small section of the topside was washed because it was felt that


liquid carryover from  top sprays could possibly cause  reheater over-


loading and fan problems.   Also the effluent residence time was in-


creased from  12 to 24  minutes, for this test, in order to determine


the effect of residence time on scrubber liquor sulfate saturation


(Run  609- 1A vs. 608-1A).




Run 609-1A was intended to be of short duration and was terminated


after  278 hours of operation.  The  lopside  spray had boon successfxil


in drastically reducing the scale buildup on the lop mist eliminator


vanes.  The washed area was essentially clean, with less than 1 mil


of solids accumulation, compared with an average  of 40 mils scale


buildup on  the  rest of the topside stir faces.




The calculated average sulfate saturation  of the scrubber inlet liquor


was 110 percent for the test (sec Table 4).  This value is about 20 per-


cent lower than the  calculated saturation for  Run (>08-1A.  If may be


concluded, therefore,  that the effect  of effluent residence lime on  sulfalc


saturation  is similar for lime systems as for limestone systems (see


Figure  6).
 These problems could be  reduced by a-sequential sectional wash of the

 topside of the mist eliminator or by using a  second mist eliminator

 downstream of the topside sprays.
                                297

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4.2   CONCLUSIONS








4.2. 1   Scrubber Internals Operability








The lime and limestone reliability tests have shown that  scrubber



internals can be  kept relatively free of scale if the sulfate (gypsum)



saturation  of the scrubber liquor is kept below about 135 percent.



As  with limestone, this can be accomplished \vith increased percent



solids recirculated (Run 603-1A vs.  601-1A) and/or with increased



effluent residence time (Run 609-1A vs. 608-1A).  Moreover, the



lime tests  have shown  that adding the lime to the scrubber downcomer



(which corresponds to  a small residence time tank in series with the



larger effluent hold tank) can substantially reduce the sulfate saturation



(Run 608-1A vs.  601-1A), allowing for operation at reduced percent



solids and/or effluent residence time.  Also, operating at higher



scrubber inlet liquor pH appears to reduce the scrubber liquor sulfate



saturation  (Run 605-1A vs. 604-1A).








The lime tests have also shown that the sulfate saturation of the  scrub-



ber inlet liquor is a strong function of the inlet gas SO;? concentration



(SO absorption  rate).   The data has  indicated that a 100 ppm  increase



in SO2 inlet concentration corresponds, roughly,  to a 13 percent in-



crease in sulfate saturation,  at the run conditions tested.








It should be noted that  the 28 full cone stellite-tipped Bete nozzles  in



the spray tower  have shown no signs  of measurable erosion after



approximately 4000 hours in slurry service.
                                 298

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4. 2. 2    Mist Eliminator Reliability








The most significant reliability problem encountered, to date,  during



the venturi/spray tower lime  reliability tests has been associated with



scaling and/or plugging of the topmost vanes of the chevron mist elim-



inator (see  Figures 1 and 3).








Runs  601-1A through 608-1A showed that, the  scale formation rate on



the top mist eliminator vanes (25-50 mils/week) was relatively unaf-



fected by the wash cycle,  wash  rate or quality (sulfate  saturation) of



the wash liquor.  Run 608-1A showed that intermittent  washing with



high pressure  (60 psig) raw water at a rate  of 3 gpm/ft  for 9 minutes



every 4 hours,  gave results that were at least as good  as results with



continuous washing with  relatively low pressure raw water at 0. 3 gpm/ft



(Run 606-1A).   Intermittent washing  can be  especially important if the



availability of raw water makeup is restricted (e. g. , at high percent



solids discharged and/or high pximp seal water  usage).








Run 609-1A showed that  intermittent topside and bottomside washing



with high pressure  raw water would most likely eliminate the scale



accumulation problem on the top vanes  of the  existing mist eliminator



(see Figure 3) and allow for long-term  reliability of the  system at the



run conditions tested (see Table 3).  However,  the problems caused



by  entrainment of topside wash  water will have  to be evaluated.








The reliability of the intermittent topside and bottomside washing with



raw water has been further substantiated in a recently completed 253



hour  test (Run 610-1A).  The  scrubber  and mist elimination systems
                                  299

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\vere not cleaned before the test.  After a total of 531 operating hours



(Runs 609-1A and nlO-lA),  the \vashed area of the  top mist eliininator



vanes was  still clean,  compared with, an average of 34 mils  scale buildup



on the rest of the topside  vane surfaces.








It is planned to test a sloped (cone-shaped) closed-vane  chevron mist



eliminator in the spray tower in the near future.   It is expected that



the  sloped  mist eliminator has better draining characteristics than a



horizontal  mist eliminator.
                                 300

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                            Section S





           PARTICULATE REMOVAL TEST RESULTS








The  overall particxilate removal efficiencies measured during the



reliability testing on the TCA and venturi/spray tower systems  are



shown in Tables 5 and 6,  respectively.  For these tests, a modified



EPA particulate train  (manxifactxired by Aerotherm/Acurex Corporation)



was  used to measure  mass loading at the  scrubber inlets and outlets.



As can be  seen from the tables,  the measured removal efficiencies



are all greater than 99 percent for the tests conducted.








In May 1973,  the EPA measured overall parliculate removal efficiency



and particulate removal  efficiency as a function of particle size for



the Shawnee TCA scrubber during limestone reliability verification



testing (see Section 3. 3 in Reference  2).  The EPA measurements



for overall efficiencies are  in  good agreement with the results shown



in Table 5.  The mass mean diameter of the inlet solids, as determined



by EPA, was approximately  23 microns.








The  particxilate removal efficiencies  shown in Tables  5 and 6 appear



to be higher than the efficiencies  predicted  from "impaction theory. "



These improved efficiencies could be due  to condensation of water



vapor  in the flue gas on the  solid  particles.  In  order  to verify the
                                301

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                                             Table 5

                 OVERALL PARTICULATE REMOVAL IN TCA SCRUBBER FOR
                               LIMESTONE RELIABILITY TESTS
Run No.
531-ZA
531-2A
532-2A
535-2A
Date
5/15
6/12
7/24
9/25
Gas
Rate,
acfm @ 300F
20, 500
20, 500
20, 500
20. 500
Liquor
Rate,
gpm
1200
1200
1700
1200
Pressure
Drop,(a)
in. H2O
6.7
10.0
6. 7
6. 2
Grain Loading,
grains /scf
Inlet
2.82
3.47
3. 33
2.88
Outlet
0.029
0. 010
0.024
0.016(b)
Percent
Removal
99.0
99.7
99.3
99.4
(a}  Including mist eliminator and Koch tray.

(b)  Outlet sample taken on 9/27,  two days after inlet sample.

-------
                                                          Table 6


                          OVERALL PARTICULATE REMOVAL IN VENTURI/SPRAY TOWER

                                             FOR  LIME RELIABILITY TESTS
Run No.
Date
Gas
Rate,
acfm @ 330F
Liquor Rate,
gPm
Venturi | Spray Tower
Pressure Drop,
in. H2O
Venturi
604-1A 6/26 25,000 100 1200 1.9
608-1A 9/11 25,000 600 1200 9.0
610-1A 10/10 25,000 600 1200 9.0
Spray Tower
Grain Loading,
grains/ scf
Inlet
3.0 2.52
2.2 2.28
3.2 2.72
Outlet
Percent
Removal
0.024 99.1
0.023 99.0
0.021 99.2
CO
o
00
           (a)  Including mist eliminator.

-------
partirulate  removal results obtained,  to  date, and identify the causes



for the observed removals, EPA has planned a new  test series for the



determination of size  and overall  removal efficiencies in the TCA



and venturi /spray tower systems.  The test series is to be conducted



by an independent party in the near future.
                               304

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                            Section  6





                         REFERENCES








1.  Bechtel Corporation,  EPA Alkali Scrubbing Test Facility: Phase II



   and III Final Report,  EPA  Report,  December 1974 (to be issued).





2.  Bechtel Corporation,  EPA Alkali Scrubbing Test Facility: Limestone



   Wet Scrubbing Test Results. EPA Rcporl  650/2-74-010,  January 1974.





3.  Bechtel Corporation,  EPA Alkali Scrubbing Test Facility: Sodium



   Carbonate and Limestone Test Results, EPA Report 650/2-73-013,



   August  1973.





4.  Bechtel Corporation,  Test Manual  for Advanced Test Program,



   EPA Report,  September 1974.





5.  P. S. Lowell,  "Use of Chemical  Analysis and Solution  Equilibria



   in Predicting Sulfate/Sulfite Scaling Potential,- presented at



   Second International Lime/Limestone Wet Scrubbing Symposium,



   New Orleans,  Louisiana,  November 8-12,  1971.





6.  R. H.  Borgwardt,  "EPA/RTP  Pilot Studies Related to  Unsaturated



   Operation  of Lime  and Limestone Scrubbers,"  presented at Symposium



   on Flue Gas Desulfurization, Atlanta, Georgia, November  4-7,  1974.





7.  Radian Corporation, A Theoretical Description of the Limestone-




   Injection Wet Scrubbing Process, NAPCA (APTIC No.  22709 and



   25446) Report, June 9,  1970.
                               305

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306

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OPERATIONAL STATUS AND PERFORMANCE




                OF THE




   ARIZONA  PUBLIC SERVICE COMPANY




   FLUE GAS  DESULFURIZATION SYSTEM




        AT THE  CHOLLA  STATION
                   By




            Lyman K.  Mundth




     Arizona Public Service  Company









            November 4,  1974
                   307

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308

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              OPERATIONAL STATUS AND PERFORMANCE
                               OF THE
                 ARIZONA PUBLIC SERVICE  COMPANY
                 FLUE GAS DESULFURIZATLON SYSTEM
                      AT  THE CHOLLA STATION
       My name is  Lyman  Mundth and I  am Vice President of Power
Production and Operations for Arizona  Public Service Company.   My
discussion will  cover our experiences  with wet  scrubber  systems at
our Cholla Power  Plant near Joseph  City,  Arizona.   The Cholla Plant
currently  has  a  single  coal  fired unit  rated at 115  MW which has been
operating  since  1962.  The  unit burns  coal from  the Gallup,  N.M.
area and  this  coal contains approximately 10 percent ash  and .5 per-
cent sulfur.

       We operate this unit base  loaded and have  historically had
trouble  free operation,  with a capacity factor of  near  90  percent.  The
original capital  cost of the  installation  in  1962  was approximately  $20
million.   Mechanical collectors designed  to remove 80 percent of  the
fly  ash  provided the emissions abatement on  that installation.   We
recently retrofitted the unit  with  a Research-Cottrell sulfur dioxide/fly
ash removal process and a by-pass  system at a  capital cost of $6.3
million.

       Construction of the Research-Cottrell system was  completed in
December, 1973,  one year behind the  scheduled  date  of  December  3,
1972.   The system,  consisting of two  parallel gas  cleaning trains,
began commercial operation  in  mid-December,  1973, and  has operated
to the present with  only short  outages.   Each gas  cleaning  train con-
sists  of a Flooded Disc  Scrubber, a wetted film  absorber,  mist  elimi-
nators,  and reheater.  The limestone  and fly ash slurry handling systems
are common to both trains.

       For those  of you  who picked up  a copy of my  talk , you  will
notice that Figure 1  illustrates a  single  train flow  diagram.   Flue gas
containing SO2  and  remaining fly  ash  flows from the outlet of the
mechanical collectors to the  inlet of the wet scrubber system.   A forced
draft  booster  fan  forces  the gas into the flooded disc  scrubber where
the fly  ash and a portion of the  SO2  are  removed by a recirculating
limestone/fly  ash slurry.   This  slurry  enters  into the  flooded disc
scrubber tangentially above  the  throat  and  at the disc.  Particulate
                                 309

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                                  CHOLLA  UNIT   1   WET   SCRUBBER  SYSTEM
LO
t-*
O
                          TO
                          ASH DISPOSAL
                          POND
                                                                                   SECONDARY
                                                                                   MIST ELIMINATOR
                                             FDS SLURRY TANK
                                                                    ABSORBER TOWER
                                                                      FEED TANK

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emissions  have been tested and have  been found to average 0.026
pounds  per million BTU ,  well within  state and  federal emissions
regulations.

       About  70  to 85  percent  of the  sulfur  dioxide  passes through
the flooded disc scrubber into  a  cyclonic  mist  eliminator where the
captured ash  and entrained slurry are  removed.  The flue gas  then
passes  into a  packed tower which has 2 to  5 feet of Munters  packing,
a wetted film packing.  A  limestone  slurry recirculates through the
absorber packing and absorbers SC>2.  The flue gas  and slurry are
contacted countercurrently.   To minimize scaling,  a  high liquid togas
ratio and  a moderate reaction products concentration are maintained.
Total SC>2  removal  in the train containing  packing  is expected  to  be
around 80  percent.   However,  no  comprehensive tests on SC>2  removal
have been  conducted to verify  this removal level.

       At this point,  I should  explain that,  due to  the uncertainties
involved in SO2  scrubbers, only  one  of the  trains  actually  contains
packing material.

       A two-stage mist  eliminator follows the  absorber.   The first
stage is an impingement  vane type which  is  flushed intermittently with
water to avoid both supersaturation and encrustation on the surfaces.
The  second stage is  also an impingement  vane  type.

       Before entering  the  stack  a  steam coil reheater constructed of
316  stainless steel heats  the cleaned flue gas  approximately  40  F.

       The  slurry handling  system consists of a limestone storage silo
and absorbtion tower slurry,  flooded disc  and limestone  mix tanks.

       The  system is not  equipped with any  special sludge and fly ash
disposal equipment.  Sludge  and  fly ash are  pumped via temporary surge
tanks to pre-existing ash  disposal  ponds.  However, we  do have plans
to provide  sludge disposal  capacity for  this  system  in the new units
currently under construction at  the  plant.

       Although APS  has  operated the  scrubbers since completion  of
construction in December of  1973,  many startup problems have prevented
us from final  acceptance of these units.   We had  scheduled acceptance
tests in February of  1974.   We have not run these tests  due to  mod-
ifications  required  on the  system.  Some modifications  have been rela-
tively minor while  others have  required  unit  outages to accomplish.  We
expect acceptance  tests to be completed before the  end  of  1974.
                                311

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       Major problems encountered to date can  be classified into three
categories.   They are scaling and plugging, corrosion and mechanical.
We have found  scaling in the scrubber vessel,  in piping and in the
mist eliminator.   Plugging occurs  in the nozzles to  the  flooded disc
and the mist eliminator.   Corrosion  has been  experienced in  the re-
heater and breeching expansion joints.  We have encountered mechani-
cal problems in the flooded  disc control system, by-pass damper and
the reheater.

       I would  like to discuss  some of these  problems briefly.  First,
let's  consider our mechanical problems. On initial startup  of the unit,
vibration in the reheat sections limited operation of the scrubbers  to
such  an  extent  that commercial  operation had  to  be  delayed until a
solution  could  be found.   Research-Cottrell  hired an outside  consul-
tant  to  look  at  the  vibration  problem and to determine a  solution.  The
installation  of  baffles was  recommended because Research-Cottrell's
consultant felt that  improper  flue gas distribution was causing the
vibration problem.   This  fix  initially appeared  to have  solved the
problem.  Recently, however, due to other fixes, mainly on  the leak-
ing by-pass  control dampers, vibration is  re-occurring  at full load,
but is reduced considerably  in frequency.   The  reheater vibration is
not considered to be a major problem at this time,  but we  are working
toward a final  solution.

       We have  also  had problems with the by-pass damper  operation.
The scrubber system is equipped with a by-pass system  so that the
boiler may continue to operate should any major  failures  occur in the
scrubber system.   Leakage due  to sluggish  operation and temperature
caused  distortions of  the by-pass dampers have reduced  the  effective-
ness  of the scrubber system.  Small amounts  of  untreated flue gas
pass  through the closed  damper and  by-pass the scrubber system.
Although I have previously  mentioned that  the  system has been tested
and found to control particulate to a level of  0.026 pounds per million
BTU ,  we are unable to consistently  achieve this level  due  to improper
operation of  the  by-pass  damper.  However, we  feel the scrubbers
themselves have been attaining  their designed  particulate removal effi-
ciency.

       Since the entire installation  was a retrofit, the  damper system
was  installed in the existing breeching well in  advance of  actual
scrubber operation.   Fly  ash build up occurred and  prolonged exposure
to high temperatures caused  excessive  expansion and distortion.  The
boiler had to be shut  down to trim,   clean and  align damper louvers.
This did not completely solve the problem.  Research-Cottrell then
reduced the pressure drop required in the  scrubber system in  order  to
                                312

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create a recirculating effect  such that  a  small amount of treated  flue
gas would actually flow backward through the damper  and thereby
eliminate leakage of untreated  flue gas.   Although  no prolonged oper-
ation  or testing has  occurred,  we hope this  solves  the problem.

       A  third mechanical problem involves  the  position control of
the flooded disc.   The Research-Cottrell  Flooded Disc Scrubber main-
tains  a constant pressure  drop  at all loads by controlling the position
of the flooded disc.   Some  minor problems were experienced in this
area.   Initially the  disc kept oscillating  between positions.  Build-
up around  the  disc shaft caused  binding  and improper operation.  There
was also a problem of control  points being  set  too  near  control limits.
Fortunately,  this particular problem was  easily  resolved  by  Research-
Cottrell.

       Other  mechanical problems which  bear mentioning  are leaks  in
the booster fan which have  been experienced due to improper welding
and erosion of pump  impellers  and  scrubber vessels.  Generally,
mechanical  problems  have been shakedown in nature and  have  not been
totally unexpected.

       Next I  would  like  to  cover corrosion  problems.  We  have  had
corrosion problems in the  reheater due  to condensation in the  duct
work  leading  to the reheater.  Initially the  duct work was uninsulated
and in cold weather  acid  condensation  occurred.  The acid  run-off
caused necking of  tubes at  the reheater  sheet and  subsequently tubes
have  failed.   In order to  solve the problem, Research-Cottrell  has
insulated the  breeching to minimize  or  eliminate the condensation.  We
are not sure at this  point whether this has  solved  the problem  because
no cold weather  has  been experienced  since  the insulating  job.

       We have observed  pitting in  other tube areas,  however, we do
not know whether this is  due to  the  manufacturing  process  or  to  chem-
ical attack.   Only one small leak has  been  observed  other  than  those
clue to acid run-off  and its  cause is  unknown.

       Because of  the condensation  in  the breeching,  failures have
also been  experienced in  the expansion joints.   We have just  recently
replaced all  of the metal  expansion  joints with  a rubberized fabric
type.   Very little operating  experience  is available  with  the new  joints.

       Other corrosion problems which  have  occurred have been due to
improper application  of protective coatings and were easily  repaired.
                                313

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       It is  our  belief that  plugging  in parts of the scrubber system
has occurred due to  excessive scaling  caused either by settling or
high concentration of solids.  Chemical control  on the system has
been good.

       Material  has  accumulated and partially plugged  the  first  stage
demister, but this material has  been soft  and easily removed by wash-
ing with high pressure water.  No  adverse operating effects  have been
seem  due to excessive plugging, however,  Research-Cottrell has re-
designed  the demister wash  system  for better coverage and frequency
of washing.   It  now appears from a  short operating  experience  that
only minimal buildup occurs.

       Piping has  scaled in  the tangential  nozzle  area of  the flooded
disc scrubber which  in turn  has caused  nozzles to plug.   The nozzles
are designed in  such a way  that they can be cleaned while the  system
is in  operation.   The plugging is due mainly to settling out of solids
in the  piping  to  the  nozzles  and the formation  of  a  scale  olug.  Re-
search-Cottrell has re-designed  this  system with increased velocities,
however,  the  problem has not been  totally  eliminated.

       Problems  in most  cf  the  areas discussed appear to  be those
which will be experienced in  most  scrubber systems .   These will un-
doubtedly require a good maintenance effort.

       Scrubbers  appear  to require  a great  deal  more maintenance than
other  equipment  in general  use by utilities.  We expect that we will
have additional  maintenance  on  nozzles,  scale  removal, valve wear,
pump  packing and impellers  and process lines.   Although the system
shakedown is continuing, a  tremendous effort has  already  been  put
forth by  both  APS and Research-Cottrell  during  the time that the scrub-
bers have been  in operation.  We hope  that  the same type of effort
will not  be  required  in normal operation.

       We have  tried to  separate the shakedown effort from the main-
tenance effort in  order to project our maintenance  requirements for the
scrubbers.  Again, for those of  you who  have copies,  Figure 2 illus-
trates manhour requirements  for  experienced  scrubber maintenance.   The
average daily manhour requirement through August  of this  year has been
about 30  hours.   This constitutes 37 1/2 percent  of the available
maintenance  manpower at this plant.  We  expect that  it will be neces-
sary to  increase  our maintenance force  by approximately 50 percent to
avoid sacrificing  other routine and preventive plant maintenance  pro-
grams and total  unit  reliability.
                                314

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         CHOUA UNIT 1  - SCRUBBER MAINTENANCE
                       Figure 2
JAN      FEB     MAR     APR      MAY    JUN     JUL      AUG
                    315

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       In addition,  one auxiliary operator per shift is required  for
scrubber operation.  Auxiliaries for the scrubbers include 2.8 MW for
electricity and 18,000  pounds per hour of steam for reheat.   Limestone
is consumed at  the  rate of 15 tons per- day.  As indicated previously
the system  currently does not include waste  disposal.

       Table  1 is a summary of operating costs for the  scrubber  at
the bus bar.  Based on these costs and  on  our 1973  operating  costs,
it  is estimated that the scrubber will  add approximately 15.9 percent
to the  cost at the bus  bar.

                              TABLE  1

                CHOLLA SCRUBBER OPERATING COSTS
                	(ESTIMATED)	

                                                  Mills/KWH

       Auxiliaries (Steam and  Electrical)              0.2
       Operating Labor                               0.09
       Maintenance Labor                            0.09
       Parts and Materials                           0.07
       Limestone                                     0.15

       TOTAL                                        0.6 mills/KWH

       Total Cost 1973  FPC Form  1                   3.78 millsAWH

       With regard  to system  availability,  scrubber A which contains
packing in  the absorber tower has operated for a total of 4,778  hours
vs a possible 5,064 hours.   Scrubber B has  operated a  total of 4,401
hours vs  a  possible 5,064  hours.   These numbers do not accurately
represent  the scrubber  availability since  a great deal of time has been
spent in resolving the  problem areas  in order to minimize down time.
During times when leaks have occurred in the reheater or nozzles have
plugged,  the  unit  continued to operate so that  individual items  of
equipment  are not necessarily represented by the above  figures.   No
hard availability  data  has been kept and  it is unfair  to  suggest  that
one time  malfunctions which have been corrected by design  changes
be included in any assessment of true system availability  in the  future.

       While the  scrubbing  system at Cholla appears to be  successful,
it  does not necessarily  reflect the  experiences of  others on  large util-
ity boilers.  On  very  large  boilers, solutions which have worked at
Cholla may not work due to increased  size and  numbers of  scrubbers.
It  is our  belief  that improvements must be made in the future and pos-
sibly new  approaches  of dealing with  sulfur must be  developed  and
                               316

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tried  in order to successfully handle variations  in  size,  fuel types
and environmental constraints.

       In summary,  we feel  the  system will  ultimately work.   How-
ever,  new developments  arc  needed.  The  systems must  be improved
both mechanically and  chemically.   Disposal of wastes from existing
throw-away systems is a  serious problem  not yot  solved.  Hopefully,
technology will  find a  way to utilize or eliminate these wastes.
Technology  should be  given adequate time  to provide the  solutions at
a realistic cost in terms of dollars  and reliability  of generation.
                                 317

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 Wet Scrubber Operating  Experience
                   at
     La Cygne Station Unit No.  1

Kansas City Power & Light Company
   Kansas  Gas & Electric Company
               By C.F. McDaniel
            Kansas City Power & Light Co.
              Kansas City, Missouri
                 Presented at
        EPA Flue Gas Desulfurization Symposium
              Sheraton-Biltmore Hotel
                Atlanta, Georgia
               November 4-7, 1974
                    319

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320

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Description
La Cygne Unit No. 1 is a  new generating station
located about 55 miles south of downtown Kansas
City  and east of La Cygne, Kansas, figure 1. The
plant is jointly  owned  by Kansas  City  Power &
Light and  Kansas Gas  & Electric Company. The
plant is  manned  by  KCP&L  employees,  with
output shared equally  by the two companies.

Site  construction was started in  April, 1969, with
erection  of  the  Air  Quality   Control  System
initiated  in mid-1971.  Unit No. 1  was nearing
completion  when the  boiler was  first  fired  on
December  26,  1972,  and  construction was
considered  complete  when the unit was declared
commercial on June 1. 1973.

An  earth fill  dam  almost  7,000  feet  long was
constructed to form a 2,600 acre lake for cooling.
Fly ash and spent  slurry from  the scrubber  are
contained in a 160 acre settling pond located east
of the cooling water lake.

Coal is delivered  to  the mine-mouth plant with
off-the-road  120-ton  trucks from  a strip  mine
operated by  Pittsburg & Midway Coal Company.
Run  of mine si/.e coal, 30 in. x 0 is conveyed from
the receiving hoppers  at a rate of  2,000 tph to two
rotary  breakers and reduced to 3  in. x 0  size. The
fuel  is a low grade bituminous  coal that has an
as-fired  heating  value  of  9.000-10.000 Btu/lb,
20-30  percent ash, and up  to 6  percent sulphur.
The  coal  continues  on  to be  stacked in  the
storage area   with  the stacker-reclaimer,  or  a
maximum  of  1200 tph  may be bypassed to  the
secondary crushers.

Limestone  is obtained from nearby  quarries  where
the rock  is reduced to 3/4 in. x 0. It is delivered to
the  plant  in  50-ton off-the-road  trucks and is
stacked  and  conveyed  with the  coal  handling
equipment.

The   boiler  is  a  cyclone-fired,  supercritical,
once-through, balanced draft Babcock  & Wilcox
boiler.  Its rating is 6,200,000 pounds of steam per
hour, 1,010 F, 3,825 psig  at the superheat  outlet
and 1,010 F at the reheater outlet.

The   turbine-generator  was  supplied  by
Westinghouse and is rated at 870 MW gross output
with 5 percent overpressure.
The air quality system,  shown schematically in
Figure 2 was supplied by Babcock  &. Wilcox, and
consists   of  seven,  one-seventh  capacity
venturi-absorber scrubber  modules,  designed  to
handle  the entire  flue  gas  flow  of  2,370,000
ACFM,  (Figure  3)

Each  scrubber module consists of a variable-throat
venturi  followed by  a  two-stage countercurrent
tray  absorber,  with  the  wetted parts  fabricated
from  316L  stainless steel.  Seven rubber lined,
7,750-GPM venturi  recirculation pumps and seven
10,300-GPM  absorber  recirculation  pumps
recirculate  a flyash-limestone  slurry in the system.

The original plant design called for only  one of the
seven scrubber modules to be supplied with  two
stages  of absorber  internals  and  absorber
recirculation pumps.

Flue  gas leaving the scrubber modules is reheated
25  F with a bare-tube steam  coil reheater  and
discharged  to a 700-foot stack  by  six one-sixth
capacity induced draft fans which draft both  the
boiler and scrubber system.

Limestone  rock. 3/4 in. x 0 pulverized to a fineness
of  95 percent  minus 200 mesh in two 100 tph
Koppers wet ball mills.

The auxiliary power requirements for the AQC
system, 28 .MW, are about the same as the normal
auxiliaries  for  the   plant.   22  MW,  The total
auxiliaries  result in  a design plant net electrical
output of 820 MW.

Startup and Operation

The scrubber system was initially placed in service
on  December 26, 1972, using two venturi scrubber
modules during initial  firing of the boiler.  The
turbine  was  rolled  on January 25,  1973,  and
synchronized on February 23, 1973. A total of 1(5
days  of   operation  was  obtained  with  the
boiler-scrubber during the first 3-month startup
period.  Sustained unit load was not obtained until
the month of April, 1973. The  unit was declared
commercial on June 1,  1973, only 4 weeks after
the scheduled  commercial  date, and a peak load of
832 MW obtained  on June  2, 1973. During this
initial trial operating  period,  many problems were
                                              321

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encountered with the plant, most of which would
not be  considered abnormal when starting up an
entire  new  power  plant facility  the size of La
Cygne.  These problems involved  auxiliary boiler
casing  leaks, boiler  tube leaks,  furnace  slag tap
freeze-ups,  generator  balancing,  control  system
problems, coal bunker difficulties, and auxiliary
transformer problems.

Scrubber  system  problems during  the  startup
period involved mainly completing the contruction
of scrubber  modules and the instrumentation and
controls.

One of the  major operating problems has been
associated  with  the  induced  draft  fans being
designed too close to  their critical speed, which
resulted in high fan  vibrations created by buildup
of wet flyash deposits on the rotors. This condition
necessitated frequent fan washing and balancing of
the rotors. The fan rotors have all been rebuilt with
increases in  shaft diameter  and  blade thickness in
order to increase the critical speed. The problem of
wet flyash deposits on the fans is thought to be the
result of a number of conditions which exist in the
scrubber system. Some of these reasons are:

System scrubber chemistry has been very difficult
to control; that is maintaining the limestone  feed
slurry fineness, concentration and feed rate within
limits that do not produce scale. The reasons for
this control  problem will be explained later. When
operated  outside  normal  chemistry  limits,  the
scrubbers generate  large  quantities  of  calcium
sulfate  scale that  cause pluggage and  erosion of
venturi  spray nozzles.  Most  of the scrubber
modules have been operated with  only the venturi
recirculation circuits in service since start-up. The
nozzle pluggage condition has led to poor fly-ash
removal which has resulted in a rapid  buildup of
flyash  deposits on moisture separators, reheaters,
and ID fans. In addition to poor flyash removal,
these  periods of nozzle pluggage also  permit some
of  the sulfur  trioxide in  the  flue  gas  to  pass
through  the scrubber,  resulting  in  a condition
where the gas entering the induced  draft fans is
below the SO3  dew point, even after reheating the
flue gas 25 F. This condition results in  wet, acidic
(pH 1) flyash deposits on ID fan and  reheater
surfaces. This combination of flyash and  sulfuric
acid has eroded fan blades and caused failure of the
304 stainless steel reheaters.
A  test  program is  currently  under  way  to
determine the following:

    1.   Degree of flue gas reheating that will result
        in minimal deposits on the fans.
    2.   The   best  method  of  obtaining  the
        additional reheat.

In  the meantime, 75  degrees reheat has  been
temporarily provided by  taking secondary air at
495 F from  the air heater and  blending this with
flue gas leaving  the  scrubbers  to obtain a  200
degree  flue  gas  entering  the  fans.  This reheat
arrangement limits the unit load to approximately
650 MW.

"D" module  is the onJy module that is complete
with  both  venturi  and  absorber   recircuiation
circuits, two  stages of absorber trays and a water
wash  stage below  the moisture  separator. Testing
during  the past year indicates that dust  loadings
leaving this module are better by a fator of  two
than dust loadings obtained from the venturi-only
modules. The average of 37 tests on  "D" module
(table  I) show that the dust removal  performance
has been better than predicted.

Within the last few weeks,  one additional absorber
stage  and a water wash tray have been added to
"C" module and tests were conducted to verify its
performance.  The results of  11 dust tests show
better  performance than either the venturi alone or
the venturi and  one absorber stage configuration.
Additional absorber and water wash trays are being
installed in the other  modules as they  become
available for   revision.

The sulfur  dioxide removal  performance at  La
Cygne is dependent upon many factors:

(1) module  equipment  (2)  purity  of limestone
from  the  quarry and (3) operation of the milling
system. This  summary of SO2 performance (table
2}  show  from  75-83% SO2   removal has  been
obtained  from  "D"  module  when  the  above
conditions are close to expected.  Operation with
one absorber stage  has resulted in 50-74% SO;
removal, and with the venturi  only, we get 35-50%
percent efficiency.  (Table  2)

Proper  chemistry  control  is the most  important
factor required for the successful operation of the
                                               322

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La Cygne scrubber system. This control not only
includes  maintaining  recirculated  slurry  within
certain operating limits but also encompasses the
selection of raw limestone rock, reducing it to the
right fineness, and feeding the limestone slurry to
the scrubber at the right time.

The limestone and the coal at  La  Cygne are  both
mined  locally; both vary considerably in chemical
analysis;  and if  you don't obtain  the right type,
you are  going  to  have problems.  Unfortunately,
with both the coal and limestone, you don't know
you  have the wrong type until it gets into the
system. Figure 4 shows some recent  variations in
limestone purity since April of this year.

During  the period April-August, 1974,  we  went
through  a  period  of excellent  chemistry control,
seldom having to take  a module out of service due
to low pH. This period the limestone purity was
generally  greater  than  90 percent calcium
carbonate,  the magnesium carbonate concentration
was  less than  1.5 percent,  and the milled  feed
slurry  fineness in  the range of 4.5-6 microns. A
number of interesting observations were also made
during this operating period.:

    1.  The system pH was easily maintained at pH
       5.7-6.0  with  limestone feed  at 150-175
       percent of stoichimetric requirements.
    2.  Little scaling was observed in  the scrubber
       modules.
    .3.  The oxidation  rate  of calcium sulfite to
       sulfate was as low as 10-20 percent during
       some periods of operation.

During this operating period large hydrocyclones
were  put  in  service on  all the module venturi
recirctilation streams.  Prior  to this  time,  it was
almost  impossible  to  prevent   venturi   pump
recirculation  screens  from  plugging  with  scale.
These   were   replaced  with  low-pressure-drop
hydrocyclones designed to remove particles greater
than 50 mesh in size  from  the entire 5,500  GPM
venturi  recirculation  flow.  Oversize  material  is
discharged into  a grit screen located on top of the
recirculation tanks. This system has reduced nozzle
pluggage in the Venturis and has greatly decreased
erosion of valves and spray nozzles in the scrubber
system.

With four to six ID fans operating in  parallel from
the plenum common to the discharge of all seven
modules, some will assume all the  load and others
unload when the negative pressure reaches 42"-45"
H2 O. Unless lowered by the Control Operator this
will  lead  to  a  boiler  trip.  Individual  fan
characteristics  are  currently  being studied  to
correct this problem.

Present  procedures call for cleaning one module
each night on a rotational schedule and attempting
to keep all seven in service during the day. Washing
requires two to three men approximately ten hours
to complete,  including tagging and  opening  the
many sections.  The  predemisters  and  absorber
trays are  normally clean unless scaled over from
erratic  pH  control.  The  venturi  area usually
requires nozzle and wall wash cleaning which may
include dismantling up to 7 or 8 of the 80 nozzles.
The  common sump under the venturi and absorber
usually contains from 4 to 12 inches of hard sludge
formed  from flyash, carbonate, and sulphates and
often is like concrete to remove. We currently are
experimenting  with  this  "puddle"  to  see  if
removing the sump screens  will eliminate this fluid
level.

COSTS

The  operating expense for the first nine months of
1974 is as follows:

Operating labor       S 187,497  0.17 mils/kW
Operating materials   $  26,353  0.12mils/kW
Maintenance labor    $ 260,486  0.23 mils/kW
Maintenance material  S 456,567  0.42 mils/kW
Limestone            S 627,419  0.56 mils/kW
  TOTAL
Capital Costs

Total Unit
Total Scrubber
    $1,566,322   1.40 mils/kW
$195,000,000
$ 42,000,000
$238/kW
$ 51/kW
The problems discussed were some of the more
involved and time consuming that we confronted.
Many repairs and  some design changes have been
made to  the  scrubber  during the shutdown  for
first-year turbine inspection - February 15 to April
6.  These  changes  have given  us a  much  more
reliable  and  maintenance-free operation.  Startup
problems  are always expected, and we believe we
now  have the  experience to  maintain  reliable
operation,   while  contending  with any  other
problems that may appear.
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Improvements being considered for the system are:

1.   Addition of fan eighth module
2.   Additional forced draft fan
3.   Additional induced draft fan
4.   Separate conveyor system for limestone
5.   Different ball mill liners - manganese or rubber
    instead of nihard.
6.   Modernizing  certain  instrumentation  for
    reliability.  Add  instrumentation  to  the
    moisture content of reheat.
7.   With the remaining life of the 160 acre settling
    pond estimated at 1-1/2 years, evaluation will
    have to  be  made  for an  additional  lake,
    removing the contents to fill in a nearby quarry
    or coal  pits, or building the dams higher.
8.   Module Improvements:
    a.  New improved demister  installation
    b.  Additional absorber tray
    c.  New perforated predemister installation
    d.  Second demister tray installed in  addition
       to new tray
    e.  Re-evaluation  of reheat system  to include
       reheat  tubes and  heat from  an  external
       source such as  oil burners
    f.  Additional  wash  systems  to  eliminate
       periodic cleanings

Performance & Availability

The availability  of the  boiler-turbine has  been
increasing steadily, from 37% in January, to 60% in
May, to 83% in September.  This has consequently
put increased pressure on  continuous operation of
the scrubbers. There are  three demands  affecting
module  outages:  (1)   regular  cleaning  (2)
maintenance  requiring immediate attention,  and
(3) continuing modifications.  Often these  cannot
be  done  simultaneously  but  for  the  past  few
months module  availability has  been  100%;  7
modules have been  operating 20%, 6 modules 90%
and  5 modules 96% of  the  time  the  boiler  is
available. In all fairness to our past efficiency tests
it makes a tremendous difference in the cleanliness
of  the module, the solid control  through good
instrumentation and maintaining the unit without
imbalances.
                                              324

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U!
ro
Ul
     c
     S
                                La Cygne limestone wet scrubbing system

-------
Single scrubber module
        326
Figure 3

-------
                                 Particulate Performance

Module

A.B.C
C

D

No. of
tests
30
11

37


Outlet
dust
loadmp
Ib/IOOOlbgas
0.178
0-115

0.080
009!


Remarks

Ventun i 1 absorber stage
Venturi + 2 absorber swges +
wash water tray

Predicted performance equiva-
lent to EPA 0.1 Ib/MKB
                                                                  Trible  I
                                        i  Performance
Module
A
E
D
S02 ppm
inlet
4522
3970
4453
outlet
2710
1410
819
Removal
efficiency
%
40
64
82

Range of
SO-, removal
%
3540
50-74
7583
80
Remarks
Venturi
Ventun + 1 absorber stage
Veniori t 2 absorber stages
Predicted performance
                                                                               Table
         100 r-
   %      90
 CaC03
   %
 MgCO3
Average
particle
diameter
 micron
                  
                            Limestone analysis and fineness
                              
          

                          MAY
                                                     
                                                    JUNE
                                             327
                                                JULY

                                                 Figure 4

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   DUQUESNE LIGHT COMPANY
   PHILLIPS -POWER STATION
   LIME SCRUBBING FACILITY
              By
        Steve L. Pernick, Or
    Manager-Environmental Affairs
        Duquesne Light Company
       Pittsburgh, Pennsylvania
              and
        R. Gordon Knight
 Superintendent-Technical  Services
      Duquesne Light Company
     Pittsburgh, Pennsylvania
     Prepared for presentation
              at
EPA Flue Gas Desulfurization Symposium
        Atlanta, Georgia
       November 4-7, 1974
              329

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                       DUQUESNE LIGHT COMPANY
                       Phillips Power Station
                       Lime Scrubbing Facility
                              CONTENTS

                                                             Page
Introduction	331
Pilot Plant Operation 	332
Installation Schedule	333
Descri pti on of System	335
Initial Operation 	 338
Extended Shutdown for Repairs	,	340
Second Start-up Operation	343
Sludge Treatment and Disposal	345
Future Operating Plans	348
Aval 1 abi 1 ity and Rel iabi 11 ty	350
Capital and Operating Expenses	350
Future Objectives	351
                              330

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                           DUQUESNE LIGHT COMPANY
                           Phillips Power Station
                           Lime Scrubbing Facility
INTRODUCTION

          Duquesne Light Company is an investor-owned electric utility
serving approximately 1/2 million customers in southwestern Pennsyl-
vania including Pittsburgh.  The Company has a net generating capa-
bility of approximately 2700 MW and presently operates three coal
burning power stations, two of which, Phillips and Elrama, are dis-
cussed in this paper.

          In 1969, Gibbs & Hill, Inc.  was engaged to conduct a com-
prehensive study of the most feasible means of complying with:  the
emission regulations being promulgated at the time by Allegheny County,
which has control over the Phillips Station; the regulations of the
Commonwealth of Pennsylvania, which has jurisdiction over the Elrama
Station, and the most stringent regulations that could reasonably be
conceived.  The study was completed in September, 1970.   It repre-
sented a comprehensive evaluation of all  test data concerning emis-
sions from the two power stations and an intensive investigation of
all possible means of compliance with the applicable and anticipated
regulations.  The study concluded that:  (1) the use of low sulfur
western coal was not a feasible means of compliance since it would
not achieve compliance with the particulate emission limitations of
the regulations with the existing dust collection equipment; (2) that
conversion from coal to low sulfur oil was not feasible due to the
uncertainties of obtaining a sufficient supply of the necessary
large quantities of such oil; and (3) that the most practical means
of sulfur dioxide emission control  was desulfurization of stack
gases.  The consultants then conducted a thorough study of existing
methods of sulfur dioxide removal from stack gases.  At the time of
their investigation in 1969 to 1970, only two full scale stack gas
scrubbing systems were in operation in the United States.  One of
these has since been abandoned and the second has had a poor record
of operating reliability.  Furthermore, the injection of limestone
directly into the boiler, which was the basis of these SO? removal
processes, was not at all suitable for consideration at the Elrama
and Phillips Power Stations since it would result in additional
boiler tube erosion to which the boilers were already particularly
susceptible.  Furthermore, available data indicated that S02 removal
efficiency might not be sufficiently high to comply with the regu-
lations which were among the most stringent in the country.

          Because of the characteristics of our boilers  and our re-
quirements for a system that would remove both particulates and sul-
fur dioxide, the report concluded that a tail-end scrubbing system
was the best available means of control and recommended  that we in-
stall a dual stage venturi scrubbing system.  Some of the technical
                                 331

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reasons for choosing the system are as follows:

  1.  It was thought that a dual stage scrubbing system would enable
      separating the sludges resulting .from scrubbing for fly ash
      in the first stage and scrubbing for $62 in the second stage,
      in the event the sludge from the SC>2 removal stage became a
      problem.

  2.  A dual stage scrubber had the potential of being converted
      to a magnesium oxide regenerative system in the event it
      became desirable or practical to do so.

  3.  Venturi scrubbing for particulate removal was fairly well
      proven in the steel industry.  Furthermore, if only one
      of the scrubber trains was equipped with a dual stage S02
      prototype, and this was proved to be impractical or un-
      workable, vie would still have a workable single stage ven-
      turi scrubber system for particulate removal.  We could
      then investigate an alternate method of 502 removal with
      minimal loss of investment.

          In addition to the above reasons was the fact that preliminary
time schedules indicated that these scrubbers could be delivered with the
least delay.  Duquesne accepted the recommendations of Gibbs & Hill, and
in view of the unproven nature of the wet scrubbers for sulfur dioxide
removal, decided that the most prudent approach to the installation was
to begin by equipping only a portion of the scrubber system at the Phillips
Station with sulfur dioxide removal equipment.  Subsequently, Gibbs & Hill
was instructed in September, 1970, to proceed with the designing and in-
stallation of the Phillips scrubber system.  The scrubber installation
at this plant was to include four scrubber trains.  Three of these were
single stage scrubbers for dust removal, and one was a dual stage scrub-
ber (two single stages in series) which is the prototype for sulfur di-
oxide removal.  Each scrubber was to be capable of approximately 540,000
CFM, which is the equivalent of approximately 125 megawatts.  With the
station rated at 387 megawatts, this meant that the station would be
equipped with essentially a spare scrubber train.  This was a criterion
specified by Duquesne Light Company to assure sufficiently high avail-
ability of the system.

          It was anticipated that after a trial period, the operation of
the prototype would serve as a basis for decision as to the installation
of additional similar S02 removal equipment at this station and other
coal burning facilities to comply with the applicable regulations.

PILOT PLANT OPERATION

          In February,  1971, a pilot plant size Chemico venturi type,
dual stage scrubber system with a capacity of 1500 CFM was installed
at the Phillips Power Station to study the performance and operating
characteristics of the dual stage venturi scrubber system.  The pilot
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plant was connected to the duct entering the mechanical dust collector
of Mo. 5 boiler.  The scrubber was operated with various types of lime-
stone and lime.  In addition, other conditions such as the stoichiometry,
liquid to gas flow ratio and pressure drop were varied in order to deter-
mine the conditions which would yfeld optimum collection efficiency and
operating conditions.  After determination of these parameters in approxi-
mately 3 months of operation, the pilot scrubber was dismantled on May 8,
1971.

          In the meantime, in March, 1971, invitations to bid were issued
by Duquesne Light Company to Chemico and Combustion Engineering for a
scrubber system capable of removing sufficient SC^ and particulates to
comply with existing and anticipated future regulations.  The bid was
subsequently awarded to the Chemico Corporation in July, 1971.  The
battery limits for Chemico was limited to the scrubbers and associated
pumps and controls between the inlet hot gas duct manifold to the exit
wet gas header, including the reheater but excluding the new induced
draft fans.

          In obtaining approval of our plan, compliance programs were
negotiated with Allegheny County for the Phillips Station and with the
State for the Elrama Power Station.  The program included the instal-
lation of five single stage venturi scrubbing trains for particulate
removal only at the Elrama Station, to be installed concurrently with
the Phillips scrubber system as described above.  The plan was to use the
prototype sulfur dioxide removal installation at Phillips as a basis for
decisions concerning additional S02 removal equipment at both stations
in order to comply with SC>2 emission limitations.

INSTALLATION SCHEDULE

          Although in Duquesne's best judgment, the scrubber system could
not be made operational, even for particulate removal, prior to July 1,
1973, which was 34 months from the date of our decision to install a
scrubber system, Duquesne Light eventually acceded to pressure from the
State of Pennsylvania and established a target date of January 1, 1973.
Following startup, the schedule called for a two-month "debugging" period
followed by a ten-month test program on the prototype SO^ scrubber at
Phillips.  This would determine if stack gas scrubbing with alkaline in-
jection on a plant scale basis was a feasible and reliable means of re-
moving sulfur dioxide from the gases.  The plan was to study operating
conditions during this period to establish optimum S02 removal efficiency
using various types of lime, the operating mode most conducive to reliable
trouble-free operation, and other essential information.  The schedule
called for a decision to be made by January 1, 1974, as to whether or not
the operation of the prototype SO? scrubber was satisfactory or if an
alternate system should be investigated.  If the operation of the prototype
sulfur dioxide scrubber proved satisfactory, the schedule called for design,
procurement and installation of additional SO? removal equipment by January 1,
1975, for both stations.  At that time, compliance with County and State
regulations would be achieved.  (For a list of significant dates see Figure 5)
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          Despite our best efforts, no part of the Phillips scrubber
installation was placed in operation until July 9, 1973, and then for
only two boilers.  At that time, two of the scrubber trains were
placed in operation, and two of the six boilers were connected to the
scrubber system.  This was consistent with our startup schedule which
called for connecting one boiler at a time to the scrubber system so
as not to jeopardize the availability of a significant portion of the
plant's generating capability in the event of failure of the scrubber
system.  The two boilers connected have a combined steam generating
capability equivalent to approximately 80 megawatts.

          The July 9, 1973 startup date represents a slippage of approxi-
mately 6 months from the original schedule.  This slippage was attribut-
able to the following factors:

  1.  The venturi scrubber system was not a completely engineered
      system at the time it was purchased, and a considerable amount
      of developmental engineering was required to adapt the scrubbers
      to a system that would meet our requirements.   Chemico was al-
      so charged to incorporate, to the limits of their responsibility the
      latest available operating and maintenance experiences at the Four
      Corners Plant in New Mexico, the Dave Johnston Plant in Wyoming,
      Mitsui Plant in Japan, and any other Chemico installation having
      experiences adaptable to  our proposed installations.

  2.  Equipment suppliers and fabricators did not meet promised de-
      livery dates due to the volume of orders, decreased produc-
      tivity, and inadequate quality control.  Considerable money
      was spent to expedite and inspect equipment and materials for
      our project.  In spite of this effort and expense, many late
      deliveries and mistakes in fabrication occurred.  Some examples
      are as follows:

      a.  The induced draft fans were scheduled for delivery
          in Phillips by July 15, 1972.  Delivery was not
          completed until December 12, 1972, a delay of five
          months.  Not only were the fans late, but numerous
          cracks and defects in the welds on the fan rotors
          were found after delivery.  It was necessary to
          grind out all of the  defective welds and make the
          necessary repairs in  the field.

      b.  An approximate five-month delay was experienced in
          delivery of the ductwork.  In addition, because of
          the huge size and weight of the ductwork,  many
          structural support schemes had to be studied before
          an acceptable method  of reinforcing the existing
          station building to accept the unusual weight load
          of the ductwork could be determined.  After a rein-
          forcement plan 'was devised, errors were discovered
          in the implementation of the plan, requiring cor-
          rective design work.
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      c.  Delays of up to six months were experienced in the
          delivery of electrical equipment such as switch-
          gear and transformers.  In addition to the delay
          of equipment, errors were, found in the wiring dia-
          grams for this equipment.  Once the equipment was
          received, design errors were also discovered, such
          as improperly designed bus connections on the switch-
          gear and improper alignment of bus bars on power
          centers.  In addition, failures of switchgear and
          transformers were experienced during field testing.

      These are only a few examples of the numerous delays and errors
      by equipment suppliers which affected the final completion date
      of the first phase of the Phillips project.

  3.  Major delays were also incurred in the field, such as the follow-
      ing:

      a.  Because of engineering delays and late delivery of
          equipment, construction schedules had to be con-
          tinually revised which seriously affected pro-
          ductivity.

      b.  Space limitations existing at the job site, more
          serious than anticipated, affected productivity
          because of the lack of accessability and maneuver-
          ability.  Special equipment and construction methods
          for the installation of the equipment were required
          beyond those originally anticipated, thus contribu-
          ting to additional delays.

      c.  The availability of boiler outages for tie-in of the
          new ducts, presented additional problems.  Outages
          had to be scheduled months in advance, and any re-
          vision in schedule was dependent upon availability
          of purchased power and the outage schedules of
          other generating equipment, both on our system and
          on interconnections.

DESCRIPTION OF SYSTEM

          Design of both the Phillips and Elrama systems was a joint
effort by Gibbs & Hill and Chemico, each having certain battery limits.
Construction was the responsibility of Gibbs & Hill.  Only the Phillips
system will be described in detail.

          The Phillips system comprises four parallel trains, Figure 1,
and was designed to handle a total  gas volume of 2,190,000 ACFM with
all trains in service.  With one train out of service, the three
trains have a capacity of 1,600,000 ACFM, which is sufficient for
400 MW, assuming normal excess air.
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          Three scrubber trains were provided with first stage scrub-
bing for fly ash removal, Figure 2.  The fourth train, known as the
"prototype" SO- train, was fitted with a first stage particulate re-
moval scrubber and a second stage SC^ absorption scrubber as shown
on Figure 3.

          The ductwork on each boiler was modified to enable operation
with the gases going either to the scrubbers or to the original gas
path after passing through the existing dust collection equipment.
A mechanical and electrical dust collector are located in series
ahead of each individual boiler stack.  The existing ducts leading
to the old ID fans and stacks were blanked off with removable steel
plates to enable diversion of the flue gas to a new common duct.
The new ductwork is routed to the scrubber building where 16 foot
diameter takeoffs lead to each of the four first stage scrubbers.

          The hot flue gas (about 340F) containing fly ash and sul-
fur dioxide (about 1400 ppm $02) enters the first stage scrubber and
impinges upon the upper cone.  One half of the total scrubber liquor
(8250 gpm) is introduced, Figure 4, into the vessel through the bull
nozzle where it is sprayed over the surface of the upper cone, to
initiate the scrubber action.  A second stream of 8250 gpm scrubber
recycle liquor enters through the tangential nozzles at a point
above the adjustable throat damper.  The flue gas and scrubbing
liquor are brought into intimate contact in the throat section of
the scrubber where the particulates and some 502 are removed-  The
gas and liquor continue downward to the separator section where, after
being separated from the scrubbing liquor, the flue gas enters a de-
mister where entrained liquor is removed.  The gas leaves the scrubber
and enters a new wet ID fan which is provided with water sprays to re-
move any accumulation of solids resulting from carryover from the
scrubber.  Fresh water is used for spraying.

          The ID fan housings are lined with 1/4 inch thick natural
rubber.  Wheel material is Carpenter 20 Cb 3.  The shaft is 316 L
stainless steel.  Each fan is driven by a 5500 HP, 1200 RPM, 4160V
electric motor.  Bearings are of the water-cooled type, served from a
closed  cooling water system.

          Outlet gas temperature, normally 110-120F, from the first
stage scrubber is monitored.   At 175F a control  valve is automatically
opened to admit emergency cooling water to the upper cone.  Additional
temperature rise would automatically shut down the fan and close the
isolation dampers.

          The gas leaving the ID fan enters one of two vessels de-
pending on the train.  In the case of the three single stage scrubber
trains, the gas enters an entrainment separator in which entrained
water is separated and collected.  The separators or mist eliminators
are separate vessels which will be replaced by second stage scrubber
vessels if the test program indicates this to be necessary.  in the
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case of the SC^ prototype train, gas leaving the ID fan enters a
second stage scrubber vessel, which is identical in size and design
to the first stage.  This second stage vessel is equipped with a
reagent (lime) injection nozzle in the bottom cone.  The scrubbing
liquor is then picked up by the two recycle pumps  (Carpenter 20
Cb 3).  Some of the liquor is bled off to the first stage scrubber, where
some is removed from the cycle to thickeners, and the balance is
recycled.

          Total recycle flow is about 16,500 gpm with a 615 gpm
bleed to the thickeners.  All single stage vessels have also been
fitted with reagent nozzles and feeds to enable control of pH and
incidental S02 removal.

          The exit gases leaving either the second stage scrubber
vessel orthemist eliminator vessel enter a common wet duct lined
with Flakeline 103 (a product of the Ceilcote Company consisting
of a glass flake filled modified polyester resin, subsequently
referred to as Ceilcote) which leads  to a new concrete acid re-
sistant brick lined chimney.  Prior to entering the 340 foot
chimney, a section of the wet gas duct, constructed of 316L SS is
equipped with a reheater, employing a direct oil-fired burner system.
The two-burner system is capable of reheating 30F, although the in-
tent is to normally reheat 20F.

          Bleed off f-rom all scrubbers is directed to a trough feeding
two 75 foot diameter thickeners.  The overflow from these thickeners
is directed to a collecting tank where it is pumped by two-2000 gpm
SS pumps to the make-up line for return to the scrubber system.

          Thickener underflow, at 35 to 40% solids concentration, is
pumped by one of two 105 gpm, 15 HP pumps to one of three clay lined
sludge holding ponds.  Each pond has a capacity of about 6500 cubic
yards.  Just prior to discharge to the holding ponds, the sludge
enters a mixing tank where a stabilizing agent can be added at a
predetermined rate based on the density of the sludge as it leaves
the thickener.  After the additive is intimately mixed with the
sludge, the mixture discharges by gravity to one of the ponds.

          In the pond, both settling and curing take place.  Super-
natant liquid is withdrawn and recirculated to the scrubber system
via the thickener.  The sludge curing ponds provide interim storage
while stabilization is taking place.  One pond received thickener
underflow, while a second is curing and the third is being excavated
for final off-site disposal.

          Lime is fed from a storage silo at a controlled rate to the
lime slaker where it is slaked with fresh make-up water.  The slaked
lime overflows into a slaker transfer tank, where make-up water is
added to provide a constant flow of lime slurry with a concentration
of about 15%.
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          A service (river) water system independent from the power
station service water system is provided.   It includes a pair of 900
gpm, 100 HP pumps taking suction  from the existing condenser dis-
charge tunnel and a 10 inch distribution header for the scrubber
facility.  It provides fan spray water, pump seal  water, mist elim-
inator and scrubber demister spray water,  instrumentation flush
water, chemical mixing tank, and emergency water for scrubbers.

INITIAL OPERATION

          Although the lime addition system was not yet completed,
partial start-up of the scrubber system began on July 9, 1973.  The
decision to proceed with startup, without  the lime addition system,
was made in light of the fact that we thought the scrubber system
was suitable for operation at a low pH.  Almost all of the major
components and piping were either Ceilcoted, rubber lined or fabri-
cated of a corrosion ^esistant material to withstand a low pH.
During the first five days of operation, a pH of approximately 1.3
to 2.0 developed in the scrubbing liquor while burning 1.8-2.0% sul-
fur coal.  Because of pressure to proceed  with the debugging operation,
and because of our reluctance to incur additional  delays, the decision
was made to continue operation with the low pH rather than shut down
the scrubbers until the lime system became operational.  Unfortunately,
as a result, the scrubber system was forced out of service due to the
corrosion failure after five days of the two thickener overflow re-
turn pumps, which were intended for operation at a pH of b  to  6..  They were
promptly replaced with two 316 L SS pumps.  Use of the lime system
feed to the thickeners was obtained after the first week of operation.

          During the first two weeks of operation, additional problems
developed and were corrected in a two-week outage following the first two
weeks of operation:

  1.  A piece of rubber liner was found in the suction of one of
      the recycle pumps.  The individual scrubber was shut down
      in an effort to locate the source; however, it could not
      be determined until the corrosive nature of the scrubber
      media  caused the failure of a 20"/16" Tee within 10 days.

  2.  Leaks occurred in the lead floor lining of the stack which
      were a potential threat to the stack concrete structure.
      The lead sheets had been soldered rather than "burned."
      The lining was replaced.

  3.  Leaks developed in four 405 SS expansion joints in the
      gas ducts leading to the stack.  The appearance of the
      failed metal was variously described as that of "lace
      curtain" or "swiss cheese."  This resulted from partial-
      load type of operation of the scrubber system requiring us
      to partially open the vacuum breakers and allow ambient air
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      to supplement the gas flow through the scrubbers.  Conden-
      sation resulted.  The joints were replaced with an asbestos/
      butyl material.

  4.  The reheater, which utilizes direct firing of No. 2 oil in
      the .cold gas duct as it enters the stack, is not yet oper-
      ational.  We have been unable to obtain satisfactory oper-
      ation of the reheater due to burner problems and oil pump
      problems.  We have placed no priority on solving these prob-
      lems due to our reluctance to operate the reheater consid-
      ering the present energy crisis and oil shortage.  Whenever
      the reheater becomes operational, we plan to operate it
      during periods of adverse meteorological conditions'to ob-
      tain a higher effective stack height.

  5.  During the outage, evidence of corrosion was found on the
      ID fan shaft shrouds, inlet dampers and stiffener bars - all
      316 L stainless steel.  Two corrective measures were taken -
      redesign of the fan sprays and application of 1/4-inch
      rubber coating to the affected parts.  After two weeks of
      operation the chloride concentration in the liquor (closed
      cycle)had reached 800-900 ppm.  This, no doubt, contributed
      to the corrosion noted above.  It was eventually to reach
      3500-4500 ppm.

          On August 5, 1973, the scrubber system was returned to service
with the lime feed system for pH control continuing in operation.  In
addition to No. 1 and No. 2 boilers, the No.  3 boiler was also connected
to the scrubber system, which made a total of approximately 145 mega-
watts.

          During the following weeks of operation, we were informed by
Chemico of a major change in the operating requirements of the scrubbers;
namely, the necessity to bleed more fluid to the thickener tanks so
that the concentration of solids in the recycling fluid could be kept
to a minimum in order to protect the recycle pumps, and to minimize the
settling of solids in the bleed lines.  This caused a change in the de-
sign concept by essentially doubling the bleed rate.  This meant that
the two 900 gpm thickener tank overflow return pumps, which had been
provided with the system, were inadequate since they no longer had
sufficient capacity to supply the needs of the scrubber system under
one pump operation (the second being a spare) with all boilers con-
nected to the scrubber system.  Two 2000 gpm pumps were obtained for
later installation in parallel with the two 900 gpm pumps.

          During the two months of operation following the August 5,
1973 start-up date, operation of the scrubbers was alternated between
trains.  In other words, as problems arose on one train, it was shut
down and another train was put in service to take its place.  No effort
was made to operate the dual stage prototype S02 scrubber for full S0
removal because it was felt that debugging operations could more effect-
ively proceed with the most basic operation possible, in other words,
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with  the single stage scrubbers.

EXTENDED SHUTDOWN FOR REPAIRS

         During the operation of the  scrubbers  in  August and Septem-
ber,  1973, additional problems came  to  light  which  caused an extended
shutdown of the scrubber system, and a  further delay in the operating
schedule, namely:

  1.  A routine inspection of the new  stack  revealed additional
     moisture leaks from condensation  (pH 2,0)  seeping through
     the mortar joints and running  down  the  outside of the acid
     brick lining.   Seepage was occurring in more  than 100 areas
     of the brick lining.  The condensate was collecting at the
     bottom of the stack in the annulus  between the lining and
     the shell.  The acid condensate was also seeping through
     construction joints and down the  outside of the concrete
     shell permitting it to attack  the concrete, which could
     possibly impair the structural stability of the stack.  The
     contractor advised us that a four week  outage would be
     necessary to permit inspection of all mortar  joints and
     to repoint as required.  This  outage for other reasons to
     be described,  extended for about  five months.

  2.  Significant scaling and buildup  had occurred  in various
     portions of one or more of the scrubbers and  in the asso-
     ciated piping in varying degrees  as described below:

     a.  Buildup was found on many  of  the upper cone sup-
         port struts.  These football-size accumulations
         appeared to be creating a  disturbance  in  the water
         flow pattern over the cone resulting in accumu-
         lations of deposit on the  cone  surface.

     b.  Deposits were found in the throat area of two of
         the scrubbers, sufficiently  thick in some areas
         to prevent the maintenance of the  six  inch de-
         sign pressure drop across  the throat.

     c.  A thin buildup of hard scale was observed on the
         face of the throat dampers of one of the  scrubbers.

     d.  Deposits of fly ash were found  in and  around the
         operating mechanisms of the adjustable throat
         dampers.  These were sufficient to  prevent full
         adjustment of the dampers.

  3.  Corrosion/erosion was found in numerous areas:

     a.  Severe pitting and corrosion appeared  on  all of the 316 L
         clad ID fan damper blades  and frames.   The cladding was
                                340

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        removed and the carbon steel was Ceilooted.

    b.  In all  scrubbers, a moist layer of fly ash was observed
        on the  carbon steel skirt that directs the flue gas
        down the cone.   Extensive rusting was found under the
        fly ash and on the underside  of the vessel tap as well.
        The latter may have resulted from frequent outages for
        inspection, during which alternate wetting and drying
        occurred.

    c.  The upper cones of the scrubber vessels were fabricated
        with a  316 L SS apex.   The balance was carbon steel with
        a Ceil cote coating.  The uncoated apex showed erosion/
        corrosion in all  vessels.  Similar attack was shown on
        the inner surface of the 316 L bull nozzle directly
        above the cones.   Both affected areas were coated during
        the outage.

    d.  Baffle  plates in  some  tangential nozzles (12 per vessel)
        were found badly  corroded.  The specified material of
        construction was  316 L SS, but it was found that the
        corroded baffles  had been fabricated of 304 SS.  Six-
        teen baffles out  of a  total of 60 required replacement
        with 316 L.

    e.  Similarly, the throat  damper arms (12 per vessel) were
        supposed to be 316 L SS.  Thirty-two out of a total of
        60 were badly corroded and were found to be 304 SS.  They
        were replaced with 316 L.

    f.  The top and bottom throat damper scraper blades were
        practically destroyed.  The also were found to have
        been 304 SS instead of 316 L.  They were replaced with
        316 L.

4.  An initial  inspection and  analysis of the ID fans by Franklin In-
    stitute Research Laboratory (FIRL) indicated the existence of
    chloride stress corrosion  cracking of the parent metal and
    structural  welds, as  well  as general corrosion on all exposed
    surfaces.  At that time, they advised us that the problems re-
    sulted from the hostile environment in which the fans were
    operating.   In addition, they made a specific recommendation
    that the fans not be  operated in the condition found at that
    time, due to possible catastrophic failure.

      As a result of their search for protective coatings, FIRL
    recommended the application of a Ceilcote material, Coroline
    505AB.  This is a hard, impervious, acid resistant, epoxy base
    material which is applied  at a nominal thickness of approxi-
    mately 1/4".  The application of the Coroline is a tedious,
    time consuming hand application by trowel and requires close
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      quality control.  The application of the material began in
      November, 1973.  Although Coroline had not been extensively
      used on fan blades, or proven to any degree, we were given
      reasonable assurance that it would be successful.  As a
      result, we began application of this material to as many
      fans as manpower permitted.

        On January 22, 1974, the first fan was completely coated
      and was started up for balancing.  After a balance move
      was attempted, the fan was forced out of service due to
      excessive vibration resulting from separation of a portion
      of the coating from one of the blades.  The Ceilcote Com-
      pany informed us that the separation was localized and
      probably caused by a faulty batch of material which did
      not properly adhere to the metal. The Coroline was re-
      applied and the fan was started again on February 5, 1974
      and again was forced to shut down due to separation of the
      material in a second area.  At that time, the Ceilcote Com-
      pany was unable to adequately explain the failure of the
      coating to adhere to the fan surfaces.  As a result, the
      decision was made that the application of Coroline as
      protection against the adverse effects of the flue qases
      was not the answer to the problem. It is believed that the
      flexing of the blades during operation may have contributed to
      the lack of adhesion between the Ceilcote and the blades.

        By this time, FIRL had been able to conduct more exhaustive
      investigations and analyses  on the fan blade material.  As a
      result, they revised their initial conclusion and reported
      that the fans were suffering from a much lesser degree of
      stress corrosion cracking of the weld metal and a degree of
      pitting attack on all fan blades.  The report also indicated
      that fan failure was no longer considered imminent.

          In review of the ID fan  problems, it appears that the corrosion
problems which we had experienced  might be partially due to the operation
of the scrubber system at a lower  pH and a higher chloride concentration
(3500-4500 ppm) than had been foreseen by the scrubber designers.  Several
steps were taken to try to alleviate the situation:

  1.   Operation of the dual stage  scrubber with full  lime addition,
      which we felt would be adequate for maintaining optimum pH
      control in that train;

  2.   Addition of supplemental  lime feed to the other operating
      scrubbers, and

  3.   The installation of a redesigned spray system,  which had proven
      effective at other installations.
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    These steps in addition to frequent scheduled fan inspections
    were felt to be adequate safeguards for placing the system
    back in operation.

          Our ability to start up the scrubber system and initiate full
S02 removal in the dual stage prototype was further improved by the
completion of the sludge stabilizer addition system.  We had been re-
luctant to add large quantities of lime to the single stage scrubbers,
and equally re'iuctant to begin operation of the dual stage scrubber,
both of which result in the production of considerable amounts of
sulfate sludge, without the capability of adding a stabilizer.

SECOND START-UP OPERATION

          Removal of the Coroline material from the dual stage scrubber
fan No. 1 was .completed, and startup of the scrubber system once again
began March 17, 1974.  At that time, the dual  stage Scrubber Train No. 1,
and Scrubber Train No. 4 were placed in operation with boilers No. 3
and 4 connected to the scrubber system.   Since then there have been
these additional developments:

  1.   Excessive Fly Ash

      The sludge handling system was designed  so that after 30
      days of normal operation with all  boilers tied in and
      with the dual  stage S0"2 prototype and two of the three
      single stage scrubbers, the first curing pond should be
      approximately full.  However, after the  first two weeks,
      one pond was completely filled with only two boilers con-
      nected to the scrubber system during the first week and
      three boilers connected to the system during the second
      week.  This means that, with an average  of 120 megawatts
      connected to the scrubber system,  we were producing approxi-
      mately 7,000 tons of sludge in a two week period.   Or,
      stated another way, if the entire plant  were connected to
      the scrubber system, we would fill a pond within a week.
      The major factor contributing to this change in capacity
      proved to be an increased fly ash loading of the scrubber
      system.   The sludge disposal system was  based on a 90%
      combined collection efficiency of the mechanical dust
      collectors and electrostatic precipitators.  The transition
      of the new scrubber ductwork to the old  ductwork is such
      that the gas flow pattern of the gases through the pre-
      cipitators proved to be greatly disrupted.   Velocity
      traverse data indicated that laminar gas flow no longer
      exists.   Rough estimates indicated that  the amount of
      particulates leaving the precipitators and entering the
      scrubber system may have trippled.  Additional details on
      the sludge handling will be covered later.
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2.  ID Fan Stress

    As part of the continuing investigation to determine the
    conditions of the ID fans, Structural Dynamics Research
    Corporation (SDRC) was engaged to conduct a series of
    strain gage tests to determine the structural stability
    of the fans.  Their tests indicated that the yield
    strength was being exceeded in several portions of the
    fan blades, and that a degree of metal deformation was
    taking place.   After additional strain gage testing,
    SDRC recommended the installation of doubler (reinforcing)
    plates on each of the blades to reduce the stresses to
    acceptable levels.  After actual tests with stressed welded
    specimens in the fan atmosphere, it was also recommended
    that the doubler plates be welded with an Inconel 112 rod,
    rather than the Carpenter 20, 4 NIA or 8 N12 rods pre-
    viously used.   Since the installation is on a fan-by-fan
    basis, so that a spare scrubber train would always be
    available for emergency backup, it is expected that all
    four fans will not be completed until the end of November,
    1974.

3.  ID Fan Attack

    Frequent shut down of the ID fans for inspection revealed that
    significant attack was still taking place.  Despite the addi-
    tion of lime for S02 removal and pH control, a low pH was being
    encountered in the ID fan drains.  This results from additional
    SC"2 scrubbing occuring with the fan spray system.  In a trial
    installation,  caustic was added to the fan spray water.  How-
    ever,  an inordinate quantity is required to obtain even a pH
    of 4,  and the trial will  soon be ended.  As another attempt
    to alleviate the attack,  a new type of fog nozzle was installed
    on one of the ID fans in  an attempt to increase the effective-
    ness of spraying.  No evaluation is yet possible.

4.  ID Fan Deposits

    In addition to the cleaning being accomplished by both the
    original and the new fan  spray systems, it was necessary to
    periodically remove the ID fans from service to remove de-
    posits by manual  methods.   In recent weeks,  this phenomenon
    has not required the need to clean the blades as frequently.
5.  Recycle Pumps

    An unsatisfactory degree of wear (about 30% in three months)
    is being experienced on the recycle pumps to the point where
    pump parts are being diverted from the Elrama scrubber system
                               344

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     to Phillips at such a rapid rate that the stock of installed pumps
     at Elrama will soon be depleted.  Experimental  pump impellers and
     wear rings of three different materials and design will  be installed.

 6.  Thickener Capacity

     Modifications were made to the thickener tank overflows  to increase
     their hydraulic capacity and thus compensate for the increased dust
     loading and provide spare capacity.

 7.  Throat Dampers

     Significant unacceptable accumulations are still being found in and
     around the scrubber throat damper operating mechanisms.   These have
     restricted the damper operation and  resulted in operation at pressure
     drops of up to 10 inches instead of  the normal  6 inch drop.   Cleaning
     requires removal  of the train from service for manual  removal of the
     mechanism and hand cleaning.  About  288 manhours per scrubber are
     required.

 8.  Sump Pumps

     The ID fan spray sump pumps have been wearing out much faster than
     anticipated.   This is due in part to the low pH and to the higher
     solids concentration in the fan drains.  Once again, we  have had to
     draw on the Elrama installation for  replacements.

 9.  Closed Loop Operation

     A closed-loop system may be possible at maximum load with all boilers
     cut-in.  However, the Phillips Power Station is not a base load station,
     and as a result,  the load fluctuates between 30% and full load.  At the
     lower loads,  less water is evaporated from the system, while many of the
     points of water addition (purge, seal and spray water) continue.  This
     results in an excess of water in the system.  Temporary  permission was
     obtained from the Pennsylvania Department of Environmental Resources
     (PDER) to discharge the excess to our existing bottom-ash settling ponds.
     This permits  the settling out of particulate matter and  dilution of the
     blowdown prior to discharge to the river,

10.  S02 Guarantee Performance Tests

     In July, 1974, several  tests were made on the dual  stage prototype scrubber
     for S02 removal,  with inlet S02 concentrations ranging from  1263 ppm vol.
     to 1,603 ppm. at stoichiometric ratios from 1.01 to 1.15  the  S02 removal
     ranged from 86% to 93%.  The guaranteed SOj removal is  80%.

SLUDGE TREATMENT & DISPOSAL

     At the time the present period of operation started, the sludge
     additive system had been completed to the point where it was
     considered operable.  However, it soon developed that the pumping
     system for the additive was operating below design capacity.  The


                                       345

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necessitated pumping a slurry with higher solids content,
and the 750 ft. long transfer lines were frequently out of
service due to plugging.

  This stabilization additive chosen for use is Calcilox,
a proprietary product of the Dravo Corporation.  This
material was developed in the approximate period of
October through December, 1972, when we re-installed the
Chemico pilot scrubber for the sole purpose of making
sludge.  Industry knowledge of sulfate-containing scrubber
sludge and means of stabilization appeared almost totally
lacking at that time.  The scrubber was connected so it
could be supplied from either upstream or downstream of
the existing dust collectors of the No. 4 boiler to enable
experiments with both clean and dirty gas.  The material
developed, Calcilox, is of the consistency of dry cement and,
on the basis of laboratory tests, has the property of con-
solidating the sludge so that it can be disposed of as land
fill without an objectionable leachate.  The degree and time
of consolidation depends on the amount added (3-15% by dry
weight of sludge), the pH of the sludge (10.5 appears suit-
able for our curing time), and temperature (lower temperatures
slow the process).  Since actual field leaching tests had not
been made, we installed two membrane-lined ponds in an inactive
ash disposal area to enable collection and retention of leachate
from Calcilox-treated sludge.  Bottom drain systems were pro-
vided with valves to enable leachate sampling at intervals.
One of the ponds has 22,860 yd3 capacity, the other 5720 yd3.
These capacities may be increased by 50% if the material proves
suitable for successive layering and compacting.

  During the previously noted difficulties with the additive
system, Calcilox was either added sporadically or not added
at all.  As a result, the sludge after residence time in the
ponds was of a "soupy" nature, which made it difficult to
excavate with a clam shell and to transport in open trucks.
Prior to placing the material in the trucks, fly ash from the
ash silo was deposited in the rear of the truck to seal the
tailgate.  Because of the difficulties in handling the sludge,
additional boilers could not be connected to the scrubber
system since it would tax our ability to remove the sludge
from the ponds as rapidly as it was being produced.  Since
the sludge did not have the amount of additive which would
normally be added prior to discharging it to the ponds, no
appreciable degree of stabilization took place in the ponds.
We did not feel that the "soupy" material was representative
of that which would result from the normal sludge disposal
system, and were reluctant to use one of the lined test
ponds for this material.  Therefore, we requested interim
permission from the State's Solid Waste Disposal Division
of the PDER to dispose of the material on the ash disposal
area where we normally dispose of the fly ash and bottom
                              346

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from the generating plant.  The State consented to our
request, and we started disposal of the unstabilized sludge
on our ash disposal site.  It was spread in thin layers,
mixed with additional fly ash and then compacted.

  Handling of the sludge was extremely difficult.  The trucks
could only be loaded to approximately 1/2 capacity because
of the danger of the sludge flowing over the sides if the
truck stopped or started too abruptly or made turns at
excessive speed.  In addition, because it was impossible to
prevent sludge from dripping onto the sides of the truck
during the truck loading operations, it was necessary that
the trucks be washed prior to leaving the plant premises.
Even with such precautions, occasions arose when sludge was
deposited on the roadways.  After several warnings from the
local police and the Pennsylvania Department of Transportation,
it was necessary to rent a street cleaner and a water sprinkler
truck to clean the streets during the hours of sludge hauling.

  In approximately May, 1974, modifications were completed on
the additive system, and Calcilox was then added on a continu-
ous basis to the sludge with around-the-clcck technical super-
vision.   Filling time per pond was about 10-14 days with the
increased quantity of fly ash, instead of the 28-30 days which
had been planned.  Similarly, the curing time was reduced from
30-60 days to 14.  However, with about ~\Q% Calcilox addition
the sludge did consolidate to the extent that drag-line ex-
cavation was possible, truck tailgates did not require sealing,
and it was possible to fully load the trucks.  Observations
of the sludge during excavation showed that although the top
layer resembled hard clay in consistency, it became earth-like
and then almost fluid near the bottom.  It was necessary to
mix the lower-most layer with dryer material from the upper
layers to obtain a satisfactory handling quality.

  The consolidated material was trucked to and deposited in
one of the lined areas for leachate monitoring.   However, the
thixotropic nature of the material was such as to prevent
either leveling or successive layering of truckloads.  It
was necessary to tailgate the sludge and then let it stand
(cure?)  for about six more weeks before it could be leveled,
and dozers and trucks did not get "hung-up."  This, of course,
slows the disposal process considerably.

  Our present procedure is to add consolidated sludge to the
lined area whenever possible.  At other times, it is mixed
and compacted with dry fly ash on the normal disposal area.
We have now been monitoring the bottom drains from the lined
area at weekly intervals for six weeks.  In that time, the
total dissolved solids (TDS) have varied from an original
                            347

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      2203 mg/1 to the present (October 2) 3380 mg/1.   A sample analyzed
      by the PDER on September 22 verified the results on our own
      sample of that same date.  No record of total  volume of leachate
      has been maintained, and it is realized that this quantity can
      affect the measured IDS appreciably.  Similarly, it is realized
      that the method of disposal by tailgating and  our inability to
      level the top of the sludge to a possibly impervious surface
      has also had an effect.

        In addition to the above tests, leachate studies were con-
      ducted on a more closely controlled basis.  About June 1,1974,
      we used a concrete mixture to prepare four sludge mixtures
      with various additives.  The additives were fly ash, 2%
      hydrated lime, 5% hydrated lime and 11% Calcilox.  Each mix
      was then added to a plastic wading pool which  had previously
      been fitted with a valved underdrain system for leachate
      sampling.  Since the tests started, we have added water to
      each pool once each week so as to cover the sludge after
      first sampling and draining all water from the previous week.
      After fourteen weeks, the most meaningful tests  are those with
      the 5% lime and the Calcilox.  They show that  the total dissolved
      solids (TDS) on the lime test started at 1450  mg/1 and are now
      460 mg/1.  The TDS on the Calcilox started at  3370 and are now
      2000.  Penetrometer readings in that time have increased to
      2.7 tons/ft^ on the lime and 4.5+ on the Calcilox.  In summary,
      while more salts are leached from the Calcilox mix, the degree
      of consolidation is higher than that of the lime.

FUTURE OPERATING PLANS

          Due to improvements in the method of sludge  treatment and
handling, and due to close control of the thickener  tank underflow
operation, it was possible to cut-in a fourth boiler to the scrubber
system on August 18, 1974.  This increased the capacity connected to the
scrubber system to approximately 180 megawatts.  Our plan is to operate
the scrubber system with the four boilers for a period of time to deter-
mine the extent of any aggravation of existing problems and the occurrence
of any new problems.  If the problems become intolerable, it may be  neces-
sary to return the scrubber system to a three boiler operation.  However,
if the problems are not severe, we anticipate the possibility of adding
a 5th boiler to the scrubber system.  We are extremely cautious in our
optimism because of the number of unknowns in the sludge disposal system
such as the following:

  1.  Since the lime feed system is essentially operating at
      maximum capacity, additional boilers will reduce the pH
      in the scrubber system.  We are told that a reduced pH would
      adversely effect the stabilization of the sludge.  However,
      we do not know to what degree it will be affected.  Also,
      if additional boilers are connected to the scrubber system,
                                 348

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      the rate of sludge production may not permit optimum stabili-
      zation period which now appear to be greatly in excess of 14
      days.

  2.  With the oncoming cold winter months, it is not known to what
      extent low temperatures will hinder stabilization.

  3.  If additional boilers are connected to the scrubber system,
      and it becomes impossible to optimize stabilization of the
      sludge prior to removing it from the ponds, it may be necessary
      to again seal the tailgates with fly ash prior to loading the
      trucks with sludge.  This would then be conducive to sludge
      material dropping on to the road, freezing and causing com-
      plaints from the local citizens.

          If we can connect five out of the six boilers to the scrubber
system by November 30, 1974, we will begin our ten-month test program
at that time to evaluate the efficiency, reliability, and practicability
of the scrubber system.  A decision would then be made on September 30,
1975, concerning the installation of additional S02 removal equipment
for compliance with the S02 emission limitations.  The number of
additional second stage scrubbers required for compliance with the
regulations will be determined during the ten-month test program, and
this will establish the completion date for installation of all additional
scrubbers.

          In the hope of obtaining higher efficiencies of S02 removal with
the use of lime, Duquesne Light is conducting tests using Thiosorbic lime
(a Drayo development) which is a lime having a concentration of magnesium
oxide in the order of 4 to 6%  Various tests on pilot scrubber systems
indicate that the higher reactivity of such a lime results in S02 single-
stage removal efficiencies in the 90's.  In preparation for these tests,
one of the single stage scrubbers was isolated along with one of the
thickener tanks.  This isolation was necessary to establish and main-
tain the desired chemistry, since lime slaking capacity is insufficient
to maintain the necessary conditions in all scrubbers and both thickeners.
A test run with Thiosorbic lime was made in September, 1974.  However,
we encountered difficulties in achieving a sufficiently high rate of
utilization of the magnesium oxide.  A few cursory tests under these
conditions indicated S0 removal efficiencies somewhat better than those
with high calcium lime, but also significantly less than anticipated.
The tests were suspended later in September to further evaluate means
of increasing the reactivity and utilization of the Thiosorbic lime.
Resumption is planned for about October 21.

          As of August, 1974, construction on the Elrama scrubber system,
which is essentially identical to the Phillips scrubber system, had pro-
gressed to a point where no additional meaningful work could be accom-
plished until the problems with the Phillips scrubbers are resolved.
With the modifications and test programs now being conducted at Phillips,
it is anticipated that solutions to the present problems may progress
to the point where startup of the Elrama scrubber system may be possible
in May, 1975.
                                   349

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AVAILABILITY AND RELIABILITY

           The availability of the Phillips scrubber system is  meaning-
 less at this point since we have essentially 100% backup.   In  other
 words, there are two spare scrubber trains which can be placed in
 service whenever a problem arises on an operating train.   The  service
 hours for each train for the period from March 17,  1974 through
 September 30, 1974 are 3430 hours for No.  1  train (dual  stage),
 1678 hours for No. 2 train, 1931  hours for No. 3 train,  and 2803
 hours for No. 4 train.

           Reliability was built into the design of the system  which
 called for a spare scrubber train enabling us to carry almost  full
 station load on three scrubber trains.  In addition, a degree  of
 reliability is built into each scrubber train through the  instal-
 lation of spare pumps, thickener capacity and backup electrical con-
 trols.

           We do not view bypassing as the solution  to maintaining
 acceptable reliability.   However, we have incorporated a manual type
 bypass into our scrubbing system as the best approach to avoid the
 serious consequences of scrubber failure.   The system uses blanking
 plates to redirect the gas flow to the original stacks,  and the
 boilers have to be shut down during the plate change.  Under normal
 circumstances, this process would consume several days depending  on
 the availability of manpower.  There really was no alternative in
 designing a bypass system for our plants.   Mechanical bypass systems
 utilizing a damper arrangement require tight dampers, and  sufficiently
 tight dampers have yet to be developed.  We also had serious space
 limitations on installation of a mechanical  damper system.

 CAPITAL AMD OPERATING EXPENSES

           As of this date, the scrubber systems at Phillips and Elrama
 represent a capital investment of approximately $61  million.  It  is
 expected that an additional $19 million will be required for equip-
 ment necessary to comply with the S0 emission limitations. This will
 represent a total investment of $80 million or approximately $91  per
 kilowatt, exclusive of the cost of any additional sludge disposal facili-
 ties required.

           A recent estimate indicates that the annual operating and
 maintenance expenses, including fixed charges, at Phillips and Elrama
 with full S02 scrubbing will be in excess of $30 million per year,  or
 5.5 mills per kilowatt hour, exclusive of additional sludge disposal
 facilities which will be required for full S02 removal operation. These
 expenses would represent an increase of approximately $11  per  ton of
 coal consumed.  Expressed in different terms, these expenses,  without
 fixed charges, would represent approximately a 50% increase over  the
 actual operating and maintenance expenses for 1973.
                                   350

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          In an effort to estimate the total capital and operating
costs that would ultimately be incurred for the scrubber systems at
the Phillips and Elrama Stations, including provision of adequate
sludge disposal facilities for full S0 removal, a preliminary
evaluation was made of the additional property required for develop-
ment into a disposal area and the additional expenses involved in
disposing of the sludge.  This estimate indicates possible capital
expenditures of $110 million for scrubber installation and property
acquisition and development, of which $61  million has thus far been
spent.  This represents an investment of approximately $124 per kw.

          Present estimates of the sludge disposal costs are $7 to
$10 per wet ton, or $15 to $20 per dry ton of sludge.

Future Objectives

          Although we feel we may be able to overcome the present oper-
ating and equipment problems with additional time, effort and expense,
there are five levels of performance which must be satisfactorily re-
solved if this flue gas desulfurization system is to be operationally
feasible and economically acceptable:

  1.  Reliability - meaning the scrubber facility should meet
      the degree of availability normally expected of power
      generating equipment.

  2.  Turndown - the capability of the flue gas desulfurization
      equipment to follow the normal cycling operation of a
      power generation facility without serious disruption to
      both the scrubber system and the generating plant.

  3.  Closed Loop Operation - the ability to operate without
      the discharge of objectionable liquid effluents as
      dictated by the applicable water quality requirements.

  4.  Sludge - the technique for disposing of sludge from the
      flue gas desulfurization system without any adverse
      ecological effects.

  5.  Cost consideration - capital and operating expenses should
      not be of such a magnitude as to impose unreasonable
      financial burden on the operator/ owner and the consumer.

          Until all these areas of concern are resolved, our system
cannot be considered a successful operation as reports by others have
indicated.
                                 351

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                          FIGURE 1
                      CALCILOX   CAiL/LOX
                      BiPG.
               PUMPS ftiM\ ft//K\ fUM
                   SILOJ \SILOJ \f,iLO/^)\
                   ^/ x>/ \--S  I*-BLURRY
                          I   I  AKEA
                          TRAIN 4
TRAIN 3    "TKAIN 2.   TRAIN 1
AIR POLLUTION  CONTROL  EQUIPMENT  LAYOUT
             PHILLIPS   POWEg   STATION

-------
              FIGURE 2
HOT FLUE MS TO /Lr. STAGE SCKUaBKS
                         SINGLE
                       SCRUBBER  TRAIN
                   PHILLIPS  POWER STATION

-------
                                 FIGURE 3
PROTOTYPE DUAL STAGE SCRUBBER TRAIN-PHILLIPS  POWER  STATION
HOT PI. tie GAS
                             COLO
                                  cv*s
                                                   OIL
                                                        AIR




A^1
8
t













KXX*
$vv
>

tH-UWtK 1 I
T T


_[







 	
                                              VtBKArOP.
                                                            PUMP (2)

-------
*a-
LU
rs
CJ3
                      A PJUS TA BL E TUROA T
                           PAMPERS
             VZNTURI  SCRUBBER  SECTION
                         355

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                                   FIGURE 5

                             SIGNIFICANT  DATES
December, 1969


September, 1970




October, 1970


February-May, 1971  -


May, 1971

July, 1971



December, 1971


July, 1973
July 9, 1973


October 8, 1973

March 17, 1974

August 26, 1974

October, 1974
Gibbs & Hill, Inc.  requested to study methods
of compliance.

Gibbs & Hill  study recommends scrubber and
Duquesne Light Company gave authority to
Gibbs & Hill  to proceed with projects at
Elrama and Phillips Power Station.

Invitations were extended to bid on scrubber
pilot plant.

Chemico pilot scrubber tests at Phillips under-
way.

Design of full  scale system started.

Contract for scrubber process including scrubber
recycle pumps,  reheater and associated controls
and instrumentation awarded to Chemico.

Construction started at both Phillips and Elrama
plant sites.

Construction of Phase I at Phillips essentially
complete.  Phase I  consists of one  dual stage
S02 scrubber train  and 3 single stage particulate
scrubber train  with associated lime and thickener
equipment.

Operation began at Phillips with two  and eventually
three of station's  six boilers.

Scrubber system shutdown for extensive repair.

Scrubber system began with three of six boilers.

Fourth boiler cut into scrubber system.

Fifth boiler cut into scrubber system.
                                     356

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              THE HORIZONTAL CROSS FLOW SCRUBBER
                              by

    Alexander Weir, Jr., Principal Scientist for Air Quality
          John M.  Johnson, Test Modules Program Manager
         Dale G. Jones, Horizontal Module Project Manager
Spencer T.  Carlisle, Highgrove Horizontal Scrubber Project Manager
               Southern California Edison Company
                     for presentation at the
        United States  Environmental  Protection  Agency's
             "Flue Gas Desulfurization Symposium '
                        Atlanta, Georgia
                        November k,
                            357

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                          TABLE  OF  COKTEI'ITS




                                                                Page No.






Abstract                                                          359




Foreword                                                         360




Introduction                                                      361




System Description                                                363




Operations:                                                        369




     Operations and Maintenance                                    ^69




     Availability                                                 369




     Turn Down Ratio                                              371




     pH Control                                                   372




     Closed  Loop Water System                                      372




Performance:




     S02 Removal                                                  374




     Particulate Removal                                           377




     Lime Utilization                                             380




     Power Consumption                                            383




     Pressure Drop                                                383




Acknowledgments                                                   386




References                                                        387
                                358

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ABSTRACT

The Horizontal Cross Flow Scrubber

     The results of pilot plant testing of  9 scrubbers and the
rationale for selection of two scrubber types for construction on a
much larger scale at the Mohave Generating Station was described^ at
a previous EPA symposium.  One of these referenced scrubbers, the TCA
Scrubber, was severely damaged by a fire January 2k, 197^ and is still
undergoing repair at the time of this writing (August, 197*0.

     This paper presents the results obtained with the other large
scrubber, the Horizontal Cross Flow Scrubber, since the start of its
test program January 6, 1.91k.  The results of operation at ^75,000
SCFM are compared with those previously presented for operation on a
much smaller scale (3000 SCFM).

     Operating experience to date confirms the wisdom of the Test
Module approach as the best method for achieving reliable, continuous
compliance with the very stringent 0.15 Ib/million BTU SOg removal
regulations imposed by local and federal authorities.
                                   359

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FOREWORD
     The experiments reported in this paper relating to the 1 MW and.
10 MW Horizontal Scrubbers were sponsored by the Southern California
Edison Company.

     The 1TO MW Horizontal Cross Flow Scrubber was designed, construc-
ted and tested as part of the NAVAJO/MOHAVE TEST MODULES PROGRAM.   This
program was established as a joint venture of the Navajo/Mohave
Power Project participants to demonstrate full-scale scrubbing as  a
necessary step in meeting regulatory requirements.  The participants
in this joint venture are:

     Salt River Project Agricultural Improvement and Power District
     Arizona Public Service Company
     Department of Water and Power of the City of Los Angeles
     Nevada Power Company
     Tucson Gas and Electric Company
     Bureau of Reclamation of the United States Department of the
        Interior
     Southern California Edison Company

     Funding for this program was provided by the participants in
accordance with their respective megawatt entitlements in the Navajo
and Mohave Power Projects.
                                  360

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                  THE HORIZONTAL CROSS FLOW SCRUBBER
INTRODUCTION
     Pilot plant testing of scrubbers was initiated at the Mohave
Generating Station in July of 1971-  Tests with sodium carbonate,
ammonia, lime, limestone, and limestone with added soluble salts
were performed with various scrubbers and combinations of scrubbers
although not all reagents were tested with all scrubbers.  The
scrubber combinations tested on a pilot plant scale are listed.

Scrubber

1.  Conventional Spray Drier Followed by a Cyclone Separator.

2.  Horizontal Lime Kiln Containing Balls or Chains.

3-  Single Stage Ventura with Fixed Annual Throat Followed by
    Centrifugal Separating Chamber.

U.  Vertical Absorber Followed by Three-Stage Impingement Tray
    Vertical Absorber.

5-  Vertical Absorber Packed with Plastic Polygrid Packing.

6.  Vertical Turbulent Contact Absorber Tested with 1, 2, 3 and
    k Stages of Mobile Spheres.

7-  Vertical Spray Tower.

8.  Venturi Followed by Three Stage Turbulent Contact Absorber.

9-  Horizontal Cross-Flow Scrubber.

     Some of the results of this comparative testing has previously
been reported.!  At that time it was indicated that two of the
scrubber types had been selected for further development on a larger
scale than heretofore had ever been built, 1450,000 SCFM each.
Formal authorization was given to contractors to design and construct
a Horizontal Cross Flow Scrubber system (called the Horizontal
Module) and a four stage Turbulent Contact Absorber system (referred
to as the Vertical Module) in December 1972 and, as previously
reported, construction started on the Horizontal Module on
February 15 > 1973.  Start-up of the Horizontal Module occurred on
schedule November 1, 197** and start-up of the Vertical Module
occurred on schedule January 1,  197^.  Unfortunately, a fire in the
chlorobutyl rubber lining of the TCA scrubber occurred on January 2k,
197^-  The damage caused by this fire has still not been repaired
as of this writing (September 13, 197*0 , and hence no operating data
                                  361

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on this scrubber in available and, therefore,  the Vertical Module
will not be discussed further in this paper.   Instead,  this paper
will present data obtained with the full-scale Horizontal Cross
Flow scrubber compared to the pilot plant data previously reported.
The operating data obtained to date has justified the earlier
decision to use the Test Modules approach rather than proceed with
the installation of ten production modules simultaneously at the
Mohave Generating Station.
                                  362

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SYSTEM DESCRIPTION

     The Horizontal Module was built essentially as described, in
Figure 17 of the previous paper-*-, which is presented here as Figure 1
for convenience.  A simplified flow schematic is included as Figure 2.
Photographs of the scrubber and some of the supporting systems are
shown as Figures 3 and h.  Referring again to Figure 1, some idea of
the size can be obtained by comparing the 3,000 SCFM pilot plant (and
the 6 foot tall operator) shown on the left of the figure with the
Horizontal Module shown on the right.  Spray headers located at the
top of each scrubbing chamber are 33 feet above grade.  The scrubbing
chamber is 15 feet high and 28 feet wide.  Flue gas is drawn from the
Mohave Unit 2 electrostatic precipitator outlet duct by the 1750 hp
booster fan and is pumped through the scrubbing chamber and a demister
section in that order.  The scrubbed flue gas then is mixed with
heated outside air in an indirect reheater before re-entering the
precipitator outlet duct just upstream of the 500 foot stack where it
is discharged to the atmosphere.

     The design of the indirect reheat section contributes to the over-
all reliability of the scrubbing system when compared to direct reheat
systems.  In this system outside air provided by a 250 hp reheat fan
is passed over carbon steel steam coils and the heated air is then
mixed with the water-saturated flue gas.  The steam coils are thus not
exposed to gas more corrosive than air, and reheater performance is
independent of demister performance (with direct reheater tubes, an
inefficient demister would allow entrained scrubber slurry to build up
on the reheater tubes, increasing flue gas pressure drop as well as
accelerating corrosion of the reheater tubes themselves).  Downtime
for reheat cleanup and repair is thus avoided.

     The remainder of the scrubbing system was also designed with
reliability in mind.  Since the scrubber does not contain any in-
ternal packing or trays, buildup and plugging in the  scrubber itself
with fly ash/scrubber slurry mixture does not occur,  either during
operation or on shutdown.  During operation the lime  scrubbing
slurry is pumped in a counter-current manner from the bottom of
one stage to the top of the next stage.  Three slurry pumps are used
for each stage and, as indicated in Figure 2, they are located at
the bottom of pyramidal hoppers.  The use of three pumps allows the
benefits of redundancy since at nominal L/G ratios only two pumps
are required.  Satisfactory operation has been obtained with only
one pump per stage, thus allowing pump maintenance to be performed
without scrubber shutdown.

     While four stages of scrubbing are used, the scrubber can con-
tinue to operate with three, two or one stages o^ scrubbing,
although as may later be seen with considerable degradation of
S02 removal performance  (only J0% SQp removal with two stages).  This
                                  363

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                                   FIGURE  1
                       SIZE COMPARISON BETWEEN PILOT
                    AND FULL-SCALE HORIZONTAL  SCRUBBERS
U)
    N \_Vjt
 PILOT FACILITY
FULL-SIZE HORIZONTAL TEST MODULE

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Figure  2
                           170 MW
                      HORIZONTAL MODULE

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Figure 3,   170 MW Horizontal Module with
            lime silo in background

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Figure A,  170 MW Horizontal Module vith
           thickener tank in foreground
           and Mohave Unit 2 in right
           background,
                       367

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redundancy allows scrubber maintenance or repair problems to be
postponed until the generating unit is shut down.

     To digress for a moment, the modular approach adopted for the
Mohave Generating Station also includes the benefits of redundancy.
As previously indicated, the Mohave participants decided to test
full scale modules before proceeding with the installation of 10
or 12 scrubbers.  Thus, operating problems encountered could be
solved once, rather than trying to fix the same problem simultaneously
on a number of scrubbers.  While a selection of scrubber types has
not been made, present plans are either to install five vertical
modules as presently designed plus one spare per generating unit or
four Horizontal Modules as presently tested plus one spare per
generating unit.  Thus an individual module availability would only
have to be 83.3% in the case of the TCA scrubber or 80.0$ in the case
of the Horizontal Scrubber to allow 100% scrubber availability to the
generating unit operating at full load.  It is believed that the
"elasticity" incorporated in the Horizontal Module will allow it to
meet that goal.
                                  368

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OPERATIONS

Operations and Maintenance

     The test program has been scheduled to operate the scrubber
continuously for 2k hours a day, 7 days a week in order to obtain
the maximum amount of operating time and data.

     All scrubber operations are performed by SCE plant equipment
operators (PEO's) and operating foremen that are also rotated to
other station activities.  One Generating Station "Watch" engineer
has been assigned full time as the operating supervisor for both the
Vertical and Horizontal test programs.  SCE chemical and instrument
technicians are available as required.  Although many of the test
conditions that are peculiar to the test program sometimes make
operations more complex than would normally be expected, it has been
demonstrated that two PEO's and one foreman, per shift, can operate
the Horizontal Module.  Maintenance support is contracted and
consists of one millwright and one pipefitter during the day shift,
5 days per week, and one laborer during the day shift, 7 days per
week.

     For both test programs three SCE Research and Development
engineers have been assigned at Mohave for test planning, test
monitoring, data analysis, evaluation and reporting.  Special
chemical laboratory support and particulate/gas sampling tasks have
been contracted.

     It is anticipated that the operation of multiple commercial
type Horizontal Scrubbers would be a relatively simple task that can
be handled by a minimum number of PEO's who have completed the
standard apprentice training program.

Availability

     The Horizontal Test Module at Mohave receives flue gas only
from Unit 2 and does not have the inlet ducting cross-connected to
Unit 1.  As a result, the scrubber is only operated when Unit 2 is
in service, i.e., when the unit is down for any reason the scrubber
is shutdown.  Therefore, availability has been calculated with
respect to Unit 2 operating time as opposed to calendar time or other
reference standards.  Since the start of the test program on
January 16, 197^ and as of September 13, 19T^ Unit 2 has been in-
service for a total of 5,003 hours and the scrubber in operation for
a total of U,292 hours resulting in an overall availability of
l|292/5003 X 100 = 85.h%.  This percentage is the accumulative total
availability and does not distinguish between scrubber outages that
were scheduled for inspections and/or test program configuration
changes, those that were necessitated because of test module problems
                                 369

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or unit outages which allowed for "free" maintenance time on the
scrubber.  A brief description of both categories are listed below:

     Planned or Scheduled Scrubber Outages = 297 Hours

                                                           Hours

     Inspect all spray nozzles                              19

     Install full compliment of spray nozzles for
     high L/G tests                                         92

     Remove spray nozzles to revert to design
     configuration                                          98

     Inspect demister blades                                 1*

     Hardware configuration change and
     maintenance                                            8^
                                  Total                    297

     Test Module Problem Outages = UlU Hours

     1.  Clean mix tank screen - h hours.

         Problem:  Overflow of the h8,000 gallon mix tank.

         Cause:  Debris from the first stage hopper clogged
                 the mix tank inlet screen.

         Correction:  Replaced the 1/V mesh screen with an
                 expanded metal screen containing 3A" openings

     2.  Repair and clean slaker/piping - Hi hours.

         Problem:  Loss of lime feed slurry to the mix tank.

         Cause:  Lime slaker and associated piping vas plugged
                 with hard calcium sulfate scale.  Formation
                 of this scale resulted from using scrubber
                 process water for slaking.

         Correction:  Converted to use of station service
                 water for feeding the slaker, transfer pump
                 seals and lime slurry feed tank level control
                 bubblers.  Also replaced major portions of
                 the slaker related carbon steel piping with
                 rubber hose and eliminated most all of the
                 horizontal pipe runs and 90 elbows.
                                  370

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     3.   Remove two hard hats  from the thickener  -  9^  hours.

         Problem:   Plugged thickener tank outlet.

         Cause:  Excessive winds,  up to ^5 MPH, caused two  operators
                 working at the  thickener to  lose their hard  hats.
                 The hats lodged in the thickener outlet drain  cone
                 above the discharge valve.

         Correction:  Two scuba  divers, in wet  suits,  were  eventually
                 able to retrieve  both hard hats  but only after the
                 bed and liquid  levels of the thickener were  lowered.
                 A storage box for hard hats  has  been  placed  at the
                 bottom of the thickener tank ladder.

     k.   Repair inlet isolation  damper - TO hours.

         Problem:   Inlet isolation damper would not close.

         Cause:  Both push rod shafts were bent due to operation with
                 improperly adjusted jack screws.

         Corrections:  Replaced  both push rods, added  thrust  bearings
                 to the jack screws and installed heavy duty  limit
                 switches.

     5.   Align booster fan/motor shafts - l6T hours.

         Problem:   Excessive vibration in booster fan/motor shafts.

         Cause:  Gradual increase  in vibration  during  the early
                 summer high temperatures at  Mohave.   Motor and
                 concrete foundation were placed  during cooler
                 weather during  the fall of 1973  and expanded with
                 the temperature increase.

         Correction:  Realigned  the shafts and  measured the alignment
                 numerous times  to obtain and confirm  the proper
                 settings.

     6.  Repair inlet duct  turning vanes and scrubber hopper flange
         leaks -  38  hours.

         Fatigue  failure  which  caused  portions of a turning vane to fall
         off and  corrosion  failure of  two carbon steel hopper flanges
         required repair  work.

Turn Down Rat To

     The Horizontal Module was designed for a nominal  operating inlet
gas flow rate of ^50,000 SCFM.  This corresponds  to a  superficial
linear velocity of 21.6 ft/sec in the scrubber  shell,  based on  the
                                  371

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1 MW pilot plant tests.  Results of flexibility testing indicate the
scrubber can be operated satisfactorily over a wide range of inlet
flue gas flow rates.  The highest gas flow obtained to date has been
^kh,000 SCFM (S02 removal of approximately 9^%} and represents the
upper limit of the booster fan capacity.  The  lowest gas flow rate
tested has been 130,000 SCFM (91-^% SC>2 removal) and represents what
is believed to be equivalent to one-fifth of the lowest gas flow
rate (or load) at which one Mohave boiler unit would be operated.

pH Control

     The lime slurry feed rate to the reaction mix tank is auto-
matically controlled to maintain a constant slurry pH.  As antici-
pated, this automatic pH control method provides a very stable and
finely tuned chemical control system for the scrubbing system.
Results from the long duration material balance tests indicate that
the control system ensures both a high S02 removal and a high utiliza-
tion of the added lime under steady state conditions.  Results of
the shorter flexibility tests have demonstrated the pH control system
capable of "following" fluctuations in flue gas flow rate and inlet
S02 concentrations.

Closed Loop Water System

     The front and backend systems are integrated with the scrubber
to provide a closed loop water system.  This allows the makeup water
flowrate to be a function of flue gas flowrate (and S02 content) by
providing all internal water requirements with recycled water.  The
scrubbing system can thus be turned down to any desired capacity
while simultaneously turning down the makeup water flowrate to avoid
operating the system out of water balance.

     The makeup requirement at a flue gas flowrate of UiiO,000 SCFM
and 280F (averaged over 1036 hours of continuous testing) is 152 gpm.
82% of this total was cooling tower blowdown water and 18$ was service
water required for slaking and dilution of lime slurry.  93% of the
makeup water goes up the outlet duct as water vapor and the remainder
is water of hydration, interstitial water and evaporation which
cannot be reclaimed from the waste sludge disposal pond.  The
scrubber area is paved with concrete and provided with curbing.  All
seal water drips, hose washdown water, spills and pond supernatant
water are returned to the scrubber system to maximize waste water
utilization.  No water is put into the ground or the station peri-
pheral drainage system.

     The most critical part of the water recycle concept required
for closed loop operation is the source of pump and instrument seal
water.  The seal water requirement represents a flowrate of 50 gpm,
which is independent of flue gas flowrate or unit load.
                                  372

-------
     With high levels of dissolved solids in the makeup water, the
total dissolved solids in the scrubber slurry reach extremely high
levels - 15 to 20 weight percent.   The salts represented are largely
sodium chloride (NaCl), magnesium sulfate (MgSOlj) and sodium
sulfate
     Thickener overflow is filtered to provide the pump and instrument
seal water.  In spite of the high dissolved solids no severe chemical
scaling or corrosion has been observed.
                                  373

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PERFORMANCE
S02 Removal

     The S02 removal results of the full-scale Horizontal Scrubber are
compared in Figure 5 with data from the original 1 MW pilot plant
scrubber at the Mohave Station.  For both the pilot plant and the
full-scale test module, 90% SOp removal was achieved at a liquid to
gas contacting ratio (L/G) of about 17-5 gallons per 1000 SCF, using
four stages of scrubbing.  The degree of repeatability between pilot
scale results and full-scale results is noteworthy.  The performance
of the full-scale test module is slightly better than the pilot
plant at reduced L/G ratios.

     The criterion for the Mohave Station to be in compliance with
the Clark County SC^ regulations is equivalent to about 50 ppm at full
load.  The scrubber design criterion was established at an outlet S02
concentration of Uo ppm.  This criterion was met or exceeded by the
full-scale Horizontal Scrubber at 200 ppm inlet SC>2 concentration with
an L/G ratio (per stage) as low as 12.5 gallons per 1000 SCF.

     Percent SC>2 removal at various L/G ratios is shown plotted for
three different gas flow rates in Figure 6.  These results show more
efficient S02 removal at lower gas flow rates (and increased residence
time in the scrubber) as would be expected.  As mentioned earlier,
the Horizontal Module can be operated with any number of stages.
Figure 7 shows SC-2 removal efficiency as a function of the number of
stages and indicates that 90% SOp removal can be achieved with three
scrubbing stages at the specified conditions.

     The sulfur content of the coal burned at Mohave has averaged
0.38% which results in an average stack gas S02 concentration of
2CO ppm.  A recent coal survey of the Black Mesa mine field indicates
the highest coal sulfur content ever to be expected will be 0.&3%
which corresponds to approximately UOO ppm 862  Most of the original
pilot plant work was performed at this level and future plans are to
inject gaseous SOp to achieve this level for testing the Horizontal
and Vertical Modules.  A good estimation of the performance expected
from the Horizontal Module at ^00 ppm inlet S02 (and higher) can be
obtained from the results of SCE's Highgrove Generating Station 10 MW
Horizontal Scrubber Pilot Plant Experiment ("to test the feasibility
of scrubbing high sulfur oil-fired flue gas to the equivalent of low
sulfur fuel oil").  The Highgrove 10 MW scrubber design was based on
results from the high inlet S02 experiments performed on the Mohave
1 MW pilot unit, and is essentially identical to the ^50,000 SCFM
Horizontal Test Module with respect to operating parameters.

     Figure 8 presents a comparison of outlet S02 concentration vs.
L/G ratio of the 1 Ml-/ and 10 MW scrubbers at an inlet 302
                                 374

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                        FIGURE 5
          SO2 REMOVAL VS L/G RATIO
  COMPARISON 1 MW PILOT&170 MW MODULE
   100-
   95-
   90-
   85-
   80-
o
LLJ
   60-



   50-


   40-


   30-

   20-
   10-
    0-
170 MW HORIZONTAL
    MODULE
                                   1MWMOHAVE PILOT
                                             DD
                            RATED GAS VELOCITY
                            C 0.38% SULFUR COAL
                     10       15      20
                     L/G (gpm/1000 SCFM)
                                   25
30
                        375

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    100-
                          FIGURE  6
              SO2 REMOVAL vs L/G  RATIO

             170  MW  HORIZONTAL MODULE
LJJ
o
    95-
    90-
    85-
    80-
    70-
    60-
    50-
    40-
                                       460,000 SCFM
    30-
              0.38% SULFUR COAL
    20-
    10-
    o-
      o
5
10
15
I
20
25
                       L/G (gpm/1000 SCFM)
30
                       376

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concentration of ^CC ppm.  Again, the degree of repeatability between
the pilot and the 10 MW version is quite good.  From this plot we can
reasonably expect the It50,000 SCFM Horizontal Module to meet the
90% removal criteria (at UOO ppm_ inlet 862) with an L/G ratio (per
stage) of approximately 17-5 gallons/1000 SCF.

     Figure 8 also presents the curves for the pilot plant and 10 MW
scrubbers at the 1000 ppm inlet SOp level.  It is obvious that the
10 MW Highgrove scrubber performs much better than expected with
respect to L/G ratio.  The lower L/G ratio requirement for the High-
grove scrubber to achieve the same degree of removal as the pilot
plant was obtained by optimizing the placement and number of nozzles
in the scrubber chamber.

     Experiments with the pilot plant scrubber indicated that inlet
S02 concentration was an important variable in SOg removal.  Pilot
plant test results indicated a maximum 62 removal efficiency under
fixed operating conditions at UOO ppm inlet and a rapid decrease in
removal efficiency with increases in inlet SOp concentration above
kOO ppm.  The effect of decreasing removal efficiency above hOO ppm
was not as pronounced with the 10 MW scrubber as shown in Figure 9-
For the Highgrove scrubber the slight reduction in S02 removal
efficiency above 1600 ppm 862 can be minimized by either a small
increase in the L/G ratio or by the addition of a fifth scrubbing
stage.  Recent tests have been made at Highgrove utilizing five
steges of scrubbing at inlet concentrations as high as 3000 ppm.

Farticulate Removal

     An objective of the Horizontal Scrubber Test Program equal in
importance to S02 removal has been that of particulate removal down-
stream of the 9W efficient, cold-side, electrostatic precipitators
at the Mohave Station.   Since the ash content of the coal is
nominally 9%> the grain loading downstream from the precipitator is
nominally 0.07 g**/SCF, but varies with coal quality, unit load, and
operating conditions from 0.01 gr/SCF to perhaps 0.10 gr/SCF.

     Previous pilot plant results with the 3000 SCFM Horizontal
Scrubber indicated about 90% particulate removal at representative
grain loading conditions.  This result has been re-confirmed with
the full-scale Horizontal Module, operating above its design conditions
at a flue gas flowrate of 47*1,000 SCFM.

     Inlet and outlet particle grain loadings under constant scrubber
operating conditions are presented over a wide range of inlet grain
loadings in Figure 10.   As shown, the particulate removal varies
with inlet grain loading from 70$ removal at 0.01 gr/SCF to 98$
removal at 1.00 gr/SCF.
                                 377

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                  FIGURE 7
SO2 REMOVAL vs. No. OF SPRAY STAGES
     170 MW HORIZONTAL  MODULE
      100-
       90--
       80--
       70--
   1   60 +
    OJ
   o
      50--
       40--
       30--
OPERATING CONDITIONS
  460,000 SCFM
  L/G = 19.6
  SO2 INLET = 2IOppm
               NUMBER OF SPRAY STAGES
                378

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                    FIGURE 8
      OUTLET SO2 vs. L/G  COMPARISONS-
        1 MW MOHAVE PILOT AND 10 MW
             HIGHGROVE SCRUBBER
  1000-
  9 -
  8 -
  7 -

  6 -

  5
  4 - r
  \J
	 2-4-
 E
 a
^o.
 CN
o
CO
I
uu
j-j 100
ID  9 -
O  8 -
   7 -
   6

   5

   4 - -
   3 --
   2 -4-
   10-
                                 MW MOHAVE PILOT
vO
 a
          10 MW HIGHGROVE
       d
o
              1 MW MOHAVE PILOT
          10 MW HIGHGROVE
                              D
                             O
                               D
                                ON
                                    O
        AT RATED GAS VELOCITY
                                     O
                  10       15      20

                   L/G(gpm/1000 SCFM)
                 25
                    30
                       379

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     The increased particulate removal efficiency at higher inlet grain
loadings is undoubtedly due to the fact that at higher dust loadings
the stack gas is composed of larger diameter particles due to
precipitator sections being out of service.

     Particle size in the flue gas at Mohave are normally very small.
About 90 cumulative wt % of the particles are less than U microns
in diameter with 70 vt % less than 2.0 microns in diameter, Uo wt %
less than 1.0 micron in diameter and about 15 'wt % less than 0.5
microns in diameter.

     Fractional size collection efficiencies previously reported in
last year's EPA symposium for the pilot plant are compared below with
full-scale test results.

                             3000 SCFM              U7l*,000 SCFM
                       Horizontal Pilot Plant    Horizontal Scrubber

                         at an inlet grain         at an inlet grain
Particle Size          loading of 0.02 gr/SCF    loading of 0.08 gr/SCF

Greater than
1.5 microns                     97$                       92%

1.0 to 1.5
microns

0.5 to 1.0
microns                         87$                       85$

0.3 to 0.5
microns                         75f                       16%

Lime Utilization

     High calcium pebble lime delivered from Nevada indicated the
following average composition:

     CaO alkalinity as CaO
        (CaO, Ca(OH)2, and CaC03)                          95-5$

     Total alkalinity as CaO
        (CaO, MgO, Ca(OH)2, CaC03
       and other trace alkaline materials                 97-^$

     Lime utilization was calculated by three different methods over
an operating period from May 6 through May 25, 197^.  Other sources
of alkalinity entering the scrubber system were also taken into
account.  Chemical analysis showed that flyash and scrubber makeup
                                  380

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                                        FIGURE 9
LO
00
      i
      LLJ
      ex.
       CN
      o
      t/5
            100-
            90- -
            80- -
70- -
            60- -
              0
                      EFFECT OF  INLET  SO2 CONCENTRATION

                            ON PERCENT SO2 REMOVAL
                  D
                                                10 MW HIGHGROVE L/G = 20
     1 MW MOHAVE PILOT L/G = 20
     FROM MAY 1973  EPA PAPER
                                                 AT RATED GAS VELOCITY
       200
400
600
800
1000
1200
1400
1600
1800
                                       INLET SO2 (ppm)

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                  FIGURE 10
 INLET vs. OUTLET GRAIN  LOADING
   170 MW HORIZONTAL  MODULE
    3,0-
LO
o
z
g
LU
5
I
ID
U
     1.0- -
    0.3- -
     0.1- -
    0.03--
    0.01- -
   0.003- -
   0.001
                       O
                   O
                O
                                o
             AVERAGE OPERATING CONDITIONS:
               FLUE GAS FLOW = 474,000 SCFM inlet
                           584,000 SCFM outlet
              L/G = 20.6
     0.001          0.005  0.01          0.05

          OUTLET PARTICULATE LOADING(gr/SCF)
                 382

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water contributed respectively 1.17$ and 0.85$ of the equivalent CaC
fed to the system.  The three lime utilization determinations are
summarized as follows:

Method A:  CaO utilization (from.S02 removed from gas) = 99-75%

Method B:  CaO utilization (from unreacted CaO in sludge and material
           flowrates) = 99-^0$

Method C:  CaO utilization (from chemical analysis of sludge
           independent of material flowrates) = 99.27$

The average utilization for the three methods is 99-^7% which is nearly
stoichiometric.

Power Consumption

     The electric power consumed by the Horizontal Scrubber is metered
at the itl6o volt bus and includes transformer losses for voltage
less than itl60 volts, control room power and air conditioning,
scrubber lighting and miscellaneous welding and maintenance power
usage.  Kct included are the following usages of power:

     A.  Reheat steam at U0,000 Ib/hr, itOOF and 350 psig

     B.  Service air at ko SCFM, 90 psig

     C.  Electric power to operate sludge stabilization mixing
         equipment (k kW)

     The electric power usage was monitored during 556 hours of con-
tinuous operation.  The average flue gas flowrate during this period
was it51,000 SCFM.  The scrubber power consumption averaged 2.66 MW.
In general, flue gas flowrate per MW varies from station to station.
For the 790 MW Unit Two at Mchave, the flue gas flowrate at full load
is between 1.9 and 2.1 X 106 SCFM (at 60F and 1 atm).  Thus a flowrate
of it51,000 SCFM is equivalent to a range between 170 and 188 MW, and
the power consumption measured corresponds to a range between I.it2
and 1-57$ of the power generated.

Pressure Drop

     One important characteristic of a scrubber which contributes a
great deal to both the capital cost and the operating cost is the
pressure drop through the scrubber.  The pressure drop is, of course,
primarily a function of the design of the scrubber.

     As discussed in last year's EPA symposium, the Horizontal pilot
plant was characterized by a low pressure drop compared with the other
                                   383

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pilot plants.  Specifically Figure Hi of Ref.  1 indicated that the
pressure drop across the 3000 SCFM Pilot Plant Horizontal Scrubber
itself was 1.0 inches of water while Figure 19 indicated that the total
system pressure drop (at nominal conditions) anticipated for a
it50,000 SCFM Module System was 6 inches of water.

     In Figure 11, the total system flue gas pressure drop is plotted
versus gas flowrate at a constant L/G ratio.  As may be seen, the
total system pressure drop at ^50,000 SCFM is 5-5 inches of water.  This
may be compared to the 6 inches of water previously predicted.  The
total system pressure drcp is the differential pressure developed by
the booster fan as required to draw flue gas from the precipitator
outlet duct and drive it through the scrubber, deraister, reheat mix
chamber and outlet ductwork into the stack breeching duct.

     The test data in Figure 11 indicates that the total system pres-
sure drop under design operating conditions was approximately 6.0
inches of water.  The various scrubber components contributing to this
total are roughly as follows:

                                              Differential
                                             Pressure Inches
     Component                                 of Water	

     Inlet Ductwork                               1.0
     Scrubbing Chamber                            1.0
     One Demisting Stage                          0.5
     Indirect Reheating Chamber                   2.5
     Outlet Ductwork                              1.0

                                  Total           6.0

The pressure drop through the indirect reheating chamber is somewhat
high to insure complete mixing of hot and cold gas streams.
                                 38^

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                    FIGURE 11

        SYTEM PRESSURE DROP vs.

           FLUE GAS FLOWRATE

      170 MW HORIZONTAL  MODULE
    5--
o
o
o
Cf
o
2
LU

u


LU






g

(JL

CO


O

LU
    4-
                    O/
    3--
    2--
     FOUR STAGES OF SCRUBBING

      L/G RATIO = 22 gpm/1000 SCFM
    3--
     0
23456

 SYSTEM PRESSURE DROP

    ( Inches of Wafer)
                   385

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ACKNOWLEDGMENTS

     The experiments reported in this paper relating to the 1 MW and
10 MW scrubbers were sponsored by the Southern California Edison
Company.  Construction and Testing of the 1?0 MW scrubber was funded
by the Mohave Project and Navajo Project participants - Arizona Public
Service Company, City of Los Angeles Department of Water and Power,
Nevada Power Company, the Salt River Project, Southern California
Edison Company, Tucson Gas and Electric Company and the United States
Department of the Interior, Bureau of Reclamation with costs
allocated in accordance with their megawatt entitlements in the Mohave
Project and in the Wavajo Project.  The Salt River Project serves as
Project Manager for the Navajo Project while Southern California Edison
serves as Project Manager of the Mohave Project as well as Project
Manager for the Test Modules Program.

     The design, construction and operation of the Horizontal Module
required the efforts of many individuals and organizations.  The
courageous management decision tc build the Horizontal Module 150
times larger than the pilot plant was made by Mr. Tom Morong, Chief
Engineer and Assistant General Manager of the Salt River Project and
Mr. Jack B. Moore, Vice President of the Southern California Edison
Company.  Mr. Richard Durning of the Salt River Project made many
contributions, particularly in the design criteria and test planning
area.

     Stearns Roger, Inc. performed the engineering design according to
SCE design criteria and also procured the major equipment and provided
an engineer for test support.  The Bechtel Power Corporation performed
all construction activity at the Mohave Generating Station.  Routine
maintenance and design modification services have been performed
during the Test Program by Jesco, Inc.  Truesdail Laboratories has
also supported the test program with field chemists, and gas
s ampling c r ews.

     Many Edison personnel have contributed a great deal to the success
of this program; these include Messrs. B. C. Stowers and J. Harvey of
Construction Engineering, Mr. N. J. Dellaven of Generation Engineering,
Messrs T. L. Reed, R. L. Manley and C. Patel of Cost Schedule Engineering,
and Messrs. H. A. Kerry, E. A. Danko, S. D. Sharp, W. C. Martin and
R. B. Rolfe of Edison's R&D Organization.  Mr. G. L. Fraser, Station
Superintendent and Mr. R. Young of the Mohave Generating Station Staff
have successfully supervised the operation and maintenance of the
scrubbers.  The contributions of the SCE operators and foremen them-
selves cannot be overstated.

     Finally, Dr. L. T. Papay, Director of Research and Development
for Southern California Edison Company has served as Chairman of
the Coordinating Committee for the Wavajo/Mohave Test Modules
Program.  His encouragement and technical contributions are sincerely
appreciated.
                                 386

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REFLRJM'JCES

     Alexander Weir, Jr. and Lawrence T. Papay "Scrubbing Experiments
at the Mohave Generating Station" U. S. Environmental Protection
Agency's Flue Gas Desulfurization'Symposium, New Orleans, Louisiana,
May 111, 1973.
                                  387

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      OPERATIONAL STATUS AND PERFORMANCE OF THE LOUISVILE

             FGD SYSTEM AT THE PADDY'S RUN STATION7
     Mr. Robert P. Van Ness, Manager Environmental Affairs
     Louisville Gas And Electric Company

     November 4-7, 1974
     EPA, FGD Symposium, Atlanta, Georgia
                           ABSTRACT


     Operations at the Closed Loop Full Scale 65M'.\' SU7 System com-
menced in April 1973 and has operated in limited and extended modes
to date.  Absolute reliability of the system has not been esta-
blished; however, operations to date have been extremely satis-
factory and gratifying.  All data suggests high attainments of
S0_ and particulate matter reouirements without operational diffi-
culties such as scaling, plugging, and corrosion or errosion pro-
blems.  High degree of operational on time at varying loads with
various levels of sulfur coal input.  Extremely high removal rates
of efficiencies of SO- in 1974 with inoculations of varying amounts
of magnesium,   Stoichiometric requirements of the system have been
excellent.
                               389

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         OPERATIONAL  STATUS  AND  PERFORMANCE  OF  THE  LOUISVILLE
              FGD  SYSTEM  AT  THE  PADDY'S  RUN  STATION
       1  have  been  requested  to present  to  this  Symposium  a  status  report
 on  the operation of  the  Paddy's  Run  Unit #6  S0?  removal system  to  date
 and  the  current status of  the compliance program proposed  to meet  local
 air  pollution standards.

       Our  Ca(OH)?  (carbide lime)  slurry tail  end wet  scrubbing  system
 has  been described in detail by  both Combustion  Engineering Co.  and
 Louisville Gas & Electric  Co. in  previous  statements  and  in publica-
 tions.   So, in the interest of avoiding repetition,  L will  assume  that
 everyone is basically familiar  with the installation.  Lf  not  and more
 information is desired,  I would recommend  that you obtain a copy of a
 recent paper  presented by Messers. Martin, Plumley and Minor at  the
 National Coal Association Symposium on  "Coal  and the  Environment"  in
 Louisville, Ky. on October 23.  The paper  entitled "The C,  E. Lime Wet
 Scrubbing  Process  from Concept to Commercial  Operation" covers  in  con-
 siderable  depth the data, concepts, flow conditions and charts pertaining
 to  the system and  its operation.

      As a start,  flow diagrams of this system are enclosed (Exihibit A),
 for  your edification which basically shows the equipment and overall
 design flows  and enumerates the stages of  control of  the calcium bisul-
 fite and calcium sulfite reactions using a waste product known as  carbide
 lime additive.  Basically, the concept has been  to remove the S09  from
 the  flue gases by  the use of a liquid to gas  contactor such that the S0?
 is removed in a soluable form (calcium bisulfite) and Lo control the
 chemistry  so  that  the solid salts of calcium  sulfite and calcium sulfato
 are  not  formed in  the scrubber.   The former is a critical item in  that ir.
 tends to come out  of solution at a pll of about 6.2.  The sulfate formation
 is an oxidation reaction which must be controlled by various techniques
such as pH, time,  liquid  and  gas  flows,  and seed crystals.   The  control
concept and equipment have produced very satisfactory results.
                                   390

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      In our opinion the overall reliability  and  efficiency  of  this  SO-
removal system  to date has been good.   Starting in  April  of  last  year  the
unit was able to operate 70% of the  time  that the boiler  was available for
service through 9 months of 1973 and an availability of 98%  during the last
4 months of the year.

      The low 70% availability factor was for the most part  due to various
modifications which we chose to incorporate in the  system during  the early
periods of operation.  These changes include:
      (1) Modifications to the carbide  handling system by adding
          a Rietz Disintegrater which was installed to uniformly
          size  the carbide lime slurry  before it  enters the  system.
      (2) Modifications to the thickener circuit  to improve  settl-
          ing characteristics of the calcium  sulfite crystals by
          the addition of a flocculating system.  The flocculents
          used  in this system were Dow  A-23 and Betz 1100.   The
          best results were obtained with the latter.
      (3) Improvements to the top water washer in the demister
          system which was at the start of operations found  to
          be inadequate.
      (4) Various piping and pH control changes.

      Generally, the system has operated in a  satisfactory manner and  very
few problems have been encountered to date.   No major problems of scaling
or plugging have been encountered in this 9 month period.  Once we observed
a minor build up of calcium sulfite scale that occurred when the scrubber
was allowed inadvertently, in one instance, to run  at a pH above the critical
point of 6.2.   This scale was easily removed  by dissolving the crystals by
lowering the overall pH of the system and no  further build up or scaling has
occurred.   During these operations the SO  removal  efficiencies averaged from
80% to 90%.   The best operations were accomplished  on a general pH input of
approximately 8.  This 8 pH area of control was selected  to cover fluctuations
in SO  concentration in the flue gas when the boiler operated on varying sulfur
levels in the coal.   The overall range of sulfur in the coal  during these test
periods were in the range of 1.5% to something greater than 4%.   The particu-
late removal efficiency throughout these varying operating conditions fell
well below the standard of .05 grains/Scf.  Most of the data  was in the range
                                   391

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of .02 and .035 grains, thus, producing a particulate efficiency well in
excess of 99%.  The inlet gas to the scrubber contained a particulate load-
ing of about .2 to ,4 grains.

      The stoichiometric requirements of the system appears to approach
100% based on the total SO,, removed or approximately 80 to 90 percent
depending on the inlet SO- concentrations in the flue gas to the scrubber
system.

      As you are quite aware, this system has been operated in a closed
loop mode and has never been out of that mode during any of our operations
to date.  This requirement of the system obviously only allows a small
period of time to wash the demisters, since excessive use of wash water
would upset the water balance and thus open the loop.  Generally speaking,
this washing operation at approximately 200 GPM of river water, is utilized
8 to 12 minutes every 8 hours.  In the overall water balance, the only water
that is removed from the system is that water which goes out with the re-
heated flue gas to protect the scrubber fan, which is in the circuit between
the scrubber  and the stack, and the water that is removed from the system as
sludge from the filter circuit.   The moisture content of the filter cake,
which for our convenience is removed from the scrubber area by trucks, rather
than some other method, approaches 55 to 65 percent water.  This sludge is
conveyed to a borrow pit approximately a mile from the plant where the sludge
is mixed haphazardly with flyash to produce a rather solid landfill.  In order
that no one misunderstands, this is not in our opinion the best environmentally
acceptable approach to a chemical fixation reaction.  We feel that the sludge
coming off either the drum filters or the higher percentage moisture content
sludge from the thickener should be mixed with the dry flyash in the immediate
vicinty of the plant where lime or other types of additives are mixed so that
the resulting product can be pumped to the storage area.  The water and the
solids will then set-up in time to hopefully produce an environmentally accept-
able solid landfill.   By so doing,  the water is chemically bonded in the new
resulting solids thus protecting the ground water and eliminating uhe need to
transport water back into the scrubber system.   Much work remains in the deve-
                                   392

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lopement of an economically feasible and environmentally acceptable method of
waste disposal.

      When the unit is operating at full load the overall electrical load
demand on the system is basically equivalent to approximately 2.3% of the
output of the boiler.  This is accomplished by a relatively low liquid to
gas ratio in the entire system of 30 plus (15 to 18 per bed) and a pressure
drop on the overall system of 14 to 15 inches.  In future installations our
efforts  will be directed toward lower capital and operating costs.

      Obviously, from the above discussion we have operated the system to
date in a rather trouble free mode.  No major problems have existed or
have occurred which have been identified as general problem areas such as
corrosion, errosion, scaling, plugging, and maintenance difficulties.  For
the most part,  the dernister banks from a visual observation appear as clean
as they were when the system first went into operation last year.

      The system as you probably are aware has a bypass feature which has
worked extremely well under varying conditions.   In fact, other than total
bypassing of the system, it enables a proportioning of the gases for recycle
as the boiler load varies from time to time,  this provides extensive turn-
down capabilities which gives the system almost unlimited control.  To be
sure the use of recycle increases power requirements on lower load condi-
tions.

      After the operations were temporarily suspended in late December 1973,
a complete inspection of the system was made and very few areas of diffi-
culties were observed.  During this past summer, we used the system as the
boiler requirements occurred.  At no time during this period did any diffi-
culties occvr in the system.  During this running period, we changed the
operating mode to a degree in that a waste product, high in MgO, was inocu-
lated into the carbide lime slurry to evaluate the effects on the system
with increased levels of MgO.  This of course, was done because MgO appears
to have a greater effect on SO  removal rates than do the basic calcium hy-
droxides.  The main reasons for these inoculations was to ascertain if higher
                                    393

-------
levels of SO  removals could be accomplished.  The results were quite interest-
ing.  For the most part, the levels of SO  in  the flue gas to the scrubber
averaged approximately 2,000 ppm and the exit  SO  concentrations maintained
themselves well below 50 ppm.  Generally, we had no trouble in operating in
this mode.

      Overall, from this paper, it is obvious  that we have established some
very encouraging results, however, it would be impossible for us to state
that absolute reliability of the system has been established.

      Now to other areas:  Last year as required by the Clean Air Act of
1970, we submitted a complete compliance schedule for S0_ removal systems
for units requiring control at our plants known as Cane Run and Mill Creek.
This plan basically proposed that the Primary Ambient Standard would be
attained by July 1, 1977 and the Secondary Standard by July 1, 1979 or
somewhat later.  Obviously, this attempt did not satisfy the Clean Air Act
since it exceeded the guidelines in time, even though, we felt it to be a
very optimistic schedule.

      After considerable time and many lengthy discussions with various
regulatory bodies, the first phase of the plan was agreed upon and a
variance was granted us by the local air pollution board since the time
of completion extended beyond the limit of local regulations.  The en-
closed exhibit is a schedule of the installations included in the approved
compliance plan.  With this agreement in hand the next order of business
was to request authority to expend funds by obtaining a "Certificate of
Convience and Necessity" from the Public Service Commission of Kentucky.
Initially the KPSC had granted a certificate on a new source boiler of
425 MW at Mill Creek Unit #3 which is scheduled for operations in early
1977.  The next three units in the plan were units which would be retro-
fits, known as, Cane Run #4, #5 and #6.   Initially, Cane Run #4 was re-
quested followed by a request for Cane Run #5.  In late 1973 a formal
hearing was held on Cane Run #4 with a decision by the Commission on
March 20 of this year.  This order granted the Certificate of Convience
and Necessity for Cane Run #4 but delayed any further consideration on
                                    394

-------
other units until Cane Run #4 had been installed and had successfully
operated for one year.  Thus, the dilemma of non-compliance of the plan
until some undetermined time  frame beyond the sacred date of July 1, 1977.

      In order to better clarify our position, we requested the KPSC for a
rehearing of their order.  At this rehearing in May and June, intervenors
testified.  They included the Environmental Protection Agency, the Edison
Electric Institute, The Mayor of Louisville, the County Judge of Jefferson
County, the Air Pollution Control District of Jefferson County, the Kentucky
Department of Natural Resources and Environmental Protection, and Action for
Clean Air (a local environmental group).  As of this date, in late September,
when this report is being written, we have had no ruling by the KPSC.  However,
in the meantime, as you can see from the approved compliance plan as noted in
exhibit B we have exceeded some of the progress dates in the actual plan.  In
short, we have an enforcement order from the Air Pollution Control District of
Jefferson County to proceed, but can not proceed until Public Service Commission
approval is received.
                                    395

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                                                                                                   EXHIBIT  A
                                    Cat t* Hoc*
     Cm ra
     4 Ho
u>
   JTO.OOO ei>
   Cl 3S5 f >,
   Cc
       p^

Co*nmintiror I



  -O-J
  J.IOO c'

pM.4 ??OO{
                       BlOO Cd'n
                      srt.4 ov
                     SC'dM'
                     *'/. 0
Sc/^brf
drain pifre
                                       T Mxwm film
                                                                          400 r< oaltf (lolol)
                                                                          pH*6 or ft'Cftr
                                                          5H.6J
                                                           kkh
                                                                                                         To
{(Wltr
...
1

' ,M.
J

K5-J.SU.

4030$et/tcgbBr pH93


95 40SOp"./,c.vbb,r

yJoVr^w-NH' ?' "*" '*" 20 ,pm ltoro.1
* M'0m COM') | . |


















A
*

7*
pH *u:ifoc ^ 	 "
o

                                                                                           ?'*'" i    *00 m (IOIOII
                                                                                             '       4SO rip acK
                                                         L EMIxtnl

                                                        ^ O.xllo- 
                                                                                                                              4600 lt>/>" dry Co (OH),
                                                                          c^ffl      H
                                                                                                  Pump
                                                                                                                                         50 1 ioi'0/o<
                                                                C-E AIR-QUALITY CONTROL SYSTEM
                                                                LOUISVILLE GAS &  ELECTRIC COMPAKY
                                                                PADDY'S RUN NO. 6 SCHEMATIC
                                                                FLOW DIAGRAM

-------
                                                                           EXHIBIT A
Overflow and effluent water

Clarifier discharge
                                                               Voouum filter Ihp
                                                               Flapper, 2 hp
                                                               Agnator, l hp
                                         Connection
                                         for air flow
                                                                                                     Conveyor, l-jphp

                                                                                               To atmosphere
                                                                           Overflow weir ond drnin
Underflow pump,5 hp
pH 6.5,25% slurry
80 gpm (total)
                                         C-E AIR-QUALITY  CONTROL  SYSTEM
                                         LOUISVILLE GAS & ELECTRIC  COMPANY
                                         PADDY'S RUN NO.  6 VACUUM-FILTER SCHEMATIC

-------
                                                                                          EXHIBIT
 Cane Run #4


 Cane Run #5


 Cane Run #6
GJ

MU1 Creek #3 (Approx.)
                                             Louisville Gas  and Electric Company


                                                        Appendix VI


                                         Sulfur Dioxide Removal System Installation


                                              Proposed Construction Schedule*
                                                                                                          Completion of
Order
Equipment
5-20-74
5-20-74
9- 1-74
3-27-74
Start Construction
9-20-74
12- 1-74
2- 1-75
6- 1-75
Construction
Completed
3-1-76
8-1-76
4-1-77
4-1-77
Start-up Date
4-1-76
9-1-76
5-1-77
5-1-77
Start-up Period
& Compliance By
6-1-76
11-1-76
7-1-77
7-1-77
           The above schedule is predicated on manufacturers'  current  delivery  estimates and does not consider
 potential time loss due to strikes, material shortages or other unforeseen developments beyond the control of the
 Company.
 *Revised as of 3/21/74

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  DISPOSAL OF BY-PRODUCTS FROM

    NON-REGENERABLE FLUE GAS
     DESULFURIZATION SYSTEMS
          A STATUS REPORT
                   by
               J, Rossoff
             R.  C. Rossi
            L.  J.  Bornstein
    Environment and Urban Division
      The Aerospace Corporation
        El Segundo,  California
                  and

             J. W. Jones
      Control Systems  Laboratory
 U.S. Environmental Protection Agency
Research  Triangle  Park, North Carolina
            Presented at the
   EPA Control Systems Laboratory
Symposium on Flue Gas Desulfurization
           Atlanta, Georgia
         November 4-7, 1974
                399

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      This paper has  been reviewed by the Environmental Protection
Agency and approved  for presentation.  Approval does not signify
that the contents necessarily reflect the views and policies of the
Agency,  nor does mention of trade  names, commercial products, or
commercial processes constitute endorsement or recommendation
for use.
                            CONTENTS
                                                             re
     1.0  Introduction                                     402
     2.0  Summary                                        403
     3.0  Potential Water Pollution Problems               406
     4.0  Potential Land Reclamation Problems             414
     5.0  Potential Disposal Problem Solutions             422
     6.0  Disposal Cost Estimates                         430
     7.0  Shawnee Sludge Disposal Field Demonstration     441
     8. 0  References                                      442
                                   400

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                  DISPOSAL OF BY-PRODUCTS FROM
    NON-REGENERABLE FLUE GAS DESULFURIZATION SYSTEMS
                          A STATUS. REPORT
                                  by
                             J. Rossoff
                             R. C.  Rossi
                           L. J.  Bornstein
                   Environment and Urban Division
                      The Aerospace Corporation
                        El Segundo, California
                                 and
                             J. W.  Jones
                     Control Systems  Laboratory
                U.S.  Environmental Protection Agency
               Research Triangle Park, North Carolina
                             ABSTRACT
         A summary of an on-going Aerospace Corporation  study for the EPA's
Control Systems Laboratory to characterize flue  gas desulfurization sludges
and to assess methods for their environmentally sound disposal is given.
The sludges  studied were selected from non-regenerable scrubber systems
using lime or limestone as the  absorbent at several Eastern and Western
coal-burning power plants.  Chemical analyses have shown  that untreated
sludge liquors contained  mercury,  selenium,  boron, chloride, sulfate,  and
total dissolved solids  considerably in excess of water quality criteria (most
of the  constituents  of concern,  which without scrubbing are  discharged in
the fly ash and flue gas,  originate in the coal).  Since soil attenuation of
selenium,  boron,  and chloride  is known to be ineffective, and since the
remaining sludge liquor constituents prevent direct discharge to streams,
the need for  environmental control of sludge disposal sites is strongly
indicated.  In addition, the water-retentive properties of raw (untreated)
sludge oresent land reclamation difficulties.  Currently available disposal
methods include landfilling of sludge (which has been chemically treated
for strength  and the prevention of leaching of undesirable constituents to
water  suoplies), and disposal of untreated sludge in oonds (lined with  highly
impermeable materials).  Estimates  from various sources  indicate disposal
costs of from $2 to $9/ton for chemical fixation and from $Z. 50 to $4. 50/ton
for ponding,  excluding oossible subsequent pond  reclamation costs.   An
average disposal cost of  $5/ton is equated to  1. 1  mills/kwhr.  Other less
developed disposal techniques include  drying,  and conversion to gypsum.
                                   401

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       DISPOSAL OF  BY-PRODUCTS FROM NON-REGENERABLE
     FLUE GAS DESULFURIZATION SYSTEMS - A STATUS REPORT

1.0  INTRODUCTION
The Aerospace Corporation sludge disposal study discussed in this paper
is in its second year of a two-year program which began in November
1972 under EPA Contract 68-02-1010.   The results of the first year's
                                             1
work is described in detail in an initial report .   This  paper up-dates
that work in a summary form.
Sludge samples have been obtained from the EPA/TVA Shawnee limestone
and lime prototype scrubbers, the Southern California  Edison Mohave
Station limestone  pilot scale scrubber,  and the General Motors  Parma
facility  double alkali scrubber.  The major portion of the analyses of all
these samples has been  completed except for  the double alkali samples.
Additionally, technical and economic assessments are  being made of
power plant and commercial processor operations being  conducted to
develop environmentally sound sludge disposal techniques.  Chemically
conditioned sludge samples from  some  of these sources, namely,  Chemfix,
IU Conversion Systems, and Duquesne Light Company which uses  a Dravo
Corporation additive have been received and are  being  analyzed.  Reviews
are being made continually of state and federal standards which govern
water quality and  the potential land disposal of sludges.  Present plans
by the EPA are to expand the Aerospace study to include the sampling of
sludges from four other scrubber systems to  increase  the data base being
established in this study.
A sludge disposal field demonstration program of untreated and treated
sludges is  being initiated by the EPA at the TVA Shawnee site in Paducah,
Kentucky.  Analyses of sludges, leachate, and ground water from that
site will be conducted  during the next two years in the Aerospace program
and will be integrated  with  the Aerospace study data and  other data as
appropriate.
                                     402

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2.0   SUMMARY
In this study,  sludge samples have been analyzed from three scrubbers
involving lime/Eastern coal,  limestone/Eastern coal and limestone/
Western coal.  Additionally, two sludges from other scrubbers (limestone/
Western coal and lime/Eastern coal) were analyzed in another study for
the U.S. EPA National Research Center,  Corvallis, Oregon (EPA Research
Grant R802853-01-1) and assessed as a part of the total program.  Chemical
characterizations  of the sludge liquors were performed to identify the  con-
centrations of nine trace metals of interest and  seven  major soluble species,
as well as the pH and total  dissolved solids (TDS) for each of the  samples
collected.   (Input materials such as coal, fly ash,  make-up  water,  lime
and limestone were also characterized to identify source of  constituents
found in the sludges).   A preliminary assessment was made of these
samples with  regard to any potential environmental problem that  might
be posed if these sludge liquors entered water supplies.  This assessment
was made  by comparing the chemical characterizations with the criteria
established by the  states,  the U.S.  Public Health Services Drinking Water
Standards  - 1962,   and the  EPA Proposed Public  Water Supply Intake Criteria
October 1973,   The latter  criteria were used in the final analysis at this
stage of the study.
In assessing the potential impact of trace metals, it was found that in each
of the sludge liquors at least one of the following trace metals exceeded
the EPA prooosed  criteria:  arsenic,  cadmium,  chromium,  lead,  mercury,
and selenium.   Except  for mercury and selenium,  these trace metals
exceeded the criteria by not more than a factor  of 5.  Mercury and selenium
exceeded the criteria in each of the sludges analyzed by more than  an
order of magnitude.  Comparing the concentrations of the major soluble
soecies with the criteria,  it was found that particular  excesses exist
for chloride,  sulfate and TDS for each of the samples  analyzed.   To date,
only one sample has been analyzed for boron, which was also found to  be
in excess.  It should be noted that most of the constituents of concern,
which without scrubbing are discharged in the fly ash and flue gas,
originate in the coal.
From the assessment just described, it appears that in all of the power
plant sludge liquors analyzed,  water quality  criteria are appreciably
exceeded for mercury,  selenium, boron,  chloride,  sulfate and TDS.
Attenuation of chemical species by soil is widely accepted in many  land

                                    403

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disposal oractices; however, attenuation of three of the species discussed
above, namely, selenium,  boron and chloride is known to be ineffective.
Therefore,  the concentrations of these three  species strongly indicate
that environmentally  sound techniques such as lined ponds or chemical
fixation are needed for scrubber sludge disposal.
Detailed physical characterizations of various samples have also  been per-
formed under the Aerospace Corporation study to determine properties
such as:  ease of dewatering/settling, bulk density,  viscosity,  load bearing
strength and oermeability.  Some significant  results relating to land-use
capabilities are as follows: scrubber sludges are highly water-retentive
and have little or no  bearing strength as produced;  they are thixotropic;
they can be  dewatered and/or compacted to produce appreciable bearing
strength and low coefficients of  permeability, but after being dewatered,
they easily rewet in the presence of water.
A sulfite  sludge  can be dewatered in a thickener to between 35 and 45
percent solids and will not increase its solids content significantly by
settling; however, when allowed to drain freely, its solids content will
increase to  about 50  percent.  A filter or centrifuge will produce  a solids
content of about 50-55 percent.  In contrast a sulfate  sludge which can be
dewatered to 35-45 percent solids in  a thickener, will increase  its solids
content to about 65 percent upon settling, and when  freely drained or cen-
trifuged,  will dewater  to about 75 percent solids.  It can be dewatered to
about 80 percent solids by filtration.
A better comparison of physical properties can be made when sulfite and
sulfate sludges containing equivalent  moisture content are compared.   For
example,  at  65 percent solids content,  sludges will support personnel,
and at solids content greater than 70  percent,  sludges will support heavy
equipment.   A settled sulfate sludge can be easily compacted such that it
will readily support personnel and equipment, but sulfite sludges  by com-
parison are much more difficult to dewater to the required degree of
dryness for compaction.
From the preceding discussion,  it appears that raw sludges or raw sludge
ponds which  have been  dewatered could be used for  structural purposes.
*  Sulfite and sulfate sludges described herein apply specifically to TVA
   Shawnee  and S.C. Edison Mohave pilot plant sludges defined in Figures
   1, 2 and 3.

                                     404

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However, the cost of dewatering the sludge and maintaining the site at
the necessary degree of dryness is strongly dependent on the  raw sludge
properties,  and may or may not compare favorably with the cost of an
alternative  disposal technique such as chemical fixation.  Data  from
chemical fixation processors indicate  that treated sludge quickly attains
a compressive strength above the  limit for hard clay or compacted fine
sand as defined in the Uniform Building Code.  This conditioned sludge
would have  the capability to make  a disposal site  reclaimable  for either
structural or recreational use.
Based on the sludge properties just described,  the best practical methods
currently available for sludge disposal are ponding,  and chemical fixation
for landfilling.  Ponding which may be environmentally sound with  regard
to water quality consists of lining  the  containment basin with an impervious
material  such as  clay,  plastic or  rubber to prevent the seepage of  sludge
liquors to water  supplies.  There  are  certain problems attendant to this
approach which are still being considered; these include the inability of
the liners to last indefinitely and the difficulty of  reclaiming the land after
the site is abandoned.  A more technically sound  approach is  that offered
by industry  in which the material is  chemically conditioned so that leaching
of undesirable  constituents is  minimized and  the material can be easily-
used to oroduce a structural landfill.
Preliminary cost estimates of these disposal alternatives, assuming a
sludge consisting of 50 percent solids, place  the cost of ponding in the
range of $2. 50 to $4. 50 per ton.  Some additional cost to provide per-
manent environmental protection or  land reclamation if desired may be
incurred at  the end of the service  life  of the pond.  The cost of  disposal
by fixation currently is  quoted in the range of $2. 00  to  $6. 00 per ton by
the fixation  processors  and approximately $7. 50 to $9.00 per  ton by power
companies performing  their own disposal task.   The cost of ponding
appears  to be about half that of fixation; however,  ponding is not neces-
sarily a permanent disposal technique.
A disposal cost of $2. 50 per ton, in  terms of power  produced, is equivalent
to 0. 56 mills /kwhr; $5. 00 per ton  is equivalent to 1 . 1 2 mills /kwhr.  This
example is  based on the use of a limestone scrubber,  85 percent
   All costs quoted herein are on a wet sludge basis.
                                       405

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SO  removal,  1.2 CaCCX/SCX  mole ratio,  50 percent solids sludge plus
ash at a station burning coal that has 3 percent sulfur and 12 percent ash,
at 0. 88 Ib/kwhr.
3.0   POTENTIAL, WATER  POLLUTION  PROBLEMS
3. i   WATER QUALITY
The  disposal of scrubber sludges presents  potential water pollution and
land reclamation  Problems  because of soluble species and dewatering
difficulties.  The  measure of those problems is defined by authoritative
water  quality standards and solid waste disposal regulations,  or by judg-
ment of regulatory officials when standards are nonapplicable or non-
existent.   The  most nearly applicable water quality  criteria that exist
for determining the environmental  acceptability of sludge disposal are
given in Table  1.   This table shows the water quality criteria of the U.S.
Public Health Service (USPHS) -  1962 Drinking Water Standards ,  the
1973 State of Illinois criteria (an example of one of the more compre-
hensive of all state criteria) for both public and food processing water
supply (PWS) and  water effluent discharge standards - and the  1973 EPA
                                    4
Proposed Criteria for Water Quality .
Regarding the quality of surface waters,  it should be noted that all states,
in conformance with  Federal EPA guidelines, do not consider dilution of
an effluent as an acceptable method of treating wastes in order  to meet
the effluent standards.   Regarding  the quality of underground waters,  in
general, states which do not have specific regulations concerning the
quality of underground water apply  stream or drinking water standards
to underground water for lack of more definitive regulations.  One state
which  does regulate underground waters is  Illinois,  which requires that
underground waters that are a  present or potential source of water for
public or food processing supply shall also  meet the standards  for those
supplies.
Standards  for the  regulation of solid waste disposal, as related  to water
quality,  are much less specific than water quality criteria.  Regulations
ordinarily limit the disposal of toxic,  hazardous, and harmful substances
by requiring that  those materials not be disposed of on the ground, or
underground, without the approval of a designated authority such as the
State Department  of Health, the State Health  Commissioner, County
Health Commissioner,  or the State Department of Commerce.   The
                                   406

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                     TABLE   1.    WATER  QUALITY  CRITERIA
                                             CONCENTRATION, ppm

ARSENIC
BORON
CADMIUM
CHROMIUM (total)
COPPER
LEAD
MERCURY
SELENIUM
ZINC
CHLORIDE
FLUORIDE
SULFATE
TDS
PH
USPHS - 1962
DRINKING
WATER
STANDARDS
0.05
--
0.01
--
1.0
0.05
--
0.01
5
250
2. 4 AT 50 F
1.4 AT 90 F
250
500
--
ILLINOIS - 1973
PUBLIC AND FOOD0
PROCESSING
WATER SUPPLY
0.01
1.0
0.01
--
0.02
0.05
0. 0005
0.01
1.0
250
1.4
250
500
6.5-9.0
EFFLUENTb
DISCHARGE
STANDARDS
0.25
--
0.15
--
1.0
0.1
0. 0005
1.0
1.0
--
2.5
3500C
5 - 10
EPA PROPOSED
PUBLIC WATER
SUPPLY INTAKE
OCT 1973
0.1
1.0
0.01
0.05
1.0
0.05
0.002
0.01
5.0
250
--
250
NO LIMITd
5.0-9.0
 Point at which water is withdrawn for  treatment and distribution
 Based upon 24-hour composite sample.   No contaminant  shall at any time exceed five (5) times
 the concentration limit
cNot more  than 750 ppm above background concentration limits unless caused by pollution
 abatement practices
  No  limit" indicates that insufficient data existed for prescribing  limits

-------
survey undertaken to date indicates that those offices, when judging the
disposal of sludges, base their judgment on sludge quality as related  to
the local or state water quality criteria'.
The limitations imposed on  sludge  disposal have been further intensified
by the recent  oassage of legislation and the potential passage of others.
For example,  the Federal Water Pollution Control Act Amendments of
197Z  essentially require the revision and  re-aoproval of all state water
quality standards: to  change applicability from interstate waters to all
waters, to prohibit or  limit direct  discharges of pollutants  to streams,
to limit subsurface disposal, and to include Federal E PA-prescribed
criteria for specific toxic elements. Additionally, the federal  drinking
water standards are being revised,  and legislation is  in process to develop
new limitations for the land disposal of solid wastes.
3.2   SLUDGE SAMPLING
Sludge samples analyzed to  date were taken from three scrubbers  at two
different power plants  representing both Eastern and Western coals and
the lime and limestone processes.   These are: EPA/TVA Shawnee TCA
scrubber with  limestone,  EPA/TVA Shawnee Venturi  scrubber  with lime,
and Southern California Edison (SCE) Mohave TCA pilot scrubber with
limestone.  Additionally,  sludge liquors from two  other plants  (an Eastern
utility plant lime  scrubber,  and a Western utility plant limestone scrubber)
have been  characterized in a separate study for the EPA NRC,  Corvallis,
Oregon,  and assessed along with the data  determined  in this program.
Samoles were  taken at various  points within the scrubbing system  so  that
the fate of trace elements and major species  of interest could be "observed1'
as they  passed through the system.  In  addition, samples of process
ingredients -- coal, process water, fly ash,  lime, and limestone  -- were
taken to identify the source of the elements entering the system.  Samples
were taken over a short period of time  in  an  attempt  to minimize the
effect of system fluctuations.
3.3   CHEMICAL CHARACTERIZATION
Chemical analysis of the sludge samples  consisted of  the determination of:
                                     408

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a) magnesium and trace metals by atomic absorption spectrophotometry,
b) calcium by wet chemical methods, c) sulfate by turbidimetry, and
d) chloride, fluoride,  and sulfite by specific ion electrode.  Results of
these analyses are presented in Tables 2 and 3 for the various power
plant sludges analyzed.  In each case (except for  Plant A), the analysis
is for the liquor fraction of the sludge representing the condition in which
the sludge is likely to be disposed, e.g., clarifier underflow,  filter cake
or centrifuge cake  (Plant A liquor is scrubber effluent and does not rep-
resent actual disposal material).
Since these analyses represent sludge liquors from a variety of scrubber
systems,  certain qualifications must be made for accurate interpretations
of the data.  Four principal system conditions influence the concentrations
of soluble species in system liquors.  The first is the  "tightness" of the
scrubber  system liquor loop.  The tighter the system, the less liquor is
lost with the discharge from the recirculation system to the disposal
area.  Consequently,  less make-up water is required and less dilution
is oossible.  An example of the effects  of this condition can be seen in
Table 3 where  it is shown that the concentrations of chlorides and TDS
in the SCE Mohave liquor are at least an order of magnitude greater than
those in the Plant A liquor.  The Mohave pilot scrubber had a tightly  closed
loop system, whereas the Plant A scrubber was running open  loop and
consequently experienced a high degree of liquor  dilution.
If it were theoretically possible to dewater the  sludge solids completely
and  return all liquor to the system,  no  make-up water would be required
for water balance except to make-up for evaporation.  Soluble  species
would build up  in concentration until they reach a saturation level resulting
in precipitation and subsequent removal with  the solids. From the point of
view of minimizing the volume of waste material, an absolute separation of
solid and  liquid might aopear desirable, but from the point of view of a
reliable system operation,  an excessively tight liquor  loop could present
major difficulties  in the operation of the system.  In practice,  disposal
of liquor with solids is not only necessary but unavoidable.
The second principal system condition that can affect the concentration of
soluble species is related to the operational  differences in scrubbing  flue
                                    409

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                          TABLE  2.    TRACE  METALS  IN  SLUDGE  LIQUORS*
                                              (concentration in ppm )
SCRUBBER
SIZE, Mw
PERCENT
SOLIDS IN
DISCHARGE
ARSENIC
BERYLLIUM
CADMIUM
CHROMIUM (total)
COPPER
LEAD
MERCURY
SELENIUM
ZINC
PH
TVA SHAWNEE
LIME
10
50-55
0,02
< 0.002
0.10
0.03
< 0.002
0.05
<0.001
<0.02
0.08
9
TVA SHAWNEE
LIMESTONE
10
35-40
0.20
0.01
0.005
0.15
0.02
0.1
0.06
0.30
0.30
8
SCE MOHAVE
LIMESTONE
<1
75-80
0.03
<0. 001
0.05
< 0.005
0.08
0.01
0.0012
0. 12
0.12
7
PLANT Ac
LIMESTONE
(western coal)
>100
15
< 0.004
0.18
0.01
0.21
0.20
0.02
0.12
2.5
0.12
4
PLANT B
LIME
{eastern coal)
>100
35-40d
0.085
0.012
0.023
0.040
0.048
0. 18
0.045
0.80
0.09
9
WATER QUALITY
CRITERIA
EPA PROPOSED
PUBLIC WATER
SUPPLY INTAKE
OCT 1973
0.1
--
0.01
0.05
1.0
0.05
0.002
0.01
5.0
5 TO 9
 All sludge  liquor samples, except those from SCE Mohave,  contain significant amounts of  fly ash
 Equivalent  to  mg/l
cPlant A sample  is scrubber effluent and does not represent  actual disposal material
 An undertermined  amount of  clarifier overflow liquor  is discharged from this system,
 making  the effective percent  solids in discharge  somewhat lower than value shown

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                       TABLE  3.    MAJOR  SPECIES  IN  SLUDGE  LIQUORS'
                                           (concentration in  ppmb)
SCRUBBER
SIZE, Mw
PERCENT
SOLIDS IN
DISCHARGE
CALCIUM
MAGNESIUM
BORON
CHLORIDE
FLUORIDE
SULFATE
SULFITE
TDSf
TVA SHAWNEE
LIME
10
50-55
2520
25
40.8
5000
3.3
800
0.9
9000
TVA SHAWNEE
LIMESTONE
10
35-40
1600
600
_e
2500
3,4
2000
110
7000
SCE MOHAVE
LIMESTONE
<1
75-80
1400
_e
_e
30, 000
3.1
2500
<0. 1
70, 000
PLANT Ac
LIMESTONE
(western coal)
>100
15
700
6
_e
1400
0.6
1150
<0. 7
3500
PLANT B
LIME
(eastern coal)
>100
35-40d
1400
410
_e
2700
2.6
2250
20
7000
WATER QUALITY
CRITERIA
EPA PROPOSED
PUBLIC WATER
SUPPLY INTAKE
OCT 1973
--
__
1.0
250 .
--
250
__
NO LIMIT9
 All sludge  liquor samples, except those from SCE Mohave,  contain  significant amounts of fly ash

K
 Equivalent  to mg/l


cPlant A sample is scrubber  effluent and does not represent actual disposal material


 An undertermined amount of  clarifier  overflow  liquor is  discharged  from this system,  making
 the effective  percent solids in  discharge somewhat lower than value  shown
 'To be  determined
f
 Includes other soluble  species (e.g.,  sodium and  potassium)


a"No  Limit"  indicates that insufficient data existed for prescribing limits

-------
gas from Eastern and Western coals.  In all cases, the solids content of
the waste bleed stream from the scrubber loop is typically  10 percent
^solids  contents from 8 to 1 5 percent have been measured and appear to
depend  on the presence of fly ash in the liquor and system design variables
associated with relative liquor holding capacity).  However, for  equiva-
lent system operation and equivalent sulfur scrubbing efficiency,  the
sludge production rate (and therefore the sludge bleed rate,  excluding
ash) from the scrubber recirculation loop for low sulfur Western coal is
considerably less than that for a high sulfur Eastern coal.   Therefore,
less occluded liquor would be  bled from  the Western system than the
Eastern system.  Since absorption of soluble species takes  place with
each liquor pass through  the scrubber,  and since the  scrubber liquor
"residence time"  is greater in the Western coal system, the  concentra-
tion of soluble  species is greater.  The ratio of the lowest Western coal
sulfur content to the highest Eastern coal  concentrations analyzed and
reported here is 1:8 which implies  that the scrubber loop liquor  residence
time is  about 8 times longer in this  low sulfur system (see  TDS for
Mohave pilot and Shawnee liquors in Table 3).  This is an extreme condi-
tion which compares an Eastern high sulfur coal sludge which includes
fly ash,  with a Western coal sludge  that  contains an insignificant amount
of fly ash.  If fly ash had been  collected  along with SO? in the Mohave
scrubber, this effect of sludge liquor extended residence time would not
have been as pronounced.
The  third principal  system condition affecting the concentration of soluble
species pertains to  the system design for  collection of fly ash.  Most of
the trace metals in  the sludge originate from fly ash simultaneously
scrubbed from the flue gas; therefore, the scrubber systems that do not
collect fly ash  should be expected to have  significantly lower concentra-
tions of trace metals than those systems that do collect fly  ash.
The  fourth principal, system condition affecting  the concentration of soluble
species is the pH  at which the system operates.  For example, the lime
scrubbing orocess operates at a higher bleed pH than the limestone process.
                                      412

-------
As a consequence, the soluble element content in lime sludge liquors
appears  to be consistently lower than the same element content in lime-
stone scrubbing systems.   This trend  can be most easily seen when
comparing the lime and limestone systems at Shawnee where input flue
gases are generated from the same boiler (see Table 2).  In each  case,
the concentration of trace elements in the lime system is less than that
in the limestone  system.  These data suggest that  the more environmentally
acceotable sludges (from the point of view of soluble trace  metals in sludge
liquors)  are  those disposed of at the high pH more typical of lime  scrubbing
systems.
Preliminary correlation between  the soluble element content of the sludges
and their concentrations in coal has  been made.  Arsenic,  lead, and
mercury are found in  higher concentrations in Eastern coals than  in
Western coals, and thei-r concentration in Eastern power plant sludges
generally is  also higher.  Similarly, Western coals have higher concentra-
tions of copper and selenium and  these elements  are generally found in
greater concentrations in Western power plant sludges.
3.4  ASSESSMENT
The environmental acceptability of sulfur sludge liquors can be assessed
by the comparison of the analyses determined on actual sludges presented
in Tables 2 and 3 with the water quality criteria of various regulatory
agencies presented in Table 1.  For the trace metals  (see Table 2), all
elements analyzed except copper  and zinc exceed water quality criteria
in at least one power plant.  The  remaining trace elements, except mercury
and selenium, exceed the criteria by not more than a factor of five,  with
one exception (cadmium - Shawnee lime).  Mercury and selenium  exceed
these criteria for each of the power  plants,  and the excess  is greater than
an order of magnitude.
Comparing Tables 1 and 3 for major soluble species,  it is  seen that water
quality criteria are  surpassed in  several cases.  Particular excesses
exist for chloride, sulfate and total dissolved solids for each of the power
plants.   Boron is  in excess based on the one sample analyzed so far.   The
                                    413

-------
values for sulfate ions for any given plant will not vary too widely from
those given here because they are controlled by the chemistry of the
scrubbing system.  On the other hand,  the chloride ion and total dissolved
solids values can vary by an order of magnitude or  more and  are depen-
dent on factors  such as "tightness" of the looo, coal composition, and
sludge bleed rate.
Summarizing the above comparisons of trace metals and soluble species
against water quality criteria, in all of sludge liquors  analyzed,  water
quality criteria were appreciably exceeded for mercuy, selenium,  boron,
chloride, sulfate and TDS.  It should be noted  that most of the constituents
of concern, which without scrubbing are discharged in the fly ash and flue
gas, originate in the coal.  Attenuation of chemical species by soils is
widely accepted in many disposal practices.  However, soil attenuation
of selenium, boron, and chloride is known to be ineffective.   Therefore,
even if excessive concentrations of other constituents were acceptable
because of soil attenuation effects, the  presence of  these three species
in concentrations in excess of water quality  criteria strongly  indicates
that environmentally sound techniques  need to  be  employed for scrubber
sludge disposal.
4. 0   POTENTIAL LAND RECLAMATION PROBLEMS
4. 1   LAND USE CRITERIA
Criteria identifying  the load suoport limits to be attained on top of a filled
sludge pond for eventual use as structural or recreational land are not
included in either the  state solid waste  disposal regulations or building
code requirements.   However,  the Uniform  Building Code  shows that the
range of allowable soil pressure for building construction is from Z441
kg/sq m (500 psf) to 39, 064 kg/sq m (8000 psf) depending on the type of
soil and the depth of footing used.  Samples of the weakest  and strongest
soils  considered for structual usage are loose inorganic sand silt mixtures
and hard clay, respectively.  Materials like loose organic  sand and silt
mixtures and muck or bay mud are considered to  have "zero" allowable
soil pressure, but it is accepted practice to  reclaim municipal landfills
(e. g. , organic soils) for  recreational land use.
                                     414

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4.2   PHYSICAL CHARACTERISTICS
The  physical characteristics of power plant sludges are primarily dependent
on the percent moisture.  However,  the degree to which a. sludge can be
dewatered is dependent on the relative quantities  of the major ohases
present, i. e. ,  calcium sulfite,  calcium sulfate,  calcium carbonate and
fly ash.  Among these, the dewatering capabilities of a sludge  depend
mostly on  the degree of oxidation of the  sulfite phase.   Primarily as a
consequence of the platelet-like nature of the sulfite crystals,  water
becomes entrapped between the crystalline olates and is not easily or
readily removed by physical dewatering techniques, such as filtration
or centrifugation.  In  contrast,  the sulfate crystals are "blocky" and do
not trap water.  A sulfite sludge can be  dewatered in a  thickener to 35-45
oercent solids  and will not increase solids content significantly by settling.
A filter or centrifuge will increase solids content to about 50-55 percent.
A sulfate  sludge dewatered to 35-45 percent solids will increase its solids
content to  60-65 percent  upon settling,  75 percent when freely  drained or
centrifuged, and about 80 percent by filtration.  The presence  of signifi-
cant amounts of fly ash will slightly alter  the dewatering characteristics
by increasing the solids content of sulfite  sludges but will  decrease slightly
the solids  content of sulfate sludges. Since some degree of oxidation exists
in all power plant sludges, observed behavior tends to fall between these
values deoending on the relative quantities of the  phases present.   Figures
1 and 2 show the dewatering behavior of two specific sludges, Shawnee
limestone  sludge and SCE Mohave limestone sludge.
Since all physical properties of a sludge are deoendent on moisture content,
it is  not possible to relate directly  the behavior of different sludges at
similar stages.  For example, a filtered sulfate  sludge will produce a cake
that  is firm, easily compacted and  can  readily support personnel and
equipment.  In contrast,  a filtered  sulfite sludge  will produce a cake that
may have a solid-like appearance but has  a consistency much like tooth-
paste. A better  comparison of ohysical properties can be  made when
sludges containing equivalent moisture content are compared.  For example,
at 65 percent solids content,  sludges are firm enough to support personnel,
                                      415

-------
               SHAWNEE
(Sludge contains about  40% sulfite,
10% sulfate, 40% fly ash, and
10% unreacted limestone)
                 20      40      60     80      100

             SOLIDS CONTENT,  weight percent
Figure 1.    EPA/TVA Shawnee limestone  sludge bulk dt-nsities
                             416

-------
1.9r-
           MOHAVE     (Sludge is primarily
                        sulfate and limestone)
                                  80
       SOLIDS CONTENT,  weight  percent
                                             100
Figure
       SCE Mohavc limestone sludge bulk densities
                      417

-------
and at solids content greater than 70 percent,  equipment  ca.n be  supported.
The thixotrooic behavior of the sludge is a  direct function of sulfite content.
Hence, while sludges with equivalent moisture content are capable of
suooorting equivalent Loads,  the work applied  to a sulfite sludge in walking,
or moving equipment, will tend to liquefy the  sludge whereas a sulfate
sludge will tend to remain firm.   The oresence of fly ash  in the  sulfite
sludge will tend to firm it somewhat, but has  no observable  effect on a
sulfate sludge.  Again an  example is made  of  the TVA Shawnee limestone
and SCE Mohave limestone sludges  (Figure 3} where the load carrying
capacity of the sludges are compared at equivalent moisture content.
When a sludge is dewatered or dried to a point at -which air voids are
created, the sludge can be compacted so as to increase its bulk density.
The point at  which this behavior occurs varies among  sulfite and sulfate
sludges.  Because of the ^article  agglomeration nature of sulfite crystals,
sulfite sludges will create air voids at  a  solids contents as low as 60-65
oercent.  Sulfate sludges  develop  air voids at  a solids content of about
80 percent.  The presence of fly ash in the sludge will affect the sulfite
sludge by increasing the  solids concentration at which air void formation
is reached.  As in other  properties  just mentioned, fly ash has little
effect on sulfate  sludges.   The amount  of compaction is dependent upon
many factors defending on phase compositions,  moisture  content, and
compaction force,  but dry bulk densities up to 1.5 gm/cm  (93 Ib/ft  )
can be obtained in  many sludges.  This represents  a 25 percent  volume
reduction on a dry solids  basis for sulfite sludges but only a 7 oercent
reduction for sulfate sludges.  Although the efficiency of field compaction
may not be as high as that in the laboratory, relative volume reductions
by comoaction between the two extreme types  of sludges will be  generally
the same.  Figure 4 shows the compaction  capabilities for typical sulfite
and sulfate sludges as a function of moisture content.  The moisture content
for optimum  compaction  is about 10 percent for sulfate sludges but about
20 percent for sulfite sludges.  This greater moisture requirement for
sulfites is  primarily a consequence  of the entrapment of moisture between
the platelet-like  crystals that make  up particle agglomerates.
                                    418

-------
VO
                  V)
                  Q.
                  I
                  I-
                  o
l-
to
O
Z
cc:
                     35
                     30
                     25
                     20
                  Z  15
LU
CD

0

O
                     10
                           SHAWNEE
                           (sulfite sludge
                           with fly ash)
                       0
                          MOHAVE
                          (sulfate sludge
                          without fly ash)
30                35                40

    MOISTURE CONTENT,  weight  percent
                                                                  45
                                  Figure  3.   Sludge compaction strength

-------
       2.O.
to
o
       1.8
    o
       1.6
    LJ
    Q
    D
    CD
       1.4
1.2
                                                                                          SULFITE

                                                                                          SULFATE
       1.0
          0
                            10           15           20

                                MOISTURE CONTENT, percent
25
30
35
                          Figure 4.    Preliminary compaction capabilities of sulfur sludges

-------
The density of sludge is of orimary importance  because it is the major
determinant of its  compaction strength, compressibility, and perme-
ability; all these factors affect the environmental acceptance of the
sludge for disposal.   The density also determines the quantity of sludge
that can be stored  in a given disposal area,  thus affecting disposal
costs.  However, cost savings gained by higher density filling can be
offset by the additional cost of compaction.  On  the other hand, if high
density fill would render the disposal area to a greater economic use
after reclamation,  this  factor must also be  considered in choosing disposal
techniques.
From the dewatering data discussed earlier, it  can  be seen  that a sulfate
sludge dewatered by filtration or centrifugation  will have a moisture
content very near the requirement for optimum  compaction,  although
the volume gain by compaction is minimal.  Sulfite sludges do not
dewater as well as sulfate sludges and will require subsequent dewatering
such  as combining  with  dry  additives, or thermal drying  to attain the
moisture content for optimum compaction.  It should be noted that although
a sludge can be dewatered to a degree such  that it will support personnel
and equipment,  it will readily rewet in the presence of water.  The gain
of moisture in rewetting is limited by the  volume of the voids in the sludge.
Therefore,  a rewetted compacted sludge will not return to its original
moisture content or volume.  By contrast, a rewetted uncompacted sludge
will have properties nearly  identical to those it  had in its original wet
state. Studies are continuing to  determine the degree to  which different
rewetted compacted  sludges approach their  original state.
An additional physical parameter affecting disposal  technology is the
permeability of the sludge to leachate waters.  Permeability among the
sludges can vary over several orders of magnitude depending on phase
composition and  degree of compaction.  Sludge that is allowed to  settle
and drain freely will have a permeability value equivalent to that  of fly
             -4
ash,  about 10   cm/sec.  Sulfate sludge in a settled state will drain more
readily than sulfite sludge in the  same state.  When these sludges are
compacted,  drainability is  reduced.  The  addition of fly ash  also  reduces
the drainability of  sludges.  The  drainability of  sulfite sludges is reduced
                                     421

-------
only slightly, but the drainability of sulfate sludges  is reduced by nearly
an order of magnitude.  A permeability value as low as 10   cm/sec has
been obtained for a compacted sulfate sludge containing fly ash.  This
appears to be the minimum permeability obtainable for untreated sludge.
4.3  ASSESSMENT
.Laboratory tests have shown that  raw sludge which has been dewatered
to about 65-70 percent solids can  support loads in the  range  of 4883 kg/
sq m (1000 psf) to 24, 41 5 kg/sq m (5000 psf).  Thus, it appears  that raw
sludge or raw  sludge oonds which have been dewatered could be used for
structural purposes per the Uniform  Building Code.  However, the cost
of dewatering the sludge  and maintaining the site at  the necessary degree
of dryness is strongly dependent on the raw sludge properties, and may
or may not compare favorably with the cost of an alternative disposal
technique such as chemical fixation.
Data from  chemical fixation processors indicate that treated sludge quickly
attains a compressive strength above the maximum limit  for compacted
fine sand or  hard clay; i. e. , 39, 064 kg/sq m (8000 psf).  This material
has the caoability to make a disposal site reclaimable  for either  structural
or recreational use.
5.0  POTENTIAL DISPOSAL PROBLEM SOLUTIONS
5. 1  DISPOSAL ALTERNATIVES
The choice of disposal alternatives is governed by the  criteria for an
environmentally sound disposal  plan.  These criteria are presently address
ing the potential for surface or ground water pollution  by  either runoff or
leachate  percolation and  the requirements  for  land reclamation of retired
disposal  sites.  Whereas these criteria are established by state  regulatory
agencies and in as much  as the disposal requirements  are not yet fully
defined by  any state,  it will be oresumed that all disposal alternatives
herein discussed may be equally acceptable.
In each of  the disposal plans, the  basic concept of control is containment
or isolation.  The extent or thoroughness of containment required will
depend on  the hazard the disposal is adjudged to present to the environ-
ment.  For example,  a sludge from which  chemical  pollutants  may leach
                                     422

-------
may require containment within a disposal site with an impervious liner
made of either natural or man-made materials.  The most obvious  example
would be disposal in a clay or plastic lined pond.  An alternative to this
approach would be to  reduce leaching by one of several commercially
available chemical fixation processes.  An alternative to chemical fixation
may be direct land filling of  dewatered sludge by methods  that restrict
rain water oercolation and leaching.  The acceotability of the latter method
may deoend on the geological and hydrological conditions of the disposal
site.  Variations of these methods and  the advantages and  disadvantages
of each are discussed in the following sections.
5. 1. 1   Chemical Fixation/Landfill
To date, three companies - Chemfix, Pittsburgh, Pennsylvania; Dravo
Corporation,  Pittsburgh, Pennsylvania; and IU Conversion Systems, Inc. ,
Philadelphia,  Pennsylvania  - have developed a  significant  technology for
chemical fixation of power plant  sludge materials at disposal costs  that
may be considered generally acceptable.  Whereas  all three processes
are designed to produce a material that chemically binds soluble com-
ponents, their processes and oroducts are  distinctly different.  Although
not all of these processes are currently being operationally demonstrated
with oower plant sludges, each processor has sufficient experience  in the
fixation of sludge materials to give credence  to his performance claims.
The following discussions reflect these claims, which are now being
assessed by independent analyses in the Aerospace Corporation sludge
disposal study.
                                               7 8
5. 1. 1. 1   Chemfix Process.   Chemfix has noted '  that their company has
gained wide field exoerience  in the fixation of solid, sludge, and liquid
wastes oroduced by automotive,   chemical,  mining, paint,  petrochemical,
steel  and metals industries.  The Chemfix  process reportedly can handle
sludge fixation over a broad range of percent solids and produces a  product
with a soil-like appearance which does  not  prevent  the oercolation of rain
water, but does have structurally stable oroperties and chemically binds
the constituents to accomplish pollution control .
The Chemfix process  involves the reaction of sodium silicate and one or
a combination of setting agents--portland cement, lime, calcium sulfate,
calcium chloride--with the waste material to form  chemically and mechan-
                                     423

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ically stable solids.  The  reaction occurs at ambient temperatures and is
not affected by temperature variations.  The particular chemical
choice, chemical ratios, and reagent quantities depend on the type of
waste, required speed of reaction,  and the  end use of the fixed material.
Either reactive or nonreactive wastes can be treated with the Chemfix
process.  The reaction process  involves an initial gelatinous state and
a subsequent hardening period.  The gelation time,  which is  controlled,
is based on the  distance the treated material must be pumped to the
disposal site.
The treated waste  can be made either hard  or  soft with varying textures
depending on its ultimate disoosal requirements.   The  chemical system
reacts with all polyvalent  metal ions oroducing stable,  insoluble inorganic
compounds.  The resulting material reportedly can be  used directly as
landfill which, when oroperly fertilized, will readily support grasses and
olant life-
Chemfix data further indicate that the material produced by the Chemfix
process  does not leach chemical constituents by  rain water at concentra-
tions that exceed the natural background levels in ground waters.   Its soil-
like behavior should allow it to be compacted such that land reclamation
costs can be minimized for  any  subsequent  use of the land.  Chemfix
claims chemically fixed sludges by this process  should be acceptable to
regulatory agencies for disposal directly as landfill without further treat-
ment.
5. 1. 1. 2   Dravo Process .   The Dravo  Corporation process is now being
used by Duquesne Light Company to stabilize the sludge  produced  by the
lime scrubbers at Duquesne's Phillips Station  near Pittsburgh, Pennsyl-
                     Q
vania.  Dravo claims   that they have gained extensive  laboratory  experience
on sludges from various air pollution control devices that include  but are
not limited to power plant sulfur dioxide scrubbers.  This process can
chemically fix sludges at various solids content and it  produces  a  material
that is clay-like in consistency.
                                     424

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 The Dravo process chemically fixes sludge by the inclusion of a proprietary
 admixture called Calcilox.  The Calcilox is mixed with the sludge usually
 just before the sludge is pumped to a disposal basin.   The sludge solids
 are allowed to settle and curing takes  place under water over a 30-day
 period.  Disposal can be made directly in the final disposal site,  or an
 interim  curing basin can be used from which  the  cured solids can be
 removed to a oermanent disposal site.
 Dravo information indicates that the product  of the  Dravo orocess is a
 firm material which is  convenient for  disposal.   By adding 3 percent
 Calcilox (based on sludge solids) the conditioned  sludge has properties
 that compare with silty clay with permeability of 2  X  10   cm/sec.  Clay-
 like properties including high shear and compressive strength are being
 obtained with Calcilox additions of 5 to 10 percent.
 The low permeability,  low leachability and the  structural stability of
 sludges  conditioned by the  Dravo process  should  allow them to be used
 directly as landfill materials.  The company  claims that sludges chemically
 fixed by this orocess have  been accepted for  disposal without  containment
 in at least one site in Pennsylvania.
 5.1.1.3  IUCS Process.   The IOCS process   '   '   has been field tested on
 sludge produced  by wet  scrubbing  effluent  gases on a  lead  smelter using
 hydrated lime as  the absorbent.  This sludge has many properties similar
 to power olant sludges  and produces a hardened composition when  chemi-
 cally fixed.  Laboratory tests have verified the similarity of sludge fixation
 behavior between this sludge and cower olant sludges.
 The IUCS process uses  fly ash and a lime  additive as  ingredients  in the
 chemical fixation of sulfite/sulfate sludges.   The quantity of either of
 these additives depend on the moisture content of the  sludge and the
 reactivity of the  fly ash. In some cases, dewatering  of the sludge is
 necessary  for the desired reactions  to take place at economical amounts
 of the additive.   Three primary reactions  take place in this process:
 1) the reaction of lime  with soluble sulfate that originates in either of the
fly ash or sludge liquor  so  as  to form  calcium sulfate (sulfite  will also
 react,  but  more  slowly), 2) the reaction of lime,  sulfate and iron or
                                   425

-------
aluminum oxides  oresent in the fly ash glass forms  complex sulfo-ferrites
or sulfo-aluminates  (this reaction results in the formation of the crystalline
phase ettringite which contains  substantial quantities of water within the
crystalline  structure), 3) the  reaction of lime with the  glassy  silica of fly
ash results in the well known  pozzolanic  reaction that proceeds slowly to
form the  calcium silicate phase, tobermorite.
Some IUCS  laboratory results of this process are shown in Table 4 for
the Shawnee limestone sludge.  The data indicate that the material  can
develop strengths as high as 4. 1 tons/sq ft in seven days.  Falling  head
permeability data indicate improvement during the first month of curing
from 10   to 10    cm/sec.  The low permeability is a  consequence partly
of the expansive nature of ettringite which tightly seals the set mass  and
which prevents  shrinkage crack formation which may otherwise allow
some leakage.  Besides  low leach rate, analysis of  the leachate indicates
a reduction in concentration of trace elements of approximately one order
of magnitude.  Thus, as  a consequence of chemically combining trace
elements  into new crystalline  phases and the reduction  in leaching rate,
the availability of soluble salts or toxic contaminants to ground waters can
be reduced  many  times,  when comoared  to unfixed sludge (see Tables 2,
3,4).  An indeoendent analysis of this fixed  sludge sample (as  well as
others using Calcilox and the  Chemfix orocess) is now  being conducted
in the Aerospace  Corporation  laboratories,  and further verifications will
be made in  an EPA field  disposal program.
In addition to producing material suitable for landfill, the IUCS process
may also  be applied  to the manufacture of synthetic  aggregate having
properties suitable for road base material.  This application,  which
requires increased quantities  of the additives and additional processing
equipment (when compared to  a landfill application),  is currently being
field  demonstrated.
5.1.2  Dewatering/Landfill
One method of sludge disposal may incorporate dewatering, drying  and
placement of the -waste solids  by one of several techniques.  The most
direct technique would use the method of compaction developed for  sanitary
                                    426

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  TABLE 4.   LABORATORY RESULTS OF  FIXED TVA  LIMESTONE SLUDGE ANALYSIS13
LEACHATE
CONCENTRATIONS,
ppma
TOTAL ALKALI
TOT. DIS. SOLIDS
so3
so4
Cl
Ca
Mg
Al
Fe
Mn
Cu
Zn
Cd
Cr+3
As
Pb
Sn
Hg
pH

PERMEABILITY,
cm/ sec
COMPRESSIVE
STRENGTH, tons/sq ft
AGE OF TEST, days
2
1068
1370
11
45.2
64
268
0.005
2.2
0.02
0.005
0.02
0.005
0.007
0.05
0.01
0.2
0.1
0.01
12.35
4
542-
730
19
41.9
12
220
0.005
3.2
0.01
0.01
0.01
0.01
0.005
0.03
0.01
0.05
0.1
0.01
12.5
6
810
1210
14
36.2
74
235
0.005
11.4
0.01
0.007
0.01
0.005
0.005
0.02
--
0.05
0.05
--
12.1
10
524
770
20
51.0
21
170
0.01
0.95
0.05
0.007
0.02
0.005
0.005
0.02
__
0.05
0.05
--
11.9
14
40
180
10
48.5
16
27.5
0.05
0.01
0.005
0.005
0.005
0.005
0.01
--
0.05
0.05
--
10.2
28
40
250
3
43.6
14
20
0. 1
< 0.01
< 0. 005
< 0.01
< 0. 005
< 0. 005
< 0.01
--
< 0.03
< 0.1
--
9.0

AGE OF TEST, days
0 7 14 21 35
1 x 10-4 6.3 x 1Q-5 " 6.2 x 10'6 5>0x 10~
4.1 4.7
Equivalent to mg/I

-------
landfill.  For the oroblem of leachability, containment -n clay cells may
be necessary.   In some cases, final covering with clay may be all that
would be necessary to prevent contamination of ground waters.  The
soecific method of solid waste disposal will depend strongly on site
requirements.
In most cases,  partial drying is required to produce a material that is
readily compacted so that the disposal site may be ready for structural
use immediately after filling.  The  extent of drying required would be
dependent upon the physical nature of the sludge.  Several alternatives
exist and  their  cost effectiveness depends on sludge characteristics,
climatic conditions,  and system variables.  For a sulfate sludge dewatered
by filtration or  centrifugation,  if any additional drying is required to
reduce the water content to a. level suitable for compaction,  solar drying
may be sufficient.  On the other hand, for a sludge with relatively high
sulfite content,  dewatering by either filtration or centrifugation is not
adequate for compaction.   In this case, one  alternative might include the
blending of dry collected fly ash to sludge dewatered by filtration or cen-
trifugation to reach optimum moisture content for compaction.   A second
alternative  might employ  a thermal dryer that uses waste heat to dehydrate
the sludge.   Depending on the many system variables, it is possible to
pass all the dewatered sludge solids through  the dryer to reach an optimum
comoaction consistency,  or to  pass through  the  dryer, a portion which
can then be mixed with the remaining solids to reach  proper consistency
for placement.  To acquire the proper degree of dryness,  the two  alterna-
tives  cited above may also be aoolied to the sulfate sludge.  A third alter-
native would be to oxidize the calcium sulfite to gypsum  and thereby gain
the dewatering advantages of sulfate sludges.
The environmental acceptance of direct landfilling with dewatered sludge
will be deoendent on  its potential for environmental pollution by leaching.
The potential for leaching oossibly can be minimized for sulfate sludge
by cake washing and  treatment of the wash liquor.   However, this  has  not
yet been demonstrated.  For most  cases,  the cost for containment (e.g. ,
with clay),  if necessary,  would equal or exceed the cost required for
direct oonding in clay or an equivalent containment material.  However,
in the  case of dewatered sludge disposal, the benefits of reducing the
                                     428

-------
disoosal volume and the future land use of a compacted sludge site may
offset the dewatering costs.
5. 1.3  Environmentally Controlled Ponding
A ootential disposal alternative is the ponding of raw sludge; e.g.,
clarifier underflow or dewatered sludge cake.  In this concept, the sludge
is transoorted (pumped or hauled) from the scrubbing operations to a
waste disposal pond suitably constructed to contain the raw  sludge for
long oeriods of  time.  The pond configuration commonly used is essentially
an excavated oit or basin  with the soil graded into embankments or dikes
generally 3 to 15m (1 0 to  50 ft) in height.  The pond bottom is usually
flat,  but may be contoured to  drnin off seeoage.  Impervious liner materials
are installed along  the inner pond surface to  inhibit  any seepage of liquids
from the sludge into the ground.  Both flexible (e.g.,  polyethylene,  ooly-
vinyl chloride,  butyl rubber,  chlorinated polyethylene, duPont Hypalon
films) and nonflexible liners such as  bituminous concrete, clay,  and
pozzolan stabilized base are used.
Leakage detection concepts are usually incorporated into the pond design.
These concepts  vary from a simple  underdrainage basin with visual
monitoring to an electrical system designed to measure the  electrical
resistivity of the  ground in the pond area.  In addition, many installations
have  visual or remote sensing systems to monitor the nearby surface and
ground waters to  determine if there is any leakage or seepage from  the
pond.  Overdrainage can return oond surface water  to the scrubber if
appropriate to the total system design.
Although the basic design features of ponds arc generally uniform through-
out the country,  there are local ordinances and environmental regulations
that govern.  Even though the concept of ponding  is a proven technique for
large-scale, low  cost evaporation operations, the predicted useful life
of a potential sludge disposal  pond liner still needs to be  defined.  It is
directly dependent upon the aging characteristics of the liner material and
its  chemical interaction with the sludge and the supporting soil.   Flexible
                                                  14
liners are  generally guaranteed for  20 to 25 years   ,  and the life expectancy
                                       429

-------
of nonflexible liners  is estimated to be somewhat longer.  However, long
term service data applicable to  desulfurization sludge containment  do
not yet exist for either type of liner.
In addition,  systems to  control seepage from a sludge disposal pond after
it has  completed its  service life have not yet been demonstrated.  Such a
system might consist of provisions for underdraiaage and overdrainage
combined with air drying to dewater the site, followed by capping with a
contoured  clay cover to provide for runoff of rain water.  The purpose of
such a system would be to  eliminate a hydraulic head, thereby preventing
seepage from the pond.
6.0   DISPOSAL COST ESTIMATES
Disposal cost estimates were  made for each of the  two most prevalent
disposal methods:  ponding, and landfill using chemical fixation.  Infor-
mation was provided by various  sources, and for each method the cost
data are widely variant.  As a result,  the disposal  costs are given in
ranges of values consistent with appropriate qualifications based on the
many variable parameters  attendant to either disposal method.  Although
refinements are  expected during succeeding disposal cost  studies in this
orogram,  the disposal costs are exnected to be always expressed as a
range  of values,  except when applied to a specific disposal operation.
This section summarizes this analysis to date and includes significant
disposal costs and appropriate rationale.  All costs are  given in units
commonly  used in industry, e.g.,  dollars /short ton (dollar s /O. 907
metric ton) and dollars/sq  yd  (dollars/0. 836  sq m).
6. 1   CHEMICAL FIXATION DISPOSAL COSTS
The  disposal costs  by chemical fixation are dependent upon many factors
such as: the fixation process  and the contractor-operating efficiency;
sludge characteristics including water, ash, and  chemical content;
disposal site physical characteristics;  distance from power plant to disposal
site; sludge transoort method; disposal site land costs and ownership;
residual value of disposal site; and environmental monitoring.  Addi-
tionally, the costs depend upon whether the power plant uses a disposal
                                     430

-------
contractor or does the work itself.   To determine these costs, data were
obtained from personal communications,  visits, published cost data,  '   '
brochures,  and testimony from the National Power  Plant Hearings on
Scrubbers,  October - November  1973.  Sources of these data were:  power
companies - Commonwealth Edison Company and Duquesne Light  Company;
chemical fixation companies - Chemfix, Dravo  Corporation, and IU
Conversion Systems,  Inc. ; and the EPA Control Systems Laboratory.
Some estimated disposal costs  (converted to a 50 percent solids basis)
quoted by the power companies and fixation companies are listed in Table
5.
These values,  equated to sludges that are 50 percent solids, range from
$2. 00  to $9. 00/ton.  All  relevant factors  pertaining to the  values  given
are not available; however, based on the  data given,  it appears that exceot
for extreme  cases (e.g.,  development or demonstration),  the general
range of costs will be aoproximately $2. 50  - $5. 00/ton of sludge on a 50
percent solids  basis.  Some additional costs may be incurred for  soil
cover and/or seeding  after the disposal site is filled.
Previously published fixation cost data  include various limitations on the
applicability of the values, and do not include recent escalations in costs.
These data,  therefore, have been augmented through personal communica-
tions  with several of the  companies involved for the purpose of deriving a
general cost estimate for fixation/disposal  rather than to attempt a  rating
of one versus another since each application would be condition and site
deoendent.  Sources which provided  estimates for complete disposal systems
(using quite different approaches) were Dravo Corporation which provides
a disposal service, and two power companies performing their own disposal
tasks.  Appropriate Dravo data are taken from  costing of a pro >osed
disposal operation for the Bruce Mansfield  Station,  a  now  1650 Jvlw
plant,  in western Pennsylvania.   The costing data are  based on consider-
able  land acquisition and development costs and the pumping of the sludge
(32-37 percent solids) approximately Smiles to the disposal site where
it is  to be chemically  treated prior  to disposal.   In this case, although
capital costs are high, the large quantities  of sludge place the cost per
                                    431

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  TABLE  5.   SLUDGE  FIXATION  COSTING  ESTIMATES
            (all values are condition and site dependent)
        SOURCE
DOLLARS/TON
 (50% solids)
     REMARKS
COMMONWEALTH EDISON
  COMPANY,  WILL
  COUNTY STATION
DUQUESNE LIGHT
  COMPANY,
   PHILLIPS STATION

IU CONVERSION
SYSTEMS, INC.

CHEMFIX

DRAVO CORPORATION
 8. 00 - 9. 00

 6. 00 - 6. 50


   -7.50
 2.00 - 6.00
CURRENT ESTIMATE1

TARGET0


TOTAL DISPOSAL
TOTAL DISPOSAL
 Company operation - on-site disposal; excludes capital costs

-------
ton as analyzed in this  study at less than $5. 00.  For sites requiring
less land development and shorter pumping distances, Dravo estimates
costs of less than $4.00 per ton.  On the other hand, Commonwealth
Edison and Duquesne Light Company are currently conducting their own
systems on what can be termed development operations.   These are, by
comparison to  the Dravo  example, relatively  small systems (156 and
100 Mw, respectively), and they use intermediate curing ponds and
trucking of the cured sludge to disposal sites  up to 1. 6 Km (1 mile)
from the fixation operation. Estimated current costs for  these two are
in the  range of $7. 50 to $9. 00  per  ton on a 50  percent solids basis.  Some
estimates of power plant  operation such as the one at Commonwealth
Edison indicate that refinements in the system may bring  the cost down
to approximately $6. 00 per ton on  an operational basis.  Additional
contacts with Chemfix and IUCS to up-date published information indicate
that for fixation disposal  of 50 percent solids  sludge including all capital
charges and local transport of the  treated sludge,  a cost of $4. 00 to $5. 00
per ton is reasonable.
6.2   PONDING ECONOMICS
The cost for  constructing a sludge pond will depend not only on the technical
design details, but it will also depend upon its geographical location.   The
cost for shipping the liner materials to the site frotn the factory or pro-
cessing center will vary with the distances traveled; and,  the labor costs
for construction and liner installation vary with the different areas of
the country.  The economic analysis undertaken in this study considered
these variations and used average  values such that the costs presented
in this paper can be considered typical, but not necessarily specific.
Cost estimates are from  suppliers of pond materials and builders of
      1417
ponds   '   .  All costs  are  as  of August 1974.  The economic analyses are
based on a 1000 Mw power  plant burning coal  with 3 percent sulfur and
12 percent ash.  The plant  life is  30  years with the plant operating an
average of 4560 hours per year with  an average annual sludge  (50 percent
solids including ash) production of 930,000 metric  tons (1,025,000 short
tons).
                                       433

-------
The annualized costs used in this work included the costs for labor,
maintenance and capital charges at 18 percent.  The capital charges
included depreciation,  replacements,, insurance, cost of capital,  and
taxes.
Figure  5 presents a composite cost summary  for the  various liner
materials considered.  The values shown are  typical  of the range of
costs that might  be expected for installed liners at the field  site,  but are
to be  used for planning purposes only.  For this study,  the mid-point of
the price range was used.  The widespread variations in costs resulted
because of factors such as  the cost of transportation from the liner manu-
facturer's facility to the  field site within a radius of 1609 Km (1000 miles),
the variation in the cost of labor throughout the country for liner installa-
tion,  and price discounts for purchasing large quantities of liner materials.
It  is expected that the flexible liners  could probably be purchased and
installed at the lowest cost values; however, these lower  limit numbers
were  avoided in the cost analyses  as  a precautionary  measure against
data which may not be reliable.
In early 1973,  it was reported that the projected cost for  a 46-cm (18-in)
thick  clay liner installed in  several large ponds being constructed in the
midwest was about $6. 00 per  sq yd.  This clay was transported by truck
about 48 Km (30  miles) from the clay pits directly to  the pond site.  If
suitable clay could have been available on the  pond site,  it could have been
moved into  place at a cost of $1. 00 per sq yd.   At today's  prices, the
costs have risen to approximately $9. 00 and $1. 50 per sq  yd, respectively.
The increase in installed costs during this same time period for the
flexible liners  has been about 100  percent for  0. 254 mm (10 mil) thick
polyethylene liners,  50 percent for 0. 508 mm  (20 mil) thick polyvinyl
chloride, and 25 percent for 0. 762 mm (30 mil) thick Hypalon.  The other
flexible liners  also have  had appreciable rate  increases.   It is expected
that the prices will continue to increase in the foreseeable future,  since
many of the liner materials are presently in such short supply that  the
prices vary on a monthly basis.  Some contractors have indicated that
the actual price will be established only at the time of delivery to the
field; they will probably also consider writing  escalators  or surcharges
                                  434

-------
INSTALLED COST,  $/sq yd
     CM           Ul
                                        01


f-"
5=
C
U1
V.
P
d.
"i
c
cr.



LINERS J
iND THICKNESS
1 1 1 1 1
1 O 1 POLYETHYLENE - 10 mils
1 O i POLYVINYL CHLORIDE - 10 mils
LHMMM^^WV^MMB^^^^ r\f\ I V/ V/l kt\/ 1 ^* LJ 1 ^*\D 1 F^ C* OA w*  1 
' ^ 1 POLYVINYL CHLORIDE - dO mils
H-O-H PETROMAT FABRIC - 125 mils
1 -Q I BUTYL RUBBER - 30



mils
CHLORINATED
I 	 Q H POLYETHYLENE -
30 mils
ff 1 Q 	 1 HYPALON - 30 mils
(/>
, EPDM RUBBER
5-3 i -0 ' 30 mils
^p | ___^_CLAY 18
Cn f~i -^ ON
3 CD CD
q {/> OT
RETE

-------
into the fixed price contracts to permit then to tag on price increases
as the materials they purchase go up in costs.
Figure 6 illustrates the 30-year averag-e  disposal cost in dollars per ton
of sludge (50 percent  solids) as a function of the depth of raw sludge in the
pond from 3 to 1 Z meters (1 0 to 40 ft).  Two liner materials \vere con-
sidered:  0. 508 mm (20 mil) thick polyvinyl chloride (PVC) at an installed
cost of $2. 33/sq yd including a soil cover of 15. 2 cm (6  in), and 0.762 mm
(30 mil) thick duPont Hypalon at a cost of $3. 85/sq yd  installed.  These unit
costs are also applicable to equivalent cost liners (see Figure 5).   It can
be seen that  the disoosal cost is (without including the  cost of land) about
$2. 50 per ton if PVC is used, and about $3.40 per ton  when a higher cost
liner such as Hypalon is  used.
Each pond configuration  used in these analyses had a 0. 915 meters  (3 ft)
freeboard.   It was assumed that all of the land needed to contain the
sludge during the full 30-year life of the power plant would  be purchased
initially.  However,  the  sludge ponds would be constructed  each 10  years
as the previous ones became filled.  Land costs of $404  and $2020/hectare
($1000 and $5000/acre) were used.  As expected, the land cost  decreased
proportionately as the dike height increased because of a smaller area
needed for the ponds to contain the 30-year production of sludge.  Figure
6 illustrates the effect of the cost of land on the sludge disposal costs.   It
also indicates that for each pond  concept there is an optimum sludge depth
at about  9. 15 meters  (30 ft) which represents  theoretical minimum  disposal
costs.
6. 3   EFFECT OF DEWATERING
The disposal costs presented thus far were based on a desulfurization sludge
with a mixture of ash and water at  a total solids content  of 50 percent.
Over the 30-year operating life of the example power plant,  sludge  at this
solids level  will occupy a volume of about 2720 hectare-meters  (22, 000
acre-ft).
An  investigation is underway to assess  the  effects (on  pond  size and disposal
costs) of the dewatering  of the sludge prior to disposal.   Figure 7 graphically
presents the results of the initial work  comparing the  volume occupied by:
                                    436

-------
               PVC - 20 mil
                                                         HYPALON - 30 mil
O
O
m
a
UJ
O
O
ID
               TOTAL COST INCLUDING LAND
                        ($5000/acre)
                       TOTAL COST
                       WITHOUT LAND
  TOTAL COST
INCLUDING LAND
 ($1000 per acre)
            INSTALLED LINER ONLY
              I
             10       20        30

             SLUDGE DEPTH,  feet
                                    40
                                         6.
                                              o
                                              8
                                              O
O
a.
ili
O
O
                                                           V-TOTAL COST INCLUDING LAND
                                                           \         ($50007acre)
                                                                               TOTAL COST
                                                                               INCLUDING
                                                                               LAND
                                                                               ($1000/acre)
                                                                            TOTAL  COST
                                                                            WITHOUT  LAND
                                                     INSTALLED LINER COST
             10        20       30

              SLUDGE DEPTH, feet
40
                                             Dispose) costs -  ponding
                                                    50 pcrct-nl solids
                                                   Yea r

-------
00
VOLUME INDEX
O  f\> OJ .&.


1.0
/>
S
p

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only sludge at 50 percent solicit,  sludge at 65 percent solids, and then
separately mixing these sludges with 80 percent solids ash.   The reduc-
tions in volumes  required for sludge, disposal as a result of dewatering
and/or ash removal prior to disposal are shown.   For example, the
disposal of sludge plus ash (50 percent solids) requires a pond  volume
3. 55 times that required for ash only; whereas,  the  disposal of sludge
only, at 65 percent solids,  requires a volume only 1. 3 times that for
ash alone.  This  concept in ponding offers the potential advantage of
reducing the disposal costs by reducing the pond size and land  required
for the pond.
Economic  trade-off evaluations are in progress to determine:  1)  the
various cost factors for conventional fly ash collection and sludge de-
watering (at numerous  solids content),  Z)  the disposal cost  savings
attributed  to these  factors, and 3) the  net effects of 1) and  Z).   The de-
watering techniques currently being  considered include operations  such
as filtration,  centrifugation, thermal drying, oxidation of the clarifier
sludge, and settling in a thickener or settling pond.
6. 4   DISPOSAL COST COMPARISONS
The  disposal  of scrubber sludges using a chemical fixation process is a
rather new industry; therefore, little cost data  exist based on actual
practice by the power utilities.   Similarly,  little actual cost data exist
for scrubber  sludge disposal by lined ponding.   However,  the art and
technology of ponding are well established,  but  there is little experience
with power plant  sludge  disposal through the use of lined  ponds  or of sub-
sequent pond  reclamation.  There are many ponding choices available that
offer a wide range of costs with apparently  small differences in net results.
Therefore, at this time,  comparisons are made by observing the ranges
of values  available  and making rational comparisons  in light of the  varia-
tions in both the requirements and potential disposal methods.
It should be acknowledged that these two methods,  which  appear to  be the
best currently available or now in development,  do not necessarily oifer
the same  degree  of environmentally  sound disposal.   For example,  fixation,
                                    439

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which may be the more expensive process of the two, appears to offer a
permanent solution and may be suitable for land reclamation, but further
study is needed to evaluate the long-term environmental acceptability of
this process.  Flexible liner ponding,  which may be the least expensive,
may provide safeguards at a particular site  for as long  as approximately
25 years, but some added costs may occur for final disposal safeguards
which may be necessary to provide permanent environmental protection
and land reclamation.  Although nonflexible  liner systems may protect
for periods greater than 25.years,  eventually additional costs may also
be required to accomplish  permanent environmental protection and land
reclamation.
Comparisons of fixation and lined ponding, therefore, cannot necessarily
be made on an equal basis  since the two methods do not necessarily offer
the same results.  If the two could offer the  same  environmental protection
indefinitely and if land reclamation were not of primary interest  at a
particular disposal site,  then  a  reasonably equal comparison could be
made.   Regardless of the many  variations and differences that exist between
the two processes, both are being considered throughout the power gener-
ating industry; therefore,  cost comparisons  are in order at this time.
Ponding costs are estimated to be in the range of $2. 50 to $4. 50  per ton
depending on factors  such as the moisture content  of the disposal sludge,
dike height,  liner material used and the cost of land.  Fixation cost estimates
vary from $2. 00 to $9. 00 per  ton depending on factors such as sludge
chemistry including water  content, chemical additives used, capital costs
and transport method.  Neglecting development factors  and  unusual cir-
cumstances, it appears that average ponding costs (as qualified  previously)
should be about half fixation disposal costs.
The following example considers the cost of  disposal of all  sludge and ash
(50 percent solids) in  terms of power produced; limestone scrubber; 85 percent
SO-, removal; 1.2 GaCO,/SO?  mole ratio;  coal--3  percent sulfur and
   u                   J    L*
12 percent ash--burned at  the rate of 0. 88 lb/kwhr.  If the average disposal
cost is  in the range of $2. 50 to $5/00 per ton,  the  cost for this example
would be 0. 56 to 1. 12 mills/kwhr respectively.  If a lime scrubber is used,
                                 440

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the cost  of disoosal would be about 10 oercent less because the tonnage
would be reduced.   Additionally, reductions in disposal costs  may be
oossible as noted in Section 6- 3.
7. 0  SHAWNEE SLUDGE DISPOSAL FIELD DEMONSTRATION
The Aerospace  Corporation is participating in a scrubber sludge disposal
field demonstration orogram being conducted by the EPA Control Systems
Laboratory at the TVA Shawnec Power Station in Paducah, Kentucky.  This
program, which includes the monitoring of test ponds with each pond con-
taining a raw or chemically conditioned lime or limestone sludge, \vill
provide field condition data  that will  be  integrated with the data being
developed in the Aerospace  Corporation disposal study.  The Aerospace
participation in the  field demonstration  consists of test planning, coordina-
tion, selected testing {soils, input sludges,  leachate and ground \vater
well samples,  and conditioned sludge cores), and reporting.   A complete
description of the field demonstration is given in Reference  18.
                                  441

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 8.0      REFERENCES
 1.  Ros.soff, J. and R.C. Rossi,  Aerosoace Corporation, "Disposal of
    By-Products from Non -R egenerable Flue Gas Desulfurization
    Systems:  Initial Report, "  EPA -650 11 -74 -037 -a,  May 1974.

 2.  Public Health Service Drinking Water Standards,  Publication No.
    956, U. S.  Department of Health,  Education and Welfare,  Public
    Health Service, Washington 28, B.C., Revised 1962.

 3.  Water  Pollution Regulations of Illinois,  Pollution Control Board,
    State of Illinois,  Springfield,  Illinois, July  1973.

 4.  Proposed Criteria for Water Quality, U.S.  Environmental Protection
    Agency,  Washington, D. C. ,  20460, October 1973.

 5.  "Federal Water Pollution Control Act Amendments of 1972, 92nd
    Congress  - Second Session, "  United States  Code Congressional
    and  Administrative News,  No. 10, West Publishing Company,  1972.

 6.  Uniform Building Code,  Table 29C, Vol. I,  International Conference
    of Building Officials, 1970 Edition.

 7.   Personal Communication,  Chemfix, Division of Environmental
     Sciences,  Inc.,  Pittsburgh,  Pennsylvania.

 8.  Conner,  J.R., "Fixation/Solidification  of Sludges from  Lime/
    Limestone SO  Scrubbers"; Chemfix, Division of Environmental
                  j^
     Sciences,  Inc.,  November  1973.

 9.  Personal Communications,  J.G. Sclmeczi,  Dravo Corporation,
    Pittsburgh, Pennsylvania,  February and May 1973.

10.   Personal Communications, L. J.  Minnick,  IU Conversion Systems,
     Plymouth  Meeting,  Pennsylvania,  March 1973.

11.   Minnick, J. L. ,  "Fixation  and Disposal of Flue Gas  Waste Products:
     Technical and Economic Assessment, " Paper presented at Environ-
     mental  Protection Agency Flue Gas Desulfurizalion  Symposium,
     New Orleans, Louisiana,  May 14-17,  1973.

12.   "Converting Stack Waste into Usable  Products,"  POWER,
     L. J. Minnick, January  1974.

13.   Personal Communication,  R.G.  Hilton,  IU  Conversion  Systems,
     Inc., Plymouth Meeting, Pennsylvania,  August  1974.

14.   Personal Communication,  O.H.  Honsgen,  Waterproofing Systems,
     Inc. , Los Angeles,  California, August  1974.
                                      442

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15.  "Truck Loads of Landfill from Waste Sludge, " Chemical Week,
     January 26,  1 974.

16.  Gifford, D.C.,  "Will County Unit 1  Limestone Wet Scrubber Waste
     Disposal".  Presented at the Electric World Conference,  Chicago,
     Illinois, October 30-31,  1973.

17.  Personal Communication, W.A.  Wheeler andH.C. Ellingston,  Jr.,
     McKittrick Mud Company,  Inc.,  Bakersfield,  California,  August
     1974.

18.  Jones, J.W., EPA Control Systems  Laboratory (CSL) "Environ-
     mentally Acceptable  Disposal of Flue Gas De sulfurization Sludges:
     The EPA Research and Development Program", for presentation
     at the EPA CSL Symposium on Elue Gas  Desulfurization,  Atlanta,
     Georgia, November 4-7, 1974.
                                  443

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    AN OVERVIEW OF DOUBLE ALKALI PROCESSES
        FOR FLUE GAS DESULFURIZATION
                    by
               Norman Kaplan
         Control Systems Laboratory
     Office of Research and Development
       Environmental Protection Agency
Research Triangle Park, North Carolina  27711
           For Presentation At:
  EPA Symposium on Flue Gas Desulfurization
              Atlanta, Georgia
             November 4-7, 1974
                  445

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                               ABSTRACT

     The chemistry and process design considerations applicable to
sodium/calcium double alkali systems are presented.  Technical
terminology associated with these systems is defined.

     The developmental efforts and full scale applications of the
technology by Envirotech Corporation, FMC Corporation, General Motors
Corporation, Zurn Industries, Arthur D. Little, Inc./Combustion
Equipment Associates, Kawasaki Heavy Industries, Ltd./Kureha Chemical
Industry Company and Showa Denko KK are discussed with reference to
appropriate flow sheets.  Planned applications of the technology by
these companies are also discussed and tabulated.
                                   446

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                           ACKNOWLEDGEMENTS



     The author wishes to express appreciation to Carolyn Fowler and

Gloria Rigsbee for assistance in typing this paper, under the stress

imposed by unusual time constraints.



     Appreciation is also expressed toward the personnel listed below,

without whose cooperation and informative input, a presentation of  this

type would not have been possible:



          Conrad Cornell  ,         ,  _
          ..,,.   m .    ; Envirotech Corporation
          William Ellison                 ^



          Jack Brady    ,
            n T     i  . ) FMC Corporation
          Karl Legatski          r



          Thomas Dingo -, _     _       _
          ,      vr     ; General Motors Corporation
          Thomas Mason



          John Tormev, Zurn Air Systems



          Toshio lihara -, .,     .  .      T  ,
          ...    ...   .  } Kawasaki Heavy Industries
          Makoto Yanai                 J
                                   447

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                          NOTES

Company Names and Products.

The mention of company names or products is not to be considered
an endorsement or recommendation for use by the U.S. Environmental
Protection Agency.

Consistency of Information.

The information presented in the section on Status of Technology
was obtained from a variety of sources (sometimes by telephone
conversation) including system vendors, users, EPA trip reports
and other technical reports.  As such, consistency of information
on a particular system and consistency of information between
the several systems discussed may be lacking.  The information
presented is basically that which was voluntarily submitted by
developers and users with some interpretation by the author.
The order of presentation of information or the amount of information
presented for any one system should not be construed to favor
or disfavor any particular system.

Units of Measure.
EPA policy is to express all measurements in Agency documents
in metric units.  When implementing this practice will result
in undue cost or difficulty in clarity, NERC/RTP is providing
conversion factors for the particular non-metric units used in
the document.  Generally, this paper uses British units of
measure.

For conversion to the Metric system, use the following equivalents

       British                       Metric
       5/9 (F-32)
       1 ft
       1 grain
       1 in.
       1 in. 2
       1 in.3
       1 Ib (avoir.)
       1 ton (long)
       1 ton (short)
       1 gal.
C
0.3048 meter
0.0929 meters2
0.0283 meters3
0.0648 gram
2.54 centimeters
6.452 centimeters^
16.39 centimeters3
0.4536 kilogram
1.0160 metric tons
0.9072 metric tons
3.7853 liters
                               448

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                           TABLE OF CONTENTS




                                                            Page




Introduction and Background                                  451




Definition and Discussion of Terms                           453




Design Considerations                                        460




Status of Technology                                         475




     Envirotech Corporation                                  476




     FMC Corporation                                         484




     General Motors                                          492




     Zurn Industries                                         498




     A. D. Little/Combustion Equipment Associates            500




     Kawasaki/Kureha                                         501




     Showa Denko KK/Ebara                                    506




Summary and Conclusions                                      509
                                  449

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INTRODUCTION AND BACKGROUND

     Recently, there has been an increasing interest in the double
alkali processes as alternatives to wet lime/limestone slurry scrubbing
systems for utility and industrial boiler flue gas desulfurization (FGD)
applications.  Presently there are no full scale utility boiler double
alkali applications in this country but there are two 150 Mw operating
systems in Japan.  In the U.S. there are two operating full scale
industrial boiler applications equivalent in size to a 40 Mw and a 20 Mw
control system respectively and an industrial kiln control system
equivalent to a 10 Mw control system based on off-gas flow.   The start up
of a 20 Mw prototype utility boiler system is imminent.  There has been
a great deal of pilot plant testing of these systems in a variety of
applications including coal and oil fired utility and industrial boilers,
smelting plants, and in a sulfuric acid plant.  There are now under
construction in the U.S. (including the 20 Mw utility prototype) at
least five full scale systems ranging in size from 3 to 150 Mw equivalent
electric generating capacity.  To put application of this technology in
perspective, however, there are 11 utility boiler FGD applications now
in service using lime/limestone scrubbing totaling over 2500 Mw of controlled
capacity and at least 13 more systems under construction totaling over
7600 Mw of controlled capacity.

     "Double alkali" or "dual alkali" processes as they have come to be
known, like their precursors the lime or limestone wet scrubbing processes,
are aqueous alkali scrubbing processes used for FGD.  If a "black box"
view of these processes is employed, they are, with minor exception, like
the lime/limestone scrubbing systems:  lime or limestone is consumed, and
a calcium sulfite/sulfate and flyash wet solid waste product is produced.
A more detailed examination inside the "black box", however, would show
that the overall process has been split into a number of intermediate steps
designed to improve upon the lime/limestone processes by increasing
reliability of operation, utilization of lime and/or limestone, and sulfur
oxide removal efficiency and, under certain circumstances, producing a
solid waste with better handling characteristics.  Whereas in a lime/lime-
stone process the absorption of the SOX from the flue gas and the production
of the waste product occur to some extent simultaneously in a single reaction
system, in the double alkali processes, these two steps are separated through
the use of an intermediate soluble alkali; absorption and production of
waste product can then occur in separate system components.

     Separating the absorption and waste production functions accomplishes
two very important objectives.  First, it permits scrubbing the flue gas
with a soluble alkali thus limiting the SOX absorption reaction only to
gas/liquid chemical equilibrium and to the rate of transfer of SOX from the
flue gas to the scrubbing solution.  In lime/limestone processes, the rate
of dissolution of lime or limestone is a third important limiting factor.
Thus SOX absorption efficiency in a double alkali system is potentially
                                 451

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higher than in a lime/limestone system with the same physical
dimensions and liquid/gas flow rates.  Additionally, soluble
calcium is minimized and calcium slurry is kept out of the scrubbing
apparatus thus preventing solids build-up (commonly known as scaling
and plugging) in this critical area.  Another benefit of this is better
control of the lime/limestone reaction with acidic sulfur containing
compounds in separate equipment specifically designed for this reaction
thus potentially increasing lime/limestone utilization.

     Although a number of other processes can technically be considered
double alkali processes, this paper is limited to consideration of the
sodium/calcium based double alkali processes.  In these processes, a
soluble sodium based alkali (NaOH ,  Na2SCu, Na2CO^, NaHCO^) is used to
absorb SOX from the flue gas in the scrubber, and then a calcium based
alkali (Ca(OH)2, CaO, CaCO^) is reacted with the S0x~rich scrubber
effluent liquid to precipitate the insoluble CaS03l/2 H20 and CaS04-2H2d
and regenerate sodium based soluble alkali for recycle to the scrubber
system.  Double alkali systems using ammonium/calcium base have been tested
and while they might have advantages in the reaction with calcium compounds,
their main disadvantage is the potential for pollution by a visible
ammonium salt plume from the scrubbing apparatus caused by the highly
volatile ammonium compounds in the scrubbing apparatus.  Another variation
that might be considered double alkali is Monsanto's "Calsox" process,
which uses an aqueous organic base as the absorbent solution in combination
with lime as the calcium supplying alkali to produce the t'nrowaway product.

     This paper will discuss some of the chemistry and the status of
technology of sodium/calcium double alkali processes, concentrating for
the most part on work done and data developed by Envirotech Corporation,
FMC Corporation, Arthur D. Little,  Inc., General Motors Corporation and
Kawasaki Heavy Industries, Ltd. since these companies have made significant
contributions to the development of the technology and are the front-
runners in application of the technology.
                                 452

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DEFINITION AND DISCUSSION OF TERMS

     As with any specialized technology, a discussion of flue gas
desulfurization in general, and double alkali technology more
specifically, involves the use of special terminology which has
evolved with the technology.  While it is understandable to those
dealing with the subject on a daily basis, it can be somewhat
ambiguous to others.  To clarify some of these ambiguities, and
to define terms used here and by others describing double alkali
technology development, a number of terms and concepts are defined
and discussed in a general sense.

Absorption/Regeneration Chemistry

     The main chemical reactions that take place in double alkali
systems can be divided functionally into the absorption and regeneration
reactions.  A number of secondary reactions which have very important
effects on the overall functioning of the system also take place.
These include oxidation, softening and sulfate removal reactions which
are discussed under the appropriate headings.

     The regeneration reactions and in some cases the absorption
reactions will be dependent upon which calcium supplying regenerant
is used - lime or limestone.  With lime the system can be operated
over a wider pH range than with limestone.  This wider pH range allows
lime systems to operate over the complete range of active alkali
hydroxide/sulfite/bisulfite whereas limestone systems can only
operate in the sulfite/bisulfite range.

     The main overall absorption reactions are described by the
following equations:

     2NaOH + S02 -> Na2S03 + tUO                                      (1)

     Na SO., + S02 + HO -> 2NaHS03                                    (2)

The main overall regeneration reactions are described by the following

equations for lime and limestone respectively:

     Lime

     Ca(OH),, + 2NaHSO  -> Na9SO  4- CaSO  '1/2 H 04- + 3/2 HO           (3)
           _         _}     Z  j       _)      Z          /
     Ca(OH)2 + Na2SO  + 1/2 H20 -> 2NaOH + CaSO^l/2 t^O-l-             (4)

     Ca(OH)  + NaS0  + 2H0 ? CaSOO -I- + 2NaOH                  (5)
                                 453

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     Limes tone
CaCO  + 2NaHS03 -f 1/2
                                        + CaSOyl/2 l^OI + CC>2 +  ^0  (6)
Active Alkali
      This  term  relates  to  concentration  of NaOH,  Na?CO ,  NaHCO ,
 Na^SO-  and  NaHSO   in  the scrubbing  solutions.   Sodium Bisulfite is
 included in this  definition  although  it  is not  technically an alkali
 (i.e.,  it  cannot  react  with  SO   in  these systems);  however,  it can be
 converted  to  an alkali  by  reaction  with  lime  or limestone.  It should
 also  be noted that  the  molar capacity of each of  these species for
 absorption  of SO,,  is  different,  and can  vary  from zero to 2  moles of
 SO- per mole  of active  alkali.   This  difference in  molar  capacity for
 absorption  of SO,,  is  illustrated by the  following reaction equations:
     NaHCO
              + H00 -v 2NaHSO- + CO-
     j       L     2           32
     (Sodium carbonate molar capacity:   2 moles SO /mole)
             * NaHSO- + CO-t
     j      z        32
     (Sodium bicarbonate molar capacity:   1 mole SO /mole)
     NaOH
          (Sodium hydroxide molar capacity:  1 mole SO /mole)

          U + SO,, + H^O -^ 2NaHSO^
          (Sodium sulfite molar capacity:  1 mole S0-/mole)

          - + SO- -> No reaction
          (Sodium bisulfite molar capacity:  zero mole S0-/mole)
 (7)


 (8)


 (9)


(10)


(11)
     Molar capacity is simply the number of moles of SO  needed to convert
1 mole of the absorbent alkali completely to sodium bisulfite.  Since
there is a difference in the molar capacity of different active alkali
components to absorb SO-, active alkali is a descriptive rather than a
quantitative term.  If the concentration of each of the active alkali
components (moles/liter) is known, however, the capacity of the scrubbing
liquor to absorb SO- (moles of S0-/liter of solution) can be calculated
as the sum of each of the active alkali component concentrations
multiplied by their respective molar capacities as follows:

     Scrubber liquor S02 capacity (moles/liter) =
     2 [Na2C03J + [NaOH] + [NaHCOj  +  [Na2S03]
                                 454

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TOS

     This is an abbreviation for "total oxidizable sulfur".  It
denotes the concentration of sulfur compounds in solution in which
the sulfur is in the +4 oxidation state.  Simply, this is the total
concentration of sulfite plus bisulfite.

     TOS (moles/liter) = [S03=] + [HS03~]

Sulfate is not part of TOS, since the sulfur is in the +6 oxidation
state in this specie.  Sulfur dioxide dissolving in scrubbing solutions
increases the TOS in solution.

Active Sodium

     This is the concentration of sodium in solution which is
associated with the active alkali.

     [Na+]    = [NaOH] + 2 [Na CO.,]  + [NaHCO ] + [NaHSO ] + 2 [Na SO ]
          3CL                 Z  J)          .3          _5         .  j

If NaOH, NaHC03, Na CO , NaHSO  or Na SO  solids are added to double
alkali solutions, the increase in sodium ion in solution is "active
sodium".  If Na SO, or NaCl, for example, is added, the increase in
sodium ion is "inactive sodium".  Active sodium is not increased by
the dissolution of SO,, in scrubber solutions.

Oxidation

     Oxidation in a double alkali system refers to the conversion of
TOS to sulfate by one of the following equations:

     HSO ~ + 1/2 00 -> SO " + H+                                     (12)
        J         24

     SO" + 1/2 00 -> S0,=                                           (13)
       J         24

Simple oxidation of SO- to SO- in the flue gas is also considered
oxidation in the double alkali system:

     S02 + 1/2 02 -> S03                                             (14)

     Oxidation in the system has the effect of changing active sodium
to inactive sodium, or active alkali to inactive alkali.

     Oxidation may occur in any part of the system:  in the scrubber,
the reaction vessels, or in the solids separation equipment.  Rate of
oxidation in the system is thought to be a function of rate of
dissolution of oxygen, pH of the scrubbing solution, and impurities
present in solution.  Oxidation rate is thus affected by composition of
                                 455

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the scrubbing liquor (scrubbing liquors containing high concentrations
of dissolved salts may absorb oxygen more slowly), oxygen  content  of
the flue gas, impurities in the coal and lime or limestone, and  the
design of the equipment (the regeneration and solids separation
sections of the system in particular can-be designed to limit
dissolution of oxygen).

     Oxidation rate is expressed as a percentage and is calculated from
an overall material balance on the system:

     Oxidation rate (%) = [SO   leaving the system (moles)]      IQQ
                          [Total sulfur collected  (moles)]

Sulfate leaving the system is total moles of sulfate in the solid  waste
plus any sulfate in the associated liquor.

Sulfate Regeneration

     This term is a misnomer.  Wh^.t is really meant is sulfate removal
from the system with regeneration of active alkali from inactive sodium
sulfate.  (See Sulfate Removal.)

SujLtate^ jtemovaJL

     Sulfate is removed from the system with regeneration  of active alkali
from inactive sodium sulfate.  Examples of these sulfate removal reactions
are given below:

     Na^SO, + Ca(OH)0 + 2H00 -> 2NaOH + CaSO, -2H_Ov                   (15)
       24         2     2                42
                                         (Gypsum)


     Na.SO, + 2CaSO  -1/2 H-O + H_SO. + 3H_0 -> 2NaHSO_ + 2CaSO  -21U04-(16)
       24         3      2242          3        42
                                                            (Gypsum)

     y Na2SO, + x NaHSO  +  (x+y) Ca(OH)2 +  (z-x) H90 ->               (17)

        (x+2y) NaOH + x CaSO^y CaS04'z ^04-
                      (mixed  crystal or solid solution)


     Na0SO, + 3H00 Electrolytlc cel1 > 2NaOH + H0SO. + H0 4- 1/2 00    (18)
       242                               2422

     Sulfate removal should be accomplished in  an  environmenta.ll>  acceptable
manner; a simple purge of soluble Na^SO, from the  system  to land or water-
way disposal is not acceptable in large quantities.
                                 456

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Softening

     This term is used to describe various methods used to lower the
dissolved calcium ion concentration in scrubber solutions.  The
purpose of softening the scrubbing liquor before recycling to the
scrubber is to assure that it is subsaturated with respect to gypsum.
This reduces the gypsum scaling potential in the scrubber.  Following
are examples of softening reactions:

     Ca4"1" 4- Na2C03 -> 2Na+ + CaCO.4-                                   (19)

     Ca++ + Na SO  + 1/2 HO + 2Na+ + CaSO -1/2 H 04-                 (20)
              +  J        L-               -J      
     Ca++ + C02 + H20 -> 2H+ + CaCO 4                                 (21)

     In each of the above reactions, calcium ions are removed from solution
as part of an insoluble material, outside the scrubber system.  Reactions
(19) and (21) are referred to as carbo.-.ate softening.  Reaction (20) is
considered sulfite softening.  Generally, dilute systems employ carbonate
softening while concentrated systems employ sulfite  to prevent scaling
in a system.

Dilute ys_. Concentrated System

     Dilute or concentrated refers to the active alkali concentration
in a particular system.  This differentiation is made because, in
theory at least, based on their solubility products  in water, both
CaSO, and CaSO,. should not precipitate from a solution of sulfite
and sulfate simultaneously, unless the concentrations of sulfite and
?ulfate are present in a certain ratio.  This can be shown by dividing
one solubility product equation by the other:
             [S03] =
from this , cancelling Ca   ion concentration
             =  constant
      [so3
The ratio of sulfate to sulfite for simultaneous precipitation of
CaSO/ and CaSO^ is shown to be a constant.

     The constant in the above equation is the ratio of solubility
product constants of calcium sulfate and sulfite.  Then, in theory, if
                                 457

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the ratio of sulfate to sulfite is higher than this constant, only
calcium sulfate should precipitate; and if the ratio is lower than the
constant, only calcium sulfite should precipitate.

     This very simplified consideration of the chemistry given above
is clouded in the "real world" by factors that contribute to non-
ideal behavior in these systems.  These factors include changes in
ionic activities in solutions containing high electrolyte concentrations
and evidence of coprecipitation of calcium sulfite and sulfate in the
form of a "mixed crystal" or "solid solution" in a manner which is not
completely understood at present.^'-^

     With due consideration to the non-ideal behavior of these systems,
however, under given conditions, a ratio of sulfate to sulfite in
solution can be determined at which the previously cited examples hold.
The ratio establishes a definition for "dilute" or "concentrated"
double alkali systems.  When the ratio is such that either gypsum or
both gypsum and calcium sulfite will precipitate from the solution with
the addition of slaked lime, then the system is "dilute".

Lime or Limestone Stoichiometry

     Lime or limestone Stoichiometry can be expressed as a percentage,
based on an overall material balance around the system:

     T .   c.  ...         moles CaO added   	      nn
     Lime Stoichiometry = :			7  x  100
                          mole sulfur collected

                 . . .         moles CaCOo added         ,_
     Limestone Stoichiometry = ;	J		  x  100
                               mole sulfur collected

Lime or limestone Stoichiometry is an indication of the efficiency of
usage of lime or limestone in the system.  Ignoring alkali components
in the flyash collected, 100% Stoichiometry is complete utilization;
stoichiometries over 100% represent less efficient utilization of
lime or limestone.

Feed Stoichiometry

     This is calculated by a material balance around the scrubber.
It is usually expressed as the ratio:

         ,   .  ,    Liquor S00 Capacity (moles/liter) x Flow (liters/min)
     Feed Stoxch = -3	2	^ (mole/min)	

                   This ratio is evaluated for streams
                   entering the scrubber.
                                458

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     Feed stoichiometry is a measure of the ability of the incoming
liquor to react with or absorb all of the incoming SCL in the
scrubber, assuming ideal contact of gas and liquor.  Feed stoichiometry
above 1.0 is required for high SO- removal.  At feed stoichiometries
at or below 1.0, assuming ideal contact between the gas and liquor,
there will be significant equilibrium SO,, partial pressure above the
liquor, and thus S0? removal is theoretically limited to the value
calculated on the basis of this SO,, partial pressure in the exiting
flue gas.
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DESIGN CONSIDERATIONS

     A commercial double alkali system must be designed to remove the
desired quantity of sulfur oxides from a given flue gas stream, while
operating in a reliable manner and discharging environmentally acceptable
solid waste product.  In fulfilling these design objectives, cost is
also an important factor.

S02 Removal

     The fact that small quantities 01 sunur aioxiae can oe removed
from large amounts of relatively inert gas by cyclic processes involving
absorption into aqueous solutions of sodium sulfite/bisulfite has been
                                      (i
known for some time.  Johnstone et al.  published a paper in 1938 giving
data on the vapor pressure of S02 over solutions of sulfite/bisulfite
and methods of calculating these equilibrium values under various
conditions.  The equilibrium partial pressure of S0~ above sulfite/bisulfite
solutions, the theoretical limit which a practical design can approach,
is generally a function of solution temperature, pH, concentration of
sulfite/bisulfite and total ionic strength.  Since Johnstone's work a
number of organizations have pursued this technology with laboratory,
pilot plant and full scale applications for flue gas desulfurization,
and many have demonstrated the ability for high removal efficiencies.
(It should be noted that although Johnstone's work was aimed at cyclic
processes with thermal regeneration, such as the Davy Powergas system,
the vapor pressure data is also applicable to double alkali systems
which use chemical regeneration.)

     Once methods have been established to determine equilibrium S09
vapor pressure over scrubbing solutions, of the various concentrations
to be encountered in an operating system, it becomes a matter of
standard chemical engineering practice to design adequate gas absorption
equipment to accomplish the desired SO,-, removal in a system.   For
comparison, it should be noted that the design of lime/limestone slurry
absorption equipment is further complicated by the kinetics of dissolution
of the lime or limestone, the particle size of the suspended material,
and the crystal morphology of the lime or limestone.

Reliable Operation

     System reliability can be adversely affected by two classes of
problems, chemical and mechanical.

     The mechanical problems include malfunction of instrumentation
and mechanical and electrical equipment such as pumps, filters,
centrifuges, and valves.  These problems in a commercial FGD system
can be minimized by carefu] selection of materials of construction and
equipment and by providing spares for certain equipment such as pumps
                                460

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and motors which are expected to be in continuous operation and are
prone to failure after a relatively short period of operation.
Another important consideration in minimizing mechanical problems
is the institution of a good preventive maintenance program.

     The chemical (or physical/chemical) problems which may be
associated with a double alkali system include scaling, soluble
sulfate build-up, production of non-settling solid waste product,
water balance and build-up of non-sulfur solubles which enter the
system as impurities in the coal or lime.  Each of these factors
is associated with reliable system operation, or production of
an environmentally acceptable solid waste.

     a. Scaling - One of the primary reasons, and probably the most
important, for development of double alkali processes was to
circumvent the scaling problems associated with lime/limestone
wet scrubbing systems.  Therefore, a double alkali system should be
designed to operate in a non-scaling manner.

     Scaling is caused by precipitation of calcium compounds from
scrubbing liquors, on the surfaces of various components of the
system.  When this occurs in the scrubber it is particularly
troublesome since the flue gas path through the scrubber, if
affected, could cause shutdown of the boiler-scrubber system and
lower reliability.

     Since scrubbing in double alkali systems employs a clear
solution rather than a slurry, there is a tendency to ignore
potential scaling problems.  Testing experience with double
alkali systems has indicated, however, that scaling can occur
and indeed the problem should be a legitimate concern in the
design of any system.  Both gypsum and carbonate scale build-up
has been recognized in these systems.  Gypsum scaling is caused
by the reaction of soluble calcium ion with sulfate ion formed
in the system through oxidation of the absorbed sulfur dioxide
or from absorbed sulfur trioxide according to the reaction:

              Ca^ + 304= + 2H20    ->    CaS04-2H20  i     (22)
     Gypsum scaling is controlled by softening the regenerated
liquor prior to recycling to the scrubber.  Softening ensures that
the liquor rscycled to the scrubber system is unsaturated with
respect to gypsum; therefore, with proper softening even if some
sulfate is formed in the scrubber, the liquor will not be saturated
                                461

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with gypsum and cause scaling on the inside surfaces of the scrubber.
In concentrated active alkali systems, a special softening step
is not necessary since high sulfite concentration is maintained
throughout the system.  This sulfite maintains a low calcium ion
concentration  (sulfite softening), and thus maintains the scrubbing
solution unsaturated with respect to gypsum.

     Based on experience gained in lime/limestone scrubbing testing,
a certain factor of safety in the prevention of gypsum scaling probably
exists in double alkali systems.  Gypsum has been found to
supersaturate easily to about 130% saturation; thus, even if sulfate
formation is higher than expected, gypsum may not precipitate in
the scrubber until the liquor is over 130% of saturation with respect
to gypsum.

     Carbonate scaling usually occurs as a result of localized high
pH scrubbing liquor in the scrubber where C09 can be absorbed from
the flue gas to produce carbonate ion.  This ion subsequently
reacts with dissolved calcium to precipitate calcium carbonate
scale according to the following series of reactions:

              Carbon dioxide absorption by high pH liquor:

              C02  +  2 OH"    -v    C03=  +  H20             (23)

              Calcium carbonate scaling:

              C03= +  Ca++   -*   CaC03  i                    (24)


     Based on experience with the General Motors full scale double
alkali system,5 carbonate scaling could occur with scrubber liquor
pH's above 9.  At lower pH, the carbonate/bicarbonate equilibrium
system tends to limit the free carbonate ion and thus prevent
precipitation of calcium carbonate:

              H+  +  C03=   ,:   HC03~                        (25)

Thus, carbonate scaling can be eliminated by control of pll in the
scrubber.

     b.  Production of Non-Settling Solids - Under certain conditions,
the waste product solids produced in the regeneration sections of
various double alkali systems have a tendency not to settle from the
scrubber liquors.   This creates problems in the operation of settlers,
clarifiers,  reactor clarifiers,  filters and centrifuges.   Although

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the phenomenon has been observed in the laboratory testing conducted
by EPA on dilute systems and in the laboratory and pilot plant work
conducted by Arthur D. Little, Inc. (ADL) on dilute and concentrated
systems, it is not completely understood.3

     Some of the factors thus far identified which appear to affect
the solids settling properties are reactor configuration, concen-
tration of soluble sulfate, concentration of soluble magnesium and
iron in the liquor, concentration of suspended solids in the
reaction zones, and use of lime vs. limestone for reaction.  Based
on laboratory work in dilute systems (about 0.1 M active sodium)
using limestone it appears that solids settling characteristics
degraded significantly at soluble sulfate levels above 0.5 M.  Based
on laboratory work with concentrated systems (about 0.45 M TOS,
5.4 pH, 0.6 M sulfate) using limestone, marked degradation of solids
settling properties occurred at a magnesium level of 120 ppm and
virtually no settling of solids occurred at the 200 ppm magnesium
level.  Equal degradation of solids settling properties also occurred
in concentrated systems when the sulfate level was raised to the
1.0 M level while maintaining low magnesium level (about 20 ppm)
and keeping other variables constant.

     Envirotech  advocates the recycle of precipitated solids from
the thickener underflow to the reaction zones in an effort to grow
crystals which settle faster and are more easily filtered.

     ADL cites reactor configuration as being important in the
production of solids with good settling and filtration characteristics.
Their basis for this is comparative tests of a simple continuous flow
stirred tank reactor  (CFSTR) with the ADL/Combustion Equipment
Associates (ADL/CEA) designed reactor system under similar conditions.
The ADL/CEA reactor system appeared to give better settling solids for
a greater variety of conditions than a simple CFSTR.

Environmentally Acceptable Solid Waste

     Ideally, the solid waste product produced by double alkali FGD
systems should be environmentally acceptable.  Some of the properties
which can be ascribed to such a solid waste product are listed below:

          non toxic
          low soluble solids content, non-leachable
          low moisture content
          non-thixotropic
          high corapressive or bearing strength
                                 463

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     In order to generate waste product solids which have properties
approaching those listed, the following design considerations are
appropriate:

         sulfate removal
         water balance/waste product (cake) wash
         gypsum vs. calcium sulfite
         sludge fixation technology

     a.  Sulfate Removal - In double alkali systems, some of the
sulfur removed from the flue gas takes the form of soluble sodium
sulfate due to oxidation in the system, thus changing some of the
active sodium to the inactive variety.  When sodium in the system is
converted to the inactive form (Na2SO/),  it is relatively difficult
to convert back to active sodium.  To convert inactive sodium to
active sodium, sulfate ion must be removed from the system in some
manner, while leaving the sodium in solution.  The alternative to
this is to remove the sodium sulfate from the system at the rate
it is being formed in the system.  This alternative is not desirable
since it is wasteful of sodium and generally is carried out by
allowing the sodium sulfate to be purged from the system in the
liquor which is occluded in the wet solid waste product.'  The solid
waste product can then potentially contribute to water pollution due
to leachability.   Water run-off can lead to contamination of surface
water, while leaching and percolation of the leachate into the soil
can result in contamination of the ground water in the vicinity of
the disposal site.  Failure to allow for sulfate removal from
double alkali systems will ultimately result in a) precipitation
of sodium sulfate somewhere in the system if active sodium is made
up to the system, or b) in the absence of make-up, eventual deterioration
of the S02 removal capability due to the loss of active sodium
from the system.

     The equations  (15), (16), (17) and (18) shown previously under the
definition of "sulfate removal" describe several sulfate removal
techniques which have been used in FGD system pilot tests.

     The first equation depicts the sulfate removal technique
used in dilute active alkali systems:

       Na2S04  +  Ca(OH)2  +  2H20  J  2NaOH  + CaS04'2H20  4-   (15)
                                                (Gypsum)
     Concerning the full-scale dilute alkali system installed and
operating at the Parma, Ohio, transmission plant of General Motors,
and dilute systems in general, Phillips-" stated:
                                464

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            "The presence of Na2SO^ in the scrubber effluent
          is the prime factor influencing the design of the
          regeneration system.   Na2SO^ is not easily regenerable
          into NaOH using lime.   The reason being that the
          product, gypsum, is relatively soluble. . .  .  Na2SO,
          cannot be causticized  in the presence of appreciable
          amounts of S03= or OH~ because Ca"^ levels are held
          below the CaSO/ solubility product.  To provide for
          sulfate causticization, the system must be operated
          at dilute OH~ concentrations below 0.14 molar.  At
          the same time, SO/= levels must be maintained in the
          system at sufficient  levels to effect gypsum
          precipitation. ...   We selected 0.1 molar OH~ and
          0.5 molar S0^= as a design criteria."

In a previous paper, Phillips^  showed a plot of equilibrium caustic
formation in Ca(OH)2~Na2S04 solutions at 120F which is the basis
for selection of the design criteria.  The essence of this discussion
is that if the active sodium concentration is sufficiently dilute,
sulfate can be removed from the  system by simple precipitation as
gypsum by reaction of lime with  sodium sulfate.

     Since, as explained above,  this reaction will not proceed to a
great extent in concentrated active alkali systems, other techniques
must be employed to effect sulfate removal in these systems.

     The second equation depicts a technique which is used in the full
scale double alkali systems in  Japan, and which has been pilot tested
by ADL under contract with EPA:
            + 2CaS03-l/2 H20 + H2S04 + 3H20 -> 2NaHS03 + 2CaSO^'2H20 4-  (16)
                                                           (Gypsum)

     This technique is used to precipitate gypsum by dissolving calcium
sulfite in acidic solution thus increasing the Ca++ in solution enough
to exceed the solubility product of gypsum.  Ideally according to
equation (16) 2 moles of gypsum should be precipitated for each mole
of sulfuric acid added.  In practice, however, this is not the case
since  any material which functions as a base can consume sulfuric
acid and reduce the efficiency of this reaction for its intended
purpose.   Unreacted lime or limestone, sulfite ion and even sulfate
ion can consume sulfuric acid thus lowering sulfate removal from the
system.
                                  465

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     Conceivably, this method of sulfate removal is economically
unattractive in applications with very high oxidation rates, and
where the gypsum produced must be discarded.  The economic picture is
considerably changed where this system is used merely as a slip-
stream treatment to supplement other sulfate removal methods and/or
where the solid product gypsum is saleable as is the case in Japan.

     The third equation describes a phenomenon which has been
referred to as mixed crystal or solid solution formation:

          x NaHS03 + y Na2S04 + (x+y) Ca(OH)2 + (z-x) H20  -^       (17)

             (x-2y) NaOH + x CaSO-j-y CaS04-z H20  *
                           (mixed crystal or solid solution)
                                                     j
This phenomenon is described by R.H. Borgwardt of EPA  as it applies
to lime/limestone wet scrubbing based on pilot plant investigations.
A similar phenomenon has been observed by ADL in some of their early
pilot testing of double alkali systems in conjunction with CEA, and
later in the EPA/ADL dual  alkali test program.

     It appears that under certain conditons the solids precipitated
in lime/limestone and double alkali systems contain sulfate, sulfite
and calcium; however, the liquor from which these solids precipitated,
appears to be subsaturated with respect to gypsum.  This is based on
the fact that pure gypsum crystal could be dissolved in the mother
liquor from which the mixed crystal/solid solution was precipitated.
In addition, the solid material was examined by X-ray diffraction
and found to contain no gypsum; infrared analysis confirmed the
presence of sulfate.

     Borgwardt found that the molar ratio of sulfate to sulfite in
these solids was primarily a direct function of sulfate ion activity
in the mother liquor.  In pilot test work with lime/limestone
scrubbing, with little or no chlorides present and normal magnesium
level (below 1000 ppm) in solution, the sulfate to sulfite molar
ratio in the mixed crystal solids was found to reach a maximum level
of 0.23.  This is equivalent to a [SO^"]/total [SOX] ratio in the
solids of 0.19.

     In pilot test work with concentrated double alkali systems, ADL
observed the simultaneous precipitation of sulfate and sulfite with
calcium in lime and limestone treatment of concentrated double alkali
scrubbing liquors.  This phenomenon was surprising at first, in light
of the reasoning which led to the development of dilute double alkali
                                 466

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systems; i.e., gypsum cannot be precipitated from solutions
containing high active alkali concentrations.  It was a simple
technique for sulfate removal in concentrated systems.  The [SO/]/
total [SOX] ratio observed in pilot double alkali work was as high
as 0.02 as a maximum.3  Coincidentlv,  this is the same value
observed  by Borgwardt in lime/limes tone testing.  This leads
to the suspicion that the same phenomenon is occurring in both
processes.  The mother liquor from which these solids were
precipitated was also found to be subsaturated in gypsum, and when
the solids were examined, pure gypsum was not found.

     Based on the observed data, it appears reasonable to design
a concentrated active alkali system for a particular situation in
which the system oxidation rate is below about 20%.   In this case,
sulfate can be removed at the desired rate, without the necessity
for purging Na2S04 or supplementing the system with other complex
methods of sulfate removal.

     The fourth equation shows sulfate removal as sulfuric acid
in an electrolytic cell:

                     Electrolytic
      Na2S04 + 3H20     cell     ;   2NaOH + H2S04 + H2 + 1/2 02  (18)


     This method is the basis for operation of the Stone and Webster/
Ionics process sulfate removal technique.  In Japan, Kureha/Kawasaki
has pilot tested the Yuasa/Ionics electrolytic process for sulfate
removal in conjunction with their double alkali process.  They feel
that this process will be less expensive overall than the presently
used sulfuric acid addition method.  In addition, they feel that
sodium losses from the system can be cut in half through the use of
this method:  from 0.018 moles Na loss/mole S02 absorbed to 0.009
moles Na loss/mole S02 absorbed.

     Another approach to sulfate control is to limit oxidation.  With
sufficient limitation of oxidation, by process and equipment design,
it may be possible to control sulfate by a small unavoidable purge
of Na2SO^ with the solid waste product.  To design for minimum oxidation,
there should be minimum residence times in equipment where the
scrubber liquor is in contact with oxygen-containing flue gas, and
all reactors, mixers, and solids separation equipment should be
designed to minimize absorption of oxygen from air.  In addition,
it has been reported^ that oxidation of scrubber liquors can be
minimized by maintaining very high ionics strength.  One possible
                                  467

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explanation for this is that high ionic strength liquors are poor
oxygen absorbers and that oxidation in these systems is oxygen
absorption rate limited.

     b.  Water Balance and Waste Product (Cake) Washing - In order
to operate a closed system to avoid potential water pollution problems,
system water balance is a primary concern.   Water cannot be added to
the system at a rate greater than the normal water losses from the
system.

     Generally there is a tendency to add fresh water to a scrubbing
system to serve many purposes.  These include:

         saturation of flue gas
         pump seal needs
         demister washing needs
         slurry make-up needs
         waste product washing

     On the other hand water should only leave the system in the
following ways:

         evaporation by the hot flue gas
         water occluded with solid waste product.
         water of crystallization in solid waste product

     Careful water management, part of which is the use of recycled
rather than fresh water wherever possible,  is necessary in order to
operate a closed system.

     As previously indicated, disposal of wet solid waste containing
soluble salts is ecologically undesirable.   In addition, allowing
active alkali or sodium salts to escape from the system is an
important operating cost factor.  Sodium make-up to double alkali
systems is usually accomplished by adding soda ash (recently quoted
at $49 per ton) at some point in the system.  Thus, both ecological
and economic considerations dictate that waste product washing is
desirable.

     A rotary drum filter, belt filter or centrifuge is usually the
equipment in which the final solids separation is made.  This
equipment can be designed to permit solids washing with fresh water.
                                468

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     One concern in waste product washing is the extent to which the
cake should be washed.  At present, there are no federal regulations
concerning the amount of total dissolved solids (TDS) which is
permitted in a waste product which is to be disposed of as landfill.
The future, however, may unfold stringent regulations in this area.
One obvious consideration in waste product washing is system water
balance.  Unlimited waste product washing is not possible if a closed
system operation with no liquid stream discharge is a goal.  Another
more subtle reason for limiting waste product washing is the potential
problem of non-sulfur/calcium solubles build-up in the system.  These
non-sulfur/calcium solubles enter the system with the flyash, flue gas,
the lime and/or limestone and the make-up water.  Probably the soluble
material in highest concentration would be sodium chloride which results
from the absorption of HC1 from the flue gas by the scrubber solution.
A material balance around the system at steady state necessitates
that solubles leave the system at the rate they enter.  Thus, depending
upon how well the waste product is washed, a certain level of non-sulfur
solubles will be established in the system.  Since the only mechanism
for these solids to leave the system is as part of the wet solid
waste, a certain purge rate is necessary.  This purge also necessitates
the loss of some sodium from the system.  Practical limitations in
filter design and water balance probably would limit a system to two
or three "displacement washes" of the waste product (one displacement
wash means washing with an amount of fresh water equivalent to the
amount of water contained in the final wet waste product per unit of
waste) .   Depending on the characteristics of the waste product and
the design of the washing system, one displacement wash can reduce
the solubles content of the waste product by as much as 80%.
     c.  Gypsum vs. Calcium Sulfite - Although gypsum
is more soluble than calcium sulfite hemihydrate (CaSQ^' 1/2
gypsum may be considered a more environmentally acceptable end
product.  The solubility of gypsum in water is about 0.25%; that
of calcium sulfite is on the order of 0.0025%.  It is interesting to
note that while gypsum is a naturally occurring mineral, calcium
sulfite is not found in nature.  In the solid x^/aste product (sludge)
from lime/limestone and double alkali FGD systems, gypsum has better
handling properties than calcium sulfite.  Sludges containing a
high ratio of gypsum to calcium sulfite are less thixotropic, better
settling, more easily filtered, and can be more completely dewatered
than sludges containing a high proportion of calcium sulfite.  Another
important characteristic x^hich has been attributed to high gypsum (as
opposed to calcium sulfite) sludges is their higher compressive or
bearing strength.  Typically, lime/limestone systems which generate
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solids having a high proportion of calcium sulfite can be filtered
to 40-50% solids, while some double alkali systems producing high
gypsum cake can be filtered to over 65% solids.^0

     Some explanation for the behavior of these sludges is given by
Selmeczi and Knight.H  Although filter cakes appear dry, they still
contain a considerable amount of water and thus, upon vibration or
application of stress, they have the tendency of again becoming fluid.
This thixotropic property and high moisture content are both explained
by the morphology of calcium sulfite clusters.  Due to the highly
open, porous or sponge-like nature of these clusters, a considerable
amount of water is retained in the clusters.   The calcium sulfite
crystals are rather fragile and break under pressure releasing some
of the water, which results in the sludge becoming fluid.

     It is possible in some double alkali systems to produce a high
gypsum product.  In Japan, where by-product gypsum is a saleable
product, the calcium sulfite solids produced are oxidized completely
to gypsum in a separate oxidation process tacked on to the tail end
of the system.  In applications where high excess combustion air is
present in the boiler or where low sulfur coal is burned or a
combination of these conditions is present, the oxidation rate in the
system tends to be high (possibly about 90%)  and the proportion of
gypsum in the sludge tends to be high.  In some dilute systems the
proportion of gypsum in the sludge can be increased by augmental
aeration of the scrubbing liquor.12  Crystal seeding techniques used
in conjunction with augmental aeration can produce relatively coarse
grained gypsum crystals with good dewatering and structural properties
in the final waste product.

     d.  Sludge Fixation Technology - Chemical or physical fixation of
the sludge produced in a double alkali system is another potentially
important means of producing an environmentally acceptable solid waste
product.  This technology is under investigation by I.U. Conversion
Systems, Inc., Chicago Fly Ash, Dravo Corporation, and Chemfix
Corporation.  Most of their efforts are concentrated on sludge produced
from the more prevalent lime/limestone systems; however, there is also
some evaluation of double alkali sludges.  The objective of sludge
fixation technology is the production of a non-toxic, unleachable
solid waste product which has reasonably high load bearing strength.
If double alkali sludges are amenable to this type of treatment, the
need to reduce soluble sulfates in the solid waste product becomes
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less of a problem.  Some sodium sulfate has been found to be
physically or chemically tied up in the solid calcium sulfate/
sulfite crystal lattice;-^ however, the extent of this phenomenon is
not generally considered to be adequate to remove all of the sodium
sulfate produced via oxidation.  Sludge fixation technology may
be a mechanism by which additional sodium sulfate can be removed
from the system without adverse environmental effects.  There is
some concern as to whether this is viable, however, since sludge
fixation chemistry involves pozzolanic reactions between calcium
compounds and flyash components in the sludge x^hich may only
involve multivalent ions rather than monovalent sodium.  In other
words, monovalent ions such as sodium may either a) not take part
in the pozzolanic reactions, or b) inhibit or limit such reactions.
Further investigation is called for in this area.
Dilute vs. Ccmcentrated System

     The selection of a dilute or concentrated double alkali system
is an important design consideration in any application.  In general
it can be stated that the concentrated systems are more suited
to applications in which oxidation is expected to be relatively
low, and that, conversely, dilute systems are favored in applications
where oxidation rates are high.  High sulfur Eastern coal applications
on utility boilers where excess air is controlled carefully and
maintained at the lowest value consistent with complete combustion,
the concentrated systems may be favored.  On the other hand, in
utility or industrial boiler applications where Western low sulfur
coal is burned, and/or where control of oxidation is difficult due
to high excess air, the dilute systems may be favored.

     Oxidation rate is promoted when low sulfur coal is burned, since
the ratio of oxygen to sulfur dioxide in the flue gas is higher than
in high sulfur coal applications.  Since oxidation is a strong function
of the rate of absorption of oxygen, liquor which is dilute in TOS
is subject to having a greater proportion of these species oxidized
by a given amount of absorbed oxygen than one in which the TOS is
more concentrated.

     Under a given set of conditons without consideration given to
waste disposal, a concentrated system can be installed at lower
capital cost than a dilute system as previously discussed; however,
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the desirability to produce a manageable solid waste (dilute systems
can be designed to produce high gypsum sludges) could, in cases,
override the economic issue.

Costs

     Based on cursory design and cost analysis, with the assumption
that a single scrubber device can be used to remove particulates and
SO? to the extent required to meet new source performance standards,
the capital and operating costs of double alkali systems appear to be
significantly less than those for a lime or limestone system designed
for the same requirements.-^

     Generally, the dilute active alkali systems tend to be higher
in capital costs than the concentrated systems since both equipment
size and process flows are required to be larger to accomplish the
same degree of desulfurization.  Methods used for sulfate removal and
for reduction of scaling tendencies will affect both capital and
operating costs.

     Since there are presently no full scale utility applications in
the U.S., a discussion of projected costs for such an application
can only be based on costs for actual industrial boiler systems,
vendor cost estimates and other engineering estimates based on
hypothetical cases.  Actual capital costs for industrial boiler
applications tend to be high on a per KW basis compared to what would
be expected in a large scale utility system because a) these systems
are first-of-a-kind applications and consequently are designed for
various operating contingencies, b) they are relatively small scale
systemseconomies of scale would be expected in larger scale
units, and c) there are more than the usual equipment redundancies
e.g., four separate scrubbers to control only 32-40 Mw equivalent of
flue gas.  Vendor cost estimates tend to be less than complete and
thus low, since they generally do not take into account all of the
details that need to be considered for a specific application with
its unique requirements.  Engineering estimates are just that,
estimates based on certain reasonable assumptions.

     With the above qualifications, some double alkali system costs
can be given.

     a.  Actual Industrial Boiler System^ - The General Motors
industrial boiler system was installed for about $3.5 million.
Based on flue gas rate, it is presently equivalent to a 32 Mw system;
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however, the regeneration system is designed to handle 40 Mw equivalent.
The GM system is a dilute system.

             Unit Capital Cost:  $88/Kw
     Unusual features:

          4 separate stainless steel scrubbers
          2 separate filters
          overdesigned reactor clarifiers
          first-of-a-kind system

     b.  Vendor Cost Estimate - FMC Corporation1^ has estimated the
cost of a double alkali S02 removal process for a 150 Mw utility boiler
system to be about $6 million.   Some of tne assumptions and components
of this estimated cost are shown in Table 1.

             Unit Capital Cost Estimate:  $40/Kw

     c.  Engineering Cost Estimate - TVA has prepared a preliminary
engineering cost estimate for a limestone double alkali process on
a 500 Mw, new, coal fired power unit burning 3.5% sulfur coal designed
for 90% S02 removal with on-site solids disposal. ->

             Unit Capital Cost Estimate:  $61/Kw

     For comparison, on a similar basis, the TVA estimate for a
limestone slurry process is $50/Kw.  Note that this comparison is
in conflict with the cursory design referred to above.

     Obviously the data base for double alkali system costs is
extremely thin compared to that for lime/limestone systems.  The
costs cited above are given only to establish a basis for further
consideration.
                                473

-------
                  Table  1.  ESTIMATED CAPITAL COST

                 FMC CORPORATION S02 CONTROL PROCESS

         Retrofitted Parallel Scrubbers for 1-150 Mw Utility Boiler
                                 and
                     Complete Regeneration Plant
               Fully Instrumented, Installed & Operable

                    	Thousand $	
                      Materials _          Installation              Total

DIRECT COSTS

Scrubbing Section        497                   430                   927
Regeneration             381                   706                 1,087
Thickener and Offsites   465                   310                   775
Buildings, Foundations
 and Structural          428                   436                   864

SUB TOTAL A            1,771                 1,882                 3,653

INDIRECT COSTS

Engineering
  (17,000 MH @$16/hr.)                                               272
Field Indirects
  (140% of Direct Labor)                                           1,330
Fee
  (5% on $5,255,000)                                                 263

SUB TOTAL B                                                        1,865

OTHER COSTS

Proprietary Process Fee
  (Based on 150 Mw)                                                  198
Contingencies
  (5% on $5,518,000)                                                 276

SUB TOTAL C                                                          474
TOTAL A + B + C                                                    5,992

NOTE:  Includes chemical storage, reheaters, building, structural
       steel, flue gas ducting, waste solids handling and storage,
       insulation, steam tracing, startup, and operator training
       in addition to complete scrubbing system.
                                 474

-------
STATUS OF TECHNOLOGY

     A number of variations of double alkali FGD systems have been
tested and studied extensively during the past few years by equip-
ment vendors, potential users, and EPA.  Some of the results of test-
ing and a description of some significant systems tested will be
discussed here.   In addition, some of the planned full scale installa-
tions will be discussed to illustrate the commitment made by industry
to this technology.

     In the United States, Arthur D. Little/Combustion Equipment
Associates (the two companies have agreed to develop and market the
technology jointly), Envirotech Corporation and FMC Corporation have
all conducted extensive pilot plant testing with the aim of marketing
sodium based double alkali systems for FGD applications on utility and
industrial boilers.  General Motors Corporation has undertaken to
develop a double alkali process for use in their industrial boilers
through pilot plant testing and, later, the installation of the first
full-scale industrial boiler application of this technology in the
country.  General Motors does not intend to market their system;
however, the results generated through their efforts will be in the
public domain.

     In Japan, the Showa Denko KK Company and Kureha Chemical Industry
Company/Kawasaki Heavy Industries have developed sodium based double
alkali systems through pilot plant testing and have gone on to relative-
ly large full scale FGD applications which are currently operating.
Due to different economics in Japan, the processes developed and
installed by these companies produce saleable by-product gypsum rather
than a disposable solid waste product.  Another interesting difference
between the development of technology in Japan and the U.S. is the use
of limestone rather than lime as the source of calcium for the Japanese
processes.  In the U.S. the major emphasis in development and in
commercial application has been with lime.

     This discussion on the status of technology is presented by system
developer or vendor, with emphasis on:

          'System descriptions
          Test results/operating experience
          Plans for future testing or full-scale application.
                                  475

-------
Envirotech Corporation

     The Envirotech testing is being cqnducted in a 2500 ACFM pilot
plant at the Gadsby Station of Utah Power and Light Company in Salt
Lake City, Utah.  The pilot plant was constructed in late 1971.  Test-
ing began in January 1972.  Flue gas is supplied to the pilot plant
from No. 3 boiler, a 100 Mw coal fired unit.

     a.  System Description - Envirotech has tested and continues to
test a number of configurations in the pilot plant.  Particulate
loading in the flue gas can be varied considerably since the flue gas
take-off point from the power boiler can be upstream or downstream of
a mechanical separator and an electrostatic precipitator or between
the two.  Two types of scrubber systems have been tested, a polysphere
scrubber containing two trays of balls, and a venturi/cyclone separator
scrubber.  Two types of mist eliminators were tested, a spin vane in
series with a cyclone, and a Euroform chevron type (this type of curved
chevron demister allows the de-entrained liquid to flow from the system
perpendicular to the gas path).  Although the majority of testing was
conducted in a dilute mode of operation which Envirotech calls the
"sulfate mode" due to employment of augmental oxidation, they have
recently also begun testing a concentrated mode of operation.

     Envirotech has stressed equipment development in conjunction with
process development.  Use of reactor clarifiers is stressed to main-
tain high suspended solids content in the regeneration reaction zones.
Quenching the incoming flue gas with recycle liquor (as opposed to
fresh water) to avoid water balance problems has been stressed.  Liquor
introduction in a "dentist bowl" is used as a technique to avoid wet/
dry interface fouling problems, while still providing the x^ater needed
to quench the hot flue gas.

     Figure 1 is a slightly modified version of the basic sulfate mode
flow scheme tested at the Gadsby station pilot plant by Envirotech.  Al-
though  the majority of the testing was done with a polysphere scrubber,
and the remainder with a venturi, this flow sheet incorporates both.
Augmental oxidation is accomplished in a scrubber recycle tank by sparg-
ing with atmospheric air.   (In the pilot plant over 90% oxidation was
obtained with only a crudely designed sparging system; i.e., a rubber
hose blowing air below the liquid surface.)  This oxidation process con-
verts most of the soluble sulfite to sulfate and thus the name, "sulfate
mode".  The purpose of this is to produce a waste product consisting
mostly of gypsum and therefore having desirable settling, filtration
and dewatering characteristics.  This is workable, consistent with
adequate sulfate removal, since the system operates in a dilute mode.
Sodium sulfate is essentially converted to sodium hydroxide by lime
precipitation of gypsum according to equation (15), with little inter-
ference of sulfite ion.  The extent to which hydroxide can be regener-
                                   476

-------
                   RECIRC. WASH WATER
    FLUE GAS
      IN
      VENTURI
     QUENCHER
1 SCRUBBER



       OXIDATION  jf
          TANK
PUMP
 FRESH WATER
_J. MAKEUP
                                   HP
                                          GAS
                                          OUT
                             FINAL MIST
                             ELIMINATOR
                                                     FILTER
                                                     VACUUM
                                                      PUMP
                                                        RECEIVER
                                                                          CAKE WASH
                                                               ~1   	RFRESH WATER)
                                                  SLAKED LIME   FILTRATE
                                                                 PUMP
  ROTARY
VACUUM FILTER
(BELT TYPE)
SULFATE CAKE
(70-80'* SUSPEN.
   SOLIDS)
WASH WATER BLEED LIQUOR
   TANK       TANK      PUMP
                                                    REACTOR-
                                                    CLARIFIER
                                                           REACTOR
                                                           CLARIFIER -
                                                                                  SUSPEN.
                                                                                 SOLIDS
                                                   PUMP
                                                       SUMP
               FIGURE 1.  ENVIROTECH SULFATE - MODE DOUBLE ALKALI

-------
ated in this way is limited to the range of approximately 0.1 molar OH
concentration.

     The scheme makes use of two reactor clarifiers, a thickener and
continuous rotary drum vacuum (belt type) filter for solids separation.
The reactor clarifiers are units designed for a combined job of
reaction, clarification, and solid particle growth.  Crystal growth
and continued reaction are accomplished by internal circulation of
suspended solids in the central zone of the equipment.  The remainder
of the equipment serves to split the feed slurry into a clarified
liquor overflow and a thickened slurry underflow product.  Reactor
clarifier No. 1 serves these functions for the reaction tank effluent
slurry.  Reactor clarifier No. 2 is used for the softening step.  Soda
ash is added here serving the dual purposes of a) sodium make-up
reagent and b) carbonate supplying reagent for softening.  The soda ash
reacts with soluble calcium, replacing some soluble calcium with soluble
sodium, and precipitating calcium carbonate according to equation (19).
This is carried out in the central reaction zone where the precipitated
solids are caused to coagulate (grow) so that they may be more easily
separated from the mother liquor.  Clear liquor overflowing from reactor
clarifier No. 2 is thus softened (subsaturated with respect to gypsum)
and can be fed to the scrubber circuit as regenerated liquor with no
gypsum scaling potential.  It should be noted that reactor clarifier
No. 2 was added to the pilot plant only after significant gypsum scaling
was observed in the early testing in 1972.  Coagulant, an organic chemical
which may be added to the reactor clarifiers to the extent of a few parts
per million, can serve to aid solids separation.

     The  thickener serves to make a gross separation of product solids
from mother liquor which cuts down on the duty of the filter where the
final separation and washing of  the product solids occur.

     The  equipment arrangement used by Envirotech for testing a concen-
trated mode of operation is somewhat simpler compared to that used in
the sulfate mode.  The absorption section consists of a venturi/cyclone
separator with recirculation.  The regeneration system essentially con-
sists of  two  series stirred tank reactors; the solids separation section
consists  of a single  thickener and continuous rotary  filter.

     b.   Test Results - General  conditions and performance data for the
Envirotech pilot plant operated  in the sulfate mode are  tabulated below:
                                  478

-------
Flue Gas

   Source:  pulverized coal boiler flue gas
   Fuel:  coal, 0.4% Sulfur
   Oxygen content:  5%
   Flow Rate:  1500-3000 ACFM @ 220F
   SC>2, inlet concentration:  250-1500 ppm
   Particulate, inlet concentration:  0.2-0.3 gr/SCF

Absorber System

   Absorber Type:                    Polysphere       Venturi

      S02 Removal:                      90%            80-85%
      S02 Exit concentration:         15-40 ppm
      Particulate exit
         concentration, gr/SCF:       0.0.1-0.02
      L/G ratio, gal./lOOO ACFtf:        20               24
      Scrubber pressure drop,
         in. H20:                      4-10              6-8
      Recycle tank/oxidizer
         residence time, min.:        10-15
      Scrubber liquor 
         Inlet, pH:                   7.5-7.7
         Exit  (typical), pH:          5.8-7.1 (6.5)
      Oxidation rate, %:                ^90

Regeneration System

   Lime stoichiometry:  110-115% of S02 removed
   Reactor residence  time:  30 minutes, total for both reactors
   Regeneration liquor composition:  6.5 pH inlet
                                     12.2-12.5 pH exit
                                     0.1 Molar hydroxide, exit
                                     40,000-45,000 ppm S04=
                                     1000 ppm Cl~
                                     ^500 ppm Ca4^"  (approxi-
                                        mately 100 ppm below
                                        saturation of
                         479

-------
          Solids Separation

             Residence times:  Reactor clarif iers :  1-2 hrs
                               Thickener:  3-4 hrs
             Waste product composition:  30-40% water
                                         1-2% flyash (dry basis)
                                         2% solubles (dry basis)
                                         10-15% unreacted CaC03 or
                                            Ca(OH)2 (dry basis)
                                         remainder:  CaSOx solids
                                            (mostly CaS04'2H20)
             Waste product wash:  1 displacement wash,
                                  80% reduction in solubles

          Discussion - The conditions under which the pilot plant
operated, for the most part, simulated typical conditions for a utility
boiler fired with Western low sulfur coal.  The actual range of S02
concentration in the boiler flue gas was 250-400 ppm since coal contain-
ing approximately 0.4% sulfur was fired in the boiler.   A much larger
range of inlet S02 concentration is, however, indicated above, due to
the. fact S02 was added to the flue gas during some of the later testing
to simulate conditions typical for a utility operating with a higher
coal sulfur content.  The majority of the testing with the higher S02
inlet levels was conducted with the venturi scrubber.  During this test-
ing the flue gas flow rate was at the lower end of the indicated operating
range (M.500 ACFM) .

     The majority of the testing with the polysphere scrubber was con-
ducted at a total pressure drop of 4 inches of water using two trays
of balls.  Figure 2 shows the performance of a single polysphere tray;
S02 removal is plotted against L/G ratio in gal./lOOO ACF at three
different pressure drops (4, 7 and 10 in. H^O) at pH in the range of
5.8-7.1.  Figure 3 shows a plot of S02 removal vs. scrubber effluent
pH at an L/G ratio of 19 gal./lOOO ACF at a total pressure drop of
4 in. H20 across two polysphere trays.  It can be seen that, generally,
two trays operating at a pressure drop of 4 in. H20 are equivalent to
one tray operating at a pressure drop of 7 in.
     S(>2 and particulate levels achieved in the treated flue gas were
well within the requirements of federal new source performance standards
based on the data reported.

     Lime stoichiometry reported for most of the testing was in the range
of 110-115% based on S02 removed.  Envirotech has forecasted, however,
that utilization of lime could be improved so that in a commercial
application one might expect to achieve lime stoichiometry in the range
of 100-110% based on SC>2 removed,6
                                  480

-------
    100
    95-
    90
 LU
 CC  85
   r*
 o
     80
     75 
     t
             10
20
30
40
               L/G  Gal/MACF
   FIGURE 2.  SO2 removal vs. L/G. Coal  fuel
electrostatic   precipitator   discharge.  pH;
5.8 - 7.1, single-stage.
                 481

-------
    100
    90l
 Q
 111
    80
 LU
 DC
  
 o
 W 70
    60
                              o  o
                       o
           345678
          SCRUBBER EFFLUENT pH
   FIGURES. SO2  removal  vs. pH level. Coal
fuelelectrostatic  precipitator  discharge.
L/G,  19 gal/1,000  cu.ft.,  AP =  4 in. H,O.
Two-stage operation.
                482

-------
     The scrubber/regeneration liquors had a chloride content in the
range of 1000 ppm at steady state.  Soluble chloride is expected to
concentrate in most wet scrubbing systems due to the conversion of
coal chloride to HC1 which appears in the flue gas and is absorbed by
scrubber liquors.  There were no apparent detrimental effects noted for
chloride levels in the range experienced in this double alkali appli-
cation.

     The solid waste product, primarily gypsum, appeared to settle and
dewater readily.  The filter cake end product contained 60-70% solids,
generally better than that produced in typical lime/limestone appli-
cations.  The filter cake, however, contained about 2% solubles, some-
what higher than that expected in a typical lime/limestone system, but
probably as low a value as has been obtained in steady state closed
loop operation of a double alkali system.  Experiments indicated that
a single displacement wash could achieve as much as 80% reduction in
soluble solids.  The use of additional wash could conceivably lower
the cake solubles content; however, in actual practice, the design of
the filter, buildup of non-calcium/sulfur solubles in the system,
applicable regulations concerning solids disposal and economic
considerations would determine the need for additional washing.

          Reliability - The pilot plant testing began in January 1972
and continued for 3 months during which period some gypsum scaling
problems were encountered.  The pilot unit was shut down for a period
of about 5 months between the late spring and fall of 1972.  During
the 5 month shutdown a reactor clarifier was added to the flow scheme
to accomplish the carbonate softening step which reportedly eliminated
subsequent gypsum scaling problems.

     The basic sulfate mode flow scheme was then operated for almost
2 years with no shutdown-causing, operating problems between fall of
1972 and August 1974.  The pilot plant was operated mostly by a single
technician per 8-hour shift for 24 hours per day, 5 days per week.
The unit was shut down on weekends for convenience; however, there was
no drainage of scrubbing or regeneration solutions or cleaning of
equipment during the weekend shutdown periods.  In November/December
1973 there was a brief shutdown period in which the venturi scrubber
was tied into the system.  After August 1974, testing of the sulfate
mode was discontinued so that concentrated active alkali systems which
Envirotech has termed "sulfite mode" could be tested and evaluated for
comparison with their dilute sulfate mode of operation.
                                  483

-------
FMC Corporation

     FMC began development work on a sulfur dioxide control system in
the early 1960's at the Company's Modesto, California, chemical plant.
In this plant, barium and strontium sul'fate ores are processed in high
temperature reduction kilns to produce barium and strontium sulfides
with some evolution of SO^.  After some initial experimentation with
lime and limestone scrubbing processes in which severe scale formation
problems were encountered, FMC began work on the double alkali process.
They developed a concentrated active alkali scheme which was put into
service controlling S02 emissions from two reduction kilns at the
Modesto plant in December 1971.  This was probably the first U.S. full-
scale application of double alkali technology.

     a.  System Description - A typical schematic of the "FMC/Link Belt
Alkaline Absorption Process" is shown in Figure 4.

         General

             Absorption - The scrubber system depicted here is what FMC
refers to as their "dual throat" venturi and cyclonic separator.  Absorp-
tion of S02 occurs by conversion of sulfite to bisulfite in the venturi
(equation (2)).   Due to the fact that FMC employs a very concentrated
active alkali scrubbing liquor which is highly buffered by the sulfite/
bisulfite equilibrium system, there is only a very small change in pH
between the inlet and outlet of the venturi, on the order of 0.1 pH unit
(e.g., typical operation of the FMC system might involve venturi inlet
liquor pH of 6.5 and effluent pH of 6.4).  Gypsum scaling does not occur
in these systems since the calcium ion concentration is held well below
that required for gypsum precipitation by the high sulfite concentration
in solution.  This can be referred to as sulfite softening (equation  (20),
Carbonate scaling is not a problem in operation at these relatively low
pH's due to the carbonate/bicarbonate equilibrium system which tends  to
depress the carbonate concentration and favor soluble bicarbonate.

     Make-up sodium is fed as soda ash directly to the scrubber  recir-
culation tank.  No carbonate softening is intended in this step.

             Regeneration - A relatively small bleed of scrubber liquor
is taken from the scrubber recycle loop  to  the regeneration system.
The regeneration system consists of a continuous flow stirred tank
reactor with a 5 minute residence time and  a thickener.  Regeneration
in this concentrated scheme involves only conversion of some of  the
bisulfite to sulfite by reaction with lime  (equation (3)).  There is  no
free hydroxide ion formation.  Clarified liquor from the thickener rich
in sulfite is fed back to the scrubber recirculation tank to raise the
capacity of the scrubber liquor for absorption of
                                   484

-------
       120 PSIG STEAM
FLUE GAS
              FAN
                     1
T
                              TO STACK
                       REHEATER
                CONDENSATE
 IN
 30
               SCRUBBER
     RECIRCULATING
         PUMP
           SPARE
           PUMP
                                   SODA ASH
                                   STORAGE
                                      BIN
                           V
  LIME
STORAGE
  BIN
                               V
                                RECIRCULATING
                                       TANK
                             30 PSIG
                             PLANT WATER
                                        LIME
                                      REACTOR
                FILTRATE
                RECEIVER
                                        THICKENER

THICKENER
UNDERFLOW
PUMP


	 r
                                                                                         AND
                                                                                        CaSOs
                                                                                   EXHAUST
                                                        FILTER
                                                       VACUUM
                                                        PUMP
                                                         	1
                                                       RATE
                                                       URN
                                                       MP    W-
                    FILTRATE
                     RETURN
                      PUMP
                                                                    I
                                                                                   SURGE TANK
      FIGURE 4.  FMC/LINK-BELT ALKALINE ABSORPTION PROCESS FOR SULFUR DIOXIDE CONTROL
                                      SIMPLIFIED FLOW SHEET

-------
             Solids Separation - Solids separation begins in the thick-
ener which produces a concentrated slurry underflow for feed to the
continuous rotary vacuum filter which makes the final separation of
solids.  The FMC system is designed for simultaneous removal of flyash
and S02? therefore, the waste solids will contain a considerable amount
of ash if the system is employed in a coal fired boiler application in
which there is no separate provision for removal of flyash upstream of
the control system.

             Modesto System Description - The double alkali system in
operation at the FMC Modesto chemical plant processes a combined
30,000 ACFM gas stream (550F) containing 5000-8000 ppm S02 from two
barium/strontium reduction kilns.  The scrubber system consists of a
tower (packed with 9 feet of Intalox saddles) and a recirculation tank.
The regeneration system consists only of a single stirred tank reactor
fed with lime and a bleedstream for the scrubber loop.  Solids separa-
tion is accomplished in a rotary vacuum filter producing a solid waste
containing 40-50% solids.  There are no provisions for waste product
washing.  The overall system at Modesto is equivalent to 7-10 Mw based
on exit flue gas flow, and possibly up to 35 Mw based on SC^ removal
capabilities.

     b.  Operating Experience and Testing - FMC has operating experience
in the system at the Modesto plant since start-up in December 1971.  In
addition, FMC constructed a 3500 ACFM pilot plant in a mobile 40 foot
trailer which has been tested at various locations on at least seven
different flue gas and other waste gas streams for control of S02 and
particulates.  The basic flow scheme in the mobile pilot plant is that
previously described and depicted in Figure 4.

             Modesto System - This system has an enviable reliability
and performance record since start-up in December 1971.  As of early
September 1974, the system had been on line for 22,800 hours at 100%
availability for control of kiln off-gases.  The kilns had scheduled
shutdowns approximately every 3 or 4 months for maintenance and/or
change of chemical process service; however, between December 1971
and September 1974, they were in service approximately 95% of the time.
Operation  of the system is now considered routine rather than experi-
mental.  With inlet S02 levels of 5000-8000 ppm, the system has achieved
as high as 99.7% S02 removal; it routinely runs with less than 100 ppm
in the exit off-gas stream.

     The waste product solids from the system are discharged from a
rotary vacuum filter at about 40-50% solids but there is no waste
product washing.  The discharged solids ara reslurried to about 20-25%
solids with other plant waste water streams to be sluiced out to an
on-site disposal pond.  The sludge dewaters by solar evaporation and
percolation into the soil surrounding the pond.  About once a year some.
                                  486

-------
of the drier sludge is dredged from the pond for disposal elsewhere
to create more on-site "running room".

     The only serious drawback to the system is the large sodium loss
due to the lack of waste product wash.  The sodium loss in a concentra-
ted system without cake x^ash is probably greater than that which could
be tolerated in a large scale FGD application.   The loss is both costly
and a potential water pollution problem.
             Pilot Plant Testing - Data reported by FMC which were
taken in a 3 week test, 8 hours per day, in the FMC mobile pilot plant
processing a slip stream of industrial boiler flue gas are tabulated
below:

                 Flue Gas

                    Boiler type:  Stoker-fired coal boiler
                    Fuel:  Coal, 4.8% sulfur
                    Flue gas flow:  2,578 ACFM @ 400F
                    Flue gas composition:  N2 = 76.3%
                                           02 = 7.6%
                                           C02 - 11.4%
                                           H20 =4.7%
                                               100.0%

                                           S02 inlet = 3363 ppm
                                           S02 exit  =  343 ppm
                                           Particulate inlet = 2.4 gr/SCF

                 Absorption

                    SO2 removal:  89+%
                    Absorber type:  Dual throat venturi
                    L/G ratio:   13.6 gal./lOOO ACF
                    Pressure drop:  10 in.  H20
                    Liquor composition:  pH     6-7
                                         total sodium >2 Molar
                                         active alkali >0.5 Molar

                 Regeneration

                    Lime stoichiometry:  - 105% based on S02 removed
                    Soda ash addition:   f 0.026 moles Na2CC>3/mole S02
                                           removed
                    Reactor residence time:  5 minutes
                    Thickener rise rate:  0.3-0.4
                                  487

-------
                 Solids Separation

                    Filter cake composition:  CaSC>3-l/2 H20       47.93%
                                              Ash                 13.95%
                                              CaC03                1.14%
                                              Sodium as Na2SO^     1.18%
                                              H20                 35.80%
                                                                 100.00%

                    Solubles in waste product:  1.84%  (dry basis)
                    Soluble sulfur loss:  0.027 moles soluble sulfur/
                                          mole S02 removed
                    Filter cake wash:  2 displacement wash or less,
                                       90% reduction in sodium

                 Discussion - The results reported are typical for oper-
ation of the FMC concentrated double alkali system in a high sulfur coal
application.  As previously discussed, the concentrated systems are
better suited to high sulfur, low oxygen (rather than low sulfur, high
oxygen) applications due to the necessity to control sulfate formed by
oxidation in the system.  Since sulfate formation rate in the system
is related to the rate of oxygen absorption, sulfate will comprise a
smaller fraction of the total soluble sulfur species in a concentrated
system than in a dilute system.  Thus the soluble sulfur loss is a
small fraction of the S02 removed in these applications; however, it
can be expected to be a larger fraction in low sulfur fuel applications
if all other factors remain constant.

     The FMC system is not designed for sulfate removal by any of the
chemical mechanisms described under the term "sulfate removal"; thus,
there must be a loss of soluble sulfate from the system at the rate
at which it is formed.  This soluble sulfur loss occurs as solubles
contained in the waste product cake moisture.  Apparently, operation
at the very high ionic strengths employed by FMC minimizes the removal
of soluble sulfate via the mixed crystal or solid solution mechanism
described by equation (17).  On the other hand, the high ionic strength
liquor employed by FMC probably absorbs oxygen at a lower rate than the
less concentrated systems, and thus reduces sulfate formation by reduc-
ing oxidation rate.  The soluble solids level reported in the above data
by FMC appears to be as low percentagexjise as any of the values report-
ed for other throwaway product systems in the U.S.  In general, FMC has
stressed lowering sulfate formation rates rather than methods of sulfate
removal.

     Another important factor which influences oxidation rate is scrubber
type.  FMC has conducted tests with a packed tower, venturi, valve tray
(Koch) scrubber and a "disc and donut" scrubber, and has correlated
oxidation rate with scrubber type.  As expected, the scrubbers x^ith the
larger liquor residence times exhibit the higher oxidation rates.
                                  488

-------
     Table 2 presents a summary of the FMC testing with the 3500 ACFM
mobile pilot plant.  A wide range of testing experience is shown for
the mobile pilot plant.  No scaling problems or other major reliability
problems have been encountered in this testing.

     c.  Future Applications - FMC has four double alkali systems
under construction, and a fifth in the design phase in the U.S.  The
largest planned U.S. application of the FMC system is a 150 Mw system
for the control of S02 from the pulverized coal boilers at FMC's
Green River, Wyoming, plant.  The system is scheduled to start up in
the summer of 1975.  In addition, FMC has licensed the Ataka Construc-
tion and Engineering Company of Osaka, Japan, to install their system
in Japan.  The first application of the FMC technology in Japan will
be for the control of S02 from a 45,000 Ib/hr steam boiler at a paper
manufacturing company.  That installation is scheduled to start up in
the first quarter of 1975.

     A summary of the FMC systems planned for near future operation is
given in  Table  3.
                                   489

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                                       Table 2.  FMC 3500 ACFM MOBILE PILOT PLANT TESTING
      Application

  1.  S02 and  flyash,
      stoker boiler
       (FMC Plant
      So. Charleston,
      West Virginia)

  2.  S02 and  flyash
      stoker boiler

  3.  S02 and  flyash,
      stoker boiler
       (General Motors
      Plant)

  4.  S02 and  flyash
-e-     on bark  oil  and
o     coal fired boiler

  5.  S02 and  flyash,
      pulverized coal
      boiler

  6.  S02 and  flyash,
      pulverized coal
      electric power
      boiler

  7.  S02 control,
      sulfuric acid
      plant
Pressure
Test Time S02 Removal Particulate Scrubber Drop Temp.
(Months) (%) Removal (%) Type (in.H20) (F)
6 90+ 99+ Dual 10-15 400
Throat
Venturi
3 90+ 99+ Dual Throat 10-15 350
Venturi
4 90 99 Dual Throat 10 390
Venturi
2 90 99.5 Dual Throat 10 iOO
Venturi
1 89+ 99+ Dual Throat 10 +00
Venturi
4 90+ Dual Throat 4.5-10 150
Venturi,
Koch Tray,
Disc & Donut
1 90+ Dual Throat 4.5-10 L20
Venturi,
Disc & Donut
Flue Gas
02 Content Inlet S02
(%) (ppm)
12 400-1400
10 1800
9-10 600-1200
7 1000
7 3300
5 1000-1200
6 1200

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                          Table 3.   FUTURE FMC DOUBLE ALKALI APPLICATIONS
    Application

1.  Stoker fired
    industrial
    boiler system

2.  Oil and coal
    fired boiler
    (Firestone,
    Potts town, Pa.)

3.  Pulverized coal
    boiler
    (FMC's Green
    River, Wyo.
    Plant)

4.  Oil fired
    boilers

5.  Heating plant
    coal boiler

6.  Paper plant,
    boiler
    (Japan)
      Size
(Mw,  Equivalent)

       50
      150
       13
       14
 Scrubber
   Type

Dual Throat
  Venturi
                         Dual Throat
                           Venturi
Disc & Donut
Disc & Donut
Disc & Donut
S02 Inlet
  (ppm)

  1800
                     1400
  1000
   250
  Start-Up
    Date

First Quarter
    1975
                 December 1974
  Mid 1975
Construction to
start in 1975

  Late 1974
                                                             First Quarter
                                                                 1975

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General Motors

     General Motors (GM) Corporation developed a dilute double alkali
system through pilot testing in a 2800 CFM cross-flow packed bed
scrubber at the GM Chevrolet, Parma, Ohio, plant.  Flue gas for pilot
testing was an isokinetic sampling representing 10% of the total flue
gas flow from a boiler having a steaming capacity of 80,000 Ib/hr and
burning 2% sulfur coal with 100% excess air.

     In the pilot plant, it was found that a 1 molar sodium solution
would give reasonably good S02 absorption, while also regenerating
caustic and precipitating sulfate as gypsum.  It was found that a
maximum concentration of 0.1 M hydroxide could be regenerated in a
1 M sodium solution.  Increasing the sodium ion concentration above
1 M did not give appreciable increase in regenerated hydroxide
concentration.  Lowering the sodium ion concentration, however, gave
a decrease in regenerated hydroxide concentration.

     Optimum lime utilization was found to occur with high speed mixing,
using near stoichiometric quantities of lime.  Eighty percent conversion
of lime was attained in 5 minutes.

     Early in the pilot plant program, GM ran into the calcium scaling
problem; but later, using soda ash softening, they were able to allevi-
ate it.  Reportedly, using soda ash for sodium make-up, they were able
to reduce the calcium content in the scrubber loop from 400 to 250 ppm.

     The pilot plant was operated for a period of about 4 months in
Parma.  Other pilot tests were conducted concurrent with the Parma
tests at another General Motors plant in Livonia, Michigan.8

     Based on the results of testing in the pilot units, General Motors
designed and constructed a full scale system for S02 and particulate
control at  the  Parma plant.

     a.  System Description  - The full scale double alkali system
installed at Parma is shown schematically (only one scrubber is shown)
in Figure 5.  The boiler system consists of four stoker fired boilers,
two with steaming capacities of 100,000 Ib/hr and two with 60,000 Ib/hr,
totalling 320,000 Ib/hr or approximately equivalent to 32 Mw electric
generating capacity.  All of the boilers are equipped with mechanical
dust collectors.

     The double alkali system was designed to handle a steaming capacity
of 400,000 Ib/hr anticipating the addition of a fifth boiler in the
future.
                                   492

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                           SODA ASH
vo
                           REACTOR
                           CLARIFIER
                             =2
                           FIGURES.  GENERAL MOTORS' DOUBLE-ALKALI SYSTEM.

-------
     The absorption system consists of four Koch valve tray scrubbers
containing three trays per scrubber.  The trays have a type of floating
bubble cap which rises and falls adjusting to gas flow.  The upper
portion of the scrubbers contain mesh mist eliminators.  The scrubbers
are constructed of 316-L stainless steel.

     The regeneration system handles the bleed flow of spent liquor
from the four scrubbers.  It consists of two mix tanks or reaction
tanks (CFSTR's), two s laker-feeders (one on standby) and two reactor
clarifiers.  One of two continuous drum filters makes the final solids
separation (the second is on standby).  The filters are equipped with
spray nozzles to allow for cake wash.

     The system operates similarly to the Envirotech dilute scheme,
with the primary exception that there is no augmental oxidation;
however, due to the fact that the boilers operate with high excess
air, high oxidation rates in the system are expected, and have been
experienced.

     The primary functions of some of the major equipment are given below:
         Mix Tank No . 1 - Spent scrubber solution containing
       and NaHS03 is mixed with the slurry underflow from reactor
clarifier No. 2 which should contain NaOH, Na2S03 and CaCC>3.  This
tank was designed to increase lime utilization by making use of the
CaC03 that results from the softening reaction in reactor clarifier
No. 2 (discussed later), to neutralize some of the bisulfite in the
spent scrubber solution.  The extent of CaCC^ utilization, however,
is highly dependent on the scrubber bleed stream pH.  If this pH is
not low enough, very little, if any, CaC03 will be utilized as shown
in the following reaction (previously shown under limestone regeneration)

         CaC03 + 2NaHSC>3 + 1/2 H20 *

             CaS03'l/2 H20 I + CC>2 * + H20
         Mix Tank No. 2 - The primary reactions between lime and sul-
fite, bisulfite and sulfate begin to occur in this tank, precipitating
gypsum and calcium sulfite.  Effluent from mix tank No. 1 and filtrate
from the filter are mixed with lime in this tank.

         Reactor Clarifier No. 1 - Slurry feed is received from Mix Tank
No. 2.  Here the reaction between lime, sulfite, bisulfite and sulfate
is continued.  The overflow consists of clear regenerated liquor, and
the underflow is a thickened slurry of waste solids which is fed to the
filter for final solids separation.
                                  494

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         Reactor Clarifier No. 2 - The overflow from reactor clarifier
No. 1 is softened via equation (18) or (21) with soda ash or CC>2,
respectively, in this unit before it is fed back to the scrubber
system.

     b.   Operating Experience - General conditions of operation and
performance data for the full-scale system at Parma are tabulated
below:

         Flue Gas

             Source:  four coal stoker fired boilers
             Fuel:  coal, 2.3-2.6% sulfur, 2.5% sulfur average
             Boiler excess air:   50% large boilers
                                 120% small boilers
             Oxygen content:  8.5-11.5%
             Flow rate:  60,000 ACFM @ 350F - Large boilers ,    ,  . o
                         50,000 ACFM @ 550F - Small boilers      esign
                         26,000-28,000 SCFM/scrubber, typical of
                              recent operation
                         (Normally, 2 of 4 boilers and scrubbers
                         in operation)
             S02 inlet concentration:  900-1600 ppm (1200-1300 ppm
                                                     average)
             Particulate inlet concentration:  0.3 gr/SCF

         Absorber System

             Absorber type:  Koch valve tray scrubber, 3 trays
             S02 removal:  88-98%
             S02 exit concentration:  20-200 ppm
             Particulate exit concentration:  0.05 gr/SCF (design  value)
             L/G ratio:  20 gal./lOOO CF
             Scrubber pressure drop:  7-1/2 in. HoO
             Scrubber liquor pH:  inlet ^ 9.0
                                  outlet 5.5-6.0

         Regeneration System

             Lime stoichiometry:  140-165% based on S02 removal
             Regeneration liquor composition:

                               Scrubber Recycle     From Regeneration

                       pH_        5.5 - 6.0               >12
                       S05        0.35M
                       OH"        Trace                   0.1M
                      HS03        0.03M                   Trace
                       Ca^       300-400 ppm             300-400  ppm
                                   495

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         Solids Separation

             Solid Waste composition:  Ca(OH>2      10-20%    dry basis
                                      Flyash        1-2%     dry basis
                                      Solubles (Na2SO^) 4-5% dry basis
                                      CaSOx        Remainder
                                      Moisture       50%
             Solid product wash:      Crude wash, 20% reduction of
                                                      solubles

         Reliability - The Parma full-scale system was started up in
March 1974.  There were at least two scheduled shutdowns soon after
start-up for inspection.  After the second shutdown a problem developed
which kept the system off line for about 3 weeks.  As of early October
1974 the system has been in operation since May 23, without a total
system shutdown.  Since the total system consists of four scrubbers
and four boilers, and the steam requirements have been such that usually
only two boilers and scrubbers have been on line at any one time, it
does not necessarily follow that each boiler/scrubber system was with-
out problems for the whole period between May and October 1974.  In
fact, if and when a problem developed in one boiler/scrubber system,
that system was shut down and another started up.  This has been
possible since the plant steam requirements have been well below the
system capacity.

     Of the problems which have been experienced since start-up, only
one seems to be recurrent and is cause for individual scrubber shut-
down:  the top tray in the scrubbers has a tendency to scale with
calcium carbonate.  The other problems were relatively minor, and were
possibly a result of lack of operating experience.  The scaling problem
is probably due to the fact that high pH liquor (pH above 12) from the
regeneration system enters the top tray of the scrubber directly,
causing local high pH regions on the top tray.  The localized high pH
regions absorb C02 from the flue gas, precipitating CaC03 scale.  A
solution for this problem is planned.  Regenerated liquor will be mixed
with scrubber recycle liquor (pH 5.5-6.0) so that pH on the top tray is
controlled at a level low enough to prevent precipitation of CaC03
(equations (23) and (24)).  At pH's belox^ about 9, CaC03 is solubilized
due to the carbonate/bicarbonate equilibrium:

             CO^ + H+ J HCO~                                     (25)

A more complete discussion of the GM system and the operating problems
experienced to date is given by Dingo and Piasecki.^6
                                  496

-------
     c.  Discussion - As of early October 1974, the GM system at Parma
has not been in steady state operation in the strict sense of the term.
Some improvement and optimization of the system, including solution of
the carbonate scaling problem, are still intended.   The sulfate level
in the system presently at 0.35M concentration is lower than the design
level of 0.5M.   Fluctuations in the sulfate level are indicative of poor
control of soda ash make-up to the system.  The high lime stoichiometry,
140-165%, is indicative of poor lime utilization.  Closer control of the
system should bring this lime utilization more in line with the lower
lime stoichiometries in use in the other double alkali systems.

     General Motors has entered into an agreement with EPA which will
allow Arthur D. Little, Inc., as a contractor for EPA's Control Systems
Laboratory, to conduct a test program at the Parma plant to more fully
characterize the double alkali system.  Through careful material balances
in the system, calculated from flow rate measurement and chemical ana-
lytical data, a number of important parameters will be studied.  Among
these are included:

          SC>2 removal
          Process reliability (scaling phenomena)
          Sulfate control
          Waste characteristics
          Degree of closed loop operation
          Utilization of lime and other chemicals
           Oxidation rate
                                  497

-------
Zurn Industries

     Zurn has designed, constructed,, and started up a dilute double
alkali system for control of S02 from two coal fired industrial boilers
having a total steaming capacity (180,000 Ibs/hour) equivalent to about
20 Mw electric generating capacity.   The system was started up in early
October 1974; consequently, no operating data can be reported at this
time.  The boilers burn coal containing about 3.0% sulfur.  Generally,
the system is patterned after the General Motors system in Parma.  The
scrubber system consists of two Zurn "Dustraxtor" scrubbers, containing
24 and 28 tubes, respectively.  Briefly described, this is a multitube
impingement/entrainment type scrubber capable of achieving very high
internal L/G ratios.   The system employs two series lime reactors and
a sodium carbonate softening step.   Provisions have been made for waste
product washing on the rotary vacuum filters, to minimize sodium losses
and associated potential secondary  pollution problems.

     A schematic of the Zurn double  alkali system is shown in Figure 6.
                                  498

-------
                  FRESH WATER
                           t
    BOILER
     NO. 2
VD
VD
CT
\
CaO
n
Na2C03
                                                      DRY CHEMICAL
                                                        TRANSFER
  EXISTING
COLLECTOR
             EXISTING
            COLLECTOR
                                                                                      VACUUM
                                                                                      FILTER
                                                                                       SPARE
                                                                            VACUUM
                                                                           RECEIVER
                                                                            SPARE
                                                                                         'VACUUM
                                                                                           PUMP
                                                                                           SPARE
                                                                                       VACUUM
                                                                                        PUMP
                                                                                                     MOVABLE
                                                                                                     CONVEYOR
                                                                                               H.-'
                                                                                              *:*?>.
                                                                                    WASTE PRODUCT
                                                                                      (10) PICK-UP
                                                                                      CONTAINERS
                                    FIGURE 6.  ZURN DOUBLE ALKALI SYSTEM

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A. D. Little/Combustion Equipment: Associates

     Pilot testing by ADL/CEA in a 2000 ACFM pilot plant in the ADL
complex in Cambridge, Massachusetts, in 'early 1973 led to the develop-
ment of a concentrated double alkali system.  Based on the results of
that testing, CEA contracted with Southern Services, Inc., a subsidiary
of The Southern Company (a Southeastern Utility Combine) to install
a 20 Mw prototype test unit at the Scholz station of Gulf Power Company
near Chatahoochee, Florida.

     In May 1973, EPA contracted with ADL to conduct a laboratory and
pilot plant study of various double alkali schemes of operation.  About
a year later, when construction of the prototype system was well under-
way, the EPA contract with ADL was expanded to include prototype testing
of the ADL/CEA system at Gulf Power.  A good description of the ADL/CEA
pilot plant and the Gulf Power 20 Mw prototype system is given in the paper
entitled, EPA-ADL Dual Alkali ProgramInterim Results.  Also contained
therein are operating conditions and test results obtained under the EPA
program to date.  The system developed by ADL/CEA is among the various
schemes tested under the program.
                                 500

-------
Kawasaki /Kureha_

     Kureha Chemical Industry Co., Ltd., developed a concentrated lime-
stone double alkali process in a small pilot plant.  Initial testing
led to the construction of a larger pilot plant (3000 SCFM) jointly
with Kawasaki Heavy Industries, Ltd., in July 1972.  Pilot testing was
completed in March 1973.  Since then, these two companies have jointly
developed a commercial double alkali process which is in operation at
the Shinsendai station of Tohoku Electric Power.  This unit processes
one quarter of the flue gas from a 600 Mw oil-fired boiler (150 Mw
equivalent).

     a.  Sy_stem Description - A schematic diagram of the system installed
at Tohoku Electric is shown in Figure 7.  The system consists of an S02
absorption section, a limestone regeneration section, a sulfate removal
section and a gypsum production section.

             Absorption - Flue gas from the oil fired boiler passes
through an electrostatic precipitator before entering the system.  The
gas is moved by a hot fan, forced draft with respect to the scrubber
system.  There is a precooler section at the entrance to the scrubber
in which the hot incoming gas is adiabatically cooled with recycle
liquor.  The scrubber is a grid-packed type consisting of two separate
stages of packing; gas flows upward through the packing.  Scrubber
recycle liquor and effluent from the top stage are fed to the top of the
bottom stage.  The bottom stage operates at an L/G ratio of about 12 gal./
1000 CF.  Regenerated liquor, only, is fed to the top stage thus maximiz-
ing the pH in this stage and achieving good countercurrent mass transfer
resulting in high S02 removal efficiency.  The total S02 removal in the
system is split, 90% in the bottom stage and 10% in the top stage (this
does not imply 100% removal of the incoming S02).  Flue leaving the
absorber is reheated to 285F by direct firing of 1.2% sulfur oil.

             Regeneration - The regeneration reaction consists of neutral-
ization of NaHS03 with finely ground limestone (equation (6)).  The lime-
stone is ground to 10 microns in a wet vertical tower mill.  Scrubber
effluent liquor bleed taken from the bottom stage recycle stream is
filtered to remove oil soot before it is pumped to the regeneration
reactors to be reacted with limestone.  The reactor system consists of
five closed reactors in series which are operated at about 90C to
promote the reaction between limestone and NaHS03 in the scrubber bleed.
The solid product produced in the reactors is separated from the mother
liquor and washed in a vacuum filter.  The liquor is recycled to the
scrubber system, and the solids, mostly CaS03-l/2 t^O are fed to the
oxidizer system and to the sulfate removal section.
                                   501

-------
O
K)
                                           REGENERATION
                                             REACTOR
                                              SYSTEM
FRESH
WATER
                                                                                                        -  I


                                                                                                CENTRIFUGE
    GYPSUM
                                                                                AIR-
                                  FIGURE 7.  KUREHA-KAWASAKI  DOUBLE ALKALI PROCESS AT

                                          TOHOKU ELECTRIC'S SHINSENDAI STATION

-------
             Sulfate Removal - This system is designed to remove sulfate
formed in the scrubber as gypsum via reaction with sulfuric acid and
calcium sulfite according to reaction (16).  The process is fed with a
bleed stream of scrubber effluent,, a portion of the calcium sulfite
cake (washed) from the filter and sulfuric acid.  In order to maximize
sulfuric acid efficiency, a small absorber and stripper are incorporated
in this sulfate treatment loop.  The incoming scrubber bleed is acidified
in the absorber with S02.  SO? is supplied by the stripper which converts
NallSOj to Na2S03, stripping off S02 via thermal decomposition according
to the following reaction:
                            i i P^ t~
                 2NaHS03     ->     Na2SC>3 + S02 + H20             (26)
This reaction is the thermal regeneration reaction used in the Wellman-
Lord process which is now commercialized by Davy Powergas .   Feed liquor
to the stripper is the acidic mother liquor from the sulfuric acid
reactor in which the sulfate removal occurs.  Stripped liquor from the
stripper is recycled to the regeneration reactor .system.

     Feed to the sulfuric acid reactor is thus already at a low pH, and
therefore requires less sulfuric acid addition to achieve a given
conversion of Na2S04 to gypsum.

     Effluent slurry from the sulfuric acid reaction is centrifuged to
separate the gypsum produced from acidic mother liquor.  The separated
solids are transferred to the oxidizer system together with the calcium
sulfite solids produced in the regeneration reaction.  The centrif ugate,
as previously stated, is recycled to the stripper to allow recovery of
acid values.

             Oxidation - The oxidizer developed by Kawasaki/Kureha is
considered to be proprietary.  Oxidation air is supplied at 5 psig.
Repulped calcium sulfite slurry from regeneration and gypsum from the
sulfate removal step are pumped to the oxidizer.  Sulfuric acid is added
to adjust pH in the reaction to attain the desired conditions for the
oxidation reaction.  Calcium sulfite is oxidized to gypsum by reaction
with atmospheric oxygen according to the overall reaction:

         CaS03'l/2H20 4- 1/202 + 3/2 H20 -> CaS042H20              (27)
The reaction mechanism may be acidic dissolution of CaSOo'l/2H20 followed
by oxidation of the bisulfite to sulfate regenerating the acid value to
dissolve additional CaS03-l/2H20.  Gypsum product is separated from
oxidizer effluent and washed in centrifuges.  Spent off-gas from the
oxidizer is recycled through the scrubber to remove S02 which was
emitted to the acidic oxidation reaction.
                                  503

-------
     b.   Operating Experience - Typical conditions and performance data
for the  Tohoku Electric FGD system are tabulated below:

             Flue Gas

                Source:  oil fired boiler
                Fuel:  1.2-1.5% sulfur oil
                Oxygen content:  3%
                Flow rate:  247,000 SCFM (420,000 Nm3/hr)
                SC>2 inlet concentration:  600-800 ppm
                Participate inlet:  0.0009-0.0044 gr/SCF (2-10 mg/m3)
                Reheat:  direct fire with 1.2% sulfur oil to 285F
                                                            (140*C)

             Absorber System

                Absorber type:  grid packed, 2 packing stages
                S02 removal:  98%
                S02 exit concentration:  <10 ppm
                L/G ratio:  12 gal./lOOO CF (1 kg/kg), bottom stage
                Scrubber pressure drop:  7.9 in. 1^0 (200 mm H20)
                Scrubber liquor pH:  6.9-7.6 inlet; to top stage
                                     6.3-6.5 bottom stage recycle
                Recycle liquor composition:  5-10%
                                             5-8%
                                             6-9%  Na2S03
                Oxidation rate:  5%

             Regeneration

                Limestone stoichiometry:  100% of S02 inlet
                Sodium make-up rate:  0.018 moles Na/mole S02 absorbed
                Reactor system residence time:  3 hrs (total, 5 reactors)
                Reactor % solids:  5% (essentially all CaS03'1/2H20)
                Reactor filter cake solids:  40%
                Regenerated liquor:  6.9-7.6 pH
                                     20% total dissolved solids
                                     <10 ppm Ca
                Limestone particle size:  lOy

             SojJ.ds Production. (Gypsum)

                Water content:  5%
                Sodium content:  <300 ppm on dry basis
                Particle size:  30x200p
                                  504

-------
             Reliability - The full-scale unit started up in January/
February 1974.  Based on reports as of August 1974, there have been no
significant reliability problems.  The only problem noted during a visit
in Japan by a representative of EPA was the plugging of the oil soot
filter.

     Discussion - The system is said to be a closed loop system in that
there is no intentional water purge; however, based on the rate of
water addition to the system, and a comparison of the rate of sodium
make-up with the sodium content of the product, it appears that there
is some sodium loss from the system other than the amount in the
product gypsum.  The overall system is fairly complex when compared
to some of the systems under development in the U.S.  The reasons for
the additional complexity appear to be related to a) the system pro-
duces a relatively pure saleable product, b) it is designed to achieve
extremely high S02 and particulate removal, and c) limestone rather
than lime is used as the source of calcium.  Apparently, there has
been considerable effort devoted to minimization of reagent usage;
i.e., sulfuric acid, limestone and sodium.

     The gypsum product has been used in cement manufacture; however,
it also meets the more stringent specs for wallboard production.

     The very low oxidation  (5%) in the absorption system is attributed
by Kawasaki/Kureha  to proprietary know-how.

     c.  Plans _for  Future Testing and Full-Scale Application - Kawasaki/
Kureha plans to pilot-test an electrolytic process step which was pre-
viously piloted by Yuasa/Ionics  in Japan.  This process step is being
evaluated  to replace the sulfuric acid reactor/absorber/stripper
operation  for sulfate removal.  The electrolytic sulfate removal scheme
is similar to that  used in the Stone & Webster/Ionics process, equation
(18).  Testing was  scheduled for October 1974, in a 3-5 Mw pilot plant
consisting of  two 5 ft^ cells capable of decomposing 10 Ibs/hour of
Na2SO^.  Use of  the electrolytic step is expected to reduce sodium
make-up requirement to  the system by 50%, and is anticipated to reduce
capital costs of the overall system.

     A number  of additional  large  scale  utility double  alkali  systems
are  presently being engineered  and/or  constructed by Kawasaki/Kureha.
These  are  tabulated below:

       Utility                   Capacity  (Mw)            Start-Up

Sikoku Electric Power               450                   August 1975
Sikoku Electric Power               450                   October 1975
Tohoku Electric Power               350                   October 1976
Kyushu Electric Power               250                   May  1977
Kyushu Electric Power               250                   May  1977

                                   505

-------
Showa Denko KK/Ebara

     Showa Denko KK and Ebara Manufacturing Co., Ltd., of Japan jointly
developed a concentrated double alkali process using limestone as the
calcium source, and producing a saleable gypsum by-product.  Development
began in a 5,900 SCFM pilot plant at the Kawasaki plant of Showa Denko
in 1971.  This has culminated in the construction and operation of a
150 Mw system on an oil fired boiler at Showa Denko's plant in Chiba.

     a.  System Description - Figure 8 is a schematic representation of
the Showa Denko/Ebara process.  Basically it is similar to the Kawasaki/
Kureha system.  The full scale unit (150 Mw) uses four inverted "vertical
cone" scrubbers (similar to the Zurn or Bahco type).  Liquor is entrained
at the bottom of a conical draft tube (truncated apex) by the entering
flue gas and the mixture passes up the tube.  At the top of the tube
(conical base) there is a disengaging section where liquor separates and
falls back to the bottom of the scrubber.

     In the reactor system, limestone is reacted with spent scrubber
effluent to neutralize  the NaHS03 producing Na2S03 for recycle  to the
scrubber and CaS03-1/2^0  (equation (16) which  is sent to an air oxidi-
zer to be converted to  gypsum by air oxidation  (equation  (28)).  A slip
stream of spent scrubber liquor is taken to a sulfate treatment section
which converts Na2S04  to gypsum and NaHS03 by reacting it with  sulfuric
acid and calcium sulfite according to reaction  (16).  Gypsum from this
reaction containing some unconverted calcium sulfite  is combined with
the calcium sulfite produced in the limestone neutralization reaction
and pumped to  the  air  oxidizer system.  Sulfuric acid is  added  to ad-
just the pH in  the oxidizer system to achieve optimum conditions for
the calcium sulfite oxidation.

     The system operates in an open loop since  the amount of water
required to wash  the gypsum product to below  300 ppm  sodium content  is
greater  than  the  system water losses  through  evaporation, water of
hydration, and  moisture in the final product.   The  sodium  content
specification  for  wallboard manufacture  is  less than  300  ppm.   The
corresponding  specifications  for gypsum  used  in cement manufacture  is
900 ppm.

     b-  Operating Experience - General  conditions and performance data
for the  full  scale system  are  tabulated below:

              Flue  Gas

                Source:  oil  fired 150 Mw  boiler
                Fuel:   2.5-3.0% sulfur
                Particulate inlet concentration:  0.8 gr/scf
                S02 inlet  concentration:   1200-1500 ppm
                Reheat:  direct fired with  1% sulfur oil  to 285-300F
                                   506

-------
WASTE
                               LIMESTONE
                                  FIGURE 8. SHOWA DENKO SODIUM-LIMESTONE PROCESS

-------
             Absorber System

                Absorber type:  4 vertical cone scrubbers
                S02 exit concentration:  60-100 ppm after reheat
                                         with 1% sulfur oil
                Particulate exit concentration:  0.025-0.035 gr/SCF
                L/G ratio:   7.5 gal./lOOO CF
                Scrubber liquor pH:  6.3 exit
                Oxidation rate:  <10%

             Regeneration Chemical Usage

                Limestone utilization:  96%
                Sulfuric acid usage:  0.2 moles H2S04/mole SO? absorbed
                Sodium usage:  0.10-0.12 moles of NaOH/mole SC>2 absorbed

             Oxidizer

                Suspended solids content:  15%

             Gypsum By-Product

                Na content:  <300 ppm
                Water content:  7-8%

             Reliability - The full scale system was started up in
June 1973.  It was shut down for a period in March 1974 for inspection.
As of March 1974, the scrubbers were said to have been near 100%
reliable, and they were found to be clean in the March inspection.
The regeneration system had given some trouble but since there is
adequate solution surge capacity, regeneration difficulties have not
affected boiler reliability.  The trouble has been mainly pipe plugging
which was not considered to be chemical scaling.
                                   508

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SUMMARY AND CONCLUSIONS

     Based on the initial performance and reliability demonstrated in
various double alkali pilot plants, and in an increasing number of full
scale applications in the U.S. and Japan, it appears that this tech-
nology will soon become a viable alternative throwaway process to the
lime/limes tone processes which are now the prevalent FGD processes used
with fossil fueled utility boilers.  The total operating and planned
full-scale and prototype utility and industrial applications of double
alkali technology now number 17 with individual applications with total
gas flow control equivalent to 2375 Mw of electric generating capacity.
Summaries of significant pilot testing, and operating and planned full
scale systems are given in Tables 4 and 5, respectively.

     Performance of double alkali systems with respect to S02 removal
is well established.  Over 99% S02 removal has been achieved with lower
than 10 ppm S02 concentration in the treated flue gas.

     Potential problems with waste disposal from these systems are
present due to the presence of a certain amount of soluble sodium salts
which could cause water pollution problems in the surface and ground
water in the vicinity of disposal sites.   A number of techniques to
reduce the soluble sodium salts in the waste product have been tested;
however, it appears that there will inevitably be a higher level of
soluble salts in waste product from double alkali systems than from
lime/limestone systems.  With present U.S. technology it appears that
the minimum incremental amount of solubles in a double alkali waste
product (over that typically present in lime/limestone waste product)
is about 1-2% on a dry solids basis.  Development of sludge fixation
technology to change the wet solid waste product to a hard unleachable
solid could conceivably reduce this potential problem.

     Actual costs for full scale utility boiler applications are not
available.  Estimates for these applications based on the best available
information put double alkali system capital costs in the range of lime/
limestone system costs; however, these types of estimates are necessarily
subject to qualification.

     In the U.S., development has stressed the use of lime rather than
limestone as the calcium source in all of the full scale industrial
applications and in most of the pilot plant testing in both dilute and
concentrated systems.  In Japan, limestone rather than lime is used for
concentrated systems in full scale utility boiler applications apparently
for the operating cost benefit which is derived through the use of the
less expensive regenerant.  Also, due to differences in the economies
of the  two countries and state-of-the-art of technology, production of
by-product gypsum from the Japanese double alkali systems is prevalent;
                                  509

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                           Table 4.  SUMMARY OF SIGNIFICANT PILOT PLANT DOUBLE ALKALI TESTING
System Developer

Envirotech



FMC
General Motors
A- D. Little/
Combustion Equipment
Associates/EPA

Kawasaki/Kureha

Showa Denko KK
   Pilot Plant Location

Utah Power & Light Company
electric power boiler,
coal fired

At least 7 different locations,
coal and oil fired industrial
boilers, elec. power boilers,
acid plant

GM Parma Plant
GM Livonia Plant
coal fired industrial boiler

ADL Facility
Cambridge, Massachusetts
Natural gas furnace

Oil fired boiler, Japan

Oil fired boiler, Japan
     Size
(Gas  rate,CFM)

     2500
                                                                      3500
     2800



     2000



     3000

     5900
Active Alkali

   Dilute,
   Cone.
                       Cone.
   Dilute
   Dilute,
   Cone.
   Cone.

   Cone.
Calcium Source
   Lime
                    Lime
   Lime
   Lime,
   Limestone
   Limestone

   Limestone

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                      Table 5.  SUMMARY OF OPERATING AND PLANNED FULL SCALE DOUBLE ALKALI SYSTEMS
   System Operator

FMC
  Modesto Calif. Plant

Showa Denko KK
  Kawasaki Plant, Japan

Tohoku Electric
  Shinsendai Sta.,
  Japan

General Motors
  Parma, Ohio Plant

(Unspecified)
  U.S.
Gulf Power Company
  Scholz Plant
  (Southern Services)

Firestone
  Potts town, Pa.
(Unspecified)
  U.S.
(Unspecified)
  U.S.

(Unspecified)
  Japanese Paper Plant
System Application
Reduction kilns
Oil-fired elec.
power boiler
Oil-fired
utility boiler
4 coal fired
industrial boilers
2 coal fired
industrial
boilers
Vendor or
Developer
FMC
Showa
Denko /Ebara
Kawasaki/
Kureha
General
Motors
Zurn
Industries

(Mw,
10
150
150
40
32
20


Size
Equivalent)
(Gas Rate)


(Regen)
(Gas Rate)



Active
Alkali
Cone .
Cone .
Cone .
Dilute
Dilute


Calcium
Sources
Lime
Limestone
Limestone
Lime
Lime


Start-Up
Date3
Dec. 1971
June 1973
Jan. 1974
Mar. 1974
Oct. 1974


Coal fired
utility boiler-
prototype

Coal & oil fired
industrial boiler-
demonstration

Coal fired
industrial heating
plant

Coal fired
industrial boiler
system
Oil fired
industrial boiler
A.D.Little/       20
Combust. Equip.
Associates

FMC                3
FMC               14
FMC               50
FMC/Ataka
Cone.
Cone.
Cone .
Cone.
Cone.
Lime
Lime
Lime
Lime
Lime
(Nov.  1974)



(Dec.  1974)



(Dec.  1974)



(early 1975)


(early 1975)

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               Table 5 (Continued).   SUMMARY OF OPERATING AND PLANNED FULL SCALE DOUBLE ALKALI SYSTEMS

System Operator
FMC
Green River, Wyo.
Plant
Sikoku Electric Power,
Japan
Tohoku Electric,
Japan
(Unspecified)
U.S.
Kyushu Electric
Power, Japan

System Application
Coal fired
electric power
boiler
2 Oil fired
utility boilers
Oil fired
utility boiler
Oil fired
industrial boiler
2 Oil fired
utility boilers
Vendor or
Developer
FMC


Kawasaki/
Kureha
Kawasaki/
Kureha
FMC

Kawasaki/
Kureha
Size Active
(Mw, Equivalent) Alkali
150 Cone.


900 (2-450 Mw) Cone.

350 Cone.

13 Cone.

500 (2-250 Mw) Cone.

Calcium
Sources
Lime


Limestone

Limestone

Lime

Limestone

Start-Up
Date3
(mid 1975)


(Aug. -Oct.
1975)
(Oct. 1976)

(Late 1976)

(May 1977)

Dates in parentheses are projected start-up dates

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whereas, production of a throwaway solid waste product is the general
rule with development of the technology in the U.S.

     The development of double alkali technology has obviously stemmed
(and benefitted) from both lime/limestone and other soluble sodium
scrubbing technology development.   Possibly as a result of this and
certain inherent advantages of soluble alkali scrubbing, it appears
that the reliability established at this point in the development of
double alkali technology is greater than that which had been estab-
lished for the lime/limestone, systems at a corresponding stage of
development.
                                  513

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REFERENCES

 1.   Ponder,  W.  H.,  "Status of Flue Gas Desulfurization Technology For
     Power Plant Pollution Control."  Presented at Thermal Power
     Conference, Washington State University,  Pullman,  Washington,
     October  4,  1974.

 2.   Epstein, M., R.  Borgwardt,  et al., "Preliminary Report of Test
     Results  from the  EPA Alkali Scrubbing Test Facilities at  the
     TVA Shawnee Power Plant and at Research Triangle Park."
     Presented at Public Briefing, Research Triangle Park, North
     Carolina, December 19, 1973.

 3.   La-Mantia, C.,  et  al. ,  "EPA-ADL Dual Alkali Program Interim
     Results."  Presented  at EPA Symposium on  Flue Gas  Desulfurization,
     Atlanta, Georgia, November  4-7, 1974.

 4.   Johnstone,  H.  F., et  al., "Recovery of Sulfur Dioxide from Waste
     Gases."   Ind.  & Eng.  Chem.,  Vol.  30,  No.  1,  January 1938,
     pp 101-109.

 5.   Phillips, R. J.,  "Operating Experiences with a Commercial Dual-
     Alkali S02  Removal System."  Presented at the 67th Annual Meeting
     of the Air  Pollution  Control Association, Denver,  Colorado,
     June 9-13,  1974.

 6.   Cornell, C. F. and D.  A.  Dahlstrom,  "Performance Results  on a
     2500 ACFM Double  Alkali Plant for  S02 Removal."  Presented at
     the 66th Annual Meeting of  A.I.Ch.E., Philadelphia,  Pennsylvania,
     November 11-15, 1973.   Condensed version  of  the paper appeared
     in December 1973  CEP.

 7.   Kaplan,  N., "An EPA Overview of Sodium-Based Double  Alkali
     Processes - Part  II Status  of Technology  and Description  of
     Attractive  Schemes."   Presented at the EPA Flue Gas  Desulfurization
     Symposium,  New Orleans,  Louisiana,  May 14-17,  1973.

 8.   Phillips, R. J.,  "Sulfur  Dioxide Emission Control  for Industrial
     Power Plants."  Presented at the Second International Lime/Limestone
     Wet-Scrubbing  Symposium,  New Orleans, Louisiana, November  8-12, 1971,

 9.   Brady, J. D.,  "Sulfur  Dioxide Removal Using  Soluble  Sulfites."
     Presented at Rocky Mountain  States  Section Air  Pollution  Control
     Association, Colorado  Springs,  Colorado,  April  30,  1974.
                                 514

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10.  Cornell, C. F.,  "Liquid-Solids Separation in Air Pollutant Removal
     Systems."  Presented at the ASCE Annual and National Environmental
     Engineering Convention, Kansas City, Missouri, October 21-25, 1974,

11.  Selmeczi, J.  G.  and R.  G.  Knight, "Properties of Power Plant Waste
     Sludges."  Presented at the Third International Ash Utilization
     Symposium,  Pittsburgh,  Pennsylvania, March 13-14,  1973.

12.  Ellison, W.,  et  al., "System Reliability and Environmental Impact
     of S02 Scrubbing Processes."  Presented at Coal and The  Environ-
     ment, Technical  Conference, Louisville, Kentucky,  October 22-24,
     1974.

13.  Rochelle, G.  T., "Economics of Flue Gas Desulfurization."
     Presented at  EPA Flue Gas  Desulfurization Symposium, New Orleans,
     Louisiana,  May 14-17, 1973.

14.  "Sulfur Dioxide  and Flyash Control", FMC Corporation Technical
     Bulletin.  FMC Corporation, Air Pollution Control Operation,
     751 Roosevelt Road, Suite  305, Glen Ellyn, Illinois 60137.

15.  McGlamery,  G. G. and R. L. Torstrick, "Cost Comparisons  of Flue
     Gas Desulfurization Systems."  Presented at the EPA Symposium on
     Flue Gas Desulfurization,  Atlanta, Georgia, November 4-7, 1974.

16.  Dingo, T. and E. Piasecki, "General Motor's Operating Experience
     with a Full-Scale Double Alkali Process."  Presented at  the EPA
     Symposium on  Flue Gas Desulfurization,  Atlanta, Georgia,
     November 4-7, 1974.
                                 515

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Initial Operating Experiences
    With A Dual-Alkali  SO2
         Removal System
          Parti
          PROCESS PERFORMANCE WITH A COMMERCIAL
          DUAL-ALKALI S02 REMOVAL SYSTEM
          Thomas T. Dingo/General Motors Corporation
          Part I I
          EQUIPMENT PERFORMANCE WITH A COMMERCIAL
          DUAL-ALKALI S02 REMOVAL SYSTEM
          Edmund J. Piasecki/General Motors Corporation
             for presentation at

     ENVIRONMENTAL PROTECTION AGENCY
         SYMPOSIUM ON FLUE GAS
            DESULFURIZATION
            ATLANTA, GEORGIA
            NOVEMBER 4-7, 1974
                  517

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                   ABSTRACT
The first commercial demonstration of dual-
alkali wet scrubbing went on-line in March,
1974, at the General Motors Chevrolet plant
in Parma, Ohio.  The S02 system was installed
at a cost of $3.5 million and was designed to
handle a steaming capacity of 400,000 pounds
of steam per hour.  In this system, a dilute
sodium hydroxide solution absorbs S02/particulate
matter from the flue gas.  The spent scrubbing
solution is then recausticized with lime and
reused in the scrubbers while precipitated
sulfur compounds are dewatered and sent to
landfill.  The system is currently under-
going a shakedown and evaluation period.

This paper is an update of operating ex-
periences.  Equipment performance, SC>2 re-
moval capabilities, process reliability and
control, sulfate formation, chemical utili-
zation, calcium ion control and waste cake
characteristics are reviewed.
                        518

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                   PART  I
         PROCESS PERFORMANCE WITH A
  COMMERCIAL DUAL-ALKALI S02 REMOVAL  SYSTEM
               Thomas T. Dingo
         General Motors Corporation
          Manufacturing Development
              Warren, Michigan
For Presentation at Environmental Protection
Agency Symposium on Flue Gas Desulfurization
              Atlanta, Georgia
             November 4-7, 1974
                      519

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                  PROCESS PERFORMANCE WITH A
           COMMERCIAL DUAL-ALKALI  SO?. REMOVAL  SYSTEM
                     I..  INTRODUCTION

General Motors, like everyone else, has been caught in the energy
squeeze.  Natural gas and fuel oil are not readily available as
in the past.  Thus, because of the long term availability of coal
over oil or natural gas, the Corporation has made every effort
to use this fuel wherever economically possible within existing
pollution codes.

GM is already a large industrial user of coal in the generation of
steam for process uses.  In 1973, the Corporation consumed close
to 2.0 million tons of coal.  Strict air quality standards,
however, in many urban areas have made the use of coal very
difficult.  In some cities,  even switching to a low sulfur coal
would not result in meeting air quality requirements.  These
situations have forced us to look to yet unproven sulfur dioxide
emission control technology.

In 1968, in anticipation of more stringent pollution codes coupled
with shortages and drastically high cost for low sulfur fuels, the
Corporation initiated a program to determine if control technology
could be developed for its industrial powerhouses.  The criteria
in developing such technology were as follows:

1.  The system must afford high process and equipment reliability.

2.  It must be simple and not dictate the operation of the power-
    house .

3.  It must not be a chemical plant and must produce a by-product
    that can be easily disposed.

4.  It must be economically competitive with other alternatives.

Scrubbing with a soluble salt coupled with regeneration and reuse
of the scrubber effluent appeared to satisfy our criteria best.
Pilot work was started in 1969 and the system developed has come
to be known as the GM Double Alkali SO,, Control System.  The first
commercial demonstration of this system is the $3.5 million
installation at GM's Chevrolet-Parma plant near Cleveland,  Ohio,
Figure 1.  The system was placed on line in March,  1974 and has
been going through shakedown and adjustment.
                            520

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It is the purpose of this paper to describe the process chemistry
and equipment and to relate the performance characteristics of
the system to date.


                 II.  PROCESS DESCRIPTION

The General Motors dual-aklaki process involves the use of a
dilute alkaline stream of sodium hydroxide  (NaOH) to remove sulfur
oxides from the boiler gases and alkaline lime  (CaO) to regenerate
the spent scrubbing liquor by precipitating the absorbed sulfur
to reform an hydroxide solution.  It is the purpose of this
section to describe the process chemistry through the absorbing,
regeneration, softening and neutralization sections of our system.
Figure 2 shows a process schematic.

SCRUBBER CHEMISTRY

The reactions that take place in the absorbing section of our
system are straight forward and are shown below:

    2NaOH + S0	*-NaSC>  + HO             (1)

                                            (2)

                                            (3)

Sodium hydroxide reacts with sulfur dioxide to form sodium sulfite
(Reaction 1).  The sodium sulfite, then can react further with
sulfur dioxide and water to form sodium bi-sulfite  (Reaction 2).
In addition,  some of the active sulfite is oxidized to sodium
sulfate due to the presence of excess oxygen  (Reaction 3).

REGENERATION CHEMISTRY

Because of the formation of Na~SO., the regeneration section has
to be capable of regenerating ootn sulfate and sulfite.  The
sulfate reaction,  however,  is quite difficult because of the
relative solubility of the product, calcium sulfate.  In addition,
the_sodium sulfate cannpt be causticized in the presence of high
S0^~ or OH~ because Ca   level are held below CaSO  solubility
product.  Thus,  to provide effective sulfate regeneration,  the
system must be operated at a dilute OH  concentration (<  0.14M)
while maintaining sufficient levels of sulfate (> 0.4M)  to affect
calcium sulfate precipitation.  In actual practice,  we try  to_
maintain our feed solution at 0.1 Molar OH  and 0.5  Molar  SO.~.
The chemical reaction that take place in the regeneration  sections
are:
                             521

-------
    NaHS03 + Ca(OH)2  *-NaOH + CaS03r  + H20       (4)
    Na S03 + Ca(OH)  *- 2NaOH + CaSC^r             (5)

                                                   (6)

SOFTENING CHEMISTRY

Because of the difficulty in regenerating  sodium  sulfate  (Reaction
6), an excess of lime must be added.  This  causes  dissolved calcium
ion levels near SOOppm, which, if allowed  to  enter the scrubber,
could precipitate as calcium salts and  cause  subsequent scaling.

To alleviate this problem, a softening  step was added to our
flowsheet.  In this step, soda ash and  carbon dioxide are added
to precipitate the dissolved calcium  as a  carbonate.  The reactions
are:
             Ca(OH)2  *- 2NaOH + CaCO.              (7)
    C02 + Ca(OH)2 *- CaC03- + H20                  (8)

The resultant calcium levels now leaving the  softening clarifier
can be as low as SOppm, but are controlled to approximately 300ppm.

A double media softening is used to maintain  a chemical balance
on the system.  The main function of the soda ash  is to replenish
the sodium losses from the vacuum filter.  Because of this, the
soda ash make-up is not sufficient to  lower the dissolved calcium
to the desired level.  The carbon dioxide, then, supplies the
additional softening required.  As shown in Reaction 8, however,
the carbon dioxide lowers the free hydroxide  available for scrubbing,
From an economic and chemical utilization standpoint, the system
should be operated with the minimum softening to avoid scrubber
scaling.

NEUTRALIZATION CHEMISTRY

If the calcium carbonate formed through softening  is not reused
in the system, the lime utilization suffers drastically.  In a
sense, calcium would be added in one section  and thrown out in the
next.  The only place where the calcium carbonate could be used
back in the system is with the spent scrubbing liquor.  The sodium
bi-sulfite would react with the carbonate as  shown in the following
reaction.-
T +
    CaC03 + 2NaHS03  *- CaS03T + Na2S03 + H2C03     (9)
                              522

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Thus, a reaction tank to pretreat the scrubber effluent before lime
addition was added to the system.  Complete use of the calcium
carbonate is dependent on the oxidation rate, low sulfate formation,
in the scrubbers.
                Ill.   EQUIPMENT DESCRIPTION

The Chevrolet-Parma Plant was chosen as a demonstration site
for our process because it is located near Cleveland where a
rigid S0? emission limitation exists.  This code requires us
to burn an equivalent of 0.625% sulfur coal.  The plant consumes
approximately 55,000  tons/year of 2.0 to 3.0% + sulfur coal.  The
total steam generating capacity of the facility is 320,000 Ibs/hr.
from four spreader stoker fired boilers.  In anticipation of an
additional boiler, however, the sulfur dioxide control system
was designed to handle a steam capacity of 400,000 Ibs/hr.  The
equipment used in our double-alkali system is described below.

ABSORBERS

Four scrubbers are utilized in our system, one for each boiler.
They are approximately 12 ft. in dia. and 20 ft. high, Figure 3.
In these units, the boiler gases enter through a prequench-
section at the bottom of the scrubber and flow upward through
three absorption trays to exhaust.  Scrubber feed and recycle
are added at the top of the scrubber, flowing counter-current to
the gases down to a recycle tank.  Each of the absorption trays
contains a series of movable bubble caps that adjust to changes
in gas flows.  Each unit is designed to give us a 3:1 turn down
capacity.  This type of absorber gives us good S02 removal at a
relatively low recycle pH and good particulate removal.  The
particulate loading from our units must be near 0.05 grain per scf.

The scrubbers are constructed of 316-L stainless steel and are
designed to operate at a total system pressure drop of 7.5 in.
H,,O.  They are also rated for a maximum liquid to gas ratio of
20:1 of which about 20% of the liquid is scrubber feed.

REACTORS

The bleed from the recycle tanks, Figure 4, is pumped through
two back mix reactors in series.  They are carbon steel in
construction and, are designed with a 6000 gallon capacity to
give a 5 minute retention time at full flow.  In the first reactor,
a CaCO. slurry from the softener clarifier is added for neutrali-
zation.  In the next reactor, lime slurry is added for recausti-
cization.  Both reactors are mounted on the side of the scrubber
building as shown in Figure 5.
                                523

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CLARIFIERS

From the reactors, the regenerated solution, laden with fly ash
and calcium precipitates, flows by gravity to two 300,000 gal
reactor clarifiers in series, Figure 6.  Each clarifier is 60 ft.
in dia. and has a maximum 0.46 gpm per square foot rise rate.
In the primary clarifier, the solution goes through additional
reaction, if needed, and solid separation.  In the second
clarifier, the solution is softened with Na CO  and CO .  A
regenerated, clarified, and softened solution then overflow back
to the scrubber building.

VACUUM FILTERS

The underflow from the primary clarifier  (approximately a 15%
slurry) is pumped to a sludge holding tank for batch vacuum
filtering.  Two 500 square foot filters are available, each with
a maximum capacity of 50 tons of cake per day,  Figure 7.  The
cake from the filters is dumped into trucks for disposal as a
landfill material.  The filtrate is returned to the system at
the clarifiers.

CONTROL PANEL

To assure proper operation of the system, an elaborate panel was
designed to simplify the control and monitoring functions, Figure 8.
From here, the operator has positive indication of what is happening
in the scrubbers, on the floor, and outside of the building and
can change chemical addition rates as required.

The control theory of the double alkali system is relatively
simple.  First, caustic is fed to the scrubbers on the basis of
the boiler steam load and trimmed by the pH in the recycle line.
Steaming rate is a good indicator of coal usage and subsequent
pounds of sulfur dioxide being formed.  Since a certain pH range
is desirable for proper SO,, removal,  pH control was also combined.
Also,  since the scrubber feed is proportional to the caustic
being supplied to the scrubbers, this signal was selected as a
basis for control of the chemical feeds of lime, soda ash, and
carbon dioxide.  Physical titrations for caustic concentration
leaving the recausticizer and calcium concentrations across the
softening clarifier are periodically made.  Chemical feed rates
are adjusted if necessary.


             IV.  PERFORMANCE CHARACTERISTICS

The dual alkali system at Chevrolet-Parma was officially placed
on line in early March, 1974.  Since that time, it has been going
                             524

-------
through a checkout and shakedown period to determine the actual
performance characteristics of the system.  During this period,
many interrelated and unrelated mechanical and chemical difficulties
were encountered.  Some of these problems did cause complete shut-
downs, but most were overcome through minor process and operational
modifications while on stream.  It is the purpose of this section
to describe the performance of various parts of the system.

jGRUBBER PERFORMANCE

The heart of the system, of course, is the absorbers for removing
the sulfur dioxide.  The chemical reactions that take place in
these scrubbers, however, will greatly affect the operation and
economics of the regeneration section of our system.  Thus it is
not just a matter of scrubbing out SO-, but doing it with a con-
trolled scrubber chemistry.

Sulfur dioxide tests across the scrubbers have shown removal
efficiencies from 85 to 95% over the range of scrubber outlet
pH of 5.5 to 6.5.  Particulate loadings leaving the scrubbers are
still to be determined.  Testing is being continued to determine
tray efficiencies for possible optimization.

As stated previously, scrubber chemistry will greatly affect the
regeneration section of our system.  Specifically, if the oxidation
rate {Reaction 3) in the scrubber is too high, not enough bi-sulfite
(Reaction 2} will be formed to take care of the calcium carbonate
(Reaction 9) in our neutralizer reactor.  This means that the lime
utilization of the system would be very poor. *For complete utili-
zation of the lime, the maximum oxidation rate  must, be near 10%.
Actual tests, however, show that our oxidation rates fluctuate
between 30 and 80% with the recycle pH and steaming rate.  The
exact effect of these variables on the oxidation rate will be
determined in hopes of controlling a lower rate.

In addition, oxidation rate will greatly affect the scaling ten-
dencies in our scrubbers.  Again, a sufficient amount of bi-sulfite
must be present in the recycle liquor to partially neutralize the
incoming scrubber feed over the top tray.  if the pH on the top
tray is not kept near 9.0, soluble calcium can react with the
CO- in the flue gases and form a carbonate scale, causing high
pressure drop and poor liquid-gas contact.  Initially,  this problem
was very acute and necessitated frequent shutdowns for manually
removing the calcium carbonate scale.  Since then, however,
revisions have been made to alleviate this problem.  First,  a
*0xidation _ lnno/ _ Total normality of HSO0 + SO-, in recycle    ,  n
 Rate      ~  UU/   Normality of OH in scrdbber reed          x luu/
                            525

-------
piping revision was made to assure better mixing of the acidic
recycle liquor with the incoming scrubber feed on the top tray.
Second, the recycle liquor is now controlled at a 6.0 pH instead
of 6.5 pH to assure more bi-sulfite.  Finally, the soluble calcium
levels in the feed stream are maintained around 300 ppm through
softening.  The combination of these changes has now allowed us
to run over a month on a scrubber without any appreciable increase
in pressure drop.  It is still too early to tell whether we have
eliminated the scaling altogether or are just retarding it.

REGENERATION PERFORMANCE

The main function of the regeneration section is to produce a
0.1M OH  solution.  No problems have been encountered in doing
this, but, because of the inability to reuse the CaCO-, in the
neutralization reactor,  the overall lime utilization nas been
very poor.  The lime/sulfur stoichiometry has been in the range
of 1.4 to 1.5/1.0.  Original design expectation were 1.1/1.0.

The problem in using the calcium carbonate have been both mech-
anical and chemical.  As explained previously, the high oxidation
in the scrubbers rate causes a deficiency of bi-sulfite in the
scrubber bleed liquor.  This deficiency then requires that only
a small volume of carbonate slurry be metered to the neutralizer
tank.  This necessitates only cracking the control valve for the
low flows.  The slurry then has a tendency to plug the control
valve.  Thus we have been forced to over-feed the carbonate slurry,
Also working against the neutralization is the fact that we
utilize a back mix reactor.  In essence, we are trying to react
an acidic stream with a basic stream in an already highly basic
media.  A plug-flow reactor arrangement is being investigated.
Once these problems are overcome, our lime to sulfur stoichi-
ometry should improve to be 1.3:1.

PRIMARY CLARIFIER PERFORMANCE

From the regeneration section, the recausticized solution flows
to a primary clarifier for solid-liquid separation.  If not
operated correctly, we found that this unit could cause major
problems and shutdowns.

The first problem was encountered early in the debugging period.
The total system was being operated on a Monday through Friday
basis with inspection scheduled for the weekends.  At that time,
it was standard practice to shut off all pumps and completely
stop the solution flow.   During one of these periods, the slurry
pumps at the bottom of the clarifier broke down and we could not
recirculate or draw off sludge.  As a result of the complete
quiescence, the sludge blanket in the clarifier, approximately
                            526

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60 tons, settled rapidly to the clarifier bottom and jammed
the clarifier rake.  It became necessary to completely drain the
clarifier, manually remove most of the sludge and manually free
the rake.  One week was lost because of this.  Now it is a
standard practice to always keep an upflow through the clarifiers
to keep the solids in suspension.

The second major problem occurred when we progressed from
scrubbing one boiler to three boilers.  After operating about a
week on  three boilers, solid carry over became evident, upset
the softening clarifier, and got into the scrubbers causing
scaling and plugging.  At that time, it was not known whether this
carry over was due to a change in scrubber chemistry or an
inability to remove solids on a regular basis.

Originally, we thought that additional scrubbers that we placed
on line had low oxidation rates and their spent solution was
forming calcium sulfite (Reaction 5) when regenerated.  The
CaSO 1/2H-0 is much more difficult to settle and filter than
the CaS04 2H_0.  If allowed to build up then, the calcium sulfite
could form an hindered settling zone in the clarifiers.  The
oxidation rates, however,  in all the scrubbers were found not to
vary significantly.

Also, at the same time we placed the system completely on line,
we encountered some scheduling problems with the solid waste
hauler of our sludge.  Since trucks were not available, we could
not draw off enough sludge to keep up with its formation.  As
a rule of thumb, five tons of wet sludge should be removed for
every ton of lime added to the system.  Consequently, we started
to build up a solid inventory in the clarifiers (400 tons), lost
the sludge blanket, forced an hindered settling zone in the
clarifiers, and pushed the solids over the top.  A month was lost
while cleaning the solids from the total system.

After realizing this, several operational changes have been made
to assure that this situation does not develop again.  First,
it is imperative that we be able to remove solids at a greater
rate than they are formed.  Once the sludge blanket in the
clarifier is formed, it must be maintained at the desired level.
We now have the capability to remove sludge as required through
additional trucks and manpower.  Second, it is important that
the sludge blanket in the clarifier be periodically checked.
The operators now regularly check the sample ports on the sides
of the clarifier to determine the solids concentration throughout
the tank.  The sludge withdrawal rate is then increased or
decreased to keep the solid blanket below the clarifier cone.
Finally, to improve clarity of the clarifier overflow, a coagulant
                             527

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is being added in the contact zone.  The optimum concentration
of this additive is yet to be determined.  Currently, we use
about a 0.3 ppm concentration.

SOFTENER PERFORMANCE

The dissolved calcium levels leaving the primary clarifier are
around 700 ppm.  We have found that the calcium ion reduction
in the softening clarifier can be controlled to any desired
level through either the addition of soda ash or carbon dioxide
(Reactions 7 & 8).  Currently, we are controlling the effluent
from the softener at about 300 ppm without noticeable scaling
in the scrubbers.  Material balances across the softener
indicate almost 100% chemical utilization of Na0C00 or CO~ .
                                               Z  J      f.
Initially, we experienced some problems in settling the precipi-
tated carbonate.  We have found it necessary to maintain a
sufficient concentration of precipitates (5% slurry)  in the
reaction zone of the clarifier for effective seeding and par-
ticle growth.  Also, we have started adding a coagulant to the
reactor zone to improve the solution clarity at the overflow.
Again, the optimum concentration is being determined.  One
phenomena that we still must face is a build-up of carbonate
salts on the clarifier surfaces.  As of yet, it is not severe
enough to force manual cleaning.

SOLIDS HANDLING PERFORMANCE

Initially, considerable difficulties were encountered in the
solids handling section of our system.  Minor operational and
process changes have proven successful.  First, we had to
determine the best percent solids at the discharge of the sludge
pumps for our system.  This is essential for proper solids handling
because:  (A) too thick a slurry can cause^plugging of the pumps
and subsequent sludge build-up in the clarifiers, and (B) too
thin a slurry can cause poor performance of the vacuum filters.
A slurry concentration of around 15% solids has been found to work
very well.  Second, on the vacuum filters themselves, we have
switched from a 100% olefin to a 100% nylon cloth.  The release
characteristics of the cake have improved greatly.  Last, we had
to adjust the speed and vacuum on the filters to achieve a
consistent cake.

Since we have been handling sludge on a more continuous basis,
most of the vacuum filtering problems have diminished.  Except
for start-up and some random occurrences, the filter can run
unattended and as designed.  On  an average, we have been dis-
charging a 53% solids cake with or without cake washing.  The percent
                             528

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soluble in the wet cake without cake washing is about 5%.  The
effect of cake washing on soluble salts is being determined
currently.  Also, the optional water volume and arrangement for
the wash sprays have to be determined to measure its effects on
the system's water balance.  Fortunately, contrary to original
projections, we should not have to add a repuddler to aid in
filter cake washing.

CONTROLS PERFORMANCE

In general,  the control system has been able to function properly
and to provide smooth responses to changes in boiler loads.
Relatively constant scrubber bleed pH and good SO  removal
efficiencies are easily maintained.  Some revisions, however,
had to be made in the control theory so that a steady operation
could be assured.  These changes were in the areas of lime
feeding, clarifier monitoring, and pH sensing.

Originally,  lime feed was somewhat difficult to automatically
control because the magnetic flow meter used to monitor the slurry
flow is susceptible to scaling.  We were never really sure what
the flow of the slurry actually was and,  consequently,  started
to notice wild fluctuations in the alkalinity at the causticizer
reactor.  To circumvent this situation, we are now manually
controlling the rate of dry lime addition to the system and set
the slaking rate to maintain a constant level in our lime slurry
tanks.  Presently, we maintain a constant volumetric flow rate
to the causticizer, but the percent lime in the slurry varies
as we change the lime addition rate.  A rough addition rate is
known through experience and is adjusted after manually sampling
for alkalinity in the causticizer.

Also, at start up, we thought that the torque reading on the
clarifier rakes would be a good indication of sludge inventory
and blankets heights.  Experience has shown, however, that no
direct correlation can be made.  Thus we have had to implement
the manual monitoring of the sludge blanket previously described.

In the most critical area, pH sensing of the recycle stream, we
have found that the sensors have a tendency to drift and must
be recalibrated every shift.  This drifting may be caused by the
way we are sampling rather than the instrument itself.   Current
practice calls for comparing the solution pH at the sensor to the
pH reading of a lab instrument and adjusting accordingly.  The
effects of shielding the pH probe from the abrasive action of
the recycle stream is being investigated.
                              529

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MISCELLANEOUS HARDWARE PERFORMANCE

To date, most equipment has performed as expected with no serious
problems.  The fiberglass reinforced piping on the scrubber feeds
and recycles show no evidence of abrasion.  Slurry pumps and feed
pumps are also holding out well.  Some plugging and scaling
problems have been encountered with other pieces of equipment,
however.

The largest problem has been with the lime slakers.  They have
required considerable maintenance and attention.  Most of this,
we feel, is due to the fact that we are slaking with process
water.  Thus we are carrying out the same reactions in our slaker
as we are in the causticizer.  Gypsum scale has been evident both
in the slakers and the slurry piping.  A modification has been
made so that we can slake with city water when the water balance
of the system allows.  Currently, we operate the slakers half
the time on city water and half on process water.  The maintenance
has decreased drastically since starting this and the practice
of running them continuously.

Also, some plugging and scaling of the gravity lines in the system
have recently become evident.  The overflow line between the
primary and softening clarifiers became partially plugged and had
to be descaled with a high pressure water hose.  The scaling in
this section was probably caused by the fact that our calcium
carbonate slurry is recycled through this line.  A revision in
this piping arrangement is planned.  In addition, the overflow
line between the two reactors has shown signs of scaling.  The
exact cause is not currently known, but calcium carbonate is
again suspected.  A piping revision is also planned for here.
The reactor tanks themselves also show signs of scale build-up.
A regular maintenance program may have to be set up to maintain
the gravity flow lines.
                    V.  PROCESS ECONOMICS

The main reason for selecting the double alkali system for
Chevrolet-Parma was that it afforded an economic advantage
over conversion to lower sulfur oil or burning low sulfur coal.
After assessing our current cost, we feel that this advantage
is still real.  A precise cost estimate at this time is impossible
because of fluctuating labor requirements, projected sludge
handling changes,  and rising chemical cost.  Currently, our best
estimate is $12/ton of coal burned.  This figure represents fixed
cost, current chemical cost, utilities, labor, and maintenance
and is broken down as follows:
                            530

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     Chemical Costs                 Cost/Ton of Coal (55,000 Tons/Yr)
                                           $

        Lime                               .98
        Soda Ash                           .82
        Carbon Dioxide                     .07
        Polymer                            .01

                          Sub Total                      1.88

     Utilities

        Water                              .16
        Steam                              .37
        Electricity                       1.32

                          Sub Total                      1.85

     Solid Waste                           .81

     Labor                                2.04

     Maintenance                           .67

     Fixed Costs                          4.55

                          Sub Total                      8.07

                              Total                     11.80

This cost added to the $21/ton of coal purchase price is still
some $8/ton lower than the premium price for low sulfur coal.

The cost figures for Chev-Parma have to be used with discretion
and cannot be applied across the board for every one of GM's
powerhouses.  Each one is somewhat unique and thus capital costs
for installation can vary greatly just because of the physical
plant site.  As an example,  an estimate of installation costs for
another GM plant was made and determined to be $8 million, more
than double that of Chevrolet-Parma.  This higher fixed cost
coupled with the plant's lower steam requirements would mean
operating costs double that of Chev-Parma.  For this particular
site, other control alternatives may be more economical.
                            531

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                       VI.   SUMMARY

The double alkali system is still going through intensive
evaluation to determine its complete capabilities.  In general,
the trend of the system seems to be one of steady improvement.
The system's evolution has not been easy, however, and has
required a concerted effort.  What must be remembered is that
we are working with a highly developmental system.  Not all
the problems have been solved, and it will take time to
establish the process and equipment reliability and the exact
operating costs.  Hopefully, after a complete year of operating
experience, these questions can be answered positively and we will
have provided an economic alternative to meeting the sulfur dioxide
emission requirements.  General Motors will gladly keep all
interested parties informed of our progress in meeting this
challenge.
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                       BIBLIOGRAPHY
1.   R.  J.  Phillips,  "Operating Experiences With A Commercial
     Dual-Alkali SO2  Removal System",  67th Annual Meeting
     of the Air Pollution Control Association,  June,  1974,
     Denver Colorado.

2.   R.  J.  Phillips,  "Sulfur Dioxide Emission Control for
     Industrial Power Plants",  Manufacturing Development,
     General Motors Corporation.

3.   D.  Draemel, "An EPA Overview of Sodium-Based Double-
     Alkali Processes,  Part I-A View of Process Chemistry
     Of Identifiable And Attractive Schemes", Control Systems
     Laboratory, U.S. Environmental Protection Agency,
     Research Triangle Park, North Carolina.
                              533

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                Figure 1.   CHEV-PARMA
                   SCRUBBER BUILDING

    Vacuum
    Filter
                                        A
                    Exhaust
               Neutralizer
      Recausticizer
 Primary
Clari fier
 Soda
 Ash and

?L
                              Scrubber

                                Gas
                              Recycle
                              Tank
  Softener
  Clarifier
        Figure 2.  PROCESS  FLOWSHEET

                        534
                                       Scrubber
                                         Feed

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Figure  3,   SCRUBBER
Figure  4.   RECYCLE TANK
            535

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Figure  5.   REACTOR TANKS
Figure 6.  CLARIFIERS
             536

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   Figure 7.  VACUUM FILTER
             "J""S
090090 Q

    mmtmmm
          OBBGBO
      Figure 8.   CONTROL PANEL
              537

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                  PART II
        EQUIPMENT PERFORMANCE WITH
A COMMERCIAL DUAL-ALKALI SO2 REMOVAL SYSTEM
            Edmund J. Piasecki
        General Motors Corporation
             Argonaut Division
             Detroit/ Michigan
For Presentation at Environmental Protection
Agency Symposium on Flue Gas Desulfurization
             Atlanta, Georgia
            November 4-7, 1974
                        539

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                 INTRODUCTION
Industrial boilers because of their size,
load fluctuation and operating character-
istics such as high excess air, relatively
high dust loads, etc., make them differ
from utility units.

When investigating possible control systems
for S02 emissions, a basic criteria was es-
tablished.  This was as follows:

1.  The system must provide complete equipment
    reliability.

2.  The system must have a minimum of com-
    plexity.

3.  The system must maintain control over
    a wide range of steam loads.

4.  The system must be economically com-
    petitive with other control strategies.

Since this was the first full-scale instal-
lation of a double-alkali control, there was
no previous experience from which to draw.
However, the Argonaut Division of General
Motors Corporation has had considerable ex-
perience in the design and development of
systems for industrial waste treatment
plants and powerhouses; and it was from
this area that equipment selection and de-
sign for this plant was utilized.
                      540

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             EQUIPMENT CRITERIA AND PERFORMANCE
As with any new process, one can expect any number of start-
up problems.  These may be related to the process chemistry,
mechanical equipment or a combination of both.  At our Chevrolet-
Parma facility we experienced some difficulties in these areas.
We will point out problems along with a presentation of basic
design information.

Booster Fans - The existing boiler I.D. fans were retained and
the increased pressure requirements for the scrubbing system
were obtained by the addition of booster fans.  The fans were
located upstream of the scrubbers to allow them to run in the
dry inlet gas stream.  This approach eliminates the need for
expensive corrosion resistant materials which would be required
on the outlet side of the scrubber.  The design parameters for
the booster fans are:

                              Boilers 1 & 2      Boilers 3 & 4

Flue Gas Flow (cfm)           61,500             58,500
Static Pressure               13"                13"
Design Temperature            393F              730F
Gas Density                   0.0474 lbs./ft.3   0.0347 lbs./ft.3
BHP                           187                178
Motor HP                      200                200
Fan & Motor Speed             1180 RPM           1180 RPM
Electrical Characteristics    460-3-60           460-3-60

Scrubbers - After evaluation of many scrubbers, it was felt
that the impingement type unit would be the unit most likely
to succeed in a double-alkali type process.

This type was selected because of the need for removal of both
S02 and par