EPA-650/2-74-127
DECEMBER 1974
Environmental Protection Technology  Series


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                                  EPA-650/2-74-127
EVALUATION  OF SULFUR DIOXIDE
   EMISSION CONTROL  OPTIONS
    FOR  IOWA  POWER  BOILERS
                     by
           D. O Moore, Jr. , J M Pctert.
         W S. Alper, E. Rosen, and J . R Burke

             The M W. Kellogg Company
            1300 Three Greenway Plaza East
               Houston, Texas 77046
            Contract No. 68-02-1308, Task 3
               ROAP No. 21ADD-079
             Program Element No. 1AB013
         EPA Project Officer: James D. Kilgroe

             Control Systems Laboratory
         National Environmental Research Center
       Research Triangle Park, North Carolina  27711
                  Prepared for

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

                 December 1974

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This report has been reviewed by the Environmental Protection Agency
and approved for publication.  Approval does not signify that the
contents necessarily reflect the views and policies of tho Agency,
nor docs mentioir of trade names or commercial products constitute
endorsement or recommendation for use.
                                  11

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                     TABLE  OP CONTENTS

                                                          Page No,

   I.   Introduction                                             1

  II.   Summary  and Conclusions                                  6

 III.   Overall  System Evaluation                               30

       A.  Basic Assumptions  Made  for the System               31
          to Use in  the  Linear Computer Program

       B.  Linear Computer  Program Results                     33



  IV.   Process  Descriptions                                    44

       A.  Flue Gas Scrubbing Processes                        44

          1.  Wet Limestone  System
          2.  Wellman-Lord System
          3.  Allied System

       B.  Coal Cleaning  Process                               58

  V.   Descriptions of Power Plants in Iowa                    62

  VI.   Estimates for Flue Gas Scrubbing                        ««

       A.  Detailed Estimates for Wet Limestone                90
          Systems

       B.  Computerized Estimates for Both Scrubbing           94
          Systems

          1.  Wet Limestone Cost Model
          2.  Wellman-Lord/Allied Cost Model

       C.  Comparative Economics of Wet Limestone            105
          vs. Wellman-Lord/Allied

VII.   Linear Programming Model                              115

      A.  A Brief Discussion of Linear Programming          115

      B.  The Definition of the Problem in  Terms of an LP   us
          Model
      C.  Solution Using KELPLANS                           125
                              111

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                                                          Page No.

VIII.  References                                           139

  IX.  Glossary                                             141

   X.  Appendices                                           143

       A.  Power Plant Input Data                           144

       B.  Wet Limestone System                             183

           B-l.  Process Flow Sheets
           B-2.  Equipment List
           B-3.  Standard Scrubber Modules
           B-4.  Standard Sizes for Venturi
                 Scrubbers and Absorbers
           B-5.  Standard Limestone System -
                 Plan & Elevation
           B-6.  Sludge Pond Size Sheet
           B-7.  Plot Plans for Each Plant -
                 Wet Limestone Systems Added

       C.  Wellman-Lord/Allied System                       205

           C-l.  Process Flow Sheets
           C-2.  Equipment List
           C-3.  Standard Scurbber Module
           C-4.  Standard Wellman-Lord System Plan
           C-5.  Standard Component Sizes
           C-6.  Plot Plans for Each Plant -
                 Wellman-Lord/Allied Systems Added

       D.  Coal Cleaning System                             225

           D-l.  Process Flow Sheet
           D-2.  Equipment List
           D-3.  Simplified Plot Plan - Typical
                 600 TPH Plant

       E.  Plot Plans of Other Power Plants                 230

       F.  Conversion from English to Metric Units          237

       G.  Linear Computer Program Print-outs  (Abridged)    239
                               iv

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                      LIST OF FIGURES

Figure No.                Title                            Page No.
    1       Plot of Incremental System Costs vs. S02           43
            Emission Specification
    2       Scrubbing System Costs vs. % Sulfur               114
    3       Wet Limestone Scrubbing Costs Used in             127
            Linear Program
    4       Coal Cleaning Costs Used  in Linear Program        128
    5       Process Flow Diagram - Limestone and Effluent     184
            System
    6       Process Flow Diagram - Scrubber System            185
    7       Standard Scrubber Module  - Type A: Size I         190
    8       Standard Scrubber Module  - Type B: Size I         191
    9       Standard Scrubber Module  - Type C: Size I         192
   10       Standard Limestone System - Plan and Elevation    195
   11       Plot Plan - Des Moines Plant - Wet Limestone      197
            Scrubbing System
   12       Plot Plan - Maynard Plant - Wet Limestone         198
            Scrubbing System
   13       Plot Plan - Muscatine Plant - Wet Limestone       199
            Scrubbing System
   14       Plot Plan - Riverside Plant - Wet Limestone       200
            Scrubbing System
   15       Plot Plan - Burlington Plant - Wet Limestone      201
            Scrubbing System
   16       Plot Plan - Kapp Plant -  Wet Limestone            202
            Scrubbing System
   17       Plot Plan - Prairie Creek Plant - Wet Limestone   203
            Scrubbing System
   18       Plot Plan - Sutherland Plant - Wet Limestone      204
            Scrubbing System
   19       Process Flow Diagram - Wellman-Lord Process       206
   20       Process Flow Diagram - Allied Chemical Process    207
   21       Standard Scrubber Module  - Wellman-Lord Process   214
   22       Standard Module Plans - Wellman-Lord/Allied       215
            Process

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                      LIST OF FIGURES CON'T.
Figure No.                Title
Page No.
   23       Plot Plan - Des Moines Plant - Wellman-          217
            Lord/Allied Process

   24       Plot Plan - Maynard Plant - Wellman-             218
            Lord/Allied Process

   25       Plot Plan - Muscatine Plant - Wellman-           219
            Lord/Allied Process

   26       Plot Plan - Riverside Plant - Wellman-           220
            Lord/Allied Process

   27       Plot Plan - Burlington Plant - Wellman-          221
            Lord/Allied Process

   28       Plot Plan - Kapp Plant - Wellman-Lord/           222
            Allied Process

   29       Plot Plan - Prairie Creek Plant - Wellman-       223
            Lord/Allied Process

   30       Plot Plan - Sutherland Plant - Wellman-          224
            Lord/Allied Process

   31       Process Flow Diagram - Coal Cleaning Process     226

   32       Simplified Plot Plan - Coal Cleaning Plant       229

   33       Plot Plan - Pella Plant                          231

   34       Plot Plan - Iowa State University Plant          232

   35       Plot Plan - Fair Plant                           233

   36       Plot Plan - Dubuque Plant                        234

   37       Plot Plan - Lansing Plant                        235

   38       Plot Plan - Sixth Street Plant                   236
                              VI

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                      LIST OF TABLES

Table No.                 Title                            Page No,
   1       Case 1 - Summary of Costs                           40
   2       Case 2 - Summary of Costs                           41
   3       Case 3 - Summary of Costs                           42
   4       Economic Comparison of Wet Limestone vs.           109
           Wellman-Lord/Allied
   5       Power Plant Input Data - Des Moines Plant          145
   6       Stack Gas Scrubbing System - Des Moines Plant      150
   7       Power Plant Input Data - Maynard Plant             151
   8       Stack Gas Scrubbing System - Maynard Plant         156
   9       Power Plant Input Data - Muscatine Plant           157
  10       Stack Gas Scrubbing System - Muscatine Plant       160
  11       Power Plant Input Data - Riverside Plant           161
  12       Stack Gas Scrubbing System - Riverside Plant       166
  13       Power Plant Input Data - Burlington Plant          167
  14       Stack Gas Scrubbing System - Burlington Plant      170
  15       Power Plant Input Data - Kapp Plant                171
  16       Stack Gas Scrubbing System - Kapp Plant            174
  17       Power Plant Input Data - Prairie Creek Plant       175
  18       Stack Gas Scrubbing System - Prairie Creek Plant   173
  19       Power Plant Input Data - Sutherland Plant          179
  20       Stack Gas Scrubbing System - Sutherland Plant      182
  21       Equipment List - Wet Limestone System              186
  22       Absorber-Venturi Standard Sizes                    193
  23       Wet  Limestone Process - Scrubber Area Dimensions   194
  24       Sludge Pond Size Sheet                             196
  25       Equipment List - Wellman-Lord/Allied Process       208
  26       Wellman-Lord/Allied Process Standard Sizes         216
  27       Equipment List - Coal Cleaning Plant               227
                              VII

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                     ACKNOWLEDGMENTS
The authors wish to gratefully acknowledge the assistance and
support of a number of persons and groups who provided valuable
contributions to this project.  The U.S. Environmental Pro-
tection Agency, the Iowa Geological Survey, and the Iowa Depart-
ment of Environmental Quality provided aid in defining the
nature and scope of the task.  Gates Engineering Company of
Beckley, West Virginia performed the study entitled "Feasibility
Study of Iowa Coals" which gave essential background information
for the study.  The Iowa electric utility industry provided
data and drawings for the power plants which were used  ex-
tensively in the preparation of the report.
                              vni

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                        I.  INTRODUCTION

 This  report  presents  the  results  of  a detailed study performed
 for the  U. S.  Environmental  Protection Agency (Contract 68-02-
 1308,  Task No.  3)  and administered by the  Iowa Geological  Survey
 and the  EPA.   Close liaison  and cooperation with the Iowa  Depart-
 ment  of  Environmental Quality  (IDEQ)  and with the electric utility
 industry in  Iowa were also essential aspects  of this task..

 The primary  objective of  this  task was to  study coal burning
 power  plants in Iowa  as a  system  and to evaluate various emission
 control  strategies for this  system which would minimize total
 operating costs while meeting  selected S02 emission  levels.  To
 accomplish the objective  it  was necessary  to  determine  the  feas-
 ibility  of building centralized facilities for physical cleaning
 of indigenous  and  "foreign"  coals used in  Iowa's coal-fired
 steam-electric generating  plants.  It  was  also necessary to
 determine the  feasibility  of stack gas scrubbing at  some of the
 more problematic plants, as  selected by the IDEQ.  The  impetus
 for the  study was a need to  determine  optimal  (minimum) costs
 of reducing power plant emissions of sulfur dioxide  to  or below
 regulation levels.  In recent  years  increasingly more costly
 materials and,services and scarcer clean fuels  have  made it
 difficult to economically meet stringent environmental  constraints.

 There  are currently 35 power plants  in the state  which were de-
 signed to burn coal in at  least one  boiler per  plant.  Although
many of them also consumed natural gas  and fuel  oil  in past
years, the assumption was made for this study  that the Btu  require-
ment in each plant capable of  firing coal, was met exclusively
with coal.  The total generating capacity in the  state is present-
 ly some 3093 mw (excluding that produced by two plants not de-
signed for coal).   Most of the plants  are small, often with dimin-
utive boilers which were added piecemeal over the years as power
demands grew; rated capacities of the power plants range from
4.6 to 490.8 mw.

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The plants selected for the stack-gas study are as
follows:

     Des Moines Power Station No. 2, Des Moines
     Pella Plant, Pella
     Iowa State University Plant, Ames
     Maynard Plant, Waterloo
     Muscatine Plant, Muscatine
     Fair Plant, Montpelier
     Riverside Plant, Bettendorf
     Burlington Plant, Burlington
     Dubuque Plant, Dubuque
     Lansing Plant, Lansing
     Kapp  Plant, Clinton
     Prairie Creek Station, Cedar Rapids
     Sixth Street Station, Cedar Rapids
     Sutherland Plant, Marshalltown

To obtain data and drawings and  to permit  comprehensive
evaluation of each plant,  the  following  actions were  taken:
 (1)  an introductory  letter was sent  by the Iowa Geological
Survey to each of  the  utility  home offices,  explaining the
purpose and  conduct  of the study;   (2) questionnaires
were mailed  to the utilities)  with more  detailed  informa-
tion requested  from  the  above  listed plants;   (3)  Federal
Power  Commission  Forms (FPC 67),  detailing the plants'
 fuel consumption,  operating parameters and effluent charater-
 istics, were obtained from the EPA;  and  (4)  visits were
made to each of  the  plants above.*   Additionally,  photographs
were taken  at some of the sites  when weather permitted.
 * The Lansing plant was not visited due to time limitations;
 however, adequate data and drawings were provided by the
 Interstate Power Company and the EPA.

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The EPA Task Order specified that two flue-gas scrubbing methods
be considered:  the wet limestone system and a regenerable
sorbent system which yields by-product elemental sulfur.  Be-
cause the WeiIman-Lord/Allied process has been applied at plant
scale, it was selected for the second system.  Some operating
data are available for both methods; however, no attempt is
made in this report to evaluate whether or not flue-gas scrubbing
is proven technology.  Instead the basic approach included
application of available operating and design data to the power
plants selected for consideration of equipment retrofit.

To accommodate a range of boiler sizes, a graduated set of stan-
dard scrubber modules was developed for both processes. Eight
standard modules.were designed from which an appropriate size
and number could be selected for each application.  For the wet
limestone ststem, storage, preparation and handling equipment
were sized and cost estimates were prepared for each plant.

Major use was made of computerized cost models in estimating
capital and operating costs for both systems.  Additionally,
detailed estimates of capital costs of wet limestone systems
were made by Kellogg1s Estimating Department.  Because of the
nature of the estimates, the accuracy of vendor quotes, the lack
of a completely definitive design, and other factors, the overall
accuracy of the estimates is probably 30-35%,  with the probability
of underrun being very small.

Physical cleaning of coal was examined in this study as a
possible alternative to flue-gas scrubbing.  A subcontract was
let to Gates Engineering, Inc., Beckley, West Virginia, to
determine the availability, locations, costs, characteristics
and washabilities of coals in Iowa, Illinois and Kentucky; the
same parameters (except washability) were provided for Colorado,
Wyoming and Montana coals.  Also, capital and operating cost data

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were estimated for a typical 600 t/h  Cfeed) coal-cleaning faci-
lity, and several likely locations were suggested for several
centralized plants of like size.

Because of the large number of variables involved in determin-
ing the lowest system cost for reducing sulfur emissions in the
state, it was necessary to devise a linear programming  (LP) model
capable of accommodating the many possible permutations and
optimizing (minimizing) the system costs.  Among these variables
were transportation modes and costs, coal characteristics, coal
costs and mine locations, power plant locations and fuel demands,
possible cleaning plant locations and costs, and scrubbing
equipment costs and characteristics.  Much information compris-
ing the data base was obtained from the coal-cleaning subcontract
and was then used as input to solve the LP model.  Using a matrix-
generation routine and an optimization routine, the LP model is
solved by computer to determine the optimal systen costs for
sulfur reduction.

The linear programming model, developed by Kellogg's Information
Systems Department, proved to be a very useful tool.  Once the
model was perfected it was readily modified to accommodate a
range of sulfur emission specifications, mine capacities, coal
costs, transportation costs and other parametric constraints.
Of course only one variable was allowed to change at a time so
that the optimal solutions could be properly correlated.  The
resulting set of minimal system costs provided important inputs
to the conclusions given in the next  section.

The proposed sulfur dioxide emission  regulation for the State
of Iowa  (on power plants not subject  to Federal New-Source
regulations is 6.0 pounds of S02 per  million Btu of heat input
 (based on higher heating value of fuel) for coal-fired boilers.
The present emission standard set by  the Iowa Air Quality Commission
 (effective January 1, 1975) is 5 Ib S02/MM Btu.  It is worthy to
note that this regulation is- one of the least stringent con-
straints in the United States.  Since it is oossible that other
S02 emission controls will be imposed, it was decided to use a
                               4

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 range  of  sulfur  control  specifications  for  the  linear  program
 work.  Thus we have  been able  to  present  comparative costs  for
 optimal sulfur control at various specification levels.   Sulfur
 dioxide emission levels  used in his  study included  no  control,
 5.0, 3.1,  and 1.2  Ib S02/MM Btu.

 A  total of 18 power  plants (2737  mw)  were used  in the  linear
 computer  program.  At 100% generating capacity, these  plants
 require about 35,000 t/d of coal.  The  use  of a load factor of
 about  65-70% for these plants  would  more  nearly approximate the
 actual Iowa coal demand.   However, the  conclusions  reached
 regarding incremental system costs (in  C/MM Btu) to meet  any
 given  specification  would not  change.

 All costs used in  the study -  scrubbing system  capital and
 operating costs, coal cleaning costs, coal  pithead  costs, ash
 and refuse disposal  costs, coal storage/transfer cost, and  rail
 and barge freight  rates  - are  on  a January,  1974 basis.   The
 conclusions of the study are based on the assumptions  made.
 The present unprecedented inflation  rate  leads  to rapidly
 changing  equipment,  coal, and  transportation costs.  Therefore
 certain limitations  exist when attempting to predict the  ootimal
 sulfur dioxide control strategy a few years hence.

 Since  this study was conducted for the  State of Iowa,  it  follows
 that the  conclusions apply only to that state due to Iowa's
 particular geographic location and power  plant  network.

It is recognized that the needs of other states  for low sulfur
western coal  will make competition for this  fuel very keen.   How-
ever,  the assumption was  made for this study that at least 16,000 tpd
will be available to Iowa utilities.

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                    II.  SUMMARY AND CONCLUSIONS

A.  General Conclusions Pertaining to Coal as an Energy Source

 •  There is no question that coal is the most abundant fossil fuel
    energy source in the United States.   Coal accounts  for 87.1*  of
    the mineral fuel reserves in the country.  Oil  and  gas account
    for 8.1? and shale and others account for 4.8*  (1,  p.  29). The
    total coal reserves in the United States are estimated to be
    some 3,210 billion tons (1, p.  432)  or 48.1* of the estimated
    total world reserves (1, p. 32).  There is far  more coal  in
    this country than in any other country in the world.

 •  Of the total coal reserves in this country,  about 71-3* is predicted
    to be bituminous, sub-bituminous, and anthracite (1, p. 432).
    If half of this  coal can be considered recoverable, the usable
    reserves are approximately 1,144 billion tons (assuming no land
    use restrictions).   In 1972, the steam-electric utility plants
    in the U.S.  consumed fuel (coal, oil, and gas)  at the  rate
    equivalent to 634.9 MM tons of  coal  per year.   At that rate of
    consumption, there  is enough coal to last about 1,800 years.  If
    the steam-electric  utilities are allocated only 60% of the coal
    reserves (and assuming they burn coal exclusively), the reserves
    will last  about  1,080 years.  Finally,  assuming a continued
    increase in  the  electric  power  demand,  it is  easy to see  that
    there is enough  coal to  last for hundreds of years.

 •  The reserves of  coal in  the  U.S.  containing  1* sulfur or  less are
    estimated  to be  about  65%  of the  total  tonnage  (based on  a study
    done in  1966 by  the  Bureau  of Mines  - 1,  p.  203).   About  6% of
    the total  reserves  (containing  1*  sulfur  or  less) lie in  the eight
    major coal producing states  (Alabama, Illinois, Indiana, Kentucky,
    Ohio,  Pennsylvania,  Virginia, and West Virginia).  About 59%
    of the  total reserves  (containing  1%  sulfur or less) are estimated
    to be  in states  which  are not now major coal producers (principally,
    Colorado,  Montana, New Mexico, North  Dakota,  and Wyoming).  Hence
    it  may be  concluded  that while there  are  abundant reserves of low

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    sulfur coal in the country, drastic changes will be needed in the
    coal industry as well as in transportation to enable the steam-
    electric utility industry to use this coal.

B.  General Conclusions Regarding the Supply of Coal for the State of Iowa

•   The steam-electric power generating capacity in the State of Iowa
    (in 1972) is 3093 mw  (9, p. 17).  This power is generated at 35
    plants having the ability to burn coal  (some also can burn oil
    or gas).  Two plants which burn only oil and gas and have a
    generating capacity of 19 mw total were not considered.  The
    generating capacity in Iowa is fairly low - about 1% of the total
    in the United States  (9, p. 53). The average load factor for all
    steam-electric power plants in Iowa in 1972 was 51% (9, p. 17).
    If the average load factor is assumed to increase to 60% in 1974
    due to population and industrial growth as well as increased use
    of electrical equipment, and if the total energy requirement is
    met with coal, then the total coal requirement for the state will
    be about 8.66 MM tons/year  (about 23 ,700 tons/day on a 365 day
    basis).  Assumed are a heat rate of 12,000 Btu/kwh and an HHV of
    11,260 Btu/lb.

•   Total coal reserves in the State of Iowa are estimated to be
    7,236 MM tons in seams thicker than 14 inches  (2, p. 4).  These
    reserves are located in 25 seams and are broken down as follows:

                     Thickness            MM Tons
                     14" - 28"
                     28" - 42"
                         + 42"
                     Total

    The tabulation shows that 5,076 MM tons exist in seams 28" or
    more in thickness which could be mined economically.  Another
    source (1, p. 432) credits Iowa with known bituminous coal reserves

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of 6,519 MM tons with  another  14,000 MM tons being estimated to
exist in unmapped  and  unexplored  areas.  No matter which estimate  is
used, it is evident that there  is enough coal  in  Iowa to meet the
demand of the steam-electric utility industry  for hundreds of years.
However, the quality of Iowa coal is rather poor.  The sulfur
content ranges from 4-8%, the ash content from 12-23%, and the
higher heating value  (HHV)  from 9,400-11,500 Btu/lb (2,  p.  6).
Therefore,  owing to air pollution regulations, Iowa coal cannot
be used unless one or  more  of the following control measures is
put into effect:
                 - low sulfur coal blending
                 - coal cleaning
                 - stack gas scrubbing
The logical states to  choose as alternative suppliers of coal for
Iowa are Illinois, Kentucky, Wyoming, Colorado, and Montana (as
well as possibly Kansas and Oklahoma).  Illinois  has the largest
known bituminous coal  reserves  in the United States and Kentucky
has the third largest.  However, these coals have intermediate
sulfur contents (about 2-4% sulfur) and cannot be used exclusively
to meet stringent air  pollution regulations (2, p. 8).   Wyoming,
Colorado, and Montana  are the best potential suppliers of low
sulfur coal (<.!%)  for the State of Iowa. The following table gives
the breakdown of coal  reserves of  the states  considered  as  suppliers
(1, p. 432) :
        Coal Reserves  of Potential Supply States  (MM tons)
                   Overburden 0 - 3000 Ft.  Thick
          Resources Determined by Mapping and Exploration
           Bituminous     Sub-bituminous
              Coal       	Coal       Lignite  Anthracite Total
Colorado
Illinois
Iowa
Kentucky
Montana
Wyoming
62,389
139,756
6,519
65,952
2,299
12,699
18,248
0
0
0
131,877
108,011
0
0
0
0
87,525
0
78
0
0
0
0
0
80,715
139,756
6,519
65,952
221,701
120,710

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C.  General Conclusions Reached When Comparing the Use of Low Sulfur
    Coal to Stack Gas Scrubbing to Meet an Emission Specification of
    1.2 Ib S02/MM Btu

•   When low sulfur coals are located reasonably near the demand sites
    and when low cost unit train rates may be applied, the use of low
    sulfur coal appears to be superior to the use of stack gas scrubbing
    to meet emission regulations (particularly when the power plants
    are small, e.g., <250 mw, and difficult to retrofit with scrubbing
    facilities).  This is the case in the State of Iowa where western
    coal is about 1000 miles away and the power plants are small.
    Simplified incremental system costs are shown below assuming equal
    coal pithead cost, Btu value, ash content, etc.

                   Basis:  250 MW Plant
                           Coal HHV = 10,000 Btu/lb
                           Incremental distance = 1000 miles

    Use of Low Sulfur Coal                  Stack Gas Scrubbing
    1000 Mi  ($0.005/T Mi)  (100) = 25C/MM Btu     40-45C/MM Btu
    20 MM Btu/ton

    If transportation costs increase 60-80% (to $0.008-0.009/T-Mi)
    or if low sulfur western coals cost 15-20C/MM Btu more than local
    coals, then the two cases would be essentially equal.

•   When low sulfur coals are located at great distances  (> 1500
    miles) from the demand sites and when the power plants are large
    (> 500 mw) and relatively easy to retrofit with stack gas
    scrubbing facilities, the use of stack gas scrubbing appears
    to be superior.  This is not the case in Iowa.

                   Basis:  1000 MW Plant
                           Coal HHV = 10,000 Btu/lb
                           Incremental Distance = 1500 miles

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     Use of Low Sulfur Coal                        Stack Gas Scnibbing
     1500 Mi ($0.005/T-Mi) (100) = 37.5CMM Btu     30-35C/MM Btu
     20 MM Btu/ton

•    If it should be determined that the use of either control measure
     (low sulfur fuel or stack gas scrubbing) would yield about the
     same incremental cost in C/MM Btu, then it probably would be
     advantageous to use stack gas scrubbing due to inflationary factors.
     About 40-50% of the costs associated with stack gas scrubbing
     will remain constant while incremental transportation costs (as
     well as pithead costs) for western coals will probably continue
     to rise.

     The needs of other states for low sulfur coal along with finite
     mining, storage, loading, and shipping facilities will likely make
     competition for this source of "clean" fuel very keen.  It is
     likely, in turn, that delivered costs of western coals will
     continue to increase.

D.   Specific Conclusions Pertaining to the State of Iowa as Determined
     by the Linear Computer Program.

     Three cases were considered for Iowa using the linear computer
     program.

     Case 1:  No limits are placed on any of the coal supplies.

     Case 2:  A limit of 16,000 t/d of western coal is imposed on the
              system.  This is approximately the quantity of low
              sulfur coal required by the power plants for which it is
              not practical to use stack gas scrubbing in order to
              meet an emission specification of 1.2 Ib SC^/MM Btu.
              The other eight plants are then forced by the system
              constraints to use stack gas scrubbing to meet the
              most stringent regulation.
                                   10

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     Case 3:  Limits of 16,000 t/d of western coal and 7,000 t/d of
              Illinois coal are imposed on the system.  These limits
              force the use of considerable quantities of Iowa coals
              (about 40% of the total state requirement).

     Four different emission levels were considered for each case
     using the program.

     20 Ib S02/MM Btu:   This represents no control.

     5 Ib S02/MM Btu:    This will be the emission control level in
                         Iowa as of January 1. 1975.

     3.1 Ib S02/MM Btu:  This level was arbitrarily chosen as being
                         halfway between the actual emission level
                         and the most stringent level.

     1.2 Ib S02/MM Btu:  This is the Federal emission control level
                         for new coal-fired boilers.

     For this study, the simplifying assumption was made that low
     sulfur western coals could be burned in existing Iowa boilers
     without modifying these boilers.  In reality, it may or may not
     be necessary to modify the boilers and particulate emission
     control equipment depending on the properties of the particular
     western coal burned and on the design of the boilers.  The
     modifications required, if any, may range from slight to extensive.
     It was not possible to quantify the effect of burning western coals
     in the existing power plants for this study.  These  boiler modifi-
     cation costs, if accounted for, would tend to shift  the optimal
     cost solution in favor of stack gas scrubbing.  Refer to Section
     II (Part G)  for a discussion of the properties of western coals
     as they relate to use in existing boilers.

1.   Case 1 - Unlimited western coal, unlimited Illinois  coal

•    The following table presents the incremental system costs for

                                   11

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meeting various S02 emission specifications as well as the
source of the coal for meeting the different specifications:

                        Incr. System     Coal Used; % of Tonnage
Spec; Ib S02/MM Btu   Cost; <=/MM Btu* Iowa  Illinois  Western  Total
   20 (No Control)         0.00       49.5    31.1     19.4    100.0
    5                      5.04       10.0    56.9     33.1    100.0
    3.1                    8.38        5.6    28.2     66.2    100.0
    1.2                   12.10        1.5     4.6     93.9    100.0

As shown by the table, the incremental system costs rise about lin-
early as the regulations become more stringent.  However the increase
in cost is rather nominal (12.IOC/MM Btu), even when meeting the
most stringent regulation (1.2 Ib S02/MM Btu).

In no instances are scrubbing facilities or coal cleaning plants
installed.  Instead, the more stringent regulations are met by
blending in greater quantities of western coal.

As shown in the table, whenever any emission regulation is im-
posed, the amount of Iowa coal used is rather small (dropping
from 10% of the total at a 5 Ib specification to 1.5% of the
total at a 1.2 Ib specification).

The quantity of western coal used at the 1.2 Ib specification
is fairly large - about 3 unit trains/day (note that a unit
train carries about 10,000 tons).

Western coal would need to increase in cost by about $6.50/ton
in order to obtain equal costs for Cases 1 and 2 at the 1.2 Ib
specification.  It would need to increase in cost by about $7.60/ton
to obtain equal costs for Cases 1 and 3 at this specification.
These increases in cost may result from increased coal pithead
cost, increased transportation cost, or a combination of the two.

Includes all incremental coal, transportation, treatmentr storage
and disposal costs to meet the specified emission level.

                              12

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2.  Case 2-16,000 T/D limit on western coal, unlimited  Illinois coal

*   The following table summarizes this case:

                          Incr. System     Coal Used;	% of Tonnage
    Spec; Ib  S02/MM Btu Cost; C/MM Btu Iowa  Illinois  Western
       20 (No Control)        0.00      49.5    31.1     19.4
        5                     5.04      10.0    56.9     33.1
        3.1                   9.66      20.6    35.5     43.9
        1.2                  26.21      11.9    42.5     45.6     100.0

•   This case is identical to the previous case (Case 1) with no
    control or with a 5.0 Ib specification.  The incremental costs
    are somewhat higher at the 3.1 Ib specification  (about 1.3C/MM Btu)
    because the limitation of western coal forces a cleaning plant
    to be installed  (capacity = 7,489 t/d; location - Leon, Iowa).

•   At the 1.2 Ib specification, a drastic increase in incremental
    system cost  occurs.   With this regulation, scrubbing facilities
    are installed at the eight plants which were considered possible
    candidates for scrubbing.   (Note that 16,000 t/d of western coal
    is that quantity which is required in order for the  other ten
    plants to meet the 1.2 Ib specification).  No coal cleaning
    plants are installed.  The incremental system cost is 26.21C/MM Btu
    over no control or about 14C/MM Btu over Case 1 which has
    unlimited western coal.

 3.  Case 3 - 16,000 T/D limit on western coal
              7,000 T/D limit on Illinois coal

•   The  following table summarizes this case:
Incr. System
Coal Used:
Spec: Ib S00/MM Btu Cost: C/MM Btu Iowa
20 (No Control) 1.03
5
3.1
1.2
8.02
12.24
28.58
59.9
38.6
40.4
38.7
Illinois
18.7
18.7
18.1
18.7
% of Tonnage
Western
21.4
42.7
41.5
42.6
Total
100.0
100.0
100.0
100.0
                                   13

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•    In this case the Illinois coal was limited to about 20% of the
     total in order to observe how the use of increased quantities
     of Iowa coals influenced system costs.  Under the three
     control conditions (specifications of 5, 3.1 and 1.2), the total
     Iowa coal used was about 14,000-15,000 t/d or about 40% of the
     total.  Based on the assumptions made, the incremental system
     costs for this case (Case 3) rose by about 2.5-3C/MM Btu over
     the costs for Case 2.  The pithead costs for the Iowa coals
     would have to be lowered by about $1.50/ton in order to obtain
     costs equal to Case 2.  Also, the costs for no control increased
     by 1.034/MM Btu over Cases 1 and 2 because of the increased use
     of Iowa coal.

•    Cleaning plants are installed under all three control conditions
     due to the high sulfur content of the Iowa coals.

     Spec; Ib SO^/MM Btu      Cleaning Plant Size; T/D     Location
              5                         7,200              MB*(Mine at
              3.1                      14,398              MB  Leon
              1.2                       7,200              MB  Iowa)

•    Stack gas scrubbing is installed on the eight plants  (previously
     deemed possible candidates) only for the most stringent regula-
     tion  (1.2 Ib S02/MM Btu).  Note again that the use of stack
     gas scrubbing causes a rather sharp increase in incremental
     system costs.

E.   Conclusions Regarding Coal Cleaning

e    Coal  cleaning  (by heavy media washing) is a viable method of sulfur
     removal for coals which have a relatively high pyritic sulfur
      (FeS2) content.  About 1/3 to 1/2 of the sulfur originally
     present can be removed.  No organic sulfur can be removed by this
     process.  A sizable reduction in ash content  (about 50%) also  is

*    Refer to Section VII  for explanation of location codes.
                                   14

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 realized by this process.  However, about 12-16% of the Btu content
 of the coal is lost (at 80% total coal recovery).

 The following table lists properties of raw and cleaned coals
 (80% coal recovery):
 Mine
     Location
   Raw Coal Properties (As Received)
 % Moisture  % Ash  % Sulfur  Btu/lb
MA
MB
MC
MD
ME
Frederick, Iowa
Leon,
Ogden ,
Marion
Iowa
Iowa


, Illinois
Madisonville,
Ky.
11
18
13
7
8
.2
.0
.4
.0
.3
14.
12.
13.
14.
14.
2
8
2
9
8
5.
4.
6.
3.
4.
9
3
9
1
1
10
9
10
11
11
,038
,676
,184
,951
,801
 Mine
 MA
 MB
 MC
 MD
 ME
	Location
Frederick, Iowa
Leon, Iowa
Ogden, Iowa
Marion, Illinois
Madisonville, Ky.
            Clean Coal Properties

% Moisture % Ash  % Sulfur
11.2
18.0
13.4
9.0
8.3
7.9
7.0
7.5
7.0
7.2
3.5
1.9
4.5
2.0
2.7
          % HHV
 Btu/lb Recovery
11,033   87.9
10,650   88.1
11,166   87.7
12,505   83.7
12,340   83.6
An examination of the table indicates that only a modest reduction
in sulfur content normally can be achieved utilizing coal cleaning.
Therefore, this process appears to be promising only when an inter-
mediate SO- emission regulation is in effect  (i. e., 3.1 to 5.0 Ib
SO2/MM Btu).  Obviously, cleaning of these coals will not prove to
be adequate to meet the most stringent regulation  (1.2 Ib S02/MM Btu).
In some cases, a combination of coal cleaning and the use of low
sulfur coal will prove to be the logical choice to meet a given
specification.

An 80% coal recovery level was chosen for all coals after cleaning
                                15

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as this is approximately the optimum.  An examination of the graph
(2, p. 16) of sulfur content vs. percent recovery for Iowa coals
reveals that the largest drop in sulfur content occurs from 100 to
80% recovery.  There is very little decrease in sulfur content
as recovery drops from 80 to 60%.

The operating cost of coal cleaning  (for plants in the size
range of 600 t/h raw coal feed) is about $1.90/ton feed coal.  The
capital investment cost for a 600 t/h plant  (which
operates 2 shifts/day for 220-260 days per year) is broken down
as follows (2, p. 13).

                                 Capital Investment;   $
Raw coal unloading and storage           1,471,000
Preparation plant                        3,841,000
Clean coal handling                      1,437,000
Site preparation, roads, etc.              590,000
Refuse handling                            360,000
Total                                    7,699,000

This is equivalent to a unit investment of about $12,800/t/h for
plants in the 600 t/h size range.

Refuse disposal from a cleaning plant is expected to add about
$0.31/ton of refuse to the operating cost  (2, p. 21). The operat-
ing cost for intermediate storage of coal  (whether at a cleaning
plant or at a transfer point) is expected to be about $0.30/ton
of raw coal  (2, p. 21).

Refuse from a cleaning plant may be disposed of by several
alternative methods.  The means of transporting the refuse from
the plant is dependent on factors such as terrain, availability
of disposal areas, and quantity of material to be disposed of.
The most common methods used to transport the refuse are
trucking, belt conveyors, and aerial tramways.
                             16

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At the disposal site, earthmoving equipment must be available
to move and compact the refuse.  Depending on state require-
ments, when filling of an area is completed, it may be necessary
to cover the refuse with  a layer of soil and plant the area
with vegetation.

During storage of refuse, drainage facilities must be provided to
divert runoff water from adjacent areas away from the refuse
storage.  Also, drainage ditches must be installed to collect
runoff water from the refuse area and send it to a pond.  If
this water is acidic, provisions for treatment will be needed
before the water can be discharged into streams (2, pp. 17, 18).

The following hypothetical case is a summary of the incremental
cost to a power plant to clean a relatively high sulfur coal to
a level sufficient to meet a specification of 5.0 Ib  SO2/MM Btu.
             Coal Storage
             Coal Cleaning
             Refuse Disposal
                          % Sulfur        HHV;Btu/lb
             Raw Coal        4.0           10,000
             Clean Coal      2.7           10,800

             % Sulfur Removal = 46
             % HHV Lost       = 14
             SO2 Emission     = 5 Ib/MM Btu

             Incremental cost   2.26 x 100
             to power plant   = 0.86 x 20 MM    = 13-1<:/MM Btu

If, instead of cleaning, a sufficient quantity of low sulfur coal
(0.9% S) which must be transported 1,000 miles, is blended with
the 4.0% coal to meet a specification of 5.0 Ib  SO-/MM Btu,

                                17

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the following cost results  (assuming equal coal pithead cost,
Btu value, ash content, etc.):

                       % Sulfur     HHV     Incr. Distances; Miles

      High Sulfur Coal      4.0    10,000               0
      Low Sulfur Coal       0.9    10,000            1,000

      Weight fraction of high sulfur coal = 0.516
      Weight fraction of low sulfur coal  = 0.484
      Unit train freight rate = $0.005/T-mile

Incremental cost = 0.484 (1000) (0.005)  (100) = 12.lt/MM Btu
to power plant              20 MM

Therefore, it can be seen that the choice between coal cleaning and
blending low sulfur coals is a close one.  It depends primarily
on the following factors:

     - Actual incremental distance the low sulfur coal must be
       transported and the  freight rate

     - Pithead costs of the low vs. the high sulfur coal

     - Actual ash, -moisture, Btu, and sulfur contents of the
       two coals

     - Degree of sulfur removal attained when cleaning the high
       sulfur coal

     - Rate at which new low sulfur coal supplies can be made
       available
                               18

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F.  Conclusions Regarding Stack Gas Scrubbing
    1.  Capital Investment
    •   The following table summarizes the approximate capital invest-
        ment required to install wet limestone scrubbing at the eight
        power plants in Iowa selected as potential candidates for
        scrubbing:

               Plant        MW      Capital Investment; $     $/KW
             Des Moines    325          24,300,000            74.60
             Maynard       107          16,200,000           151.10
             Muscatine     117          11,300,000            96.90
             Riverside     222          18,900,000            85.00
             Burlington    212          14,300,000            67.40
          N  KapP          237          15,900,000            67.00
             Prairie Creek 245          19,600,000            80.10
             Sutherland    157          17,000,000           108.30

             Total        1622         137,500,000            84.80 Average

        The above figures assume that a thickener and small pond are
        provided for sludge.  If a large pond  was installed at six of
        the eight plants where space may be available  (Des Moines,
        Muscatine, Burlington, Kapp, Prairie Creek and Sutherland),
        the investment cost would increase by about $7-12/kw depend-
        ing on sulfur content of the coal.

    •   Of the thirteen plants for which detailed capital cost estimates
        were prepared, five were dismissed from consideration due to
        their small size and hence burdensome costs (or due to space
        limitations).  These plants are Pella, Iowa State University,
        Fair, Dubuque, and Lansing.  The average cost for limestone
        scrubbing for these five plants is $171.10/kw or about double
        that for the other eight plants.   No estimate was prepared for
        the Sixth Street Station due to the unusually limited space
                                      19

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    at the site.

•   Estimates for the Wellman-Lord/Allied scrubbing system costs
    were made using the M. W. Kellogg computerized cost model  (3, pp.
    110-129).  They were made assuming the same degree of difficulty of
    retrofitting this process as would be encountered with the
    Wet Limestone process.  The capital estimates are shown below:

           Plant       MW     Capital Investment;$     $/KW
        Des Moines    325           36,400,000        112.00
        Maynard       107           18,400,000        172.50
        Muscatine     117           14,900,000        127.10
        Riverside     222           24,800,000        111.60
        Burlington    212           18,800,000         88.50
        Kapp          237           20,700,000         87.50
        Prairie Creek 245           23,300,000         94.90
        Sutherland    157           20.500,000        130.50

        Total        1622          177,800,000        109.60 Average

    The figures shown above indicate that in every case the Wellman-
    Lord/Allied process is more costly than the Wet Limestone  process
     (by an average value of about  $24-25/kw).  Wellman-Lord/Allied
    scrubbing systems also would not be feasible at the six plants
    previously ruled out for Wet Limestone scrubbing for the same
    reasons.

 2.  Capital and Operating Cost

 •   Computerized cost models also  were used  to calculate capital
    and operating costs for both the Wet Limestone process  (3,  pp.
    83-98) and the Wellman-Lord/Allied process.  The basic input data
    for the programs are listed below:

                HR = 11,000 Btu/KWH  (Plant average heat rate)
                HHV= 10,000 Btu/lb  (Coal higher heating value)

                                   20

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           RBmax     =1.7  (.Retrofit difficulty factors selected
           RBase     =3.5  to best match detailed cost estimates)
           P         =1.52 (Location factor)
           LF        =0.70 (Load factor)
           CSL       = $1.50/T (Wet Limestone process sludge
                                disposal cost)
The average capital investment predicted by the model for the
two processes (for the eight plants in Iowa) is as follows:

           Wet Limestone             $  86.40/KW
           Wellman-Lord/Allied         109.80/KW

Operating costs for the two processes are shown below:

                	$/MM Btu Input

Plant Gen:
 Cap: MW
2%
W. L
34.3
32.7
Sulfur
. W-L/A
37.2
33.5
4% Sulfur
W.L. W-L/A
40.5 49.2
38.9 45.3
6% Sulfur
W.L. W-L/A
46.8 61.3
45.0 57.2
   250
   500

Based on the assumptions made, the Wet Limestone process is
less expensive to operate than the Wellman-Lord/Allied process
in all cases.

When processing flue gas from boilers burning very low sulfur
coal  (1-2 % S), the processes are about equal in
cost.

As expected, as plant size increases, the operating cost in
C/MM Btu decreases.

The Wellman-Lord/Allied process is more sensitive to the sulfur
content in the coal than is the Wet Limestone process.  For a
250 mw power plant, the increased operating cost for each 1%
sulfur increase is shown below:
                               21

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             Wet Limestone               3.12C/MM  Btu
             Wellman-Lord/Allied         6.02C/MM  Btu

 The sludge  disposal  cost  for  the Wet  Limestone process which
 will bring  its operating  cost up to a figure  equal  to that
 of the Wellman-Lord/Allied process is variable and  depends
 on the sulfur content of  the  coal.  For  a  500 mw  plant burning
 low sulfur  coal  (^ 2.5% S) this cost  is  about $2.44/ton of wet
 sludge.  For the same size plant burning high sulfur coal
 (^5.% S), this cost  is about  $3.44/ton.

 The higher  operating costs for the Wellman-Lord/Allied process
 (using high sulfur coals) can be explained solely by capital
 charges  on  a considerably greater investment.  There is much
 more equipment associated with this process due to  its complexity.
'The somewhat higher variable costs for chemicals, utilities, and
principally waste disposal for the Wet Limestone process are off-
set by lower labor charges.

For the Wet Limestone process, economics indicate that if sludge
disposal costs rise above about $1.50/T, then the installation of
a large pond would be indicated in order to limit disposal costs.

Sludge disposal for the Wet Limestone process presents a major
problem.  The sludge is composed mainly of CaS04»2H20, CaSO_»1/2H_O,
unreacted CaCC>3/ and fly ash.  The quantity produced  (at 40% so-
lids) is about 15 tons per ton of sulfur removed from the flue gas
(4, p. 7).  The size of a pond to hold 20 years of sludge produc-
tion is quite large.  For example, a 250 mw power plant burning
5.0% sulfur coal would require a sludge pond 120 acres in area
x 50 feet deep (4, p. 79).
Solids disposal does not present as great a problem for the Well-
man-Lord/Allied process.  Sulfur produced is assumed to have a
                              22

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    credit (of $10/LT).   This may be an oversimplification if the
    sulfur supply-demand situation is studied.  In 1985, the North
    American demand for sulfur will probably reach about 17.5 MM
    tons while the supply from traditional sources (Frasch process,
    gas and oil desulfurization, and smelter acid) will be about
    22 MM tons.  Therefore it is obvious that the supply from existing
    sources is more than adequate to meet the demand  from traditional
    sulfur consuming industries in 1985.  If  (by 1985) the utility
    industry was consuming 500 MM tons/year of coal containing 3%
    sulfur then an additional 15 MM tons/year of sulfur would be po-
    tentially available.  Clearly this would tend to lead to a con-
    siderable oversupply of sulfur.  However there are some potential
    new uses for sulfur which may help to alleviate the problem.  Some
    of these are (17, pp. 239-243):

    - Addition of sulfur to asphalt for use as a paving material
    - Sulfur use in concrete
    - Sulfur use as a bonding material
    - Sulfur use as a coating material

    A small quantity of purge solids also is formed in the Wellman-
    Lord/Allied process.  These solids  (consisting mostly of sodium
    sulfate and sodium thiosulfate) are. produced at the rate of about
    0.30 tons/ton of sulfur removed from the flue gas  (3, p. 121).

3.  Stack Gas Scrubbing Evaluated in the Linear Program

•   Since the Wet Limestone process appears to be less costly then
    the Wellman-Lord/Allied process, its operating costs were incor-
    porated into the linear computer program.  Two segments of the
    Wet Limestone process operating cost were input into the program:

    - The first is dependent on plant size

    - The second is dependent on sulfur content of the coal
                                   23

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The linear program could be modified to accommodate operating
costs for any other scrubbing process.

As discussed previously, stack gas scrubbing does not compare
favorably (in Iowa) with the use of low sulfur coal and/or coal
cleaning.

- At the 1.2 Ib S02/MM Btu specification, no stack gas scrubbing
  is used if unlimited low sulfur coal is available.  If low sul-
  fur coal is limited, stack gas scrubbing is used in eight
  plants.

- At the intermediate specifications  (3.1 and 5.0 Ib S02/MM Btu),
  no stack gas scrubbing is used.  Emission standards are met by
  using low sulfur coal and/or coal cleaning.
                              24

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G.  Conclusions Pertaining to the Use of Western Coals In .Existing
    Boilers

    1.  General

     •  The conclusions reached in this study point to the use
        of about 33 to 94%iwestern coals in Iowa boilers to meet
        varying S02 emission regulations.  The use of these western
        coals in boilers and in pollution control devices  (electro-
        static precipitators) designed for indigenous and midwestern
        coals may pose operational problems which will have to be
        dealt with on an individual case basis.  Of primary im-
        portance are ash characteristics which determine the degree
        of slagging and fouling which will occur in the boiler,
        the bulk resistivity of fly ash passing through existing
        electrostatic precipitator installations, and the abrasive-
        ness of the coal.

    2.  Average Properties of Western Sub-bituminous Coals

     •  The following table gives the range of properties of the
        western sub-bituminous coals used in this study.

                   % Moisture                    12.4 - 25.5
                   % Ash                          4.2 - 10.0
                   % Sulfur                       0.3 -  0.9
                   HHV (Btu/lb)                   8790 - 11,460
                   Grindability (Hardgrove)         45-53

     •  In general, the western sub-bituminous coals are  low
        in sulfur (below 1%); they are relatively high in
        moisture and,  therefore,  relatively low in heating value;
        they are high in volatile matter and have good ignition
        characteristics.
                                 25

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    Of main concern to the boiler designers however, are the
    ash characteristics.  In this respect western coals run the
    full spectrum.

3.   Ash Slagging

 •  Ash slagging refers to the ash deposits that form on
    surfaces in the furnace exposed to radiant heat (10, p.
    2).  The ash fusion temperature of a given coal provides a
    rough indication of the potential furnace wall slagging
    problems which may occur.  Generally boilers which use coals
    with high ash fusion temperatures will remain dry with little
    or no deposit on the furnace wall.  Slagging is usually
    meant to be the physical transport of molten or sticky
    ash particles and the subsequent formation of dense hard
    deposits on the radiant tubes  (11, p. 3).  Most coals
    have low to intermediate ash fusion temperatures; hence
    boiler designers must rely largely on slag viscosity
    characteristics of  lignite type ash to predict slagging
    tsndencies in boilers  (18, p.  9).  Coals with low ash
    viscosity characteristics tend to cause  excessive slagging
    (18, p. 3).  If the information is available, the viscosity
    of the coal ash slag is used as a guide in furnace design
    of a steam generator.  When the viscosity of the  ash is
    not known, however, it has been necessary to derive
    slagging indices based on ash  analysis and furnace
    observation.  One such slagging index  (Rg) has been de-
    veloped which divides  the slagging characteristics of  coal
    into  four different categories as  shown below  (11, p.  11).
                                                   1^
            Slagging Type           Slagging Index; S
            Low                     Less than 0.6
            Medium                  0.6  -  2.0
            High                    2.0  -  2.6
            Severe                  Greater than 2.6
                              26

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    Based on the relative slagging index the furnace design
    may be modified to consider such items as burner input
    vs.  furnace size, burner clearances, furnace exit gas
    temperatures, and the number and location of furnace
    wall blowers for the most effective removal of slag
    (11, pp. 11-12).

4.  Ash Fouling

 •  Ash Fouling refers to bonded deposits that form at
    high temperatures on convection tube banks, especially
    the superheater and reheater which are not exposed to
    direct radiant heat from the furnace  (11, p. 2).  The
    high temperature bonded deposits are generally caused
    by volatilization of elements from the ash and selective
    condensation and deposition upon the convection tube
    surfaces as well as by impaction of ash on the tubes.
    The amount of ash in the coal frequently has little
    influence on ash fouling.  More important is the behavior
    of the ash minerals when they are subjected to high tem-
    peratures during combustion of the coal  (11, p. 4).

 •  The first constituents identified as contributing to
    deposit strength are the alkali metals, sodium and potas-
    sium  (10, p. 2).  Generally the sodium oxide and calcium
    sulfate content of the ash is used to predict fouling
    tendencies in the convection passes  (18, p. 6).

 •  A  fouling index R^ has been devised dividing coal into
    four categories  (11, p. 12).

          Fouling Type                      Fouling Index ;^
          Low                               Less than 0.2
          Medium                            0.2 - 0.5
          High                              0.5 - 1.0
          Severe                            Greater than 1.0
                              27

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 9  Some of the boiler design parameters which may be changed
    to mitigate the relative fouling tendency of the coal are
    the flue gas temperature, back-spacing and side-spacing of
    tubes, slope of superheater and reheater floor and
    clearances under pendant sections, number and location of
    soot blowers, cleaning radius of soot blowers, and tube
    bank depths.  For example, if it is expected that the coal
    to be fired will produce hard massive deposits (Rp=
    1.0 or higher) the pendant superheater sections are de-
    signed to permit easy deposit removal. Lateral tube spacing
    is increased, tube bank depth is decreased, and the banks
    are located in cooler gas temperature zones.  A greater
    number of high capacity soot blowers will be required
    (11, p. 13).

5.  Relative Abrasiveness of Sub-bituminuous Coal

 •  An important characteristic of a coal is its relative
    abrasiveness.  This property may affect the life of
    grinding equipment (pulverizers) by a factor of 5-10
    to 1.  Abrasiveness is a separate characteristic of coal
    apart from the grindability.  The abrasiveness of a coal
    depends largely upon the amount of quartz or other hard
    materials associated with the impurities, while grind-
    ability is determined primarily by the structure of the
    organic materials.  In abrasiveness also, the western
    sub-bituminuous coals run the full spectrum from high to
    low  (18, p. 3).

6.  Electrostatic Precipitator Performance

 •  Ironically the low sulfur content of western coals which
    makes them so attractive may cause problems with particulate
    collection in the electrostatic precipitators.  Two of
    the important para-meters in determining the efficiency
                              28

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of an electrostatic precipitator are the residence time and the
resistivity of the fly ash.  Performance drops off with increased
resistivity (due to lower sulfur content) and with decreased
residence time.

One approach used to improve efficiency is to make the electro-
static precipitators larger, hence decreasing the velocity
which will compensate for the change in resistivity.  This
approach is expensive, however, because the electrostatic
precipitators must be increased in size.  It would be very
impractical for existing units which are already in service.

A second approach used is to locate the electrostatic precipitator
in the hot gas zone upstream of the air preheater (where the
resistivity of the fly ash is lower) thereby regaining the fly
ash removal efficiency.  Using this technigue means treating a
greater gas volume and makes the electrostatic precipitators
larger and more expensive (10, p. 3).  This approach is also
impractical for existing cold side units.

The third approach used to restore electrostatic precipitator
efficiency is the conditioning of the flue gas with a small
quantity (15-20 ppm)  of S03 to lower the resistivity of the
fly ash.  When sulfur content in the coal is low the resistivity
of the fly ash particles is high (at normal air heater outlet
temperatures)  and it is difficult for them to accept a charge
and be attracted to a plate in the electrostatic precipitator.
Conditioning the gas produces a lower resistivity of the fly
ash particles and restores the electrostatic precipitator effi-
ciency  (13, pp. 50-53).  This is the recommended approach for
the Iowa power plants when burning low sulfur western coal.
                             29

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                  IIL  OVERALL SYSTEM EVALUATION

The State of Iowa currently has some 35 power plants which burn
coal with a total installed generating capacity of 3093 mw.
Though many of the boilers in these plants have previously burned
some natural gas and fuel oil, the assumption was made for this
study that the energy requirement for each plant will be met ex-
clusively with coal.  Indeed, the projected use of coal in 1975
will total 79.1% of the state's utility fuel requirement and in
1980 will total 89.0% (1, p. 326).

Coal used in Iowa utilities comes from a number of states  (Iowa,
Illinois, Kentucky, Kansas, Oklahoma, Wyoming, and others).
There are many mines in each state which can supply coal.  In
addition, there are many different methods (and different costs)
of transporting the coal from the mines to the power plants
(truck, rail, unit train and barge or some combination of these).
Also, the coal may travel over different routes.  The purchased
price of each coal varies as does its properties (% ash, % sulfur,
HHV, and % moisture).  The cleaned properties of each coal also
vary.

When coal is burned in utility power plants, the sulfur originally
in the coal  (whether present as pyritic sulfur, organic sulfur, or
sulfate) is converted to S02 and S03  (100% conversion to S02 was
assumed in this study)  which then flows out of the stack in the
flue gas.  A number of different maximum emission levels of SO?
(Ib S02/MM Btu input) are being considered.  The least stringent
regulation, of course,  would be no control and the most stringent
regulation would be the Federal new-source regulation of 1.2 Ib
SO7/MM Btu.  There are also some intermediate regulations being
considered.
                                 30

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How does a utility control the amount of S02 being emitted to meet
a given regulation?  Three methods or some combination of them were
chosen in this study:

                  - the use of low sulfur coal
                  - coal cleaning
                  - stack gas scrubbing
To further compound the problem, the number, size and locations of
the cleaning plants and scrubbing systems can vary.

To evaluate a system of such complexity, M. W. Kellogg devised a
linear computer program.  The program minimizes the overall system
cost while delivering the required amount  of coal to each power
plant and while meeting any one of a number of different SO- emission
speci fications.

A.  Basic Assumptions Made for the System to Use in the Linear
    Computer Program
    1.  Power Plants Considered
        In order to limit the size of the problem, it was necessary
        to limit the number of power plants considered in this
        study.  A total of eighteen power plants having an installed
        generating capacity of 2737 mw (88.5% of the total) was
        used.  The following table lists these power plants, their
        generating capacity, and their energy requirements in
        MM Btu/D.
  Location Code*
  Class PL      	Plant Location	         MW       MM Btu/D**
   DA          Ames (Ames Municipal Plant)         60        18,684
   DB          Ames (Iowa State University)       25        12,994
   DC          Montpelier                         63        17,726
   DD          Lansing                            64        20,023
   DE          Dubuque                            74        24,504
   DF          Clinton                           237        59,525
   DG          Cedar Rapids (Prairie Creek)      245        64,862
   DH          Cedar Rapids (6th Street)           92        64,937
   DI          Marshalltown                      157        43,219

* Refer to Section VII of this report

                                 31

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 Class PL        	Plant Location        MW     MM Btu/D**
    DJ           Bettendorf                  222      67,512
    DK           Council Bluffs              131      33,461
    DL           Des Moines                  325      87,017
    DM           Waterloo                    107      31,570
    DN           Salix                       491     115,682
    DO           Eddyville                    71      25,608
    DP           Burlington                  212      51,307
    DQ           Muscatine                   117      31,488
    DR           Pella                        44      18,259
Total                                       2737     788,378

** @ 100% generating capacity (a 65-70% load factor for these
plants would more nearly approximate the actual Iowa coal requirement)
*** Included because of high heat rate due to exporting heating steam
       Generally speaking, power plants with a generating capacity
       of about 40 mw or less were eliminated from consideration
       in this study.  Some seventeen plants comprising about half
       of the total number of plants in the state but only about
       11.5% of the generating capacity were thus eliminated.  Con-
       clusions reached in the study however (which include coal
       cleaning or low sulfur coal blending), may be extended to
       include the small power plants.

   2.  Coal Mine Selection
       The following tables list the eight coal mines which were
       selected for this study.   The tables also list the mined coal
       properties,  costs, mine capacities, and clean coal properties.
Raw Coal
Location
Class ML
MA
MB
MC
MD
ME
MF
MG
MH
Code
Location
Frederick, Iowa
Leon , Iowa
Ogden , Iowa
Marion, 111.
Madison vi lie , Ky .
Hanna , Wy .
Craig, Col.
Colstrip, Mont.
% Ash
14.2
12.8
13.2
14.9
14.8
8.4
4.2
10.0
Properties
% Sulfur
5.9
4.3
6.9
3.1
4.1
0.9
0.3
0.8
Btu/lb
10,038
9,676
10,184
11,951
11,801
10,506
11,460
8,790
Cost:
$/T
6.25
6.25
6.25
6.70
6.70
4.20
5.00
3.60
Mine
Capacity
MT/D

<
»
H
M
cn

                                32

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               Cleaned Coal Properties*
Location Code
Class ML .
MA
MB
MC
MD
ME
% Ash
7.9
7.0
7.5
7.0
7.2
% Sulfur
3.5
1.9
4.5
2.0
2.7
Btu/lb
11,033
10,650
11,166
12,505
12,340
Loss : %
20.0
20.0
20.0
20.0
20.0
Selection of the coal mines to provide coal for the Iowa
Utility Industry was based primarily on the report submitted
by the Gates Engineering Company (2, pp. 7-9).  Ten potential
mines were presented in the report for the State of Iowa.
From this group three were selected as being representative
of the Iowa coal supply (2, p. 14).  For the State of Illinois
the average properties of the No. 5 and No. 6 seams from
Marion, Illinois were used in the study (2, p. 8).

The Kentucky coal used in the study is from Madisonville,
Kentucky.  The average properties of the No. 6, No. 9, No. 11,
and No. 12 seams from Madisonville were used  (2, p. 8).  A
number of potential mine sites were given in the Gates report,
Appendix C, in Wyoming, Colorado, and Montana.  From  this list
one mine site considered to be representative was selected for
each state.  The three choices were Hanna, Wyoming; Craig,
Colorado; and Colstrip, Montana.

The coal prices  (FOB mine) also were furnished in the Gates
report.  In Iowa, Illinois, and Kentucky the coal was assumed
to be 40% strip mined and 60% deep mined.  The western coals
were considered to be 100% strip mined.  Each ton of  strip
mined coal has a 70* transfer charge added to transport  the
coal from the mine to the rail site.  Coal prices are given
in the Gates report  (2, p. 1).

Coal properties which can be  achieved by a coal  cleaning
plant with  80 weight % recovery.
                          33

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     The following calculations show how the coal pithead costs
     were computed.

          %  strip mined (strip mine cost)  + % deep mined (deep mine
          cost)  + % strip mined (strip mine transfer charge)  = total

     Iowa Coal
          0.4 (4.85)  + 0.6 (6.70)  + 0.4 (0.70.  = $6.24    (Use $6.25/T)

     Illinois Coal & Western Kentucky Coal
          0.4 (5.25)  + 0.6 (7.20)  + 0.4 (0.70)  = $6.70/T

     Wyoming Coal
          3.50 + 0.70                          = $4.20/T

     Colorado Coal
          (3.90 + 4.70) = 4.30   4.30+0.70   = $5.00/T
                2
     Montana Coal
          8790 (3.50) = 2.93     2.93 + 0.70   = $3.63/T  (Use $3.60/T)
         10506
     It was  assumed that the five high sulfur coals used in the
     study could all be cleaned to the 80% recovery level.  This re-
     covery  level is shown to be about optimum from the Gates report
     (2, pp. 14-16) for the Iowa coals.  The same recovery level of
     80% also was chosen for the Illinois and Kentucky coals.  Note
     that no cleaning was permitted for the western coals since these
     fuels are already very low in sulfur content and fairly low in
     ash content.
3.    Potential Other Possible Transfer Points (in addition to the mines
     and power plants)

     The following is a list of other possible transfer points:
              Class OL
                 PA                  Paducah, Kentucky
                 PB                  Gorham, Illinois
                                   34

-------
    Paducah, Kentucky is located on the Ohio River, 85 miles
    by rail from Madisonville, Kentucky.  A logical method of
    shipment would be by standard rail from Madisonville to
    Paducah and then by barge on the Ohio and Mississippi
    Rivers to the power plants.  Gorham, Illinois was chosen
    as a possible transfer point because it is the closest
    point on the river from the Marion, Illinois mine.  Again
    a logics1 shipping method would be to ship coal by standard
    rail from Marion, Illinois to Gorham and then by barge on
    the Mississippi River to the Iowa power plants.

4.  Potential Scrubbing Locations

    The following plants were chosen as potential sites for
    scrubbing facilities:

        Class SL            Plant Location
           DF        Clinton
           DG        Cedar Rapids (Prairie Creek)
           DI        MarshalItown
           DJ        Bettendorf
           DL        Des Moines
           DM        Waterloo
           DP        Burlington
           DQ        Muscatine

    Ten of the eighteen power plants used in the study were
    not considered for stack gas scrubbing due to either the
    small generating capacity of the plant, overcrowded
    conditions existing at the plant, or previous committments
    for low sulfur fuel by the plant.

5.  Potential Cleaning Locations

    The following is a list o'f possible coal cleaning plant
    locations chosen in the Iowa study:
                             35

-------
             Class CL          Location
                DN         Salix, Iowa
                DP         Burlington, Iowa
                MA         Frederick, Iowa
                MB         Leon, Iowa
                MC         Ogden, Iowa
                MD         Marion, Illinois
                PA         Paducah, Kentucky
                PB         .Gorham, Illinois

    It was necessary to reduce the number of possible cleaning
    locations in order to greatly minimize the number of
    calculations to be performed by the computer.   The logical
    cleaning plant locations are at the mines since there is
    a 20% material loss at the cleaning plant resulting in
    considerably lower freight rates from the mines to the
    power plants.  Four other possible cleaning locations (DN,
    DP, PA, and PB) were also selected.

6.  Summary of Loading/Unloading Facilities

    All power plants, mines and the two other locations were
    assumed to have standard railroad facilities.   In addition,
    unit train facilities were assumed to be present at DN,
    DP, MD, ME, MF, MG, and MH.  Barge loading/unloading
    facilities were assumed to be present at the seven Iowa
    power plants located on the Mississippi River (DC, DD, DE,
    OF, DJ, DP, and DQ).  Also, barge loading facilities were
    assumed to be present at PA and PB.

7.  Specifications

    The following list includes the four specifications that
    the program was run for:
                             36

-------
                  Table Specification

                  1   20.0   Ib SO2/MM Btu (No emission control)
                  2    5.0   Ib S02/MM Btu
                  3    3.1   Ib S02/MM Btu
                  4    1.2   Ib S02/MM Btu

    Note that the model can be easily adjusted to run any other
    specification as long as it is uniform statewide or systemwide.

8.  Summary of Economic Factors

                                        Rate         Basis
    Standard Rail                   $0.0'28/T-M Iowa Util.  Avg.  Rate
    Unit Train                      $0.005/T-M (1,  p.  435)*
    Barge                           $0.006/T-M (2,  p.  21)
    Ash Disposal at Pwr.  Plant      $1.00/T    Iowa Utilities
    Refuse Disposal at Clng.  Plant  $0.31/T    (2,  p.  21)
    Storage/Transfer Cost           $0.30/T    (2,  p.  21)**
    Cleaning Plant Oper.  Cost       $1.90/T    (2,  p.  13)***
    *Supplemented by information from Union Pacific Railroad
   **Applies to any coal  shipment which goes through an inter-
     mediate point (either a  transfer point or a cleaning plant)
  ***Adjusted to include  profit, depreciation, and interest.
9.  Distances by Rail

    The distances between all points are tabulated in the
    Table RRDIST which forms a symmetric matrix half of which
    is entered as a triangular table.  The 1973 Railroad Atlas
    was used to compute the minimum distances between all
    points (8).  In many cases, calculating the minimum distance
    between two points meant transferring from railroad tracks
    owned by one railroad company to tracks owned by another
    company.  This operation was assumed to present no problem
    for the study.
                             37

-------
  10.  Distances by River

       A separate table (Table RIVERD) was supplied to give the
       river mileages between all points located on the Mississippi
       and Ohio rivers.  This table is to be used in calculating
       barge transportation costs.  The points included in this
       table are power plants DC, DD, DE, DF, DJ, DP, and DQ and
       other locations, PA, and PB.

  11.  Cost of Washing and Scrubbing

       As indicated above, the coal cleaning plant operating cost
       used  in  this  study  is  $1.90/ton of feed coal.   The  minimum
       cleaning plant size used is one capable of processing
       7200 t/d of feed coal.  The cost of stack gas scrubbing
       (using the Wet Limestone process) is made up of two parts.
       The first is the non-linear cost which is related to plant
       size; the second is the linear cost related to the sulfur
       content in the feed coal.  These costs are broken down
       more fully in Sections VI and VII.  The minimum size
       scrubbing facility considered is one which would be
       applicable for a 50 mw boiler.

B.  Linear Computer Program Results

       The following tables summarize the results for the three
       cases studied for Iowa. The following items are shown in
       the tables for each of the sulfur dioxide emission levels
       (20,  5, 3.1, and 1.2 Ib/MM Btu):

       -  All of the components which comprises the totel system
         cost (coal pithead  cost, freight cost, ash disposal
         cost,  scrubbing cost, coal washing cost, refuse dis-
         posal cost, and coal storage/transfer cost).

       -  The incremental system cost over no sulfur dioxide

                                 38

-------
     control

    The quantity of coal used from each mine

    The numbar of stack gas scrubbing systems used.

    The number of coal cleaning plants used

Following the tables is Figure 1 which is a plot of the in-
cremental system cost in C/MM Btu vs. the sulfur dioxide
emission level in lb/MM Btu.
                             39

-------
                                              Table 1
                                              CASE  1
 8 Possible Scrubbing Locations
 8 Possible Cleaning Locations
 System Cost ;  $/D


 TFRT
 TASH
 TSC1
 TSC2
 TWSH
 TREF
 TSTO

 Cost Total

 A Cost Over Spec 20  :  $/D

 A Cost Over Spec 20  :  C/MM

 Coal Source ;  T/D

 MA
 MB
 MC
 MD
 MB
 MF
 MG
 MH

 Total

 Scrubbing Systems

 Cleaning Plants : T/D

IOWA STUDY
788,400 MM BtU/D
ons Unlimited Western Coal
ms Unlimited Illinois Coal
Spec : Ib SO2/MM Btu
20
219,517
90,935
4,774
3,249
318,475
Btu -
8,650.4
9,499.4
11,383.4
7,098.0
36,631.2
None
None
5
205,165
141,749
4,198
7,071
358,183
39,708
5.04
508.4
2,406.4
534.4
19,741.5
7,683.5
3,813.7
34,687.9
None
None
3.1*
185,502
188,100
3,301
7f672
384,575
66,100
8.38
292.6
1,385.0
307.6
9,978.6
13,605.7
9,818.6
35,388.1
None
None
1.2
171,510
232,085
2,129
8,120
413,844
95,369
12.10
76.8
363.6
80.8
1,622.3
10,193.0
22,914.6
35,251.1
None
None
 •DK, DN Below Specification
** Refer to  pages  240-241

-------


Table 2
CASE 2

IOWA STUDY

8 Possible Scrubbing Locations
8 Possible Cleaning Locations


System Cost : $/D

Limit = 16,
Unlimited
Spec :
20

TPIT 219,517
TFRT
TASK
TSCI
TSC2
TWSH
TREF
TSTO
90,935
4,774
_
-
-
_
3,249
Cost Total 318,475
A Cost Over Spec 20
A Cost Over Spec 20 : C/MM Btu
Coal Source : T/D
MA
MB
MC 9
MD 11
ME
MF 7
MG
MH
Total 36
Scrubbing Systems
Cleaning Plants : T/D
-
-

8650.4
-
,499.4
,383.4
—
,098.0
-
—
,631.2
None
None

000 T/D Western Coal
Illinois Coal
Ib SO,/MM Btu
5

205,165
141,749
4,198
_
-
-
—
7,071
358,183
39,708
5.04

508.4
2406.4
534.4
19,741.5
—
7683.5
3813.7
~
34,687.9
None
None
788,400 MM
(8,000 T/D


3.1

207,110
160,788
3,356
-
-
14,230
464
8,660
394,608
76,133
9.66

_
7489.5
-
12,940.4
—
8000.0
8000.0
~
36,429.9
None
CC1MB = 7489


Btu/D
Hanna, 8,000 T/l


1.2

199,517
159,133
3,762
116,356
39,327
—
—
7,017
525,112
206,637
26.21

_
4171.0
—
14,902.7
~
8000.0
8000.0
" ~
35,073.7
All 8 plant:
None

-------
                                                    Table   3
                                                    CASE 3
      8 Possible Scrubbing Locations
      8 Possible Cleaning Locations
      System Cost  ; $/P

      TPIT
      TFRT
      TASH
      TSC1
      TSC2
      TWSH
      TREF
      TSTO
to     Cost Total
      A Cost Over Spec 20  :  $/D
      A Cost Over Spec 20  :  C/MM Btu  1.03

      Coal Source i T/D

      MA
      MB
      MC
      MD
      ME
      MF
      MG
      MH

      Total

      Scrubbing Systems

      Cleaning Plants :  T/D
ns
s Limit -
Limit"

20
220,504
99,144
4,784
2,163
326,595
8,120
itu 1.03
11,258.4
11,142.2
7000.0
8000.0
37,400.6
None
None
IOWA STUDY
16,000 T/D Western Coal
7,000 T/D Illinois Coal
Spec :lb SO,/MM Btu
111 5
211,067
146,210
3,471
13,680
446
6,808
381,682
63,207
8.02
5404.1
7200.0
1886.6
7006.0
8000.0
8000.0
37,490.7
None
CC1MB = 7200
788,400 MM BtU/D
(8,000 T/D Hanna, 8,000 T/D C:
(7,000 T/D Marion)

3.1
217,964
156,680
3,019
27,357
893
9,064
414,977
96,502
12.24
338.1
14,398.4
857.8
7000.0
8000.0
8000.0
38,594.3
None
CC1MB • 14,398


1.2
211,340
148,898
3,489
113,448
45,565
13,680
446
6,968
543,834
225,359
28.58
6885.0
7649.4
7000.0
8000.0
8000.0
37,534.4
All 8 plan
CC1MB = 721

-------
                                                     Figure 1

                              INCREMENTAL SYSTEM COST VS. SO2 EMISSION SPECIFICATION
   30
D
m  20

1
UJ

01
OC
O
    10
CASE 1
                                                                                              8
                                     EMISSION SPECIFICATION:  LB SO2/MM BTU

-------
                   IV PROCESS DESCRIPTIONS


A.  Flue Gas Scrubbing Processes

    1.  Wet Limestone System  (Refer to Appendix B)

        a.  General

            This task specified that two types of stack gas
            scrubbing processes for S0~ removal be evaluated:

                      - a throw away system
                      - a regenerable system

            The throw away process selected for S0_ removal is
            the Wet Limestone process.  The process design for the
            Wet Limestone system is based on the design proposed
            by the Tennessee Valley Authority for their Widow's
            Creek Unit 8 SO- removal process.  This design was
            used because it incorporates up-to-date technology
            regarding wet limestone scrubbing.  However some minor
            departures from the TVA design were taken in both the
            limestone handling system and the scrubbing system.
                                                 i
        b.  Limestone Handling, Grinding and the Effluent System

            This system is designed for receiving limestone by
            both rail and truck from the limestone quarries.
            Limestone is unloaded into a 100 ton hopper, 101-F,
            located in a concrete pit below grade.  The hopper
            is sized to accomodate unloading of railroad cars
            as well as trucks.  The limestone is transferred
            from the hopper via a feeder, 101-V, to the tunnel
            belt conveyor, 102-V, which transfers the limestone
                                44

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to either the stacker, 103-V, feeding the dead
storage pile or to the plant conveyor, 104-V, which
feeds the live storage silos via the tripper belt,
105-V.

The limestone system for each plant is designed for
running the power plant at peak capacity using coal
containing the maximum sulfur content (highest
monthly average for 1972) .  Limestone flow rate is
based on 150% of the stoichiometric quantity re-
quired.  Design capacity for the feeder, conveyors,
stacker and tripper is five times the maximum lime-
stone consumption rate to allow for receiving lime-
stone in a 40 hour week while the plant operates
continually.  A limestone dead storage pile is sized
for 30 days usage (in the event of an interruption
in the supply of limestone) and the live storage silos,
102-F, are sized to hold 3 days supply  (to allow
the plant to operate over a 3 day weekend without
receiving limestone).  The live storage silos and
ball mills are located in  an enclosed building,
101-K, to preclude weather and fugitive dust
problems.

Limestone is fed from the  live storage silos to the
wet ball mills, 101-L, where it is ground in closed
circuit from the purchased size  (3/4" x 0") to the
final size  (90% minus 200 mesh).  The slurry from
the ball mills (about 65%  solids) is fed to the
cyclone classifiers.  Underflow from the classi-
fiers containing oversized particles is recycled to
the ball mills for regrinding.

Overflow from the cyclone classifiers flows to a
                     45

-------
mill slurry sump where sufficient water is added to
reduce the solids concentration to 40%.  Mill sump
pumps are used to transfer the 40% limestone slurry
to the limestone slurry surge tank, 103-F.

Three 33% capacity ball mills are used in each plant
(based on the maximum limestone flow) allowing two
mills to handle the normal limestone requirement.
The limestone slurry surge tank is a carbon steel
rubber-lined vessel with an agitator.  It has a
capacity corresponding to 4 hours storage (at maxi-
mum limestone flow), allowing the scrubbing trains to
continue operating while maintenance is being done in
the grinding area.

Limestone is fed to the scrubbing trains by rubber-
lined centrifugal limestone slurry feed pumps, 101-J.
One pump is used for each individual scrubbing train
with a spare provided for each three operating pumps.

Effluent slurry containing about 15% solids flows
from the venturi scrubber circulating tanks to the
effluent slurry surge tank, 104-F, which is a
rubber-lined carbon steel vessel with  an agitator.
It is sized for 5 minutes storage capacity.  Rubber-
lined centrifugal pumps, 104-J, send the slurry
to a thickener, 102-L, which concentrates the solids
                                  i
to about 40%.  Recycle water pumps, 103-J, return
overflow water from the thickener to the scrubbing
trains and the ball mills.  Net make-up process
water requirements comprise that which is evaporated
into the gas while cooling it in the venturi scrubber
and that which is  lost in the sludge.  This water
is supplied by the raw water pumps, 102-J.
                     46

-------
    Sludge is sent from the thickener to a relatively
    small lined holding pond.  The ponds are sized to
    hold about 2 weeks production of sludge.  The solids
    portion of the sludge consists mainly of hydrates of
    calcium sulfite and calcium sulfate, unreacted lime-
    stone, and fly ash.  Net sludge produced will have
    to be removed from the plant site via truck, rail,
    or barge.

    Alternatively the thickener can be eliminated and a
    large settling pond used.  However, lack of land pre-
    cludes using this disposal method in most cases.  For
    example, a 500 MW plant burning 5% sulfur coal would
    require a 241 acre by 50 feet deep pond to hold 20-
    years production of sludge.

    Wash water is pumped from a settling pond (fly ash
    pond) to the entrainment separators by the wash water
                                         2
    pumps, 106-J, at the rate of 1 gpm/ft  of CSA.  En-
    trainment separator pumps, 105-J, return this water
    to the pond.

c.  Scrubbing System

    Flue gas leaves the electrostatic precipitators of the
    power plant boilers at essentially atmospheric pressure
                                     o
    and at a temperature of about 300 F  (ranges from
             o
    250 - 350 F).  It has a fly ash loading of about 2-5
    grains per actual cubic foot (gr/acf) entering the
    precipitators.  The fly ash loading leaving the pre-
    cipitators will be about 0.4-1.0 gr/acf (wet) assuming an
    efficiency of 80%.  The S02 content of the flue gas will
    range from about 1650 to 3300 ppm (wet) with coal having
    an initial sulfur content of 2.5-5.0%.

    Eight standard sized scrubbing trains were designed
                         47

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for use in this study.  The largest train  will treat
about 545,000 acfm  (hot gas) corresponding to about
167-182 mw.  This is currently the largest unit being
built by UOP.  The smallest train will treat about
91,000 acfm which corresponds to about 28-30 mw.  Each
scrubbing train consists of a fan, venturi scrubber,
venturi scrubber circulating tank and pumps, absorber,
                  u
absorber circulating tank and pumps, an entrainment
separator, and a reheater.

Flue gas from the existing electrostatic precipitators
enters the fan, 203-J, in a scrubbing train.  The fans
are double inlet centrifugal units equipped with
variable speed fluid drives.  Each fan is designed
for a pressure differential of 25" E^O and a flow
rate 10% above normals.  The fans supply the motive
power for the scrubbing system.

A venturi scrubber,  201-E, is used to cool, saturate,
and remove residual fly ash and some SO^ from the
flue gas.  The unit is designed for a pressure drop
of 10" H20 and a fly ash removal efficiency of about
99%.  S0_ removal in the venturi scrubber is expected
to be about 20-30%.   The venturi scrubber is con-
structed of 316 L stainless steel with an abrasion
resistant lining and has a rectangular throat with a
motor operated variable throat mechanism.  Velocity
in the throat is in the range of 200 fps.  Constant
speed rubber-lined centrifugal pumps, 201-J, are used
to pump slurry (15% solids) from the venturi scrubber
circulating tank, 201-F, to the venturi scrubber.
Two pumps are provided per train - one operating and
one spare - and are designed to supply liquid to the
venturi scrubbers at a rate of 16.1 gpm/mscfm of in-
let gas  (11 gpm/macfm hot gas).  The venturi scrubber
                       48

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circulation tanks are rubber-lined carbon steel
vessels provided with agitators, 201-L.  They are
designed for a retention time of 5 minutes  (85%
full) based on the venturi circulation rate.  This
design is similar to that used by Catalytic, Inc.
(15, pp. 23-24).

Saturated gas from the venturi scrubbers (at 125°F)
flows to the absorbers, 202-E.  These units are UOP*
Turbulent Contact Absorbers  (TCA's).  The absorbers
are rubber-lined carbon steel vessels with 316 SS in-
ternals containing 3 beds of hollow 1-1/2" diameter
thermoplastic spheres.  Each bed has a static ball
depth of 12" and the beds are spaced 4 feet apart.
The absorbers are designed for a superficial gas
velocity of 12.5 fps.   They are rectangular in cross
section with the largest unit being 15' x 40' and
the smallest being 15' x 6.67'.  Overall height of
the absorbers from the bottom of the hopper is 45'.
Expected SO2 removal efficiency in the absorber is
about 87% of the remaining SO~ in the gas from the
venturi giving an overall SO- removal efficiency of
90%.  Pressure drop through the absorber is expected
to be 7" H20.

Rubber-lined centrifugal pumps, 202-J, equipped with
variable speed fluid drives are provided to pump
slurry (containing 10% solids) from the absorber
circulating tank, 202-F, to the absorber.  Three
pumps are provided per scrubbing train - two oper-
ating and one spare.  The pumps are designed to supply
slurry to the absorbers at a rate of 64.5 gpm/mscfm
of inlet gas to the venturi.   This corresponds to
                                                  2
about 44.2 gpm/macfm of hot gas or about 40 gpm/ft  of
CSA.  Design of the unit is based on information from
TVA and UOP.
*UOP: Universal Oil Products Company (Air Correction Division)
                         49

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Gas from the entrainment separator is heated from 125 F
to 175°F in the reheater, 201-C, to desaturate and provide
buoyancy for the gas.  This unit is an indirect tubular ex-
changer utilizing saturated steam at 500 psig.  Estimated
pressure drop in the unit is 4" H20.  The first 30% of the
rows of tubes are constructed of Alloy 20 for corrosion re-
sistance to the gas which enters at its dew point.  The
remaining 70% of the rows are constructed of carbon steel.
A reheat AT of 50°F was chosen in this study because it is be-
lieved to be about the minimum acceptable value.  Note that
each 50°F increase of the flue gas temperature requires about
1.3% of the gross heat input into the plant.

Steam operated soot blowers are provided at locations
where solids deposition is expected to occur.  Soot blowers
are placed in the inlet duct to the venturi, 203-L, in the
elbow between the absorber and the entrainment separator,
204-L, and at the reheater, 205-L.

Gas leaving the reheater flows to the stack.  Positive
shut-off guillotine gates are provided at three locations -
the inlet to the fan, the exit from the reheater, and a
by-pass connecting the inlet and outlet ducts.  These gates
will make maintenance possible on one scrubbing train while
the remainder of the trains continue operating.

Fresh limestone slurry, water recycle, and make-up water
are added to the absorber circulating tank.  Limestone
is fed at 150% of the stoichiometric rate and water is added
in sufficient quantity to maintain the solids concentration
at about 10%.  Overflow  from the absorber circulating tank
goes to the venturi scrubber circulating tank.  The solids
concentration in this tank will depend on the inlet flue gas
fly ash loading but will normally run about  15%.  Overflow
from each venturi scrubber circulating tank goes  to the
effluent slurry surge tank as described previously.
                             50

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Clean flue gas flowing to the stack will have a fly ash
loading of about 0.01-0.02 gr/acf  (wet) and an SO  content
of about 160-320 ppm based on 90% removal in the scrubbing
train.
                             51

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2.  Wellman-Lord Process
    a.  Scrubbing Section (Area 100)
        The Wellman-Lord scrubbing system is designed to reduce
        the S02 content in power plant flue gases to an accept-
        able level for discharge to the atmosphere.

        Flue gas from the boiler enters a booster fan, 101-J,
        which sends the gas through the system.  The gas enters
        the absorber, 101-E where it is first pre-scrubbed with
        recirculating water to remove residual flyash.  The
        water is circulated by the prescrubber circulating
        pumps,  103-J.  The solids content in this stream is
        controlled by purging a small slipstream to the exist-
        ing flyash disposal pond.  Fresh make-up water is added
        in the prescrubber section.  Cool, saturated gas at
        about 130°F is then contacted countercurrently with
        a sodium sulfite solution in the top section of the
        absorber for removal of SO .  The Na_SO_ solution chemically
        absorbs S0_ by the reaction:

            S02 + Na2 S03 + H20 -»• 2 NaHS03.

        The sodium sulfite solution is circulated through the
        absorber via the absorber circulating pumps, 104-J.

        Gas leaves the absorber after passing through a mist
        eliminator and flows to a reheater, 101-C.  The temperature
        of the gas stream is raised to about 175°F to desaturate
        the gas and provide buoyancy for it.  Clean flue gas
        containing only 5% of the initial S02 then flows to the
        stack.

        Another reaction which may occur to some extent in the
        absorber when S0_ is present in the gas is the following:
                                 52

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         2Na2
    Also some oxidation of the sodium sulfite solution
    may occur.
                   1/2
    The bisulfite rich solution  (NaHSO-J is withdrawn
    from the bottom of the absorber and is sent to the
    abosrber surge tank, 101-F.

b.  Regeneration Section (Area 200)

    Bisulfite rich liquid is pumped from 101-F through
    the flyash filters, 201-L, via the filter feed pumps,
    201-J.  From the filters, most of the liquid flows to
    the evaporator feed tank, 201-F.  However, a small
    quantity is sent to the Purge/Make-up Section for
    sodium sulfate extraction.

    The evaporator feed pumps, 203-J, send the solution
    to the evaporator, 202-F.  Liquid is circulated
    through the evaporator heater, 201-C, by the evaporator
    circulating pumps, 205-J.  The solution is heated in an
    indirect heat exchanger using low pressure steam.  As the
    solution boils, SO_ and H_O vapor are released and sodium
    sulfite crystals precipitate from the solution.  The
    reaction occurring in the evaporator is:
         2NaHS03 •* Na2S03 + + S02 * + H^Q t.
    A heavy slurry of undissolved solids is maintained in
    the evaporator circuit by withdrawing part of the slurry
    and sending it to the dump/dissolving tank, 203-F.
                             53

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Overhead gas from the evaporator flows to the primary
condenser, 202-C, where water vapor in the gas is
partially condensed.  Gas leaving the primary condenser
joins overhead gas from the condensate stripper and feeds
the secondary condenser, 203-C, where most of the remain-
ing water vapor is condensed.  Cooling water is circulated
through both the primary and secondary condensers.  Con-
densate from both the primary and secondary condensers
flows to the condensate stripper, 201-E.  In this packed
column, the condensate is stream stripped to remove any
dissolved SO-.  The condensate from the stripper is used
for redissolving the sodium sulfite crystals in the dump/
dissolving tank.  It is pumped through the condensate
cooler, 205-C, via the condensate stripper pumps, 209-J,
to 203-F.

SOj vapor from the secondary condenser flows through a
knock-out drum and then to the S02 superheater, 204-C,
where it is heated and then compressed by the S02 com-
pressor, 210-J, and sent to the sulfur plant (Area 400).

Regenerated sodium sulfite  (Na, S03) solution from the
dump/dissolving tank is pumped to the absorber feed tank,
204-F, via the transfer pumps, 207-J, and is then returned
to the absorber  (Area 100) via the absorber feed pumps,
208-J.

Soda ash  (Na,CO,) make-up solution is added to the dump/
            ^  J
dissolving tank where it reacts with sodium bisulfite to
form additional sodium sulfite solution:
               2NaHS03
                        54

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c.   Purge/Make-up Section (Area 300)

    The purge/make-up section is designed to remove inert
    compounds such as sodium sulfate and sodium thiosulfate
    from the liquids and return sodium sulfite/bisulfite back
    to the S02 revovery unit.  A side-stream is taken from the
    evaporator feed for sodium sulfate purge and another side-
    stream is taken from the dump/dissolving tank for sodium
    thiosulfate purge.  The purge compounds are removed as
    dry solids after processing and sodium sulfite/bisulfite
    solution is returned to the evaporator.
                           55

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Allied Chemical Process for SO  Reduction
In the Allied Chemical process, SO. produced in the Wellman-
Lord process is reduced to elemental sulfur.  Natural gas
is used as the reducing agent.  The natural gas is mixed with
SO- from 210-J in the proper proportion for feeding the
reactor-regenerator system and passed through the feed
preheater, 403-C, to raise the temperature above the dew
point of the sulfur that is formed in the primary reactor.

The principal function of the catalytic reduction system
is to achieve maximum utilization of the reductant while
producing both sulfur and H S such that the proper ratio
of H S/SO- of 2:1 is realized for the subsequent Claus
reaction.  The preheated gas mixture enters the catalytic
reduction system through a four-way flow reversing valve
and is further heated as it flows upward through a packed
bed heat regenerator, 401-DB.  The gas stream then flows
downward through the reduction reactor, 402-D.  The temp-
erature of the gas entering the reduction reactor is con-
trolled by bypassing a quantity of cold gas around the
upflow regenerator.

Upon leaving the reactor, the main gas flow passes down-
ward through a second heat regenerator, 401-DA, giving up its
heat to the packing in that vessel before leaving the catalytic
reduction system through the  flow reversing valve.  A thermal
balance is maintained in the  system by passing a minor flow
of the hot gases around the downflow regenerator and the flow
reversing valve and remixing  with the main stream.  The direction
of flow through the two heat  regenerators is periodically
reversed to interchange their functions of heating the feed
gas and cooling the product gas.

The effluent gas from the reactor-regenerator system is further
cooled  in the mixed gas cooler, 404-C.  Some sulfur is condensed in
                               56

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this unit and it flows to the sulfur pit, 401-F.  Low pressure
steam is generated on the shell side of this unit.  A portion
of the gas from the mixed gas cooler then is used to heat the
feed gas in the feed preheater.  Gas leaving the feed
preheater enters the 1st sulfur condenser, 405-C.  Low
pressure steam is also generated on the shell side of this
unit.  Some sulfur is condensed and it is sent to the sulfur
pit.  Exit gas is then blended with hotter gas from the mixed
gas cooler to feed the 1st Claus reactor, 403-D.  Here the
following exothermic reaction takes place:
                       3S
The gas is cooled in the 2nd sulfur condenser, 406-C, and
the liquid sulfur formed flows to the sulfur pit.  Further
conversion to sulfur takes place in the 2nd Claus reactor
404-D.  Sulfur is condensed in the 3rd sulfur condenser,
407-C, and flows to the sulfur pit.  Low pressure steam is
also generated on the shell side of the 2nd and  3rd sulfur
condensers.

The gas stream then enters the tail gas mist eliminator,
401-G, for removal of entrained liquid droplets.  Residual
H_S in the gas is oxidized to SO  in the tail gas incinerator,
 £,                              £•
401-B.  Air is supplied to this unit by the dilution air
blower, 403-J, and the combustion air blower, 404-J.  The
incinerator outlet gas containing S02 is recycled to the
absorber in the scrubbing area to minimize SO  emission
to the atmosphere.

Product sulfur is pumped from the sulfur pit to  the sulfur
storage tank, 309-F, via the sulfur pit pumps, 402-J.
                              57

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B.  Coal Cleaning Process  (See Appendix D)

    The process description which follows is based on a coal
    preparation plant with a capacity of 600 t/h  of raw
    coal feed, operating two shifts/day for 220-260 days/yr.
    The total coal processed at such a plant would be 2.112
    MMTons/yr.  The site for the plant will require about
    25 acres; an additional 75 acres should be acquired ad-
    jacent to the plant for refuse disposal.  The utilities
    and manpower requirements for such a plant are itemized
    below:
       Electric Power
           Preparation plant
           Materials handling and storage
           Unloading and loading
           Total
       Manpower Requirements
           Preparation plant                        25 men
           Refuse handling                           3 men
           Intermediate storage & handling           8 men
       Make-up water requirements                  200 GPM

    Coal is received at the preparation plant in the raw coal re-
    ceiving bin, 101-F.  It is transferred from there to the 1500
    raw coal silo, 102-F, via a conveyor.  The plant feed conveyor
    transports the raw coal to the preparation plant where it is
    first screened in the raw coal screen, 101-G,and the pre-wet
    screen, 102-G.  This operation serves to separate the coarse
    coal particles  (5" x 1/4") which make up about 70% of the coal
    feed, from the fine coal particles  (1/4" x 0).

    The slurry containing the fine coal particles passes first  to
    a  stationary screen  (sieve bend screen, 103-G), and then to a
    desliming screen, 104-G.  Slurry passing through this screen
                                  58

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 flows  first  to  classifying  cyclones  ,  116-G.   The  underflow
 from these cyclones  (28M x  200M)  flows  to  froth  cells,  117-G.
 The overflow from  the  classifying cyclones  (200  M  x  0)  flows  to
 the thickener,  102-L.   Coal (1/4" x  28M) from the  desliming
 screen,  flows to the pulp sump,  103-F,  where  it  is mixed with
 concentrated magnetite.  This  stream is then  directed  to the
 heavy media  cyclone, 105-G, where gravity  separation taxes
 place.   The  heavy  media slurry containing pyrites  flows  to  the
 refuse drain and rinse  screen, 106-G.   Refuse is screened off
 here and sent to the refuse bin,  106-F, and the  heavy media
 slurry flows through the screen  to the  heavy  media sump,  104-F.
 It is picked up from the sump  by  the heavy media pumps,  101-J,
 and transferred back to the pulp  sump,  103-F.

 The overflow from  the heavy media cyclone containing small
 coal particles  (1/4" x  28M) flows over  a second  sieve bend
 screen,  107-G, and then to  the clean coal drain  and  rinse
 screen,  108-G.  Dilute magnetite  flows  through this  screen
 and combined with  the rinse underflow from the refuse screen,
 106-G, flows to the magnetic separator, 109-G, which concen-
 trates the magnetite and returns  it  to  the heavy media sump.
 Clarified water separated here is  returned to the  screen
 sprays.  Fine coal (1/4" x  28M) from 108-G then  is   trans-
 ferred to the centrifugal dryer,  110-G.  This unit separates
 the fine coal (1/4" x 28M), which  is transferred to  the clean
 coal silo, from a  slurry.   The slurry is sent to the froth
 cells, 117-G.

 Coarse coal  (5" x  1/4") which was  screened off in  the front
 end of the process is transferred  to the heavy media washer,
 111-G, where a gravimetric  separation is made in a magnetite
bath.   Refuse is separated at this point and transferred  to the
 refuse drain and rinse screen, 112-G.  The rejected material
 (5" x 1/4")  is screened off at this point and transferred to
 the refuse bin,  106-F,  along with  the remainder of the refuse.
 Concentrated magnetite flowing through this screen flows back
                              59

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to the heavy media sump, 105-F, while dilute magnetite flows
to the magnetic separator, 115-G.

Coal from the heavy media washer flows to the clean coal drain
and rinse screen, 113-G.  Coarse coal  (5" x 1-1/2") overrides
this screen and is sent to the crusher, 101-L.  Coal from the
crusher  (1-1/2" x 0) is then transferred to the clean coal silo,
107-F.  Coal overriding the second deck (1-1/2" x 1/4") is then
transferred to a centrifugal dryer, 114-G.  Slurry is separated
from the coal at this point and transferred to the froth cells,
117-G.  The clean coal from the centrifugal dryer  (1-1/2" x 1/4")
then joins coal leaving the crusher to be transferred to clean
coal storage.

Concentrated magnetite from the clean coal drain and rinse
screen flows to the heavy media sump, 105-F.  From here it
is picked up by 102-J and transferred back to the heavy media
washer.  Dilute magnetite from the clean coal drain and rinse
screen flows through the screens to the magnetic separator,
115-G.  Concentrated magnetite from this unit flows to the
heavy media sump and clarified water is returned to the
screen sprays.

From the froth cells, 117-G, small coal particles  (28M x 0)
are sent to the clean coal filter, 118-G.  Filtered coal
is then transferred to clean coal storage.  The filter over-
flow is pumped to the screen sprays.  The static thickener,
102-L, receives the refuse slurry from the froth cells.  A
further  feed to the thickener is a slurry stream which comes as
the overflow from the classifying cyclones, 116-G.  Refuse
from the thickener  is transferred to the refuse filter, 119-G.
Filter cake from this unit  (28M x 0) then joins the remainder
of the plant refuse.  Water from this  filter  is returned to
the screen sprays.  Clarified water  from the  thickener is
sent to  108-F  from  where it is returned to screen  sprays.
                               60

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Make-up water for the process is sent to the make-up water
tank, 108-F.  Water from the thickener also flows to 108-F.
Water is pumped from this vessel to the screens to be used as
screen spray.

A supplemental system which can be used in the coal pre-
paration plant includes a thermal dryer, 101-B.  This unit
receives as feed, coal (1/4" x 28M) from the centrifugal
dryer, 110-G and from the clean coal filter (28M x 0). It
reduces the water content of the fine coal (1/4" x 0) to
the desired surface moisture level.  Dried coal from the
thermal dryer is then transferred to the clean coal silo.
                               61

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V. DESCRIPTIONS OF POWER PLANTS IN IOWA
   A.  Des Moines Plant (See Fig. 11, 23)

       The Des Moines Plant  is a coal, oil and gas  fired steam
       electric power plant  owned by Iowa Power  & Light Company.
       It has a generating capacity of 325 raw, the second largest
       in the state.  It  is  located  on the north bank of the Des Moines
       River in Des Moines,  Iowa.

       The plant  is situated just north  of a  bend in the Des Moines
       River on a site  of approximately  60 acres.   The plant
       site is bound on the  south, the southwest and the southeast
       sides by the Des Moines River.  An oil storage tank  farm
       lies north of the  plant past  the  coal  pile.  The boilers
       are enclosed in  a  building which  runs  in  a north-south
       direction.  West of the power house is a  large cooling
       tower running in a northwest  to southeast direction.  The
       cooling tower is situated above its basin.  A 46 kv substation
       is located due east of Boilers 7  and 8 and a parking lot is
       located due east of Roiler 11.  Highway 46 runs in a north-
       south direction  dividing  the  plant property.  It crosses the
       river just east  of the 46 kv  substation.  Just east  of High-
       way 46  is  a large  69  kv electrical switchyard and east of
       it is an even larger  161 kv electrical substation.  North
       of these electrical facilities is a large ash disposal pond.
       The pond  is approximately 900' wide and 1000' long.  Rail-
       road tracks enter  the boiler  area from the northwest and
       from the northeast.

       Coal is received at the Des Moines Power  Plant by rail and
       by truck  from a  number of different sources.  Some western
       coal is burned  at  this plant. Total coal used in 1972 was
       524,000 tons.   The average properties  of  this coal on an
       as received basis  are as  follows:
                                     62

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     HHV        :   9400 Btu/lb
     %S         :   4.1
     %Ash       :   15.2
     %Moisture  :   16.9

Coal is stored in a large pile located north to northwest
of the power plant.

The Des Moines plant has 6 boilers and 7 generators which
range in capacity from about 30 to 110 mw.  Boilers 6, 7,
8 and 9 supply steam to five turbines through a common
steam header.  Boilers 10 and 11 each have their own turbine
and generator.  The average load factor for the Des Moines
power plant in 1972 was 58.5%.  Boiler 6 uses gas exclusively.
It is a front firing boiler.  The standby fuel for this unit
is No. 2 fuel oil.  Boilers 7, 9 and 9 are pulverized coal,
tangential-fired units.  Boilers 10 and 11 are pulverized
coal, front-fired units.  Units 7 and 8 are tied together
to a common stack 250' high.  Units 9, 10, and 11 each has
its own stack.  These stacks are also 250* high.

Boilers 7, 8 and 9 are served by cyclones for removal
of fly ash.  Estimated efficiency of these units is 65%.
Boilers 10 and 11 are presently served by multiple cyclones
with a design efficiency of 75%.  These units are scheduled
to be removed in mid 1974 for the installation of new
electrostatic precipitators.  The new ESP's "are designed
to remove 99.3% of the fly ash.
                            63

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B.  The Pella Plant (See Fig. 33)

    The Pella Plant, located in the small town of Pella
    (about 40 miles southeast of Des Moines), is owned and
    operated by the Pella Municipal Power and Light Company.
    The area is sparsely populated, primarily rural, and
    lightly industrialized.

    Rated at 44 mw, the plant has operated largely on Iowa
    coals from nearby mines;  but some consideration is being
    given to cleaner "foreign" coals, particularly from the
    West.  In 1972, the 62,000 tons burned came from mines in
    Marion and Mahaska counties and were trucked very short
    distances.  There are rail facilities nearby as well.
    The coal burned in 1972 had the following average proper-
    ties:

         HHV          :  8800 Btu/lb
         %S           :  6.6
         %Ash         :  17.5
         %Moisture    :  14.8

    There are six boilers in the plant, and coal, oil or
    natural gas are the design fuels.  However, only two of
    the boilers, the number  6 and  7 units, are used for base-
    load operation;  the others  are either stanby units or are
    being phased out.  The two generators are connected by a
    common header.  The two  base-load boilers are fairly new,
    one  commissioned in 1964 and the other  1972.  The average
    load factor in  1972 was  20.3%.  The boilers are dry
    bottom, spreader-stoker  fired  units.
                                  64

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A new stack serves both boilers, which feed flue gas
through common breeching to a new electrostatic precipi-
tator designed for 95% efficiency.  The stack is roof-
mounted and stands 250 feet above grade.

The site is triangular in shape, bounded on the north and
east legs by city streets and on the hypotenuse by a rail
spur.  Space is severely limited on-site because of the
in-town location.  The total area occupied by the plant
is only about 3 acres.  The substation is small and
located west of the main building.  Space for coal storage
is severely limited and is situated near the cooling
towers east of the building and south as well.  There is
no ash pond, ash being stored in a silo for periodic haul-
age by truck to land fill sites.
                             65

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C.  Iowa State University Steam and Power Plant (See Fig. 34)

    This plant is located on the campus of Iowa State
    University in the town of Ames, in central Iowa.
    Although the installed generating capacity is only
    25 mw, the plant consumes considerable more energy
    than would be expected since it provides steam for
    heating campus-wide.

    Two of the existing five units are coal-fired, and the
    other three are designed for coal and gas.  A new boiler
    which is slated for commissioning in mid-1975 will re-
    place the old number 4 unit and will be designed to use
    coal, oil or gas.  In past years this plant made exten-
    sive use of Iowa coals, but due to the impending sulfur-
    control regulations, it was expected that 1974 would
    see exclusively Illinois coal in use.  In 1972 some
    95,000 tons of coal was received by train from Iowa,
    Illinois and Oklahoma mines.  This coal had the following
    properties:

         HHV         :  11,300 Btu/lb
         %S          :  4.0
         %Ash        :  11.5
         %Moisture   :  9.7

    Capacity factors are high in the ISU plant, averaging
    some 80-90% in 1972.  All of the boilers are relatively
    alike in size, consuming about 10-14 t/h of coal;  they
    were added piecemeal at about 8 year intervals as demand
    increased.  They were placed in service from 1946 to 1974.
    Presently there are no electrostatic precipitator installa-
    tions in place or planned, but efficient multiple cyclones
                                 66

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(92%) are anticipated to be installed by mid-1974.
Ash is trucked out to landfill sites;  there is no ash
pond, and temporary ash storage is handled in a silo.

Space is severely limited at the site since it is on
the campus proper.  Because of the presence of nearby
academic  and administrative buildings there is little
possibility of expansion.

Coal storage is east of the main building and occupies
only a few acres.  The rail siding and unloading facili-
ties skirt the north boundary, and the southern side is
confined by Wallace Road.  The area is somewhat hilly.
There are buildings nearby in every direction.  Because
of the nature of the plant, there is no large switch
yard and substation.  Northwest of the plant.are water
treating and storage facilities and the cooling towers.

An old stack at the southern edge of the building is
to be removed and a new one 190 feet high will serve
two of the 5 units  (Units 5 and 6) while the other
three (UrJts 1/2, and 3) will be served by a 160-foot
high stack.
                            67

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D.  Maynard Plant (See Fig. 12, 24)

    The Maynard Plant is coal, oil, and gas fired steam electric
    plant owned by Iowa Public Service Company.  It has a
    generating capacity of 107 mw and it is located on the
    north bank of the Cedar River in Waterloo, Iowa.

    The plant is located on a fairly congested site.  It is
    bound on the south and west sides by the Cedar River, on
    the north side by Lafayette Street and on the east side by
    another street.  The area of the property south of Lafayette
    Street is about 7 acres.  The ash pond, coal yard, and
    fuel oil storage tanks are located across Lafayette Street
    northwest of the boiler area.  Due north across Lafayette
    Street is the City Water Works and adjacent to it is an
    industrial area.  A residential area lies east of the
    plant across the city street.  Several railroad tracks
    approach the boiler plant from the north side.  A 69 kv
    substation and a 34.5 kv substation are situated northwest
    of the boilers.

    Coal is received by rail from Illinois.  In 1972, the
    plant used 82,000 tons of coal having the following
    properties as received:

        HHV            :  10,900 Btu/lb
        %S             :  2.5
        %Ash           :  11.0
        %Moisture      :  12.0

    The Maynard Plant has 5 boilers and 4 generators ranging
    in capacity from 12 to 58 mw.  Boiler 14 is base loaded
    and boilers 9, 10, 11, and 12 cycle in capacity.  All
    boilers can burn coal and gas and, in addition, Unit 12
                               68

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can also burn fuel oil.  Average plant load factor in
1972 was 40.0%.  The boilers were placed in service from
1937 to 1958.  Units 9 and 14 are pulverized coal fired
and Units 10 and 11 are stoker fired.  Units 9, 10, and
12 are served by a common stack 220 feet high.  Unit 11
has its own stack which is 220 feet high and Unit 14 also
has its own stack which is 250 feet high.

Fly ash is removed from the flue gas from Boilers 9 and
11 by Western Multiclones.  Boiler 10 has a Pratt-Daniel
Thermix Tubular cyclone.  Boiler 12 has a mechanical pre-
cipitator^  Boiler 14 is served by a Joy electrostatic
precipitator with a design efficiency of 99%.
                            69

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E.  Muscatine Plant (See Fig.  13,  25)

    The Muscatine Plant is a coal fired steam electric power
    plant owned by the Muscatine Municipal Electric Plant.
    It has a total installed generating capacity of 117 mw.
    The plant is located on the west bank of the Mississippi
    River in a rural area near Muscatine, Iowa.

    The plant has 4 boilers (No. 5 through No. 8) in a row
    facing the river with Unit 5 on the north and Unit 8
    on the south.  Maple Grove Road runs north-south in the
    narrow space between the boiler house and the Mississippi
    River.  A 69 kv electrical substation is situated due
    west of Unit 8 and another substation is located west of
    Units 5,6 and 7.  The older portion of the power plant
    located on the north side of Unit 5 is to be dismantled.
    Railroad tracks approach from both the west and the south
    making a large loop through the southwest quarter of the
    plant.  The plant area east of the railroad tracks to
    Maple Grove Road occupies about 13 acres.  Some relatively
    open farm land lies west of the plant.

    Coal is stored in a large pile about 400' wide and 600'
    long which is located south of Unit 8.  The plant used
    251,000 tons of coal in 1972.  This coal was shipped from
    Illinois and had the following average properties as
    received:

         HHV         :  10,900 Btu/lb
         %S          :  3.0
         %Ash        :  10.2
         %Moisture   :  16.4

    Coal is received at the Muscatine Station by rail and by
    barge.  The barge dock and the unloading facilities are
                                70

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located out over the water southeast of the plant,
some 160 feet from the river bank.

The four boilers of the plant are associated with four
generators ranging in capacity from 7.5 to 84 mw.  Unit
5 is the smallest and is used for standby.  Unit 6 is
used for peaking and Units 7 and 8 are base loaded.
Unit 8 rated at 84 mw is by far the largest.  Average
load factor in 1972 was 57.9%.  Units 5,6, and 7 are
spreader stoker-fired and Unit 8 is cyclone-fired.  The
boilers were placed in service from 1941 to 1969 and
have an expected remaining life of  7-35 years.  Units
5,6, and 7 will be tied together and served by one new
stack 220 feet high.  Unit 8 is served by its own stack
320 feet high.

Units 5 and 6 are to be served by new mechanical dust
collectors rated at 80% efficiency which are to be
placed in service in May, 1975.  Unit 7 is presently
served by a mechanical dust collector rated at 80%
efficiency.  In addition, a new ESP is to be installed
in May, 1975 to serve Unit 7.  This will be a cold side
ESP rated at 90% efficiency.  Unit 8 presently has a
Research-Cottrell cold side ESP rated at 95% efficiency.
                            71

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F.  The Fair Station (See Fig. 35)

    The Fair Station is located in the small town of Montpelier
    in southeastern Iowa;  it is a Mississippi River plant with
    a generating capacity of 63 mw.  The area is rural with light
    population and industrial development.  The plant is owned
    by the Eastern Iowa Light and Power Cooperative of Wilton
    Junction, Iowa.

    There are two boilers, placed in service in 1960 and 1967,
    each designed to burn coal or natural gas.  The two gen-
    erators have capacities of 25 and 41 mw.*  There are two
    stacks, each roof mounted 164 feet above grade.  To date
    the only ash collection equipment consists of multiple
    cyclones designed for 85% efficiency but electrostatic
    precipitators are planned for early 1975.

    The approximate coal consumption in 1972 was 81,000 tons.
    This coal was delivered to the plant by barge following a
    rail leg from Illinois.  Rail unloading facilities are
    also available at the plant near the river dock.  Coal used
    in 1972 had the following average properties:

         HHV           :  10,900 Btu/lb
         %S            :  3.3
         %Ash          :  9.2
         %Moisture     :  11.3

    *It is common  to find plants  in which name plate and
    100% load ratings  are not identical.
                                  72

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Space for future expansion is not a serious problem at
the Fair Station site.  Some room exists to the west of
the main building and north of the building near the
substation.

The coal storage pile occupies some 6.5 acres (440'x640')
due east of the main plant and north of the dock.  Two ash
ponds are located at the opposite (west) end of the property.
The larger of the two is about 2.5 acres in area while the
smaller is about 220'x280' (1.5 acres).  The major rail line
runs east and west along the north boundary and parallel to
State Highway 22.  The river bounds the south property line.
The total plant site covers about 28 acres.
                             73

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G.  The Riverside Plant (See Fig.  14, 26)

    The Riverside Plant is located on the Mississippi River
    in the city of Bettendorf, Iowa, and is owned by Iowa-
    Illinois Gas and Electric Company.  Generating capacity is
    222 mw.  The area is heavily populated, and industrial
    development is very heavy.

    Design fuels are coal and natural gas.  There are 5 boilers
    and 5 generators ranging in size from 16 to 140 mw.  The
    units were placed in service from 1937 to 1961.  Boilers
    5-8 are pulverized coal, front-fired units and Boiler 9 is
    a pulverized coal, tangential-fired unit.  In 1972 the
    average load factor for the plant was 66.2%.  All of the
    boilers are enclosed and are served by individual electro-
    static precipitator units rated  at 99% efficiency.  One
    346' high stack serves the newest three boilers  (7,8, and 9),
    and the two oldest ones  (5 and 6) have their own stacks
    (each 144' high).

    The plant grounds are rather crowded with equipment and
    auxiliary facilities.  Coal storage and handling and ash
    storage areas are south of the plant proper;  to the north
    are more coal facilities and storage.  West of the building
    are parking areas, substations,  rail facilities, water tanks,
    gas turbine houses and other facilities.  The river confines
    the east property line.

    Coal unloading  facilities appear to be exclusively rail,
    although the plant is on the river.  In 1972 all the coal
    used, some 472,000 tons, was brought in by rail from Illinois.
    This coal had the following average properties:
                                 74

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     HHV          :   10,400 Btu/lb
     %S           :   2.6
     %Ash         :   8.7
     %Moisture    :   16.8

The only availabe space on the property appears to be
north of the main building and close to the river.
                             75

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H.  Burlington Plant (See Fig. 15, 27)

    The Burlington Plant is a coal fired steam electric power
    plant owned by Iowa-Southern Utilities Co.  It has a
    total installed generating capacity of 212 mw.  The plant
    is located on the west bank of the Mississippi River in
    Burlington, Iowa which is in the  southeast corner of the
    state.

    The plant has a single boiler with the stack being located
    east toward the river and the turbine-generator room
    being located west.  The plant is situated on a fairly
    large track of land  (about 120 acres) which is bound on
    the east by the Mississippi River and on the northwest
    by the CB & Q Railroad.  An old ash disposal basin (approx-
    imately 500' x 800') is located due south of the plant.
    A large new ash basin is located west of the coal pile and
    northwest of the plant.  Located due west of the turbine-
    generator room is the main electrical substation.  Rail-
    road tracks parallel the river and enter the plant area
    from the north.

    Coal is stored in a  large pile having dimensions of about
    450 feet x 450 feet.  The coal pile is located north of
    the plant and a conveyor runs from the crusher building
    some 450 feet to the silo bay of  the boiler.  The plant
    used 544,000 tons of coal in  1972.  It was shipped by
    rail from Illinois and had the following properties:

        HHV              :  10,100  Btu/lb
        %S               :  2.6
        %Ash             :  8.2
        %Moisture        :  20.5

                                76

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The single boiler and generator are rated at 212 mw.
The unit was built in 1968 and has a remaining life of
about 25 years.  Load factor in 1972 was 59.2%.  The unit
is designed for pulverized coal, tangential firing.  It
is served by a single stack 306' tall.

Fly ash is removed from the flue gas by a UOP electrostatic
precipitator located on the cold side.  Tested efficiency
of the unit at start-up was 98.5%.
                            77

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I.   Dubuque Plant (See Fig.  36)

    The Dubuque Plant, owned by Interstate Power Company,
    is located on the Mississippi River  in metropolitan
    Dubuque.  Generating capacity is 91 mw including all
    units and 74 mw if the two oldest boilers are excluded.
    The surrounding area is heavily populated and very
    industrialized.  The plant occupies an area of about
    12-15 acres.

    There are 5 boilers; design fuels are coal, oil and
    natural gas.  The boilers range in design coal consump-
    tion from 8.7 to 25.2 t/h; load factors, from 2 (for
    standby units) to 53.5; generating capacity, with 4
    generators, 10.0 to 37.5 mw; commissioning dates, 1926
    to 1959.  Two oldest boilers were not fired at all in
    1973.  Average plant load factor in 1972 was 54.3%
    (based on a generating capacity of 74 mw).

    There will be 2 stacks, both 106 feet above grade.
    Presently there is only one electrostatic precipitator
    installed, but two other  (newer) boilers will each have
    ESP's by the end of 1974.  All ESP's are cold side units
    with design efficiencies of 99%.

    Coal may be delivered either by barge or by train and is
    stored  in a yard southeast of the plant.  In 1972 all
    of the  coal used  (about 121,000 T) was supplied by barge
    from Illinois.  This coal had the following average proper-
    ties:
         HHV          :  11,300 Btu/lb
         %S           :  3.2
         %Ash         :  10.9
         %Moisture    :  10.3
                                78

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Space is rather limited at this site due to its in-city
location.  Miscellaneous city facilities and commercial
interests line the plant property on three sides, and
the river confines the east border.  The only available
room for expansion appears to be south and northeast
of the main building.  The precipitators and stacks are
south of the building, and a rail spur passes underneath
through to the river dock unloading facilities.  The sub-
stations and poleyard are located to the north.  One city
street  (E. 8th St.) passes partway through the plant area.
The area to the northeast has power cables and poles in
it.  There is no ash pond on-site; ash is trucked away
to landfill sites.
                            79

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J.  The Lansing Plant (See Fig.  37)

    The Lansing Plant,  with 3 coal-fired boilers rated at
    64 mw total generating capacity, is owned by Interstate
    Power Company (of Dubuque).   It is a Mississippi River
    plant serving Lansing, in northeastern Iowa and environs.
    The area is lightly populated,  primarily rural, and light-
    ly industrialized.

    The boilers are  designed for coal consumption of 7.4 to
    18.5 t/h and are rated at 15 to 37.5 mw.   They were
    commissioned in  1948 to 1957 and operated ,at an average
    load factor of 47.4% in 1972.   Two stacks each 151 feet
    above grade,  serve  them.

    Electrostatic precipitators  will be installed on all
    three units before  the end of 1974.   The  ESP's will be
    cold side units  with design  efficiencies  of 99%.

    Coal may be delivered either by  rail or by barge.   In
    1972 the 154,000 tons of coal used at Lansing was  del-
    ivered by barge  from Illinois mines.   The average  prop-
    erties of this fuel  on an as received basis were  the
    following:

         HHV         :   11,200 Btu/lb
         %S           :   3.0
         %Ash        :   10.5
         %Moisture   :   11.1

    Future plans  call for a fourth boiler,  generator and
    precipitator  system  (and  presumably  another stack,  as
    well)  which will probably be commissioned in 1977.   More
    immediately,  changes will be made in the  coal unloading
    and water treatment  facilities.
                               80

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Space is not a critical problem at this plant site;
expansion space for the new unit is located directly
north of the main building.  A large open area west of
the substation and switch yard, which lies west of the
plant proper, is presently set aside for coal storage
for the new unit.  Also there is a small space directly
southeast of the building, as well as a larger space
across the rail tracks in the same direction.  Addi-
tional coal storage is located farther to the west.
The river curves around the north and east sides of the
site.  A creek runs south and east of the plant and
proposed coal yard.
                            81

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K.  The Kapp Plant (See Fig.  16,  28)

    The M. L. Kapp Plant is owned by the Interstate Power
    Company of Dubuque and is located on the west bank of
    the Mississippi River near the small town of Clinton,
    Iowa.  Installed generating capacity is 237 raw.  The area
    is generally rural; industrial development in the general
    vicinity is moderate to heavy.

    The Kapp Plant has 2 coal-fired boilers, commissioned in
    1947 and 1967, respectively,  and 2 generators.  Unit 1
    is rated at 19 mw and is a pulverized coal, front-fired unit.
    Unit 2 is rated at 218 mw and is a pulverized coal, tangen-
    tial fired unit.  Average load factor for the plant in 1972
    was 59.8%.  Both boilers are wet-bottom units and are
    enclosed in the main building; both are served by separate
    electrostatic precipitators and stacks.  (The ESP for Unit 1
    will be on steam in early 1975).  The stacks are located
    south of the building and are 210 and 245 feet tall.

    The area occupied by the plant (excluding the ash pond)
    is about 35 acres.  High-voltage switch gear is located
    at the northeast wall of the building; the power sub-
    stations are located to the northwest on the other side
    of the rail spur.  An ash storage pond  (approximately 50
    acres) is located to the west of the substations and near
    U.S. Highway 67.  Ash is sluiced either to this pond or to
    an emergency settling basin north of the plant via a 10-inch
    sluice pipeline.  Open space exists to the immediate west
    of the building, where a third unit was once planned; evi-
    dently this plan was subsequently abandoned,and the space
    is presently used for parking, storage and construction.
    Other than this, the only unused space inside the property
                                82

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line is south  of the building, but this space is limited
by a railroad  right-of-way, a water treatment plant and
one of the stacks.  There is little available space nearby
outside the property line.  The Mississippi River bounds
the east side; a city sewage disposal plant is located
north of the plant  on the other side of a creek skirting
the north property line.  The creek curves around the west
side line, leaving little space between the property line
and substations.  To the south and southwest are DuPont
facilities and ponds.

Coal for the plant was supplied (1972) from three Illinois
mines by barge.  Rail unloading facilities are also present.
The coal yard is east of the building.  Design coal con-
sumption  (100% rating) totals 103 t/h  the plant used
575,000 tons of coal in 1972 having the following average
properties on an as received basis:

     HHV         :  11,000 Btu/lb
     %S          :  3.1
     %Ash        :  11.0
     %Moisture   :  11.8
                            83

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L.  Prairie Creek Plant (See Fig.  17,  29)

    The Prairie Creek Plant is a coal, oil and gas fired steam
    electric power plant.  It has an installed generating
    capacity of 245 mw.  Units 1, 2, and 3 are rated at 96 mw
    and are owned by Central Iowa Cooperative.  Unit 4 rated
    at 149 mw is owned by Iowa Electric Light & Power Company.

    The plant is located on the west bank of the Cedar River
    outside of Cedar Rapids, Iowa in a fairly rural area.
    The plant site is a long narrow strip of land of about
    50 acres in area extending westward from the Cedar River.
    The property is bound on the north by the Chicago and
    Northwestern Railroad and it is bound on the east by a
    road.  An open pasture lies to the south of the plant.
    A 115 kv electrical substation is situated north of the
    boilers.  Some water treating buildings and offices lie
    northwest of Unit 4.  A number of railroad tracks run
    through the property in an east-west direction.  The ash
    disposal basin is located at the west end of the property.
    A parking lot is situated on the east side of the power
    house.

    Coal is stored in a large elongated pile (about 300' wide
    x 2000" feet long)  located south of the boilers.  The plant used
    497,000 tons of coal in 1972.  The coal had the following
    properties on an as received basis:

        HHV             :  10,500 Btu/lb
        %S              :  2.5
        %Ash            :  8.5
        %Moisture       :  16.9

    Coal is received at the Prairie Creek station by rail.  The
    principle source of the coal is Illinois.
                                84

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The plant has four boilers and four generators ranging
in capacity from 23.5 to 149 mw.  The boilers were placed
in service from 1960 to 1967.  In 1972 the average load
factor for the plant was 53.5%.  The boilers are arranged
in a row with number 1 boiler located on the east side
of the power house and number 4 boiler on the west side.
Units 1 and 2 are peak shaving, spreader-stoker fired boilers
Units 3 and 4 are base load, pulverized coal, front-fired
boilers.  Units 1 and 2 share the same stack which is roof
mounted and 180' above grade.  Unit 3 has its own stack
which is also roof mounted and 180' above grade.  Unit
4 has its own stack which is located west of the power
house.  It is mounted at grade and 200' high.

Units 1 and 2 have multiple cyclones for fly ash removal.
The design efficiency on these units is 85%.  Unit 3
is served by an electrostatic precipitator designed for
9B~.6% removal of particulate matter.  Unit 4 is served
by multiple cyclones designed for 80% particulate removal.
A new electrostatic precipitator is now being installed
on Unit 4.  Scheduled completion date is October, 1974.
                            85

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M.  6th Street Station (See Fig.  38)

    The 6th Street Station  is a coal, oil and gas fired steam
    electric plant owned by Iowa Electric Light & Power Company.
    It has a generating capacity of 92 mw and is located in
    downtown Cedar Rapids,  Iowa.  In addition to the other
    fuels mentioned, the plant also burns considerable amounts
    of furfural waste.  A  substantial portion of the steam
    generated at the 6th Street Station is used for heating
    purposes.

    The plant is located in a very conjested area of approximately
    five acres.  The boilers are enclosed in a building which
    is located at the south corner of the property.  The plant
    is bound on the northwest and south sides by railroad tracks
    and on the north side  by Cedar Lake.  Water storage tanks,
    chemical storage facilities and water treating equipment
    occupy the space northeast of the power house.  A 33 kv
    electrical substation  is located north of the plant.  A
    115 kv electrical substation lies northeast of the 33 kv
    substation.  Immediately south of the boiler area is a
    small parking lot.  West of the plant, across the railroad
    tracks is a Quaker Oats plant.  There is no coal pile at
    this plant simply because there is no room for one.  Coal
    is unloaded from railroad cars to a hopper and is
    then conveyed directly to the coal bunkers at the power
    plant.

    The plant burned  260,000 tons of coal in 1972.  Average
    properties of this coal on an as received basis are as
    follows:

        HHV         :  10,300 Btu/lb
        %S          :  2.3
        %Ash       :  7.6
        %Moisture   :  20.0

                                 86

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The plant has 10 boilers and 10 generators ranging in capacity
from 6 to 25 mw.  The boilers were placed in service from
1937 to 1950.  Average load factor for the plant in 1972
was 31.4%.  All boilers are pulverized coal, front fired
units and all have the capability of also firing residual
oil.  There are 5 stacks at the 6th Street Station, each
being 198' high.  Boilers 1 and 2 are served by stack 1;
Boilers 3 and 4 by stack 2; Boilers 5 and 6 by stack 3;
Boilers 7 and 8 by stack 4; and Boilers 9 and 10 by stack
5.

Ply ash is removed from the flue gas from Boilers 1 and 2
by cylcones with a design efficiency of 47%.  Four electro-
static precipitators serve the other eight boilers.  The
design efficiency on the ESP's serving Boilers 3-4, 5-6, and
7-8 is 98%.  The design efficiency on the ESP serving
Boilers 9-10 is 99.3%.
                            87

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N.  Sutherland Plant (See Fig.  18,  30)

    The Sutherland Plant is a coal fired stea'm electric power
    plant owned by Iowa Electric Light and Power Company.  It
    has a total installed generating capacity of 157 mw.
    The plant is located in a rural area near Marshalltown,
    Iowa.

    The plant is situated on a fairly large open site of
    about 80 acres.  The cooling tower for Unit 3 is located
    about 400 feet due east of Unit 3 and the cooling tower
    for Units 1 and 2 is located about another 300 feet due
    east of the other cooling tower.  An ash basin (8001 x 600')
    is located east of the cooling tower for Units 1 and 2.
    Coal is transported to the boilers by conveyors which enter
    from the north side.  Some oil storage tanks are located
    in a tank field about 500-650 feet northwest of the boilers.
    A parking lot is situated just south of the boilers.  A
    115 kv substation is located southwest of the boiler area.
    There are some open areas due east as well as southeast
    of the boilers.

    Coal is stored in a large pile (about 300' x 1000') north-
    east of the boilers.  The plant used 199,000 tons of
    coal in 1972.  This coal had the following properties:

        HHV              :  10,100 Btu/Lb
        %S               :  2.8
        %Ash             :  11.7
        %Moisture        :  16.0

    Coal is received at the Sutherland Station by rail.

    The plant has three boilers and three generators ranging
    in capacity from 37.5 to 81.6mw.  The boiler houses are
                                  88

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enclosed and the boilers are arranged in a row with Unit
1 to the west and Unit 3 to the east.  The boilers were
placed in service from 1955 to 1961.  In 1972 the average
load factor was 73.5%.  Boilers 1 and 2 are pulverized coal,
front firing types and boiler 3 is cyclone firing type.
Each boiler is served by its own stack and each stack is
190 above gride.

The original installation had multicyclones on all three
units for fly ash removal.  Design efficiency of the units
was 80%.  Each boiler will have a new ESP installed for
final clean up by early 1975.  The new ESP's for Units 1 and
2 will be mounted on a steel structure just north of the
boilers.  The new ESP for Unit 3 will be mounted on the roof
of the building.  All new ESP's will be downstream of the
air heaters  (cold gas side).
                            89

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              VI ESTIMATES FOR FLUE GAS SCRUBBING


A.  Detailed Estimates for Wet Limestone Systems

    1.  Results

        The capital investment required to install Wet Lime-
        stone scrubbing systems on each of the eight selected
        Iowa power plants are tabulated below:*
Gen Cap:
MW
325
107
117
222
212
237
245
157
Capital Total
Invest: Int. During Capital
$MM Const: $MM Inv: $MM
22.1
14.7
10.3
17.2
13.0
14.5
17.8
15.5
2.2
1.5
1.0
1.7
1.3
1.4
1.8
1.5
24.3
16.2
11.3
18.9
14.3
15.9
19.6
17.0
$/KW
74.60
151.10
96.90
85.00
67.40
67.00
80.10
108.30
Muscatine
Riverside
Burlington
Kapp
Prairie Creek
Sutherland
Total          1622      125.1      12.4      137.5       84.80 Avg,

       These estimates assume that a thickener and small pond
       (2 weeks storage)  are provided for sludge disposal.
       Sludge would have to be removed from the plant site
       via truck,  rail or barge.   If a long term sludge pond
       were provided the capital investment required would
       increase.  The extent of the increase would depend on
       several factors:

            - the number of years of sludge storage provided for
            - the sulfur content of the coal feed
            - the type of pond lining used and thickness of
              the lining.
* Costs are on a January, 1974 basis.
                               90

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    Detailed estimates for Wet Limestone scrubbing were
    also prepared for the following smaller plants:  Pella,
    Iowa State University, Fair, Dubuque, and Lansing.
    The average capital investment for these five plants
    was $171.10/kw.  No detailed estimate was prepared for
    the Sixth Street Station due to the unusually crowded
    conditions existing at the plant site.  These six
    plants were dismissed from consideration for stack
    gas scrubbing due to their small size (and high unit
    investment cost)  and due to space limitations.

2.   Procedure

    The design proposed by the Tennessee Valley Authority
    for their Widows  Creek Unit 8 Wet Limestone Scrubbing
    system was used.   Some slight modifications were made
    in both the limestone handling system and the scrubbing
    system (14).

    To evaluate the capital investment required for Wet
    Limestone Scrubbing at 13 power plants containing
    many boilers of different sizes, it was decided to
    develop several different standard size scrubber modules.
    It was found that eight standard scrubber modules would
    be sufficient to adequately cover the range of boiler
    sizes involved.*  The largest scrubber module (Size I)
    is capable of treating flue gas from a boiler generating
    about 167-182 mw and the smallest scrubber module (Size VIII)
    is capable of treating the flue gas from a boiler generating
    about 28-30 mw.  Vendor quotations were obtained for
    the major equipment items in the largest (Size I)
    scrubbing train.   Costs for the smaller size trains
    were pro-rated down from this cost.
*   The number and size of the standard scrubber modules are
    chosen to best match the flue gas flow from each power
    plant.
                           91

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Prices of the major equpiment  items  in  the  limestone
handling and grinding  system were  also  obtained  from
vendor quotations.  The equipment  in  this area includes
conveyors, pumps, motors, ball mills  ani the grinding
building.   Subcontract cost items in this area include
the limestone silos, thickener, slurry tank, effluent
tank, and unloading hopper.  Prices  for different
equipment sizes were obtained  so that a cost curve
could be prepared for  the limestone  handling and
grinding system.

Using the drawings obtained from the  power  companies,
layout sketches were made showing the number, size,
location,  and orientation of the scrubbing modules.
Also shown on the drawings were the  limestone storage,
handling, and grinding facilities.   In  addition, major
revamp work needed to  install the Wet Limestone Scrubbing
system at each plant was indicated on the drawings.

Process flow sheets for the limestone handling and
grinding system and for the scrubbing system were
prepared.  Three different standard  scrubber module
drawings were also prepared and layout  dimensions
were provided for them.  A tabulation of the eight
standard scrubber module sizes and capacities was
completed.  Also a tabulation  of standard piping
sizes for each different scrubber  module was made.

The M. W.  Kellogg Estimating Department was used to
prepare the detailed capital estimates  for  the 13
Iowa power plants.  General information transmitted
to the Estimating Department included the following:

    - cost of standard scrubber modules
    - cost curve for limestone system
    - standard piping  sizes
    - standard scrubber module drawings
                       92

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      - isometric scrubber module sketch
      - process  flow  sheets
      - tabulation of standard scrubber module sizes
        and capacities

  Specific information  turned over to  the  Estimating
  Department for each plant included the following:

      - power plant  summary sheet showing number
        of scrubbing  trains required,  the train size,
        train type, additional duct work required (if
        any) and pond size requirement
      - a plot plan for the power plant showing the
        location of the scrubbing trains,  the location
        of the limestone handling and  grinding system,
        and notes indicating extra work which must be
        done at the power plant (such  as relocation of
        tanks, buildings, railroad tracks, fences,
        miscellaneous equipment,  etc.)

  With this input information, the M.  W. Kellogg Estimating
  Department prepared capital estimates for each of
  the 13 power plants.   The estimates  include major
  equipment as well as  site preparation, steel structures,
  buildings, piping,  electrical,  instruments, insulation
  and paint, subcontracts, construction costs, procurement,
  engineering, central  staff, sales tax, insurance,  start
  up cost, contractor overhead and profit, and construction
  interest.*
* Due to the nature of the task,  the overall accuracy of
  the estimates is expected to be about 30-35% with the
  probability of underrun being very small.

                          93

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B.   Computerized Estimates

     1.  Wet Limestone Scrubbing Cost Model'
         The M.W. Kellogg model for wet limestone scrubbing
         was developed in a report entitled  "Evaluation of
         R & D Investment Alternatives for SO  Air Pollution
                                             J^
         Control Processes."  This report was performed
         under EPA Contract 68-02-1308, Part I, Task 7(3, pp.  83-98).
         The model was programmed on the Wang 720 computer
         to facilitate evaluation of different process
         variables.  For a description of the process, refer
         to Section IV in this report.  The  process flow sheet
         and equipment list are included in  the Appendix
         of this report.  Equations used in  this model are
         listed in the following sections:
         a.  General Equations

             (1) SF = (MW) (BtuAWH)  (Wt.FR.SULF)          M LB/HR
                              (BtU/LB)

             (2) SO, Emission = (2) (SF) (106)            LB S02/MMBtu
                 (No Control)   (MW)  (Btu/KWH)

             (3) S02 Emission = d-SO2 Removal)/SO_ Emission\LB S02
                 (After Scr)                    \No Control  /MMBtu

             (4) Annual Power = (MW)  (8.76)  (LF)            MMKWH/YR
                 Generated
              (5) RB = 1 +
              (6) GB = £W§   (MW)  (0.00034196)          MACFM/Boiler
                 Note: If GB is  given, the program uses it.
                                  94

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    (7) TB = GB/550                  NO. Scr. Trains/Boiler
        (Note:  If TB is fraction or 1, use  1 train;
                If TB is > 1, use next  larger integer number)
    (8) GT = GB/TB

    (9) GP =  £GB

        BOILER GEN. CAPACITY;
                   <50
                 50-100
                101-200
                201-500
                   >500
                  New

b.  Capital Cost Equations
             NA
                                               MACFM/Train

                                               MACFM/Plant
                                        3.5
                                        3.0
                                        2.5
                                        2.25
                                        2.0
                                        1.0
                     r
(1)  EC = !>~  (TB-RB)  1041 (GT/550)0'5 + 408 (GT/550)
         n=l         L
    +  238 RP (GP/3,300)0'5 + 201 (SF/28)0'5
                                                         0'9
    (2)  ES = 1680 (SF/28)

        P = 5,000
                         0.9
                                               $M
                                 \0.5
                           ISOf^l     (l-ls)   5M
         •W
    (4)  L = 0.39 (EC) + 0.18 (ES)

    (5)  M = 0.82 (EC) + 0.09 (ES)
                     ,6
    (6)  T = 170
            'SP\°-'
             28 j
(1-IS)    (If required)
$M

$M
    (7)  BARC = 1.15 (EC + ES + M)  + [P + 1.43 (L)]F + T
        (If required)                               $M
                         95

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    (8) TPI = 1.12 (1.0 + CONTIN) BARC
                                                         $M
    (9) TCR - (1.03 + CONST INT) TPI + 0.8  TO-CO
              (1+P) +0.4 ANR
   (10) $/KW
           TCR
           MW
   (11) $/MMBtU/H
                TCR (10°)
                MW (BtU/KWH)
c.  Operating Cost Equations
    (1) AL = 600 CL-LF  (SF/28)
    (2) AA = 0.43 CA  (SF/28)
    (3) AW = 230 CW-LF  [(GP/3,300) +  (SF/28)]
    (4) AF = 1,800 CF-LF  (GP/3,300)
    (5) AE = CE-LF  [213  (GP/3,300) +  35  (SF/28)]
    (6) ASL = 2210 (CSL)  (LF)  (SF/28)  (1-Is)
(7) ANR
                                       ASL
    (8) TAG • 0.237 TPI +2.1 TO-CO  (1+F) +  1.04  ANR
    (9) Mills/KWH =
                       TAG
   (10) $/MMBtu
                MM KWH/YR

               Mills/KWH (105)
                  BtU/KWH
     $M




     $/KW



$/MMBtu/HR
d.
     $M/YR


     $M/YR


     $M/YR


     $M/YR


     $M/YR


     $M/YR


     $M/YR


     $M/YR


 Mills/KWH


   «/MMBtu
Economic Factors Used for the Wet Limestone Model
Fraction S02 Removal                            0.90
Purchased price of limestone  ($/T)              4.00
Purchased price of ammonia  ($/T)              50.00
Purchased price of water  ($/M GAL)              0.20
Purchased price of fuel oil  ($/MMBtu)           0.80
                              96

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    Purchased price of electricity (Mills/KWH)     8.00

    Average hourly wages per Gulf Coast ($/HR)     7.00

    Total number of operators                      8.00

    Construction interest (Fraction)                0.10

    Contingency (Fraction)                          0.00

    Location factor                                1.52

    Load factor (Fraction)                          0.70

    Sludge disposal cost ($/T)                      1.50


e.  Nomenclature - General and Fixed Capital Investment


GP        Total flue gas from plant                MACFM

GT        Maximum flow of gas into each venturi
          (Maximum value of GT = 550)              MACFM

GB        Total flue gas from one boiler           MACFM

NA        Number of boilers/plant
TB        Number of scrubbing trains/boiler

SF        Maximum flow of sulfur into the control
          unit                                   M LB/HR
LF        Load factor of the power station

E         Major equipment cost
          (Material and subcontract)                $M

M         Other material costs (piping,
          instruments, electrical, civil etc.)      $M
L         Direct field labor costs                 $M

C, S      Letters follows E, M'and L
          C refers to chemical process type
          equipment
          S refers to solid handling equipment
P         The total cost of the settling pond
          (Material and total labor)

T         Thickener cost if required (subcontract) $M
RB        The retrofit difficulty factor of a
          boiler
RP        The retrofit difficulty factor of all
          scrubbing equipment which is not in
          parallel trains.  Assume to be equal to
          the highest RB
F         Location Factor

Is        Sludge pond indicator (Is=  1  for large pond;

          Is= o for small pond and  thickener)

                         97

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CONST INT    Construction Interest
   CONTIN    Contingency
   BARC      Bare cost of control unit
   TPI       Total plant investment
   TCR       Total capital required

   Nomenclature - Operating Cost
                                         $M
                                         $M
                                         $M
   AL
   AA
   AW
   AF
   AE
   ASL
   ANR

   CL
   CA
   CW
   CF
   CE
   CSL
   TO
   CO
   TAG
Total annual cost of limestone           $M/YR
Total annual cost of ammonia             $M/YR
Total annual cost of process water       $M/YR
Total annual cost of fuel oil            $M/YR
Total annual cost of electricity         $M/YR
Total annual cost of sludge disposal     $M/YR
Summation of annual costs of chemicals,
utilities, etc.                          $M/YR
The purchase price of limestone          $/T
The purchase price of ammonia            $/T
The purchase price of process water      $/M GAL
The purchase price of fuel oil           $/MM Btu
The purchase price of electricity        Mills/KWH
Cost of sludge disposal                  $/T
Total number of operators
The direct cost of operating labor       $/HR
Total annual production cost             $M/YR
                            98

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Wellman-Lord/Allied Cost Model
The M.W. Kellogg model on  stack  gas  scrubbing using
the Wellman-Lord/Allied process  was  also  derived from
the report entitled "Evaluation  of R &  D  Investment
Alternatives for SO^. Air Pollution Control  Processes" (3 , pp. 110^129).
For a description of the process, refer to  Section IV
in this report.  The process  flow sheets  and equip-
ment lists are given in the Appendix of this report.
The equations used in the  model  which was also programmed
on the Wang 720 computer are  given in the following sections:
a.  General Equations

    (1) SF =  (MW)  (BtU/KWH)  (WT.FR.SULF)            LB/HR
                      (BtU/LB)

    (2) S02 Emission =  (2)  (SF)  (106)              LB  SO2/MMBtu
        (No Control)    (MW)  (BtU/KWH)

    (3) S00 Emission =  (1-S00 Removal)  /SO_  Emission\  LB  SO,
          2,                 i           I  z          1  _ £
        (After Scr.)                    \NO  Control /  MMBtu

    (4) Annual Power = MW(8.76)  (LF)                MM KWH/YR
        Generated

    (5) RB = 1.0 + [, ^X . .  RBASE - Ij
                   3'5   L
=&£ 1
 \J\Wn /
     (6) GB =       (MW)  (0.00034196)                 MACFM/Boiler
             \J\Wn /
        Note:  If  GB  is  given,  the program uses it.

     (7) TB = GB/550                       No.  Scr.  Trains/Boiler
         (Note: If  TB  is  fraction or 1,  use 1  train;
          if TB is  > 1,  use  next larger  integer no.)
                         99

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(8)  GT = GB/TB

(9)  GP =   IGB

The following table is used  for

   PLANT GEN. GAP: MW
b.  Capital Cost Equations
              NA
(1)  EA
              n = 1
                       [~
<50
50-100
101-200
201-500
>500
New
3.5
3.0
2.5
2.25
2.0
1.0
                    (TB.RB)  726  (GT/550)
                                        0'5
                                              MACFM/Train

                                              MACFM/Plant
        639  (GT/550)°'9Jn  + 119 RP  (GP/3300)0'5

        + N7  [l33  (S7/7)0'5 + 127  IF  (S7/7)0'6]
                                                $M
    (2) ES =N7[209  (S7/7)005 +  618  (S7/7)0'6

        + 157  (S7/7)0'9]                            $M
    (3) EP = N28 [525  (S28/28)0'5 +  380  (S28/28)0'6

        + 86  (S28/28}°-7+ 306  (S28/28)0'8

        + 519  (S28/28)°'9J                         $M
                         100

-------
    (4) ER = 998  (SF/28)0'5 +  287  (SF/28)0'6
        + 683  (SF/28)0'9                            $M
    (5) M = 0.429 EA + 0.742  ES  +  0.827 EP + 0.772 ER  $M

    (6) L = 0.224 EA + 0.310  ES  +  0.433 EP + 0.623 ER  $M

    (7) BARC = 1.15 (E+M) +  1.43 (L) (F)             $M

    (8) TPI = 1.12  (1.0 + CONTIN)  BARC             $M

    (9) TCR = (1.03 + CONST  INT) TPI  + 0.8 TO -CO (1+F)
        + 0.4 ANR                                   $M
   (10) $/KW =                                      $/KW

   (11) $/MMBtu/HR =   R°                        $/MM Btu/HR
c.  Operating Cost Equations

    (1)  AS = 28.2 CS-LF  (SF/28)                    $M/YR
    (2) AAO = 0.04 CAO-LF  (SF/28)                   $M/YR
    (3)  AN = 1460 CN-LF  (SF/28)                    $M/YR
    (4) AFA = 1.24 CFA-LF-IF  (GP/3300)              $M/YR
    (5)  AE = [154 (GP/3300)  +  79  (SF/28)]  CE-LF   $M/YR
    (6)  AH = 5430 CH-LF  (SF/28)                    $M/YR
    (7) ACW = [856 (GP/3300)  +  19,900  (SF/28)]  CCW-LF $M/YR
    (8)  AW = 64  (SF/28) CW-LF                      $M/YR
    (9)  AF = 1,800  (GP/3300) CF-LF                 $M/YR
   (10) ASC = 95.4 (SF/28) VSC-LF                   $M/YR
   (11) APS =37.3 (SF/28) VPS-LF                   $M/YR
   (12) ANR = AS + AAO + AN + AFA  +  AE  +  AH + ACW
        + AW + AF + ASC + APS                      $M/YR
                         101

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    (13) TAG = 0.237 TPI + 2.1.TO-CO (1+F) + 1.04 ANR $M/YR

                        TAP
    (14) Mills/KWH = 5555^5                      Mills/KWH

    ,15,
d.  Values of Economic Factors

    Fraction S0_ Removal                           0.95
    RB Max.
    Purchased Price of Na2C03:  CS ($/T)          40.00
    Purchased Price of Anti-oxidant:  CAO ($/T)   40.00
    Purchased Price of Natural Gas:  CN ($/MSCF)   0.50
    Purchased Price of Filter Aid:  CFA ($/T)     50.00
    Purchased Price of Electricity:  CE (Mills/KWH)8.00
    Purchased Price of Steam:  CH  ($/MLB)           0.70
    Purchased Price of Cooling Water:  CCW ($/MGAL)0.02
    Purchased Price of Water:  CW  ($/MGAL)         0.20
    Purchased Price of Fuel Oil:  CF ($/MMBtu)     0.80
    Value of Sulfur Credit:  VSC ($/LT)           10.00
    Cost of Purge Solids Disposal:  VPS ($/T)      1.50
    Location Factor:  F                            1.52
    Load Factor:  LF  (Fraction)                    0.70
    IF (If fly ash present, IF = 1.00)              1.00
    Average Hourly Wages, Gulf Coast:  CO  ($/HR)   7.00
    Total Number of Operators:  TO                16.00
    Construction Interest (Fraction)               0.10
    Contingency (Fraction)                         0.00

e.  Nomenclature - General and Fixed Capital Investment

GP        Total flue gas to control plant          MACFM
GT        Total flue gas to each absorber  train
          (maximum value of GT = 550)              MACFM
GB        Total flue gas from one boiler           MACFM
NA        Number of boilers per plant
TB        Number of absorber trains per boiler

                         102

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  SF


  S7
  S28




  N7



  N28


  E


  M

  L

  A,S,P,R
  F

  LF

  IF



  RB


  RP
Total sulfur flow in flue gas to
control plant

Total sulfur flow in flue gas to
control unit per train of sulfur-
related equipment in absorber and S02
regeneration areas (maximum value of
S7 = 7) .

Total sulfur flow in flue gas to
control unit per equipment train
in the purge/make-up area (maximum
value of S28 = 28)

Number of trains of sulfur-related
equipment in the absorber and SO2
regeneration areas.

Number of equipment trains in the
purge/make-up area

Major equipment cost (direct material
and subcontracts)

Field Materials Costs

Field Labor Costs
Letters following E, M, L

A refers to absorber area

S refers to S02 regeneration area

P refers to purge/make-up area
R refers to S0_ reduction area

No letter following refers to total for
all areas

Location Factor
Load Factor of Power Plant

Particulate index  (IF = 1 if par-
ticulates are present in flue gas.
IF = 0 if particulates are absent)
Retrofit difficulty factor of each
boiler

Retrofit difficulty factor of gas-
related equipment in the absorber area
which is not in parallel trains, i.e.,
the fuel oil system; assumed to be equal
to the highest RB.
M LB/HP
                                                     M LB/HR
M LB/HR
$M

$M

$M
CONST INT   Construction interest
                          103

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CONTIN
BARC
TPI
TCR
Contingency
Bare cost of the control unit
Total Plant Investment
Total Capital Required

$M
$M
$M
Nomenclature - Operating Cost
AS
AAO
AN
AFA
AE
AH
ACW
AW
AF
ASC
APS
ANR
CS
CAO
CN
CFA
CE
CH
CCW
CW
CF
VSC
VPS
TO
CO
TAG
Annual cost of sodium carbonate
Annual cost of anti-oxidant
Annual cost of natural gas
Annual cost of filter aid
Annual cost of electric power
Annual cost of steam
Annual cost of cooling water
Annual cost of process water
Annual cost of fuel oil
Annual sulfur credit
Annual purge solids credit or debit
Summation of annual costs of chemicals,
util., etc.
Purchase price of sodium carbonate
Purchase price of anti-oxidant
Purchase price of natural gas
Purchase price of filter aid
Purchase (or transfer) price of
electricity
Purchase (or transfer) price of steam
Cost of cooling water
Cost of process water
Purchase price of fuel oil
Unit value of sulfur (negative if
credit)
Unit value of purge solids (negative
if credit)
Total number of operators
Unit cost of operating labor
Total annual production cost
$M/YR
$M/YR
$M/YR
§M/YR
$M/YR
$M/YR
$M/YR
$M/YR
$M/YR
$M/YR
$M/YR
$M/YR
$A
$/T
$/MSCF
$/T
Mills/KWH
$/M LB
$/M GAL
$/M GAL
$/MM Btu
$/LONG TON
$/T

$/HR
$M/YR
104

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C.  Comparative Economics of Wet Limestone vs. Wellman-Lord/Allied
    Processes for SO- Removal

    1.  General
        The M.W. Kellogg estimating department prepared capital
        estimates for wet limestone scrubbing for 13 power plants
        in the state of Iowa.  Out of these 8 were selected as
        potential candidates for a scrubbing process.  The others
        were rejected due to either lack of space for installing the
        equipment or due to the small size of the power plants. The
        plants selected as potential sites for scrubbing  facilities
        are the following:

            Des Moines Plant
            Maynard Plant
            Muscatine Plant
            Riverside Plant
            Burlington Plant
            Kapp Plant
            Prairie Creek Plant
            Sutherland Plant

        The estimating department capital cost estimates  for these
        plants ranged from 67.0 to 151.1 $/kw.  The average for
        the eight v?as $84.80/kw.  The cost model for wet  limestone
        scrubbing using RBMAX = 1-0, predicted an average cost of
        $62.30/kw.  It was found that the model using RBMAX =1.7
        and RDACE = 3.5, predicted an average capital investment
        cost of $86.40/kw for the eight plants involved.  This figure
        is almost identical to the capital cost predicted by the
        estimating department.  Incremental capital investment re-
        quired over that which would be required by a new plant is
        $24.10/kw on the average for the eight plants.

        The scrubbing train area required for the Wellman-Lord/
        Allied process is identical to that required by the Wet
        Limestone process for a scrubber capable of processing a
        given quantity of gas.  Also the space required for the
                                 105

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    regeneration, purge/make-up, and SO. reduction areas is
    similar to that required in the Wet Limestone system for
    limestone storage, handling and grinding.  Therefore, the
    assumption was made that the degree of difficulty in re-
    trofitting either process would be the same.  That is,
    if one process would require additional duct work, relocat-
    ion of  buildings, coal piles, railroad tracks or other
    miscellaneous expenses, the other process would require the
    same.

    Using  the computer program for the Wellman-Lord/Allied
    process, the capital investment required for the eight
    plants  (using RBMAV =1.0) ranged from 72.1 to 106.4 $/kw
                    MAX
    with the average being 87.1 $/kw.  Using the program with
          = 1.7 and R _.c_ = 3.5 the computer predicted an
    —MAX
    average cost of 109.8 $/kw.  Therefore, the incremental in-
    vestment for retrofitting the plants is 22.7 $/kw (almost
    identical to that for the Wet Limestone system).

2.  Economic Comparison of the Wet Limestone Process vs. the
    Wellman-Lord/Allied Process

    a.  Basic Assumptions

        Heat Rate = 11,000 Btu/KWH
        HHV       = 10,000 Btu/lb
        TiD
                  = 1.7
                  = 3.5
        F         = 1.52
        LF        =0.70
        CSL       = 1.50/T

        The heat rate of 11,000 Btu/kwh and HHV  (of coal) of
        10,000 Btu/lb were used as they represented the approx-
        imate average values for the eight plants selected as
        scrubbing candidates in the State of Iowa. As noted

                                 106

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    above, the RB    of 1.7 and RfiASE of 3.5 are used to
    calculate the increased cost of retrofitting stack gas
    scrubbing systems into existing plants in Iowa.  The
    location factor (F) of 1.52 represents the ratio of
    Iowa labor cost to Gulf Coast labor cost.  The load
    factor of 0.7 was chosen as a practical average power
    plant load factor, although this may vary from plant
    to plant and from area to area.  The actual load factor
    that a power plant will operate at in a future year is
    difficult to predict because of the uncertainty of
    the rate of population growth as well as that of indus-
    trial growth in the area.  The cost of sludge disposal
    for the Wet Limestone process was assumed to be $1.50/T.
    Other economic factors such as the prices of chemicals,
    utilities and by-products are given in the preceding
    section of this report.

b.  Specific Comparison of the Two Processes

    The following table presents the econonmics of the
    two processes:
$/MMBtu
2%S
PLANT GEN.
CAP. : MW
125
250
500
1000
W.L.*
36.7
34.3
.32.7
31.0
W-L/A**
44.1
37.2
33.5
30.6
4%S
W.L.
43.2
40.5
38.9
37.0
W-L/A
56.4
49.2
45.3
42.4
                                                          6%S
                                                      W.L.   W-L/A
                                                      49.6   68.6
                                                      46.8   61.3
                                                      45.0   57.2
                                                      43.0   54.1
    * Wet Limestone
   ** Wellman-Lord/Allied

    As can be seen from the above table, the Wet Limestone
    process is less expensive to operate than the Wellman-
    Lord process in all cases.  The two processes are
    essentially equal in cost, in plants 250mw in size and
    larger, only when the percent sulfur in the coal is
    very low  (between 1 to 2%).
                          107

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   The  following general  conclusions  can  be  drawn from the
   table  and  also  from the  graph which  is a  plot of C/MMBtu
   vs.  percent  sulfur  in  the  coal with  plant sizes as  para-
   meters.   This graph is noted as  Figure 2.

    (1)  As  expected, the  operating  cost in C/MMBtu drops
        as  the  plant size increases.  For the Wet Limestone
        process using  (4% S coal),  the  cost  drops from 43.2
        C/MMBtu for a  125 mw  plant  to 37.0 C/MMBtu for a
        1,000 mw plant.   The  drop is  even more drastic for
        the Wellman-Lord/Allied process with the cost
        dropping from  56.4 C/MMBtu  for  a 125 mw plant  to
        42.4 C/MMBtu for  a 1000 mw  plant.

    (2)  For a given plant size (in  megawatts), the cost of
        scrubbing  in C/MMBtu  increases  linearly as the %S
        in  the  coal increases.  The scrubbing system cost
        for the Wellman-Lord/Allied system is more  sensi-
        tive to %S in  the coal than is  the Wet Limestone
        scrubbing  system.  For example, a 250 mw power
        plant using the Wellman-Lord/Allied scrubbing  system
        is  estimated to have  an operating cost of 37.2 C/MMBtu
        using 2% S coal and a cost  of 61.3 C/MMBtu using 6% S
        coal.  This represents an  increase in operating cost
        of  6.02 C/MMBtu/%S.  The Wet Limestone scrubbing
        system  for a  250  mw power  plant is estimated to have
        an  operating  cost of 34.3  C/MMBtu using 2% S coal
        and 46.8  C/MMBtu  using 6%  S coal.  This represents
         an  increase in cost of 3.12 C/MMBtu/% S for a given
        plant size.

c.  Detailed Economic  Comparison of the Two Processes
    When Installed on  a 500 MW Power Plant

    (1)  The following table gives a detailed breakdown
         of the capital and operating cost for the two
         processes.
                          108

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                      500 MW
WELLMAN-LORD/ALLIED
2.545%S
f/KW 84.39
Mills AWH 4.04
t/MMBtu 36.72
Capital Costs: MS
EA 9,011
ES 1,968
EP 1,129
ER 1,261
H 7,232
L 3,903
BARC 32,173
TPI 36,034
TCR 42,196
Operating Costa: M$/YR
AS 394.'
AAO 1
AN 255
AFA 25
AE 713
AH 1,330
ACW 146
AW 4
AF 575
ASC -334
APS 20
ANR 3,129
TAC 12,387
SF: Mft/HR 14
TB(No. SCR. Trains) 4
K7 (No . REGEN . Trains } 2
N28 (No. Purge/Make-
up Trains) i
Breakdown of TAC
0.237 TPI 8,540
2.KTO) (CO) (1+F) 593
1.04 ANR 3,254
12,387
5.09%S
113.51
5.66
51.54

9,531
3,936
1,816
1,968
10,030
5,367
43,037
48,202
56,758
790
1
511
25
934
2,660
285
9
575
-668
39
5,161
17,384
28
4
4
1
11,424
593
5 ",367
17,384
MET LIMESTONE
2.545IS
77.37
3.79
34.50

EC 9,402
ES 900
P 106
T 112
7,791
3,829
29,402
32,931
38,683
AL 840
AA 11


777


34
575

ASL 1,160
3,397
11,634
14
4
7,805
296
3,533
11,634
5.09%S
83.07
4.65
42.29

9,461
1,680
150
170
7,909
3,992
30,982
34,700
41,533
1,680
22


875.


50
575

2,320
5,522
14,263
28
4
8,224
296
5,743
14,263
109

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Detailed examination of the table yields the
following conclusions:

(a)   Using low sulfur coal (2.545 %S),  the
     Wellman-Lord/Allied process is just
     slightly more costly than the Wet  Lime-
     stone process (36.72 vs.  34.50 C/MMBtu -
     a difference  of only about 2.2 C/MMBtu).
     Most of the increased cost for the Wellman-
     Lord/Allied process lies  in higher fixed
     capital charges (due to the presence  of
     considerably  more equipment in the regener-
     ation  area, purge make-up  area and S02 re-
    duction area,  than is required in the limestone
     system).  The variable cost of chemicals,
     utilities and waste  disposal are somewhat
     higher  for the Wet Limestone process but
     this is offset by lower labor charges.

    A comparison  of the processes using a
     fairly high sulfur coal (5.09  $3)  gives
    an even larger advantage to the Wet Lime-
     stone process,  its operating  cost  is ex-
    pected to be about 42.29  $/MMBtu vs.51.54
    C/MMBtu for Wellman-Lord/Allied - a diff-
    erence of 9.2  C/MMBtu.  Again,  as with the
    low sulfur case, capital charges on-the
    substantially  higher investment for the
    Wellman-Lord/Allied  process make up the
    difference in  cost.   As previously  in-
    dicated,  the variable cost  of  chemicals,
    utilities  and  purge  disposal is  somewhat
    higher  for the Wet Limestone process, but
    this  is  offset by lower labor charges.

    Now we  can address the problem  of sludge
    disposal cost  for the Wet Limestone process.
               110

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As previously indicated, a cost of $1.50/Ton
of wet sludge (40% solids) was used for the Wet
Limestone sludge disposal cost.  For the 2.545%
sulfur case, a sludge disposal cost of $2.44/Ton
would bring the Wet Limestone process cost up to
a figure equal to the Wellman-Lord/Allied cost
(36.72 C/MMBtu).  For the high sulfur coal
case  (5.09% S) ,  a sludge disposal cost of $3.44/Ton
for the Wet Limestone process would bring its
operating cost up to that of the Wellman-Lord/Allied
process (51.54 C/MMBtu).  It is worthy of note
that it does not appear to be economical or
feasible to pay more than about $1.50/Ton for
sludge disposal as used in the economic calcula-
tions in this study.  The reason for this is the
fact that the use of a  large disposal pond (20
years storage) provides a more viable economic
alternative for sludge  disposal rather than pay-
ing extremely high sludge disposal costs.

For example, using the Wet Limestone process and
2.545% S coal, it is estimated that the use of a
large disposal pond would reduce the operating
cost to 33.02 «/MMBtu vs. 34.50 C/MMBtu when
using a sludge disposal cost of $1.50/Ton.  The
incremental capital investment required for a
plant with a 20 year disposal pond vs. one which
has a small pond and thickener is about $7/kw.

For the 5.09 % S coal case, it is estimated that
the use of a large  (20 year) storage pond would
reduce the operating cost of the Wet Limestone
process to 39.16 C/MMBtu vs. 42.29 C/MMBtu using
a sludge disposal cost  of $1.50/Ton.  The in-
cremental capital investment for installing a
large disposal pond rather than having a small
pond and thickener is about $12/kw for the 5.09
%S case.
                Ill

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     In some power plants,  particularly those located
     in cities,  there simply is no room for a large
     disposal pond.  If this is the case,  one posssi-
     ble alternative would  be to transport the sludge
     out of the  city to an  open area where a large
     pond could  be installed.

(c)   An examination of the  operating cost  for chem-
     icals, utilities, sulfur credit and sludge dis-
     posal (at 5.09 %S coal)  indicates that the most
     significant contribution to operating cost for
     the Wellman-Lord/Allied process is the steam
     cost.   The  most significant contribution to
     operating cost for the Wet Limestone  process is
     the sludge  disposal cost (at $1.50/Ton).   If a
     40% savings in steam could be realized for the
     Wellman-Lord/Allied process using double effect
     evaporators,  the operating cost would drop by
     about 3.1 C/MMBtu to 48.4 C/MMBtu vs.  42.29 <:/
     MMBtu for the Wet Limestone process.

     The cost of electric power is about the same
     for both processes as  is the cost of  fuel used
     for reheat.   For the Wellman-Lord/Allied pro-
     cess,  the costs of filter aid,  cooling water,
     process water,  and the cost for disposal of
     purge solids  are rather insignificant.  The
     sulfur credit of $10/long ton is mildly signi-
     ficant.   If this credit were reduced  to 0,  the
     operating cost for the Wellman-Lord/Allied
     process would rise by  about 2C/MMBtu.

     As previously mentioned, the sludge disposal
     cost for the  Wet Limestone process makes  the
     most significant contribution to the  variable
     operating cost.   The next most important con-
     tribution is  made by the limestone cost.
                     112

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               Fairly insignificant  in the operating cost
               picture are the costs of ammonia and make-up
               water.

3.   Conclusions Regarding Stack Gas Scrubbing as Used in
    the Iowa Study

    a.  Since the Wet Limestone process (with sludge disposal
        at $1.50/Ton) appears to be more economic than the
        Wellman-Lord/Allied process, the costs for this process
        were used in the linear computer program for the Iowa
        study.   From the graph, (See Figure 2), it can be
        seen that for a 250 mw power plant (note that the
        average size of the eight power plants in Iowa
        is about 203 mw) that the operating cost is about 40.5
        C/MMBtu using 4% S coal and 43.6 £/ MMBtu using 5% S
        coal.

    b.  If the Wellman-Lord/Allied process costs were used,
        then the cost for stack gas scrubbing would be about
        49.2 C/MMBtu using 4% S coal and 55.2 C/MMBtu using
        5% S coal.
                                113

-------
                                              Figure 2
                             SCRUBBING SYSTEM COST VS. % SULFUR IN COAL
60
50

40
30
20
                                PLANT GENERATING CAPACITY: MW 125
               WELLMAN-
              LORD/ALLIED
                                                                                        WET
                                                                                      LIMESTONE
HR = 11,000 BTU/KWH
HHV = 10.000 BTU/LB
RBMAX  =1.7
R BASE = 3-5
F = 1.52
LF = 0.70
CSL = $1.50/TON
                                                 L
                                          3             4
                                        % SULFUR IN COAL
             6

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                     VII.  LINEAR PROGRAMMING MODEL
A.  A Brief Discussion of Linear Programming

    1.  Linear Programming

        Linear programming deals with the problem of allocating
        limited resources among competing activities in an optimal
        manner.  The  great variety of situations to which linear
        programming can be applied is indeed remarkable.  Linear
        programming uses a mathematical model to describe the pro-
        blem of concern.  The adjective "linear" means that all the
        mathematical functions in this model are required to be
        linear functions.  The word "programming" is essentially a
        synonym for planning.  Thus, linear programming (LP in
        brief) involves the planning of activities in order to obtain
        an " optimal" result  (according to the mathematical model
        describing the problem of concern) from all feasible alter-
        natives.

        A typical LP problem can be described mathematically as
        follows:
        Find X, , X~, X-, ... , X  that maximizes or minimizes the
        linear function
             Z = cnX, + c_X- + c,X_ +  ... + c X
                  11    I i    J j          nn
        Subject to the restrictions
             allXl + a!2X2 +  ''' + anVbl
             a21Xl + a22X2 +  ••' + a2nVb2
             amlXl + am2X2 + ' ' ' + amnVb;
                                          m
                                     115

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         and   X1>0, X2>0 ..., Xn>0

         where a. , b., c. are given constants.

    The function being maximized or minimized is called the
    objective function and the restrictions are called the
    constraints or restraints.

    If a real world problem can be defined in terms of such
    equations then this will be a linear programming model of
    the problem.  For further discussion  on linear programming
    the reader should refer to any text book on operations re-
    search  (19) .

2.   Simplex Method

    The "Simplex Method" is the method for solving any linear
    programming problem.  This is an algebraic procedure which
    progressively approaches the optimal solution through a well
    defined iterative process until optimality is finally reached.
    Even though the method is straightforward  it requires con-
    siderable time if done manually.  The difficulty in finding the
    solution is greatly  increased with number of constraints and
    the number of unknowns entering the LP model.  However, an
    LP model can be easily solved using an electronic computer.

 3.  Special Types of Linear Programming Problems

    As pointed out in the above discussion on linear programming,
    LP can be applied to different practical problems.  One of the
    common  and widely used applications of LP is to  transportation
    or transhipment problems.  A typical transportation problem
    determines optimal  shipping patterns between different sources
    of supply and points of demand under the constraints of de-
                                  116

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    mand and supply.

4.   Handling of Non-Linear Relationships

    Certain functions related to economic decisions are non-
    linear in nature and not directly applicable to linear
    programming treatment.  Some common examples include the
    capital cost versus capacity of a process unit in any
    investment model, costs functions for shipping a product
    by common carrier, etc.  Many of the non-linear relation-
    ships can be adequately represented using linear segments
    approximating the desired curve.  There are techniques for
    handling non-convex functions in an LP environment and the
    ones most commonly used are:

                 Separable programming
                 Integer programming
                 Mixed integer programming

5.   Kellogg's Experience With Linear Programming

    Over the years, the M. W. Kellogg Company has utilized linear
    programming and other related computer techniques in process,
    economic and cost studies for clients within the process
    industry.  Some of these applications have included

                 Refineries
                 Gasoline Blending Model
              -  Kellogg1s Olefin Plant LP System
                 Fuels Refinery System

    The proper selection and application of computer software for
    compiling and solving LP problems requires a thorough know-
    ledge of the problem and the sensitivity of the needs of the
    user.  The major aspects of the LP software package include
                                 117

-------
        MAGEN and MPSX.

        MAGEN (6) is a software system developed by Haverly Systems,
        Inc. to generate a matrix.  Through classification of related
        variables and restrictions, LP problems can be generalized
        by type, thus making it easy for the user to supply pertinent
        data in a convenient tabular form and define his own terms.

        The IBM  (MPSX) Mathematical Programming System Extended  (7)
        is a set of procedures containing linear programming optimi-
        zation codes from which a user can select a strategy for
        solving an LP problem.

        KELPLANS, Kellogg Planning and Analysis Systems, are the ef-
        fective resultants of process engineering and computer appli-
        cations toward a realistic optimum solution to complex economic
        problems.

B.  The Definition of the Problem in Terms of an LP model

    The earlier sections have already discussed the objective of this
    study in great detail.   Stated again, we want to find the minimum
    overall system cost ($/day)  for different transportation patterns,
    for various  S02 emission specifications,  under the constraints of
    the system.   These constraints are developed by generating suit-
    able equations containing variables that relate the different
    parameters of the system.  The mathematical model will use the
    values of the constants for the equations from the input data
    tables given in Section III.   As stated in Section III of this re-
    port there are so many  variables affecting the overall cost of
    controlling  S02 emissions from power plants in the State of Iowa
    that a mathematical model (LP model in this case)  has to have a
    certain convenient nomenclature to cover all the possible variables
    to be determined in the objective function (costs)  and the con-
    straints.
                                    118

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1.  Objective of the LP model

    The purpose of the model is to minimize total system costs
    by determining the optimal sources and distribution routes
    for the coal needed by various power generation stations in
    the State of Iowa while complying with the effluent specifi-
    cations established by the EPA.  It is anticipated that
    some of the coal may require treatment to reduce the emission
    of S02, and, if so, the number and locations of the treatment
    plants will be determined.  It is also expected that stack
    gas scrubbing may be required to meet the more stringent
    regulations (particularly if low sulfur coal is limited).
    If so, the number and locations of the scrubbing systems
    will be determined.

2.  Basic Assumptions of the Model

    The model is based upon the following assumptions:

       a.  The energy requirement of each power generating plant
           (expressed as MMBtu/day) must be satisfied.

       b.  Assuming total conversion of sulfur in the coal to
           SO-' emissions must not exceed a certain specifi-
           cation in pounds of SO? per MMBtu of energy require-
           ment.

       c.  The emission specification can be attained by selec-
           tive use of low sulfur coal, by reducing the sulfur
           content of the coal (cleaning), and/or by treating
           the exhaust gases to reduce the emission of SO.
           (scrubbing).
                                119

-------
    The cleaning process removes most of the pyrites
    which contain proportionately more sulfur than
    does the coal.  The ash content of the coal is reduced
    somewhat, and the heat content somewhat increased.


    The scrubbing process removes most (90%) of the
    S0_ in the exhaust gases.  The wet limestone scrub-
    bing process costs were used in the model because
    they appeared somewhat lower than Wellman-Lord/Allied
    costs (based on the assumptions made).  However, the
    program can be adapted to use other scrubbing costs.


d.  Coal may be shipped by rail or (where applicable) by
    barge on the Mississippi and/or Ohio  rivers.  Where
    appropriate rail facilities are available for storage
    and switching of coal cars, "unit trains" may be used
    for rail shipments at rates significantly below
    normal freight costs.


e.  Specification of the availability of coal  (in tons/
    day) at any source  (mine) is optional.


f.  The KELPLANS investment type LP model  (5) is used to
    simulate the scrubbing and cleaning facilities.  It
                         120

-------
            uses continuous and integer variables to:

                 (1)   represent the non-linear function that
                      relates the cost of scrubbing with the
                      size of the equipment by means of two
                      linear segments.  (The cost of cleaning
                      is given to be linear with respect to
                      the equipment size).
                 (2)   bound the size of the scrubbing as well
                      as cleaning systems between an upper and
                      lower limit.  (See Figures 3 and 4).


3.   Nomenclature

    As stated above all the variables that affect the overall cost
    are generated using a convenient scheme.  Each category of
    variable that affects the system is called a class.  The fol-
    lowing discussion explains how the different variables are
    generated.

         a.  Location Codes:  each geographic point in the model
             has been assigned a two character location code as
             shown in page 129.  For example, the code "ME" rep-
             resents Madisonville, Ky where there is a coal mine.
             The notation "(ML)" represents the set of all coal
             mines:  MA, MB, ..., and MH.  Similarly, the symbol
             "(DL)" represents the set of all power plants and
             "UD" represents other locations.  "(PL)" is the
             set of all locations referenced and is equivalent
             to the logical union of (ML) U (DL) U  (<|>L) .

             On page 131 under class SL, a list of the possible
                                 121

-------
    power plants which can have scrubbing is given.
    DF, for example, is a power plant in Clinton where
    scrubbing facilities are permitted.  The last three
    classes (M, M2 and M3) on page 131 are used to simplify
    coding of the mixed integer programming in the model
    and are not important to this discussion.

    On page 132, class CL is the list of possible cleaning
    locations.  Class N is used to simplify the mixed
    integer programming in the model.

    Class CST on page 133 represents all the cost factors
    affecting the problem.

b.  Vectors:  the vectors are the columns of the LP model
    and represent the unknowns in the problem.  The vectors
    are:

         W(ML)  (DL) = tons per day of' uncleaned coal ship-
         ped directly from a mine to a power plant.

         WS(ML)(SL) = same as W(ML)(DL) but scrubbed at
         power plant  (SL) .

         X(ML)(PL)(DL) = tons per day of uncleaned coal
         shipped from a mine to a power plant via some
         intermediate point, except where the inter-
         mediate point is  at the plant or the mine.
         XS(ML)(PL)(SL) = same as X(ML)(PL)(DL) but
         scrubbed at power plant  (SL)

         Y(ML)(CL)(DL) = tons per day of coal  shipped
         from mine to transfer point  (CL),  cleaned at
                       122

-------
transfer point and shipped to a power  plant.

YS(ML) (CL) (SL) = same as Y(ML) (CL) (DL) , but
scrubbed at power plant  (SL)

SSl(SL) =  size of scrubbing system installed  at
location  (SL) in MMBtu/day.

SS2(SL) =  variable used in KELPLAN's model to
simulate the scrubbing system at  location  (SL).
It is equivalent to  [(MMBtu/day)(% Sulfur)].

S(M)(SL) = variable used in KELPLAN's  model to
simulate the scrubbing system at  location  (SL).

CC1(CL) =  size of cleaning plant  installed at
location  (CL) in tons per day of  coal  feed.

C(N)(CL) = same as S(M)(SL) but for cleaning
system.

Q(DL) = energy deficiency, MMBtu/day

T(CST) = total cost for each cost  factor  (pit-
head, freight , etc) in $/day.

IN12(SL) or IN23(SL)  = scrubbing plant indicator
(integer variable).  If equal to zero,  plant does
not exist; if equal to one, plant exists  (at  SL).

IM12(CL) = cleaning plant indicator (integer
variable).  If equal to zero, plant does not
exist; if equal to one, plant exists (at CL).

RIIS = right hand side which shows capacities,
availabilities, etc.  in units appropriate to
                123

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                  the various equations.

                  The above notation W(ML)(DL) implies one vari-
                  able for each combination of mine and power
                  plant.

4.   Input Data to Solve the LP Problem

    The input data and the various decision variables that will
    affect the solution of the problem are input to the model
    in the form of tables.  Section III has discussed in depth
    the sources and validity, etc. of the data that was used for
    this study.  The following discussion covers the different
    tables that are used in the solving of the model.  The model
    for Iowa consists of 18 power plants, 8 mines, 28 possible
    transfer plants, 8 possible scrubbing locations, and 8 pos-
    sible cleaning locations.  There are 142 constraints irows),
    6705 variables, and 24 integer variables.

    On page 133, table RAW summarizes the properties of unwashed
    coal; table WASHED, the properties of clean coal.  Freight
    handling facilities available at each location are summarized
    in table LOAD  (page 134).

    The data shown on page 135 consists of the  energy requirements
    in table DEMAND:  the sulfur specifications  (different cases)
    are listed in table SPEC; and the miscellaneous economic  fac-
    tors are shown in table ECON.

    On pages 136 and 137, the distances between various locations are
    shown.  Since all locations are accessible to rail lines, the
    table of rail distances  forms a symmetric matrix, half of which
    is entered as a triangular table.  For locations on the Mississ-
    ippi or Ohio rivers, a separate table  (table RIVERD) of dis-
                                 124

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    tances by river has been supplied  (page 338 ).

    Table COSTSCR consists of the coordinates (MSC,SIZ) used to
    represent the non-linear cost of scrubbing by the use of two
    straight lines.   (See Figure 3).

    Likewise, t?ible COSTWAS consists of the coordinates (MS,SI)
    used to represent the cost of cleaning by one straight line
    (page 138 ) .   See Figure 4.

C.  Solution Using KELPLANS

    KELPLANS uses MAGEN(6) to generate the matrix and MPSX(7) to
    run the linear programming step.

    Once the input data matrix has been generated, the MPSX is
    performed in two distinct steps.  First the problem is opti-
    mixed while considering all integer variables as being con-
    tinous:  "continous optimum".  At the continuous optimum, the
    integer variables which denote the existance of cleaning or
    scrubbing facilities  (0=No ,  l=Yes)  may be at some intermediate
    value (such as 0.6).  This implies that the cleaning and scrub-
    bing costs may be understated and plant sizes may be below the
    feasible minimum.

    In the second step, the mixed integer program (MIP)  is involved
    to find the best solution where all of the Yes/No variables are
    either 0 or 1.  The optimal  integer solution must result in a
    cost equal to or greater than the continuous optimum solution.

    Maximum flexibility exists  in the model.   The list of power
    plants, mines, transfer points,  scrubbing and cleaning locations
    can be increased or decreased by adding or deleting the number
    in the respective class.   For example, if Salix,  Iowa (DN)  is
    not a convenient location for cleaning, in class  CL (page   ),
                                125

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DN must be deleted.  Now, if Lansing, lov/a  (DD) is a good
location for scrubbing, DD should be included in class SL
(page 131).

The same flexibility exists in the tables.  For example, if
the demand at DA has changed to 20,000 in table DEMAND
(page 135) the 18,684 for DA should be changed accordingly.

Similarly, flexibility exists in the model regardina all
other variables.  Coal mine properties, coal costs, mine
capacities, washed coal properties, transportation possi-
blities and costs, milages, and economic factors can all
be changed as necessary to evaluate the system.
                            126

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<
Q
£
S
                                       Figure 3

                     WET LIMESTONE SCRUBBING COST VS. CAPACITY
                                                        $/D = 2.82 (MM BTU/D)°J*X
	REPRESENTS TWO
STRAIGHT LINES USED
BY COMPUTER
                                 $/D = 0.0315 (MM BTU/D)(%S
                                            5%S
HR= 11.000BTU/KWH
        100
  200
(52,800)
                                              300
  400
(105,600)
500
  600
(158,400)
                          PLANT CAPACITY: MW (MM BTU/DAY)

-------
                                                        Figure 4

                                           COAL CLEANING COST VS. CAPACITY
      400
      300
$/D = $1.90 (TPD)
no
oo
      200
      100
                MIN = 7200 TPD
                                            I
                              MAX = 240,000 TPD
                          i       I       i
                                          100,000
                               200,000
                                                COAL FEED: TPD

-------
HAVERLY SYSTEMS INC LP/360 74163   VERS. J  MCO. 3

*	             IOWA F  MODEL
SYSTEM DATE - 3/01/74
TIME   REAL 00<00:00    TASK OOiOOsOO

TIME   REAL 00:00:00TASK 00:00:00
GENERATE
                                                                                     TIME   REAL 00:UP:00   TASK 00:00:00
     DICTIONARY
CLASS OL
*
DA
OB
DC
nn
OE
DF
DC
OH
DI
nj
OK
OL
OH
ON
no
H> OP
w oo
* CR
LIST OF POWER PLANT LOCATIONS
AMES (AMES MUNICIPAL PLANT)
AMES (lOfcA ST U PLANT)
KONTPELIER
LANSING
OUDUOUE
CL INTON
CCPAR RAPIDS (PRAIRIE CREEK)
CFOAP OAPIOS (SIXTH ST)
f«APSHALLTCWN
BCTTENDORF
COUNCIL BLUFFS
DES MOINES
WATFKLQO
SAL IX
FnOVVlLLE
Bit" LIN", TON
MUSCATINE
PFllA

CLASS ML
*
MA
MB
MC
MO
ME
MF
MG
MH
CLASS OL
*
PA
Pfl
LIST OF COAL MINE LOCATIONS
FREOFRICK IOWA
LFCN IOWA1
OGDEN IOWA
MAP TUN IIIINini<;
MAOISONVILLE KY
HANflA WYOMING
COLSTRIP MONTANA
LIST OF OTHER POSSIBLE TRANSFER POINTS
PAPUCAH KY
GORHAM ILLINOIS
CLASS PL
                    POSSIBLE  LOCATIONS  FOR  TRANSFER  POINTS
             ML)    (»   I  AT  ANY  MINE
            .1DL )	L>.).   J  AT  AMY  P.UWEB—PlAfll	

-------
               IQL)    (»   I  AT  ANY  OTHER  SPECIFIED LOCATION
OJ
o

-------
CLASS SL
*
OF
OG
ni
OJ
DL
DM
OP
LIST OF POSSIBLE SCRUBBING LOCATIONS


no
CLASS M
*
I
2
3

CLASS M2
*
12
LIST OF VARIABLES USED IN SCRUB. MODEL


LIST OF INTEGER VAR. SCRUB. MODEL
23
M
W CLASS M3
* M
SI
S2
LIST OF VARIABLES COST SCRUB. KODEL


-------
        CLASS CL

       	ON	
LIST CF POSSIBLE  CLEANING LOCATIONS
            OP
            HA
            MB
            MC
            MO
            PA_
            P'D
        CLASS N
       	1	
        CLASS R

            1
            2
LIST OF RIGHT HAND  SIDES
U>
to

-------
    CLASS CST
               LIST  OF POSSIBLE COSTS
        PTT  PITHEAD COST	
        FRT   FREIGHT  COST
        ASH   ASH  DISPOSAL COST
        _SC I	SC PIJB_CP.SJ	
        SC?  SCRUB  COST
        WSH  WASHING PLANT COST
       _P.E_F_P FFUSF _p ISPflSAl COST
        STO   STORAGE  / LOADING / UNLOADING  COSTS
        6RN   BROWNOUTS
OAT A	       	
    TABLE RAW
                PROPERTIES OF UNWASHED COAL
                                              CAP
MA
MB
MC
MO
KF
F-1 MF
j*\ MG
MH






14.
12.
13.
14.
14.
8.
4.
10.



8
2
9
a
4
2
& 	
ASH
SUL
BTU
CST
CAP

5
if
6
3
4
0
0
0
.3
.9
. 1
* 1
.9
.3
.8
10.038 6.25
9.676 6.25
10.184 6.25
11.951 6.70
	 ll.P01__6..7.0_
10.506 4.20
11.460 5.00
8.79C 3.60
50.
50.
50.
50.
50.
8.
8.
0.
= ASH IN WT PCT
= SULFUR IN KT PCT


HEAT
CUST
MINE

CONTENT IN MBTU/LB
AT SHIPPING POINT IN I/TON
CAPACITY IN MTON/OAY IBLANK=NO LIMIT 1


    TABLF WASHEP
               PROPFRTTCS OF Cl FAN COAL
*

*
*
*
*
MA
MB
MC
MD
MF

ASH
7.9
7.0
7.5
7-0
7.2
LOSS
SUL
3.5
1.9
4.5
2.7
5UL.DTU =
= KT PCT
BTU LOSS
11.033 20.0
10.65C 20.0
11.166 20.0
i?.<>05 ?n.n
12.340 20.0
SANE AS TABLE


RAW
LOSS ON CLEANING

-------
TABLF LOAD
*
*
RJ
*
OH
DC
no
DE
OF
OG
OH
DI
OJ
OK
01
DM
DN
no
PP
DO
DP
*
MA
MB
*C
M MO
£ MF
•* HP
MG
MH
*
PA
PB


SUMARIZES LOADING / UNLOADING FACILITIES
AT EACH LOCATION (l=YES) 	
IL LNIT BARG
1
1
1
1
1
	
1
11
1

1
1 1
11
1 1
L 1
L 1
1 1
RAIL > CONVENTIONAL RAIL CAR
UNIT = UNITS TRAIN
BARG - BARGES


-------
TABLE DEMAND
           REQUIREMENT IN MMBTU/OAY
*
04
DB
DC
no
OF
OF
OG
PH
01
OJ
OK
OL
OM
ON
00
DP
DO
OR
TABLE
*
*
1
M 2
OJ 3
ui «
18684.
1299«.
17726.
20023.
24504.
59525.
64862.
ft4S37.
43219.
67512.
33461.
07017.
31570.
1I56P.?.
25A08.
51307.
31488.
18259.
SPEC
SPFC IN LBS S02 / MPBTU
MUX
20.
5.
3.1
1.2

TABLF
*
*
*
PAIL
UNIT
BAtG
*
ASHE
PF.FIJ
STOB
*
FINV
flNV
ECON
ECONOMIC FACTORS
TON TPM TPH
t/TON S/T/M S/T/HR
O.C28
O.OC5
0.006
1.
0.31
C.30
1.0
1.0
CBPN
10000.

-------
TABLE RROIST
           DISTANCES BY RAIL
*
DA
DB
DC
DO
DE
or,
DH
ni
DJ
DK
DL
DM
nn
DP
oa
DR
MA
MB
MC
MO
MF
MF
MR
MH
V-- PA
*
OJ
OK
01.
OH
DN
on
00
OR
MA
MC
MO
ME
MF
y.H
PA
PR
	 3
167
244
177
187
105
105 	
1P3
155
36
P5
192
111
2C1
173
83
117
125
22
5C2
5S6
795
943
915
549
463
01
146
192
59
48
229
67
157
138
74
73
148
59
4UO
574
832
980
951
527
441

187
244
177
187
105
105
37
183
155
36
85
192
111
2C1
173
83
117
125
22
502
596
795
943
915
549
463
OJ
318
178
130
375
127
91
30
155
133
203
205
361
455
958
1106
109U
403
322

190
109
48
82
82
150
16
302
182
134
385
111
75
14
139
117
Ifl7
209
371
4A5
«J42
1090
1018
418
332
OK
161
237
83
197
281
288
225
191
244
133
539
633
640
788
870
5C6
500

81
142
170
170
188
174
355
247
140
390
277
265
204
3C5
203
353
266
535
629
995
1143
1019
5fl2
496
DL

107
208
75
165
168
47
81
89
58
466
560
801
94 9
950
513
427


61
89
89
140
93
331
201
94
344
196
184
123
224
202
272
199
454
548
971
1119
1043
501
415
DM

250
115
150
120
122
121
196
107
488
582
877
1025
V60
532
446


82
82
150
32
342
206
134
379
159
123
62
187
165
235
209
393
487
982
1130
1094
440
354
ON

283
370
380
255
289
297
170
622
716
682
859
707
669
583


5
68
78
260
124
52
297
107
98
68
135
113
183
127
436
530
900
1048
1012
480
394
DC


90
97
28
6
82
133
413
507
837
985
1025
460
374



68
78
260
124
52
297
107
98
68
135
113
183
127
436
530
900
1048
1012
480
394
OP


61
118
96
166
223
338
432
921
1069
1110
385
299
       00
             DR
                     MA
                            MR
MC
                                          MO
MF.
                                                        MF
OR

-------
MA
MB
MC
MO
ME
MF
pr,
MH
PA
PB
*
MH
PA
PR
103
173
195
365
479
978
1076
lOfiO
432
14ft
MG
1034
1374
1288
34
110
105
441
535
	 B65_
1013
997
408
402
MH
1456
1370
76
139
407
501
flll
<579
1031
454
368
PA
100
145
438
532
884
1032
1039
485
399
PB


518
612 145
773 1179 1273
921 1347 1421 557
929 1429 1503 887
565 54 85 1226 	
479 40 IBS 1140



-------
 TABLE  RIVERO
            DISTANCES BY RIVER
       DC    nn    DF    OF    oj    OP    DO    PA    PB
*
oc
00
OE
DJ
DP
DO
PA
1R8
1C8
48
18
67
17
516

80
140
170
255
205
704

60
90
175
125
624

30
115
AS
564


85
35 50
534 449


499
 PB     366   574   494   434   404   319   369   130
 TABLE  COSTSCR
            INCLUDES PARAMETERS NEEDED TO
            MODEL THE NON-LINEAR PART OF
            THE CCST OF SCPUBBING
      MSC	  SI2	
 1    5581.     -M2CC.
_2_ 23400.     -79200.
 3   40740.    -1584CC.
 TABLE  CCSTHAS
            INCLUDES PARAMETERS NEEDED TO
*
*
(jj
CO

1
2
MODEL
MS
136BO.
456000.
THE COST OF
SZ
-7200.
-24000C.
WASHING


-------
                              VIII.   REFERENCES
 1.   1972  Keystone  Coal Industry Manual ,  Mining Information Services
     of the McGraw-Hill Mining Publications,  1972.

 2.   Gates Engineering Company,   Feasibility  Study  of  Iowa Coals,
     May,  1974.

 3.   M. W. Kellogg  Company,  Evaluation of R & D Investment Alternatives
     for SO  Air Pollution Control Processes, Draft Report, January,  1974.
 4.   M.  W.  Kellogg Company,  Evaluation of the Controllability of Power
     Plants Having a Significant Impact on Air Quality Standards,
     February,  1974.

 5.   Schneider, L. W. ,  Mixed Integer Programming Applied to Investment
     Type LP's, NPRA-CC-71-98,  November, 1971.

 6.   Haverly Systems,  Inc.,  LP/360 Programming System, Section I - Mixed
     Integer Programming,  May,  1971.

 7.   International Business  Machines, Mathematical Programming System
     Extended (MPSX) ,  Program Number 5734-XM4, February, 1971.

 8.   Rand McNally, Handy Railroad Atlas of The United States, 1973.

 9.   National Coal Association, Steam-Electric Plant Factors, 1973
     Edition for 1972 Data,  January, 1974.

10.   Bernard, J. H., Babcock & Wilcox Company, A Steam Generator Designer
     Looks at Western Coals , Technical Paper, October 7, 1971.
                                     139

-------
11.   Attig,  R. C., Duzy,  A.  F., Babcock & Wilcox Company, Coal Ash
     Deposition Studies and  Application to Boiler Design, Technical
     Paper,  April 22,  1969.

12.   Duzy, A.  F., Babcock &  Wilcox Company, Fusibility-Viscosity of
     Lignite Type Ash, ASME  Publication, August 18, 1965.

13.   Olson,  W. T., Universal Oil Products Company, Conditioning Fly Ash
     to Improve Electrostatic Precipitator  Performance, Power Engineering,
     April,  1972.

14.   McKinney, B. G.,  Little, A. F., Hudson, J. A., Tennessee Valley
     Authority, The TVA Widow's Creek Limestone Scrubbing Facility,
     Paper Prepared for Flue Gas Desulfurization Symposium, May, 1973.

15.   Calvin, E. L., Catalytic, Inc., A Process Cost Estimate for Limestone
     Slurry Scrubbing of Flue Gas, January, 1973.

16.   Archer, W. E., Consultant, Joy Manufacturing Company, Electrostatic
     Precipitator Conditioning Techniques, Power Engineering, December,
     1972.

17.   The Problem Beyond Disposal, Electrical World Engineering Management
     Conference on Waste Disposal in Utility Environmental Systems,
     McGraw-Hill, October, 1973

18.   Duzy, A. F., Rudd, A. H., Babcock  & Wilcox Company, Steam Generator
     Design Considerations for Western Fuels, Technical Paper, April, 1971.

19.   riillier, F. S., Lieberman, G. J.,  Introduction to Operations Research ,
     Holder-Day Inc.
                                     140

-------
                                IX. GLOSSARY

acfm      :   Flow rate in actual cubic feet per minute (measured
             at flowing conditions)

Btu       :   Energy measured in British Thermal Units

load
^actor    :   Fraction which multiplied by peak generating capacity
             gives the average generating capacity for the year.

csa       :   Cross-sectional area

cu yd     :   Volume measured in cubic yards

ESP       :   Electrostatic Precipitator

°F        :   Temperature in degrees Farenheit

FPC       :   Federal Power Commission

ft        :   Linear measure in  feet

fps       :  Velocity in feet per second

sq ft     :   Area in square feet

gal       :   Volume measured in U.S. Gallons  (7.481 gallons = one
             cubic foot)

gpm       :  Flow rate measured in gallons per minute

grain     :  Mass equal to 1/7000 of one pound

hr        :  Time in hours
                                   141

-------
"H20        :  Pressure in inches of water  (27.72  inches of water =
              1 pound per square inch)

 kv         :  1,000 volts

 kw         :  Power measured in kilowatts  (1 kw = 1,000 watts)

 kwh        :  Energy measured in kilowatt-hours

 long ton   :  Mass  (1 long ton = 2240 pounds
 (LT)

 M          :  1,000 units  (e.g. M$ = thousands of dollars)

 MM         :  1,000,000 units

 mw         :  Power measured in megawatts  (1 mw = 1,000,000 watts
              or  1,000 kilowatts

 ppm        :  Concentration measured in  parts per million  (by  volume)

 psia       :  Pressure in pounds per square inch  absolute

 psig       :  Pressure in pounds per square inch  gage

 Ib/hr      :  Flow rate measured in pounds per hour

 scfm       :  Flow rate in standard cubic  feet per minute  (measured
              at  60°F and 14.7 psia)

 sec        :  Time in seconds

 ton        :  Mass  (1 ton = 2,000 pounds)

 tph        :  Flow rate measured in tons per hour
                                     142

-------
X.  APPENDICES
     143

-------
      APPENDIX A



POWER PLANT INPUT DATA
           144

-------
                           Table  5
                      Power Plant Input Data
                         Des Moines Plant
                    Iowa Power  & Light  Company
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
   Des Moines,  Ipwa
   325
Coal Data
          (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
Iowa, Illinois,  Wyoming
   Rail, Truck
  16.9
  15.2
   4.1  Max.  Monthly Avg.  4.7
  9395
 Plant Operating Data in  1972
 Plant Average Heat Rate,  Btu/KWH_
 Plant Average Load Factor,  %
11,156
  58.5
                              145

-------
                                                                                         Des  Moinea  plant
Boiler Data(2)
  Turbo-Generating Capacity,  MM
  Coal Consumption, TPH
  Air Flow
       Total Air, SCFM
       Excess Air, %
  Flue Gas Flow, ACFM
  Flue Gas Temperature, °F
  Boiler Efficiency, %
  Total Hours Operation During 1972
  Average Capacity Factor, %
  Year Boiler Placed in Service
  .Remaining Life of Unit, Yrs.
     (based on   40  year life)
  Related to Generator No.
  Served by Stack No.
                                                Table
                                           Power Plant Input Data
Boiler No. 6
Boiler No.7
Boiler No.8
Boiler No.9
136 Mw 'for
Stand-by
oil)
87,500
7
253,000
330
83.2
6,881
52
1964
30
1-5
1
4 boilers
24
52,000
10 - 30
173,000
330
82.3
7,398
52
1938
4
1-5
2
through common headers
24
52,000
10 - 30
173,000
330
82.3
6,425
52
1949
15
1-5
2

24
52,000
10 - 30
178,000
350
82.3
7,210
52
1950
16
1-5
3

-------
                                                                                         Des Moines plant
                                                Table
Boiler Data
           (2)
  Turbo-Generating Capacity,  HW
  Coal Consumption, TPH
  Air Flow
       Total Air, SCFM
       Excess Air, %
  Flue Gas Flow, ACFM
  Flue Gas Temperature, °F
  Boiler Efficiency, %
  Total Hours Operation During 1972
  Average Capacity Factor, %
  Year Boiler Placed in Service
  Remaining Life of Unit, Yrs.
    (based on   40  year life)
  Related to Generator No.
  Served by Stack No.
awer Plant Input
Boiler No. 10
70
42
79,500
23
283,000
343
86.5
6,134
80
1954
20
6
4
Data
Boiler Nc. il
110
50
109,000
19
343,000
290
88.4
7,854
71
1964
30
7
5
                                                                              Boiler Nc.
Boiler No.

-------
                                                                                     Des Moines  piant
Boiler Data(Cont'd)
  Stack Height, Ft.  above grade
  I.D. of Flue at Top, Ft.
  Distance to £ of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
     Table  5
Power Plant Input Data
Boiler No.  6
       138
        15
        80
     None
        24
Boiler No. 7
	250

	105


 Cyclones
	65

         18
Boiler No.8
        250
         10
        105
Cyclones
        65
         18
2oiler No. 9
        250
        105
 Cyclones
	65
         18
  (1)  Coal quality and heating value are average"values for .coal burned in 1972.
  (2)  Operating data are at 100% load

-------
                                                                                         Des Moines  piant
vo
                                                    Table
Boiler Data(Cont'd)
  Stack Height, Ft. above grade
  I.D. of Flue at Top, Ft.
  Distance to £ of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
                                               Power Plant Input Data
                                               Boiler No. 10     Boiler No. 11
                                                     250
                                                      12
                                                      23
                                                     ESP
                                                    99.3
                                                      12
 250
  10
  14
 ESP
99.3
  12
           Boiler No.
                                                                                             Joiler No.
       (1)  Coal quality and heating value are average values for .coal burned in 1972.
       (2)  Operating data are at 100% load

-------
                                                                                  Des Moines	Plant

                                            Table    6
                                       Stack Gas Scrubbing System
                                               Boiler        Boiler       Boiler       Boiler       Boiler
Scrubbing System                                No.7.9       No.9         No.10        No.11        No.
   No. Scrubbing Trains Required                   1            1            1            1         	
   Train Size(1)                                   IV           VI            V          III         	
   Train Type
      Wet Limestone                                C            C            C            A         	
      Wellman-Lord                                 A            A            A            A         	
Limestone System
   Max. Design Capacity :  tph                   48.1

Wellman-Lord/Allied System
   Sulfur Flow : Ib./hr.                        18,000
   Regeneration Area : No. Trains  Required         2
                       Size<2>                      I
   Purge/Make-up Area : No. Trains  Required
                       Size<2>
   SO? Reduction Area : No. Trains  Required
                       Size <«
 (1)   Refers to standard size scrubber modules.
 (2)   Refers to standard size modules.

-------
                           Table   7
                      Power Plant Input Data
                           Maynard Plant
                      Iowa Public Service Co.
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
    Waterloo.  Iowa
 107
Coal Data
         (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
    Illinois
    Rail
  12.0
  11.0
   2.5
10,861
Max. Monthly Avg.  2.8
Plant Operating Data in 1972
Plant Average Heat Rate, Btu/KWH   12,293
Plant Average Load Factor, %    	
   40.0

-------
                                                                                            Maynard
Plant
                                                   Table  7
   Boiler Data(2)
     Turbo-Generating  Capacity, MW
     Coal Consumption, TPH
     Air Flow
          Total Air, SCFM
          Excess Air,  %
to    Flue Gas Flow, ACFM
     Flue Gas Temperature,  °F
     Boiler Efficiency,  %
     Total Hours Operation  During 1972
     Average Capacity  Factor,  %
     Year Boiler Placed  in  Service
     Remaining Life of Unit, Yrs.
       (based on  40   year life)
     Related to Generator No.
     Served by Stack No.
>wer Plant Input
Boiler No. 9


6
55,900
118
102,000
400
83
2,286
18.4
1937
3
4
2
Data
Boiler No. 10


6
52,200
95
95,000
393
83
721
5.7
1943
9
4.5
2
Boiler No. I I
12
Boiler No. 12
25
6 0(§ai)fi
52,900
95
84,000
403
83
2.838
25.2
1947
13
62.900
35
101.000
300
85
4.054
26.0
1951
17
* 6
1
2

-------
                                                                                            Maynard    plant
                                                   Table
Ul
OJ
Boiler Data(2)
  Turbo-Generating Capacity,  MW
  Coal Consumption, TPH
  Air Flow
       Total Air, SCFM
       Excess Air, %
  Flue Gas Flow, ACFM
  Flue Gas Temperature, °F
  Boiler Efficiency, %
  Total Hours Operation During 1972
  Average Capacity Factor, %
  Year Boiler Placed in Service
  Remaining Life of Unit, Yrs.
     (based on  40   year life)
  Related to Generator No.
  Served by Stack No.
                                              Power Plant Input Data

                                                Boiler No. 14     Boiler No.
                                                   58
                                                   24
                                                   132,300
                                                        25
                                                   373,000
                                                       325
                                                        87
                                                     8,085
                                                        66.6
                                                      1958
                                                        24
Boiler No.
Boiler No.

-------
                                                                                         Maynard     Plant
                                                   Table
Ul
                                              Power Plant Input Data
Boiler Data(Cont'd)
  Stack Height, Ft.  above grade
  I.D. of Flue at Top, Ft.
  Distance to £ of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency* %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
                                              Boiler No. 9
                                                  220
Boiler No. 10
     220
                                              691  Q ••  above  basement floor
                                                Cyclones
                                                    88
                                                    12
Cyclones
     88
     12
Boiler No-. 11     Boiler No. 12
                 Common  stack
    220        for  Units  9,10,12
                      23'  3'
 Cyclones
      88
     12
                 69'  0"  above
                 basement floor
None
 12
       (1)  Coal quality and heating value are average values for .coal burned  in  1972.
       (2)  Operating data are at 100% load

-------
                                                                                           Mavnard
                                                                                                      Plant
tn
ui
Boiler Data(Cont•d)
  Stack Height, Ft. above grade
  Z.D. of Flue at Top, Ft.
  Distance to ft of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
                                                    Table  7
                                               Power Plant Input Data
                                                                Boiler Mo.
Boiler No. 14
  250	

   30	


  ESP	
   99	

   12
Boiler No-.
toiler No.
        (1)  Coal quality and heating value are average values for .coal burned in 1972.
        (2)  Operating data are at 100% load

-------
                                                                                    	Maynard	Plant

                                                Table     8
                                           Stack Gas Scrubbing System
                                                    Boiler       Boiler       Boiler        Boiler       Boiler
    Scrubbing System                                 No.9,10,12   No.11        No.14         No.           Ho.
       No. Scrubbing Trains Required                  3-            1          —L
       Train Size(1)                                 IV         VIII_       III.
       Train Type
          Wet Limestone                               C            C
          Wellman-Lord                                A            A

    Limestone System
,_,      Max. Design  Capacity i tph                    7t9
m
    Wellman-Lord/Allied System
       Sulfur Plow  i Ib./hr.                        303°
       Regeneration Area  : No. Trains Required         x
                           Size<2)
       Purge/Make-up Area  : No. Trains Required
                           Size<2>
       SOa  Reduction Area  : No. Trains Required
                           Size<2>
     (1)    Refers  to  standard size scrubber modules.
     (2)    Refers  to  standard size modules.

-------
                           Table   9
                      Power Plant Input Data
                         Muscatinp Plant-
                Muscatine Municipal Electric Plant
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
      Muscatine, I.owa
      117
Coal Data
          (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
      Illinois
      Barge, Rail
      16.4
      10.2
    3.0  Max. Monthly Avg.  3.2
10,899
Plant Operating  Data  in  1972
Plant Average Heat  Rate, Btu/KWH
Plant Average Load  Factor, %
11,214
  57.9
                                157

-------
                                                                                           Muscatine
                                                                                                      Plant
                                                 Table
 Boiler Data(2)

   Turbo-Generating Capacity, MW


   Coal Consumption, TPH


   Air Flow


        Total Air,  SCFM


        Excess Air, %
ml
%  Flue Gas Flow, ACFM


   Flue Gas Temperature, °F


   Boiler Efficiency, %


   Total Hours Operation During  1972


   Average Capacity Factor,  %

   Year Boiler Placed in Service


   Remaining Life of Unit, Yrs.
     (based on  40  year life)


   Related to Generator No.


   Served by Stack  No.
•wer Plant Input
Boiler No. 5
7.5 (Standby)"
4.5
Data
Boiler No. 6
12.5 (Peaking
7

30
25,000 (Est.)
360
80
2000
50
1941
7
5 or 6
30
40,000 (Est)
380
80
4000
50
1946
12
5 or 6
2(3) l(3)
Boiler No. 7
tuase
22 Load)
11.5
Boiler No. 8
(BasS
84 Load)
84
130,000 Est
20
70,000 (Est.)
340
84
7300 (Est.)
70
1958
24
7
3<3)
11.5
251,000
322
90.3
8000
90
1969
35
8
4

-------
                                                                                        Muscatine
                                                                                                   Plant
vo
Boiler Data(Cont'd)
  Stack Height, Ft. above grade
  I.D. of Flue at Top, Ft.
  Distance to ft of Stack Breeching, Ft.
    above grade (Grade = 95'-0")
                (Basement FloorF
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
                                                  Table  9
                                             Power Plant Input Data
                                             Boiler No. 5
                                                   (3)
                                               115
                                                86
Boiler No.6
   115(3)
     7
    86
                              Boiler No-. 7
                                115
                                   (3)
                                                                              6'-8'
                                120
                               boiler No.8
                               320
                             8'-6"
                               200
                                            Mech.  (May, 1975) Mech(May,1975) Mech(ESP May,1975)  ESP
                                                                                80 & 90
80
                                            Varies
80
                Varies
                                            20-26(P8Ikt8g)  20-26 Peaking)
                                     95
     (1)   Coal quality and heating value are average values for .coal burned in 1972.
     (2)   Operating data are at 100% load
     (3)   Units 5, 6,  and 7 will be served by one  new stack, 220' high.

-------
                                                                                    Muscatine
                                                   Plant
                                            Table
     10
                                       Stack Gas Scrubbing System
Scrubbing System
   No. Scrubbing Trains Required
   Train Size(1)
   Train Type
      Wet Limestone
      Wellman-Lord

Limestone System
   Max. Design Capacity : tph

Wellman-Lord/Allied System
   Sulfur Flow : Ib./hr.
   Regeneration Area : No. Trains Required
                       Size
                           (2)
   Purge/Make-up Area : No. Trains Required
                       Size
                           (2)
   SO2 Reduction Area : No. Trains Required
                       Size
                           (2)
Boiler
 No. 5, 6, 7
 VII
 9.0
3610
                                                  VI
                                                  VI
                                                  VI
 (1)   Refers to standard size scrubber modules.
 (2)   Refers to standard size modules.
Boiler
 No.8
Boiler
 No.
                                                                                       Boiler
                                                                                        No.
Boiler
 No.

-------
                           Table   11
                      Power Plant Input Data
                         Riverside Plant
                  Iowa-Illinois Gas  &  Electric Company
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
B ettendorf.  Iowa
     222
Coal Data
          (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
     Illinois
     Rail
    16.8
     8.7
     2.6
  10,420
Max. Monthly Avg.  2.9
Plant Operating  Data  in  1972
Plant Average Heat  Rate, Btu/KWH_
Plant Average Load  Factor, %    	66 .2
  12,671
                             161

-------
                                                                                            Riverside
Plant
                                                    Table  11
    Boiler Data(2)
      Turbo-Generating Capacity, MW
      Coal Consumption, TPH
      Air Flow
           Total Air, SCFM
           Excess Air, %
H
to     Flue Gas Flow, ACFM
      Flue Gas Temperature, °F
      Boiler Efficiency, %
      Total  Hours Operation During 1972
      Average Capacity Factor,  %
      year Boiler Placed in Service
      Remaining  Life of Unit, Yrs.
         (based on  40   year life)
      Related to Generator No.
      Served by  Stack No.
>wer Plant Input
Boiler No. 5
16
13.1
47,000
5
99,100
373
84.2
5,295
40.9
1937
3
3
5
Data
Boiler No. 6
20
14.8
52,000
5
103,000
375
83.8
7,419
54.4
1944
10
3
6
Boiler No, 7
22
14 '.4
51,000
5
91,000
300E8t
85.0
6,941
54.0
1949
15
4
9
Boiler No. 8
22
14.4
51,000
5
91,000
300 ESt
85.0
7,281
56.0
1949
15
4
9

-------
                                                                                           Riverside   plant
                                                   Table  11
                                              Power Plant Input Data
U>
Boiler Data*2*
  Turbo-Generating Capacity, MW
  Coal Consumption, TPH
  Air Flow
       Total Air, SCFM
       Excess Air, %
  Flue Gas Flow, ACFM
  Flue Gas Temperature, °F
  Boiler Efficiency, %
  Total Hours Operation During 1972
  Average Capacity Factor, %
  Year Boiler Placed in Service
  Remaining Life of Unit, Yrs.
     (based on   40  year life)
      Related to Generator No.
      Served by Stack No.
                                                Boiler No.  9
                                                     140
                                                    61.5
                                                  221,000
389,000
    297
  87.4
 7,074
  62.8
  1961
                                                      27
               Boiler No.
Boiler No.
                                                Boiler No.

-------
                                                                                      Riverside  plant

                                               Table  11
                                          Power Plant Input Data
Boiler Data(Cont'd)                        Boiler No.5      Boiler Mo.C      Boiler No7       aoiler No.8
  Stack Height, Ft.  above grade          	144       	144        	346         	346
  I.D. of Flue at Top, Ft.                     8'-6"           B'-6"            13'-4"           13'-4"
  Distance to £ of Stack Breeching, Ft.  	     	     	     	
    above grade  (Grade  = El 95'-6")
  Fly Ash Removal Equipment
      Type                               	ESP       	ESP        	ESP         	ESP
      Design Efficiency,                 	99.1            99.1             99.2             99.2
  Scheduled Maintenance Shutdown
      Interval, Months                       12 - 14          12 - 14           12 - 14         12 - 14
      Duration, Weeks                          2-4            2-4            2-4            2 - A
   (1)  Coal quality and heating value are average'values for .coal burned in 1972,
   (2)  Operating data are at 100% load

-------
                                                                                     Riverside  plant
Boiler Data(Cont'd)
  Stack Height, Ft.  above grade
  I.D. of Flue at Top, Ft.
  Distance to £ of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
     Table  11
Power Plant Input Data
Boiler No.9      Boiler No.
    346
                                                                            Boiler No
Toiler No.
    ESP
   99.2
12 - 14
 2-4
   (1)  Coal quality and heating value are average values for .coal burned in 1972.
   (2)  Operating data are at 100% load

-------
                                                                                         Riverside
                                                                             Plant
                                                   Table   12
                                              Stack Gas Scrubbing System
                                                       Boiler       Boiler
       Scrubbing System
          No. Scrubbing Trains Required
          Train Size(1)
          Train Type
             Wet Limestone
             Wellman-Lord
                          No.5,6
                             1
                             V
No.7,8
  1
Boiler
 No .9
   1
  II
Boiler
 No.
Boiler
 No.
01
       Limestone System
          Max. Design Capacity
    tph
       Wellman-Lord/Allied System
          Sulfur Flow : Ib./hr.
          Regeneration Area :  No. Trains Required
                              Size
                                  (2)
          Purge/Make-up Area : No.  Trains Required
                              Size
                                  (2)
          S<>2 Reduction Area
:  No. Trains  Required
Size<2>
       (1)   Refers to standard size scrubber modules.
       (2)   Refers to standard size modules.
                          7020
                           III
                                                          IV
                                                          IV

-------
                           Table   13
                      Power Plant Input Data
                         Burlington Plan*-	
                      Iowa-Southern Utilities Co.
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
       Burlington,  Iowa
       212
Coal Data
          (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
                                          Illinois
       Rail
        20.5
         8.2
     2.6    Max. Monthly Avg.  3.O
10,136
Plant  Operating  Data  in  1972
Plant  Average Heat  Rate, Btu/KWH   10,084
Plant  Average Load  Factor,  %    	59.2
                               167

-------
                                                                                          Burlington   Plant
                                                  Table  13
                                             Power Plant Input Data
CO
Boiler Data(2)
  Turbo-Generating Capacity, MW
  Coal Consumption, TPH
  Air Flow
       Total Air, SCFM
       Excess Air, %
  Flue Gas Flow, ACFM
  Flue Gas Temperature, °F
  Boiler Efficiency, %
  Total Hours Operation During 1972
  Average Capacity Factor, %
  Year Boiler Placed in Service
  Remaining Life of Unit, Vrs.
     (based on  40   year life)
  Related to Generator No.
  Served by Stack No.
Boiler No. 1
	212
	89.2

   348,000
	20
   644,000
	261
	86.4
     8,180
	59.2
      1968
        34
                                                                Boiler No.
Boiler No.
                                                                                                 i*-»iler No.

-------
                                                                                       Burlington  plant
vo
Boiler Data(Cont'd)
  Stack Height, Ft. above grade
  Z.D. of Flue at Top, Ft.
  Distance to £ of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
                                                  Table  13
                                             Power Plant Input Data
                                             Boiler No. 1      Boiler No.
                                                   306        	
Boiler No.
P.iler No.
                                                11' 9'
                                                 •V1401
                                                  ESP
                                                   98.5
                                                   12
     (1)  Coal quality and heating value are average values for .coal burned in 1972.
     (2)  Operating data are at 100% load

-------
                                                                                   Burlington
                                                                            Plant
                                            Table
                                                     14
                                       Stack Gas  Scrubbing System
                                               Boiler       Boiler
Scrubbing System
   No. Scrubbing Trains Required
   Train Size{1)
   Train Type
      Wet Limestone
      Wellman-Lord
                          No.l
                           III
No.
Boiler
 No.
Boiler
 No.
                                                                              Boiler
                                                                               No.
Limestone System
   Max. Design Capacity :
    tph
                          12.8
Wellman-Lord/Allied System
   Sulfur Plow : Ib./hr.
   Regeneration Area : No. Trains Required
                       Size
                           (2)
   Purge/Make-up Area : No. Trains Required
                           .(2)
   S02 Reduction Area
 Size'
: No.  Trains  Required
 Size<2>
                         5480
                                                   V
 (1)   Refers to standard size scrubber modules.
 (2)   Refers to standard size modules.

-------
                           Table   15
                      Power Plant Input Data
                      	Kapp Plant	
                      Interstate Power Company
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
   Clinton,  Iowa
   237
Coal Data
          (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
                                           Illinois
   Barge,  Rail
  11.8
  11.0
   3.1 Max. Monthly Avg.3.3
10,981
Plant Operating  Data  in 1972
Plant Average Heat  Rate,
Plant Average Load  Factor, %
10.465
  59.8
                               171

-------
                                                                                                 Kapp    Plant
H
-J
NJ
   Boiler Data
               (2)
Turbo-Generating Capacity, MW
Coal Consumption, TPH
Air Flow
     Total Air, SCFM
     Excess Air, %
Flue Gas Flow, ACFH
Flue Gas Temperature, °F
Boiler Efficiency, %
Total Hours Operation During 1972
Average Capacity Factor, %
Year Boiler Placed in Service
Remaining Life of Unit, Yrs.
   (based on   40   year life)
Related to Generator No.
Served by Stack No.
                                                   Table  15
>wer Plant Input
Boiler No. x
19
11.1
45,000
25
80,000
355
84.9
6406
52
1947
13
1
1
Data
Boiler No. 2
218
92
410,000
18
634,000
289
87.0
8070
71
1967
33
2
2
                                                                             Boiler No.
Boiler No.

-------
                                                                                      Kapp
                                                                                                Plant
Boiler Data(Cont'd)
  Stack Height, Ft. above grade
  I.D. of Flue at Top, Ft.
  Distance to ft of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
     Table  15
Power Plant Input Data
Boiler No.i      Boiler No. 2
     210
      25
     None
         (3)
245
                       13
 37
ESP
                     98.0
             Boiler  No.
toiler No.
   (1)  Coal quality and heating value are average values for .coal burned in 1972.
   (2)  Operating data are at 100% load
   (3)  A new ESP for No.I  will  be  on  stream in early  1975.

-------
                                                                                     K*pp
                                                  Plant
                                            Table
   16
Scrubbing System
   No. Scrubbing Trains Required
   Train Size(1)
   Train Type
      Wet Limestone
      Wellman-Lord
                                       Stack Gas  Scrubbing System
                                               Boiler       Boiler
                                                 No.l          No.2
VIII
                         Boiler
                          No.
                        Boiler
                         No.
Boiler
 No.
IV
Limestone System
   Max. Design Capacity : tph

Wellman-Lord/Allied System
   Sulfur Flow  : Ib./hr.
   Regeneration Area : No. Trains Required
                       Size<2>
   Purge/Make-up Area : No. Trains Required
                       Size
                           (2)
   S02 Reduction Area  : No. Trains Required
                       Size
                            (2)
17.4
6780
 III
                                                   IV
  IV
 (1)    Refers  to  standard size scrubber modules.
 (2)    Refers  to  standard size modules.

-------
                           Table   17
                      Power Plant Input Data
                        Prairie Creek  Plant
                      Iowa Electric Light & Power Co.  &
                      Central Iowa Power Cooperative (Units  1,2,3)
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
Cedar Rapids,  Iowa
        245
Coal Data
         (1)
Source
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
        Illinois
        Rail
        16.9
         8.5
         2.5  Max. Monthly Avg.  3.1
    10,473
Plant Operating Data in 1972
Plant Average Heat Rate, Btu/KWH
Plant Average Load Factor, %
    11.031
        53.5
                               175

-------
                                                                                             Prairie Creekpiant
                                                    Table  17
     Boiler  Data(2)


      Turbo-Generating Capacity, MH


      Coal  Consumption, TPH


      Air Flow


            Total  Air, SCFM


            Excess Air, %
H

0^     Flue  Gas Flow, ACFN


      Flue  Gas Temperature,  °F


      Boiler Efficiency, %


      Total Hours Operation  During 1972


      Average Capacity Factor,  %


      Year  Boiler Placed in  Service


      Remaining Life of Unit, Yrs.
         (based on 	year life)


      Related to Generator No.


      Served by Stack No.
iwer Plant Input
Boiler No. 1
23.5
12.5
48,200
25


344
83
5,831
47.9
1950
16
1
1
Data
Boiler No. 2
23.5
12.5
48,200
25


344
83
5,970
51.1
1950
16
2
1
Boiler No. 3
49.5
25.5
104,200
22
183,000
313
85
8,010
60.8
1958
24
3
2
Boiler No. 4
149
62
266,600
20
448,000
284
87
7,388
59.4
1967
33
4
3

-------
                                                                                  Prairie Creek  Plant
Boiler Data(Cont'd)
  Stack Height, Ft. above grade
  I.D. of Flue at Top, Ft.
  Distance to ft of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
        Table   17
   Power Plant  Input Data
   Boiler No. 1     Boiler No. 2
         180
180
          16
 16
          80
 80
Multiple Cyclones  Multiple Cyclones
          85              85
          12
 12
 Boiler No-. 3
     180
	13
     115
                 ESP
                  98.6
      12
 Boiler No.4
     200
	13
      35
                      MCTA
                                                                (3)
                       80
      12
  (1)  Coal quality and heating value are average values for .coal burned in 1972.
  (2)  Operating data are at 100% load
  (3)  A new ESP for Unit 4 will be on stream in October,  1974.

-------
                                                                                    Prairie  Creek
                                                                                                  Plant
                                                 Table   18
     Scrubbing System
        No. Scrubbing Trains Required
        Train Size*1'
        Train Type
           Wet Limestone
           Wellman-Lord
                                      Stack  Gaa Scrubbing System
                                               Boiler        Boiler
                                                No.l. 2       No.3
                                                  IV
                                                  C
                                                  fmft^m
                                                  A
                                                                               Boiler
                                                                                No. 4
                                        Boiler
                                         No.
Boiler
 No.
               IV
H
-J
00
Limestone System
   Max. Design Capacity :  tph
18.7
     Wellman-Lord/Allied System
         Sulfur Flow  :  Ib./hr.
         Regeneration Area  : No. Trains Required
                            Size
                                 (2)
         Purge/Make-up Area
                      :  No.  Trains  Required
                       Size<2)
   SO? Reduction Area :  No.  Trains  Required
                       Size<2>
                                                6450
                                                III
                                                       IV
                                                       IV
      (1)    Refers  to standard  size scrubber modules.
      (2)    Refers  to standard  size modules.

-------
                           Table  19
                      Power Plant Input Data
                         Sutherland    Plant
                      Iowa Electric Light & Power Co.
General Plant Design Data
Plant Location
Plant Capacity, MW
No. of Boilers
No. of Generators
Marshalltown, Iowa
   157
Coal Data
Source
          (1)
Method of Transportation

Moisture, %
Ash, %
Sulfur, %
Heating Value, Btu/lb.
Rail
    16.0
    11.7
     2.8  Max. Monthly Avg.  3.2
10,124
Plant Operating Data in 1972
Plant Average Heat Rate, Btu/KWH_
Plant Average Load Factor, %
11,470
    73.5
                             179

-------
                                                                                              Sutherland  plant
                                                    Table  19
00
o
Boiler Data(2)
  Turbo-Generating Capacity, MW
  Coal Consumption, TPH
  Air Flow
       Total Air, SCFM
       Excess Air, %
  Flue Gas Flow, ACFM
  Flue Gas Temperature, °F
  Boiler Efficiency, %
  Total Hours Operation During 1972
  Average.Capacity Factor, %
  Year Boiler Placed in Service
  Remaining Life of Unit, Yrs.
     (based on  40   year life)
  Related to  Generator No.
  Served by Stack  No.
»wer Plant Input
Boiler No. 1
37.5
21
76,500
22
137,000
325
85
8,424
76.6
1955
21
1
1
Data
Boiler No. 2
37.5
21
76,500
22
137,000
325
85
7,920
71. 5
1955
21
2
2
Boiler No. 3 Boiler No.
81.6
42
160,000
16
269,000
335
88
7,752
81.4
1961
27
3
3

-------
                                                                                         Sutherland  plant
                                                    Table  19
CO
Boiler Data(Cont'd)
  Stack Height, Ft. above grade
  I.D. of Flue at Top, Ft.
  Distance to £ of Stack Breeching, Ft.
    above grade
  Fly Ash Removal Equipment
      Type
      Design Efficiency, %
  Scheduled Maintenance Shutdown
      Interval, Months
      Duration, Weeks
Power Plant
Boiler NoJ.
190
81
133'
MCTA
80
12
3
Input Data
Boiler No. 2
190
81
133'
MCTA
80
12
3
                                                                                 Boiler, No. 3
                                                                                     190
                                                                                  10'-6"
                                                                                     156'
MCTA
 80
                                                                                      12
             Boiler No.
       (1)   Coal quality and heating value are average values for .coal burned in 1972.
       (2)   Operating data are at 100% load
       (3)   New  ESP's  are being installed on all boilers by early 1975.

-------
                                                                                         Sutherland
                                                                                                   Plant
                                                  Table
                                                          20
      Scrubbing System
         No. Scrubbing Trains Required
         Train Size(1)
         Train Type
            Wet Limestone
            wellman-Lord
                                       Stack Gas  Scrubbing System
                                               Boiler       Boiler
                                                 No.l         No.2
                                                    A
                                                    A
                                                                VI
Boiler
 No.3
    i
  tv
                                                                                              Boiler
                                                                                               No.
Boiler
 No.
CO
to
Limestone System
   Max. Design Capacity :  tph                    13.3

Wellman-Lord/Allied System
   Sulfur Flow : Ib./hr.                          4980
   Regeneration Area :  No. Trains Required      	1_
                             Size
                                  (2)
         Purge/Make-up Area  : No. Trains Required
                             Size
                                  (2)
         S<>2  Reduction Area
                      :  No. Trains Required
                       Size<2>
       (1)    Refers  to  standard size scrubber modules.
       (2)    Refers  to  standard size modules.

-------
     APPENDIX B
WET LIMESTONE SYSTEM
           183

-------
B
                                                                                                                                                                                 DAT!  .T   CM.
                                                                                                                                                                         ''
                                                                         \ 84
                                                                                                                                                                                                    DMAWMl 9fc,
                                                                                                                                                                                                                     THE M  W  KELLOGG COMPANY
                                                                                                                                                                                                                            •  •> Pmm«  KCOtFOtATIO

-------
                                                                                                                      ^ AX»OX*7
                                                                                                                                                      < rt/vfj? wtr-ffr
 B
11X17
                                       185

                                                                                            PAMICATIOM
                                                                                                              IIMIUKD

                                                                                                              C...T.
                                                                                                                                           THE M W. KELLOGG COMPANY
                                                                                                                                                            Ncotfoum
FIG,

-------
                r-- .
                [UEUOCO]
                  \W/
  Table 21
EQUIPMENT LIST
CLIEMT:   EPA-Iowa Utilities Study
                                                           JOB/EST. NO.
LOCATIOK:
TYPE UNIT; Limestone System;   Area-
                           CLASS    F.J.K.L
                           PAGE NO.;    1     OF
ITEM
NO.
101-F
102-F
103-F
104-F .




101-J
10 2 -J
103-J
104-J
105-J
106-J




101-K




101-L

102 -L





DESCRIPTION
EQUIPMENT TYPE: F-Drums a.nd Tanks
Unloading Hopper
Live Storage Silos
Limestone Slurry Storage TanK
Ef.fluent Slurry Surge Tank


J-Pumps and Drivers

Limestone Slurry Feed Pumps
Raw Water Pumps
Pond Water Recycle Pumps
Effluent Slurry Surge Tank Pumps
Entrainment Separator Pumps
Wash Water Pumps


K-Buildings

Grinding Building


L-Special Equipment

Ball Mills (Incl. weigh feeder, mill, classifiers, slurry
sump, slurry pumps)
Thickener (If required)





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                                        186
ISSUE NO.
DATE
1

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3

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-------
EMC rnoj • »-io
LOCATION:
                        EQUIPMENT LIST


EPA - Tnwa Utilities ^nfly	
                                                            JOB/EST.
UPE UNIT:  Eimestone System;  Rxea 100
                                                   CLASS	V.
                                                   PAGE NO.:   2
                                                                             OF
ITEM
NO.
-V
102 -V
10 3 -V
10 4 -V
105 -V


























DESCRIPTION
EQUIPMENT TYPE: V-Transportation Equip.
feeder '
Tunnel Belt Conveyor
Stacker
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Tripper Belt


























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-------
CMC PHOJ » 9-70
                                 EQUIPMENT LIST
CLIENT:   EPA - Iowa, Utilities  Study
                                                            JOB/EST.  HO.   41*1-8-03-
LOCATION: _
TVPE Ull IT; Scrubbing JErain ;
Area 200
CLASS	
PAGE HO.:
                              C.E.F.G.
OF
ITEM
NO.
201-C




201-E
202-E




201-F
202-F




201-G












»
DESCRIPTION
EQUIPMENT TYPE: OHeat Exchanqers
Reheater


E- Towers

Venturi Scrubber
TCA Absorber


F-Drums and Tanks

Vent. Scr- Circulating Tank
Absorber Circulating Tank


G-Separators

Sntrainment Separator













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                                        188
1 issue NO.
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-------
CMC PROJ 0 »-»0
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                ucuucn

                  \w/
EQUIPMENT LIST
CLIEKT: .    EPA  - Iowa  Utilities Study
                                                          JOB/EST.  HO.4118"03
LOCATION:
TYPE UNIT;  Scrubbing  Train;   Area  2QO
                          CLASS    J,L,M


                          PAGE NO.;   4
                                                                          OF
ITEM
NO.
201-J
202-J
203-J




201-L-
202-L
203-L
204-L
205-L




201-M
202-M
203-M
204-M
205-M
206-M
207-M
208-M







DESCRIPTION
EQUIPMENT TYPE: J-Pumps, Blowers , Drivers
Vent. Scr. Circulating ^wips
Absorber Circulating Pumps
Forced Draft Fan


L-Special Eauipment

Vent. Scr. Tank Aaitator W/Motor
Absorber Tank Agitator W/Motor
Soot Blower (Inlet Duct to Venturi)
Soot Blower (Elbow to Ent. Separator)
Soot Blower (Reheater)


M-Piping

Duct To Fan
Duct From Fan To Vent. Scr.
Duct From Ent. Sep. To Reheater
Duct From Reheater To Stack Duct
Inlet Shut-Off Gate
Outlet Shut-Off Gate
Bypass Shut-Off Gate
Duct From Abs. To Ent. Separator







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DIV. OR SECT.
PVJB6V**'NC









ATTENTION OF










                                       189
1 ISSUE NO. I 1
DATE 1
2

3

4

5

6

7

8

9

IO

II

12


-------
190
                                                                 95'
                                                                      30'
                                                                                  -40'-

                                                                                  -JS-
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                                                                                         *' PXllLMAN IMCO'POIATID
                                                                                                       FIG,  7

-------
B
                                                                                                                                           HKVIB10N DB0CHIPTI
                                                        191
                                                                                                                                                            I t*«UID FOM
                                                                                                                                                            | CONSTRUCTIO
                                                                                                                                                                                       OUAWM yyx^o

                                                                                                                                                                                                                 3:
                                                                                                                                                                                                      THE  M. W  KELLOGG COMPANY
                                                                                                                                                                                                             a 4l*M
-------
                                                                                                                              c :
                                                              NO.     HIVIBION I
                                                                                    IISVUCD FOR
                                                                                    coMvrnucTK
                                                                                                                      THE M.W. KKLLOOaCOMPANY
                                                                                                                      CLAM   AMKA
192

-------
          Table 22
ABSORBER-VENTURI STANDARD SIZES
                                                        VIH
ACfM W.I 1 12SV175*
ACFM Rot 1 100*
sent (Rot)
Hot Duot/Stadt Duet
Nominal N.w.
Paetor
A3SORBIK
i/ci CPH/Mscm
ON Total
Slsa
NO. PIUIBI
•IIP t 6J% Bff. (TOt.)
Ho tarn Ha. /Bp Ba.
MS. TAMX
Gal.
DlMn.
r«i BII? • 65« err.
VtMTUni
L/Cl GFM/KSCFM
CPH Total
Slia
Ho. Pimpa
BMP t «S% til. (Tot.)
Motorat Ho./Rp Ba.
VCTTURI TA1K
Gal.
Olmn.
BEMtMtRl qi MBTO/H
*0i Ft*/»til
DlMni Rt/Width/Dlpth
Bo. Tuboa/Dla. /length
Bo. Bova Hlgh/Daop
4SO, 000/481 .606
545,000
171,000
l!>xl2>/12'Bll'
112
1.080

64.1
24,000
IS' x 40'
1 (1 + SP.)
144
J/SOfl

141,000
40' 0 B 15*
1100

16.1
6000

2 11 * BP.)
211
2/250

15.100
20' 0 B 15*
21.9 .
14.140/60,000
IS' B 14* B 43*
4060/1V141
116/15
H
1*4.068/411,000
477,066
126,000
12'xir/irBll'
IS*
0.875

64. S
21,001
IS' x 33'
1 (2* SP.)
Ill
1/488

111,880
17* 0 B «'
26*0

16.1
S2SO

2 (1 » SP.)
201.5
2/150

10,900
19' 0 B 15'
20.9
1), 070/51, SOO
14' x 11' B 41*
11SO/1V111
116/15
...»F',.
118,680/167,000
401,000
288,000
ll'xll'/lO'BlO*
111
8.750

14. S
10,000
IS' x SO'
1 (2 + SP.)
Ill
1/408

106 ,000
IS' 0 B IS*
2475

16.1
4560

2 (1 + SP.)
174
2/206

26,500
17' 0 x 15*
17.9
11,200/45,000
11' x 12' B 45*
1S70/1V121
102/15
AV
111.606/101,000
141,646
111,006
lO'xlO'/U'B*'
114
0.621

64.5
IS. 000
15' B 25'
1 (2 * SP.)
517
V100

08,100
32' 0 B IS'
2060

16.1
3710

1 11 * SP.)
145
2/1S4

12.100
11' 0 B 11'
14.9
9,340/17,300
12' x 11' x 45"
12SS/1V111
91/15
125,000/244,000
271,000
167,000
»•«»•/»'«*'
91
0.500

64.5
12 .000
IS' B 20'
1 (2 * SP.)
422
I/ISO

70. SOO
28* 0 B IS'
1656

16.1
3006

1 (1 + SP.)
Ill
1/125

17.700
14' 0 B IS'
11.9
7,470/30,000
11' B 10' B 43*
2070/1 V10'
11/15
16* .000/113 .000
204.000
148 .000
O'xS'/OW
61
.375

64.5
(.000
15' S 15*
3 (1 » SP.)
116
1/175

51 ,960
25' 0 B IS'
1140

16.1
22SO

2 (1 «• SP.)
87
1/100

11,100
11--6- 0 • IS'
9.0
5,600/21,500
*' B 10' B 45*
1110/lVlO'
41/15
««^^M«
112.500/122,000
116.000
91,100
71»6'/6'x6'
41.5
0.15

64.5
(.000
15 'BlO*
1 (1 • SP.)
Ill
I/US

35,300
20' 0 B IS!
135

16.1
1500

2 (1 * SP.)
S7.1
1/75

0810
11' 0 B IS'
6.0
1, 740/15.000
7' B 8' B 45*
1785/1V6'
51/15
75.000/11,100
•0.900
61.100
S'BS'/S'xS'
M.l
<.1»7

64.5
4.000
1S-B6.67-
1 (i » sr.»
141
1/75

23.300
14--4- 0 x 13'
550

16.1
1000

1 (1 » SP.)
11. S
1/50

5810
S' 0 8 IS*
4.0
1.410/10.000
(• • 7* • 45*
1165/1V7'
• 19/13

-------
                                       Table 23
                                WET LIMESTONE PROCESS

                                   STANDARD SIZES

                   Scrubber Area Dimensions:  Ft.  (Width x Length)



SIZE          I        II       III        IV        V         VI        VII       VIII


Type A    60 x 140  56 x 136  52 x 132  48 x 128   44 x 124   40 x 120   36 x 116  32 x 112


Type B    60 x 196  56 x 190  52 x 184  48 x 178   44 x 172   40 x 165   36 x 159  32 x 153


Type C    60 x 65   56 x 61   52 x 57   48 x 53    44 x 49    40 x 45    36 x 41   32 x 37
Notes:  Type A has fan at grade  (HT = 95')
        Type B has fan at grade with additional pumps  (HT =85')
        Type C has fan over venturi scrubber  (HT  =95')

-------
 PAGE NOT
AVAILABLE
DIGITALLY

-------
                                    Tatele  24
                                  SLURRY  POND
             150 CY/H FOR A  550 MW'PLANT  BURNING 4.3% SULFUR COAI,
                   150% STOIC. QUANTITY;  SLUDGE IS 40% SOLIDS
                         70% LOAD FACTOR  (6132 HR/YR)

                                       NUMBER YEARS STORAGE
PLANT SIZE: MW
 5 YRS
10 YRS
15 YRS
20 YRS
25 YRS
     200
     400
1.67 MMCY    3.3  MMCY    5.02 MMCY     6.69  MMCY     8.36 MMCY
 (20.7)       (41.5)        (62.2)        (82.9)        (103.6)

3.34 MMCY    6.70 MMCY   10.04 MMCY    13.38  MMCY    16.72 MMCY
 (41.4)       (83.1)        (124.5)       (165.9)       (207.3)
     600
5.01 MMCY   10.05 MMCY   15.06 MMCY    20.07  MMCY   25.08 MMCY
 (62.1)        (124.6)       (186.7)       (248.8)       (310.9)
     800
6.68 MMCY   13.40 MMCY   20.08 MMCY    26.76  MMCY   33.44 MMCY
 (82.8)        (166.1)       (248.9)       (331.7)       (414.5)
    1000
8.35 MMCY   16.75 MMCY    25.10  MMCY    33.45 MMCY   41.80 MMCY
 (103.5)       (207.6)       (311.2)       (414.7)       (518.2)
Sample  Calculation:
    Calculate the pond  size  (50  feet deep)  required for a
    1180 MW power plant burning  3.2% sulfur coal with a load
    factor of 60% to hold 20  yrs.  stg.
    Area = Area, nrtn  (Gen.  Cap.) (Fraction Sulfur) (Load Factor)
               1000     Ratio          Ratio           Ratio
    Area = 414.7 x
                                          x
                                                        = 312 Acres
 No.  in parentheses  (    )  = No.  of acres of pond 50' deep
                                      196

-------
 PAGE NOT
AVAILABLE
DIGITALLY

-------
        APPENDIX C




WELLMAN-LORD/ALLIED SYSTEM
                205

-------
 PAGE NOT
AVAILABLE
DIGITALLY

-------
KM a PNOJ • B-TO
                                  Table 25
                                EQUIPMENT LIST
CLIENT:   EPA - Iowa  Utilities Study
LOCATI on; Wellman-Lord/Allied Process
JOB/EST. HO.   4118-03

CLASS C,E,F,J
TYPE UHlTScrubbing Train;  Area 100
PAGE NO.:	1
OF
ITEM
NO.
101-C



101-E



101-F



101-J
102-J
103-J
104-J







t







DESCRIPTION
EQUIPMENT TYPE: C-Heat Exchangers
Reheater


E-Towers
Absorber


F-Drums & Tanks
Absorber Surge Tank


J-Pumps, Compressors, Blowers, Drivers
Booster Fan
Quench Pumps
Prescrubber Circ. Pumps
Absorber Circ. Pumps















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it































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STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)

DESIGN

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SyiST1**""5









ATTENTION OF:










                                        20&

DATE
1

2

3

4

S

6

7

8

9

to



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-------
•N« PMOJ • •-10
                                   EQUIPMENT LIST
                                                               JOB/EST. HO..
CLIENT: 	
LOCATION:	
TYPE UN IT: Regeneration Section:   Area 200
                                                  CLASS  C,E,F,J
                                                  PAGE NO.: 2
.OF
ITEM
NO.
201-C
202-C
203-C
204-C
205-C



201-E



201-F
202-F
203-F
204-F




201-J
202-J
203-J
204-.J
205-J
206-J
207-J
208-J
209-J
210-J

DESCRIPTION
EQUIPMENT TYPE: C-Exchangers & Condensers
Evaporater Heater
Primary Condenser
Secondary Condenser
S02 Superheater
Condensate Cooler


E- Towers
Condensate Stripper


F-Drums & Tanks
Evaporator Feed Tank
Evaporator
Dump/Dissolving Tank
Absorber Feed Tank



J -Pumps , Compressors, Blowers, & Drivers
Filter Feed Pumps
Flyash Filter Sump Pumps
Evaporator Feed Pumps
Evaporator Condensate Pumps
Evaporator Circulating^Pump
Mother Liquor Pumps
Transfer Pumps
Absorber Feed Pumps
Condensate Stripper Pumps
SC>2 Compressor

lls































i«































    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)
DIV. OR SECT.

DESIGN

ii
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                                            209
   ISSUE NO.
I   '   I  '   I   '   I  '   I   '   I   '  I  7   I  '   I   '   I
                                                                            ie
   DATE

-------
•NO PMOJ« »-»C
                                    EQUIPMENT LIST
                                                                   JOB/EST. NO..
CLIENT:
LOCATION:
TYPE UNIT:

ITEM
NO.

201-L






























CLASS L
Area 200 (Cont.) PAGE NO.: 3 OF

DESCRIPTION
EQUIPMENT TYPE: L-Special Equipment

Flyash Filters































6

BD
-is



































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In z






























1
    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)

DESIGN


M

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Ckv-BuT
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                                              210

DATE
1

2

3

4

Z

6

7

8

9

1O

11

-5-1
• ..,!

-------
                 IKEUOOOI
CMC PMOJ • 9-TO
                                  EQUIPMENT LIST
CLIENT: 	
LOCATION:	
TYPE UNIT:  Purge/Make-Up  Section:   Area  300
JOB/EST. NO..


CLASS	Lz
PAGE NO.:
OF
ITEM
NO.
106-F
307-P
308-P


310-J

























DESCRIPTION
EQUIPMENT TYPE: F-Drums & Tanks
Purge Solids Bin
Na0 CO- Bin
Na; CO, Mix Tank
•- 3 	
J- Pumps, Compressors, Blowers, & Drivers
Na,, CO., Pumps
2 3
























-fS































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I*






























•
    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)
DIV. OR SECT.
DESIGN

3
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ATTENTION OF










                                        211
{ISSUE NO.
DATE
1

2

3

4

5

6

7

a

9

10

11

12 1
J

-------
KN« PMOJ • t-70
                                    EQUIPMENT LIST
CLIEHT: 	
LOCATION:.
TYPE UNIT:
                                                                  JOB/EST. NO..
                                                  CLASS.
                                                              B
SO.,  Reduction:
400
PAGE NO.;
.OF
ITEM
NO.
401-B






























DESCRIPTION
EQUIPMENT TYPE: B-Furnaces, Fired Heaters & Stacks
Tail Gas Incinerator






























SB
.is































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    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)

DESIGN

ISVSTCMI
BtfsYifc
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ATTENTION OF:










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OIV. OR SECT.
gyRjftA*M<









ATTENTION OF:










                                             212
1 ISSUE NO.
DATE
1

2

3

4

5 I 6
1
7

8

9

10

11

12 |
J

-------
                 lUUOMl
•NO FHOJ • 9-10

CLIENT:	
LOCATION:	
TYPE UNIT:
                   EQUIPMENT LIST
                                                JOB/EST. HO.	

                                                CLASS   C.D.F.G.J
S00  Reduction;
400  (Cont.)
PAGE NO.:
.OF
ITEM
NO.


403-C
404-C
405-C
406-C
407-C


401-D
402-D
403-D
404-D


401-F



401-G




402-J
403-J
404-J
405-J



DESCRIPTION
EQUIPMENT TYPE: C-Exchangers & Condensers


Feed Preheater
Mixed Gas Cooler
1st Sulfur Condenser
2nd Sulfur Condenser
3rd Sulfur Condenser

D-Converters, Reactors, & Regenerators
Heat Regenerators
Reduction Reactor
1st Claus Reactor
2nd Claus Reactor

F-Drums & Tanks
Sulfur Pit


G-Separators
Tail Gas Mist Eliminator


j-Pumps, Compressors, Blowers, & Drivers

Sulfur Pit Pumps
Dilution Air Blowers
Combustion Air Blowers
Start-up Air Blower



ffi
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    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)
OIV. OR SECT.



in
U
0

[SYSTEMS
EtfsVifc
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ATTENTION OF:










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SHIST-**"0









ATTENTION OF:










                                            213
   ISSUE NO.
                                                                            10
                                                                                  II
   DATE

-------
      FROM BOILER.
                           IQI-C
                                 J
      ~7
                                              101-E
                                                        IQI-F
fin fin nil II HIM
                            i
                           QUENCH     PrCSCKUBftte  A3SORSER.
                           PUMPS FfcN  ClRC. POMP*  CltlC PUMPS
                           IO2.-T  IQI-T     10^-T         104-T

                           	    	UO'             -- - i
                                                                   PLAN

                                                                   SIZE i
                                            7
                                y'
                            o
                                  fcBSORBK.
                      <7
                             i ' i I" "I n n n
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                                               35-
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                                                     A560RBEK
                                                       n n r
                                                        -24
                                                                                       SIDE VIEW
                                                                                                                           TYP€ A .
                                                                                                                  \NELLMAN-LIKD PROCESS
B
                                 214
                                                                                    DESCRIPTION
                                                                                              DAT! «T  CHK
                                                                                                                  THE M. W. KELLOGG COMPANY
                                                                                                                         »f PUU-MAN IMCOIW(MATO
                                                                                                                       100
                                                                                      4118-03
                                                                                                        OAT1D: fc-5-74
MODULE

V6  2!
                                                                                                                                  DKAWIN4 NO

-------
I
fcl'
          REGENERATION : AREA 200
    nn
                 SIZE m

               201-C
                Q
nn
                                                       SOZ REDUCTION: AREA, 400
                                                       ooo
                                                       40.-.*  40Z-P
&
              PURG,^/ MA^E-UP: AREA 300
                    SIZE U
                        ZH

                                      »i     )
                                       ^~^
                                    510-T
                                    cz)  cm
                                                                                PKOCCS&
              •^15
                                            MEVICION DIMCMIPTIOM
                                                               i«u: i-.jo1
                                                              MVWK: DOM
                                                                     THE M. W. KELLOGG COMPANY
                                                                       A • mlHH •* PUULJftAN IMCOHVOOATYD
                                                                        2B0.3DP

                                                              -- -- •
                                                              DATKD: 5-15-74
                                                                                Fl(^. 22
                                                                                 [MIAWIN4 NO

-------
                                     Table 26
                           WELLMAN-LORD/ALLIED PROCESS
                                  STANDARD SIZES
Scrubber Area
Size
ACFM '@
Factor
Dimen.

300°F

: Ft.
I
545,
1.

000
0
60x140
II
477,000
0.875
56x136
III
409,000
0.750
52x132
IV
341,000
0.625
48x128
V
273,
0.

000
500
44x124
VI
204,000
0.375
40x120
VII
136,000
0.250
t
36x116
VIII
90,900
0.167
32x112
Regen. Area
Size
Sulfur
Factor
Dimen.
to

Flow: Ib/HR

: Ft.

I
9,
1.

000
000
69x191


II
8,000
0.889
65x184

III
7,000
0.778
61x177

IV
6 ,000
0.667
57x170

V
5,
0.

000
555
53x163


VI
4,000
0.444
49x156

VII
3,000
0.333
45x149

VIII
2,000
0.222
41x142

H Purge/Make -Up Area
Size
Sulfur
Factor
Dimen .

Flow: Ib/HR

: Ft.
I
18,
1.

000
000
94x223
II
14,000
0.778
82x211
III
10,000
0.555
70x199
IV
7,000
0.389
61x190
V
5,
0.

000
278
55x184
VI
4,000
0.222
52x181
VII
3,000
0.167
49x178
VIII
2,000
0.111
46x175
SO0 Reduction Area
Size
Sulfur
Factor
Dimen.
I
Flow: Ib/HR

: Ft.
18,
1.
000
000
66x143
II
14,000
0.778
58x127
III
10,000
0.555
50x111
IV
7,000
0.389
44x99
V

5,000
0.278
"0x91
VI
4,000
0.222
3Rx87
VII
3,000
0.167
36x83
VIII
2,000
0.111
34x79

-------
N

-------
     APPENDIX D
COAL CLEANING SYSTEM
            225

-------
         LEGEND

_^_^  CWL
	  RCFUSE
	SLURRIES
         CONCCNTRATEO  MAGKETITC
    	  Oil U1F MAGNETITE
     . _  ClARiriCD OXER


SEE  REF 2., Pit

-------
                REllOBBl
ENC PROJ 6 9-10
                                  Table 27
                               EQUIPMENT LIST  (Incomplete - not  a11 PumPs>
                                                conveyors, sumps, etc. shown)

                                                          JDB/EST. NO.  miB-03
          EPA - Iowa  Utilities  Study	
LOCATION;   Iowa                 	-   CLASS       B. F.  G
CLIENT:
TYPE UNIT;  Coal Cleaning Plant
                                                          PAGE NO.:
OF
ITEM
NO.
101-B


101-F
102-P
103-F
104-F
105-F
106-F
107-F
108-F


101-G
102-G
10^-G
104-G
10R-G
106-G
107-G
108-G
109-G
110-G
111-G
112 G
113-G
114-G
115-G
116-G
n7-fi
118-G
DESCRIPTION
EQUIPMENT TYPE: B_—_Furnaces Fired Hea-ters , & Stacks
Thermal Dryer (Alternate)

F - Drums and Tanks
Raw Coal Receiving Bin
Raw Coal Silo
Pulp Sump
Heavy Media Sump (Fine Coal Treatment)
Heavy Media Sump (Coarse Coal Treatment)
Refuse Bin
Clean Coal Silo
Water Tank

G - Separators
Raw Coal Screen
Pre-Wet Screen
Sieve Bend Screen
Deslimine Screen
Heavy Media Cyclone (Fines}
Refuse Drain and Rinse Screen
Second Sieve Bend Screen
21ean Coal Drain and Rinse Screen (Fines)
Magnetic Separator (Fines)
Centrifugal Dryer
ieavy Media Washer
Refuse Drain and Rinse Screen (Coarse)
^lean Coal Drain and Rinse Screen (Coarse)
Centrifugal Drver (Coarse)
Magnetic Separator (Coarse)'
Classifying Cyclones
?rnhh Cells
]lean Coal Filter
z w
?«s































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M Z































    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)
DIV. OR SECT.
DESIGN
U
t-
n
>
M
oHvftfc
LkCSiT
₯&5?BIAL
flllWoRTS
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w&tv
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-------
EMC PROJ 6 8-70
                                     EQUIPMENT LIST
                                                                    JOB/EST. NO..
CLIENT: 	
LOCATIOM:_
TYPE DM IT:
CLASS   G. Jf  Kr  L
PAGE HO.t    ?     OF	2
ITEM
NO.
119-G


101-J
102-J


101-K


101-L
102-L



















DESCRIPTION
EQUIPMENT TYPE: G - Separators (Cont.).
Refuse Filter

J - Pumps, Compressors, Drivers
Heavy Media Pumps (Fines)
Heavv Media Pumps (Coarse)

K - Buildings
Preparation Plant Building

L - Special Equipment
Coal Crusher
Thickener



















-fS































u
3d
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    CHECKS IN FAR RIGHT HAND COLUMN INDICATE ITEMS CHANGED IN LATEST ISSUE.
STANDARD DISTRIBUTION (ENTIRE EQUIPMENT LIST)
DIV. OR SECT.
DESIGN
SYSTEMS
DE°sY&£l
Ekv-SiT
«&5fBb"Ll-
SUPPORTS
RJfn&MENT
WStkV
Ws^.I.M'.FN**-
SYSTEMS CNG.
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flSWESN6
iiH^fyteING
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HOME OFFICE
FIELD
COST SERVICES
PROCESS MCR.
228
ATTENTION OF'










ADDITIONAL DISTRIB. THIS SHEET ONLY
DIV. OR SECT.
PUJC^ASING









ATTENTION OF











ISSUE NO.
DATE
1

2

3

4

5

6

7

e

9

10

1 1

12


-------
                                                          RAW COAL
                                                          RECEIVING
                                                          BIN
o •
a
tm -
ui

cc
oc
o
 j •
                           EMERGENCY
                           PONDS
                                                  QC
                                                  O

                                                  UJ
                                                  O
                                                  O
                    CONVEYOR
15,000 TON
CLKAN COAL
SILO
                             THirifFWPR
                             THICKENCR
                                              PREPARATION
                                                PLANT
1500 TON
RAW COAL
SITE
                                           i	1
                                          POSSIBLE
                                          THERMAL
                                          DRYER
              SKETCH OF TYPICAL SITE LAYOUT

                    PREPARATION FACILITIES

                   THE M.W. KELLOGG  COMPANY
                          HOUSTON, TEXAS

                  GATES  ENGINEERING  COMPANY
                            CONSULTANTS
                      DENVER  BECKLEY   CHICAGO
                  SCALE: i"=20o'   229    DATE: 5/7/74
                                                   12

-------
            APPENDIX E
PLOT PLANS OF OTHER POWER PLANTS
                  230

-------
N

-------
            APPENDIX F






CONVERSION FROM ENGLISH TO METRIC UNITS
                  237

-------
                         APPENDIX F
           CONVERSION FROM
To Convert from
 acre
 atmosphere (normal)
 atmosphere (normal)
 barrel (42 US gallons)
 British thermal unit  (Btu)
 Btu/hour
 Btu/pound mass
 Btu/pound mass -  F
 foot
 foot2
 foot3
 foot /minute
 foot-pound force
 gallon (US)
 gallon (US)/minute
 grain
 horsepower
 inch
 inch H20(60°F)
 mile  (US statute)
 pound force
 pound mass av
 pound mass av
                 2
 pound force/inch
 pound mass/foot3
 °Rankine
 ton mass  (US short)
 ton mass  (US long)
 yard
 yard3
ENGLISH TO METRIC UNITS
  To
       2
  meter
  bar
  pascal
  meter3
  joule
  watt
  joules/gram
  joules/gram - °K
  meter
  meter
  meter
  meter3/minute
  joule
  meter-*
  meter3/hour
  milligram
  kilowatt
  centimeter
  kilopascal
  kilometer
  newton
  kilogram
  metric ton (.tonne)
  kilopascal
  kilograms/meter
  °Kelvin
  kilogram
  kilogram
  meter
  meter
Multiply by
4046.9
1.01325
101,325
0.15899
1055.1
0.29307
2.32600
4.18680
0.30480
0.09290
0.02832
0.02832
1.35582
0.00379
0.22712
64.7989
0.74570
2.5400
0.24884
1.60934
4.44822
0.45359
0.0004536
6.89476
16.0185
0.55556
907.185
1016.05
0.91440
0.76455
                                 238

-------
                  APPENDIX G






LINEAR COMPUTER PROGRAM PRINT-OUTS  (ABRIDGED)
                        239

-------
Linear Computer Program Print-outs (Abridged)
                       DEFINITION OF TERMS
              IN LINEAR COMPUTER PROGRAM PRINT-OUT
COSTTOTL
TPIT
TFRT
TASK
TSC1
TSC2
TWSH
TREF

TSTO

TBRN

AML
DDL

EDL
WMLDL

WS ML SL

X ML PL DL

XS ML PL DL

Y ML CL DL


YS ML CL SL

SS1SL
Total system cost: $/D
Total coal pithead cost: $/D
Total freight cost: $/D
Total ash disposal cost at power plant: $/D
Total capital based scrubbing cost: $/D
Total sulfur related scrubbing cost: $/D
Total coal cleaning cost: $/D
Total refuse disposal cost from coal
cleaning plant: $/D
Total storage/transfer cost  (whether at a
transfer point or cleaning plant):  $/D
Arbitrary penalty assigned if system cannot
meet  specification: $/D
Total coal used from each mine: T/D
Total energy requirement of each power
plant: MMBtu/D
Total S0? emission from each power plant:PPD
Uncleaned coal shipped directly from a  mine
to a power plant: T/D
Same as WMLDL but scrubbed at power plant
SL: T/D
Uncleaned coal shipped from a mine to a power
plant via an intermediate point  (PL): T/D
Same as X ML PL DL but scrubbed at power
plant SL: T/D
Coal shipped from a mine to a cleaning
plant (CL), cleaned, and then shipped 'to a
power plant: T/D
Same as Y ML CL DL but scrubbed at power
plant SL: T/D
Size of scrubbing system installed at
power plant SL: MMBtu/D
                            240

-------
SS2SL          (MMBtu/D) (%S)

SM SL          Variable used in KELPLAN'S model to simulate
               the scrubbing system at power plant SL

CC1 CL         Size of cleaning plant installed at location
               CL: T/D feed

C N CL         Same as SM  SL but for cleaning system

IN12SL or      Scrubbing plant indicator (integer variable).
IN23SL         If equal to zero, plant does not exist; if
               equal to one, plant exists (at SL).

IM12CL         Cleaning plant indicator (integer variable).
               If equal to zero, plant does not exist; if
               equal to one, plant exists (at CL).
                           241

-------
                                   Case 1:  Spec.  =  20  Ib SO2/MMBtu
to
*>
to

-------
PAGE
39  -  74/212
hi IMOCO j_Rfiy .m .
1 rOSTTOTl
? roSTPTT
3 COSTFRT
4 COSTASH
5 CnSTSCl
f> COSTSC2
7 COSTWSH
R CQSTRFF
9 COSTSTO
10 COSTBRN
11 AMA
12 AMB
13 AMC
14 AMC
15 AME
16 AMF
17 AMG
18 AMH
19 DDA
?0 DOB
to 71 ODC
*• 2? ODD
w 23 DOE
24 DDF
25 DDG
26 DDH
?7 DDI
28 DDJ
29 DDK
30 DDL
31 DOM
32 DON
33 onn
34 DDP
35 000
36 DDR
37 EDA
38 EDB
39 EDC
40 EDO
41 FOE
42 EDF
43 FDG
44 *=DH
45 EDI
4f> EOJ
47 EOK
48 EDL
49 EDM
AT
BS
E0_
EO
EO
EO
EO
EO
EO
EO
EO
BS
BS
BS
BS
BS
BS
BS
BS
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EO
EO
FO
EO
EO
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-• «•• ACT I V-W-Y-^»»
318475.25054
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9499.41084
11383.36038
7097199399
.
18684.00000
12994.00000
17726. OOOCO
20023.00000
24504. COOOO
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000.
— StACK-ACT-IVITY-
318475.25054-


41349.56689
50000.00000
40500.58916
38616.63962
50000.00000
42902.00601
5000C. 00000
50000.00000
•
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EO 87017.00000
EO 31570. COOOO
EO 115682.00000
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BS
BS
BS
BS
. BS.
BS
BS
BS
BS
BS
. BS .
BS
BS
25608.00000
51307. OOOCO
31488.00000
18259.00000
253180.45174
176077.22061
91953.86293
103676.35876
127123.12316
308806.88485
762474.61583
763356.26604
585645.79019
350242.25804
. 57328.97398
1179137.41006
427794.20154
•
120499.54826
83802.77939
262560.13707
296583.64124
362956.87684
881693.11514
53476b. 38416
535383.73395
278734.20981
999997.74195
611891.02602
561202. 58994
20J605. 79845
..LOWER LIMIT*- UDDCD i IMIT. HIIAI APTIUITV
NONE
*
•
NONE
NONE
NCNE
NCNE
NCNE
NONE
NONE
NONE
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682.00000
25608.00000
51307.00000
31488.00000
18259.00000
NONE
NONE
NCNE
NUNE
NCNE
NONE
NONE
NONE
NONE
NCNE
NONE
NUNE
NONE
NONE
•
•
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
18684.00000
12994.00000
17726.00000
20023.00000
24504. 00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682.00000
25608.00000
51307.00000
31488.00000
18259.00000
373680.00000
259880.00000
354520.00000
400460.00000
490080.00000
1190499. SS999
1297239. S9999
129B 739. 99999
864380.00000
1350239.99999
669220.00000
1740340.00000
631400.00000
.00000
.00000
.00000
.00000
.00000
.00000
29.29178
I. 00000
I. 00000
*
*
1 3435 8-
.34358-
.38662-
.43.181-
.41473-
.39867-
.47599-
.47599-
.39444-
.39114-
.49105-
.39307-
.46043-
.36617-
.34676-
.3*725-
.38235-
.36581-
•
•
•
m

-------
 .MPSX-PT«=16.    EXECUTOR.  HPSX  RELEASE  1   MOO LEVEL 4

—-NUMUEJL. ....BOW....  AT   . . .ACTI Vl.TY.... . SLACK ACT IVJTY
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-------
 .MPSX-PTF16.    EXECUTOR.



-JJ1JMRE.R-. ....ROW.^. A.T-  .
 PPSX  RELEASE  1   MOD LEVEL



.ACTIVITY^.., SLACK. ACTIVITY.
                                                              LOWF P.__JMIT . __ ..UPPER LIMIT.
              PAGE



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41  -   74/212
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108 HDM
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110 HDO
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112 JOG
113 JDI
114 JOJ
115 JDL
116 .10 M
117 JDP
118 JOO
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-------
 .MFSX-PTF1A.    FXFCUTOR.



 SECTION  2.-.COLUMNS






-  MJMBFR - .COLUMN.-  AT-  .
 HPSX   RELEASE 1  MOD LEVEL 4
                                                                            PAGE
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-------
 .MPSX-PTF16.    FXECUTDP.   MPSX  RFLEASE I   MOO  LEVEl 4

.  NUMBER. ..COLUMN^.  AT  ....ACTIVITY^..  .^JNP.UT  CCST..  . .LOKE R. JJ.MIT,
                                                                                                            PAGE
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-------
to                                   Case 1:  Spec.  =  5  Ib SOn/MMBtu
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-------
MPSX  RELEASE  1   MOO  LEVEL  3
                                                                          PACE
18  -  74/165
NUMBER .. .ROW. .
1 COSTTOTL
2 COSTPIT
3 COSTFRT
4 COSTASH
5 COSTSC1
6 COSTSC2
7 CnSTWSH
8 COSTRFF
9 COSTSTO
10 COSTBRN
11 AM A
12 AMB
1 3 A.MC
14 AMP
15 AMP.
16 AMF
17 AMG
18 AMH
19 OD A
20 DD 8
10 21 DOC
•*• 22 ODD
*° 23 DD F
24 DDF
25 DOG
26 DOH
27 DDI
28 DDJ
29 DDK
30 DDL
31 OHM
32 DON
33 non
34 OOP
35 nno
36 DD»
37 EDA
38 FDA
39 EOC
40 EOD
41 FnF
42 EOF
43 EOG
44 EDH
45 EDI
46 FDJ
47 FDK
48 EDL
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-------
MPSX-PTF13      EXeCUTOR.   MPSX  RELEASE 1  MOD LEVEL  3



 NUMBER  ...ROW..   AT	...ACTIVITY...	SLACK  ACTIVITY
..._L OWE R _LJ MIT.	. ._UPP_ER_ UM t T._
             PAGE



• DUAL-ACT IV 1T Y	
                                                                                                                 19   -  74/165
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52 EDP
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54 FDR
55 SIZXOF
56 SIZXDG
57 SI7XDI
58 SIZXDJ
59 SIZXOL
60 SIZXOM
61 SIZXOP
62 SIZXOO
63 F010F
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77 E020P
78 F0200
79 E03DF
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81 E03DI
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-------
MPSX-PTF13
EXECUTOR.   MPSX  RELEASE I   MOD LEVEL 3
PAGE
20  -   74/165
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-------
 MPSX-PTF13      EXECUTOR




_SFCJ_ION 2 -  COLUMNS
MPSX  RELEASE i  HOD LEVEL 3
PACE
21  -  7A/165
NUMBER
145
153
232
252
255
266
268
303
370
329
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509
717
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1146
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1354
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2189
2394
7396
2588
2813
30 18
3021
3437
3858
3860
4066
4766
4890
5730
6087
6215
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6300
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315.21482
219.21972
2406.44351
5505.52249
508.37364
2030.50337
132.01616
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535.06565
372.11748
701.51642
45.61012
803.97414
35.18394
983.89763
43.05784
2355.73534
153.16159
2604.37349
113.97396
2607.38493
114.10575
1735.35225
75.94340
2671.82536
173.71265
1592.47150
1764.72641
1267.61541
55.47405
671.98501
1246.15530
81.02062
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SSIDF
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ss ini
SS 10J
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BS
BS
BS
BS
BS
B_S
BS
BS
•
"
•
INPUT COST.. ..LOWER LIMIT. ..UPPER LIMIT. .REDUCED COST.
NONE
NONE
NONE
. NONE
NONE
NONE
NONE
NONE
NONE
NONE .
NONE
NONE
NONE
NONE
NONE
NONE .
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE .
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NOME

-------
c.
                                                                                                         PAGE
22  -  74/165
6805 SS10P
A BOA SSI DO
6808 SS20G
6811 SS20L
6815 S10F
6817 S30F
6820 S30G
6824 S1DJ
6826 S30J
6879 S301
6830 SI DM
6832 S30M
684S S*OP
6836 SI 00
6838 S300
6840 CC10P
6841 CC1MA
6842 CC1MB
6843 CCIMC
6844 CC1HD
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6853 C1MB
6855 C1HC
6857 riMD
6858 C2MD
6859 C1PA
6861 riPR
6874 OOL
6881 TPIT
688? TFRT
6883 TftSH
6885 TSC2
A«87 TRFF
6888 TSTO
6891 IN12DG
6892 TN120I
6A93 INI120J
6R94 IN120L
6895 IN170M
6896 IN12DP
6897 IN1200
689ft TN23DF
6899 IN230G
6901 TN230J
BS
BS
BS
BS
RS
BS
BS
BS
BS
BS
BS
BS
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BS
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BS 141748.93762
BS 4197.83093
BS
as
BS 7071.20087
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IV
IV
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IV
IV
IV
IV
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UHF w i \.uo i . . . .bwni^n. kinii. ..uri-cn i, I n i I . ^ .n [, yui. cu 1. uo I .
NONE
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NONE
NONE .
NONF
, NONE .
NONE
NGNF
NONE
i NONE
NONF
NONE
NONE
MONF
NONE
NONE
NONF
NONE
NONE
NONF
NONE
NONE
NDNF
NONE
NONE
NflNF
NONE
NONE .
NONF.
NONE
NONE
MQNF
NONE
1.00000 . NONE
1.00000 . NHNF
1.00000 . NONE
1.00000 . NONE .
1.00000 . NONF
1.00000 . NONE .
1.00000
1.00000
1.00000 .
1.00000
1-nnnnn
1.00000 .
1.00000
l.OOOOO
1.00000
1.00000
	 - i-ooooo
        6903  IN23DN
                        IV
                                                                                  1.00000

-------
              EXECUTOR.   MPSX   RELEASE 1  MOO LEVEL 3

NUMBER  .COLUMN.  AT   ... ACTIVITY	INPUT .._CQST.j__. ._L PWE_R_kl M '!_•_
6905 TN23DO
6906 IM12DN
6
-------
                                  Case  1:   Spec.  = 3.1 Ib SO_/MMBtu
01                                                           2.

-------
MPSX-PTF13      EXECUTOR.  MPSX  RELEASE 1  MOD LEVEL  3




SFC.TION  1 -  RflwS
PAGE
15  -  74/168
NUMBEP
1
?
3
4
5
6
7
8
a
10
11
12
13
14
15
16
17
IP
19
?0
NJ 21
S "
23
24
25
?ft
71
?8
?<3
30
31
3?
33
44
35
36
37
3fl
39
40
41
4?
43
44
45
46
47
4fl
49
.. .ROW..
COSTTOTl
cnsipn
COSTFRT
COSTASH
COST SCI
cnsTscz
COSTWSH
COSTREF
COSTSTO
COSTBRN
A1A
AM3
A,«r
AIT
AV.E
ANC
Air.
A«H
nnA
OD«
DDC
ODD
DDE
DDF
DOC
r>DH
PDI
noj
OIK
00 L
DDM
nnN
nun
nos>
noo
DDR
FOA
EDS
Enc
FOO
FDE
EOF
For,
EHH
FOI
POJ
ERK
COL
FOM
AT
BS
EO
EO
EO
FO
EO
EO
FO
EO
EO
BS
BS
RS
BS
BS
BS
BS
BS
FO
EO
EC
FO
EO
EO
FO
FO
EO
FO
EO
EO
EO
FO
EO
FO
FO
EO
UL
UL
UL
UL
UL
UL
UL
Ul
UL
UL
BS
UL
UL
...ACTIVITY...
384574.83811
•
•
•
•
•
292^59705
13D5. 04147
307. 59668
9^78.63212
13605I68468
9818. 65797
18684. OOOCO
12994. OOOCC
17726.00000
20023.00000
24504. OOOCO
59525.00000
64862. OOOCO
64937. COOCO
43219. OOOCO
67512.00000
33461.00000
R7G17. OOOCO
31570. OOOCO
115682. OOOCO
25608.00000
51307.00000
314r8. 00000
18259. OCOOO
57920.38672
40281.39063
54950. 58984
62071.28516
T5S62. 37500
164527.43750
201072. 12500
201304.62500
133978. 875CO
209287. 125CO
57323.97398
2t9752. 62500
97E66. 93750
SLACK ACTIVITY
384574.83811-
•
•
•
•
•
49707^40295
48614.95853
49692.40332
40021.36788
50000.00000
36394.31532
40181.34203
fOOOO. 00000
•
•
•
«
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
46400.08852
•
•
..LCWER LIMIT.
NONE
•
•
•
•
*
NONE
NCNE
NONE
NONE
NONE
NCNE
NCNE
NONE
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682.00000
25608.00000
51307.00000
31488.00000
18259.00000
NONE
NONE
NONE
NCNE
NCN =
NCNE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
..UPPER LIMIT.
NONE
•
•
•
•
•
•
•
•
soooolooooo
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461. OOCOO
87017.00000
31570. OCCOO
115682.00000
25608. OOCOO
51307.00000
31488.00000
18259.00000
57920.38672
40281.39063
54950.58984
62071.28516
75962.37500
184527.43750
201072.12500
201304.62500
133978.87500
2092R7. 12500
103729.06250
269752.62500
97866.93750
.DUAL ACTIVITY
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
8.37942-
1.00000
.00007
•
•
•
•
•
•
166753-
.66753-
.49089-
.54416-
.52313-
.50541-
.59738-
.59738-
.66970-
.49033-
.49105-
.68096-
.66119-
.36617-
.58785-
.45549-
.48574-
.62192-
.02391
.02391
.02010
.02127
.02109
.02058
.02174
.02174
.02237
.02028
.02505
.02230

-------
MPSX-PTF13 EXFCUTOR. MPSX RELEASE 1 MOO LEVEL 3
MJMPER ...ROW.. AT ...ACTIVITY... SLACK ACTIVITY* ..LCWER LIMIT. ..UPPER LIMIT.
— 50
51
52
54
55
56
57
58
60
61
6?
63
64
65
66
67
68
70
71
77
SO 73
Ul 74
'J 75
76
77
78
79
80
fll
f>2
83
S4
86
87
an
39
90
91
92
93
94
95
9ft
97
98
99
100
EON
EOP
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mo
FOP
S1ZXDF
SIZXDG
sizxni
SIZXDJ
STZXOL
SI7XIJM
S» ZXOP
sizxno
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BS 1 S81S8. 3,1960 160415. 31*>40
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UL 97612. 750CO
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EO
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FO
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BS
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BS
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BS
BS
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UL
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Ul
UL
UL
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BS . 1.00000
BS . 1.00000
RS . 1.00000
HS . 1.00000
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BS . 1.00000
BS . 1.00000
BS . 1.00000
EO
EO
EO
EO
EO
FO
NONE 358614-.12500
NONE 79384.75000
NCNE 159051
NCNE 97612
NCNE 56602


NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NGNE
NCNE
MCNE
NONE
NONE
NCNE
NCNE
NCNE
NCNE
NCNE
NONE
NCNF
NCNE
NONE
NONE
NONE
NONE 1
NONE 1
NONE 1
NCNE 1
NONE 1
NONE 1
NONE 1
NONE 1


62500
75000
88672
PAGE 16 - 74/168
.DUAL ACTIVITY
.02221
.01894
.01993
.02195
.25720
.25720
.25720
.24214
.25720
.25720
.25720
.25720
•

•
•
2384!72727
•
v
•
•
2186.00000
2186.00000
2186.00000
2186.00000
2186.000JO
00000
2186.00000
2186.00000
00000
00000
00000
00000
00000 .
00000
00000

2186.00000-
2186.00000-
2166.00000-
2384.72727-
2186.00000-
2186.00000-

-------
MPSX-PTFH
EXECUTOR.  KPSX   RELEASE 1  MOO LEVEL  3



           .ACTIVITY...   SLACK ACTIVITY  ..LOWFR LIMIT.
                                                                                                         PAGE
                                                                                                  17  -  74/168
                                                                          . . U PPER LI MIJT.	. DUAk_*.CLI.V 1.7 X_
101
10?
103
104
105
F.06DO
HOP
HTG
106 HDJ
107 HDL
108 HIM
109
10
11
12
13
14
15
116
117
lift
119
120
121
172
121
K> 124
£ 125
00 126
a 127
A 128
A 129.
A 1 30
A 131
A 13?
133
A 134
M5
11 1
138
M9
140
141
14?
HDP
HDO
JOF
.me
.101
JOJ
jnp
jno
S! 7YON
S! 7.YOP
SI7YMA
SI 7YMB
S17YMC
SI7.YMD
SI 7YPA
STZYPIJ
FUO'DN
F002DP
F.OC3M1
EOOHMC
F001MC
FOO"?PA
F003P8
FDN
r-A
pljp
FPB
EO
EO
EO
EO
EO
FO
Ed
p.d
EO
EO
FO
FO
EO
EO
FO
FO
FO
EO
EO
EO
EO
EO
= 0
EO
FO
EO
FO
EO
EC
= 0
EO
EO
EO
EC
ro
EO
FO
F.O
EO
EO
EO
2186.00000-
2186.00000-
.25720
.25720
.25720
.24214
.25720
.25720
.00085
.00238
.03150
.02568-
.00176-
.OJ150
.03130
.03150
.03150
.03150
1.90000
1.90000
1.90000
1.90000
1.90000
1.90000
1.90138-
1.90000
.
'.'.'.'.
27369.92598-
1.90000
1.90000
1.90000
1.90UOO
1.90000
1.90000
1.90138-
1.90000

-------
MPSX-PTF13     EXECUTUR.  MPSX  PELFASE  1   MOO  LEVEL 3




SFCTION 2 - COLUMNS
PAGE
IB  -  74/168
NUMBER
1*5
153
?32
252
755
?66'.
260
297
340
509
717
938
94C
1146
1 14S
1 354
1357
156?
I 5iS4
|sj 1770
Ul 1 773
*° 1<578
1981
2186
2189
?3
-------
MPSX-PTF13     PXf-CUTnR.  MPSX  RELEASE 1  MOD LEVEL 3                                               PAGE    19  -   74/168



 NUMBER  .COLUMN.  AT  ...ACTIVITY	INPUT COST..  ..LOWER LIMIT.  ..UPPER LIMIT.   .REDUCED  COST.
6604 SS2DM.
6605 SS?DP
6606 ss?no
6607 SIOC
6609 S3DF
6610 sine
6612 S30G
6613 SIDT
6615 S30I
6616 SIDJ
6618 S30J
6619 S1DL
6*-21 S3fH
6622 S1DK
6624 S3DM
6625 Sinn
66?7 S3DP
66?8 S1RO
6630 S3DQ
6631 CC10N
6632 CCIPP
6633 CC1CA
6634 CT1MR
N) 6635 CC1VC
<* 6636 CCI!»D
0 66*7 CCIPA
6c3« CCIPB
6639 C1DN
66il CIDP
6643 C1"A
06 -'.7 C1'"C
6ft 'i 9 Cl^'D
f.653 ClDa
6666 OOL
6673 TOIT
6674 T«-1T
6675 TASh
6676 TSft
6677 TSC2
6C-78 TWSH
6"-flO TSTP
6690 'N?3DF
6691 IN23PG
6692 IN230I
66°J IM23n.l
6694 IN?JOL
6695 PJPBDI^
6696 IN?30t>
6697 IM23DC
BS
BS .
BS
BS
BS
BS
BS
BS
BS
RS
BS
BS
BS
RS
BS
BS
BS
RS
BS
BS . .
BS
BS
BS
BS
BS
BS
BS
BS
RS
RS
BS
BS
RS
BS
BS
BS
RS 185501.72070 1.00000
BS 188C99. 55741 1.00000
RS 3301.51418 1.00000
BS . 1.00000
RS . 1.00000
RS . 1.00000
BS 7672.04582 1.00000
IV
IV
IV
IV
IV
IV
IV
IV
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NL'NE
NONE
NONE
NONE
NONE
NUNE
NONE
NONE
NONE
NONE
NONE
1.00000
l.OOCOO
1.00000
1.00000
l.OOCOO
l.OOCOO
1.00000
1.00000



















-------
PACE
20  -  74/168
Nlir.Hi- x
6fc99
6700
f>70?
6703
o705
.I.ULUnra.
TM17DN
IM12HP
IK12MA
TM12MB
I»U2«C
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01 ... ni. I n
IV
IV
IV
IV
IV
IV
IV




l-Lil.. ..LUWCK L1H1I. ..Uf
•
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•
.
KtK Linil. .KCUU^Cl
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
} V,US 1 .




-------
en
to
Case 1:  Spec. = 1.2  Ib  SO~/MMBtu
          c                2

-------
MPSX-PTF13     EXECUTOR.   MPSX   RELEASE  1  MOD  LEVEL  3




SECTION 1 - ROWS
PAGE
38  -  74/165
NUMBER
1
7.
3
4
5
6
7
R
p
10
11
12
13
14
15
16
17
18
l
26
27
28
29
10
31
3?
33
34
35
36
37
38
39
40
41
42
4?
44
4-5
46
47
48
49
...ROW..
COSTTOTL
COSTPIT
COSTFRT
COSTASH
COSTSC1
COSTSC2
COSTWSH
COSTREF
COSTS TO
COSTBRN
AM A
A»n
AMC
AMD
AVF.
4MF
AMG
AVH
DOA
DOB
DOC
DOD
ROE
OOP
onr,
DDH
DO I
DTJ
DDK
DHL
DOM
OON
DOG
OOP
ODD
DDR
EDA1
EOB
FDC
EOD
cne
EOF
EOG
FOH
EOI
POJ
EDK
EOL
FDM
AT
BS
FO
EO
FO
F.Q
EO
EO
FO
CP m rr
t/i O O
OS
BS
BS
BS
BS
BS
BS
EO
EO
EO
FO
F.O
EO
FO
FO
EO
EO
EO
EO
EO
FO
EO
EO
EO
EO
UL
UL
UL
UL
UL
UL
UL
Ul
UL
UL
UL
UL
UL
...ACTIVITY... SLACK ACTIVITY
413844.04347 413844
.
•
•
.
.
.
•
•
76.82086 49923
363.64020 44636
80.75896 49919
1622.28924 48377
50000
10193. 04145 39806
22914.55599 27085
50000
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862. OOOGO
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682. OOOCC
25608.00000
51307.00000
31488.00000
1B259. 00000
22420.79297
15592.79688
21271.19531
24027.59375
29404.79297
71429.93750
77834.37500
77924.37500
51862.78906
81014.37500
40153. 19141
104420.37500
37883.99219
04347-
..LOWER LIMIT.
NONE
..UPPER LIMIT.
NONE
•
.DUAL ACTIVITY
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
«. 37942-
17912
35980
24104
71076
00000
95855
44401
00000










NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570. 00000
115632.00000
25608.00000
51307.00000
31488.00000
18259.00000
NONE
NONE
NONE
NCNE
NONE
NONE
NONE
NONE
NONE
NGN?
NCNE
NONE
NONE
•
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682.00000
25f>08. 00000
51307.00000
31488.00000
18259.00000
22420.79297
15592.79688
21271.19531
24027.59375
29404.79297
71429.93750
77834.37500
77924.37500
51862.78906
81014.37500
40153.19141
104420.37500
37883.99219
1.00000
.00007
•
•
•
•
•
•
.66753-
.66753-
.49585-
.54416-
.52313-
.50792-
.59738-
.59738-
.66978-
.50038-
.53542-
.68096-
.66119-
.42550-
.58705-
.46645-
.49158-
.62192-
.02391
.02391
.02300
.02127
.02109
.02204
.02174
.02174
.02237
.02264
.02589
.02505
.02230

-------
HPSX-PTF13
FXECUTDR.  MPSX  RELEASE 1  MOO LEVEL 3
                                                                            PAGE
                                     39  -  74/165
 NUMBER  ...RflW.
    AT
.ACTIVITY...   SLACK ACTIVITY  ..LOWER LIMIT
.UPPER LIMIT.	.DUAL ACTIVITY
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
to 73
en 74
76
77
7R
79
30
31
92
83
R4
B-5
8A
87
R8
89
00
91
92
93
94
95
96
97
98
90
100
EON
EDO
EOP
EDO
FDP
SIZXDF
SIZXDG
SIZXOI
STZXDJ
SIZXDL
MZXDM
sr ZXDP
S! ZXDO
EOinF
F010G
EOIDT
E01HJ
•EQ10L
E010M
poino
E070F
EO?DG
F.02PJJ
E020P
EO'DO
E030G
E0301
F030L
E0300
E050F
PQ5DI
E05DJ
F05DL
F05HM
F050P
F05HO
E060F
F06DG
E060I
F06DJ
E060L
F060M
UL 138818.37500
UL 30729.59375
UL 61568.38672
UL 37785.59375
UL 21910.79297
EO
EO
FO
EO
FO
EO
EO
EO
BS
BS
SS
BS
BS
BS
BS
BS
RS
BS
BS
Ml.
. RS
BS
BS
BS
UL
UL
UL
BS
UL
UL
UL
UL
BS 1
BS . 1
BS . 1
BS . 1
BS . 1
BS . 1
BS . 1
BS . 1
EO
FO
EO
EO
EO
EO
NONE
NONE
NONE
NONE
NONE


NONE
NONE
NONE
NONE
NCNE
NONE
NCNE
NONE
NONE
NONE
NONE
NONE
NCNE
NONE
NONE
NONE
NCNE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
00000 NCNE
00000 NONE
00000 NONE
00000 NONE
00000 NONE
00000 NONE
00000 NONE
00000 NONE
.

138818.37500
30729.59375
61568.38672
37785.59375
21910.79297
•
•


•
•
"
-


ilooooo
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000


.03463
.02221
.02533
.02334
.02195
.25720
.25720
.25720
.24214
.25720
.25720
.25720
.25720

•
"
2384.72727

2186.00000
2186.00000
2186.00000
2186^00000
2186.00000
2186.00000
2186.00000


2186.00000-
2186.00000-
2186.00000-
2384.72727-
2186.00000-
2186.00000-

-------
MPSX-PTF13      EXECUTOR.   HPSX  RELEASE 1  MOO LEVEL  3




 NUMBER  ...BOW..  _AJ	._..'Ac.!lviIY-'-«_'	?k*?J^  *?TIVITY  ..LOWER LIHIT:
                               PAGE
                                                                                                                 40  -   74/165
..UPPER LIMIT.   .DUAL ACTIVITY
101 E060P
107 E0600
103 HDF
10* HOG
105 HIM
106 HDJ
107 Hf»L
10B MOM
109 HDP
110 MOO
111 .lf)F
HZ JOG
113 JO I
11* JOJ
115 JOL
116 JOM
117 JDP
118 JOO
119 STZYDN
120 SIZYDP
121 SI7YMA
12? SI7YMB
123 SI7YMC
to 124 STZYKO
<* 125 SI7YPA
126 SIZYPB
A 127 E003DN
A 128 PQ03DP
A 129 FQ01MA
A 130 COOV.B
A 131 EOO'^MC
A 132 E003MD
133 E003PA
A 134 E003PB
135 FON
136 FHP
.137 FMA
138 FMB
139 FMC
140 FMD
141 FPA
142 *PB
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
FO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO
EO













































2186.00000-
2186.00000-
.25720
.25720
.25720
.24214
.25720
.25720
.01071
.00763
.03150
.02568-
.00176-
.03150
.03150
.03150
.03150
.03150
1.90000
1.90000
1.9UOOO
1.90000
1.90000
1.90000
1.90138-
1.90000
•
•
•
•
•
27369.92598-
U90000
1.90000
1.90000
1.90000
1.90000
1.90000
1.90138-
1.90000

-------
MPSX-PTP13     EXECUTOR.



SECTION Z - COLUMNS
MPSX  RELEASE 1  MOD LEVEL 3
                            PACE
41  -  74/165
 NUMBER  .COLUMN.  AT
                        ..ACTIVITY	INPUT  COST..
                              .LOWER LIMIT.
.UPPER  LIMIT.  .REDUCED COST,
1*5 WMCOA BS
153 W-CDfl BS
73? WM8DL BS
252 WMFON BS
253 UMGOM BS
755 KMAOO BS
768 WMFnP BS
269 WMGOP BS
297 WSMCOG BS
305 WSMCOI OS
3*0 WSMFDP BS
509 XMGONOA BS
717 XMGONOB BS
9'. 0 XI F OP OC B S
9*1 XWiO°OC BS
11*6 XMODPOO BS
1149 XMGOPDD BS
135* XMDDPDE BS
1357 XMGOPOF BS
156* XVFRPOF BS
"J 1565 X.4GO?DC RS
2} 1770 XMnnPor, BS
177V XVGDPDG BS
1978 XMDDPOH BS
19fil XMCnPOH BS
2186 XVOnPDI BS
7139 XMGOPOI BS
2396 X1FOPOJ BS
?397 XMGOPDJ BS
2581 XMcr,MOK BS
2589 XMGONOK BS
2fll3 XMGHPDl BS
30ia xunnpoM BS
302! XMGOPOM BS
3*37 X^GOPOn BS
3360 XMFOPDO BS
3861 XWGOPOO BS
*066 XXDOPDH BS
4069 XMGODDR BS
5732 XSMFOPHO BS
5776 YMCMCDA BS
5881 YMDPAOH BS
6591 SS10F BS
6592 SSI DC BS
6593 SSini BS
659* SS10J BS
6595 SS10L BS
6596 SS1DM BS
6599 SS2DF BS
47.632*3
33.12652
363.6*020
3130.20596
2177.58003
76.'82088
1388.30127
965.79509
* *
772.85*39
537.49036
333.67151
121.*8937
7*6.90933
1*8.67780
91*. 0621*
1610.66787
1120.49119
393.5*955
2*19.51926
3<>4.00*61
2422.31695
262.23091
1612.17970
1926.78737
1270.835«0
905.41152
629.86472
3*89.52175
191.55070
1177.6*208
10*9.9B387
852.02*76
592.72521
110.78630
681.10762
* •
•
*
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NCNE
NONE
NONE
NOME
NONE
NONE
NONE
NPNE
NONE
NOME
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NOME
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
















.

-------
yf>SX-«>TF13     FXFCUTOR.   MPSX   RELEASE I   MOO LEVEL 3                                                 PACE



 NIJMBFR  .COLUMN.  AT   ...ACTIVITY	INPUT COST..  ..LOWER  LIMIT.  ..UPPER LIMIT.   .REDUCED COST.
42  -   74/165
6602 SS20J
6601 SS7DL
6604 SS20M
660? SS?OP
6606 SS200
f>607 S10F
6609 S3DF
6610 SI Of,
6612 S30C
6613 S101
6615 S3DI
6616 SIOJ
6618 S30J
6619 S10L
6621 S3DL
6622 SI DM
6624 S-»DM
6625 SlOP
6627 S30P
6578 SI HO
6630 S300
6631 CC10N
6632 CC10P
to 6633 CClf-'A
0* 6634 CC1MB
*•" 6635 CCl«1C
6636 ccno
6637 CCIPA
6638 CC1PB
6639 ClON
6641 C10P
6643 Cl^ft
6645 Cl^in
6647 CIMC
6649 CIMD
6651 CIPA
6653 C1»B
6666 ODL
6673 TPIT
6674 TFPT
6675 T4SH
6676 TSC1
6677 TSC2
6678 TWSH
6680 TSTO
6690 IN230F
6691 TN73DG
6692 IN230I
6693 1N230J
6694 TN21DL
6695 IN23DM
RS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
SS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS
BS 171510
BS 232084
RS 2128
OS
BS
BS
BS 8120
IV
IV
IV
IV
IV
IV













51717 I
66238 1
46262 1
1
1
1
40130 1















00000
00000
00000
00000
00000
00000
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NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NCNE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONC
NCNE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NONE
NCNE
NONE
NONE
NONE
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000



















-------
MPSX-PTF13
             EXECUTOR.   MPSX  RELEASE  L   MOO  LEVEL  3
                                                                                                  PAGE
                                                                                                            43  -  74/165
NUMBER . LULUMN.
6696 IN23DP
6697 IN2300
6698 IM120N
6699 IM120P
6700 TMI2MA
6701 TM12M8
6702 IM12XC
6703 fM12in
6705 IM12PB
A I . . . av. i i \
IV
IV .
IV
IV
IV
IV
IV
IV
IV
•



1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
t
L_ 	 	 	 	



0%
CO

-------
vo
                                 Case  2:   Spec.  =  20  Ib SO2/MMBtu

-------
PAGE
39  -  74/212
kl 1 AIR CD
i
?
3
4
A «;
ft
7
ft
9
10
11
12
13
14
15
16
17
IB
19
to ?1
•J 2?
0 23
24
25
26
27
28
29
30
31
32
13
14
35
36
37
•\B
39
40
. 41
42
43
44
45
46
47
48
49
-.-.-.ROW,...
rOSTTOTL
fOSTPIT
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BS
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--...ACTIVITV.-..-
318475. 250i4
-StAC*-ACT-IVJTV
318475.25054-
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NONE
..UPPER- L IMIT-.—
NONE
•
COSTFRT EO . • •
CQSTASH EO
COSTSC1 FO
COSTSC2
COSTWSH
JCOSTR.EE_
COSTSTO
COSTBRN
AM A
AMB
AMC
AMC
AME
AMF
AMG
AMH
OD A
DOB
one
ODD
DOE
DDF
nor,
ODH
DO I
DOJ
DDK
DDL
DOM
DON
or>o
DDP
DDO
DDR
EDA
FOB
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EDO
FOE
EOF
FflG
COM
EDI
EDJ
EOK
EDI
EDI
EO
EO
EO
EO
EO
BS.
BS
BS
BS
BS
BS
8S
BS
EO
FO
EO
FO
JEO
EO
FO
EO
EO
EO
EO
•
•
8650.43311
•
9499.41084
11383.36038
•
7097.99399
18634.00000
12994.00000
17726. OOOCO
20023.00000
24504.00000
59525.00000
64062.00000
64937.00000
43219. OOOCO
67512.00000
33461.00000
•
•
•
41349.56689
50000.00000
40500.58916
38616.63962
5000C. 00000
42902.00601
5000C. 00000
5COOO. 00000
•
•
•
•
•
•
•
•
•
•
EO 87C17. 00000
EO 31570. COOCO
EO 115682.00000
EO
EO
EO
EO
BS
BS
BS
BS
...us
BS
BS
BS
BS
BS
BS
BS
BS
25608.00000
51307. OCOCO
31488.00000
18259.00000
253180.45174
176077.22061
9195S. 86293
103876.35876
127123.12316
308606.88485
762474.61583
763356.26604
585645.79019
350242.25804
57328.97398
1179137.41006
427794.20154
•
•
•
120499.54826
83802.77939
262560.13707
296583.64124
362956.87684
881693.11514
53476!). 3U416
535383.73395
27d734. 20981
999997.74195
611891.02602
561202. 5B994
20J605.7S845
•
•
•
•
NONE
NONE
NCNE
NCNE
NONE
NONE
NCNE
NONE
18684.00000
12994.00000
17726.00000
20023.00000
24504.00000
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682.00000
25608.00000
51J07. 00000
31488.00000
18259.00000
NONE
NONE
NCNE
NUNE
NCNE
NCNE
NONE
NONE
NONE
NCNE
NGNE
NUNE
NONE
•
•
•
•
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
50000.00000
18684.00000
12994.00000
17726.00000
20023.00000
2A504.00COO
59525.00000
64862.00000
64937.00000
43219.00000
67512.00000
33461.00000
87017.00000
31570.00000
115682.00000
25608.00000
51307.00000
31488.00000
18259.00000
373680.00000
259880.00000
354520.00000
400460.00000
490080.00000
1190499.99999
1297239.99999
129H739. 99999
8643EO. 00000
1350239.99999
669220.00000
1740340.00000
631400.00000
nij AI ACTIVITY
1.00000
1.00000
1.00000
1.00000
1.00000
1.00000
29.29178-
l.OJOOO
1.00000
•
•
•
•
•
•
•
134358-
.34358-
.38662-
.43381-
.4U7J-
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.39114-
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.39307-
.46043-
.36617-
. 32 67 6-
.3i725-
.38235-
.36561-
•
•
•
•
•
•
•
•
•
•
•
•

-------
.NPSX-PTF16.   EXECUTOR.   MPSX   RELEASE 1  HOD LEVEl 4



 NUMBER.  ...ROW..,  AT   .. .ACT IVl TY. ... SLACK. ACT IV ITY   . .IOWFRJJ MITj
                               PAGE



. .UP.PER. JLJLM IT.   .DUAL ACTIVITY	
                                                                                                                40   -  74/212


A
A
A
A
A
A
A
A
A
I
A
A
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A

A


A
A
A
A
A

50
52
53
C A
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
Rl
82
83
R4
85
86
87
88
R9
90
91
92
91
94
95
96
97
98
99
100
EON
FOP
EDO
PHP
SIZXDF
SI7XDG
SI ZXDI
SIZXDJ
SI ZXDL
SIZXDM
SIZXDP
SIZXDO
F01PF
E01DG
E01DI
E01DJ
E010L
EOin.M
F01DP
F01DO
EOPOF
F02DG
F02DI
E020J
F02DL
E02DM
E02PP
E0700
E03DF
F_a3DC.
E03CI
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F03PM
F03DP
F0300
F050F
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F.05DI
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BS 198198.80960 2115441
BS 30103C. 64910 211129
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BS 163355.08089 466404
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BS 1
BS . 1
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BS . 1
BS . 1
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19039
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91910
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00000
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NONE
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NONE
NONE
NONE
NONE
NONE
NONE
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NCNE
NCNE
NONF
NONE
NONE
	 	 NCNE
NONE
NONE
	 NCNE
NONE
NONE
NONE
NCNE
NONE
NONE
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NONE
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NONE
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2313639.99999
512160*00000 . .
1026140.00000
629759.99999
365180. QOOOO

•

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26293-

-------
.MPSX-PTF16.   EXECUTOR.

..NUMBER.  ...ROIn_.  AT. .
 PPSX  PELEASF I  MUD LEVEL 4

.ACTIVITY....  SLACK ACTIVITY   . .LOWE PJLI MIT ,
                             PAGE     41   -  74/212

.UPPER LIMIT.	-QUA!  ACTIVITY			
A 101
A ..102-
103
A 104
a 105
A 106
A 107
1 08
A 'l09~
A 110
111
A 112
A 113
A 114
A 115
116
117
A 118
1 19
	 120..
fJ 121
>J 1??
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127
128
129
130
131
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133
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140
141
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SIZYON
STZYDP
SI7YKA
SIZYMB
S I 7 YMC
SI ZYMD
SI/YPA
SIZYPB 	
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FHA
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FMC
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                                                                                                 .18274-
                                                                                                 .03150
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! * .3841
-------
.MFSX-PTF16.   FXFCUTOR.




SECTION 2.- COLUMNS






 MIMBFB-  .COLUMN.  AT
                           MPSX   RELEASE I  MOO LEVEL 4
                                                                                                        PAGE
                                                                                       42  -  74/212
.ACTIVITY.,..
..INPUT COST.
145
153
191
199
709
733
741
252
255
766
_ 2 79
295
305
321
938
1146
1154
1562
7394
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5306
5730
6162
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6800
6801
6802
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6805
6806
6807
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6819
6822
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6830
6831 '
6831
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637.96151
3230.82464
3234.56045
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4272.24077
1549.98036
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1275.55360
2146.55740
909.49442_.
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837.71257
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NONE
NONE
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NCNE
NONE
NCNE
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-------
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-------
MPSX-PTF13     EXECUTOR.   MPSX  RELEASE  1   MOO LEVEL  3




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-------
MPSX-PTF13     EXECUTOR.   MPSX  RELEASE I  MOD tJSEL  3                                                 PAGE




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-------
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25  -  74/16*
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250
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254
266
268
320
318
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-------
MPSX-PTF13     EXECUTOR.  PPSX  RELEASE 1  MOD LEVEL  3



 NUMBER  .COLUMN.	AT  ...ACTIVITY	INPUT CC'STl.  ..LOWER  LIMIT.  ..UPPER LIMIT.   .PEDUCED COST.
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-------
PAGE:
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-------
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-------
PAGE
53  -  74/163

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-------
MPSX-PTF13
               EXFCUTCJR.   MPSX   RELEASE  1   KCD LEVEL 3
                                                                                                       PAGE
                                                                                        54  -   74/163
 NUMBER  ...ROW
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-------
MPSX-PTF13
EXECUTOR.  HPSX  RELEASE L  MOO LEVEL 3
                                                                                                     PAGE
                                                                                              55  -   74/163
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-------
MPSX-PTF13     EXECUTOR.




          - COLUMNS
MPSX  RELEASE 1  MOO LEVEL  3
PAGE
56  -  74/163

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-------
MPSX-PTF13
EXECUTOR.  MPSX  RELEASE 1   MOD LEVEL  3
                                                                                                    PAGE
                                                                                             57  -   74/163
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-------
MPSX-PTF13     EXECUTOR.   KPSX   RELEASE  1   MOD LFVEL 3                                                PAGE

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58  -  74/163
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-------
S                                    Case  3:   Spec.  = 20  Ib SO_/MMBtu
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-------
MPSX-»TF13     EXECUTOR.  MPSX  RELEASE I   MOO LEVEL 3
                                                                                                     PAGE
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-------
MPSX-PTF13      F?ECUTOR.   KPSX   PELFASE I  MOD LEVEL 3

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-------
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-------
MPSX-PTF13     EXECUTOR,



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-------
MPSX-PTF13     E>ECUTCR.   MPSX  RELEASE 1   HCO LFVEL  3                                               PACE



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-------
MFSX-PTF13     FXECUTOR.  NPSX  RELEASE 1  MOO LEVEL 3                                               PAGE



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-------
MPSX-PTF13     EXECUTOR




SECTION 2 - COLLINS
KPSX  PFLFASE 1  MCC LFVEL 3
                                                                                                      CASE
-  74/179

199
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-------
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MPSX-PTFU     FXECUTOR.   KPSX.  PEIEASE  i   VCD LEVEL 3
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-------
MPSX-PTF13     EXECUTCft.  I*PSX  RELEASE I  MOD LEVEL  3                                                PAGE     23   -  74/179




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-------
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-------
MPSX-PTF13     EXECUTOR.  MPSX  RELEASE 1  I*CO LEVEL  3




SECTION 1 - ROWS
PAGE
19  -  74/179
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-------
MPSX-PTF13     FXFCUTOR.  MPSX  RELEASF  1   HOD LEVEL 3




         ...POta..  AT  ...ACTIVITY...   SLACK  ACTIVITY  ..LOWER LIPIT.
                             PAGE



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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
  REPORT NO
   EPA-650/2-74-127
                                                           3. RECIPIENT'S ACCESSION-NO.
 4. TITLE AND SUBTITLE
   Evaluation of Sulfur  Dioxide Emission Control
   Options for Iowa Power Boilers
                                 5. REPORT DATE
                                   December,  1974
                                 6. PERFORMING ORGANIZATION CODE
 7. AUTHOR(S)
   D. 0. Moore, Jr., J. M.  Peters, W. S. Alper,
   E. Rosen, and J. R.  Burke
                                 8. PERFORMING ORGANIZATION REPORT NO
9 PERFORMING ORGANIZATION NAME AND ADDRESS
   The M. W. Kellogg Company
   1300 Three Greenway  Plaza East
   Houston, Texas  77046
                                  10 PROGRAM ELEMENT NO.
                                    1AB013; ROAP  21ADD-079
                                  11. CONTRACT/GRANT NO.
                                                             68-02-1308, Task 3
 12. SPONSORING AGENCY NAME AND ADDRESS
   EPA, Office of Research  and Development
   NERC-RTP, Control  Systems  Laboratory
   Research Triangle  Park,  N.  C.  27711
                                  13. TYPE OF REPORT AND PERIOD COVERED
                                   Final; 7/73-11/74
                                 14. SPONSORING AGENCY CODE
 15. SUPPLEMENTARY NOTES
 16. ABSTRACT           •	
        The report gives  results of an evaluation of S02  emission control strategies
   for major coal burning boilers in Iowa, considering options  such as using low-
   sulfur Eastern and Western coals, mechanical coal cleaning,  and flue gas desul-
   furization  (FGD).  Major  utility boilers were surveyed, probable coal sources
   were determined, and alternate transportation routes were defined.   Coal cleaning
   plant and FGD design studies were performed.  Cost data were generated and a
   linear computer program model was developed to determine minimum cost strategies
   for meeting emission levels corresponding to no-control and  control to 5.0, 3.1
   and 1.2 Ib S02/MM Btu.  For the cases studied, FGD was most  cost effective only
   for the most restrictive  emission level (1.2 Ib/MM Btu) and  when the supply of
   low-sulfur coal was limited.   Importing low-sulfur Eastern and Western coals or
   combinations of mechanical coal cleaning and low-sulfur coal import gave the
   lowest cost for all other cases.   These conclusions are not  generally applicable
   to other states because of differences in the distances low-sulfur  coal must be
   transported, the washability characteristics of local  coals, the size of the
   power plants, the power plant network and other factors.
17.
                               KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                             b IDENTIFIERS/OPEN ENDED TERMS
                                              c  COSATI Field/Group
   Air Pollution
   Sulfur Dioxide
   Boilers
   Electric Power Plants
   Utilities
   Coal
Flue Gases
Desulfurization
Coal Preparation

Transportation
Cost Effectiveness
Air Pollution Control
Stationary Sources
Iowa
Low-Sulfur Coal
13B, 21B
07B, 07A, 07D
13A, 081
10A
     15E
21D, 14A
 8 DISTRIBUTION STATEMENT

  Unlimited
                    19. SECURITY CLASS (ThisReport)
                      Unclassified
                         21 NO. OF PAGES
                              331
                                             20 SECURITY CLASS (Thispage)
                                                Unclassified
                                                                        22 PRICE
EPA Form 2220-1 (9-73)
                                           323

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                                                        INSTRUCTIONS

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         Insert the EPA report number as it appears on the cover of the publication.

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        Indicate interim final, etc., and if applicable, dates covered.

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    IS.  SUPPLEMENTARY NOTES
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        To be published in. Supersedes, Supplements, etc.

    16.  ABSTRACT
        Include a brief (200 words or less) factual summary of the most significant information contained in the report.  If the report contains a
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    17.  KEY WORDS AND DOCUMENT ANALYSIS
        (a) DESCRIPTORS - Select from the Thesaurus of Engineering and Scientific Terms the proper authorized terms that identify the major
        concept of the research and are sufficiently specific and precise to be used as index entries for cataloging.

        (b) IDENTIFIERS AND OPEN-ENDED TERMS • Use identifiers for project names, code names, equipment designators, etc. Use open-
        ended terms written in descriptor form for those subjects for which no descriptor exists.

        (c) COSAT1 FIELD GROUP - Field and group assignments are to be taken from the 1965 COSATI Subject Category List. Since the ma-
        jority of documents are multidisciplinary in nature, the Primary Field/Group assignment(s) will be specific discipline, area of human
        endeavor, or type of physical object.  The appucation(s) will be cross-referenced with secondary Field/Group assignments that will follow
        the primary postmg(s)

    18.  DISTRIBUTION STATEMENT
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        the public, with address and price. /

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    21.  NUMBER OF PAGES
        Insert the total number of pages, including this one and unnumbered pages, but exclude distribution list, if any.

    22.  PRICE
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EPA Form 2220-1 (9-73) (Reverse)

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