f/EPA
             United States
             Environmental Protection
             Agency
               Region V
               Air & Radiation Branch
               230 S. Dearborn Street
               Chicago, Illinois 60604
EPA 905/2-83-001
June 1983
The Impact of
Coal Cleaning as a
Sulfur Reduction Strategy
In the Mid west
 Do not WEED. This document
 should be retained in the EPA
 Region 5 Library Collection.

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      THE IMPACT OF COAL  CLEANING  AS A
  SULFUR REDUCTION STRATEGY  IN  THE MIDWEST

                     by

         R.D.  Doctor,  J.L. Anderson,
D.B. Garvey,  C.D. Livengood,  and P.S. Farber
              EPA  905/2-83-001
                ANL/ECT-TM-7
         ARGONNE NATIONAL LABORATORY
           9700  South Cass  Avenue
          Argonne,  Illinois  60439
             IAG  No.  AD89F2A161
    Project Officer:  Rizalino Castanares
                  June 1983
    U.S. Environmental Protection
    Region 5, Library 
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                                ACKNOWLEDGMENTS
       The  authors  gratefully  acknowledge  the valuable  contributions of  the
EPA project officers, John  Paskevicz and Rizalino Castanares, to  the  planning
and  performance  of  the  work  presented in  this  report.   Thanks  are  also
extended to B.C.  O'Meara and L.S.  Benson  of  Argonne for  their  preparation of
the printed text.
                                     iii

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                                   CONTENTS


ABSTRACT	    1

1  INTRODUCTION	    1

2  POWER PLANTS IN THE STUDY REGION	    4

   2.1  Screening Criteria	    4
   2.2  Characteristics of Plants	    4
   2.3  Characteristics of Fuel Supplies	    4
        2.3.1  Data Sources.	    4
        2.3.2  Coal Washability Data	    6
        2.3.3  Current Status of Coal Washing	    6

3  DESULFURIZATION TECHNOLOGIES	    7

   3.1  Physical Coal Cleaning	    7
        3.1.1  PCC Commercial Technology	    7
        3.1.2  PCC Systems Overview	   10
        3.1.3  PCC Level 1 System	   10
        3.1.4  PCC Level 2 System	   12
        3.1.5  PCC Level 3 System	   15
        3.1.6  PCC Level 4 System	   17
        3.1.7  PCC Existing Capacity	   21
        3.1.8  PCC Equipment Service	   21
        3.1.9  PCC Costs	   30
   3.2  Flue-Gas Desulfurization	   30
        3.2.1  FGD Commercial Technology	   30
        3.2.2  FGD Existing Capacity	   32
        3.2.3  FGD Equipment Service	   34
        3.2.4  FGD Costs	   34

4  COMPARISON OF PCC AND FGD	   38

   4.1  Emissions Corresponding to ROM Coal	   38
   4.2  Emissions under 1980 Conditions	   39
   4.3  Purchase Patterns for Coal in 1980	   39
   4.4  Emissions with Full, Cleaning	   42
   4.5  Comparison of PCC and Partial FGD  Costs	   52
   4.6  Statewide Sulfur Reductions	   53

5  REGULATORY AND INSTITUTIONAL CONSIDERATIONS	   56

   5.1  Background	   56
   5.2  Constraints on Voluntary Use of Cleaned Coal....	   57
   5.3  Options for Increasing the Use of  Cleaned Coal.....	   58
        5.3.1  Policies to Encourage the Use of Cleaned  Coal	   58
        5.3.2  Policies to Require the Use of  Cleaned Coal	   60
                                       v

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                              CONTENTS  (Cont'd)


6  CONCLUSIONS	   62

   6.1  Data on Power Plants' Coal Usage	   62
   6.2  Emission Reductions Due to Coal Cleaning	   63
   6.3  Coal Cleaning vs. Partial FGD	   63
   6.4  Regulatory and Institutional Considerations	   64

REFERENCES	   67

APPENDIX A:   COAL SUPPLY DATA	   69

APPENDIX B:   COMPUTER MODELS OF COAL PREPARATION	   77

APPENDIX C:   COMPARISON OF PCC AND PARTIAL FGD DATA	  113


                                    FIGURES


 1   Block Diagram for Level 1 PCC	   12

 2   Block Diagram for Level 2 PCC	   13

 3   Block Diagram for Level 3 PCC	   16

 4   Block Diagram for Level 4 PCC	   22

 5   Physical Coal Cleaning Plants in Illinois, Indiana, and Ohio	   23

 6   Coal Sulfur Content vs. Equivalent Scrubbing Capacity, 1980	   33

 7   Summary and Comparison of Calculated FGD System Availabilities.......   35

 8   Power-Plant S02 Emission Rates, 1980	   40

 9   Power-Plant S02 Emissions, 1980	   41

10   Number of Power-Plant Coal Purchases	   43

11   Coal Tonnages Corresponding to Power Plants' Purchases	   44

12   Sulfur Dioxide Emissions Rates for Selected Utilities	   45

13   Total Sulfur Dioxide Emissions for Illinois, Indiana,  and Ohio	   55

C.I  Cumulative S02 Removal as a Function of Cost	  116
                                       VI

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                                    TABLES


  1  Power Plants with Coal-Firing Capacities of 500 MWe or Greater	    5

  2  Levels of Physical Coal Cleaning	    7

  3  Major Equipment for Level 1 PCC Plant	   11

  4  Major Equipment for Level 2 PCC Plant	   14

  5  Major Equipment for Level 3 PCC Plant	   18

  6  Major Equipment for Level 4 PCC Plant	   20

  7  Inventory of Illinois PCC Plants	   24

  8  Inventory of Indiana PCC Plants	   27

  9  Inventory of Ohio PCC Plants	   28

 10  Adjusted Capital and Annual Costs for Operational FGD Systems  by
     Process Type	   37

 11  Summary of PCC Sulfur Reductions, PCC Costs, and FGD Costs	   54

A.I  Available Preparation Equipment for Coal Mines in Illinois	   72

A.2  Available Preparation Equipment for Coal Mines in Indiana	   73

A.3  Available Preparation Equipment for Coal Mines in Kentucky	   74

A.4  Available Preparation Equipment for Coal Mines in Ohio	   75

A.5  Available Preparation Equipment for Coal Mines in Pennsylvania.	   76

C.I  Data on PCC and Partial FGD	  115
                                      VII

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                       THE IMPACT OF COAL CLEANING AS A
                   SULFUR REDUCTION STRATEGY IN THE MIDWEST
                                      by
                          R.D.  Doctor,  J.L.  Anderson,
                 D.B. Garvey, C.D. Livengood, and P.S. Farber
                                   ABSTRACT
               The   potential   for  reduction   of   sulfur   dioxide
        emissions  through  coal  cleaning  is  examined  for  electric-
        utility  power  plants  in  the   Ohio,  Indiana,  and  Illinois
        region.  Twenty-four plants burning predominantly high-sulfur
        coal  and having capacities of 500 MWe or greater are identi-
        fied,  and  the  characteristics  of  their  coal supplies  are
        analyzed.   The sulfur reductions attainable via coal cleaning
        for  the  various coals  are estimated,  and  the  costs  are com-
        pared  with  those   for  equivalent  sulfur  dioxide  reductions
        using  flue-gas desulfurization.   Coal cleaning is shown to be
        a  cost-effective option  for  approximately half of the plants
        studied,  although  the  total  sulfur dioxide  reduction poten-
        tial  is  much less  than  for flue-gas  desulfurization.

               Regulatory   and  institutional considerations  relevant
        to  mandatory coal  cleaning requirements  are evaluated, as are
        options  for  encouraging  greater  voluntary  use  of  cleaned
        coal.   Actions at  the  state  level to promote  greater use of
        cleaned  coal are found  to be  most  likely.
                                1   INTRODUCTION
       Reduction in sulfur dioxide  (802) emissions  from  stationary  sources  has
long been  one  of the most prominent  objectives of pollution-control  legisla-
tion and  regulation.   Emphasis at the  federal level has  been on  developing
requirements for new coal-fired power plants  and  industrial boilers,  but  the
possible impacts of emissions from  existing facilities has  recently been given
new  importance in  the  continuing  studies of  acid-rain causes  and  effects.
Many  such  facilities  are   operating  under  emission  regulations  much  less
stringent  than  those  for new boilers  and  can be  expected  to  continue  in
operation  for  a number of years.   This  is particularly  true in light  of  the
recent  slowdown in  new  power plant  construction.   Thus,  any  strategy  for
regional  or  national reductions  in S02  emissions  must  consider  options  for
increased control of existing sources.

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       This study had as its primary  focus  the  question  of  what  SC>2 reductions
could be obtained in  the Midwest by applying extensive  physical coal cleaning
(PCC) to fuels  being  burned by  major power plants.  In addition,  we examined
briefly the cost tradeoffs betwen coal cleaning  and  partial flue-gas desulfur-
ization  (FGD),  as  well as  the  legislative/regulatory  options  available  for
implementing a requirement for coal cleaning.

       The study involved  24  power  plants in Illinois,  Indiana,  and Ohio that
have  capacities  of  at  least 500 MWe,  burn  coal  with  more than  one  percent
sulfur, and  have  no FGD  systems.   We examined the Federal Energy Regulatory
Commission (FERC) records  (form 423) of  1980  coal purchases for  these plants
to determine the states, counties, and mine seams  that were the  sources of the
principal coals supplied to each plant.   After making  these determinations,  we
used  the  coal-cleaning  ("washing")   characteristics  of  these  coals (as  pre-
viously determined  by  the U.S. Bureau  of Mines)  in conjunction  with a  PCC
computer code to model  the results  of coal washing  for  these plants.  All but
one of  the  coals  surveyed showed some  reduction in total  sulfur  content  with
cleaning.   These reductions varied from 0-50%, with  an average value of 29%.

       The costs of equivalent  sulfur dioxide  reductions  by means  of  PCC and
FGD  were  estimated and  compared  on the  basis  of  dollars  per  ton  of  S02
removed.   The results  indicate that  PCC is the  most  cost-effective  control
option for about half of the plants.  However,  it  must be noted  that FGD has a
greater total potential for S02  control due to  the higher removal  efficiencies
possible with currently available technology.

       Another factor that makes evaluation of  the study results  difficult  is
that most of  the  coals studied  appear  to already be receiving  some degree  of
cleaning.     Since   this information  is  not  reported  by   the  utilities,  we
inferred the use and  degree  of  cleaning  through analysis of raw and delivered
coal characteristics together with information  on  cleaning  equipment available
at  specific  mines.    Considerations,  aside from environmental  concerns,  that
promote the use of  cleaning include the large quantities of refuse produced  by
certain mining techniques, high  shipping  charges that  make  preshipment  removal
of mineral matter (ash) desirable, and plant operational benefits  attributable
to cleaner and less variable coal.   PCC  has already  achieved wide acceptance,
although the  high  degree  of  cleaning observed  in  this  study is usually  only
applied to metallurgical coals.  Thus,  the potential S02 reduction achievable
by mandatory PCC  is actually somewhat less  than projected  in this report,  by
an amount corresponding to current washing  practices.

       Many  plants  also fire  a variety  of  coals, some of which  differ  sub-
stantially in sulfur  content  from  the principal coals analyzed  in  this study.
Thus, actual  emissions  may  differ  significantly from those predicted  on the
basis of  a  single  coal per  plant.   However, while  this fact and  the  current
use of  coal  cleaning  may make development of a  suitable control strategy more
challenging,  they  should  not  obscure  the  conclusion  that  PCC  can  make  a
significant and cost-effective contribution to  S02  control  for many facilities
in the Midwest.

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       Chapter  2  of  this  report gives  the criteria  used in  selecting power
plants for  this  study and summarizes  the  plant characteristics,  fuel charac-
teristics and sources of data.   Chapter  3  presents  descriptions of current PCC
and FGD  technology,  while Chapter  4 presents  the  study  results  and compares
the two  approaches  to SC>2  control.  Policy  issues and the  conclusions drawn
from the results are given in the final  two chapters.

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                      2   POWER PLANTS IN THE STUDY REGION


2.1  SCREENING CRITERIA

       Criteria for  screening  power plants in the study region  included  size,
fuel, fuel sulfur  content,  and current emissions control technologies.   Table
1 lists the 24 plants chosen for study  as  a result of  this  screening.

       The specific screening  criteria  were:

       •  Survey region:  Illinois,  Indiana,  and  Ohio

       •  Power-plant size:  500 MW  or  greater

       •  Fuel:  Coal with a sulfur  content exceeding  1%

       •  Emissions  control technologies:   Power plants or individual
          units with FGD systems were  eliminated  from  consideration.


2.2  CHARACTERISTICS OF PLANTS

       The breakdown  of  power  plants with coal-firing capacities  in  excess  of
500 MW  and  no FGD  capacity (or FGD  capacity limited to recently  constructed
units) is shown in Table 1.  Twenty-four  plants were  identified, of which only
five were of  less  than 1000 MW  capacity  and  only four were greater  than 2000
MW.   The typical  power  plant therefore  falls  in the  range  of  1000-2000  MW.
The  states  rank as  follows:    Ohio -  eleven plants,  Indiana  - nine  plants,
Illinois -  four plants.   For purposes of  this  study,  these plants  have been
randomly ascribed identifying  letters,  which  will be used  for  the remainder of
the report.


2.3  CHARACTERISTICS OF FUEL SUPPLIES


2.3.1  Data Sources
       Public  utilities  are  required  to  file  monthly  statements  with  the
Federal  Energy Regulatory  Commission  describing the  sources  of  their  coal.
This  one-page  form,  FERC-423,  requests information  about the  state,  county,
and  name of the  producing  mine;  coal  quantities  purchased;  and  the  heating
value, ash,  and  sulfur content  of  the  coal.   This information  is  part of the
public record  of utility  activity that  is available  to any interested party at
either the  regional FERC offices or  the  main office  in Washington,  D.C.   The
Energy Information  Agency (EIA)  regularly abstracts  the information from these
forms  relating to  coal  quantity  purchased,   heating  value,  ash,  and  sulfur
content.  These computer  files were also available  to this study.

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   Table  1   Power  Plants  with Coal-Firing Capacities of 500 MWe or Greater'
State Plant Names
Illinois Coffeen

Kincaid
Joppa Steam
Baldwin
Indiana Petersburg

E.W. Stout

Bailly

Michigan City

Cayuga

R. Gallagher

Gibson

Wabash River

Clifty Creek

Ohio Cardinal
W.C. Beckjord

Miami Fort

Avon Lake

East lake

Conesville

R.E. Burger
Sammis
Kyger Creek
Muskingum R.
J.M. Gavin
Unit
Numbers
1,2

1,2
1-6
1-3
1-3

5-7 ,A3 ,A4

7,8

2,3,12

1,2

1-4

1-4

1-6

1-6

1-3
1-6

5-8

6-9

1-5

1-6

1-5
1-7
1-5
1-5
1,2
Total
Capacity
(MWeb)
1006

1319
1098
1892
1338

705

616

661

1062

600

2672

962

1304

1865
1221

1377

1085

1257

2135

546
2304
1086
1507
2600
Utility
Central 111. Public
Service Co.
Commonwealth Edison
Electric Energy, Inc.
111. Power Co.
Indianapolis Power
& Light Co.
Indianapolis Power
& Light Co.
Northern Ind. Public
Service Co.
Northern Ind. Public
Service Co.
Public Service Co.
of Indiana
Public Service Co.
of Indiana
Public Service Co.
of Indiana
Public Service Co.
of Indiana
Indiana-Kentucky
Electric Corp.
Buckeye Power Co.
Cincinnati Gas &
Electric Co.
Cincinnati Gas &
Electric Co.
Cleveland Elec.
Illuminating Co.
Cleveland Elec.
Illuminating Co.
Columbus & Southern Ohio
Elec. Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Valley Electric Corp.
AEP: Ohio Power Co.
AEP: Ohio Electric Co.
aInventory of Power Plants in the United States,  1980 Annual, U.S. Depart-
 ment of Energy Report DOE/EIA-0095 (June 1981).

^Nameplate (gross) capacity.

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       For purposes  of all but a  very approximate analysis  of  performance of
coal  cleaning  systems,  it  is essential  that information  about  the  specific
seam being mined  be  obtained.  For this study, we  manually examined the FERC-
423  forms  for  1980   and  attempted  to  reconcile those   data  with  industry
reference sources  to  provide the  best  basis  for  the  washability calculations.
Part  of  this  information had  already been  summarized in another study  for
plants in Ohio.

       The details  of  this data acquisition, including  additional information
for the 53 mines it was possible to identify, are  summarized in  Appendix A.
2.3.2  Coal Washability Data

       The coal washability  data were derived by  integrating  coal washability
and coal  reserves  data obtained  from  the  U.S. Bureau of Mines.   Two computer
programs  previously  developed by Argonne   matched the appropriate  entries in
each data set and then merged the data.  Approximately 18%  of  the demonstrated
coal reserves were  matched with  washability  data.  However,  about  35%  of the
reserves that account for 80% of  current production  were  successfully matched.

       Specifications as to the  location and  size  of the  reserve, and descrip-
tions of  the coal with  data  on selected physical  and  chemical characteristics
were also included.   Washability data are presented for  three crush top sizes
(1.5 in., 3/8 in., and 14 mesh)  and  several specific gravities.   In each case,
the  values   of  percent  recovery,  Btu/lb, percent  ash,  percent  sulfur,  Ib
S02/106 Btu, and reserves available  at 1.2  Ib S02/106  Btu are  given.
2.3.3  Current Status of Coal Washing

       Information about the potential  ability  of  any mine to wash coal can be
obtained  by  reviewing  the  reported information  about preparation  equipment.
However,  the  coal washing  plants  produce a  variety of products,  including a
stream of  tailings,  that are  high in  sulfur and  ash content.   Because these
tailings  are  being sold  to the utilities  in a few cases, the  situation can
arise where  a plant with  the  capability  for a high  level of cleaning is in
fact selling  a  coal  high in sulfur and ash content  to the utility.   Levels of
cleaning were assigned  to the output  from each mine based on  a  comparison of
the washability data with the full  series  of  mine  shipments during the year.

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                        3  DESULFURIZATION TECHNOLOGIES
       Commercially available desulfurization  technologies  fall  into two basic
categories.   The  first of these  are  techniques, such as physical  coal clean-
ing, that effect the sulfur removal prior  to combustion.  Although  these tech-
nologies  have been developing  for over 100 years,  a number  of new  and  com-
                                                       A
mercially significant  approaches  are being considered.    The second  class  of
desulfurization  technologies effects  the  post-combustion  control of  sulfur
dioxide  through  the   use of   flue-gas  desulfurization,  which  has  been  in
commercial use  at  power plants for  about  15  years.   An overview of these two
contrasting methods follows.
3.1  PHYSICAL COAL CLEANING

       Physical  coal  cleaning  processes  remove clay,  shale,  and pyrite  from
run-of-mine (ROM) coals.   Cleaning is achieved by grinding  the  coal  to liber-
ate  impurities  that  are  not  chemically bound  and then  taking advantage  of
specific gravity differences  between  the organic matter that formed  the coals
(called macerals) and the denser mineral  impurities.   Sometimes  differences  in
surface-wetting  properties  between  macerals  and  impurities  are  used  for
separation.

       General cleaning strategies for plants  depend on  the  desired  level of
coal cleaning.  These levels are assigned as shown in  Table  2.
3.1.1  PCC Commercial Technology

       PCC plants  may involve  up to  four major  subsystems:   1)  comminution
(size reduction),  2)  screening,  3)  concentration, and  4)  dewatering.   These
subsystems have  to be  tailored  to  the  specific  coal  and desired  level  of
                   Table  2   Levels  of Physical Coal Cleaning


Level
0
1
2
3
4



No Preparation (ROM)
Top Size Control
Coarse Beneficiation
Moderate Beneficiation
Full Beneficiation

Weight
Yield (%)
100
98-100
75-85
60-80
60-80
Btu
Recovery
(%)
100
100
90-95
80-90
80-90
Reduction

Ash
None
Fair
Good
Good
Excellent

Sulfur
None
None
.Fair
Fair
Good

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                                       8
cleaning.  This  requirement contrasts markedly with  the  general  applicability
of flue-gas desulfurization.
       Comminution

       One  of  the  main  goals  of  the  crushing  operation  is  to  achieve  a
specified  top-size  without creating  excessive  difficult-to-clean fines.   The
optimum size to which coal is crushed depends on  its  washability and end-use.

       Rotary  breakers   are  most  often  used  for preparation of  deep-mined
material with a significant amount of roof  and  floor  material.   Radial lifting
shelves in the  unit  lift  and  drop coals as the unit  rotates.   Stones, shales,
logs, and  other debris  too large to pass through  the perforations in the drum
are conveniently discarded.  Breakers are the lowest  in  fines  production.

       Roll crushers squeeze the coal between tooth-covered  rollers.  They are
also low in fines production and are  capable of reducing ROM coal to 1 1/2 in.
or less.

       Hammer mills throw  coal against breaker  blocks and grate bars until the
product is reduced to the  size of  the grate opening.   These  machines produce a
large quantity of fines in comparison with  the  above  techniques.

       Magnets are often included  directly  after  coarse  sizing and crushing in
the comminution circuit.   "Tramp iron" that may be present in  the crushed coal
is removed by these magnets so that  it will not damage downstream equipment.
       Screening

       Either wet  or dry methods may  be used to classify  coal  into different
size  ranges  before  introduction to  coal-cleaning circuits.    Screens  remove
rocks and  foreign  material prior to  crushing,  and later in  the circuit other
screens are used to  separate coal into  coarse and  fine  fractions for marketing
or further preparation.   For  a Level 1  circuit, comminution  and screening are
the only system operations.  More advanced  circuits use screening for recovery
from heavy-media circuits and  dewatering of coarse  coal.
       Concentration
       Concentration  is  the  operation in which  the  coal  and impurities  are
actually separated.   General methods  can  be classified as water-only,  heavy-
media,  and  dry  separation.   Some   specialized  fine-coal  recovery  methods
include froth flotation and  oil agglomeration.

       Jigs  are  the oldest  and  simplest  of  all  coal washing devices.   Their
principal  service is  on  coarse-sized  coal,  and they  remain the most  widely

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 used devices in this country.   In  jigging,  a series of pulses  (at the  rate  of
 one  pulse  per second)  moves up through the coal-filled bath to  provide  a  rough
 classification of  the coal  and mineral  impurities by  density.   The denser
 impurities  are drawn off  the  bottom and  discarded,  while the  top fraction  is
 withdrawn  as product coal.  These  devices produce a large "middling" product,
 which  is either recycled  or sent to other concentrating systems.

       The  concentrating  table  is widely  used  for fine-coal cleaning.  Tables
 are  large   tilted  rhomboid-shaped  decks  with  ridges  (riffles)  that  span the
 table  diagonally.   Reciprocating motion  of the  table  causes  feed material  to
 fan  out  onto the deck into strata  of  different density.   Tabling concentrates
 the  heaviest and finest  of the particles at the bottom  of  the deck while the
 lightest  and  coarsest  particles  congregate at  the top  of  the deck.   This
 system is   particularly  applicable  for washing  soft  and friable  coals  that
 degrade easily.

       Hydrocyclones  are  separating devices for medium- to  fine-sized  coal.
 These  devices make  use of high  centrifugal  forces to effect the separation  of
 denser impurities  from the coal.  Heavy-media  cyclones add  325-mesh magnetite
 to  the wash  circuit  to  increase   the  wash water's  apparent  density  (to  a
 specific gravity,  or  S.G.,  of  1.3-1.8),  which provides  for  a  finer "cut"  on
 the  pyritic impurities.   Currently, this  represents  the  most  advanced form  of
 physical coal cleaning available.   The circuit  becomes  more  complicated by the
 need to recover magnetite  so  as to  minimize processing  costs.   The dense-media
 recovery unit is generally a  drum-type  magnetic separator that  provides for
 the  effective recovery of  all  but the  smallest  of magnetite  particles.

       Froth flotation has come into wide use  for the  recovery of the heating
 value  of  coal  fines  produced  by  the  comminution step.    In  contrast  to the
 other  concentrating  processes, flotation does  not use  specific  gravity as the
 basis  of  the separation.   The wetting  properties  of the macerals and the
 impurities  are characteristically different,  the  ash being hydrophilic (water-
 attracting)  while  the  macerals are hydrophobic  (water-repelling).    Blowing
 fine  bubbles of air  through the aqueous  phase  (usually  enhanced  by surfact-
 ants)  floats  the coal up to  the surface for  recovery.

       While  flotation is  effective in ash removal,  one  serious deficiency  is
 its  difficulty in  selectively  rejecting  pyrites.   The wetting  properties  of
 pyrites are similar  to those  of coal  macerals,  and  it is generally necessary
 to reclean  the froth,  with slight  modifications  of  the surface  tension, so as
 to remove the pyrites.
       Dewatering

       After washing the coal, excess moisture  must  be reduced to minimize the
penalties incurred  in decreased  heating  value of  the fuel,  increased  trans-
portation costs,  and  handling and  shipping  problems.   The  types of equipment
used  in  this  service  are  directly  related  to the  coal  grind.   They  are

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                                      10
screens,  centrifugal  dryers,  various types  of  vacuum dryers,  filter  presses,
belt filters, thermal dryers, and water clarifiers.
3.1.2  PCC Systems Overview

       General cleaning strategies for plants depend  on which  of  the  following
levels of coal cleaning are desired.

       1.  Run-of-Mine.  Level  1  involves  no cleaning but reduces ROM
           coal to user's  size  specifications,  prepares  it  for ship-
           ment,  and  possibly reduces moisture  content  (an important
           consideration for  low-rank western coals).   Coal prepared
           in  Level  1 facilities  may have  to  be blended  with other
           coals to meet S02 emission standards.

       2.  Coarse-to-Moderate Beneficiation.  Levels  2 and 3 use low-
           efficiency  separation  devices  to  process  easy-to-clean
           coals  (coarse  coal only  in  Level 2)  and  therefore should
           be  employed  to  remove  pyritic  sulfur from coal  that com-
           plies or almost complies with S02 emission standards.

       3.  Full Beneficiation.   Level 4 makes use  of high-efficiency
           separation  methods  to  clean  the +28  mesh size fractions,
           while  the  ultrafine  coal  (-28 mesh)  is  cleaned  using
           hydrocyclones.  Thus, all  coal  is cleaned  at this level.

The coal processing equipment used will vary with coal characteristics  and,  to
a  lesser  extent,  with site-specific  constraints  that require  the  development
of  the  most suitable  combination of unit operations for each  coal-cleaning
case.   Consequently, very  few physical  coal  cleaning  plants are  identical,
clearly indicating that no standard solution for  upgrading  coal exists.

       Equipment and/or unit operations can be subtracted  or added  to adapt  to
changes  in  the coal  characteristics  during  the  life of a  plant.   It  is  also
possible  to convert  the  plant  to another  level of  physical coal  cleaning.
This  feature  allows  the  construction  and operation of  low-level  cleaning
plants that are designed to be changed to  higher  level plants  at  a  later date.
For  descriptive  purposes,  "typical" flowsheets  have been  developed for  the
various cleaning levels.  The following descriptions  are adapted  from Ref.  4.
3.1.3  PCC Level 1 System

       Coal for power  generation is usually shipped in 2  in.  or 1-1/2  in.  x 0
size  ranges,   thus  necessitating  the  crushing  of  oversize  ROM  coal.    The
screening and crushing processes to achieve  the  required  size  reduction repre-
sent the minimal effort in coal preparation  practice.

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                                       11
       A  rotary breaker  could  be selected  to  size eastern  bituminous coals,
because of their hardness  and resiliency.   The  rotary breaker not only reduces
the  size  of the ROM  coal, but  also  allows  the rejection of  rock (e.g.,  roof
material  from  underground mines or overburden  from  surface  mines) in the same
operation.

       An  eastern  bituminous coal is  typically processed for  sizing and  rock
rejection  at its  respective mine site.  A  list of  major equipment is included
(Table 3), and  a process  flow diagram is  shown  in Fig.  1.

       The coal generally  is delivered to  the receiving hopper by trucks (when
the  coal  is  mined  by  open pit)  or by  belt  conveyor (when mined by underground
methods).   The receiving hopper  is  equipped  with  grizzly  bars  to  limit  the
size of the  coal pieces entering.  The oversize coal pieces  are broken to pass
through the grizzly or are removed.

       From  the receiving  hopper,  the  coal  is fed by a  reciprocating feeder to
a stationary grizzly.  This grizzly is equipped with parallel bars that divert
the  +3  in.  oversize coal  to a  rotary breaker.   The -3  in.  undersize from the
grizzly is  collected  on  a belt conveyor.   In  the rotary-breaker,  the  +3  in.
raw  coal  is  reduced  to  3 in.  top size.    The  rotary-breaker  product  is  dis-
charged to a belt  conveyor and  combined with the  grizzly undersize for trans-
portation to a  storage silo.  The  unbroken  material leaving  the rotary-breaker
eye  contains  shale,  or other waste  rock and debris, which  is  collected  in  a
rock bin for disposal by  truck.

       Before  the  coal  is discharged  into the  storage  silo,  it is sampled and
weighed.  A suspended magnet is provided for the removal of  tramp iron.
                Table 3  Major Equipment  for Level  1  PCC Plant
             Quantity                    Equipment
                (1)     ROM hopper with  grizzly bar,  500 tons
                (1)     Reciprocating  feeder,  60 in.  duplex
                (1)     Stationary grizzly,  5  ft x 12 ft
                (1)     Rotary  breaker,  12  ft  (diameter) x 28 ft
                (1)     Rock bin, 100  tons
                (2)     Belt conveyors,  48  in.  wide
                (1)     Belt scale
                (1)     Tramp iron magnet
                (1)     Sampling system
                (1)     Storage silo,  15,000 tons,
                          70 ft (diameter)  x 200 ft
                (1)     Rail scale
                (3)     Dust collectors, 21,500  ft  /min

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                                       12
3.1.4  PCC Level 2 System

       Level 2 PCC involves  the clean-
ing  of  a course  size  fraction  of  the
raw  coal,  preceded  by a dry  screening
operation  at  a  screen-opening  size
that  allows  the  removal  of  dry  fine
coal   without   blinding   the   screen
cloth.    Depending  on   the   moisture
content of the raw coal,  dry  screening
is usually  limited  to a minimum open-
ing  size  of  1/4  in.    Larger  screen
openings  of  3/8   or  1/2  in.  generally
permit  more  efficient  screening  and
should  be used  if  characteristics  of
the  raw  coal allow use of  those larger
openings  without impairing  the  final
product  quality.    Vibrating  screens
are  required  for  the  dry  screening
operation.

       The  preferred  method  of clean-'
ing  the  coarse  coal  fraction  is  in a
jig,  which  is   characterized   by  high
capacity  per unit and  separation effi-
ciencies  that  are  sufficient  for  a
Level 2 effort.
     MEDIUM SULFUR COAL
           ROM
       SCREENING AND
         CRUSHING
                      MINE
                      ROCK
             3"xO
         STORAGE
     MINIMUM 15,000 TONS
        UNIT TRAIN
         LOAD OUT
Fig. 1  Block Diagram  for Level
             1 PCC
       Level  2  cleaning is represented
by the  flow  sheet  in Fig.  2 and equip-
ment  list in Table  4.   The  ROM  coal  is  delivered  to  a  receiving hopper
equipped  with grizzly  bars  to limit  the  size  of  coal  pieces  entering  the
hopper.   The  oversize pieces are removed or  (if  not rock) broken to pass  into
the  hopper.   From  the  receiving hopper,  the coal  is fed by  a reciprocating
feeder  to a  stationary  grizzly, which  consists of  parallel bars to remove the
+6 in.  oversize coal.   The  oversize fraction is directed  to a rotary breaker
for  reduction to 6  in.  top  size.    The -6  in.  undersize  from  the grizzly and
the  crushed coal from the  rotary breaker  are combined and conveyed to  the  raw-
coal storage  silo.

        The oversize from the rotary breaker, containing rock or other debris,
is collected  in  a  rock  bin for  transfer into trucks for disposal.

        The  coal, before being  discharged  into  the raw-coal  storage  silo,  is
sampled  and  weighed.  A magnet  suspended over  the  belt conveyor removes  tramp
iron  to  provide protection  against equipment  damage.   The  storage  silo  is
equipped  with  hoppers  and  feeders  that permit  the  withdrawal of coal   at  a
predetermined rate  and its  discharge  onto the  plant  feed  conveyor.    This
conveyor  is equipped with  a belt scale to monitor coal feed rate to the plant.

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                                      13
                                   ROM
               MINE
              ROCK
SCREENING AND
  CRUSHING
                                      ."(6") xO
                                 STORAGE
                                   DRY
                                SCREENING
                                      4" (6") x 0
                                 CLEANING
                DEWATERING
                                THICKENING
                                DEWATERING
                                                      3/8" x 0
                                                DEWATERING

                                                                CRUSHING
                                                               CLEAN COAL
                                                                STORAGE
                                                                      1 1/2" xO
  REFUSE
  DISPOSAL
 4"(6")x1/4"
                                  UNIT TRAIN
                                  LOAD OUT
	WATER FLOW

—  SOLID FLOW
                  Fig.  2  Block Diagram  for Level 2  PCC

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                                       14
                Table 4  Major Equipment  for Level  2  PCC  Plant
             Quantity                     Equipment
                (1)      Hopper  bin with grizzly,  500 tons
                (5)      Reciprocating  feeders
                (1)      Vibrating grizzly,  5  ft  x 12 ft
                (1)      Rotary  breaker,  12  ft  (diameter)  x 28 ft
                (1)      Rock  bin, 100  ton
                (5)      Belt  conveyors,  48  in. wide
                (3)      Belt  scale
                (1)      Tramp-iron magnet
                (2)      Coal  sampling  systems
                (1)      Raw coal silo,  15,000  tons,
                          70  ft (diameter)  x  200  ft
                (4)      Vibrating screen, 8 ft x  20 ft
                (4)      Dewatering screens, 8  ft  x 16 ft
                (1)      Head  tank
                (1)      Baum  jig, two-compartment
                (1)      Refuse  bin,  300  tons
                (4)      Thickening cyclones,  24  ft (diameter)
                (1)      Sieve bend,  5  ft wide
                (1)      Vibrating centrifuge
                (1)      Thickener, 75  ft (diameter)
                (2)      Crusher, double  roll,  36  in. x 60 in.
                (1)      Disc  vacuum-filtering  system,
                          12.5  ft (diameter),  13  discs
                (2)      Mixing  tanks
                (1)      Storage silo,  15,000  tons,
                          70  ft (diameter)  x  200  ft
                (1)      Rail  scale
                (1)      Fine  coal sump
                (2)      Fine  coal pumps
                (2)      Thickener pumps
                (1)      Sump  pump
                (3)      Dust  collectors, 15,000  ft^/min
                (3)      Dust  collectors, 21,500  ft /min
       Upon discharge  from the plant feed  conveyor,  the coal is  screened  dry
on a vibrating screen  to remove the oversize, which is  sent  to be  washed.   The
screen  undersize,  consisting  typically of  3/8  in.  x 0  coal,  is  discharged
directly  onto the  clean-coal collecting  conveyor for  transportation to  the
clean-coal storage silo.

       The vibrating-screen oversize  (typically 6 in.  x 3/8  in.)  is  fed to  the
washing  section.   Coal  cleaning takes  place  in a  two-compartment  Baum-type
jig.  During  the passage of coal through the  jig, heavier  refuse  particles  are
rejected  and  conveyed  to  the  refuse bin  for  disposal.    The  clean  coal  is

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                                       15


discharged from  the  jig with the  process  water and divided  into  two parallel
streams for  passage  over  two  vibrating dewatering  screens.   The  dewatered 6
in. x 3/8  in.  clean  coal continues in two streams  to  two double-roll crushers
for size reduction to  2 in.  top size and is  then discharged  to  the clean-coal
belt  conveyor  for transfer  to  the  clean-coal  silo.   The  effluent  from  the
dewatering screens, including some 3/8 in. x  0  solids,  is collected in a fine-
coal sump  and  pumped to thickening  cyclones, which remove most of the water.
The overflow from these cyclones  contains  coal fines  up to  28 mesh.   Part of
this  overflow  is used  as  process  water in  the jig,  while  the  remainder is
directed to a static thickener  located outside  the  washing plant.

       The cyclone underflow contains  most of  the  solids, which are dewatered
on sieve bends  to settle  out  the  -28  mesh solids,  the effluent from which is
sent to a  thickener.   The  oversize from the  sieve  bend (3/8  in. x 28 mesh) is
further dewatered in vibrating centrifuges and  discharged onto  the clean-coal
conveyor.   The effluent of  the vibrating  centrifuge  is also directed to  the
thickener.

       All  dilute  fine-coal  slurry  streams  from dewatering  processes  are
collected in the static  thickener  to recover  the solids and  clarify the water.
The recovery process starts  with the settling  of the  solids  in  the thickener,
aided  by  flocculant.   The  underflow  is pumped to a  disc  vacuum filter  for
dewatering  of  the  settled  material  with  the   filter  cake  discharged  to  the
clean-coal conveyor.   The  clarified overflow from  the thickener  is pumped to
the plant for reuse in  the process.
3.1.5  PCC Level 3 System

       The PCC  Level 3 effort  can  be considered as an  extension  of  a Level 2
effort  in that  fine coal  cleaning  is added  to the  coarse coal  cleaning of
Level 2.  For  Level  3, however, all  of the  coal feed, including the fines, is
wetted  (in  the Level 2 plant,  only  the +3/8 in. fraction  is washed).  There-
fore, thermal drying of the fine fraction is an essential part  of Level 3.  As
shown  in Fig.  3,  ROM  coal  is  delivered  to a  receiving hopper  equipped with
grizzly  bars to  limit  the size of the  coal  entering the hopper.  The oversize
pieces  are  removed  or broken  to  pass through  the  grizzly.  The  coal is then
fed  to  a stationary  grizzly by a reciprocating  feeder.   The grizzly, equipped
with parallel  bars,  removes the -6 in. coal and discharges the -1-6 in. coal to
a rotary breaker for size  reduction  below 6 in.  The undersize coal from the
grizzly  and the crushed  coal from  the  breaker  are  transferred  to a belt
conveyor  and  conveyed to  the  raw-coal silo.   The  rotary-breaker rejects are
transported by  a belt conveyor  to  a rock bin  and  transported  by  trucks to a
disposal  site.

       The plant feed  belt  conveyor  accepts the sized  coal from the raw-coal
silo through reciprocating  feeders, and a belt  scale monitors plant feed rate.

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                                          16
                                         ROM
r
             MINE ROCK
        DEWATERING
        THICKENING
                                     SCREENING AND
                                        CRUSHING
                                            6"(4") x 0
                                        STORAGE
        DEWATERING
                            + 3/B"
                      CLEANING
       REFUSE DISPOSAL
      	WATER FLOW

      	 SOLID FLOW
                                     WET SCREENING
                                                         3/8" x 0
                                    DEWATERING
                                       T
                                      .JL.
                                     28 MESH x 0
                                                                   DESLIMING
                                                          3/8" x 28 MESH
        28 MESH x 0
                                                                             •3/8
                             CRUSHING
                                                      CLEANING
                                                                            3/8" x 28
                                                                             MESH
                                        DEWATERING
                                                                  OEWATERING
                                                                                LL
                                             t	1..
                                                 28 MESH x 0
                                                                      THERMAL
                                                                    OEWATERING
CLEAN COAL
 STORAGE
UNIT TRAIN
 LOAD OUT
                   Fig.  3   Block Diagram  for  Level  3 PCC

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                                      17


       The raw coal  is  discharged to a chute, thoroughly  wetted,  and screened
at 3/8 in.  The  +3/8 in.  coal is sluiced into a Baum-type jig washer.   During
passage  through  the  jig  washer  the refuse  is separated from  the coal  and
rejected by bucket elevators discharging to a refuse  belt  conveyor.

       The clean  coal from the jigs  is  dewatered  on  stationary  and vibrating
screens and classified  into two  fractions:   6  x 1-1/2 in. coarse  coal,  which
is subsequently  reduced to  1-1/2  in. top size in a  double roll crusher,  and a
1-1/2  by  3/8  in.   size  fraction   that  is  further  dewatered  in  vibrating
centrifuges.

       Effluent  from the centrifuges and dewatering screens  containing -3/8
in. clean coal is combined with the  raw 3/8 in. x 0  coal,  collected in a fine-
coal  sump,  and  pumped to a  cluster  of  six classifying cyclones.   Part  of the
overflow  of  these cyclones  is  diverted to a static thickener, while  the re-
maining part  is  reused as process water  in  the jigs.  The underflow from the
cyclones  is  fed  to  Deister  tables  for cleaning.   Clean coal  is  dewatered on
sieve  bends,  screens, and vibrating  centrifuges with the effluents  from each
operation  being  drained  to  a  static thickener.   The dewatered  3/8 in.  x 28
mesh  fine  coal   is  discharged  onto  the  thermal-dryer   feed  belt  conveyor.
Refuse from  the  Deister  tables  is   dewatered in a  spiral classifier  and dis-
charged to  the  refuse belt  conveyor.   Water (from  this  operation)  containing
fine solids is drained to the static thickener.

       All -28 mesh fine solids  contained in the  plant  effluents  are settled
out  in the static  thickener with the aid of  flocculant.  The underflow from
the  thickener is  pumped  to  disc-type vacuum filters,  from which  the dewatered
solids are also  fed to  the  thermal  dryer.  The  filtrate  is  pumped back to the
thickener feedwell.

       Clarified  overflow from  the  thickener is collected  for reuse in a sump
where  makeup water  is added  to balance the plant water circuit.

       The thermal  dryer  receives 3/8 in. x 0  clean  coal via belt conveyor at
the  dryer  feed bin.   To obtain the  specified 6% surface  moisture of the total
clean  coal product,  only  part of the coal requires  thermal  drying.  Coal dry-
ing  takes  place  in  a fluidized-bed-type thermal dryer, where a rising current
of hot air contacts  the  coal particles  and  removes moisture.   After drying,
the  fine  coal is  combined  with  the coarse  coal.    This  composite  product is
sampled, weighed, and transferred to the  clean-coal  silo.

       Table 5 lists  the  major equipment  in  the  Level 3  PCC  plant.
3.1.6  PCC Level 4 System

       The  flow sheet  for  Level  4  PCC  incorporates  heavy medium  cleaning
processes for  the  size  fractions above 28 mesh.   The  coarse coal is processed
in  heavy-medium vessels,  whereas  the  fine  coal is  treated in  heavy-medium

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                         18
   Table 5  Major Equipment for Level 3 PCC Plant
Quantity                    Equipment
  (1)      ROM hopper with grizzly, 300 tons
  (1)      Feeder, 60 in. duplex, reciprocating
  (1)      Stationary screen, 5 ft x  12 ft
  (1)      Rotary breaker, 12 ft (diameter) x 28 ft
  (1)      Rock bin, 100 tons
  (5)      Belt conveyors, 48 in. wide
  (1)      Belt conveyor, 42 in. wide
  (3)      Belt scales
  (1)      Tramp-iron magnet
  (2)      Coal-sampling systems
  (1)      Raw-coal silo, 15,000 tons,
             50 ft (diameter) x 120 ft
  (4)      Reciprocating feeders
  (2)      Jig washers
  (4)      Dewatering screens, 8 ft x 16 ft
  (6)      Dewatering screens, 6 ft x 16 ft
  (1)      Head tank
  (6)      Classifying cyclones, 24 in. (diameter)
  (6)      Vibrating centrifuges, 36 in.
  (1)      Double roll crusher, 36 in. x 60 in.
  (2)      Mixing tank
  (2)      Disc vacuum-filter systems,
             12.5 ft (diameter), 13 discs
  (1)      Hammer mill
  (1)      Fluidized-bed thermal dryer
  (1)      Clean-coal silo, 15,000 tons,
             70 ft (diameter) x 200 ft
  (1)      Rail scale
  (2)      Fine-coal sumps, 2500 gal
  (2)      Fine-coal pumps
  (1)      Sump pump
  (2)      Thickener pumps
  (1)      Refuse bin, 300 tons
  (2)      Dust collectors, 21,500 ft^/min
  (2)      Dust collectors, 15,000 ft /min
  (12)     Double-deck Deister tables
  (1)      Spiral classifier
  (4)      Sieve bends, 5 ft

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                                      19


cyclones  or  similar  devices.   The  ultrafines  are  cleaned  in  two stages  of
hydrocyclones  to maximize  pyrite  removal  and  accommodate  the  cleaning  of
oxidized coal, which is not possible using  froth flotation.

       The Level 4 PCC process equipment list  is shown  in  Table  6  with a flow-
diagram in Fig. 4.  The ROM coal is delivered  by trucks or by belt conveyor to
a receiving hopper equipped with grizzly bars  to limit  the size  of coal pieces
entering  the hopper.   The  oversize  pieces  are removed or  broken   to  pass
through the grizzly.   From  the receiving hopper  the  coal  is fed by a  recipro-
cating feeder to a stationary  grizzly, which consists of parallel  bars for the
removal of the +4 in. coal.  This oversize  fraction  goes onto a  rotary breaker
for  size  reduction.    The  undersize from  the  grizzly  and the 4-in.  top  size
rotary-breaker product are combined and conveyed to  a storage silo. The over-
size from the rotary breaker,  containing rock  or other  debris, is  collected in
a rock bin and transferred to  trucks for disposal.

       Before being  discharged into the raw-coal storage  silo, the 4 in. x 0
raw  coal  is  sampled  and  weighed.   A  suspended  magnet over  the  belt removes
tramp iron for protection against damage to downstream equipment.

       The 4 in. x 0 raw coal  is delivered  to  the washing  plant  by a belt con-
veyor.  The  coal is  wet-screened at 3/8 in.,  and the oversize material is fed
to  a heavy-medium vessel.   The design  specific  gravity  of  the  heavy medium
chosen for a typical bituminous coal  is  1.40.   After  separation, the product
and  refuse are discharged to vibrating screens to remove the heavy medium from
the  solids  and  to   rinse  off  magnetite  attached  to the  coal and  refuse
particles.  Double-deck screens  are used to classify  the  clean  coal to obtain
a 4  x 1-1/2  in. size  fraction, which  is  crushed to minus  1-1/2 in. in a gear
roll crusher.  The product and rejects are  discharged to a clean-coal  conveyor
and  a refuse conveyor, respectively.

       The 3/8  in. x 0 slurry from the raw-coal screens is sluiced to vibrat-
ing  screens preceded by sieve  bends and deslimed at  28  mesh.  The  3/8  in.  x 28
mesh fraction is  fed into  a sump,  mixed with heavy  medium,  and pumped  to
heavy-medium  cyclones.   After separation  in  the cyclones,  heavy medium  is
drained  and  rinsed  off  the products  on vibrating  screens  preceded  by sieve
bends.  The  recovered  heavy  medium is returned  to the  cyclone feed sump.   The
clean-coal product is  dewatered  in a vibrating  centrifuge and discharged onto
a clean-coal conveyor, which carries the coal  to a thermal dryer.   After rins-
ing, the refuse  is added to the conveyor with  the coarse refuse.

       The magnetite-containing effluents  from  all rinsing screens   and the
centrifuge are  collected  in a static  thickener  to obtain clarified water and
an  underflow,  which  is  pumped to  double-drum  magnetic separators.   The re-
covered  magnetite is  recycled,  while  magnetite  losses  are replaced  by raw
magnetite.

       The  desliming-screen  slurry containing   the  minus  28 mesh solids  is
pumped  to a  two-stage hydrocyclone  system.    The  underflow of   the primary

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                             20
    Table 6  Major Equipment List for Level 4 PCC Plant
Quantity                         Equipment
  (1)      ROM hopper with grizzly, 500 tons
  (1)      Reciprocating feeder, 60 in. duplex
  (1)      Stationary grizzly, 5 ft x  12 ft
  (1)      Rotary breaker, 12 ft (diameter) x 28  ft
  (1)      Rock bin, 100 tons
  (6)      Belt conveyors, 48 in. wide
  (1)      Belt conveyor, 36 in. wide
  (3)      Belt scales
  (1)      Tramp-iron magnet
  (2)      Sampling systems
  (1)      Raw-coal silo, 15,000 tons,
             50 ft (diameter) x 120 ft
  (4)      Reciprocating feeders
  (4)      Raw-coal screens, 8 ft x 20 ft
  (8)      Sieve bends, 7 ft
  (6)      Sieve bends
  (2)      Sieve bends, 5 ft
  (20)     Dewatering screens, 8 ft x  16 ft
  (2)      Dewatering screens, 6 ft x  16 ft
  (4)      Heavy-medium vessels, 14 ft wide
  (4)      Heavy-medium cyclone, 24 ft (diameter)
  (36)     Primary hydrocyclones, 12 in. (diameter)
  (18)     Secondary hydrocyclones, 12 in. (diameter)
  (1)      Roller crusher, double roll, 36 in. x  60  in.
  (1)      Clean-coal silo, 15,000 tons,
             70 in. (diameter) x 200 ft
  (1)      Rail scale
  (1)      Vibrating centrifuge
  (2)      Solid-bowl centrifuges
  (2)      Vacuum filter, disc systems,
             12.5 ft (diameter), 13 discs
  (1)      Dilute-medium thickener, 50 ft  (diameter)
  (1)      Thickener, 190 ft (diameter)
  (4)      Magnetic separators, 30 in. x 84 in.,  double  drum
  (1)      Fluidized-bed thermal dryer
  (1)      Screw feeder, 9 in. (diameter)
  (2)      Vibrating feeders
  (2)      Heavy-medium sumps
  (2)      Fine-coal sumps, 2500 gal
  (2)      Cyclone sumps, 950 gal
  (4)      Fine-reject sumps, 500 gal
  (1)      Heavy-medium storage sump
  (4       Thickener pumps
  (6)      Sump pumps
  (2)      Hydrocyclone pumps
  (2)      Heavy-medium pumps
  (2)      Flocculant systems

-------
                                      21
                               Table 6  (Cont'd)
          Quantity                         Equipment
            (1)       Magnetite storage bin, 100 tons
            (2)       Dust collectors, 21,500 ft^/min
            (3)       Dust collectors, 1500 ft3/min
            (1)       Refuse bin, 500 tons
hydrocyclones  is  diluted with water  and reprocessed  in the secondary  hydro-
cyclones, where a  refuse product is obtained.  These  rejects  are dewatered in
solid-bowl centrifuges and disposed of with  the other  plant  refuse.

       The  secondary  hydrocyclone overflow is  combined with  the  magnetic-
separator effluent,  added to the  raw  coal,  and eventually  reprocessed  in the
first-stage  hydrocyclones.     The  overflow  of  the   primary   hydrocyclones
containing  the clean-coal  product  is  thickened  in  a  static  thickener  and
dewatered in a vacuum-filtration system.  The dewatered clean  coal is added to
the 3/8 in. x 28 mesh clean coal and conveyed to the  thermal dryer.

       In  order  to maintain  a  specified surface  moisture of the  total clean
coal,  the  3/8  in.  x 0  fraction  is  thermally  dried  in a  fluidized-bed-type
dryer equipped with  dry  and  wet dust-collection sections  to obtain  acceptable
stack-gas emissions.  After drying, the  coal is combined with  the coarse clean
coal, weighed, automatically  sampled,  and discharged  into the  clean-coal silo.
3.1.7  PCC Existing Capacity

       The  existing  capacity  of  PCC  equipment  (effective  for Level  2  and
higher  cleaning)  in  Illinois,  Indiana, and  Ohio is displayed  in  Fig. 5  and
given  explicitly  in Tables  7-9  (based on data from Ref. 1).   This  inventory
shows  Illinois with  the  greatest coal-cleaning capacity, followed  by  Ohio  and
Indiana.  These figures  do not relate  the  capacity  factors  for these  installa-
tions, because that information  is not  generally  reported.
3.1.8  PCC Equipment Service

       The issue  of  physical-coal-cleaning equipment service  has  not  received
much attention.   In this  respect PCC stands  in  marked contrast  to FGD  tech-
nologies.  Failures  in operating FGD systems  increase  sulfur-oxide  emissions,
while outage  times  in  a coal-cleaning  circuit can usually be made  up  so that
the  average   monthly  production  of  the  preparation plant  remains  constant.
Additionally,  it  appears   that  many  PCC  facilities   are  designed  for  only

-------
                                            22
                                             ROM
               MINE ROCK
                                         CRUSHING AND
                                           SCREENING
                                                6"I4") xO
                                            STORAGE
                                  3/8"
                                         WET SCREENING
                                                             3/8" x 0
                          CLEANING
           DEWATERING
                                       OEWATERING
                                                 3/8" x 28 MESH
                                                                      DESLIMING
                                            CLEANING
                                                                 28 MESH x 0
                             OEWATERING
                                                       OEWATERING
      	t	
	J
                                                                                 CRUSHING
                             3/8" x 28
                               MESH
                                            CLEANING
                             THICKENING
REFUSE DISPOSAL
                                                            I 28 MESH xO

                                                        •-T	
                                                       OEWATERING
                             OEWATERING
          THERMAL
         DEWATERING
                     I	J
                                  CLEAN COAL
                                   STORAGE
	— WATER FLOW
	 SOLID FLOW
                                  UNIT TRAIN
                                   LOAD OUT
                      Fig.  4   Block Diagram for Level 4  PCC

-------
                                       23
     200-,
     I5
-------
Table 7  Inventory of Illinois PCC Plants
Company
Amax Cnal Co.

Amax Co.ll Co.

Amax Coal Co.

Consolidation
Coal Co.,
Midwestern
Region
Consolidation
Coal Co.,
Midwestern
| Region
j
! Consolidation
Coal Co.,
Midwestern
Region
Consolidat Ion
Coal Co.,
Midwestern
Region
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Concentration
Comminution Heavy- Dewaterlng
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen Jig TaMes Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Sun Spot Mine, 3,500 XX X XX XX
Vermont
Leahy Mine. 12,000 X X X X X X
Campbell Hill
Delta Mine, A, 750 X X X X X X
Marlon
Burning Star 6,500 XX X
No. 1 Mine,
DuQuoln

Burning Star 6,500 XX X
No. 3 Mine,
Sparta


Burning Star XX X
No. 4 Mine,
Cutler

Burning Star X
No. 5 Mine,
DeSoto

Buckheart Mine 7,000 XXX X X
17, Canton


Orient Mine 3, 14,000 X X X X XX X
Ualtonvllle


Orient Mine 6, 6,000 XX X
Waltonvllle


Crown IT Mine, X X X X X
Vlrden



-------
Table 7  (Cont'd)
Company
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Inland Steel
Coal Co.
Inland Steel
Coal Co.
Midland Coal
Co., A Dlv. of
ASARCO, Inc.
Midland Coal
Co., A Dlv. of
ASARCO, Inc.
Monterey Coal Co.,
A Dlv. of Exxon
Coal USA, Inc.
Monterey Coal Co.,
A Dlv. of Exxon
Coal USA, Inc.
Morris, Coal, Inc.

Old Ben Coal Co.

Old Hen Coal Co.

Old Ben Coal Co.

Old Ben Coal Co.

Concentration
Comminution Heavy- Devaterlng
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Fidelity Mine 7,500 X X
11, nuQuoln


Orient Mine 4, 7,000 X X X XX
Marlon


Inland Mine X X X X X X
No. 1, Sesser
Inland Mine X X X X X X
No. 2, Senser
Rapatee Mine, X X X X X X
Mlddlegrove

Elm Mine, 7,000 XX XXX XX
Trlvoll

Monterey No. 1 12,000 X X X X X X X
Mine,
Carllnville
Monterey No. 2 20,000 XXXXX X X X
Mine, Alters

Morris No. 5, 5,000 XXXXX X X
Pittsburgh
Old Ben No. X X X X X
21, Sesser
Old Ben No. X XX X XXXX
25, Benton
Old Ben No. X X
26, Sesser
Old Ben No. X XX X XXXX
27, Benton

-------
Table 7  (Cont'd)
Company
Peabody Coal Co.
Peabody Coal Co.
Peahody Coal Co.
Peabody Coal Co.
Peabody Coal Co.
Sahara Coal Co.,
Inc.
Southwestern
Illinois Coal
Corp.
ZelRler Coal Co.
Zelgler Coal Co.
Zelgler Coal Co.
Concentration
Comminution Heavy- De water Ing
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Mine No. 10, 15,500 XX XX
Pawnee
Eagle Surface XX X
Mine,
Shawneetown
Eagle No. 2 10,000 X X
Mine,
Shawneetown
River King U.G. 7,000 XXX X
No. 1 Mine,
Freeburg
Will Scarlet 6,500 XX X
Mine, Stonefort
1-0
Central Prepara- 12,000 XX X ON
tlon Plant,
Harrlsburg
Streamline Mine, X X X X X XX
Percy
Murdock Mine, X X X X X X
Murdock
Spartan Mine, 4,000 X X X X X X X
Sparta
Mine No. 11, XXXXXX X X
Coultervllle

-------
                                           Table 8   Inventory  of  Indiana  PCC  Plants
  Company
                                                                                            Concentration
                                                       Commt nut ion
                                                                                                     Heavy-
                                                                                                     Medium
                                                                                                                                 Dewaterlng
                   Unit Name,        Dally
                    Location       Capacity   Breaker  Crusher  Magnet  Screen  Jig   Tables  Cyclone   Cyclone  Flotation  Thickener  Dryer  Centrifuge
Amax Coa1  Co.
                   Chinook Mine,
                    Brazil
                                      5,500     X
Amax Coal  Co.       Mlnnehaha Mine,     8,000
                    SulIt van
Amax Coal  Co.       Ayrshire Mine,     16,000     X
                    Chandler

Peahody Coal  Co.    Hawthorn Mine,      5,000
                    Carlisle

Peahody Coal  Co.    Universal Mine,     6,000     X
                    Universal

Peahody Coal  Co.    Lynnvllle Ml lie     14,000     X
                    Nos. 1 & 2,
                    Lynnvllle

Peahody Coal  Co.    Squaw Creek         6,000     X
                    Mine, Boonvllle

-------
Table 9  Inventory of Ohio PCC Plants
Company
Central Ohio
Coal Co.
Consolidation
Coal Co.,
Midwestern
Region
East Falrfleld
Coal Co.

Holmes Limestone
Co.

Horizon Coal Co.


Horizon Coal Co.


Industrial
Mining Co.
Island Creek
Coal Co.

K&R Enterprises,
Inc.

KSR Enterprises,

Nacco Mining Co.

North American
Coal Corp.

North American
Coal Corp.

Unit Namp, Pally
Location Capacity
Musklngum Mine, 12,000
Cumberland
Georgetown 15,000
Preparation
Plant No.
19, Cadiz
East Fairfleld 3,600
Prep. Plant
North Lima
Preparation
Plant Div.,
Berlin
Bollvar/Strasburg 1,500
Operation,
Zanesville
Rosevllle 1,000
Operations,
Zanesvllle
Rogers Mine, 2,500
Lisbon
Vail Mine
(Northern Dlv.),
Freeport
Stark No. 1 S
Kefferrose Pits,
C.in field
Keffler Rose Mine
No. 2, Canfleld
Powhatan No. 6, 11,000
Alledonia
Powhatan No. 1,
Mine, Powhatan
Point
Powhatan No. 3
Mine, Powhatan
Point
Concentration
Comminution Heavy- Dewaterlng
Medium
Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
XXXXX X XX X

XXXXXXX X X



XXX X X X


X X


XXX X


X XXX


XX XX X

x x xxx


X XXX XX


X XX X XXX

XX X XXX

XXX X


XX X



-------
Table 9  (Cont'd)
Company
North American
Coal Co.

Oglpbay Norton
Co.

Ohio Coal &
Construction
Corp.

Peahody Coal Co.

Pe.ibody Coal Co.

Qimrtn Mining Co.


Ouarlo Mining Co.


R4K Coal Co.





Southern Ohio
Coal Co.
Southern Ohio
Coal Co.
Yonghlogheny f.
Ohio Coal Co.
Youghlogheny &
Ohio Coal Co.

Concentration
Comnliuitlon Heavy- Oewaterlng
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen .Hg Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Powhatan No. 5, X X
Mine, Powhatan
Point
Saglnaw Mining 4,500 X
Co. Mine, St.
Clalrsvllle
Rayland Plant & 300 XXX XX
Dock
(Bargeloadlng),
Wlnlersvllle
Broken Aro Mine, 8,000 X
Coslioclon
Sunnyhllt Mine, «,000 XXX X
New Lexington
Powhatan No. 4 7,500 X X X X X X
Mine, Powhatan
Point
Powhatan No. 7 8,400 X XX XXX
Mine, Powhatan
Point
Rice 1,2,3,4,5, 15,000 XX X XX X X
6,7,8, Polen,
Barb Tipple,
Bell.ilre Dock,
Lamlra Prep.
Plant, Cadiz
Melgs Mine No. 1, 18,850 X X X X X X X
Athens
Raccoon Mine No. 7,000 XXXXX X X X
3, Athens
Allison Mine, 5,000 X X X X X X
Bcallsvltle
Nelms Mine 5,000 X X X X X
Cadiz Portal ,
Cadi 7.

-------
                                      30
3.2  FLUE-GAS DESULFURIZATION

       Most of  the  FGD systems currently  operating  in the field  represent  an
early  generation,  if  not  the  first  generation, of  their  respective  tech-
nologies.  Consequently,  there  remain uncertainties  about costs,  materials  of
construction, and reliability of  the  units in service.  The  investment  costs,
operating costs, and total  costs  vary significantly, depending on the  year  of
construction, FGD vendor, unit size,  fuel  burnt,  and sludge-disposal  methods.
3.2.1  FGD Commercial Technology

       Limestone  and lime  FGD  systems can  be  considered  relatively  mature
technologies  that have  experienced more  than a  decade of  utility  service.
Further evolutionary development of the technologies may  still  be  anticipated.
Other  FGD  processes are  reaching  a  point in  their development  where it  is
possible to begin assessing  their  commercial  performance in detail.   Existing
processes include:

       •  Lime/Limestone

       •  Lime/Limestone with Adipic-Acid Addition

       •  Lime/Limestone with Forced Oxidation

       •  Lime/Limestone with Alkali Fly-Ash Addition

       •  Lime/Spray-Drying

       •  Dual-Alkali

       •  Wellman-Lord

       •  Sodium  Carbonate

       The  operation  of  these systems  and   their  ability  to  control  S02
emissions have  been  demonstrated.   Current efforts  are being  directed  toward
improving  the  process  economics,  availability,  and   sulfur-dioxide-removal
efficiency.


       Lime/Limestone FGD Systems

       The  lime and limestone  FGD processes  are  considered  as one  reference
technology, or  base  case,  for  the  FGD  technologies discussed  in  this report.
This  method  of  S02 removal has  been applied in  many  coal-fired  electric-
generating  stations,  and many  more units  are in  the  design  or  construction
phase.   Historically,  capital  investments  and  operating  costs vary greatly

-------
                                      31

from application  to application.   The different  costs reflect  significantly
different site properties,  the  sulfur  content of the coal used,  different SC^
removal  requirements,  etc.   Major advantages  of  this  base-case  technology
include the  extensive  experience gained with  it  to date and  the availability
of the materials needed.  Disadvantages include a high  rate  of forced outages,
corrosion and erosion problems,  and the need  to dispose of great  quantities of
sludge.
       Lime/Spray-Drying FGD Systems

       The spray-drying/baghouse technology  represents  an improvement over the
dry  injection/baghouse  process  in  that  (1)  sorbents  other  than  (scarce)
nahcolite  can  be used;  (2) a  somewhat  higher SC>2  removal efficiency  can  be
achieved;  and  (3)  depending upon the  sorbent  used,  the  waste-disposal  diffi-
culties  can  be significantly  reduced.   In  principle,  this technology,  which
has been  commercially applied at both utility and industrial  facilities,  can
be used  with all types  of coal.   However,  economic considerations  are still
being evaluated  for  its  application to coals with a sulfur content of greater
than 2.5-3%.
       Dual-Alkali FGD Systems

       Dual-alkali  scrubbing is a  wet,  regenerable process  combining absorp-
tion  of  S02  (with  an   aqueous  alkali  solution)  and  regeneration  of  the
absorbent  (with  lime).    The  dual-alkali  systems utilize  a  clear  sodium-
sulfite-based absorption  solution.   Compared  with lime/limestone systems, they
have  reduced  problems with  plugging,  scaling,  and erosion.  Existing systems
remove S02 with  90-95%  efficiency.   Although some  systems  have  had mechanical
or  chemical  problems, they  have  shown themselves  reliable;  less  than  10% of
their total operating time has  been interrupted  with  forced outages.  This FGD
technology has  good retrofit  potential,  based  on  the small size  of  its com-
ponents.   The process  does require a large  land area  for disposing  of the
solid  waste   it  generates.   Economically,  dual-alkali systems  appear  to  be
competitive  with the wet lime and limestone systems.   The process  has been
commercially  applied  in  the U.S.   Three  full-scale demonstration  systems are
operating with coal-fired  utility boilers,  and  several commercial units are in
operation  with  coal- and oil-fired industrial  boilers.    Further  development
work  is  needed  to evaluate,  characterize,  and  compare full-size coal-fired
demonstration facilities;  to test systems  using  limestone  as a regenerant; and
to develop methods for upgrading the quality  of  sludge.
       Wellman-Lord FGD  System

       Wellman-Lord  is  an  aqueous  process  that  employs  a  sodium-sulfite
scrubbing  solution  to  remove SC^ from flue gas.   Thermal  regeneration enables

-------
                                       32
the  system  to recover  the  sulfite and  produce  a concentrated  stream  of 862 •
This process  has been  applied  commercially both  in the U.S. and  overseas  to
desulfurize flue  and  waste  gases from oil- and  coal—fired  boilers, nonferrous
smelters, sulfuric-acid plants,  and Glaus  plants.   This  FGD process has all  of
the  advantages  associated  with  sodium-sulfite-based  scrubbing:   a high  SC^
removal efficiency, no  plugging or scaling in scrubbing, and  a  low liquid-to-
gas  ratio.   It  is a  closed-loop operation, producing marketable  end products
with no large-scale solid-waste  disposal problems.   The  regeneration loop is a
complicated  process  requiring  a relatively high  energy input  and relatively
higher capital and operating costs than  throwaway  processes.  Further develop-
ment is  needed  to investigate  specific  process  improvements, to  evaluate  the
process performance in  full-scale demonstrations with coal-fired  boilers,  and
to  test  the  Wellman-Lord  system  in  combination  with  downstream  sulfur-
reduction systems, particularly  those  using coal as  a  reducing agent.
       Sodium-Carbonate FGD System

       The aqueous-carbonate  process combines the  spray-dryer  technology with
methods of  regenerating the  sorbent material and  producing a marketable end
product with  the sulfur removed  from the flue  gas.   This  FGD technology can
therefore greatly reduce the  amount of sorbent  (^2^3)  required  and can also
produce  revenues  that  partially  offset  its  own costs.    Regeneration  and
sulfur-recovery  techniques make  the  system  complex, however,  and  this  com-
plexity raises both  investment  costs and operating and maintenance costs.  On
the other hand,  SG^ removal efficiencies  can  potentially  exceed those that are
possible with other advanced  FGD technologies.   A 100-MW  test facility is cur-
rently under construction.

       One major issue  of  considerable  importance  to the further  use of this
technology is the sludge-disposal  problem associated with FGD.   Over the next
few decades,  there  will be increasing problems  with siting landfills for the
solid wastes continuously  generated  by coal-burning facilities. .Precombustion
removal of ash and sulfur  through PCC  could help ease this  problem.
3.2.2  FGD Existing Capacity

       The deployment status of FGD  technology  and  its  relation to coal sulfur
content  can  be  seen  in Fig.  6.   Not  shown in this  figure are  the  relative
capacity  factors for  the  various  systems.   If this  consideration were  in-
cluded,  the  role  of  scrubbing would  be  reduced, although  the  high-sulfur
component would  be  reduced  more significantly than  the  low- and medium-sulfur
components.

-------
                 EQUIVALENT SCRUBBED CAPACITY  (1000 MW)
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-------
                                      34
3.2.3  FGD Equipment Service

       The  results  of  a  recent  Argonne  study   on FGD  system  availability
appear in Fig. 7.   In  this study,  the system availability was  correlated  with
the  inlet  concentration  of S02  and design  scrubbing  efficiency (which  are
related to system size and sorbent utilization).   The  trends  indicate  that all
the  technologies  exhibit  high  availability  when  used  in  low-sulfur-coal
applications, but availability decreases for high-sulfur-coal applications.

       As the  coal  sulfur content increases  to 3.5% and the required removal
efficiency  increases,  dual-alkali  systems maintain  system availabilities  of
80%  or higher,  while  all  the  lime/limestone  FGD systems show  marked  declines
in availability.  The  problems with water chemistry are  apparently  compounded
by  closed-water-loop  operations  (where the  operation  minimizes  the  make-up
water needed  to  produce fresh scrubbing liquor by recycling as much  water  as
possible from other stages of  the operation), and  these  systems exhibit system
availabilities  much  lower than  the  open-water-loop  systems.   Adipic  acid
leaves  this  trend  unaffected,  although  alkali-ash  addition   makes  it  much
worse.

       The Wellman-Lord  system has  an  apparent advantage over lime/limestone
systems  for  high-sulfur  coals  at  high  removal   efficiencies.    The  system
availability  exhibited  by  this system is interpreted as  falling off  at nearly
the  same  rate as for  dual-alkali  systems, but  at  an availability lower  by a
constant factor.   This may be  attributed  to the  overall increased  complexity
of the system, especially  the  regeneration loop.
3.2.4  FGD Costs
       Capital  and annual  cost  data  for  operational  FGD  systems have  been
obtained  continuously since March  1978  for the  EPA.    Costs for  each  system
are  obtained  directly from the utilities  and  then itemized  by  individual FGD
cost  elements.   The  itemized  costs  are  then  adjusted to  a common  basis  to
enhance comparability.  This adjustment  includes  estimating costs not  given by
the  utilities and  escalating  all  costs  to  common dollars  (mid-1981).   All
adjusted  cost  data  and   computations  are reviewed   and  verified  with  the
appropriate utility before  publication.

       The key factors used to  produce these cost adjustments are:
       Capital Costs

       •  All  costs  associated  with  control  of  particulate-matter
          emissions are  excluded.

       •  Capital  costs  for  modifications  necessitated  by  installa-
          tion  of  an FGD  system are added  if  they were not  included
          in the reported  costs.

-------
   lOO-i
E-
J
5
CJ
Q
O
                                                                LIME/LIMESTONE (CLOSED WATER CYCLE)
                                                                LIME/LIMESTONE (OPEN WATER CYCLE)
                                                                WELLMAN-LORD
                                                                DUAL ALKALI
                                                                SODIUM CARBONATE
                                                              10          12
                                SYSTEM STRESS
        Fig.  7  Summary  and Comparison of  Calculated FGD System Availabilities
                                       (Source:  Ref. 5)

-------
                                      36
       •  Sludge  disposal  costs  are  adjusted  to  reflect  a  20-year
          life span for  retrofit  systems and a 30-year  life span for
          new systems.

       •  Any  unreported  direct  and  indirect  costs  incurred  are
          estimated and included.

       •  All capital costs are escalated to mid-1981 dollars.

       •  All $/kW  values reflect  the  gross  generating  capacity of
          the unit.
       Annual Costs
       •  All costs are adjusted to a common 65%  capacity  factor.

       •  Direct  costs  that  were not   reported are  estimated  and
          added.

       •  Overhead and  fixed costs that  were not reported  are esti-
          mated and added.

       •  All annual costs are escalated  to mid-1981  dollars.

       •  All mill/kWh  values  are  based  on a  65% capacity factor and
          the net generating capacity of  the unit.

       A summary of these data (Table 10) shows the  cost trends, which provide
a fair  match with  the deployment  of  existing equipment  as  outlined  in  Sec.
3.2.2.

-------
 Table 10  Adjusted Capital and Annual  Costs for Operational FGD Systems by Process  Type



Capital
Process Type
Limestone
Lime
Dual alkali
Lime/alkaline
fly-ash
Sodium
carbonate
Wellntan-Lord
Limestone/
alkaline
f 1 v-ash
Range,
S/kW
23.7-170.4
29.4-213.6
47.2-174.8
43.4-173.8

42.9-100.8

132.8-185.0
49.3-49.3


Average,
S/kW
67.9
81.8
97.8
93.9

69.2

153.1
49.3


Reported
AdluBted
Annual
Range,
o3 mtll/kWh
37.2 0.1-7.8
43.7 0.3-11.3
55.3 1.3-1.3
44.0 0.4-5.4

26.2 0.2-0.5

20.6 13.0-13.0
0.0 0.8-0.8


Average,
mlll/kWh o
1.6 2.2
3.2 2.7
1.3 0.0
2.1 1.9

0.4 0.1

13.0 0.0
0.8 0.0


Capital
Range,
$/kW
38.3-194.3
60.4-210.0
87.8-163.9
52.5-184.4

87.1-150.9

254.6-282.2
102.6-102.6


Average,
$/kW a
98.9 44.0
116.5 44.2
146.7 82.9
122.8 51.4

110.9 26.4

271.6 12.1
102.6 0.0


Annual
Range ,
mlll/kWh
1.6-14.6
4.0-17.6
5.0-13.9
3.0-14.1

5.8- 7.4

16.7-20.8
5.4- 5.4


Average,
mlll/kWh o
6.1 3.1
8.1 3.6
8.7 3.8
1.2 3.8

6.4 0.7

18.1 1.9
5.4 0.0


"Standard deviation.

-------
                                       38


                         4  COMPARISON OF  PCC  AND FGD
       Assessment of  emissions on the  basis  of pounds of  S02  per million Btu
was necessary for this study.  This  corresponds to the way most emission regu-
lations are  written and  avoids  difficulties that  could  occur  due  to differ-
ences  in  specific mining  techniques.   For  example,  it would  be  necessary to
consider  the  mining technique if  the  comparison  were based on S02 emissions
per ton of  coal.   Consider  the  case of a uniform coal bed  that can be strip-
mined  in  one  part of a  county,  while  for the remainder of  the county the bed
must be deep—mined.   Strip—mining typically permits  rather  close  control over
the quality  of  the  ROM  coal,  and  significant amounts of  the shale  matrix are
excluded  from the ROM coal.  This  is not  the  case  for deep-mined coal.  Today,
deep-mining of  coal  is highly  automated,  and it is  common for  these automated
procedures  to  include significant  amounts  of  the  roof and floor material in
the ROM product.  If  the coals obtained  by  these  two methods were compared on
the basis of S02 emissions  per ton,  the outputs of the strip-mine and the deep
mine would appear quite  different.  However, using  the heating value (Btu/lb)
of  the coal as  the basis  of  comparison would yield  a  single value  for the
outputs of the  two  mines.  Throughout  this study  we  will  continue to use this
"Btu"  basis rather than  "tons  of coal."
4.1  EMISSIONS CORRESPONDING TO ROM  COAL

       Characterizing  the emissions  corresponding to  the ROM  coals  requires
the following data:

       •  ROM  coal characteristics  for  major  coal  suppliers  to  the
          power plant, or

       •  "As-received"   coal  characteristics   for  the   major   coals
          supplied  to  the power  plant,  together  with  a knowledge  of
          the preparation  level for  the  coal.

For the  majority  of the  power plants considered  in  this  study,  both  of these
techniques were used to  complement each  other.   It was  possible to identify 53
mines located in Illinois, Indiana,  Ohio,  Kentucky, West  Virginia, or  Pennsyl-
vania that  served  as the  principal  suppliers to  the utilities  of interest in
Illinois, Indiana,  and  part of Ohio.   Appendix A  contains a  series of tables
with  specific data for  these  mines.   A perusal  of  these data  should demon-
strate that  at  least a  modest level of coal preparation  is  typical for coals
provided by  these  principal  suppliers.  However,  it  should  be remembered that
current  deep-mining techniques virtually  require  some coal washing to remove
roof  and floor materials.  This  removal is undertaken  by the  companies for
reasons  unrelated   to  environmental  concerns  about  sulfur  reduction.   Rela-
tively  minor  sulfur  reductions  are  typical  of  most  cleaning  operations
employed for steam  coal.

-------
                                      39


       The ROM  emissions  for  each power  plant's principle  coal is  rendered
graphically for 15 plants  in  Fig.  8,  and for all  plants  in  Fig.  12  to facili-
tate  comparisons  with the  PCC techniques.   One  other significant  issue  was
addressed by  this  study  in order  to  clarify the  overall  environmental impact
of any particular  power  plant.   This  is to  link  the  S02  emissions per million
Btus with  a  plant capacity factor to calculate  the  thousands of tons  of  S02
per year  that a specific  power plant would  be  expected  to generate  (see  the
explanation of Fig. 9 that follows).
4.2  EMISSIONS UNDER 1980 CONDITIONS

       In  order  to  determine  power-plant  S02  emissions  for  1980,  it  was
necessary to  analyze  the monthly Form  423  data that each  utility  provides to
the  FERC.    For  each  coal  purchase,   the  utility  supplies  FERC with  coal
quantity purchased;  heating  value;  ash content;  sulfur  content;   and  state,
county, and name of the  producing mine  (see  Appendix  A).

       By reviewing the  coal-cleaning equipment  available  to each supplier, it
was  possible  to  assign  approximate coal-cleaning  levels  to each producing
mine.  These levels were:

       •  ROM  (PCC Level  1),

       •  Coarse-to-moderate  cleaning (PCC  levels  2  and 3), and

       •  Full beneficiation  (PCC level 4).

These levels are the same as  those referenced  in Sec.  3.1.2.

       Power-plant S02 emissions in  pounds  of  S02/10   Btu  (Fig. 8)  and overall
S02 emissions  for  1980  in thousands of  tons (Fig. 9)  were calculated for each
utility by  using a computer  program to merge coal  suppliers'  cleaning-level
data with coal purchase  data  from the  Form  423  file.   No  credit was taken for
sulfur removed with the  boiler bottom  ash.  This  is  typically 5% of the total
sulfur.  Figure 9 shows  which plant/coal combinations actually account for the
greatest S02 emissions.  These estimates are  the  multiplicative products of S02
emissions rate, power-plant size, and power-plant  capacity factor.
4.3  PURCHASE PATTERNS FOR  COAL  IN  1980

       Several  trends were noted  in  the utility  coal-purchase  patterns  for
large and small coal  purchases.   The purchase-pattern trends are related here,
because they may bear on  future  deployment of PCC systems.   The trends are:

       •  Mine-mouth  power plants  typically  make  modest  purchases
          each  month  from  other mines  in   addition to  their  major
          purchase  from the adjacent mine.

-------
                       40

      i
      i
I
1
                I
               1
                       	 Legend
                       CZJ Full
                       2Z3 Coarse-Moderate
                           ROM
            E    0     P
           POWCR PLANTS


  S     R     T     U     K     V
           POWER PLANTS

            8     L
           POWCR PLANTS
Fig. 8   Power-Plant  S02 Emission Rates,  1980
                (Ib S02/106 Btu)

-------
                              41
in
z


1 »«•!

                       i
I
              0     E     0    P     H

                  POWER PLANTS
              Legend

          C3 Full

          EZ2Coarse-Moderate

          E3ROM
g
&

                   T    U

                  POWER PLANTS
^% 380-

I/I


O
                  POWER PLANTS
         Fig.  9  Power-Plant  S02 Emissions, 1980

                      (103  ton S02/yr)

-------
                                       42
       •  Most  plants  that are not  mine-mouth  power plants  typically
          have  from one to  three  favored suppliers  that account  for
          the bulk  of their  coal.

       •  Very  few  facilities have  adopted  a strategy of making  many
          small «10,000 ton)  coal purchases.

       In the absence of these trends,  the number  of  coal mines and coals that
would have  to  be  evaluated  for  their washability characteristics  would esca-
late significantly.   The number of  small coal purchases  indicated by Fig. 10
appears to  be  significant.   However, as Fig.  11  shows,  the  total tonnage of
coal  involved   appears  to  be all  but  insignificant,  with  the  exception of
facilities D and  E.  Based  on these considerations, it  would not seem neces-
sary to evaluate any but the  large (>10,000  ton)  coal purchases.
4.4  EMISSIONS WITH FULL CLEANING

       This study's guidelines recognized  that  the  utilities should be free to
determine  their own  optimal  supply  strategy.   Consequently,  the  estimated
emissions  for  the  fully cleaned coal  were based on the  reductions that could
be achieved by a PCC Level 4  plant  recovering 80 percent by weight  (wt %) of
the ROM  coal   from  the  power  plant's  principal  supplier.  The  amount  of coal
provided  by the principal  supplier  varied from  23-100% of the power plant's
feed, but  on the average it was 62%.   It should  be  noted that  two  plants (L,D)
failed to  properly  complete their  FERC Form 423s and  could  not  be included in
this  study.    Plant W  burns   an  unusually high-quality coal  that  showed  an
increase  in  sulfur content  with  washing because of  a combination  of  low
pyritic-sulfur  content  and  Btu losses  in cleaning.    There  seems  to  be  no
logical  reason  for considering  this  coal  further  in a  washing  strategy.
Lastly,  it was  not  possible  to  adequately characterize the principal coal
feeding plant X.

       The emissions rates  for 20 utility  power  plants appear  in Fig. 12.  The
first bar  (identified as  "1980 Emissions") in each  figure indicates  the total
1980 emissions  from all coal  mines and all coal  purchases  regardless of size.
The second bar ("Major  Coal ROM")  results from  considering  the  single largest
supplier mine  for each  power plant in  1980 and  using the anticipated  emissions
rate for  that  coal  if  it  were at the  mean value for the given seam and county
(see Appendix  A).   The  difference between this  value  and the  "1980 Emissions"
bar reflects a  combination  of  several  factors:

       •   Averaging properties from  all  the coal purchases,

       •   Departures  of the  ROM  coal  from  the mean value  for  the
           seam,  and

       •   Existing  application of  some level of PCC techniques  to the
           coal.

-------
£ i 10 KTONS
 Fig.  10   Number of  Power-Plant Coal Purchases

-------
 •*J
 H-
OQ
    O
    O
    01
 H
 O

 §
 Pi
 -  (0
O
0>
   TO
            -
K1ONS OF COAL PURCHASED

 M     H      »     "
 S     8      S     S
                                                                            K1ONS Or COAL PURCHASED
                     A v
                     So
                     z *
                     o 3r-
                                                                                                                                   KTONS Of COAL PURCHASED

                                                                                                                                   I      !      I     i
    0
    «
    (D

-------
   o
   10 «
     i-
   |H
             I
                       45
                     PLANT A
i
                      PLANT B

w,
 i
                      PLANT c
        W'-
        y//.
        //A
                                      '

             1980    MAJOR   CLEANED  CLCANCO

           EMISSIONS  COAL ROM  87.57.    80r.
fig.  12  Sulfur Dioxide Emissions Rates for

              Selected Utilities

-------
       o
       •» 4-1
       1
                 1
                p
                           46
                          PLANT £
                          PLANT F
        1
        1
                          PLANT  G
r4';l
1
^
                                Y/.'/l
                                0/A
                                m
                                        •'///A
K: ->:/l
^>/H
                                        * / / f*
                                        '//A
                                        / / / A
                                        ///A
                 1980     MAJOR   CLEANED  CLEANED
               EMISSIONS  COAL ROM  37,57.     eor:
Fig.  12   (Cont'd)   Sulfur Dioxide Emissions Rates
                for Selected  Utilities

-------
      j

      a
                n
                          47
                         PUNT H
       3


       D  I
       o
       tn
2£3

%
M

///'\
                          PLANT
                       v//A
                         /A

                        //
                                /A
                      ^//A
                       • / // 4
                                       '///A
       |H
       o
       ">  .4
         j-
                          PLANT  J
                1980    MAJOR   CLEANED  CLEANED

              EMISSIONS  COAL ROM  87.sr.    scr.
Fig.  12  (Cont'd)   Sulfur Dioxide  Emissions Rates


               for Selected Utilities

-------
                          48
                          PUNT  K
                        1
                                1
       | '
                          PLANT  M
                         .•
                                       '"'A
       m

       2
                          PLANT  N
                        n
ty/A
V//A

-------
 o

 "> 4-1
   1-
 o
 «" t-i
                     49
                   PLANT 0
i
                 i
                    PLANT P
                  / ' ' •
                  V/xVl

                    PLANT Q

           1980    MAJOR    CLEANED  CLEANED

         EMISSIONS COAL ROM   87.53     607.
12   (Cont'd)   Sulfur  Dioxide Emissions Rates

          for Selected Utilities

-------
      j»

      m
      2
       O
       «i
                ^
                          50
                         PLANT R
                         PLANT S
                       V/A
                                22;
                          PLANT  T
                                      S.'7/A
                1960    MAJOR   CLtANCO  CLEANED

              EMISSIONS  COAL ROM  87.57.    BCT.
Fig.  12  (Cont'd)   Sulfur Dioxide Emissions  Rates

               for Selected Utilities

-------
                      o
                      "> 4-1
                                       51
                                       PLANT  U
                                       PLANT  V
                              1980    MAJOR  CLEANED CLEANED
                             EMISSIONS  COAL ROM  87.57.    80S
               Fig. 12  (Cont'd)   Sulfur Dioxide Emissions  Rates
                             for Selected Utilities
       The  first two  of  these  factors could  either increase  or decrease  the
difference,  while  the  third  factor  will  almost  always  decrease  the  "1980
Emissions" bar.

       A  computer   code   that  predicts  PCC  plant  washing  performance  for
specific  coals  was  then  employed (further  discussion of  the  code is found  in
Appendix  B).   The  results of this  code show that the pyritic sulfur that  can
be removed  by PCC  plants when washing to the 80% recovery  level will  fall  in
the  range of 0-50%  of the total  sulfur  content  of  the coal,  with an  average
value of  29%.

-------
                                       52


4.5  COMPARISON OF PCC AND PARTIAL  FGD COSTS

       The  costs  of  PCC and  partial  FGD* were compared  by calculating system
costs on the basis of the dollar  cost per ton of  S02 removed ($/ton SO™).  The
coal-cleaning model  is  described in  Appendix B,  while the  FGD  model is based
on design  studies using the  TVA  Shawnee  code, as summarized  in a recent EPRI
study.   The following assumptions  were made  in these models:

       •  Economics were based on November 1982 dollars.

       •  ROM  coal  was assumed  to  have  a base selling  price at  the
          mine-mouth  of  $28.15/ton for a 10,678  Btu/lb  heating-value
          coal  typical  of the Illinois basin.^   Adjustments  made  to
          account  for  the  heating-value variation among  the   coals
          considered were calculated  at ($2.60/ton)/10^ Btu.

       •  Two  PCC Level  4  plants  were   considered.    One recovered
          87.5% by weight of  the coal,  and  the  second recovered  80%
          by weight of the coal.

       •  The PCC plant  was  assumed  to be available for 3000 h/yr  of
          operation.    The  remainder   of  the  time  could be used  for
          maintenance activity.

       •  A  single  conservative  shipment rate of  $4.64/ton was  used
          for PCC plants  that were not  mine-mouth  operations.    This
          was the mean value  from  a  recent  survey  of shipment  costs
          for 36 midwestern utilities'  coal contracts.

       •  A  constant  cleaning cost  of  $4.74/ton  (1978 dollars  subse-
          quently adjusted to  $6.87/ton in November 1982 dollars) was
          used for the 80% recovery PCC Level 4 plant.

       •  The emissions  rate  for the  80 wt  % coal-recovery  Level  4
          PCC system served as the  design base  for  the  FGD  system.

       •  The base FGD  system consisted  of  500 MW  of scrubbed  capa-
          city  and  used four  modules  of  167 MW-equivalent scrubbing
          capacity.   Three modules are needed in  constant operation
          with a  fourth on standby.  No adjustments were made for FGD
          system  availability.
*The FGD system would  treat  only the partial volume  of  flue gas — 32% on the
 average — that if scrubbed with 90% efficiency  and  mixed  with unscrubbed gas
 would yield the same net emissions  as  are  obtained  firing  cleaned coal.

-------
                                       53
       •  Adjustments  to  the  FGD base  capacity  were made  using  a
          power  factor  of  0.8.  No system was  permitted  to exceed 750
          MW  or  be  smaller  thn 375 MW.

       •  The FGD system retrofit  increased  the base cost by 30%.

       •  The  FGD  system  was assumed  to operate  at 90%  efficiency.
          This  eliminated reheat  requirements  by  permitting a  large
          fraction  of the  flue gas to bypass the FGD system.

Details of  the resulting cost comparisons based on these assumptions appear in
Appendix C.  A summary  of  these  data  appears in Table 11.  The general conclu-
sion  to  be drawn is  that, for  50% of these  power plants, PCC  is  more cost-
effective  than  FGD  in meeting the minimal sulfur  reductions  set forth by the
base  conditions.  A more detailed  trade-off study  would  be needed for another
one-quarter of the  plants, while PCC  appears to be less cost-effective for the
remaining  plants.   Thus,  there is not a clear advantage  in  employing either
technology.   This is due  largely  to  the wide  variations  in coal cleanability
and  the  limitations  (relative  to  FGD)  on  sulfur  removal  attainable through
existing PCC  technology.  Consideration  of  other  factors,  such  as effects on
power-system  availability,  waste-disposal concerns,  and overall  level of S02
reductions  needed,  is necessary before a control  strategy  can  be formulated.
In addition to  these  technical  factors,  regulatory and  institutional concerns
can  be  expected to play an  important role.   These concerns  are discussed in
Chapter 5.
4.6  STATEWIDE SULFUR REDUCTIONS

       The  total S02 emissions  with  and  without  coal  cleaning are  shown in
Fig. 13 for Ohio, Indiana,  and Illinois.   Within a 95% confidence limit, there
do  not  appear to  be any  statistically significant  state-by-state  variations
with respect  to  total  sulfur reduction (at 80  wt % recovery),  PCC  costs, or
FGD costs.

       The  figure  clearly shows that  power  plant S02 emissions  in  each state
are lower than those that would result if only  the  principal coal  were burned
with its  ROM sulfur  content.  Note  that  in  Indiana the total  emissions  are
heavily  influenced   by  two  plants  that  already   purchase   cleaned  coal.
Consequently, the  Indiana  1980 emissions  closely resemble  those for cleaning
at 80 wt % recovery.

       In addition  to  cleaning, many plants  buy  coal from  multiple  sources.
Much of  the  coal  purchased  to supplement  the  principal  coals is   lower in
sulfur content,  thereby reducing the  annual  totals still more  on  a  statewide
basis.   However,  those  coals  were not  subjected  to coal  cleaning in  this study
and hence should not be directly compared  against  the cleaning  results.

-------
                                  54
Table  11   Summary of  PCC Sulfur Reductions, PCC Costs, and FGD Costs
PCC Level 4, 80 wt %
Plant3
A
B
C
E
F
G
H
I
J
K
M
N
0
P
Q
R
S
T
U
V
Average
% S Reduction
14.57
34.12
39.20
24.12
26.16
23.65
41.19
23.65
34.08
17.74
27.60
32.56
31.12
33.54
10.60
14.57
39.20
29.87
50.03
32.98
29.03
$/Ton S02
1366
354
616
1162
818
778
426
778
871
883
664
434
435
851
2057
1366
616
569
483
611
809
FGDb
($/Ton S02)
525
741
1090
978
814
746
979
589
1294
593
754
674
699
1162
649
630
976
598
1231
854
829

T
-»O
FGD
<80% +20%

X
X
X
X
X
X

X

X
X
X
X


X
X
X
X
10 5
>120%
X






X

X




X
X




5
Plants D and L - Omitted because of  improper  FERC  Form 423  reporting.
Plant W - Burns unusually high-quality  coal.
Plant X - Inadequate washing data in USGS  files.

This FGD system would treat the volume  of  flue  gas that (if scrubbed
with 90% efficiency) could be mixed  with the  unscrubbed gas to yield
the same net emission as PCC.

-------
                         55
         TOTAL SULFUR DIOXIDE EMISSIONS FOR 4 ILLINOIS PLANTS
O 1000-
USE OF ONLY MAJOR
COAL AT EACH PLANT
SO2 EMISSIONS (1
O
> o
C
AL
DAI
1
\^r
| S
£/
I

1980 ROM CLEANED CLEANED
EMISSIONS 87.5% 80%
1500-



vt
SO2 EMISSIONS (K TON
M 0
O 0
O 0
0*
p-
S
V
V
ALL V
COALS /,





V
USE OF ONLY MAJOR
COAL AT EACH PLANT

TOTAL SULFUR DIOXIDE EMISSIONS
FOR 8 INDIANA PLANTS
\/
I/
K
1
r/


T980 ROM CLEANED CLEANED
EMISSIONS 87.5% 80%
1500-


^?
z
O 1000-
^
S02 EMISSIONS (1
w
0
9 O

TOTAL SULFUR DIOXIDE EMISSIONS FOR S OHIO PLANTS
USE OF ONLY MAJOR
ALL COAL AT EACH PLANT
C<

DAI

s p
\

I
!

1980 ROM CLEANED CLEANED
EMISSIONS 87.5% 80%
 Fig.  13   Total  Sulfur Dioxide  Emissions for
           Illinois,  Indiana, and  Ohio

-------
                                       56


                5  REGULATORY AND INSTITUTIONAL  CONSIDERATIONS
5.1  BACKGROUND

       Fuel pretreatment was  included as a "... technological  system  for con-
tinuous reduction  of the pollution  generated by a  source ..."   in  the 1977
Amendments to the  Clean  Air  Act.   In EPA's promulgation  of  the utility-boiler
new-source performance standards  (NSPS)  in 1979,^ physical coal  cleaning was
determined  to  be  an  acceptable  method  for  achieving  a  portion  of  the
percentage reduction of  S02  required.  Reductions in sulfur content  from fuel
pretreatment could be credited toward meeting  the requirement  for  greater than
70% reduction.   Utilities  have not  typically  considered the  addition of coal
cleaning as part  of  a 1979 NSPS-compliance  strategy, since the use of an FGD
system  would  be  necessary  in  any  case  to  achieve  compliance  with  the
percentage-reduction  requirement.    Utilities  may have  decided that  the cost
and effort needed to gain credit from washing  coal was  simply  not  economical.

       Portions of the utility  industry  are supporters of the  virtues of coal
cleaning.   The Electric Power Research Institute  (EPRI),  for example,  not only
has funded a  coal-cleaning  test facility,  but has  become an  active  proponent
of the  advantages  of cleaned coal to utilities.   EPRI noted    that  less than
20% of  the coal  used annually by the utility  industry  is cleaned,  despite the
benefits EPRI  perceives  in  cleaning coal  — lower  shipping   costs,  improved
boiler  operation,  and reduced  sulfur emissions.   If  cleaned  coal is  used to
augment scrubbers, EPRI argued that  the  performance  of  the FGD is  improved and
some  of  the  operating  costs  (sludge  disposal,   limestone) are   reduced.
American Electric  Power  (AEP) has  also  been  quoted  as  "...  enthusiastically
endorsing coal  cleaning."     AEP,  however,  was  enthusiastic  over the  use of
cleaned coal for  improving the  performance of boilers and the  availability of
power plants,  not over the sulfur-reduction potential  of  cleaning.  AEP stated
that  it would  be  "...  cheaper to buy high-quality cleaned coal  to  get peak
availability from  existing plants  than to build new plants  to replace what is
lost to bad coal."16

       More recently,  congressional  activity  in  the area  of  legislation to
control acid  rain  has  focused  attention  on  strategies for  S02 reduction,
including coal  washing.   Several  of the  many bills introduced into  the 97th
Congress (e.g., H.R.  4829, the  Moffett Bill)  specifically referred to precom-
bustion fuel  cleaning as  an approach  to emission  reduction.  Congressional
debate  had  indicated an interest  in a  mandatory  coal-washing  policy,  but no
bill  specified  such  pretreatment  as a  requirement.   In most   cases,  the pro-
posed legislation  gave  states in the  Acid Rain Mitigation (ARM)  region — 31
states  east of  the Mississippi  plus  Iowa, Missouri, Arkansas  and  Louisiana —
significant  flexibility   in  choosing   S02   reduction  methods.     Proposed
legislation  to  control  acid  rain  was   introduced   into the  98th  Congress.
Again,  coal  washing is  an  optional  strategy  for  S02  reduction but  not  a
requirement.  Congressional  interest in  the sulfur removal possible with coal

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                                       57
washing may  be reviving.  For example,  the  Congressional Research Service has
recently  initiated  a study of coal washing  —  costs,  SC>2 reduction potential,
market forces,  etc.
5.2  CONSTRAINTS  ON VOLUNTARY USE OF CLEANED COAL

       There  are  a number  of  potential  constraints on the widespread voluntary
use  of  coal-cleaning —  those that  involve possible institutional  limits on
the  expansion of  the  coal-cleaning industry  and  those  that involve the limits
to the acceptability  of cleaned coal by  the utility industry.  Among the most
obvious problems  facing the coal-cleaning industry  are  the lack of demand for
the  product  and the  major capital-investment  requirements  for construction of
a new  cleaning plant.  The  low demand is a function of the  costs of cleaned
coal (as  noted in Sec.  3.1.9), possibly  exacerbated by  the current decline in
the  demand for energy and the postponements  and  cancellations of proposed new
power  plants.   (For  example,  in 1977 the  Energy  Information  Administration
projected  a   need for  242 GW of  additional  coal-fired  generating  capacity
coming on-line between  1980   and  2000.   The most  recent  projection,  NEP-3
[July 1980]  has reduced the  additional  capacity needs  to  181 GW.)  The major
investors in  coal-cleaning facilities are large  coal  companies  and utilities.
Investment  in  a  coal-cleaning  plant  by  an  independent  entrepreneur  seems
unlikely, unless  a market  for the  product were more assured.   In addition, the
likely economies  of  scale place  smaller coal producers  at a  disadvantage,
making them unable or unwilling  to invest in cleaning facilities.

       There  are  additional constraints  on  the possible expansion of  a coal-
cleaning industry that  arise  from  environmental regulations.   Coal-preparation
plants emit   pollutants  to air,  water,   and  land in the process  of  cleaning
coal.   Consequently,  plants   face both  known regulations (e.g.,  air-quality
NSPS  limiting  particulate-matter  emissions,  water-quality   limits  on  toxic
effluents) and possible future  regulations   (e.g.,  if  coal cleaning  waste is
classified as  hazardous under RCRA, significant costs will be associated with
safe disposal).  Not only  is  there uncertainty about the environmental regula-
tions with which  the cleaning plant must comply,  there is  uncertainty about
the  future  of  regulations for  the  potential  customers  of the  cleaned  coal.
The uncertainties in  this  case range from possible  Congressional revisions to
the  Clean Air Act  (e.g.,  making  the   Act   less  stringent   by  dropping  the
percentage-reduction  requirement or making  it more stringent by adding  acid-
rain controls) to variations  in  EPA's implementation  (e.g., requiring  revi-
sions to  make state-implementation-plan  [SIP] emission  limits more  stringent
in nonattainment  areas  or allowing  SIP revisions to relax emission  limits in
attainment areas).

       Although coal cleaning  has  long  been  used for removing ash and improv-
ing the Btu content of  coal,  utilities  (or  other sources of  demand for washed
coal) appear  to have a generally limited  knowledge  of developments in cleaning
technologies  and  the uses  of  cleaned coal as  a sulfur reduction  technique.  A

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                                       58


study conducted by Battelle Columbus  for  EPA  included interviews with a number
of utility officials and concluded  that "existing  engineering/economic studies
of physical  coal  cleaning  are  believed  to provide a wholly  inadequate basis
for investment  decision making."     Even if  a utility  executive  had adequate
knowledge  to  make  an  investment  decision,   the   current  tax  status  of  the
investment might  dissuade  him.    A  utility's  investment  in  a  coal-cleaning
facility does  not have  the  same  tax  status as  an  investment in an FGD system.
The latter is  defined as a pollution-control investment, with  such financial
advantages as  accelerated  depreciation  and  investment  tax  credit.    On  the
other hand,  if independent  coal companies  were to invest  in  cleaning facili-
ties, the  costs  could be added  to  the fuel costs  to  the utility  and possibly
become part  of the fuel  adjustment  clause,  passing  the costs directly on to
the consumer.   The  pass-through of  the  costs is not  a  certainty,  however; it
would depend on the decision of a public  utility commission.
5.3  OPTIONS FOR INCREASING THE USE OF CLEANED  COAL

       If it is assumed that cleaning coal  is a useful  method  for reducing SOo
emissions and  that it  is  desirable to  encourage the  use  of  cleaned  coal  in
coal-burning facilities,  then  there  are a number of  policies  that  could  be
initiated by the federal or state government either to  encourage or to require
the increased use of cleaned coal.
5.3.1  Policies to Encourage the Use of Cleaned  Coal

       Encouraging an  expanded  supply of  and  demand  for cleaned  coal  by pro-
viding  incentives  is  difficult  and not  likely  to be  effective in  the  short
run.   Following is  a list  of  some actions  the  state or federal  government
could  take  to  overcome  some  of the  barriers  to an  expansion of  the  coal-
cleaning industry:

       •  Provide  loan  guarantees  for   the  construction  of  coal-
          cleaning plants

       •  Provide tax  incentives or direct  subsidies

       •  Clarify  the acceptability   of  the  additional  costs   of
          cleaned coal for a fuel adjustment

       •  Undertake  a substantial  publicity  (i.e.,   public  informa-
          tion) program

       •  Provide price guarantees for the  cleaned coal

       •  Reduce uncertainty in  the market by stabilizing SIP regula-
          tions.

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                                      59


Other possible actions could be taken at the  federal  government  level:

       •  Alter  the  current  IRS   approach  and  allow  coal-cleaning
          plants to be treated as pollution-control investments

       •  Set  a time  period  for  a moratorium  on  changes  in NSPS
          regulations, thus ensuring a more stable market

       •  Consider  incentives  to coal  cleaning in the  proposals for
          an industrial-boiler NSPS.

The actions listed above all work through  encouraging the  supply of  and demand
for cleaned coals,  and all assume that the demand for cleaned coal will exist.
If this assumption is not valid, the government will  find  itself locked into a
position of permanent subsidization of an  industry, which  seems  unlikely to be
a  cost-effective approach  to  reducing SC^  emissions.   In  some  cases,  the
actions would  require  the  commitment  of  an indeterminate  amount  of  public
funds  to  support one  industry.    Considering the  current depressed  economy,
large  federal  deficits,  and declining state  revenues, it seems  unlikely that
such government  action will take place.

       The  Environmental  Protection Agency  could review  possible actions to
encourage  coal  cleaning,  although  the EPA  has  limited  statutory  authority
available  for  requiring  the use of  cleaned coal.   According  to  the  Clean Air
Act  Amendments  (Sec.  Ill),  the  EPA is  empowered to set  standards  of  per-
formance for new sources,  but  not to require any specific control  technology.
EPA's  allowance  for  crediting  fuel pretreatment toward the  percentage  removal
requirement of the 1979 NSPS could  be viewed  as a policy  of  encouragement.  In
addition,  the  agency could:

       •  Review and  simplify the  procedures required for monitoring
          coal samples and determining S02 removal efficiency.

       •  Set  a  higher  limit on  the  minimum  lot—size   subject  to
          sampling   (The current NSPS  sets a lot size  as the weight
          of  coal  processed  in  24  hours; if more  than  one coal is
          treated  in a  single day.  a  sample  of each type  must  be
          collected and analyzed.)

       •  Encourage  the  inclusion  of  a requirement  for  cleaned coal
          in  an SIP, by  preparing control guidelines for reasonably
          available control  technology  (RACT) for SC^, indicating the
          potential  clean-up  from washing coal and  the acceptability
          of such an SIP attainment  strategy.

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                                       60


5.3.2  Policies to Require  the Use  of  Cleaned Coal

       Another  set  of  policies  could  be undertaken  to require  the  use  of
cleaned  coal.   Congressional  action  as part of  acid-rain  legislation could
establish a mandatory coal-washing  policy.   The  most likely governmental level
for  action  to  increase the  use of  cleaned  coal is,  however,  at  the state
level.  State air-quality-control agencies  could make the SIP requirements for
existing  coal-fired  facilities more stringent  or require a  percentage reduc-
tion  from a base  year of  emissions.    The  justification  for such  an action
would need to be  the protection or enhancement  of  air  quality in the state —
to bring  a nonattainment  area into attainment,  to  protect  a PSD  increment,  to
provide a growth  allowance  for future sources of  SC^  emissions,  or to protect
sensitive ecosystems.   Increasing  the stringency of  SC>2  regulations  would not
necessarily lead  to  an increased  use of  washed coal, however.   Lower-sulfur
coal  could  be  purchased  and blended.   In  the  midwestern states  reviewed  in
this  study,  a  requirement  to  use  local coal might be necessary to  avoid the
increased use  of  out-of-state  lower-sulfur  coal.    A  local  coal  requirement
would likely require action by the  state legislature.

       Depending  on   the  statutory power  of  a  state  regulatory agency,  a
specific requirement for use of washed coal in utilities  could be made (action
to revise state codes might be  necessary  in some  states).   Regulations could
be promulgated to:

       •  Require a  percentage  reduction of  sulfur by washing  for  all
          sources.   Such  a  requirement  might be technically  infeasi-
          ble for  all the  coals in a state  or  might be very  ineffi-
          cient in terms of Btu  losses.   Therefore, limits need  to be
          set.

       •  Require  the  removal  of  x%  of   sulfur,  if  uncontrolled
          emissions  are >  y Ib  S02/106  Btu  and if <  z% loss in  Btu
          occurs.  If  the  coal cannot be washed to x%, or if  the  raw
          coal  is  already  low  in   sulfur  content, or  if significant
          losses  in  terms  of  Btu   content will  occur,   then  the
          requirement will not be enforced.

       •  Set an emissions  cap  for  each  power plant in the state.  An
          emissions  cap would  need to be  carefully chosen, such that
          the use of washed coal would be encouraged.  This option is
          a combination of mandatory and incentive  approaches.

       •  Set regulations for  each  source.   The results  of this  study
          suggest that a source-specific regulatory strategy would be
          the most effective  choice for  The  states and utility plants
          reviewed.   This  alternative  would place heavy  demands  on
          the  staff  of an  agency.   Moreover,  in  the  absence  of a
          local air-quality problem (such  as nonattainment)  or  of a

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                                      61
          federal  requirement  for  states  to  reduce  SC^  emissions
          (such  as  proposed  in  the  acid-rain   bills   in  the  U.S.
          Congress), a selective  regulatory action could face serious
          problems of acceptability.   Equity issues could be referred
          to in  an initiative  that  would require  one  power plant to
          use washed  coal,  increasing the  costs  of its  fuel,  while
          another power plant would not be  so required.

       An effort  to implement a  mandatory coal-washing policy was  undertaken
in Ohio,  starting with  the  1979-80  legislative  session.     A number  of  bills
were  discussed  at  the  committee  level,   but  none  were  reported  out of  the
committee  for  consideration by  the  General  Assembly.   The  bills  proposed
revising  the  state code,  allowing the director  of the  state  EPA to  require
coal washing  by  all the  utilities.   The  director  was  to issue  specific coal
ashing  standards  for each source, giving  consideration to  "... whether  the
requirement  of  such  action would  be technically  infeasible  or  economically
unreasonable and  whether  the  costs  of such requirements would  be  dispropor-
tionate  to  the  benefits  to  be derived therefrom."   Initially the Ohio  EPA
had considered including industrial  boilers in  the proposed requirement,  but
instead decided to  concentrate on utilities.  A number of utilities  and  small
coal producers objected  to the proposed bill.   The  agency has  not revived the
proposal, since there has been a substantial voluntary increase  in the use of
washed coal by the utility companies  in the  state.

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                                      62


                                6  CONCLUSIONS
6.1  DATA ON POWER PLANTS' COAL USAGE

       The selection of power plants for  study  and  determination of their coal
supply characteristics was accomplished with  the  aid  of  reports  and data bases
available  from  the  U.S.  Federal  Energy  Regulatory Commission,  the  Energy
Information Agency,  and  the  Bureau of Mines.   In most  cases, these  data were
adequate  to  identify  the  mines  supplying  each  plant,  to  establish  coal-
purchase patterns, and to predict S0~ emissions corresponding  to the  delivered
coals.  Unfortunately, two plants  with relatively high  S02  emissions reported
coal-purchase  data  in such  a way  that  the  specific suppliers  could  not  be
identified.   These  plants had to  be  dropped from consideration  in the study.
Two other  plants were also  dropped:   one  because it fires coal  that  is  not
amenable to  cleaning,  and the other because  its  source of  raw  coal  could not
be adequately characterized.   This  left 20  plants  for evaluation.

       The coal-purchase data revealed that:

       •  Power  plants,   even mine-mouth  facilities,  typically  buy
          from several suppliers.

       •  Most plants  have  one  to three suppliers  that  account  for
          the bulk of  their  coal;  on the average, 62% of the coal  for
          a given plant comes from  a single source.

       •  Most plants buy coal in lots of 10,000  tons or more.

       •  Total  annual S02  emissions (a  function of  plant  size, coal
          characteristics, and  capacity  factor)  vary over  a range of
          about  6.75 to 1 among plants.

The last  fact listed  implies that  significant  emission  reductions  could  be
obtained through application of coal  cleaning (or other  controls)  to  only a
subset of the plants included in this study.

       Most of the plants  already  have S02 emissions  lower  than are predicted
from  run-of-mine characteristics of the major coal purchases.   In  some cases,
this  is  due  to  small purchases  of low-sulfur  coal   for  blending.   However,
analysis of delivered-coal versus raw-coal  characteristics  indicates  that some
degree of  coal  cleaning  is  being  employed by many   suppliers  (approximately
one-third  of the  coal evaluated  in this  study).   Details  of the  cleaning
processes  are not generally available,  although  data on coal-cleaning equip-
ment  installed at specific  facilities  are  reported.   We utilized  those data,
together with the coal characteristics,  to infer the cleaning  level for each
coal.   We  concluded  that  very little coal  is receiving  the extensive cleaning
modeled in  this  study (see  Fig. 9),  so no attempt was  made to  develop incre-
mental S02 reductions  for changing  from  coarse  to full beneficiation.

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                                       63
6.2  EMISSION REDUCTIONS DUE TO COAL  CLEANING

       The  principal  coal (i.e.,  the coal  from  the single  largest  supplier)
was identified  for each power plant  and subjected  to  a washability analysis.
The computer  model used  is  based on a typical Level  4 cleaning  plant flow-
sheet,  and  no optimization was  attempted  for  specific  coals.   In commercial
practice, cleaning plants are generally unique, being designed with particular
coals  and  markets in  mind.    Thus,   some  performance improvements  over those
predicted  here may  be  possible,  although  it  is  not   feasible  to make  any
quantitative estimates at this time.

       A larger uncertainty  in the results  stems  from  the  observed variations
in coal washability, even for coal samples  from the same seam and mine.  Where
possible,  we  used washability  data obtained  using  coal  samples  from  the
particular  mine  supplying the  principal  coal.    In other cases,  the  closest
possible match  was at the county  and coal-seam level.   More accurate  predic-
tions would require extensive sampling and  washability analysis of coal yet to
be extracted at each mine.

       The  average sulfur reduction  predicted  was about 29%,  with a standard
deviation of  9.9%.  The minimum  reduction was only  10.6%, while  a 50% reduc-
tion  was  predicted for  one  coal.   Differences in the  fraction  of the sulfur
occuring  as pyrites  and in  the  size distribution  of   the  pyritic  particles
account  for most  of  the  variation.   The  degree  of  reduction  also  depends
somewhat  on the weight  recovery  of  coal in  the  cleaning process  (i.e.,  how
much  coal the operator is willing  to  throw out along with the unwanted mineral
matter).   We investigated both  80%  and  87.5% weight recovery  and found that
the lower recovery improved the sulfur removal by  an average  of about 22% over
the higher value.  Our results are thus based on 80% recovery, which is within
the range of accepted commercial practice.
6.3  COAL CLEANING VS. PARTIAL  FGD

       The  costs for  sulfur dioxide  control by  PCC (in  terms of  $/ton S02
removed) were  compared with  those  for  limestone-slurry  FGD.   It  was assumed
that the  FGD systems would  be  designed to meet,  but not  improve  on, the S02
emissions rates  set  by PCC.  This  was  accomplished  by specifying  FGD systems
sized to  treat  only a portion  — 32%  on the  average —  of  the  flue  gas at an
S02 removal  rate of 90%.  When this  portion  of the  gas  stream  was mixed with
the untreated  gas,  the  net  effect  was  the same as  for  combustion of cleaned
coal.    A 30% increase  in FGD  system  installed cost was used  to  account for
retrofit difficulty.

       The comparison indicated that:

       •  PCC is more cost-effective than  FGD for  50% of  the plants,

       •  PCC and FGD costs are comparable for 25% of the plants,

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                                      64


       •  FGD  Is more  cost-effective  for  the  remaining 25%  of  the
          plants, and

       •  There  are no  statistically significant variations (at  a  95%
          confidence  level)   in   percentage   sulfur  reduction,   PCC
          costs, or FGD  costs  among the three states included in this
          study.

       Costs (in 1983 dollars)  for PCC  ranged from  $354  to  2057/ton S02,  with
an average of $809/ton SC^.  For FGD, the range  was  $525-1294/ton SCU,  with an
average value of $829/ton SC>2«  While these costs  are  indicative of the values
and variations  that  could be expected,  they  have not been  adjusted for site-
specific  technical  and  economic  factors that  could significantly  affect  the
results in any given case.

       Other  factors  should  also  be  considered  in  comparing  PCC and  FGD.
Specifically, PCC can:

       •  Reduce coal-transportation requirements  (reduced  secondary
          emissions and  public safety hazards),

       •  Produce a more uniform fuel,

       •  Improve  boiler efficiency by reducing  slagging  on  boiler
          tubes,

       •  Reduce load factors  for  ash-collection and handling systems
          (as well as any existing FGD  systems), and

       •  Improve overall plant availability.

In contrast, FGD systems can:

       •  Accommodate coal switching and

       •  Achieve much higher sulfur reductions  than PCC.

Furthermore, PCC plants can be  (and generally  are) constructed at  a  mine or
central location independent of  any particular consumer.  Assuming that there
is a  sufficient market  for  the cleaned coal,  this  removes the  economic  con-
straint encountered in  retrofitting new control equipment (e.g., FGD systems)
on older plants.
6.4  REGULATORY AND INSTITUTIONAL CONSIDERATIONS

       The existing use  of coal cleaning  is  fairly widespread, but  it  is  not
directed  primarily at  sulfur  reduction.    Voluntary  application  of  "deep"

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                                      65


cleaning  techniques  such  as  those modeled  in  this  study  is  likely to  be
constrained by a number of factors, including:

       •  A less favorable tax status  for PCC plants as contrasted to
          FGD systems,

       •  Lack of an assured,  stable market for  the  coal,

       •  Major capital investment  requirements,

       •  Economic disadvantages  (scale factors)  for small  producers,

       •  Uncertainties  regarding  future  environmental   legislation
          and impacts of existing regulations under  the  RCRA,  and

       •  A perceived  lack  of adequate data  for investment decision-
          making .

A number  of  possible measures to  encourage  the voluntary  use  of cleaned  coal
were suggested  in  Sec.  5.3.1.   These  included such actions as  loan  and price
guarantees,  changes  in the  tax  laws,  and stabilization of regulations  for a
guaranteed period  of time.    None  of  these  measures  is  likely to have  much
effect in  the short  term, and those  requiring commitment  of  government funds
would almost  certainly be difficult to legislate.

       Requirements  for coal cleaning  have been proposed at the federal level
as part of acid-rain legislation.  While these are  still  under consideration,
the most  likely governmental level for implementing a cleaning requirement is
the state level.  State Implementation Plans  could be  revised  to:

       •  Require a  percentage SC>2  reduction  for  all sources,

       •  Set an emissions cap for  each power  plant,

       •  Require  a  percentage  removal  of   sulfur  if uncontrolled
          emissions  are greater  than a threshold  value,  or

       •  Regulate SO* levels  for each source  individually.

Application  of  any  of these measures  could  promote the use of cleaned costl.
However,  the  regulations  would  have  to  be flexible and applied with  care to
avoid driving certain  coals  (and coal  producers) from the  marketplace  because
of  poor  cleanability.   Furthermore,  actions involving emissions caps  could
stimulate  the  transportation  of  low-sulfur coals unless  requirements  for
"local" coal  use were  also  enacted.  Experience  in  Ohio has  indicated  that it
is  quite  difficult  to  put  together  an  acceptable  legislative/regulatory
package.

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                                       66
       In  conclusion,  coal cleaning  has  the potential for  significant sulfur
reductions when  applied  to many  of  the  coals  now being  used  in  the  study
region.   The  technology  should  be considered  in formulating any  SC>2 control
strategy,  but  problems  arising  from  coal  variability,  limited  efficacy  as
compared to FGD, and  multiplicity of coal suppliers make  a  universal cleaning
requirement difficult to design and implement.

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                                      67
                                  REFERENCES
 1.   Nielson,  G.,  Ed., 1981 - Keystone  Coal Industry Manual,  McGraw Hill, New
     York (1981).

 2.   Jones,  R., and M. Jones,  The Effect  of Coal Cleaning on the Quantity  of
     Sulfur Dioxide  and  Ash  Produced by  Coal-Fired Power Generation  in the
     Northeastern   United  States,   U.S.   Department   of   Energy   Report,
     DOE/ET/12512-2  (May  15,  1982).

 3.   Argonne  National  Laboratory   and   Bechtel  Corporation,   Environmental
     Control  Implications of Generating  Electric  Power from  Coal,  Argonne
     National  Laboratory  Report,  ANL/ECT-3, Appendix A, Part 2 (Dec. 1977).

 4.   Environmental  Control Implications  of Generating  Electric  Power from
     Coal,  prepared  by Bechtel Corp.  for Argonne National Laboratory, ANL/ECT-
     3,  Appendix A,  Part  1 (Dec.  1977).

 5.   Doctor,  R.,  Utility  Flue  Gas  Desulfurization:   Innovations  and  System
     Availability,  Argonne  National  Laboratory  Report,  ANL/ECT-11   (March
     1982).

 6.   Laeske, B., Trends in Commercial Application  of FGD  Technology, EPA/EPRI,
     7th Symp. on Flue-Gas Desulfurization, Hollywood, Fla. (May 17-20,  1982).

 7.   Dunlop,  W.,  Economic  and  Design  Factors  for Flue Gas Desulfurization
     Technology, Electric Power Research Institute Report, EPRI CS-1428  (April
     1980).

 8.   Economic Indicators, Chemical Engineering 30(1) (Jan. 10, 1983).

 9.   Coal  Outlook,  Pasha  Publications,  Washington,  D.C.,  5(46)   (Nov.  29,
     1982).

10.   Phillips, P.J.,  et  al.,  Coal Preparation  for Combustion and  Conversion,
     Electric  Power  Research Institute Report, EPRI AF-971 (May 1978).

11.   Coal  Outlook  Supplement,  Pasha  Publications,  Washington,  D.C.,   5(40)
     (Oct.  18, 1982).

12.   Burhoff,  J., et  al.,  Technology Assessment Report for Industrial  Boiler
     Applications:    Coal  Cleaning  and Low Sulfur Coal,  U.S.  Environmental
     Protection Agency Report, 600/7-79-178c, p. 338 (Dec. 1979).

13.   42USC  1857 et seq.,  Sec.  lll(a)(l).

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                                      68


14.  44 FR33580 - 33624,  NSPS:   Electric Utility Steam  Generating Units (June
     11, 1979).

15.  Lihach, N., More Coal Per Ton, Electric Power Research Institute  Journal,
     pp. 6-13 (Jan.  1981).

16.  Blackmore, G.,  Coal Preparation Improves Utility Efficiencies, Coal  Age,
     pp. 70-77 (Jan. 1981).

17.  DDE/Office of  Policy, Planning,  and Analysis,  Energy  Projection  to the
     ^ear 2000, U.S. Department of Energy Report, DOE/PE-0029  (July  1980).

18.  Use  of  Coal  Cleaning for  Compliance  with  SO*  Emission  Regulations,
     prepared  by  Battelle  Columbus  Laboratories,   for  U.S.  EPA/IERL,  PB81-
     247520 (Sept. 1981).

19.  Bill to  Enact  Sec.  3704.17  of  the  Revised  Code, 113th General Assembly,
     Regular Session (1979-1980).

20.  Private  Communication with Staff of Ohio Environmental Protection  Agency
     (March 2, 1983).

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      69
  APPENDIX A





COAL DATA BASE

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                                       71


       As a  result  of  work performed at Argonne National  Laboratory using the
large analytic  and reserve  coal  data files  from  the United States  Bureau of
Mines (USBM),  it  was decided  to  facilitate future coal studies  by organizing
these data in  a manner that would  allow for quicker and  easier  retrievals by
computer.  Therefore,  the complete  USBM analytic  and reserve  data files (6.9
megabytes  of data)  were   stored  in  1978  in  an  interactive  data base  (this
provides for data current  as of 1976).
                             o
       In  a related effort,   coal-washability  and  coal-reserves data  were
integrated to match  reserves  and  washability whenever possible.   Two computer
programs were developed to match  the appropriate entries  in  each data set and
then merge the  data  into  the form presented  in the report.   Approximately 18%
of  the  total demonstrated  coal  reserves were  matched  with  washability  data.
Moreover, about 35% of the reserves  that account for  80% of  current production
were successfully matched.  Each  set of  merged  data specifies the location and
size of  the reserve,  selected physical and chemical  characteristics of  the
coal, and  washability data  at three crush  sizes  (1.5 in.,  3/8  in., and 14
mesh) and  several specific  gravities.   In  each  case,  the  percent  recovery,
Btu/lb,   percent ash,  percent  sulfur,  and  Ib  SC^/IO  Btu  are given.   These
data, combined  with  the mine-specific information that appears in Tables A.l-
A.5, served  as the  basis for  this  report.   The tables  include  data for 53
mines that were principal suppliers to those  plants in  Illinois  and Indiana
(with a  few  in Ohio) that are part of  the FERC midwestern  distribution  grid.
The  mine  identifications were  obtained  from  the   FERC  regional office  in
Chicago, with supplementary information  from  Ref.  1.

-------
Table A.I  Available Preparation Equipment for Coal Mines in Illinois




Plant
Number
1


2


3


4


5


6

7

8

9

in



II



12



13

1'.

IS

Locat ton
of Mine:
County
(Nearest
City) Seam
Wahash »">
(Keens-
burg)
Montgomery 16
(Coffeen)

Jefferson 16
(Walton-
vllle)
Williamson 16
(Marlon)

Macoupln 16
(Carl 1ns-
vllle)
Macoupln 16
(Albera)
Christian »6
(Pawnee)
Randolph 16
(Marlssa)
St. Clalr 16
(Marlssa)
Saline 15,16
(llarrls-
burg)

Randolph 15,16
(Percy)


Randolph 16
(Percy)


Douglas '6
(Murdock)
Williamson ?
(')
Macoupln ?




Mine
Wahash


Illllsboro


Orient 13


Orient »4


Monterey
11

Monterey
12
Mine 110

Baldwin
fl
River
King 16
Central
Prepara-
tion
Plant
Captain



Stream-
line


No. 5
Mine
No. 4
Mine
Ca r t e r
Available Preparation Kqulpment
«l WO -V U
r4 3 O V «
«j.u So«'SSS" * £ K
*-*'5S!»j:'3IJ'2u2«i>''u2«
Company Cle.mlnp, xmoai/iaM^oou.'nXHU.o
Amax Coal 2-1 XXX
Co.

Consoll- I
dated Coal
Co.
Freeman 2-3 X XXX XXX
United Coal
Co.
Freeman 2-3 XX XXX
United Coal
Co.
Monterey 2-iXXX X XX X X
Coal Co.

Monterey 2-3 XXX X XX X X
Coal Co.
Peabody 2-3 X X X X
Coal Co.
Peabody 1
Coal Co.
Peabody 1
Coal Co.
Sahara 4-5 X XXX XX X X
Coal Co.


South- 2-3
western
Illinois
Coal Co.
South- 2-3 XXX X X
western
Illinois
Coal Co.
/legler 1 X X
Coal Co.
Zlegler 2-3
Co.il Co.
? 2-3

-------
                 Table A.2   Available  Preparation Equipment  for Coal  Mines  in Indiana
Plant
Nnmtwr
r
2
3
4
5
6
7
8
9
10
U
12
13
14
15
16
17
1ft
19
of Mlnr:
Count y
(Nr.iri'Sl
City) So.im
Plkf '
(Srlvln)
Clay 111
(Brazil)
Sullvan V1.V11
(Sul Ivan)
Warwick VI
(Chand ler
Knox 1
(Evans-
vltle)
Knox 7
(F.vana-
vllle)
Veralllton 7
Pike ?a
(Velpen)
Warwick VI, VI I
(Warwick)
Pike (Oak- V
land City)
Pike (Oak- Vb
land City)
Greene VI
(Carlisle)
Greene 7
(Dugger)
Verallllon VI
(Universal)
Warwick V
(Lynevllle)
Vlgo 7
(Terre
Haute)
Pike
Pike
Duhols (In
eastern KY
and U. Va.)
Mlnr
Alihol t
Clilnook
Ml nnehjha
Ayrshire
Blcknell
Pit 11
Apraw
Lee
Velpen
Tell City
Old Ben
11
Old Ben
12
Hawthorne
Sycamore
Universal
Lynevllle
1 & 2
Pit *1
Enos
Marlah
Hill
-
•n u -t
Z "3 g |g
ivir^-^^'-^I^^liS.rlsS
Company Clr.inlnR s*jj2£uS*3£. SSS.gj.w
AnTmti 1
Co.il anil
Kitrrgy (.0.
Aroax Coal 1 XXXX XX X
Co.
.ana* i.o.,1 1 XX XXX
Co.
Amax Coat I- ) XXXX XXXX
Co.
Blcknel! 1
Mineral fl
Co.
Black 4-5
Beauty Coal
Co., Inc.
Cambridge 1
Hopf Mining 1
Co.
Ohio Valley 1
Coal
Old Ben 1
Coal Co.
Old Ben 4-5
Coal Co.
Peabody 2-3 X XX
Coal Co*
Peabody 1
Coa 1 Co .
Peabody 1 X X XX
Coal Co.
Peabody 2-3 XXX XXX
Coal Co.
S&G 1
Excavating
Closed 1
Closed 4-5
DM. Con) 1
                                                                                                                         OJ
 FlvP seams mined In county
''Lower Mlllcnhnrp,

-------
Table A.3  Available Preparation Equipment for Coal Mines in Kentucky
Plant
Number
1
2
3
6
5
6
7
Locat ion
of Mine:
County
(Nearest
City) Seam
Muhlenberg ?
(Central
City)
Muhlenberg 19
(Green-
ville)
Ohio 19
(Center-
town)
Ohio 19,11,13
(Beaver
Dan)
Ohio 19
(Beaver
Da.)
Hopkins 16
(Hadlson-
vllle)
Ohio T
 C t) U
M ft. u • M jo « <« -^ £e
u « « c: e • 4 c ~4 u « u
«^£b«-H«l-4Ot.« >. j< • ft*
Level of §E 2 £>S^'3^US^"SS5w
Mine Company Cleaning 2 » " « « » H < <-> <-> •• ~> » P to °
Glbralter Peabody 1
Coal Co.
River Peabody 2-3 XX XX
Queen Coal Co.
Alston Peabody 1
Coal Co.
Homestead Peabody 1 X
Coat Co.
Ken Peabody 4-5 X X X X X X
Coal Co.
Donbov Tower 4-5
Resources
Inc.
ElmCrove Closed 1

-------
,0 3D -J 0* iji *«• Ul f"J -*
3? 3? |f «»£ o| >jf of 3? ». sir
S i S. £° ST !r 5 — § 2.3 a? <* ^ ' 2
S " ti ~3 S 3 ° " s s i" I
Bl « '3 *-**«• 3 TC a
5 -" i •
7P ; si":: 3s" sz *z z
r 1 IT 3- 3-
1
owso z > ^ jj 5" •* ?

si* 1? !• 3 •a vs- *s s
?r ^ •« a w • » ^
fc N 1 J ff
N> 3 O

~* "*O*O O» OS 0»0 O"*O b»« — 0
. O e • 01 a» a atn ffc: ?£ s= 3 »
ffS- 5. ' ^3 2.S- | ?
a it • i » •


"ii1" " i ~ " i
J W



X

X

X X


X XX



X



X



X

X



z ~e
\ r
*3 ^»
° c o ° r
•» Z 0 -^ O
" *» e ^
^ o» 3 z »
1 >< 3 •*
a no
rr —3

A
3



*

3
n




a
"S
3
n r*
^ <
s —
3" o





H
0)
cr
1— >


>

*•


^
ft>
I j.
•«•
?
H
(t
T3
(U
H
1 03

Magnets

Breaker

Crusher

Dryer
Screens
Washing
Tables

Air Tables


Cyclone
Centrifuge

Flotation

Jigs

Heavy Media
Thickener
Filter
Other









>
a
?
M
l»
S
•1
§
n
s
f
3




rt
H-
O
3
t4
C
•o
3
3
rr
b
n
o
CB
-
H-
3
m
CO
3
O
y
o







-------
Table A.5  Available Preparation Equipment for Coal Mines in Pennsylvania


Plant
Number
1
2
3

Location
of Mine:
(Nearest
City) Sea* Mine
Greene Waynes- Boyle
(Greens- burg
burg)
Allegheny Pittsburgh Champion
(Imperial) 1
Greene Sewlckley Dunkard
(DIUIner)
Available Preparation Equipment
5 f g IB
sss 89. s a s D !; J s •,
Level °f g, 3 3 S, Z 'ma H o c o eoS^-ij:
Company Cleaning ^£iS«5H3o
-------
                77
            APPENDIX B





COMPUTER MODEL OF COAL PREPARATION

-------
                                      79
B.I  INTRODUCTION

       Computer  models  for  several  levels  of  physical  coal  cleaning  were
developed  for  Argonne  National  Laboratory  by  the  Center  for  Energy  and
Environmental  Studies  of Carnegie-Mellon  University (Contract No.  31-109-38-
5236).  The authors of the  September 1979  study were C.N.  Bloyd,  J.C.  Molburg,
D.R. Lincoln,  and E.S.  Rubin.   This study  surveyed four  preparation levels,
from  a simple crushing  and  sizing operation  through  complete  heavy-media
washing (including intermediate-size coal  and fines).

       The essential parameter of coal preparation is overall  plant  yield,  the
ratio of mass  output to mass  input of moisture-free  coal.   The Btu recovery of
the  coal  based on  this  parameter and  the related  production of hundreds  of
thousands of  tons  of  refuse  annually for  an  average-size  coal-cleaning  plant
is the controlling  parameter in the model.   What follows  is  a description of
the  computer  model  for  the  coal-preparation  plant  as  found   in  the  draft
report.

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                                       80






                     3  COMPUTER MODELS OF  COAL  PREPARATION



 3.1   INTRODUCTION




        With respect  to both  economic and  environmental  consequences,  the




 essential operating  parameter of coal preparation  is overall  plant  yield.*



 Since raw coal  feed  cost  is  the largest component  of total  product  cost,  the



 amount  of material discarded, as indicated by  overall yield,  must significant-



 ly impact cost.  The most evident environmental  impact  of coal  cleaning is



 the production  of refuse.  While reduced  yield may  be required to improve




 the characteristics  of prepared coal, it  is necessarily accompanied by  in-



 creased refuse  production.   Therefore, overall yield has been chosen  as a



 principal variable for the models described below.




        Using these models, specification  of overall yield along with  certain




 coal-specific data is  sufficient to estimate prepared coal  characteristics



 and cost for several plant configurations.  These  configurations have been




 chosen  as representative of  coal cleaning practice over the usual range of




 complexity for  steam coal preparation.    The  simplest, or  level one, plant



 is limited to thermal  drying to given specifications.   A level  two  plant



 washes  only coarse coal, mixing the finer coal into the product without



 preparation.  In a level three plant some of the finer  coal is  washed, but



 only in a level four plant are all coal sizes  washed.   These  plants are des-



 cribed  in more  detail  following some discussion  of coal preparation equipment.






 3.2  MODELS OF  COAL  PREPARATION EQUIPMENT



 3.2.1   Rotary Breaker



        The rotary breaker product is regarded  as run-of-mine  feed to  our  coal




 preparation processes.  The  most important characteristics of  breaker  operation



are the  size distribution of  the product stream and the  fraction of  material
 *Defined  here as the  ratio  of mass output  to mass  input  of  moisture-free  coal.

-------
                                       81


 sent to refuse.  Since the  rotary  breaking     is taken to be part of mine

 operation, the refuse is of no concern to the  cleaning plant.  The  size  dis-

 tribution, however, is.  The rotary breaker model must predict the  size  dis-

 tribution of the product.   That distribution may vary widely due to operating

 parameters and coal characteristics.  However, empirical evidence over a wide

 range of coals and sizes suggests  that the size distribution satisfies the

 following relationship (Landers, 1946):
                        «
       F(x)  = exp[-(|-) ]                                             (3_1)
                      0
 where  F(x) is the total weight fraction of material which will not pass

 through a screen of opening size x.  The constants, a and xo, are material

 parameters which characterize the  subject coal.  The range of a is  typically

 0.5 to 2.9.  The screen opening for which F(x) = 1/e = 0.3679 is x0. This

 distribution works well to  characterize broken or  crushed coal.  If F(x)

 is known for any two values of x,  a and x0, can be determined since

 log[log(l/F(x))] is linear  in log  x with slope a.

       For example, suppose F(4")  = 0.09 and F(l/4") = 0.70.  Then  the frac-

 tion of material which will not pass through 4" and 1/4" sieves is  0.09  and

 0.70 respectively, and log  [log(l/F(x))] = 0.0194 for x = 4"(log x  = 0.6021)

 and - 0.8099 for x = 1/4" (log x = 0.6021).

              0.0194 - (-0.8099) .  0.8295  =  0>689                   „„
          ~   0.6021 - (-0.6021)    1-2042                           _  l^  J

Then,
                         -1/2                  -1/0-6S9
        XQ =  x[-£n F(x)]     =  0.25[-£n 0.70]         =  1.12"       (5-3)

Therefore,  the  cumulative  size distribution function for this example is

                    (x/1.12)0"689
       F(x)  =  e -                                                    (5-4)

The weight fraction of material which falls in an interval  from Xi  to x2

is given by |F(x2) - '

-------
                                        82
       To verify equation 3-1, published size distribution data for 19 coals

were checked via least squares regression analysis for adherence to that

equation.  The results indicated very close agreement with R^ from 0.9 to 0.99

and an average R~ of 0.98 for log log(l/F(x)) vs. log x.

       A relationship between topsize (TS) and xQis expected since the size

distribution is naturally linked to the topsize.  By regression analysis of

XQ for the 19 coals considered above, the following relationship has been

obtained

                      0.467
       x   =  0.897 TS                                                 (3-5)

The results of that regression indicate that £n x0 vs. in TS is linear with

R  = 0.89S.  Ideally, size distribution data will be available.  However, in

its absence equation 3-5 may be used to estimate XG.  Note that if one data

point other than x0 is available, it may be used along with equation 3-5 to

approximate the size distribution function.  In the absence of any size data,

the parameter, a, may be estimated by

       a  =  0.4 •<• x0                                                  (3-6)

This very approximate result was also obtained by examination of the 19 coal

sample and simply reflects the fact that F(x) approaches zero as x approaches

the topsize.


3.2.2  Crusher

       The significant characteristic of crusher operation for our analysis

is the product size distribution.  The discussion of this topic for rotary

breakers applies equally to crushers.


3.2.3  Washers

       Since all washers rely on specific gravity differences, a single model

is proposed for all types.  That model requires two types of data: coal-speci-

-------
                                      83

 fie washability functions and equipment-specific distribution functions. The

 weight washability function, w(i  , iSg), predicts the mass fraction of  coal in

 a given size interval, ix, with specific gravity in the interval iSg.    For

 example, if 15% of 1/4" to 3/8" coal particles have a specific gravity  from

 1.3 to 1.4, then

       W(l/4"-3/8", 1.3-1.4) = 0.15                                     (3-7}

 This washability data is required for all washed sizes.

       If the size fraction from the previous example were washed at a  speci-

 fic gravity of 1.4 the expected mass yield of clean coal would be 0.15.  How-

 ever, equipment and operating limitations prevent all of the float from enter-

 ing the clean coal stream.  The distribution' curve for a specific washer indi-

 cates the fraction of coal with a given specific gravity that enters the clean

 coal stream.  This curve will vary according to the washer design, method of

 operation, and coal particle size.  A typical distribution curve is shown in

 Figure 3.1.   Suppose, in the example just described, that the fraction of

 coal with specific gravity 1.35 (the midpoint of interval iSo) which reports

 to the clean coal stream is 0.75.   Then the contribution to clean coal  of par-

 ticles in the size range ix is (0.75)(0.15)A0=o.113 m0,  where mo is the total
mass flow rate of feed.   Similarly, the total mass flow rate in the clean coal

 stream is:

       mc  =  I   _Z  K(ix, isg)«  D(ix,  isg) m0                         (3-8)
              ix  isg
where D(ix, iSg) is the fraction of material in size interval ix and specific

gravity interval iSg reporting to clean coal.  The midpoint of the specific

gravity interval may be used to locate the appropriate position on the  abscis-

sa of the distribution curve.

       Simplification of this result is possible through the use of cumula-

tive weight washability functions, which may be designated by W(TS, isg). This

-------
                                    84
       1.0
 fraction
    to
clean coal

       0.5
       0.0
                                                     SG
                   Figure 3.1  Distribution Function
        1.0
   fraction
      to
  clean coal
         0.0
                Figure  3.2   Ideal  Distribution Function

-------
                                       85
function indicates the fraction of coal with topsize TS which has a specific

gravity in range isg.  If W(6",iSCT) = 0.37, then the fraction of coal which

will pass through a 6" screen and which has specific gravity in the range

designated by isg is 0.37.  A  cumulative distribution function may be simi-

larly defined.  D(TS, isg) is the fraction of coal of topsize TS and in speci-

fic gravity range isg which enters the clean coal stream.  With these func-

tions,

       mc  =  _I  K(TS, isg)- D(TS, isg)-BO                            (3-9)



It is important to note here that mo is the mass flow rate of all material  •

which will pass through a screen of opening TS.  A typical washer  is used

only for a range of sizes from, say, TS to a bottom size, BS.  Equation 3-9

can be used for this situation through the use of the previously described

size distribution function.  The fraction of coal in the range BS to TS is

F(BS), where F(x) is based on the topsize, TS.  The fraction of material in

this size interval and specific gravity interval isg can be designated

W(TS-BS, isg).  A mass balance on the material in this specific gravity range

yields:

       W(TS-BS,  isg)-F(BS) = W(TS,isg)- W(BS,isg)•[l-F(BS)]  .          (3-10)

Therefore,

                         W(TS, i so) - W(BS, i „) [l-F(BS)]
       WCTS-BS,  i._)  =  	*	            (3-11)
                  g                 F(BS)

A combination distribution function for a size range TS to BS can also be

defined, but the algebra used above does not necessarily apply.  This results

since the  cumulative distribution function represents data from measurements

on actual equipment in operation.  If that equipment is processing material,

from BS to TS in size, only the effect on those sizes will be reported. Cumu-

lative washability data, on the other hand, results from tests of all size

-------
                                       86
particles up to the specified topsize.   It is possible to define a  cumulative

washabiltiy function which applies to a size range BS to TS, thus obviating

Equation 3-11.   However, much less data is required to use the suggested

formulation for various size ranges, than would be required  if each range

used separate washability data.

       Equation 3-8 is consistent with current coal cleaning models used in

the detailed design of cleaning plants where accurate estimates of each flow

stream volume and characteristics are essential.  Where somewhat less accuracy

is acceptable the data collection and calculations can be simplified by assum-

ing a special distribution function which is depicted in Figure 3.2.  For

this distribution, any material with specific gravity below SG, the specific

gravity of separation at which the washer operates, reports to clean coal.

The remainder reports to refuse.  This means that no material is misclassified

according to the specific gravity criteria which is the basis of washer opera-

tion.

       To qualitatively assess the effect of this approximation on model

accuracy consider Figure 3.3 where the fraction of misclassified material of

each specific gravity is plotted vs. specific gravity.  Note that very little
                                                             A
heavy material is substituted for light material except near SG where those

materials differ only slightly in specific gravity (and hence in properties).

The effect of ignoring the misclassification is, therefore, expected to be

slight.

                                     f 1. 0 for SG  <_ SG

                D(TS, isg)   =

                                     •  0.0 for SG  > SG

Substituting into Equation  3.8
       m
c  =  m0  I  W(TS,.isg)                                        (3-12)
                  isg :  SG  
-------
                                   87
                0.5
   fraction
 misclassified
                0.0
                                                      SG
             Figure 3.3  Misclassified Material for a Typical
                         Distribution Function.
yield     1.0
     WCTS,SG)

     W(BS,SG)
                                                          SG
                Figure 3.4  Weight Washability Functions

-------
                                       88
The sum in equation 3.12 has special significance.  It is a weight washability

function which is  cumulative in size and specific gravity.  Its value is
                                       *"                                  ^
the total fraction of feed material with specific gravity not exceeding  SG

which will pass through a screen of opening TS.  This is washability data

of the sort prepared by the Bureau of Mines (Bu Mines RI-S118, 1976).  In

summary, the cummulative washability data provides an adequate estimate  of

washer yield for a specified topsize and specific gravity of separation. Note

that equation 3-11 still applies.

       Accepting an ideal distribution function the weight washability func-

tion from equation 3-11 is simply washer yield. Total plant yield is deter-

mined by the yields of each washed stream.That is, the yield for any washer  is

       Y  =  {W(TS,SG)[1-F(TS)] - W(BS.SG)[l-F(BS)]}     1             (3.13)
                                                    F(BS)-F(TS)

where TS  and BS are the washer- specific top and bottom size.  If Y is

the required yield the washer must operate at a specific gravity which satis-

fies equation 3-13.  Figure 3.4 is typical of  cumulative weight washability

data.

SG can be determined by trial and error if the weight washability functions

are known.  For the initial trial, SG for which W(TS, SG) = Y may be used.

This will usually exceed SG.

Other Washabitity Functions

       Properties of the washed product may be determined by mass or energy

balances similar to that leading to equation 3-11.  Therefore, the heating

value   and weight fraction sulfur and ash are given by:

       BTU(TS-BS, §G) =   {BTU(TS, SG)  - BTU(BS, SG)[l-F(BS)]}__1     C3-lla)
                                                               F(BS)
       SUL(TS-BS, SG) =   {SUL(TS, SG)  - SUL(BS, SG)[1-F(BS)])  1     (3.lib)
                                                               F(BS)
       ASH(TS-BS, SG) =   {ASH(TS, SG)  - ASH(BS, SG)[l-F(BS)]}  1     (3.lie)
                                                               F(BS)

-------
                                      89
3.24  Level 1
     Preparation at this level does not involve any washing.  Its objective


is to satisfy customer specifications or shipping requirements by adjusting


coal size and moisture content.  Preliminary size control of the mine issue


is accomplished by a rotary breaker which also eliminates gross contaminants


such as large rocks or timber.  The product from the rotary breaker will be


referred to as run-of-mine coal.  Since the only effect on yield of this


breaking operation is the elimination of large rocks which would dilute the


coal, and since laboratory tests which are used to ascertain coal character-


istics do not account for such dilution, it is consistent to regard this size-


controlled product as run-of-mine coal.  This most basic level of preparation


is therefore regarded as part of the mining process.  It is, in fact, part of


most modern mines.  Hence, "Level 1" preparation is used to refer to addition-


al size control beyond that obtained with the rotary breaker and possible


moisture control.


     Figure 3.5 is a flow diagram for the Level 1 plant.Run-of-mine coal is


classified and crushed to the specified top size with single or double roll


crushers.  If moisture reduction is necessary a thermal drier, fired by


prepared coal, is used.  The various stream flow rates are determined as


follows.  The symbols used are:


     Y   =  overall plant yield


     Y.   =  yield for washer j

   •
   fflppj  =  required prepared coal flow rate (tons/hr)


     ihj_  =  coal flow rate for stream i (tons/hr)


    Yt£j  =  thermal dryer yield

      •
      M  =  rate of moisture removal (tons/hr)

    LHV   =  lower heating value (Btu/ton)

-------
        90
          rora
   THERMAL
    DRYER
      V
  (Storage^
-3>  Effluents
Figure 3.S   Level 1

-------
                                       91
          =  heat required per unit  of moisture removed by thermal dryer
                                                                     (Btu/ton)
     MJ_  =  weight fraction moisture in stream i

    HHY  =  higher heating value  (Btu/ton)

    ASH  =  weight fraction ash

    SUL  =  weight fraction sulfur

   ksul  =  ratio of sulfur adsorbed by dryed  coal to sulfur emitted by

            combusted coal.

   	  =  (underscore) indicates moist basis.

     The yield of all crushing processes is assumed to be 1.0.  Therefore,

the overall yield of the level one plant is:

     Y0  =  Ytd =   221                                                (3-14)


Except for the adsorption of a small amount of sulfur, the moisture-free coal

which enters the thermal dryer is the same as that which leaves.  Therefore,

     rfu = m7                                                            (3-15)

Also,


     "3  =  '"ppd * "4                                                   (5~16:i

Therefore, the yield may be expressed as:
The rate of coal combustion  depends on the required rate of moisture removal,

If ktcj is the heat required  (Btu) to remove one ton of moisture  from the dry-

ing coal and ft is the rate of moisture removal  (tons/hr).

     m4  =  ktd M/LHV ppd                                               (3-18)

Notice that this equation determines the moist coal flow rate.   This is due

to the use of the moist basis lower heating value .  LHV   . indicates the

actual heat delivered to the moist coal since it claims no credit  for latent

heat of inherent or surface moisture. Determination of LHV- A is discussed

-------
                                       92
later.
                          •           •
     ...        in-?         m_
     M  =  m  - m-  =  - £ —  -     3                                  (3-19)
                       1 - M2     1 - M3
Using equation 3-15
     ft  «  *2  - 2 - 3 -                                             (3-20)
Combining equations 3-18 and 5-20 with

              Mo -Mr
     B  =  _ "2 ..."3 _                                                 (3-2»
            td
                    ^
                    ii— ppd "•  'ppd      iiii-ppd
But  m  =  m    + m4  [from equations 3-15, 5-16]                        (3-23)
            ppd
So>  *4 "  Cfippd + V ktd
A mass balance relates m4 to m4
       ra4  -(1-M4) = m4                                                  (3-25)
Noting that M4 = MS = Mppd>
     n^ =  M4/(l-Mppd)                                                  (3-26)
Substituting this into Equation 3.24 and solving  for m4 yields
                 ktdB            k   B  -1
              LHv  ,
              ——ppd
The yield from equation 3-17 is therefore:
                    ktd'B              k   .B   ^  .!
                                                ]                       (3-28)
     Characteristics of the prepared coal may be  determined  on  either a
moisture-free or moist basis from characteristics of  the  raw coal.   It is
assumed that an ultimate analysis of the moisture-free  raw coal  and the weight
fraction of moisture in the raw coal are available.   It is also  assumed that
the higher heating value of the moisture-free raw coal  is known.   Then, in

-------
                                       93
our notation, the following quantities are known  directly;  SUL   ,  ASH   ,


H, 0, N, C, and Mronr  These characteristics may  also  be  expressed  on a moist


basis.


     SUL      =  SUL      (1-M    )                                       (3-29)
     - rom         rom      ronr

         ram  '  ASHrom   C^                                           (3-30)


         rom  -
     On a dry basis no change would be expected due to moisture  removal  by


the thermal dryer.  This is true except for the adsorption of SC>2  from the


thermal dryer combustion gases onto the drying coal. Define ksui as  the  frac-


tion of generated S00 which is adsorbed.  Then


                                    m
     SUL     =  SUL      (1 + ksul  • _1)                                 (3-32)
        ppd        rom        auj   m


Using equations 3-22 and 3-25



     m4       ktd (l-Mppd)B
     —  =    -                                             (3-33)
     in         LHV ppd
      2            ^r

Therefore,

                              fcsul ktd Cl-Mpnd)B
     SUL     =  SUL    [1 +   - — - i^L~  ]                      (5-34)
                   rom             Mil
Assuming HHVrom is kno\vn, LHVppd may be determined as follows  (Btu/


     HHVPPd  '
             =  HHVppd -   -18.1020                                     (3-36)



             '  LHVppd Cl - M)- M     '1020
H is the weight fraction of hydrogen in the moisture free coal.


Example for Level 1


     Data:  m   ,  =  1000 tons/hr          H  =  0.05     ASH-nm =0.20
             ppd                                             rom

            kt£j   =  4.0 106 Btu/ton    ksul  =  0.52


            Mrom  =  °'25               HHVronf  1250° Btu/lb


                  =  °'10               SUIrom=  °'03

-------
                                      94
HHVppd  =  ^'rom =  1250°

LHVppd  =  HHVppd -  9180-H = 12500 - 459 = 12041


    pd  =  LHVppd (1 - Mppd) - Mppd 1020


        =  12041 (1-0.10) - 0.10(1020) = 10735 Btu/ Ib.


                                       =  21.5'106 Btu/ton


                  ktd-B              k  -B  -1 -1
    v ,   _  n  a.  ———  t    •!•        ^"   "\
    Ytd   -  [1  +  LHV    Cj-r^	 -  	)
                  ——ppd


            M     - M
    B  =     rom	ppd
          (l-Mrom)Cl-Mppd)


           0.25  -  0.10
                           =  0.195
          (1-0. 25) (1-0. 10)


               (4.0 -106)(0-.193)            4.0-106(0.193) -1

  Ytd  = [1  +  - -, - Cjr^ -  - 1 - )  ]  =  0.98
                [21.5-106]        l U
-------
                                         95
ROM

        rotary
        breaker
crushing


drying
                            Figure 3.6  Level 2
                                                            •>•  refuse
m3  =
      m    =
       4
   BTU

                 -  F(S2)3
               Yo -
                   F(S2)
              m  ,/Y
               ppd
                   -  F(S2)]

       d   =
       [BTU(S2, 2.0)[1-F(S2)] +  BTU(S  -  S  ,  SG)-F(S2)-Y.

       [SUL(S2, 2.0)[l-F(S2)j +  SUL(Sr  S2,  SG)-F(S2)-Y ]  J_
                                                             o
       [ASH(S2, 2.0)[1-F(S2)] +  ASH(Sj-  S2>  SG)-F(S2)-Y ]_i_
(3-38)


(3-39)




(3-40)

(3-41)

(3-42)


(5-43)

(3-44)


(3-45)


(3-46)

(3-47)

-------
                                       96
 Example for Level 2

     Size distribution data:
                                 SIZE

                                3 in.
                                1 in.
                                1/2 in.
                                1/4 in.
                            10 mesh (0.069")
                                28 mesh
                                100 mesh
FRACTION OVERSIZE

      0.000
      0.175
      0.362
      0.530
      0.785
      0.905
      0.964
 Determination of F(x)

F(
1")
=
log(l) =
loglog
o
"
1
-0.
0.
•• > ~
121
000
0
0
-0
-
.175
.000
.121
(-0.978)
(-1.161)
F(0.
log
loglog
(0

0
0.
1.
069
")
.069)
1

.785
854
161

= 0.
= -1.
= -0.
0.738
785
161
978
    =  0.069[-£n (0.785)]- 1/°-738 =  0.472
 Therefore

     F(x)  =  e
                     x   0.738
                                 0.738
For example, F(0.25) = e"
Cumulative washability data:
                                      _ Q.535 which agrees with the data  above.
               TS = 5.0'
                                                   TS = 0.25'
SG FLOAT    W     %S   % ASH  BTU/LB     K
 1.5     0.7634  0.99  10.37  13065   0.7564

 1.6     0.8308  1.08  12.02  12796   0.8096

 1.7     0.8643  1.20  12.96  12618   0.8471

 1.9     0.8975  1.33  14.07  12385   0.8835

 TOTAL   1.0000  1.36  20.20  11316   1.0000
K
7564
8096
8471
8835
0000
%S
0.92
0.98
1.06
1.15
1.29
%ASH
6.99
8.40
9.63
11.07
18.43
BTU/LB
13588
13343
13117
12830
11561

-------
                                      97
Let S2  =  0.25" and YQ  =  0.90.

For an overall plant yield of 0.90, the washer yield must be:

           Y  - 1 + F(S.)    0.90 - 1 + 0.530
    Y   =  —	— =  	 =  0.817
     1         F(S2)              0.530

The specific gravity of separation for the washer, SG, is calculated as

follows:

Assume SG  =  1.57  (value corresponding to W(3, SG) = 0.811). Then  from

Equation 3.13                                     '
    _                                                     1
    Y =  Yj  = {K(3, 1.57) - W(0.25, 1.57)[1-F(0.25)]} ^
             = {0.811 - 0.794(1 - 0.53)} ^-gy =  0.826  * 0.811

For SG  =  1.55

         Yj  = {0.797 - 0.783(1'- 0.53)} Q^J =  0.809
                                 A
This is close enough.  The value SG  "=  1.55  is used for  subsequent calcula-

tions.  The washer product has the following  characteristics  (dry basis):

    BTU(3"- 1/4", 1.55) = {BTU(3", 1.55)- BTU (1/4", 1 .55) [l-F(l/4")3 >..

 =  {12931 - 13466- [1-0.55]} f-~  =  12,457  Btu/lb
                             U • i* ^>

SUL(3"-l/4", 1.55)= {SUL(3",1.55)- SUL(1/4",1 .55) [l
 -  {0.0104 - 0.0095(1 - 0.53)} ^-^r =  0.0112

ASH (3"-l/4",1.55) = {.1120-0.0770(1 - 0.53)} •—- =  0.143
                                              U • O*5

Characteristics of the prepared coal are:

    BTUppd = [BTU(l/4, 2.0)[l-F(l/4")] + BTU(3"-1/4",1 .55)F(l/4) -Y^ i-

 =  [11561 (1-0.55) + 12457(0. S3)-0. 811] ~Q

 =  11,987

SULppd  = [SUL(1/4,2.0)[1-F(1/4)J + SUL(3"-1/4",1 . 55) -F(l/4) -0. 811] ~

        = [0.0129(1-0.53) + 0.0112  (0. 53) (0. 811)]

        = 0.0121

-------
                                      98
ASH
ppd  = [ASH (l/4,2.0)(l-F(l/4))+ ASH(3"-1/4",1.55)-F(l/4)-Y^ ^_
          [0.1843 (1-0.S3) + 0.143(0.53)(0.811)]
                                                 0.90
        =  0.165

These are on a dry basis.  Note that in this example, the washed sizes

correspond to available data.  If they had not, interpolation between sizes

for which data are available would be required.

3.2.6  Level 3 - Washing of Coarse and Medium  Coal Sizes

    The Level 3 plant has two washing circuits.  The coarse coal, sizes Sj

to  S-, is washed in a jig type washer while the intermediate coal, 82, 83

is washed in a dense media washer.  The unwashed fines are mixed with the two

washed streams to form the product.   Only mechanical dewatering is used.

Figure 3.7 represents this configuration.
                 / rotary
                   breaker

                       I
                     SiXO






S3XO








^
0


/

watering


i

(D
/




/
^si-


S2XS3


^
(7)



!
\
in°*>.

($)
^
f
«2
washer






©

S1XS2

Fl
washer


\



^,-
© .



de-
watering





©

: 	 (s
                              Figure  3.7   Level  3

-------
                                      99
               ] +  [F(S3) - F(S2)] Y2 +
Let Y} = Y2 = Y1.
Then Y0 =  [1- F(S3)] +  [F(S3) - F(S2)J Y'  +  F(S2)-Y'
        =  1 - F(S3) + F(S3)-Y'
Y'
                F(S3)
 ppd =     3> 2.0)[1-F(S3)J + P(SrS2, SG2)-Y'-[F(S3)-F(S2)]
     +  P(S2,
                                                                       (3-48)
                                                                       (3-49)


                                                                       (3-50)

                                                                       (3-51)


                                                                       (3-52)
where
           ^s some property of the prepared coal.
Example for Level 3
    This is similar to Level 2 except that 2 washers are used.  SG must  be
determined for each.  Washability data for top sizes at least  as large  as
S^ and as small S3 are required.  For S3 = 28 mesh, the following washability
applies.
                          TS = 28 mesh = 0.0232"
SG FLOAT
1.5
1.6
1.7
1.9
TOTAL
i ]
Y =


W %S
70.73 0.9'6
78.01 1.01
82.13 1.04
86.25 1.03
100.00 1.43
{ . i + F(0.0232)
v
(F(0.0232)
,-0.0232^0.738
%ASH BTU/LB
7.16 13520
9.02 13196
10.23 12967
11.73 12658
18.99 11284




   F(0.0232) =  e
                             =  0.90
          0.9 - 1 f 0.9
               0.9
                        =  0.89

-------
                                       100
Washer 1

     Assume SGj  =  1.85 (at this value W =0.89 for TS = 3.0) Checking with

equation 3.13.
         =  {W(5, 1.85) - WC0.25, 1.85)[1 - F(0.25)]}
         =  [0.89 - 0.874(1 - 0.535)] — - —  =  0.904 * 0.89
                                      0.535
Washer 2
     A
     SG = 1.9 •*•  Y2 = 0.8835 is the highest SG for which W is available. One

could extrapolate beyond 1.9 but this is a reasonable first approximation

anyway.


     Y   =  {WC0.25. 1.9)[1-F(0.25)] - W(28m. 1 . 9) [1-F(0. 0232)] }
                                                                    Q2
         =  [0. 8835(1-. 535)-0. 8625(1-0. 9)] Q g_       = 0.889

Therefore  SG  = 1.85  , SG2 = 1.9 are used.

The washed coal characteristics:

Washer 1   SG =  1.85
       BTU(3"-l/4", 1.85)= {BTU(3'M.85)-BTU(1/4",1.85)
                                                     1
                         = [12443 - 12902(0.465)]

                         = 12044 BTU/LB
       SUL(3"-1/4",1.85) =  {SUL(3",1.S5)  -  SUL(1/4",1 .85) [l-

                         =  [1.30  -  1. 13(0. 465) ]  -i   =  1.45%
       ASH(3"-l/4",  1.85)=  {ASH(3",l.S5)-ASH(l/4",1.85)[l-F(l/4)]}
                          =  [13.79  -  10.71(0;465)]g-^j =   16.47%
Washer 2  SG =  1.90
BTU(l/4"-0.0232",  1.90)  =  {BTU(l/4 ,1 . 9) [l-F(l/4) ]-BTU(0.0232 ,1 . 9) [1-F(0.. 0232) ] }
                                                                    1 _
                                                             ' F(0.0232)-F(l/4)
           =   [12830(0. 465)-1265S(0. !)]       = 12877 Btu/lb

-------
                                       101
SUL(l/4"-0. 0232", 1.90) = {SUL(1/4,1 .9) [l-F(l/4)] -SUL(0. 0232 ,1.9) [l-F(0.0232) ] }



            *  [1.15(0.465)-1.09(.                        '  FC0.0232)-F(l/4)
ASH(l/4"-0. 0232", 1.90) = {ASH(1/4,1.9) [l-F(l/4) ] -ASH(0. 0232 ,1.9) [1-F(0.0232) ] }

                                                                      1
            =  [14.07(0.465)-11.07(.l)]  *    =14.89%        ^(0.0232)^(1/4)
                                       U * *jOD



The prepared coal characteristics are:



BTU  d = {BTU(0.0232,2.0) [l-F(0.0232)]+BTU(l/4-0.0232,1.9)(Y2) [F(0.0232)-F(l/4)]


       +  BTU(3"-1/4",1.85) (Yj) [F(0.2S)] } ^


       =  (11284(1-0.9) + 12850(0.89) [0.90 - 0.535]


       +   12044(0.89) [0.535]} -    =  12264 Btu/lb
SUL  d=  (SUL(0. 0232, 2. 0)[1-F(0. 0232)] + SUL(l/4-0. 0232,1. 9)\'2 [F(0.0232)-F(l/4)]


       +   SUL(3 - 1/4,1.85)Y1[F(0.25)]} -^


       =  (0.0143(1-0.9) + 0.0116(.89)(0.9-0.535) + 0.0145 (0. 89) (0.535) )

       =  0.0135 or  1.35%


ASH  d =  {ASH(0. 0232, 2.0) [1-F(0.0232) ] + ASH(l/4-0. 0232 ,1.9)Y2 [F(0. 0232)  -

                                                                  F(0.25)]

       +   ASH(3-1/4,1.85) YitFCO.25)]} -
       =  (0.1899[1-0.9] + 0.1437(0. 89) (0. 9-0. 535)^0.1647(0. 89) (0. 535)} -^


       =  0.160 or  16%


3. 27  Level 4, Complete Washing


       In this plant all coal sizes are washed.  The fines,  S,  x  0  and the


intermediate coal, $2 x 83, are thermally dried by hot gases  from the  combus-


tion of cleaned coal in a thermal dryer.  In addition to the  effect  on mois-


ture content, the thermal dryer results in an increase in  sulfur content  due


to adsorption of S02 from the hot flue  gases.  Also, the net  yield is  reduced


due to combustion of the cleaned coal.  The final product  is  a  mixture of the


dried coals and the mechanically dewatered coarse coal. Figure  3.8 represents

-------
                                    102
refuse
                                                                  refuse
                          Figure 3.8  Level 4

-------
                                       103
        =  0.90 {0.535 + 0.957  [0.465]} ~1
        =  0.92
       The specific gravity corresponding to this yield and  associated washa
bility data are found through linear extrapolation of the available  data.
Using equation 3.13 it can be verified that:
       SGj  =  1.97
       SG2  =  2.05
       SG3  =  2.18
The extrapolations are shown on the accompanying graphs (Figures 3.9-3.12).

Properties of the washed coals are :
Washer 1
       BTU(3"-1/4",1.97) = {BTU(3",1.97)-BTU(1/4",1.97)
                                                                          ,
                         =   [12300 - 12580(1 - 0.535)]-= 12057 Btu/lb
       SUL(3"-1/4",1.97) =   [1.375-1.18(1-0.535)] rO.535 = 1.54%
       ASH(3"-1/4",1.97) =   [14.4 - 11.6(1-0.535) ]*0. 535 = 16.8%
Washer 2

       BTU(l/4"-28mesh,2.05) = {BTU(l/4" ,2.05) [l-F(l/4") ]-BTU(0.0232) [1-F(0. 0232) ] }
                                                                _ 1 _
                                                               ' F(0.0232)-F(l/4)
                  = [12615(0.465) - 12425(0. 1)]  *6$ = 12667
       SUL(l/4"-28mesh,2.05) = [1.20(0. 465)-l. 12(0. 1) ] .     =  1.22%
                                                       U.
       ASH(l/4"-28mesh,2.05) =  [11 .9(0.465) -12.5(0. 1) ]   \ . = 11.74%
                                                       \J • «3O O
Washer 5
       BTU(28mesh, 2.18) =  12225
       SUL(28mesh, 2.18) =  1.17
       ASH(28mesh, 2.18) =  13.8
Properties of the thermal dryer feed stream:

-------
                                        104
                                  Figure 5.9
                               WEIGHT KASHABILITY
  2.3.
  2.2  _.
SG
  2.1
 2.0
 1.9
 1.8
 1.7  -'            • (           .             '            '            ' "

      0.80       0.82        0.84         0.86        0.88        0.90
                                                                                  •o
                                                                                   CJ
                                                                                   o
                                                                                   a
                                                                                   n
                                                                                   X
                                                                                   u:
0.92
                         Kt.  Fraction to Clean Coal

-------
                                      105
 16






%ASH





 14
 12  -
 10  -
  8  -
     1.6
1.7
                                 Figure 3.10
                              ASH WASHABILITY
                             Extrapolated
            l.S
1.9
2.0
2.1
2.2
                                      SG

-------
                                        106
 13250
13000_
12750
12500.
12250.




  HHV









12000
                                  Figure 3.11




                               BTU KASHABILITY
                                                     Extrapolated
 11750
 11500
      1.6
1.7
1.8
                                          1.9
                                    2.0
                                    2.1
                                                                             2.2
                                       SG

-------
                                        107
-1.40
   1.35.
   1.30_
   1.25_
   1.20_
   1.15
   1.10
   1.05
 1.00
                                  Figure 5.12




                              SULFUR WASHABILITY
                                                    Extrapolated
      1.6SG    1.7         1.8         1.9         2.0         2.1         2.2




                                         SG

-------
                                       108
            1    rr{BTU(28mesh,2.18)-Y'• [l-F(28mesh)]+BTU(l/4"-28mesh,2.05)-Y-
   13   Y1 [1



                   [F(28mesh)-F(l/4")]>
              1
                      •{12225(0.92) (1-0.9) + 12667  (0.92) (0.9-0.535) }
        0.92(1-0.0535)


      = 12572



SUL13 =  0.92\Q. 465) [1. 17(0. 92) (O.D+1. 22(0. 92) (0.9-0. 535)] * 1.21%





ASH   =  2.34[13.8(0.092) + 11 . 74(0. 92)(0. 365)]  =  12.20%



The properties of the dried coal are :




BTU., =  BTU. . = 12572 Btu/lb  ASH., = ASH.- =  12.20%
   ID       13                    lo      io




      =  SUL,,!. .
                         - ppd
      -   <                   10800-2000



The prepared coal properties are:




BTU  d=  { [1-0. 535] (12572) (0. 92) (0. 957) +  12057(0. 92) (0.535) } -~




       =  12313 Btu/lb



SUL  d = {(0.465)(1.22)(0.92)(0.957) +  1 .54(0. 92) (0.535)



       =  1.40%



ASH   , =  {0.465(12. 2) (0.92) (0.957) + 16.8(0.92) (0.535)



       =  14.74%

-------
                                    109
this configuration.
Y0  =  [F(S2)]« Yj * {[F(S3)-F(S2)].Y2 + [1-FCS3D]-Y3} Y
                                                          td




                               =Y'
      =  Y'F(S2) + Ytd {Y'[1-F(S2)]}                                  (3-54)





         Y'(F(S) 4 Y[l-F(S)]}                                     (3-55)



                               ]}'1                                   (3-56)
Properties of the input stream to the thermal dryer:  (dry basis)
                                                                      (3-57)



       The properties of the dried stream, P16, are determined as for  Level 1.



The prepared coal properties are then :
P  j = ill —FfS^)j*Pli*i * Y. j + PiS^—S^, So. ) * Y * r fS~)J v              f3-5S)
 ppd          *i    Jo     To      i  £     i        £   X*.





Example for Level 4



       Data required in addition to that used for the level three analysis is



          ktd  ~  4.0«10  Btu required/ton moisture removed



          k    =  0.32 Ibs adsorbed/lb SCL emitted



          M    =  0.25
           rom


          M   ,~  0.10
           ppd


        HHV    =  11316
           rom


             H =  0.05



Based on these values Y , is calculated as for example 1:




       Ytd  =  0.957



The washer yields for washers 1,2, and 3 are:



       Y'   =  Yft (F(S2) * Y_[l

-------
                                      110
       The specific gravity corresponding to this yield and associated

xvashability data are found through linear extrapolation of the available

data.   Using equation 3.13 it can be verified that:

       SGj  =  1.97

       SG2  =  2.05

       SG3  =  2.18

The extrapolations are shown on the accompanying graphs (Figures 3.9 through

3.12).

Properties of the washed coals are:

Washer 1


                                                                   1
BTU(3"-l/4", 1.97) = {BTU(3",1.97)- BTU(1/4",1.97)[l



                   = [12300-12580(1.-0.535)] Q ^    = 12057 Btu/lb

SUL(3"-l/4", 1.97) = [1.375-1.18(1-0.535)]* 0.535 = 1.54%

ASl!(3"-l/4", 1.97) = [14.4 -11.6(1-0.535)]* 0.535 = 16.8%

Washer 2

BTU(l/4"-28mesh, 2.05) = {BTU(l/4",2.05)[l-F(l/4")]-BTU(0.0232)[1-F(0.0232)]}
                                                                        1
                                                              F(0.0232)

                                                      1
                       =  [12615(0. 465)-12425(0.1)]  Q  565  =  12667
SUL(l/4"-28mesh, 2.05) =  [1 . 20(0.465)-!. 12(0. 1)]     &5  »    1.22%
ASK(l/4"-28mesh, 2.05) =  [11. 9(0.465) -12.5(0. 1) ] TT-TF =   11.74%
                                                 U .

Washer 3

       BTU(28 mesh, 2. IS)   =   12225

       SUL(28 mesh, 2.18)   =   1.17

       ASH(2S mesh, 2.18)   =   13.8

Properties  of the  thermal  dryer  feed  stream:

-------
                                      Ill
                  {BTU(28mesh,2.1S)-Y'-[l-F(28raesh)]  +  BTU(l/4"-28mesh,2.05)
       Y'[1-F(S2J]
                   Y'-[F(28raesh)-F(l/4")]}
       0-92Q.0.535)

     =  12572
                     {12225(0.92)(1-0.9) + 12667(0.92)(0.9 - 0.535)}
SUL._ = ___L_  [1.17(0.92)(0.1)+ 1.22(0.92) (0.9-0.535)]  =   1.21*
   1    0.92(0.465)
ASH   =  2.34[13.8(0.092) + 11. 74 (0. 92) (0.365)]  =   12.20%

The properties of the dried coal are:
BTU16  =  BTU13 = 12572 Btu/lb  ASH16 =  ASH13  =   12.20%
                   (0.32) (4.0-106) (1-0.10) (0.193)
SUL16  =  SUL17;[1 f - =   1 22%
   16        -10             10800-2000


The prepared coal properties are:

BTU  d = {[1-0. 535] (12572) (0.92) (0.957)+ 12057 (0. 92) (0.535) } —•

       =  12313 Btu/lb
                                                            1
SULppd = { (0.465)(1.22)(0.92)(0.957) + 1 . 54 (0. 92) (0.555) } —

           1.40%

ASH   , = {0. 465(12. 2)(0.92)(0. 957) + 16. 8(0. 92) (0.535) } -^

       =  14.74%

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                  113
              APPENDIX C





COMPARISON OF PCC AND PARTIAL FGD DATA

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                  115
Table C.I  Data on PCC and Partial FGD
Plant
A
B
C
E
F
G
H
1
J
K
M
N
0
P
Q
R
S
T
U
V
1980
Emissions
#S02/MMBtu
5.41
5.13
4.22
4.40
4.41
5.10
8.22
6.44
2.65
6.49
5.77
8.16
6.87
3.45
5.47
4.78
3.36
6.02
5.08
4.42
Coal
Cleaning
Wt. Recovery
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
800
Coal
*S02/MMBtu
5.99
5.12
9.93
6.54
4.94
3.01
4.31
3.27
5.53
4.08
6.39
4.88
6.72
3.95
6.39
4.88
3.85
2.54
7.35
6.04
6.73
4.87
8.69
5.86
9.15
6.30
4.14
2.75
5.50
4.91
5.99
5.12
4.94
3.01
7.25
5.08
4.86
2.43
6.10
4.09
ZS
Reduction
14.6
34.1
39.2
24.1
26.2
23.7
41.2
23.7
34.1
17.7
27.6
32.6
31.1
33.5
10.6
14.6
39.2
29.9
50.0
33.0
Coal
Cost
$/MMBtu
1.501
2.098
1.508
2.109
1.512
2.110
1.512
2.115
1.500
2.091
1.499
2.087
1.500
2.090
1.499
2.087
1.481
2.053
1.487
2.063
1.542
2.159
1.317
1.930
1.317
1.937
1.504
2.094
1.500
2.099
1.501
2.098
1.512
2.110
1.530
2.147
1.495
2.082
1.317
1.932
PCC Cost
$/Ton S02
1366
355
616
1162
818
778
426
778
871
884
664
434
435
851
2057
1366
616
569
483
611
Equlv.
FGD Cost
S/Ton S02
525
731
1091
978
815
746
979
589
1294
594
754
674
699
1162
649
630
976
597
1231
854

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