xvEPA
United States     Industrial Environmental Research EPA-600/7-80-105
Environmental Protection  Laboratory         May 1980
Agency        Research Triangle Park NC 27711
Cost Benefits Associated
with the Use of Physically
Cleaned Coal

Interagency
Energy/Environment
R&D Program Report

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                 RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination  of traditional  grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment Reports  (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

This report has been assigned to the  INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND  DEVELOPMENT series. Reports in this series result from the
effort funded under  the 17-agency Federal Energy/Environment  Research and
Development Program. These studies  relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to  assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations  include analy-
ses of the transport  of energy-related pollutants and their health and ecological
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                       EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
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tion Service, Springfield, Virginia 22161.

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                         EPA-600/7-80-105

                                   May 1980
     Cost  Benefits
Associated  with the
  Use  of  Physically
     Cleaned Coal
        G A (Macs. R A Ress1
       and P VY Spaite (Consultant

       PEDCo Environmental In;
          PO Bo* 20337
         Dallas, Tenas 75220
        Conuaci No 68-02-2603
            Task No 31
      Prooram Element No EHE623A
    EPA Project Ofdcer James D Kilgroe

  Indusmai Environmental Research Laboratory
  ice o< Environmental Engineering and Technology
     Research Triangle Park NC 27711
            Prepared lor

 U S ENVIRONMENTAL PROTECTION AGENCY
    Office of Research and Development
         Washington. DC 20460

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1i

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                                   ABSTRACT


     This report identifies  and  quantifies several  benefits associated with
the use of physically cleaned coal in the operation of utility electric power
plants.  These benefits occur in three general areas:   coal  and ash handling,
boiler operation, and gas handling and cleaning.   The cleaning process removes
sulfur from the coal and thus reduces the emission of sulfur dioxide into the
atmosphere.   In most cases, however, the power plant must install  supplemental
control equipment to reduce emissions enough for compliance with environmental
regulations.   The cost of this supplemental equipment is less than the cost of
a control system for use with uncleaned coal, but the cost decrement is usual-
ly insufficient to offset coal cleaning costs.  However, the total of all of
the benefits addressed in this report exceeds the cost of cleaning the coal.
In a typical  case the cost of coal cleaning is $4.85 per ton of cleaned coal,
whereas  the  total  benefits associated  with the cleaning  of the  coal  are
$7.20 per ton  of cleaned coal.    This  report  recommends additional projects
aimed at quantifying coal cleaning benefits and presents an annotated biblio-
graphy of related studies.

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                                   CONTENTS
                                                                       Page
Figures                                                                  vi
Tables                                                                   vii
Abbreviations                                                          viii
Acknowledgements                                                         ix
Conversion Table                                                           x

1.   Introduction                                                          1

2.   Summary                                                               3

3.   Applicability Of Physical  Coal  Cleaning To U.S.  Coals                  7

          Process description                                              7
          Washability of U.S.  coals                                         8
          Cost of physical  coal  cleaning                                   9

4.   Economic Benefits                                                    18

          Cost savings in coal  and ash handling                           19
               Coal transportation                                        19
               Coal handling and storage                                  21
               Pulverizers                                                 22
               Ash collection and handling                                24
               Ash disposal                                               25
          Cost savings in boiler operation                                25
               Operating and maintenance cost reductions                  26
               Boiler availability                                        32
               Boiler efficiency                                          39
               Boiler capacity                                            42
               Boiler design                                              43
          Cost savings in exhaust gas handling and cleaning equipment     43
               Collection efficiency of pollution control equipment       43
               FGD requirements                                           45

5.   Conclusions and Recommendations For Further Work                     49
          Conclusions                                                     49
          Recommendations for further work                                 50
               Calculation of benefits based on published data             50
               Coal appraisal research                                     50
               Research to verify effects of coal quality on boiler
                 operation                                                 51
               Boiler derating  study                                       51

                                      iv

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                              CONTENTS (continued)
References

Appendices

Appendix A

         B

         C


         D

         E
Literature review

Cost estimates For FGD and PCC

Calculation of revenue requirements to capitalize
  additional boiler capacity

Regression study - TVA forced outages

Calculations of boiler efficiency improvement as a
  result of PCC
  •
Sample calculations on ESP performance for raw and
  washed coal
Page

  52



  54

  77


  97

  99


 110


 113

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                                      FIGURES


Number                                                                    Page

  1       Energy Available in Northern Appalachian Reserve Base as  a
            Function of Various Physical  Coal Cleaning Levels  and
            Emission Standards                                               8

 2        Annual Incremental  Cost of Operating a PCC/FGD System at  a
           500-MW Plant Under Various S0? Regulations; Sulfur  Content
           of Raw Coal  = 2.5  Percent                                        14

 3        Annual Incremental  Cost of Operating a PCC/FGD System at  a
           500-MW Plant Under Various S0? Regulations; Sulfur  Content
           of Raw Coal  =3.5  Percent                                        15

 4        Annual Incremental  Cost of Operating a PCC/FGD System at  a
           500-MW Plant Under Various S02 Regulations; Sulfur  Content
           of Raw Coal  =5.0  Percent                                        16

 5        Relationships of Fuel-Related Boiler Maintenance Costs to
            Tons of Ash-Plus-Sulfur Fired into the Boiler                   33

 6        Annual Forced Outage Rates as a Function of Coal Ash Content      35

 7        Yearly Operating Availability for Fossil Coal-Fired  Units 400 MW
            and Above                                                       37

 8        Effect of PCC Sulfur Removal Efficiency on Allowable FGD  Bypass
            at Various  SOp Removal Regulations                              47
                                      vi

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                                    TABLES


Number                                                                    Page

  1       Summary of Coal  Cleaning Benefits for Existing Boilers              4

  2       Costs of Physical  Coal  Cleaning System at Level  2  Plants  of
            Various Capacities                                               9

  3       Coal Preparation and Performance Factors                          11

  4       Total Annual Costs for Eight Coal Preparation Plants              12

  5       Weight Yields of Washed Coal at 90 Percent Btu Recovery           20

  6       Itemized TVA Boiler Maintenance Costs, John Sevier Plant          27

  7       Itemized TVA Boiler Maintenance Costs, Kingston Plant             28

  8       Total Boiler Maintenance Costs and Fuel-Related Boiler Main-
            tenance Costs for Selected TVA Plants                           29

  9       Cost Breakdown for Selected Coal-Fired Electric Generating
            Plants with Average Boiler Size Of 200 MW or Larger             30

 10       Component and Composite Forced Outage Rates and Availability for
            Fossil-Fuel-Units:  1967-1976                                   36

 11       Typical Boiler Efficiency Losses                                  40

 12       Efficiency for Raw and Cleaned Coal                               41

 13       Comparison of ESP Requirements for Boilers Burning Raw and
            Cleaned Coal                                                    44

 14       FGD Costs for Raw and Cleaned Coal Systems                        46

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                                 ABBREVIATIONS

A+S   The Sum Of The Ash and Sulfur Percentages In A Coal
EPA   U.S.  Environmental Protection Agency
EPRI  Electric Power Research Institute

ESP   Electrostatic Precipitator
FGD   Flue Gas Desulfurization
O&M   Operation and Maintenance
PCC   Physical Coal Cleaning
SCA   Specific Collection Area
TVA   Tennessee Valley Authority
                                     vm

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                                ACKNOWLEDGMENTS
     This report was prepared for the Industrial Environmental Research Labor-
atory of the U.S.  Environmental Protection Agency by PEDCo Environmental,
Inc., Cincinnati,  Ohio.   The Project Director was Mr. Timothy W.  Devitt.
Principal authors  were Dr. Gerald A. Isaacs, Project Manager, Mr. Paul
W. Spaite, and Mr. Robert A. Ressl.

     This report utilizes several reports that have been prepared under funds
through the EPA-Interagency Coal Cleaning Program.  In addition,  generous
quantities of data have been provided by the staff of the Tennessee Valley
Authority, and the authors express appreciation for the cooperation shown by
that agency.

     The authors also wish to acknowledge the cooperation and assistance of
Mr. James D. Kilgroe,  Project Officer for the U.S. Environmental Protection
Agency, in preparation of this report.  Dr. Constancio F. Miranda also as-
sisted in review of this report for the U.S. Environmental Protection Agency.
                                       IX

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                                CONVERSION TABLE
     English units are used extensively in this report.   Equivalent Systeme
International d1  Units (S.I.) are as follows:

     meter (m)      =    3.281 feet
     kilogram (kg)  =    2.205 pounds
     joule (J)      =    9.47 x 10~4 Btu

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                                   SECTION 1

                                 INTRODUCTION
     Physical  coal  cleaning  is  a well-developed  technology  that has  been
used for many  years.   Relatively simple systems are used to remove ash from
coal  burned  for  power  generation,  and  more  complex  systems  have  been
developed to remove ash and sulfur from coking coals.

     Since the mid-1960's the U.S. Environmental Protection Agency (EPA) has
supported work to demonstrate the usefulness of PCC  in  reducing  air pollu-
tion caused  by combustion  of coal.   Special attention was given  to possi-
bilities for cor;tj"
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     This  report  is  concerned with the latter two options, i.e.,  with cases
where  coal quality  is  inadequate for  compliance  with S02  regulations,  so
that a full or partial FGD system is required.

     A  principal   preliminary  effort   of  this  project  was  the  review  of
pertinent  literature,  as detailed  in  Appendix A.   It was anticipated that
information from  the open literature and accessible expert opinion might be
scarce and that  good  data  would be  lacking in several areas.   Where this
problem was  encountered, the  report presents the  available pertinent data
with comment on data quality.

     The investigation has  shown that  the relationship between coal quality
and boiler performance  is poorly defined, despite  a  considerable  amount of
available  information; hence  some of the impacts associated with  changes in
coal that  occur as a result of PCC cannot be assessed in terms of  impacts on
boiler operation alone.   Some changes in boiler performance that result from
PCC must be  assessed in the light of total impact on the generating system.
These considerations have led to some new perspectives and to better defini-
tion of the need for additional information.

     Many  of the  benefits to be discussed are subtle and  may lead to rela-
tively small charges in  overall performance.  These small  changes may still
be  significant,  however, and  they  may help  to  justify the use  of  PCC in
specific  situations.  We  attempted,  therefore,  to recognize  all  possible
savings and to  estimate  their relative importance, and  at the same time to
avoid any  double-counting of benefits.   Further studies will be needed for a
more accurate determination of many of these potential cost benefits.

     The  impact of  PCC   on  coal to  be  burned  in either new or  existing
boilers was  assessed on  the  basis of  available information.   Quantitative
comparisons were  seldom  possible.   Where data were available,  the analyses
were complicated  by  the  different approaches to cost  estimation  in various
studies.    We did  not attempt to judge  the merits of differing approaches or
to  normalize  the  data but  rather to determine where  future  efforts  can be
applied most fruitfully.

     Section 3 describes and categorizes various  coal  cleaning processes and
briefly discusses the U.S.  coals in terms of relative washability.  Section
3 also indicates  typical  costs of coal cleaning plants  to provide perspec-
tive  for  the   subsequent discussion  of  PCC benefits.   In  Section  4  the
various PCC benefits to the utility industry are  discussed in terms of three
functional   areas:   coal  and  ash  handling, boiler operations,  and  gas
cleaning.    Each  potential   benefit  for  a  typical  boiler  operation  is
estimated on the basis of assumed coal  properties and washability data for a
selected "standard"  coal.   For  each  benefit,  a   range  of values  is also
estimated.   Section  5 outlines  additional  projects that are recommended for
more precise definition of the cost benefits associated with PCC.

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                                  SECTION 2

                                   SUMMARY
     Physical  coal  cleaning (PCC) is  an available technology  that  can be
used now  to improve  fuel  quality and to minimize the environmental conse-
quences associated  with the burning of  coal.  Unfortunately,  institutional
barriers and a  lack of  appreciation  of  all of the benefits  associated with
the application  of  coal cleaning have retarded  adoption of the technology
for use in pollution control.

     This  study  is  one  of  the first efforts to  identify  fully and to quan-
tify the benefits associated  with the use of cleaned  coal.  These benefits
are discussed,  with  quantitative estimates  of  cost  benefits  that  may be
derived  from  coal   cleaning.    A  hypothetical,   standard  coal  that   is
moderately  washable was used  as  a  basis  for our estimates,  i.e. ,  a  coal
whose ash content could be reduced from 20 percent to 10 percent  and whose
sulfur  content   could  be  reduced  from _3,5. percent,  t&	2.4 percent.    The
magnitude  of  potential  savings is  heavily dependent on  the amounts of  ash
and sulfur  that  can be  removed; we  have  attempted  to make  conservative
estimates  in this regard.   It should be noted,  however,  that  reliable  data
relative to some  of the benefit  values  are  sparse or  unavailable,  particu-
larly data that would support estimates of the range  of benefits; hence  some
of the indicated benefit values were determined subjectively.  Nevertheless,
we  attempted  in all  cases  to obtain the best information available and to
make realistic judgments.

     Several  significant  benefits have been identified  for each of  three
distinct operations:

     0    Coal and ash handling

     0    Boiler operation

     0    Gas cleaning

     Table 1 shows  results of  our benefit  analysis  in  terms  of  estimated
savings that  would  be  realized  in  each of the principal areas by burning
physically cleaned  coal  in an existing  power plant.   The greatest potential
benefit is  related  to gas cleaning.   Coal cleaning might also affect parti-
culate  control   requirements,  but essentially all  savings  in gas cleaning
operations are  attributed  to a permissible reduction  in  flue  gas desulfuri-
zation  (FGD)  requirements as  a  result  of using cleaned coal.   In extreme
cases where coal cleanability is  adequate to eliminate the need  for flue gas

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 desulfurization altogether, this single benefit may range up to about $11.00
 per  ton  of  cleaned  coal.   Typically,  the  gas  cleaning benefits would  be
 about  $4.00 per  ton  of  cleaned  coal,  where  coal  cleaning  reduces  FGD
 requirements  but does  not  completely  eliminate the  need  for a  scrubber.

           TABLE  1.   SUMMARY OF PCC BENEFITS FOR EXISTING BOILERS
Benefit area
Coal and ash handling
Coal transportation
Coal handling and storage
Pulverizers
Ash collection and handling
Ash disposal
Boiler operation
Operating and maintenance
Availability
Efficiency
Capac-ty
Gas cleaning
Particulate control
FGD systems
Total
(Dollars per ton of cleaned coal)
Typical Range
0.70
a
0.00
a
0.10
0.40
1.90
0.10
0.00
a
4.00
7.20
0.10 - 1.50
b
0.00 - 4.50
b
0.00 - 0.25
0.10 - 2.00
0.30 - 5.10
0.05 - 0.25
0.00 - 9.00
a
0.00 - 11.00

              alnsignificant for existing plants.

               Not determined.

     The  next most  important category  of  benefits  is  related to  boiler
operation.   Typical   benefits,   in  order  of  decreasing significance,  are
boiler  availability  improvement, a  reduction  of operating  and maintenance
requirements, improved efficiency,  and  increased capacity.   Savings associ-
ated with  any increase  in boiler capacity and in boiler availability can be
very  large.   Where boilers  have been derated  because  of  ash slagging and
fouling  or where  availability  is  poor  because of  low quality coal,  the
estimated  savings  can be as  high  as $9.00 per  ton of  cleaned coal.   These
savings are  calculated on the assumption that half of the power that cannot
be generated  because  of  boiler unavailability must be  replaced,  an assump-
tion suggested by  a  major utility.   For the capacity savings estimate it is
assumed  that an   investment  in replacement capacity  would  be  necessary.
Although these benefits  can  be great, they  would  be  realized only at sites
with  abnormal  operating  conditions  that  have  resulted   in derating  of
existing generating units.
     Coal and  ash handling benefits  as  a
erally small in magnitude.   They include:
result of coal  cleaning  are gen-

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    0    Reductions  in  coal  transportation  costs  as  a  result  of the
         increased thermal  content per ton of coal.

    0    Reductions in coal handling and storage  costs.

    0    Reductions  in  pulverization  costs  because of  the removal of
         hard abrasive impurities from the coal.

    0    Reductions in ash collection and handling costs.

    0    Reduction in ash disposal facility requirements.

     Although  the  main  thrust of  this  investigation  deals with  existing
plants,  possible  savings  in  design  of  a  new plant to  burn cleaned coal
rather than raw coal are discussed for each benefit category.   Such  benefits
would  be  substantial, possibly  exceeding those  that could be realized  in
existing  plants.   Total  benefits  shown  in  Column 1  of Table 1 typically
amount to  more than  $7.00  per ton of cleaned coal.  This  benefit  compares
favorably with the  cost  of coal cleaning.  For  example,  one  study  of  eight
coal  cleaning  plants has  shown an average coal  cleaning cost of $5.73  per
ton and a range from $4.40 to $8.41 per ton of cleaned  coal.

     We  have  analyzed several  situations where  coal  cleaning is used as  a
supplement to  FGD  in order to determine  the  economic effect  on  the capital
and  operating  costs  of  the FGD system.  The analytical  matrix  consists of
three  typical  regulatory levels, coals with  three  different  sulfur levels,
and  three  assumed  levels of coal cleanability.  Our estimated cost of coal
cleaning ranges from $5.95 to $7.39 per  ton  of  cleaned  coal,  including the
cost of coal rejected in the cleaning process.  Reductions in FGD costs as a
result of  coal cleaning  range from an equivalent of $3.24 to $11.09 per ton
of  cleaned  coal.   Thus,  in certain cases the  reductions  in FGD  costs alone
may  be sufficient to  justify coal cleaning.  Relative  FGD cost reductions
that  result  from  coal cleaning are dependent upon  the  specific  regulations
that   must   be  met.    Where  S02  emission  regulations  are  particularly
stringent,  the  FGD-related cost  benefits may not  be  sufficient  to justify
the  use  of  coal  cleaning,  unless cost-benefits  related  to  boiler operation
and  to coal  and  ash handling  are  very high.   Thus, in each case all of the
accounted-for benefits must be aggregated to determine whether cleaned coal
should be burned at a particular power plant.

     In  conclusion,  available data show  that PCC has a potential to produce
great  benefits in  terms  of reduced costs  for power production and environ-
mental  control.   The  most  important economic  benefits  of PCC  are boiler
operability  improvements  associated  with upgraded  quality.   Unfortunately
these  benefits are  difficult  to document.   Additional  work is  needed to
develop  a  better  understanding of the  effects of PCC  on the costs of power
production  and  environmental  control.   Until   site-specific  studies  are
undertaken to determine  savings which  can be realized by  using cleaned coal,
it  seems  unlikely  that  utilities  will  show significant  interest in  coal
cleaning.

     Further studies  should be  undertaken to demonstrate  the potential bene-
fits which  would  result if PCC  is more widely applied.   The results of  such

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studies may provide a rational basis for further governmental effort to sup-
port  the  accelerated use of PCC.   In  the  meantime, it is  felt  that  a more
widespread application  of  coal  cleaning technology seems to be economically
justified.  This  conclusion needs  to  be confirmed by  additional  work that
will  provide  a more  accurate  and reliable measure of  these potential coal
cleaning cost benefits.

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                                   SECTION  3

             APPLICABILITY OF PHYSICAL  COAL CLEANING TO U.S. COALS
3.1  PROCESS DESCRIPTION

     All  PCC systems use  equipment  that segregates  mixed  input materials of
different specific gravities  into separate  output streams.  Various degrees
of  size  reduction  are used  in isolating  materials  of different specific
gravities.   Because of  the  large  differences  in specific gravities of car-
bonaceous coal  materials  (1.5)  and the  associated  materials  to be removed
(noncombustible  minerals,  2.5;  pyrite, 5.0),  such  approaches  are very
effective where the individual  components can be  readily  isolated  from each
other.

     At  present 400 to 500  PCC  plants  are  in operation.  About  400 million
tons of  coal  per year  are  given  some level  of  physical  cleaning.   The
cleaning systems  vary  considerably in  complexity as a function of product
requirements and cleanability of the coal.

     Different  levels  of  cleaning  have  been defined as typical of systems
used to  upgrade  coal   (Kilgroe 1979;  and  Spaite 1979).  Generalization  in
this connection is difficult,  but  the higher  levels  of cleaning usually
involve more processing steps.   Four  recognized levels of coal  washing  are
as follows  (Kilgroe 1979):

    Level 1 - Beneficiation or washing of coarse coal, in which the coal
    particles  greater  than  about  3/8  inch  are treated  and  recombined
    with unwashed finer materials to form the product.

    Level 2 -  Beneficiation of  coarse  (+  3/8 inch)  and  fine  coal (3/8
    inch x 28  mesh) fractions.   The very fine (28 mesh x 0) material  is
    dewatered and either shipped as  product  or discarded.

    Level 3  -  Beneficiation   of   the  coarse,  fine,  and  very  fine
    fractions.   The moisture  content  of fine and very fine fractions  is
    usually limited by drying.

    Level 4 - Full beneficiation of all fractions.  This level of clean-
    ing  is practiced for  optimal  ash and sulfur  reduction.   It may  in-
    volve crushing  the coal  to finer  sizes  and producing a  number  of
    coal  products, each with a different ash and sulfur content.

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                   — RAW COAl
                   • PCC. 1-1 1/2 in. 1.ISG
                   • PCC. 3/8 MI. l.ior 13 SO
                   A S0% PVWTIC SULFUR REMOVED
in
•o
•o
3
cr
CD
                  TOTAL QUADS Of RAW COAL - 172S 37
   The  impact of various levels of cleaning  is  Illustrated  in Figure 1,  which
   shows  the energy  available  in northern Appalachian coals  as a  function  of
   different  levels of PCC and emission standards (Kilgroe 1979).
    1700


    1500


    1300


    1100


     900


     700


     500


     300


     TOO
                       1.0
                      EMISSION  STANDARD,  Ib S02/106BTU
   Figure 1.   Energy available  in  northern  Appalachian  reserve  base  as  a  function
          of  various  physical   coal  cleaning  levels  and  emission  standards.
   3.2  WASHABILITY OF U.S.  COALS
        The washability
   U.S.  Bureau of Mines.
   the  coal   now  being
   evaluate washability
                      of  U.S.  coals has been  studied  by the EPA and  by  the
                       More  than 455 coals representing over  70 percent of
                      burned  by  utilities  have  been  laboratory  tested  to
                      by methods  based on  differences in  specific  gravity
(Cavallaro 1976).  Data  from  these tests  have been analyzed  extensively in
numerous studies aimed at  predicting  the  extent to which PCC can be used to
permit burning of high-sulfur coals in compliance with present and projected
standards  for S02 emissions.   Although  many  coals show  good washability,
there are  few in which  sulfur  content can be reduced sufficiently  to meet
                                        8

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present standards without supplemental  controls.   Furthermore, many of those
that  could  be washed  to meet the  1971 standard  (which  was not effective
until 1979) are  located  in the West, remote from  markets  for utility coal.
A recent Battelle study (Hall 1979)  indicates the following:

    0    Nine percent of the U.S.  coal  reserves having sulfur levels
         that would give emissions in excess of the 1971 New  Source
         Performance Standard for coal-fired boilers (1.2  Ib  S02/million
         Btu when burned) would meet the standard after physical  clean-
         ing.

    0    For western coals, washing would upgrade about 15 percent of
         the reserves to meet the 1971 standards.

    0    For coals from the northern Appalachian, southern Appalachian,
         eastern Midwest, and western Midwest regions, washing would
         upgrade 6, 10, 2, and 1 percent, respectively, to meet  the 1971
         standard.

Outside the western  region the percentages that can be upgraded to meet  the
1971  standards  are  low.   More stringent  standards  (i.e., 70 to 90  percent
S02  removal)  would virtually  eliminate  the  use  of PCC as a sole method of
compliance.    This fact,  however,  is  not  as  significant as  it may  seem,
because removal  of sulfur  is  only  one  of the benefits to be realized  from
PCC.
3.3  COST OF PHYSICAL COAL CLEANING

     The costs  of  PCC at different levels  of  cleaning are highly variable.
For a  simple  plant built for Level 1 cleaning,  a capital cost of $6000 per
ton per  hour  of capacity has been  reported (Holt 1978).   For a multistream
plant  designed  for Level  4  cleaning,  a capital  cost  of $42,000 per ton per
hour of  capacity  is  reported (McGraw 1977).  Costs  of  coal  cleaning have
been calculated also by  use  of  a PEDCo computer  program in  which a three-
circuit  plant,  cleaning  to  Level 2, is assumed.   Annual  costs are affected
considerably by plant capacity.   Table 2 shows  the  resultant PCC costs for
plants at  capacities  ranging from 400 to 3200 tons/h  that would supply coal
for one  to eight 500 MW boilers.
                    TABLE 2.   COSTS OF PHYSICAL COAL CLEANING AT
                        LEVEL 2 PLANTS OF VARIOUS CAPACITIES
Capacity,
tons/h
400
1200
1600
2000
3200
No. of
500-MW
boilers
served
1
3
4
5
8
Capital
cost,
$/kW
20.2
14.4
13.4
12.7
11.9
Annual cost
mills/kWh
2.7
2.2
2.1
2.0
2.0
$/ton of
cleaned coal
6.53
5.30
5.09
4.92
4.73

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     The values are based on characteristics of a standard coal  that  is  used
throughout this  report,  i.e.,  raw coal with a heating value (HAV)  of 10,670
Btu/lb,  20 percent  ash,  and  3.5  percent  sulfur.   It  is  assumed that  this
coal can be cleaned at 90 percent Btu recovery to yield 80 percent  by weight
of a coal with HAV of 12,000 Btu/lb, 10 percent ash,  and 2.4 percent  sulfur.
The  500-MW  boiler is  assumed to operate  at a 70 percent  capacity  factor.

     Table 2  shows  a  considerable  economy  of  scale in  a  PCC plant  large
enough to service three  boilers  instead of one.  The cost  drops from $6.53
to  $5.30 per ton of  cleaned  coal,  or 19 percent.  Larger plants  show  even
greater economies of scale, but the  improvements are  less pronounced.   Total
coal cleaning  cost  at the plant servicing  eight boilers  is  90 percent  of
that at the plant servicing three boilers.

     As  a  basis for  comparison we  include results  of a  recent  analysis  of
reported costs for eight plants classified as simple,  intermediate, and com-
plex  (Hall  1979).    Results  of  that  study  are  shown   in  Table  3   (plant
description and performance factors) and Table 4 (cost factors).  These data
provide  a  perspective for assessment  of cost  levels and cost variability;
the  data also illustrate  the  variation in relative costs  depending  on the
method of presenting  annual  costs.   The performance factors of  Table 3 are
consistent with assumptions cited in Section 4 of this report for estimation
of  benefits.   For  the  eight  plants  in Table  3, the total cleaning costs
range from $4.40  to  $8.41  per ton of cleaned coal,  averaging $4.85 per ton.
The analysis in Section 4 shows that the total benefits of coal cleaning are
typically of the same magnitude and  that in some cases the benefits substan-
tially exceed the cleaning costs.

     Annual  costs include  capital recovery costs, operating and maintenance
(O&M) costs,  and the  cost of replacing  the coal rejected  by the cleaning
plant.    This replacement cost  can be substantial.  For example, if raw coal
at $1.00 per million Btu ($21.34 per ton) is burned in a boiler, 93.75 Ib of
coal must  be dug to  produce a million Btu.   If  the coal  is  cleaned at an
80 percent weight yield  with  90  percent Btu recovery then  the amount to be
dug is

        93.75 Ib x 100/90 = 104.16 Ib.

The  cost of  this extra  10.41 Ib  of  coal  must  be  borne  as part  of the
cleaning  operation.    The  cost  is  $0.11 per  million  Btu,   equivalent  to
1.11 mills per kWh or  $2.67 per  ton of cleaned coal;  this  is  about half of
the  coal  cleaning cost  of the 1200-tons/h plant.  It  is apparent that the
cost of  coal  cleaning is affected substantially by the operating efficiency
of the cleaning plant.

     The costs of coal  cleaning  and the potential benefits should be evalu-
ated within the  context  of the costs/benefits of FGD systems used alone and
of systems combining  PCC and FGD.  In general, removing  sulfur from  coal by
PCC  is  more  economical  than  scrubbing  it from  boiler exhaust  gas.   The
capability  for  sulfur  removal by  PCC,  however, is  only  about  30 to 40
percent  for most  coals,  significantly lower than that of FGD systems, which
have demonstrated  S02 removal efficiencies  above 90 percent.   Furthermore,
                                     10

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                TABLE  3.  COAL PREPARATION  PLANTS AND PERFORMANCE FACTORS (HOLT  1978)
Plant
No.
1
2
3
4
5
6
7
8
Process
Jig
Jig
Jig
Jig
Dense
medium
Dense
medium
Dense
medium
Dense
| medium
Raw coal
capacity,
ton/h
600
1,000
1,000
1,600
1,400
(720)D
600
600
900
Complex-
ity
Simple
Inter-
mediate
Inter-
mediate
Complex
Simple
Complex
Complex
Complex
Estimated
capital
investment,
$ x 103
(mid-1977)
3,946
13,681
12.084
22,886
9,962
13,449
8,420
20,916
Btu
recovery,
%
91.6
96.4
83.0
93.7
94.6
89.2
93.1
94.1
Weight
yield,
%
59.0
71.4
56.6
59.6
74.0
73.3
60.0
86.0
Clean
coal
moisture
content,
%
8-9
6.9
4.6
5.8
7.5
5.0
4.9
5.0
Ash
removal ,
lb/tona
651
472
606
678
260
338
660
145
Sulfur
removal ,
lb/tona
3.7
23.3
27.7
9.0
29.5
55.2
6.3
18.0
Lb removed per ton of raw coal processed.
680 tons/h of raw coal is not processed by the cleaning plant.

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        TABLE 4.  TOTAL ANNUAL COSTS FOR EIGHT COAL PREPARATION PLANTS (HOLT  1978)
Plant
No.
1
2
3
4
5C
6
7
8
O&M
cost,3
$/ton of
cleaned
coal
2.70
2.55
2.67
2.96
3.20
3.04
2.12
2.44
Capital .
charges,
$/ton of
cleaned
coal
0.65
1.12
1.25
1.40
0.56
1.79
1.36
0.94d
Cost of
Btu loss,
$/ton of
cleaned
coal
2.14
0.75
4.49
1.60
1.10
2.21
1.76
1.02
Total
cost,
$/ton of
cleaned
coal
5.49
4.42
8.41
5.96
4.86
7.04
5.24
4.40
Total annual cost,
$/100 Btu
recovered
0.227
0.183
0.338
0.222
0.239
0.258
0.206
0.176
$/ton of
ash removed
9.92
13.39
15.71
10.47
27.69
30.53
9.55
52.28
$/ton of
sulfur removed
1,746
271
344
789
244
187
1,000
421
Operating and maintenance (O&M) cost includes labor, supervision, overhead,  supplies,  fuel,
 electricity, and subcontract services.
bBased on a 10-year amortization period, 9 percent discount rate,  and 30 per-
 cent utilization factor, except as noted.
cCosts shown for Plant No. 5 are based on 1400 tons/h.
 Fifty percent utilization factor.

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because  regulations  typically  require  abatement  of  70 to  90 percent  of
potential S02 emissions,  the use of PCC alone  generally is not sufficient to
achieve compliance; auxiliary scrubbing  of  at least part of the exhaust gas
from a boiler is necessary even  when cleaned coal  is burned.  Thus, although
FGD can  almost always be  used  as  a sole means  of control,  coal cleaning
cannot, and usually must  be combined with FGD  to achieve compliance.

     Because coal cleaning  does  remove part of the sulfur from  coal, firing
of  cleaned  coal reduces  the cost  of the FGD  system needed to meet control
requirements.   To  illustrate this  effect,  we  performed  a  parametric cost
study comparing FGD as a sole control measure with systems that  combine FGD
and  PCC.   The  study,  described  in  detail in Appendix  B,  considers  three
postulated S02  regulations,  three  coals  with  different sulfur contents, and
three levels of sulfur removal  by  PCC.  In each case  the  use of  PCC reduces
FGD requirements  (and  costs) below  those  of  an FGD system used  alone, for
the following reasons:

    Less  scrubbing  of  exhaust  gas  is needed  at a  given  scrubber effi-
    ciency because coal  cleaning  removes part of the sulfur that would
    otherwise have to be  scrubbed.

    Exhaust gas Thaf. does not have to be scrubbed can  be  used  to provide
    part  or all  c*i  the  FGD gas  reheat  needed to promote  atmospheric
    dispersion and suppress plume formation.

    Because  coal  cleaning  reduces the  variability of  coal  quality,  a
    relatively  less  conservative  scrubber  design  can be used  to meet
    limits for maximum emission levels on a 30-day average.

     Results of this  study are  shown in Figures 2, 3, and 4,  and are summa-
rized  briefly  here.   Figure 2  shows that with  raw coal  having 2.5 percent
sulfur,  either  FGD  or  PCC can be  used alone  to comply with a regulation of
2.6 Ib S02 per million Btu.  In this  case coal cleaning costs less than FGD,
and  the  savings  is about $2.55 per  ton  of  cleaned coal.   For  the more
stringent  regulations,  1.2 Ib  S02  per  million  Btu  and  85 percent  S02
removal,  incremental costs are  associated with the use of a combined  system
over  those  of an  FGD  system  alone.   The  cost  increment  decreases with
increasing  degree  of  sulfur removal  by PCC.  For the 85 percent  regulation,
the  cost decreases from  $1.70  to  $1.60 per  ton  as  the  PCC  sulfur removal
increases from  30 to 50 percent.

     Figure  3 shows relationships  for 3.5 percent sulfur coal.   In this case
the costs of removing 85 percent of  the  S02 are nearly identical  to those of
limiting  emissions  to  1.2 Ib S02 per million Btu.   Under an emission limit
of  2.6  Ib S02  per million Btu,  no FGD system is required if PCC  can  remove
50  percent of the sulfur.  At 40 percent  sulfur removal by PCC,  the combina-
tion  system  is  more cost-effective  than  FGD  alone  by about $1.45 per  ton of
cleaned  coal;  however,  at 30 percent sulfur  removal  by  PCC the  combination
system  costs $2.25 more  per ton of  cleaned  coal  than  an FGD system  alone.

     Figure  4  depicts  the effects of input coal  with 5 percent  sulfur.   For
this  coal an 85 percent  regulation  is less restrictive than a  regulation of
                                      13

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           3 -i-
       13
       o
       u

       c
       ts
       QJ
       o   1 --
       C
       O
       OJ
           0 --
      -g  -1
          -2 --
         -4
                                                 85% S02 REMOVAL
                          1.2 LB  S02/10S  Btu
                                        2.6  LB S02/10S  Btu
                     10
20
30
40
                                                        50
                      S02 REDUCTION  BY PCC,  percent
Figure  2.   Annual incremental  cost  of  operating a PCC-FGD system  at a 500-MW
plant under various  S02 regulations;  sulfur content of raw coal =2.5 percent.

-------
    o
    o
    c
    ro
    OJ
    c
    o
    s_
    0,'
    1/1
    o
        2 --
        -3
        -4
                                               85% S02 REMOVAL
                                                 2.6 LB S02

                                                  PER  10E  Btu
                NO  FGD
                REQUIRED
                    10
20
30
40
50
                     SO, REDUCTION BY  PCC, percent
Figure  3.   Annual  incremental  cost  of  operating a PCC-FGD system at a  500-MW
plant under various S02 regulations; sulfur content of  raw coal = 3.5 percent.
                                   15

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      fO
      O
      u

      c
      fO
      01

      u
      c
      O
      QJ
      O.

      in
      U
      ID
      in
      O
      O
2 --
0 --
         -3 --
         -4
                          2.6 LB  S02/106  Btu
           1.2 LB  S02/10S  Btu
                     10
                   20
30
40
50
                      S02 REDUCTION  BY PCC,  percent
Figure 4.   Annual  incremental cost of operating  a  PCC-FGD  system at a 500-MW
plant under various S02  regulations; sulfur  content of raw coal = 5.0 percent.
                                   16

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1.2 1b S02 per million Btu; only where the regulation is  2.6  Ib  S02 per mil-
lion Btu  and 50 percent  of  the sulfur  1s  removed by coal cleaning is  the
combination  system  more   cost-effective  than the  FGD  system  alone,  with
savings of about $0.70 per ton of cleaned coal.

     In summary, where  PCC is used as an adjunct  to FGD,  the cost benefits
increase  with  increasing percentage  of  sulfur  removal  in  the cleaning
process (at a given Btu recovery level).   Restrictive S02 regulations reduce
the cost  effectiveness  of PCC.   In the cases studied, most  of  the combina-
tion PCC-FGD  systems are  more  costly than  FGD systems alone,  and the cost
diffentials range  up  to about $2.70 per ton.  In  such cases  the use of  PCC
in  conjunction  with FGD would  be  cost-effective  only  where  additional
benefits  of  corresponding magnitude could be identified.  These additional
benefits associated with the use of PCC are discussed in  Section 4.
                                      17

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                                   SECTION 4

                               ECONOMIC BENEFITS
     The several  economic  benefits  to the utility industry that are associ-
ated with  PCC  can be categorized with respect  to  three  functional  areas  of
the power plant:

    1.    Coal and ash handling
              Coal transportation
              Coal handling and storage
              Pulverization
              Ash collection and handling
              Ash disposal

    2.    Boiler operation
              0 & M
              Boiler availability
              Boiler efficiency
              Boiler capacity

    3.    Exhaust gas handling and cleaning equipment
              Performance of particulate collection equipment
              Costs of FGD  systems

     Our assessment  of  the value of the benefits of PCC in these categories
is  based on  equivalent costs  to  the  utility  that would  be  incurred  to
achieve  the  same benefit  by  some  means  other than  coal  cleaning.   For
example, the  value  of increased boiler availability is taken to be the cost
of boiler  unavailability,  in terms  of generating or purchasing the replace-
ment power.   The assessment  effort included discussions  with many persons
actively involved in power  generation and coal preparation.  Additionally, a
massive  quantity of  literature was  reviewed;   the literature  sources  are
given,  with annotation, in  Appendix A.

     As  a  basis for estimating coal  cleaning benefits,  several assumptions
were made  regarding  coal   quality,  PCC  plant  and boiler  performance,  FGD
system performance, and costs:

    0    Raw coal has a heat value of 10,670 Btu/lb, 20 percent ash, and
         3.5 percent sulfur.

    0    Cost of raw coal is $1.00 per million Btu  ($21.34/ton).
                                     18

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    0    Cleaned coal  has  a heating value of 12,000 Btu/lb, 10 percent
         ash,  and  2.4 percent  sulfur,  representing a  Btu  recovery of
         90 percent and a weight yield  of 80  percent for the PCC plant.

    0    Net heat rate of the boiler is  10,000 Btu/kWh.

     Throughout  this report  the benefit values  are  expressed in dollars per
ton of cleaned coal.   Since a ton  of cleaned coal  contains 24 million Btu, a
benefit of $1.00 per  ton  (1000  mills/ton) of  cleaned coal for a boiler with
a heat rate of 10,000 Btu per kWh  is equivalent  to

        1000 mills/ton x 10,000 Btu/kWh T 24  x  106  Btu/ton  = 0.42 mill/kWh.

This conversion  is used occasionally in  our analysis.

     We  identify  the  expected  benefits  in   a  categorical  and qualitative
fashion and attempt  also  to estimate a  quantitative range.  This assessment
provides a  basis  for  estimating  a cost  range  over which  coal cleaning  is
cost-effective.


4.1  COST SAVING:," IN COAL AND ASH  HANDLING

     Physical  coal cleaning  changes characteristics of the  coal  and reduces
the  quantities  that  are  moved to  the power plant and  into  the boilers;  PCC
also  affects  the properties  and  quantities  of refuse  generated in burning
the  coal.  These effects are discussed in detail below.

4.1.1  Coal Transportation

     A direct savings  in  coal transportation costs occurs  when  a  PCC plant
is  installed  at or near a  coal mine,  because the  ash  that is  removed from
the  coal need  not be transported.   Table  5 shows weight  yields  from PCC of
coals for which we have determined washability characteristics; all of these
coals were cleaned to a level of 90 percent Btu recovery.

     Because these  coals  were mainly from Kentucky and Tennessee,  they may
not  be  typical  of all U.S.  coals.   Nevertheless, the  weight  yields seem to
be  typical  of washed bituminuous coals,  ranging  from  72.7  to 85.8 percent;
this  suggests  that  a  PCC  plant would  produce cleaned coal  weighing 81 to
95 percent (72.7/0.90 to 85.8/0.90) as  much as the  corresponding raw coal on
a  unit  Btu  basis.   Thus the  potential  transportation  savings  would be 5 to
19 percent.  Based  on the  mean weight  yield  of 79.8 percent,  the  potential
savings would be 11 percent  (100 -  79.8/0.90).

     Coal  transportation  costs are highly site-specific.   Railroads derive
more revenue  from coal than  from  any  other  commodity.   Although there is a
governing Uniform ICC  Freight Classification  for  bituminous coal, little,  if
any,  coal  moves at class rates.  In fact, numerous types of commodity rates
apply  to bituminous  coal.   The railroads are  required by  law to  establish
just and reasonable  rates  and to  abide  by  the  rates  that they publish  in
                                      19

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schedules  known as rail freight tariffs.  Approximately 45,000 tariffs  are
in  current  use, containing millions of rates (Hoffman 1976).   Determination
of  an average coal transportation rate thus is difficult.


      TABLE 5.  WEIGHT YIELDS OF WASHED COAL  AT 90 PERCENT  BTU  RECOVERY
Coal
Old Ben 26
Fabius & Underwood
Hamilton 9
River Queen
Ohio
Sinclair 12
Sinclair 9
Sinclair 11
Ayrgem 11
Sinclair 9 - Underground
Breckinridge No. 1
Breckinridge No. 2
Brown Badgett
Ayrgem 12
Old Ben 24
Isl. Creek No. 9
Colonial 9, 11, 12
So. Fork 5A, 7, 9
Cravat - Rice 8, 9, 11
Isl. Creek Prov. No. 1
Eads
Colonial
Mean
Weight yield, %
76.5
85.8
79.6
83.6
83.5
72.7
82.0
80.5
74.2
83.6
76.5
75.3
82.4
73.4
78.5
80.1
80.6
82.7
81.4
76.2
82.1
85.1
79.8
     One report gives data for two cases that show coal  transportation costs
of $3.00 and $9.50 per ton for rail hauls of 180 and 400 miles,  respectively
(Buder 1979).  Another  report gives ten rail  transportation  cost  estimates
for  delivery of  coal  to  three TVA  plants, based  on  1977 volume  tariffs;
these  costs  average $6.34 per ton and range  from $3.00 to  $12.57 per  ton
(Foster 1977).  A  third  report suggests a  typical  coal  transportation cost
of $5.00 per ton (Phillips 1979).   These data indicate  that typical  costs of
transporting  utility coal  are about  $6.00 per ton,  but that  in  specific
cases  costs  may  range  from  about $1.00 to $15.00 per  ton or  more.   High
transportation costs are  associated  with the use of Western  coals  in power
plants  located  outside  the Western  United States.  Although cost  of these
coals  is generally  low  (f.o.b.  mine),  it  is not  necessarily  cost-effective
to clean them to  reduce  the transporation costs.   For  example,  in late 1976
the  TVA considered  the  use of a  Colorado  low-sulfur  coal at  the  Shawnee
steam  plant  in  Kentucky.   The estimated transporation  cost  was $18.19 per
ton, which exceeded  the  f.o.b.  mine price  of  the  coal,  $15.00 per ton.  If
that  coal  could  have  been  cleaned  at  an 80 percent  weight yield with
90 percent Btu  recovery,  the transportation  cost  for  the equivalent heat
content of a ton of raw coal would have been
                                     20

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        $18.19 x 0.8 T 0.9 = $16.17 per equivalent  ton.

The savings would be  $2.02 per equivalent ton ($18.19 - $16.17).  The cost
of producing an equivalent ton, however, would be

        $15.00 x 1.00 4 0.90 = $16.67 per equivalent ton

so  that  the  cost of  reject  coal  is  $1.67  ($16.67 -  $15.00).   Thus,  to
justify cleaning the  coal  in regard to savings in  coal transportation costs
only, the coal would have to be cleaned for less than

        $2.02 - 1.67 = $0.35 per equivalent ton

Table 4  indicates  that coal  cleaning  costs are generally much higher than
$0.35 per  ton.   A further  complication is that the Colorado coal contains
only  10  percent  ash,  so  that the weight  yield  would probably be somewhat
higher than 80 percent  at  a 90 percent Btu  recovery;  this would  further
reduce  the  transportation  savings.   In  summary,  the  data indicate that
(1) assessment  of  coal   transportation  cost  benefits   must be made  on  a
case-by-case basis, (2) the  transportation  cost benefit  is generally only  a
small  portion of  the cost  of  coal  cleaning, and  (3)  in cases where  the
benefit  is  especially  high,  alternative coal  supplies  may be available that
can be used more cost-effectively.

     With  an estimated  transportation  savings of 11 percent  at  $6.00  per
ton,  the  potential  transportation  benefit attributable  to coal  cleaning
would be

        $6.00 x 0.11 = $0.66 per ton of cleaned coal

A  reasonable  range  for this benefit would  be  about $0.10 to $1.50 per ton,
with a typical value around $0.70 per ton.  In some cases the benefit may be
substantially  more;  in other cases,  such  as  a mine-mouth situation, there
may be no measurable benefit  in this category.  Transportation economics for
each plant  must be carefully  evaluated  in assessing this benefit.

4.1.2  Coal Handling and  Storage

     The principal PCC benefit relative to  coal handling and storage is that
less cleaned coal must be  handled and stored than  raw coal,  because the heat
content  of the cleaned  coal  is  higher.   At  an existing plant this effect
would  be  negligible  in  an  economic sense;  there would  be no appreciable
reduction  in  requirements for a  coal handling system, for personnel, or for
coal  storage area.   However,  the  increased fugitive dust potential  associ-
ated with  coal that has been  crushed and  cleaned may pose  problems that will
have  to  be solved.   The  elements  of a  coal handling and storage system that
may be improved as a  result  of coal cleaning  include the following:
                                      21

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     0     Reduced  need  for  system maintenance of coal handling equipment
          damaged  by  corrosion  and  abrasion

     0     Reduced  consumption of fuel and electricity for coal moving
          equipment,  crushers,  and  conveyors

     0     Reduced  requirements  for  coal stockpile area and for employees
          to  handle coal

     Again,  these benefits would  be negligible at an existing plant because
 equipment sizes  and  staff requirements  are not  very  flexible.   At  a new
 plant,  however,   the  requirements for  coal  stockpile  area, coal  moving
 machinery capacity,  and  manpower could  be reduced.   Some  coal  crushing
 operations  and equipment  probably  could  be  eliminated.   As  shown later,
 however,   the  operating  and  maintenance (O&M)  costs  of  coal  handling
 represent about  14  percent  of all  O&M costs.    Although  we  assume  an 11
 percent  reduction in the tonnage  of coal  to be  handled as a result of PCC,
 we  might  expect  that  somewhat  less than  11 percent  of the  coal  handling
 costs  are directly related to  tonnage.  If we therefore assume, for example,
 a  5 percent  savings on 14 percent of  the total O&M costs,  the  benefit is
 equivalent  to only $0.01 per  ton  of cleaned  coal.   Another report has also
 concluded that the benefit is negligible,  even  at new plants (Buder 1979).

 4.1.3  Pulverizers

     Coal  pulverizers  grind  the coal into a fine product and raise the fuel
 temperature  to  about 600°F.  The effects of coal cleaning on the pulverizers
 are  twofold.   First, the quality  of the cleaned coal  increases the pulver-
 izer  capacity  at  existing  plants  and  reduces the capital  requirements for
•pulverizers  at a  new  plant;   where boilers  are  pulverizer-limited,  this is
 tantamount  to  increasing  the boiler  capacity.   Second, the  processing of
 higher quality  coal  having a finer size distribution should reduce the  costs
 of  pulverizer  operation  and maintenance,  although  the  higher  moisture
 content  of  the cleaned coal  may  offset  some  of the  maintenance savings.
 These  two effects are  discussed separately.

 Capacity  Effects--
     Coal  cleaning  should  improve pulverizer  capacity  for  two  reasons.
 First, the heat content  of cleaned coal is higher than that of raw coal, and
 therefore each ton  of pulverizer  throughput contains  more  Btu's.   When  a
 coal is cleaned with 90  percent Btu recovery and an 80 percent weight yield,
 the effective increase in pulverizer capacity on a Btu basis  is

        (0.90/0.80 - 1)  x 100  = 13 percent

 assuming  that  the tonnage  capacity of  the pulverizer  is  the same for raw
 coal  and  cleaned  coal.   Where existing utility  boilers  are operating in  a
 pulverizer-limited mode, this increase in  pulverizer  capacity may be  quite
 valuable, because part of this increased capacity  could obviate the  need for
 generation or purchase  of more costly electricity.
                                      22

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     The second factor In improvement of pulverizer capacity  is that cleaned
coal may  be easier to pulverize  than raw coal.   Thus, the mass throughput
capacity of a given pulverizer may be increased,  or,  at a  new boiler instal-
lation, a less  conservatively sized  pulverizer can  be  installed,  with a
capital cost savings  (Phillips 1979).   It is  well  known that PCC processes
easily  remove  many mineral  inclusions  in coal,  such as  rock  and shale.
Also,  PCC removes  pyrite,  an  extremely  hard  and  dense  material.   Thus,
cleaned coal should be  lighter,  finer, and softer  than raw coal, and easier
to pulverize.

     Furthermore, a recent  report indicates that because the properties of
cleaned coal are  not  so  variable as  for  raw  coal,  it should be possible to
design pulverizers less conservatively and to  avoid oversizing of equipment.

     On the other  hand,  there  are indications that  coal  cleaning may cause
certain pulverizer  operating  problems.   Since  most coal is  cleaned  in an
aqueous medium, the cleaning process has considerable potential for  increas-
ing  the coal moisture content.   The higher moisture content  may create  sig-
nificant  problems  in   pulverizer   operation  and  may  reduce  pulverizer
capacity.   The moisture  content,  however, probably would be reduced at  the
PCC  plant to a level  equal  to that  of the raw coal or at  least to a  level
where  such  problems  would  be minimal.   Therefore, the  net effect of  PCC
should be to increase pulverizer capacity and reliability.

Pulverizer Operation and Maintenance--
     The two principal categories of pulverizer wear are abrasion  and corro-
sion.  Abrasion  is  closely  related to the  hardness,  size distribution,  and
quantity  of coal  that is pulverized, whereas corrosion is mainly  a function
of  its sulfur content  and  moisture.  Although  the moisture added  in  coal
cleaning  would tend  to increase corrosion, the  reduction of sulfur content
should more than offset  this  corrosive effect.   Coal cleaning should reduce
the  abrasive and corrosive  properties of  a coal and thus reduce pulverizer
maintenance  requirements.    Pulverizer   maintenance   accounts   for  about
10 percent  of  all  boiler maintenance costs.  The principal items  subject to
wear  and  maintenance  include  grinding elements such  as  forged  steel  balls
and  races, classifiers, coal feed chutes,  and drive  mechanisms.   The service
life of the grinding  elements of ball and  race pulverizers ranges from 6,000
to  14,000 hours  of  operation.   The  rate of  wear  for these elements  is  a
function  of coal  sulfur  and  ash content, but  no  quantitative relationship
has  been  established.  Wear  is not  closely  related to the grindability of
the  coal, and operating time is reported  to be a better index of the life of
the  grinding  elements  than the  rate of  output of  a pulverizer  (Babcock
1960).

Conclusions Regarding Pulverizer Effects--
     On the whole, coal cleaning  is  expected  to  increase  pulverizer capacity
and  to reduce maintenance  costs.   Because of  the difficulty of allocating
the  total maintenance costs  among  the  different  parts of a boiler system,
the  pulverizer  maintenance  costs are  included in  Section  4.2.1,  O&M  Cost
Reductions.  Although the  increases in  pulverizer capacity may range  from
5 to  15 percent,  no net benefit  in  terms of boiler capacity would be  real-
ized at most plants,  where pulverizer capacity  is  adequate.   In contrast,  at


                                      23

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 a  plant where a 1000-MW boiler  is pulverizer-limited, so that coal cleaning
 can  increase  the  effective  boiler  capacity  from 950 MW  to  1000 MW,  the
 estimated  value  of the  PCC benefit would be equivalent to the revenue needed
 to capitalize 50 additional  megawatts  of capacity.  At  a capital  cost  of
 $1000  per  kW and an amortization period of 25 years, and with various other
 input  parameters indicated in Appendix C, the annual savings would be $11.6
 million (Foster 1975).   With  a 70 percent  capacity factor for  a  1000-MW
 boiler,  the  savings  is  1.9 mills/kWh, equivalent to $4.50 per ton of cleaned
 coal.   This  is a substantial  benefit.

     It is possible  that many existing utility boiler plants are pulverizer-
 limited and  cannot be easily  retrofitted with additional pulverizers because
 of space and geometry  limitations.   In the  past  many utility boiler plants
 switched from coal  to oil for economic and  environmental  reasons.  Because
 of the general  deterioration of coal quality since that time, these boilers
 cannot  now  be  reconverted   for  coal  firing  unless  they  are  derated  for
 pulverizer  limitations  associated with  the  poor  quality  coal   that  is  now
 available.   Coal cleaning might be  an attractive possibility  for  some  of
 these  plants.

 4.1.4   Ash Collect-ion and Handling

     Requirements for  collection and handling of  ash are  reduced in almost
 direct proportion  to  the reduction  in coal  ash  content effected  by coal
 cleaning.  A principal  problem with ash handling equipment is the  buildup of
 material  in  boilers  and equipment,  causing disruption in operation or effi-
 ciency of air pollution control equipment such  as electrostatic  precipita-
 tors (ESP) and  scrubbers.   A related problem  is  the  abrasion and corrosion
 of ash  collecting   and conveying  equipment.   Coal  cleaning  can  help  to
•alleviate  these problems,   especially  at  plants  where  hoppers  and  ash
 handling systems are undersized.  Reduction of the sulfur content  of coal by
 coal  cleaning also  reduces  the corrosive properties of  the collected ash.

     It is expected  that in specific cases PCC will alleviate some deficien-
 cies  of ash  handling  systems,  but  for most  existing boilers there will be
 little  effect,  if   any.   Reduced  ash  loadings  may  permit  less  frequent
 removal  of bottom  ash from a boiler, but in most  systems the removal opera-
 tion  is continuous  or  automatic.   Maintenance  costs for the  ash  handling
 system as  a  whole  may be  reduced  slightly,  and  any improvement in relia-
 bility of  the ash  handling  system  may have  a  corresponding effect on the
 reliability  of associated air pollution  control  equipment.   As shown later
 (Table 6),  ash  handling O&M  costs  account for  about 16  percent of all O&M
 costs.   Since the ash tonnage from firing of cleaned  coal  is  typically about
 half  of that from  raw coal,  an upper  limit on the  PCC  benefit  for ash
 handling would  be  about $0.10 per ton  of cleaned coal, and  a  typical value
 would  be  closer to $0.05 per  ton.   This benefit is  included in  Section
 4.2.1.   Another  report  indicates  that ash  handling equipment  accounts for
 less than  1  percent  of the total plant capital cost, but  that  PCC can yield
 a  one-third  savings  in those capital  costs, which  is  equivalent  to about
 $0.24  per ton of cleaned coal for a new plant  (Buder, 1979).
                                     24

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4.1.5  Ash Disposal

     Coal cleaning substantially reduces the ash disposal  requirements  for a
power plant.   At an existing plant, the ash hauling costs  can be  reduced, or
the service life of a pond or landfill  can be extended.  Generally, ash com-
position  is  not adversely  Influenced  by the cleaning process.  Of course,
all of the mineral  matter in the  raw  coal  is subject to  ultimate disposal,
either by the  coal  cleaning plant or  by  the  utility,  but disposal costs at
the cleaning  plant are  borne  as  part of the cleaning operation.   Where a
coal cleaning process removes half of the ash from the coal,  the  savings may
approach half of total ash disposal costs.

     In  this  cost study  we inspected  forms submitted to  the  Federal  Power
Commission in 1977 by several utilities.  Among eight utilities who  reported
the costs of  ash and sludge disposal,  the  costs  ranged  from 0.001  to  0.139
mill per kWh with an average of 0.076 mill per kWh.  If PCC reduces  the coal
ash content by 50 percent,  we  might expect the ash disposal  costs  to  be  re-
duced proportionately.  Thus we estimate a typical benefit of 0.038  mill  per
kWh, equivalent  to  $0.09 per ton of cleaned  coal,  and  a  benefit range from
0 to $0.20 per ton.
                *
     One  utility representative indicates ash disposal costs  in the  neigh-
borhood  of  $2 per ton  of ash.   He cautions, however, that  the  incremental
savings  may  tend to  be less.    One  problem  is  that fly  ash  is needed  for
sludge  fixation.  Since  PCC generally reduces  ash content  to a  greater
extent than  it reduces  sulfur  content, a  net deficit of  fly ash for sludge
fixation  purposes  may result.   Also,  the $2 per ton figure  includes certain
fixed costs.

     Because  12,000/10,670 tons of  raw  coal  are  equivalent to  a ton  of
cleaned  coal  in  terms  of  heat  content;  the ash  reduction  per ton  of our
example  cleaned  coal  is

     0.2  x 12,000/10,670 - 0.1 =  0.125 ton  of  ash per ton  of cleaned coal.

At  a  disposal  cost of $2 per ton  of ash, the PCC  benefit  is estimated to be

     0.125 x $2.00 =  $0.25  per  ton of  cleaned coal

As  discussed  above,  the net savings will  probably be somewhat  less because
fixed costs associated with refuse disposal would  not be  reduced proportion-
ately  and because  of potential sludge fixation  problems.   On the basis of
available data,  the typical  benefits would be about $0.10  per  ton of cleaned
coal, with a range from  0  to $0.25 per ton.


4.2  COST SAVINGS  IN  BOILER OPERATION

     Many of  the benefits  of burning  cleaned coal would  occur  in operation
of  the boiler,  since  the  cleaning  process improves the combustion properties
                                      25

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of  the  coal.    The  expected  boiler  operating  benefits  are  discussed  in
detail.

4.2.1  Operating and Maintenance Costs

     Boiler  O&M  costs may  be  influenced profoundly  by the quality of  the
coal  that is  fed to  the  boiler.   Coal  quality parameters that  influence
boiler  O&M  costs  are mineral  content and composition,  both  of which  are
influenced by PCC.  In addition to the impacts discussed earlier relative to
materials  handling,  mineral  content   influences  operation of those boiler
components that come in contact with ash.

     Mineral  composition is  also  very important with respect to performance
of the  boiler.   It affects  erosion, corrosion, and abrasion within the pul-
verizer,  the  boiler,  and  the  gas   and  ash handling  systems.    Mineral
inclusions are responsible for all  of  the slagging and fouling properties of
coal.

     Thus PCC can  reduce  the boiler O&M costs for a number of reasons.   Re-
moval  of  mineral  matter  helps  to reduce  slagging  and  fouling  of the boiler
tubes   so that  fv boiler  runs cleaner  and  tube  life is  extended.   Coal
cleaning  reduces  the  abrasive  characteristics of the coal, effecting a com-
mensurate decrease in  boiler deterioration  and in maintenance requirements.
The  reduction  of  sulfur  content  by  PCC  retards  corrosion  of boiler
materials.

     The Federal  Power Commission has  established a uniform system for  cate-
gorizing  utility  costs.   Tables 6  and 7  show  these  cost categories  and
identify  those that are  and are not  fuel-related.   These  data on the  John
Sevier and Kingston plants  were obtained from TVA  for the period from 1974
through  1977.    At the  John Sevier  plant  the  annual fuel-related  boiler
maintenance  costs  ranged  from  59 to  76 percent  of  total   boiler  costs,
averaging  66 percent  over  the 4-year  period.  At  the Kingston  plant  the
fuel-related costs constituted  about  80 percent  of total  boiler maintenance
costs  in each of the 4 years.

     Table 8 shows cost  data from  several TVA plants.  At these plants the
ratio  of  fuel-related maintenance  costs  to  total  boiler  maintenance  costs
ranged  from   45  to 87 percent.   Thus, extrapolating  from  these  data,  we
surmise  that perhaps  40 to  90  percent of all boiler  maintenance  costs  are
fuel-related.  It seems reasonable that a significant portion of these  fuel-
related maintenance costs can be reduced if coal  quality is improved by PCC.
Thus the  O&M cost benefit  is  potentially very  large.   (For convenience in
this analysis, all of  the  fuel-related reductions in O&M cost are estimated
in this  section  rather than in individual sections concerning such items as
pulverizers and ash handling equipment.)

     Table 9 shows  reported  costs  associated  with  several  large U.S.  power
generating plants.  A major point  shown by  the data  is  that boiler  main-
tenance  costs  averaged about  5 percent of fuel  costs in  1976, and ranged
from 1 to 35 percent  for  individual boilers.   The  TVA Paradise plant  shows
                                     26

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TABLE  6.   ITEMIZED JVA  BOILER MAINTENANCE  COSTS,  JOHN SEV1ER PLANT3
Cost area
Coat Handling and Storage Equipment
Railroad tracks
Locomotives
Coal sampling facilities
Coal receipts scales
Coal car unloading facilities
Storage yard coal moving equipment
Primary coal crushing facilities
Coal conveying facilities
Coal handling power and control system
Coal bunkers
Boiler and Accessories
Boilers
Soot blowe-t
Boiler water circulation equipment
Coal Burning Equipment
Coal transport piping and valves
Boiler room coal scales
Pulv. wills, primary air fans. exh. fans
Burners, lighters, cyclones
Lighter fuel oil system
Draft Equipment
Air preheaters
Forced draft fans
Induced draft fans
Air and gas ducts
Stacks
Feed Water Equipment
Feed water pumps and tanks
Feed water heaters, deaerators, & evap.
Ash Handling Equipment
Bottom ash hoppers
Fly ash collectors
Other ash disposal facilities
Ra«« Water Supply and Treating Systems
Boiler feed water
Raw water service
Boi ler Plant Piping
Boiler plant piping
Boiler Instrumentation and Controls
Boiler instrumentation and controls
Total - Fuel-related Items
Percent of total boiler
maintenance costs
1974

2.1
0.9
0.1
0.0
0.6
3.5
0.5
3.0
0.0
0.2

15.4
1.5
2.3

4.3
0.6
8.9
2.4
0.0

0.4
0.1
2.4
0.6
0.1

3.B
2.0

1.0
6.5
27.5

O.B
1.5

2.6

4.2
76.2
1975

2.6
2.7
0.2
0.1
1.8
4.6
1.0
4.5
0.3
0.3

19.4
2.5
7.4

1.4
1.1
5.6
1.5
0.2

0.3
0.?
1.6
0.7
0.0

5.5
0.5

0.6
2.8
13.7

14
3.9

4.4

6.9
59 3
1976

2.7
1.0
0.3
0.2
0.2
7.7
1.6
3.5
0.1
0.0

12.2
2.4
4.1

1.1
1.9
16.1
1.5
0.0

0.2
0.9
0.5
0.3
0.0

4.4
2.8

1.2
2.2
16.5

2.6
1.6

3.2

7.1
61.9
1977

2.0
0.4
0.2
0.2
0.3
7.3
0.5
3.1
0.1
0.0

17.1
2.2
3.7

2.3
1.1
15.2
1.7
0.1

0.2
0.2
0.2
0.6
0.0

5.8
1.9

1.2
2.2
16. 1

1.1
1.7

3.3

6.0
66.4
Avg.

2.4
1.2
0.2
0.1
0.8
5.6
0.9
3.5
0.1
0.1

16.0
2.2
4.4

2.3
1.2
11.5
1.8
0.1

0.3
0.4
1.2
0.6
0.0

4.9
1.8

1.0
3.4
19.0

1.5
2.2

3.4

6.0
66.1
        "Data for period 1974 through 1977; Indicates fuel-related areas.
                                     27

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TABLE  7.   ITEMIZED TVA  BOILER MAINTENANCE  COSTS, KINGSTON PLANT1
Cost area
Coal Handling and Storage Equipment
Railroad tracks
Locomotives
Coal sampling facilities
Coal receipts scales
Coal car unloading facilities
Storage yard coal moving equipment
Primary coal crushing facilities
Coal conveying facilities
Coal handling power and control system
Coal bunkers
Boilers and Accessories
Boilers
Soot bowers
Boiler Mater circulation equipment
Coal Burning Equipment fl
Coal transport piping and valves
Boiler room coal scales
Pulv. mills, primary air fans, exh. fans
Burners, lighters, and cyclones
Lighter fuel oil system
Draft Equipment
Air preheaters
Forced draft fans
Induced draft fans
Air and gas ducts
Stacks
Feed Water Equipment
Feed water pumps and tanks
Feed water heaters, deaerators, & evap.
Ash Handling Equipment
Bottom ash hoppers
Fly ash col lectors
Other ash disposal facilities
Raw Water Supply and Treating Systems
Boiler feed water supply & treating sys.
Raw water serv. and gland seal water sys.
Boiler Plant Piping
Boiler plant piping
Boiler Instrumentation and Controls
Boiler instrumentation and controls
Total - Fuel-related Items
Percent of total boiler
•aintenance costs
1974

2.2
1.8
0.6
0.2
0.1
5.2
0.8
3.2
0.4
0.7

33.5
3.2
1.2

2.1
0.7
9.8
2.7
0.0

3.5
0.2
1.6
0.7
0.1

2.0
1.5

1.2
4.7
9.5

0.6
0.5

1.6

4.0
78.9
1975

2.8
0.9
0.9
0.3
1.5
4.4
0.8
3.7
0.1
0.2

25.0
3.3
2.1

4.0
1.0
10.1
2.3
0.1

5.7
0.2
1.7
0.7
0.7

2.0
2.2

1.5
5.7
8.5

0.7
0.9

2.3

4.7
76.6
1976

1.9
1.2
0.8
0.2
0.3
4.1
0.4
4.7
0.1
0.5

34.2
3.5
1.1

3.6
0.7
8.4
1.6
0.0

0.6
0.2
2.0
1977

1.4
1.4
0.5
0.2
0.1
3.9
0.2
1.7
0.2
3.4

Avg.

2.1
1.3
0.7
0.2
0.2
4.4
.6
3.3
0.2
1.2

37.4 32.5
3.3 3.3
1.0

3.1
0.7
8.7
1.1
0.0

2.1
0.1
2.0
1.4

3.2
0.8
9.2
1.9
0.0

3.0
0.2
1.8
0.4 ' 0.5 1 0.6
0.0

1.4
2.1

2.3
0.0 0.2
1
2.0 ' 1.8
3.4 , 2.3

2.3 1.8
3.8 | 4.7
13.3

0.6
0.4

1.9

3.4
81.5
8.3

0.4
4.7
9.9

5.8
0.6 0.6

1.9

3.3
80.7

1.9

3.8
79.1
    *Dat« for period 1974 through 1977; indicates  fuel-related areas.
                                   28

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               TABLE 8.  TOTAL BOILER MAINTENANCE COSTS AND
                 FUEL-RELATED BOILER MAINTENANCE COSTS AT
                           SELECTED TVA PLANTS3
                                 (A)          (B)
                                Total     Fuel-related
                                boiler       boiler
                             maintenance  maintenance
                                costs,        costs,
 Cost
Ratio,
Plant
Paradise
Shawnee
Kingston
Johnsonville
Gal latin
John Sevier
Bull Run
Average
Year
1972
1973
1974
1972
1973
1974
1972
1973
1974
1975
1976
1972
1973
1974
1972
1973
1974
1972
1973
1974
1975
1976
1972
1973
1974

$1,000
8677
7817
8078
2269
2569
2558
2491
3425
3961
3907
6353
1923
2314
2946
1579
1617
2122
797
1475
1886
1069
1529
1318
1054
1187
2997
.$1,000
6573
4336
5138
1817
1966
2116
1712
2890
3077
29S6
5145
1471
1932
2166
1028
785
1317
355
1280
1414
615
949
768
594
636
2121
(B) * (A)
0.76
0.55
0.64
0.80
0.77
0.83
0.69
0.84
0.78
0.76
0.81
0.76
0.83
0.74
0.65
0.49
0.62
0.45
0.87
0.75
0.58
0.62
0.58
0.56
0.54
0.71
aData from TVA annual reports and TVA Form 4121.
                                       29

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    TABLE 9.   COST BREAKDOWN3 FOR SELECTED COAL-FIRED  ELECTRIC
  GENERATING PLANTS WITH AVERAGE BOILER SIZE  OF  200  MW OR  LARGER
Plant
Gorgas
Greene County
E. C. Guston Unit 5
E. C. Guston
Big Bend
Kinkaid
Powerton
Will County
State Line
Clifty Creek
E. W. Brown
Ghent
Mill Creek
Allen S. King
New Madrid
Thomas Hill
G. G. Allen
Belews Creek
Kyger Creek
Hatfields Ferry
Thomas H. Allen
Bull Run
Colbert "A"
Colbert "B"
Cumberland
Gallatin
Paradise "A"
Paradise "B"
John Sevier
Widows Creek "B"
Harrison
Fort Martin
New Geneva
Average
(A) Total
power
production
cost,
$1,000
78,786
25,794
48,329
71,132
65,914
28,658
59,987
70,527
47,386
73,417
28,801
23,435
23,345
29,545
25,812
17,728
62,320
126,900
59,417
95,459
39,562
41,320
47,626
15,409
91,148
56,502
41,130
31,227
61,296
50,237
139,251
60,185
22,646
53,340
(B)
Fuel
cost,
$1,000
65,357
21,130
40,420
64,150
57,464
19,184
53,336
60,581
36,874
64,903
26,426
21,540
20,796
24,867
21,345
14,895
59,427
122,288
50,531
85,183
31,666
34,823
39,637
11,841
71,726
46,395
28,727
20,858
56,586
41,211
131,777
53,703
19,317
46,029
(C) Boiler
Main-
tenance
cost,
$1,000
6,359
2,076
2,417
2,252
4,113
5,051
2,412
4,193
3,346
4,174
819
747
858
2,142
2,297
1,025
952
1,437
4,873
7,736
3,537
2,971
4,417
1,304
11,330
2,390
8,482
7,224
1,529
5,108
3,904
3,433
1,582
2,482
Cost
ratio
te nance
C * B
0.10
0.10
0.06
0.04
0.07
0.26
0.05
0.07
0.09
0.06
0.03
0.03
0.04
0.09
0.11
0.07
0.02
0.01
0.10
0.09
0.11
0.09
0.11
0.11
0.16
0.05
0.30
0.35
0.03
0.12
0.03
0.06
0.08
0.05
Data for the year 1976, obtained from TVA annual reports and TVA Form 4121.
                                 30

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the highest ratio of  boiler maintenance costs to fuel  cost.  The coal costs
at Paradise are  very  low,  and as a result of poor coal  quality, the boiler
maintenance costs  are  extremely high.   TVA attributes  these high boiler
maintenance costs to  the poor coal  quality and has contracted  for  Installa-
tion of a coal cleaning plant to alleviate the problem.

     Representative values  from Tables 8 and 9  Indicate  boiler maintenance
costs  equal  to 5 percent of fuel costs,  raw fuel costs of $21.34 per ton
($1.00/inillion Btu),  and fuel-related  maintenance costs  equal  to 70 percent
of total  boiler maintenance  costs;  if 50 percent  ash reduction  by PCC  is
assumed to eliminate  30 percent of  these costs, the value of coal  cleaning,
in terms of reduced boiler maintenance costs, is

        0.05 x 0.70 x 0.30 x $1.00/106 Btu =  $0.0105 per  million Btu.

     Where a  ton of cleaned coal provides 24 million Btu, this cost benefit
is equivalent to

        $0.0105 x 24 = $0.25 per ton of cleaned coal.

The benefit hinges  jon the  assumption that PCC  eliminates 30 percent  of the
fuel-related  maintenance costs.   Because  we  could find no available  data to
support this  assumption,  it represents a subjective estimate  in this  case.
An  independent approach  to  quantification  of  the benefit,  which  follows
shortly,  indicates  that  the  30 percent assumption  is conservative  for
estimating a  typical benefit.

     The  Paradise plant is  a less typical example; fuel  costs are $9.66 per
ton, boiler maintenance costs are 32.5 percent of fuel costs (see Table 9),
and  fuel-related maintenance  costs  are  65 percent  of   total boiler  main-
tenance  costs  (see  Table 7).   If  the use  of  cleaned  coal eliminates 50
percent of all fuel-related maintenance costs, the estimated value of a coal
cleaning  benefit is

        0.325 x 0.65  x  0.50  x $9.66/ton = $1.02 per  ton  of raw coal.

     Although  this  value  is high, it may not be  an  upper limit because fuel
costs  at  the  Paradise  plant are  so  low.   Many utilities are paying  three
times  as  much for coal.  We  estimate that in  specific  applications the  value
of  coal   cleaning,   in terms of  reduced boiler  maintenance costs,  may  range
from  about $0.10 to  perhaps $2.00 per  ton  of  cleaned  coal.   Fuel-related
maintenance  costs  may  be  considered  from another standpoint.  TVA reports
the use of the  sum  of the percentage ash  and  sulfur  contents (A+S) of a coal
as a  negative measure  of fuel  quality  (Cole  1979).  It  seems  incongruous to
add the percentages of these two impurities,  and to our  knowledge there is
no  rigorous   statistical correlation  showing that ash and sulfur should be
weighted  together  on  a  one-to-one basis.   It  is likely  that  the  sulfur
content  is the  more  detrimental of  the two coal  properties, but again we
have  no  knowledge  of  an  appropriate  weighting factor.  TVA  has used  the
simple sum, A+S, for  several  years to  determine fuel penalties to  be  charged
to producers  when they  supply inferior coal.
                                      31

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     Although  statistical  support  is  lacking,  the  use  of  A+S  as a  coal
quality parameter can be  substantiated empirically.  Figure 5 shows data for
five  TVA  plants over  the period from  initial  commercial  operation through
1974,  indicating the  relationship of  cumulative  fuel-related maintenance
costs to  the  cumulative tons of A+S.   It  is  apparent that the relationship
is  reasonably linear and,  interestingly,  that the slope is  about  the  same
for  all  five plants.  We conclude  from the data that the  addition  of  each
ton  of A+S  to these boilers costs  about $3.90 in fuel-related boiler main-
tenance.   This  value seems reasonably constant over the life of each plant.

     An important point is that the $3.90 cost parameter is apparently  inde-
pendent of  fuel  quality because the data  represent  a fairly broad range of
ash and sulfur contents.  The Paradise and Kingston plants have burned  fuels
with  over 20 percent ash.   The John Sevier plant has burned  fuels  with as
low  as  9 percent ash.   The other  plants  have burned  intermediate  quality
fuels.  Yet data from all five plants show the same basic fuel-related  main-
tenance costs per ton of A+S.

     As a check  on  our earlier conclusions about the value of coal cleaning
in  reducing boiler   maintenance  costs,  we  can calculate a  benefit  based on
this $3.90  value and on  the assumptions of a  raw coal  with a heat value of
10,670 Btu/lb,  20 percent ash,  and 3.5 percent sulfur, which is  physically
cleaned  to  12,000 Btu/lb,  10 percent  ash,   and 2.4 percent  sulfur  with
90 percent  Btu  recovery  and  an 80 percent weight yield.   The fuel-related
boiler maintenance   cost  associated with  1 ton  of  cleaned  coal  would  be

        $3.90 x (0.10 + 0.024) = $0.48.

The cost associated with the equivalent amount of raw coal would be

        $3.90 x (12,000/10,670) x (0.20 + 0.035) = $1.03.

The  coal  cleaning  benefit  is  thus  the difference between  $1.03  and $0.48,
i.e., $0.55 per ton  of  cleaned  coal,  or about twice our earlier estimate of
$0.25 per ton.

     On the basis of all  of the data analyzed,  we believe that the typical
benefit would be  between  these  two values,   i.e.,  about  $0.40 per ton of
cleaned coal.   In  specific  cases  the  value  may range from $0.10 to  about
$2.00 per ton of cleaned coal.

4.2.2  Boiler Availability

     In general,  the availability  of  a boiler shows  no  significant change
with  minor  changes  in  the ash  or sulfur  content  of a  coal.    It  seems
somewhat   obvious  that  reducing the  ash  and sulfur  content of  coal  will
reduce the  occurrence  of  tube failures, erosion and corrosion, ash handling
problems,  pulverizer wear, and slagging problems.   Other factors that influ-
ence  boiler  availability  but  are  generally  unrelated  to  fuel  quality,
include boiler design  and operating history and boiler water quality.   Data
                                     32

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OJ
         t
         •a
         o
         •o
        o
        aa
        ae
         i
        UJ
                                                                                       Average slope:
                                                                                       $3.90 per ton of
                                                                                       ash-plus-sulfur
                0_fc
                                                                              10
                                                                       12
14
        o
CUMULATIVE TONS OF ASH-PLUS-SULFUR THROUGH THE BOILER PLANTS,  millions of tons

     Figure 5.  Relationship of fuel-related boiler maintenance costs  to
               tons of ash-plus-sulfur fired  into the boiler.

-------
 indicate  that  as  coal quality deteriorates, boiler availability also deter-
 iorates,  but data relating fuel quality to boiler availability are masked by
 these  other  factors.   For this reason  it  is  difficult to formulate a solid
 statistical  relationship  between  fuel  quality and  boiler  availability.

     The  value attributable  to improved  availability is dependent  on  the
 method  of evaluation.   Where  a boiler system has excess capacity, the value
 of  increased availability is  very  low, but this is not  normally the case.
 Most utilities use coal-fired units to supply their base load and use hydro-
 electric   units,  oil-  and  gas-fired  boilers,  combustion  turbines,  and
 purchased  power to  supply peaking loads.  The differential between the cost
 of  producing  base-load  power and  the  cost  of  replacement  power  is  a
 reasonable estimate of the worth of increased availability.

     The  influence of fuel  quality on boiler availability can  be evaluated
 in  terms  of  a  relationship between fuel quality  and  the  forced outage rate
 for  a  boiler.   Forced  outages are normally  caused by failures  of pulver-
 izers,  ash  handling  equipment, coal  handling  equipment, or  boiler tubes
 (Cole 1979).    Failures  that are  fuel-independent are  less  common.   Forced
 outages have been shown to correlate with the ash and sulfur contents of the
 coal.   A  recent  TVA  study  estimates  that availability  is reduced  by 1
 percent for  each  percent  that A+S exceeds 17.5 percent, and that 50 percent
 of  such  unavailable  power  must  be  replaced  at  an  incremental  cost  of
 $0.01/kWh  (Phillips  1979).   Thus,  with  the  standard  raw  coal  containing
 20 percent ash and  3.5 percent sulfur,  the  loss  of   availability  would be

        20.0 + 3.5 - 17.5 =6.0 percent.

 The incremental cost of replacing power for a 500-MW boiler would be

        500,000 kW   x  8760  h/yr x  (0.06 r 2) x  $0.01/kWh = $l,314,000/yr.

 Cleaning  of  coal  for this boiler to 10  percent  ash and 2.4 percent sulfur,
 would  eliminate  the  availability  loss  and  would  yield  a   savings  of
 $1,314,000 per year.   At a capacity factor of 70 percent,   this translates to
 a benefit of

        $l,314,000/yr   x  1000  mills/$  -r (500,000   kW   x  8760  h/yr x 0.7)

             = 0.43 mills/kWh.

 This is  equivalent   to  $1.02  per  ton  of  cleaned coal, or $0.14 per ton of
 cleaned coal  for each percent of availability that must be replaced.

     An earlier PEDCo analysis of  operating data  for TVA  showed that the
 number of  forced  outages  of  specific  units correlated well  with properties
 of the  coals fired  on those units.  This  work  is summarized in  Appendix D.
Additional published data (Phillips 1979) relate forced outage rates to  coal
 ash content.    Figure 6  shows  that the annual forced  outage rate  of the TVA
 system  has closely  paralleled trends  in average  coal  ash  content over a
 15-year period.   The Electric Power Research  Institute (EPRI) is currently
                                     34

-------
  10.0 -r    20 -r
   7.5-1-    18 -f
0.0 -J-
       o>
       u
   5.0-      16 -
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£ 2.5-h     14 -h
                                                                    FORCED

                                                                    OUTAGE

                                                                    RATE
                                                                    % ASH
              12
                1963    65     67      69      71     73



                                     FISCAL  YEAR
                                                         75    1977
 Figure 6.   Annual forced  outage rates as  a function of  coal  ash content.
                                     35

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 investigating methods of improving plant availability, with a near-term goal
 of  increasing  availability by  2 percent.   They  expect  that this  2 percent
 increase will  be realized by reducing tube failures, fouling, slagging, and
 inadequacies  of  boiler  control system.   Further,  they estimate  that  tube
 failures  in the waterwall sections, economizers, and superheat  portions of
 the boiler  account  for approximately half of  total  losses  of boiler avail-
 ability.

      The  availability  of a  boiler-turbine  system  is  a  function of  the
 individual  availabilities  of  the boiler  and  of the turbine.   If  the  two
 component availabilities were  independent,  system availability would be the
 product  of  the component availabilities.  The  component availabilities are
 not  independent,  however.   Scheduled  outages  are  frequently  set  for  main-
 tenance of  both  units,  and if  one unit  is  forced out of service,  the  main-
 tenance crews are likely to take advantage of the outage period to  repair or
 maintain both components.

      Data in Figure 7  show  a  downward trend in  availability at  large  coal-
 fired  power plants  over the  period  from 1967 through 1976  (EEI 1977).   In
 that  10-year  period,  the  average  availability of  units  larger  than 400 MW
 decreased  from -81.5 percent  to  72.5 percent.   Capacity   of  these  units
 currently totals  more  than  50,000  MW,  so any  improvement  in average avail-
 ability  would  lead  to a  substantial   increase  in  usable  domestic utility
 capacity.

      Table  10  shows additional  availability  data for 1046 fossil-fuel-fired
 units  in  119 utility  systems  (EEI  1977).  Although these  data  include sub-
 stantial numbers  of  gas-fired  and  oil-fired units,  they  show  clearly that
 the  boiler  itself  is  by  far  the  largest contributor  to  the  unit forced
 outage  rate  and   to operating  unavailability  of  the  generating unit.   The
 boiler  is responsible  for  about 64 percent of the total  forced outage  rate,
 whereas the turbine, condenser,  and  generator are  responsible for only 22,
 2, and  7 percent, respectively.  A  similar tabulation of data on coal-fired
 boilers only would almost  certainly  show an even higher contribution of the
 boiler to system outage rate.   Thus it is concluded that total system avail-
 ability is  related principally  to  boiler availability and that improvements
 in  boiler  availability will  be  reflected  largely  in  terms of  available
 system generating capability.


          TABLE 10.  COMPONENT AND COMPOSITE FORCED OUTAGE RATES AND
        AVAILABILITY OF FOSSEL-FUEL-FIRED UNITS, 1967-1976 (EEI 1977)a

Boiler
Turbine
Condenser
Generator
Other
Unit
Forced outage rate, %
3.8
1.3
0.1
0.4
0.4
5.9
Availability, %
88.7
92.8
97.0
95.9
97.3
84.5
alncludes 1046 boilers in 119 utility systems plants.

                                      36

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 o>
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 O)
 ex
CD
       100
        90
        80
0.
O
        70
        60
         50
            67  68   69    70   71    72    73   74    75   76

                          YEAR OF  OPERATION
     Figure 7.   Yearly  operating  availability of

    coal-fired  units  400  MW and above (EEI  1977)
                          37

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     The  utilities  have considerable incentive to  improve  the  availability
of  these  units, and  because so many  forced outages are  fuel-related,  the
beneficiation of fuel by PCC may have special merit.

     A  forced  outage  does  not  always  incur an  economic  penalty.    For
example,  a  utility may  have several boilers for which operating  costs  are
similar. -Thus if one boiler is forced out of service when electrical demand
is  not  at a peak,  another boiler can be  placed in service at  little or no
incremental cost.

     It should  be  pointed  out also that an  improvement  in availability  may
not  have  significant value  if a  utility  has  no  problems  in  meeting peak
power requirements.   Most utilities maintain only  minimal  reserve capacities
that are prescribed by the Federal  Power Commission in order to  keep utility
costs as  low  as practical.   Thus,  nearly all utilities  have some difficulty
in  meeting  peak  load  requirements,  and availability is  an important consid-
eration.  All  major utilities  load  and unload their units according to an
economic  dispatch   system.   That  is,  when  the  electrical  demand on  the
generating  system  increases, the  instantaneous demand  is  met  by  the  unit
that can  do so  at  the least incremental cost within the system.  Generally,
this means  that  t.^e  unit with the  best heat rate  within the system is  given
the  incremental  load  if that  unit  is not  already operating  at  capacity.
Thus, the economic  dispatch system  uses a unit with a poor heat  rate only as
a  last  resort,  and an  improvement  in availability of that unit  would  have
value  only  to  the  extent  that the  unit could help to  supply incremental
power in  meeting peaking requirements.   The upper-limit case would be  that
of  a  boiler in  such  demand that  every increment  in availability could be
economically utilized.   In such a  case the  value of the  increased avail-
ability would  be the incremental  cost of  alternative  power,  the need  for
which is  obviated  by  the enhanced  availability of the boiler.  One approach
to  estimating this  value is to base  it on  the revenue  needed to capitalize
equivalent  new  boiler capacity, neglecting  operating and  maintenance  costs
because they  must  be  incurred in either  case.  By  use  of  the  estimating
technique  presented  in  Appendix C,  the  value of  a 1 percent  increase in
availability  of a  1000-MW  boiler  operating  at  a  capacity  factor of  70
percent would be the  revenue requirements to  capitalize  10 MW  of capacity,
or  about  $2.3 million per  year (Foster 1975).  This  is  equivalent to about
$0.90 per ton  of cleaned  coal  for  each  percent  increase  in availability.
The  true  worth of  increased  boiler  availability  may vary  considerably,
depending on  the calculation  method.   If the  greater  availability reduces
the need  to purchase  emergency power from another  utility,  the benefit may
be even higher than $0.90 per ton of cleaned coal.

     A  further  consideration is that many utilities  maintain oil-fired  gas
turbines to meet peaking power requirements.   These turbines are very expen-
sive to operate because of high fuel  costs.   Where an  increase in avail-
ability of  a  coal-fired unit  can  be  used to  generate part  of the peaking
power that  would otherwise  have to  supplied by gas  turbines,  the value of
the increased availability  can be  related to  the  cost  differential between
coal and  oil;  at  a fuel  cost differential  of $1.00 per million Btu,  the
benefit is equivalent to 10 mills for each kWh that can be generated by  coal
                                     38

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Instead  of  oil.   Thus  the value  of the greater  boiler availability that
results from burning cleaned coal  can be expressed  in  terms  of the amount of
gas turbine power  the boiler  can  displace.   As  as  example,  if it is assumed
that PCC will  enable a boiler to supply enough peaking power to  increase its
capacity factor from  60 percent to 70 percent,  and if this  peaking power .is
generated with  coal  that costs $1.00 per million Btu rather than with gas
turbine fuel that  costs $2.00 per  million Btu,  the savings  is $3.43 per ton
of cleaned coal, or $0.34  per ton  of cleaned coal  for  each percent of  avail-
ability  that  is utilized.  The benefit limit  is  uncertain,  but values of
these magnitudes seem likely.

     The degree of enhancement of  boiler availability  is much more difficult
to estimate than the value of the  availability.   It seems unlikely that coal
cleaning would  enhance the  availability of all  boilers.  On the other hand
many  boilers  are   unavailable  a high percentage of the time, and because  a
large percentage of  forced  outage  is fuel-related, it seems likely that en-
hancement  of  availability  by  PCC  may  increase  capacity  factors  of most
boilers  by  1 to 15 percent.   With such an increase  in  capacity factors,  a
conservative  range of coal  cleaning benefit would be  from about  $0.30 per
ton  of  cleaned coal to $5.00 per  ton of cleaned coal, based on the  figure
cited  above,  i.e., $0.34  per percent  of  availability utilized.   With the
standard  coal   (20 percent  ash, 3.5 percent  sulfur), which TVA  experience
indicates would produce a 6 percent  loss in boiler availability, replacement
of  half of the  unavailable power  at an average value  of  $0.62 per  ton  of
cleaned  coal [($0.90 + 0.34)/2] would yield a savings of about $1.90 per ton
of cleaned coal.

4.2.3   Boiler Efficiency

     Most  companies  report  net   generating  unit  efficiency,  i.e., after
deducting  the  power required to run  the  generating plant.   Three principal
components  are  factored  into the  generating  system efficiency:   the  boiler,
the  turbine,   and  the generator.    Typical  boiler efficiency  is  about  85
percent, turbine efficiency is about 40 percent, and  generator  efficiency  is
about 95 percent.  On that  basis the efficiency of  a  generating system would
be

         0.85 x  0.40 x 0.95  x  100 =  32.3 percent =  0.323 kWhe/kWht

where  subscripts  e and t denote  electrical  and thermal  energy equivalents,
respectively.   System heat  rate would be
         (3413 Btu/kWht)/(0.323  kWhg/kWht) =  10,600

      Losses  in  boiler  efficiency  are  typically  distributed  as  shown  in
Table 11.
                                      39

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                 TABLE 11.  TYPICAL BOILER EFFICIENCY LOSSES
                                  (percent)
Dry gas
Hydrogen and fuel moisture
Air moisture
Unburned carbon
Radiation
Other
Total
5.2
4.4
0.2
0.5
0.3
1.8
12.4
The efficiency of a boiler with such losses would be

        100 - 12.4 = 87.6 percent

which agrees well with the 85 percent figure given above.   The various  effi-
ciency loss categories are discussed briefly.

     Efficiency losses attributable to dry gas occur because all  of the heat
in  the  boiler exhaust  gases  cannot be used  to  generate  steam.   Typically,
the boiler  exhaust  gas  temperature is maintained at  about  250°F.   Reducing
the  temperature 'would   increase  the  boiler  efficiency  but for  practical
reasons  involving  materials  of  construction and  design  limitations,  the
temperature  of  the exit  gas  must  be  kept above the dew point  of the flue
gases.   The  dew  point  depends  primarily  on the  concentration  of  sulfur
trioxide  in  the  gas,  which is a function of the sulfur content of the fuel,
and on  the moisture content of the  flue  gas.   Because PCC reduces the fuel
sulfur  while maintaining  a relatively constant moisture  content,  the  net
effect  is  to lower  the  dew point,  theoretically  allowing  operation  at  a
lower  stack gas  temperature  and at  higher efficiency.   The change in dew
point,  however,   is typically too small to be significant.   Calculations in
Appendix  E  show that coal  cleaning may lower the  exhaust  gas  dew point by
about  10°F,  but  that this yields only a  0.1 percent improvement in  system
efficiency.

     The  efficiency of  a boiler is  also influenced  by the operator's ability
to  fine-tune  it.   Boiler  operators  traditionally accommodate  fuel  vari-
ability  by  adjusting  the  boiler  for  operation  while  burning  the  worst
expected  fuel.   With  less variability in fuel  quality,  the boiler  can be
adjusted  closer to stoichiometric conditions.   It  then requires  less  excess
air and operates  more efficiently.

     Table  12 illustrates  some of the  benefits attainable by reducing  excess
air requirements  as a result  of  PCC.   The  values are  based  on an exhaust gas
C02 content  of  15 percent  and on  the example  coal  with a  moisture content of
4 percent.   The  data  show  that PCC can reduce the dry gas efficiency loss  in
a  boiler by  about 0.3 percent.    The  basis  of  the effect  is that  volatile
matter  in the cleaned coal  increases as a  result of reduction of ash content
(De Lorenzi  1957).
                                      40

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                TABLE 12.   EFFICIENCY OF  RAW AND CLEANED COAL

Heat content, Btu/lb
Sulfur, %
Ash, %
Moisture, %
Fixed carbon, %
Volatile matter, %
Air, lb/106 Btu
Dry gas efficiency loss, X
Raw coal
10,670
3.5
20
4.0
52
24
950
5.2
Cleaned coal
12,000
2.4
10
4.0
59
27
935
4.9
     Boiler efficiency losses from  hydrogen  and  fuel  moisture occur because
moisture  in  the boiler exhaust  gas cannot be condensed to liberate latent
heat.   Each pound of  water  in the exhaust gas represents 1000 Btu of latent
heat that  diminishes  boiler  efficiency.   Moisture  in the  exhaust gas is a
function  of  moisture  in  the  fuel  and in the combustion air,  and  of the
hydrogen  content  of  the fuel.   Coal  cleaning can significantly affect the
fuel moisture.   If  PCC increases  the  coal moisture content to any extent,
the increase will be  reflected in loss  of  boiler  efficiency.

     Since it enters  the boiler  in the vapor  state,  moisture  in  combustion
air does  not  cause a  latent heat efficiency loss.   It is  heated in the com-
bustion process,  however,  and does account  for  a  slight efficiency  loss.
The only effect of PCC on such a  loss would be to provide  greater  uniformity
so  that addition  of excess  air (and accompanying moisture) could  perhaps  be
reduced slightly.

     Carbon losses from incomplete  combustion are principally a function  of
particle  size distribution  of the coal and of variations  in air-fuel  condi-
tions with time and at various locations within the furnace.   It is  unlikely
that coal  cleaning  would have  any measurable effect on  such  losses.   The
moisture and ash content of  the cleaned coal might affect  pulverizer  perfor-
mance,  which  would influence  carbon loss, but we have no  data that  document
the magnitude of such an effect.

     Thermal radiation from the boiler, ductwork, and boiler piping  leads  to
a  reduction   in  boiler efficiency.   These  relatively small  losses   are  a
function  of  the condition  of the  boiler,  Its  insulation,  and the  ambient
temperature; therefore it is not expected that coal cleaning would influence
these losses.

     Other  losses  include  heat   losses  in  bottom ash and  fly ash  and  in
boiler leakage.  Coal  cleaning  may reduce these  losses slightly  because  it
reduces  the  ash content  significantly.    Coal  cleaning  can  moderate  the
slagging  and  fouling associated  with  high-ash  coals so  that less soot
blowing is  needed and  heat transfer  is  enhanced,  increasing  the net effi-
ciency of the boiler system.
                                     41

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     Thus  it appears that  potential  increases in boiler efficiency by  PCC
are limited  to those that can be realized by lowering stack  temperature  (0.1
percent) and by  reducing excess air (0.3 percent).   At a fuel  cost  of $1.00
per million  Btu  ($24.00 per  equivalent  ton of cleaned coal), the  value .of
higher efficiency in terms of lower fuel  consumption is

        (0.4/85) x $24/ton = $0.11 per ton of cleaned coal

     In  conclusion,  it  is estimated  that  the  potential  benefit  of  coal
cleaning through  increases  in boiler efficiency is  probably in the  range of
$0.05  to  $0.25 per ton  of  cleaned  coal,  with  a  typical  value around
$0.10 per ton.

4.2.4  Boiler Capacity

     Effective increases in boiler  capacity allow the boiler system to  meet
more of  the   future  demands  with existing  equipment  and thus postpone  the
date when new equipment must be put into  service.   The benefit is  that power
is  produced  in older,   fully  amortized plants  rather than  in a  new plant.
The utility   can  retain its  accumulated capital  longer and  therefore  can
realize the benefit of  income derived from the unspent capital.  The benefit
is  somewhat  negated by  inflation,  in that  both  the cost of money and  the
cost of  new   construction  will  increase  with  time  and a new plant must be
built eventually.

     Very little can be done to increase  the capacity of a coal-fired boiler
beyond  its   design  capacity,  but  often  changes  can be  made  to  restore  a
boiler to its rated capacity after it has been derated.   Some of the reasons
for derating  a  boiler,  mentioned elsewhere, include limitations of  the  pul-
verizer  and   ash  handling  system  and  capacity  of  the pollution control
equipment.   Sometimes a boiler must be derated because of operating  problems
associated with  a particular  fuel.   Slagging and  fouling  are problems  in
this category.

     Slagging  is   the   accumulation  of  molten  or  tacky  deposits on  the
surfaces of  heat  exchange  components that are exposed  to  radiant heat.   It
is  caused  by reactions  that  occur  when  the mineral matter  is  heated  above
some critical temperature,  so that a liquid phase  is  produced in a portion
of  the  material.    Fouling is  the  accumulation  of  deposits,  normally  by
desublimation and  sintering,  on heat exchange components in the  convection
passes (gas  passes  containing heat exchange surfaces that  cannot "see"  the
furnace,  so  that   the  heat  exchange   is  primarily  by  convection)  at
temperatures   below  the  fusion  temperature  of any of  the  ash constituents.

     The slagging and fouling properties of various coals are each affected
differently  by  PCC.   In general  PCC causes  only a  slight change in  the
overall  ash  composition  of  coal and in its slagging and fouling properties.
                                     42

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     The  expected  effects  of  coal  cleaning  on slagging and  fouling  are:

    0    A  change In ash fusion temperature because of changed composi-
         tion.    The  direction of  change  cannot  be  predicted without
         knowledge  of coal mineral content.

    0    A  reduction In  the  Iron content  of the ash,  making the coal
         less  susceptible to variations in excess air.  Good control of
         magnetite  losses to  the coal  is required.

    0    A  reduction in  overall  ash  content  that reduces slagging and
         fouling and makes the  use of  additives  more efficient.

    0    Removal of soluble  sodium, which  reduces slagging and fouling.

It is believed that the net effect of  these changes  is small.

     Whatever  influence  coal cleaning has on boiler capacity is  extremely
site-specific.    In most  cases  PCC probably will not affect boiler  capacity.
In some  cases,  however,  PCC  can  rectify conditions that would cause rather
severe deratings.   In  such cases this benefit alone  is probably  sufficient
to justify  coal  cleaning.  For example,  where a 1000-MW  boiler that had been
derated 10  percent because  of slagging or fouling could  be restored to  capa-
city  by  cleaning the  coal,  the benefit  could be equivalent to the  revenue
needed to  capitalize  100 additional  megawatts  of capacity.    At  a cost  of
$1000 per kW and an amortization  period of 25 years, and with various  other
input parameters described in  Appendix  C,  the annual savings would be  $23.3
million  per  year  (Foster  1975).   At a 70  percent capacity  factor   for  a
1000-MW  boiler, the  savings  is  3.8 mills  per  kWh,  equivalent  to  about
$9.00 per ton of cleaned coal.   This  probably represents an upper limit for
potential  savings.   In  the typical   case  no capacity  Increase would  be
expected.

4.2.5  Boiler Design

     Many features  of  a  boiler designed to burn physically cleaned coal may
differ from  those  of  a  boiler designed  to  burn raw coal.   Differences in
ash,  sulfur,  and moisture  content  and in  ash composition should all  influ-
ence  the design.   Most  of   the changes  to accommodate  cleaned  coal   should
make  the  boiler   less  expensive.    Possible  differences  that   have been
suggested in an  ongoing  analysis by EPRI are  boiler size, tube spacing, soot
blowing  equipment,  and auxiliary power requirements.   This  EPRI  study also
includes  a  detailed  cost  analysis  that   1s  being  conducted  with  the
assistance of a  major  boiler manufacturer.


4.3   COST SAVINGS  IN EXHAUST GAS HANDLING  AND CLEANING  EQUIPMENT

4.3.1  Collection  Efficiency of Pollution  Control Equipment

      The particulate collection efficiency of a fabric  filter collector will
not  be affected by  the use of  cleaned coal,  but the collection efficiency of
                                      43

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 an ESP may be  impaired  as  a result of higher fly ash resistivity.  Burning
 cleaned coal,  however, would reduce the particulate  loading to the ESP; thus
 the efficiency needed for compliance with a given emission regulation would
 be lower.

      The ESP  efficiencies needed to meet particulate regulations of 0.1 and
 0.3 Ib per million Btu were calculated for a new boiler burning the raw and
 cleaned coals  that are used as a standard throughout this report.  Table 13
 gives results  of the  calculations, shown  in detail  in Appendix  F.   The
 values indicate that cleaned coal  requires a slightly smaller ESP than does
 raw coal to meet  a  given particulate regulation.  Depending on the equation
 selected for  calculating  the  required  specific collection  area (SCA)  and
 depending  on the  particulate regulation, the size of the ESP needed with the
 standard cleaned  coal  is 76 to 95  percent of that needed with the raw coal.
 The lower ash  content  of the  example  cleaned coal  offsets  the relatively
 slight increase  in  resistivity associated with  its lower  sulfur content.
                   TABLE  13.   COMPARISON OF ESP REQUIREMENTS
                   FOR  BOILERS BURNING  RAW AND CLEANED COAL
Parameter
Btu/lb
Ash, percent
Sulfur, percent
Uncontrolled particulates, lb/106 Btu
Estimated resistivity, ohm cm x 109
Particulate regulation, lb/106 Btu
Required particulate efficiency,
percent
SCA (Deutsch), ftVlOOO acfm
SCA (Matts-Ohnfeldt), ftVlOOO acfm
Raw coal
10,670
2.0
3.5
16.04
4.1
0.1 0.03

99.38 99.81
163 200
207 314
Cleaned coal
12,000
10
2.4
7.08
16
0.1 0.03

98.59 99.58
148 190
158 260
     Thus  it  appears  that where cleaned coal  is  to be burned, the required
size of  an ESP for a new boiler may be lower by 5 to 25 percent than if raw
coal were  burned.   The  size difference would  be  reflected  in the capital
cost of  the  ESP,  but  not significantly in operating  costs.   Given that an
ESP  represents about  5 percent of  the capital  cost  of  a power  plant,  a
benefit can be calculated as the savings associated with the capital savings
for the  ESP.   With a 1000-MW plant, a 10 percent savings in the cost of the
ESP, and  a base-case  ESP cost of  5 percent of  the  total plant  cost, the
estimated  benefit  is  $0.45 per ton  of cleaned  coal.   This  value  agrees
reasonably well with  a published estimate of $0.84 per ton of cleaned coal
(Buder 1979).

     In  conclusion,   it   appears  that  PCC  would  produce  no  tangible ESP
benefit for  most  existing  plants,  but might  slightly enhance  ESP perfor-
mance.   New plants might realize ESP capital savings equivalent to $0.25 to
$1.00 per ton of cleaned coal.
                                     44

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4.3.2  FGD Requirements

     In  certain  cases  PCC  can  completely eliminate  the need  for an PCD
system.  Examples include the Homer City coal  cleaning  plant  of the  Pennsyl-
vania  Electric  Company and  the  Camp Breckinridge cleaning plants  for TVA.
In other cases, however, PCC will reduce FGD requirements  only slightly.  As
an example, consider a 500-MW coal-fired power plant burning  our  example raw
coal with  a  heat content of 10,670 Btu/lb, 20 percent  ash,  and  3.5 percent
sulfur.   Net heat  rate  is  10,000 Btu/kWh.   Coal  cost  is  $21.34 per ton
($1.00 per 106 Btu).  The equivalent raw coal  S02 content  is  6.56 Ib S02 per
million  Btu.  When  this coal is cleaned at an 80 percent  weight  yield  and  a
90 percent  Btu  recovery,  the  cleaned  coal  properties are  12,000 Btu/lb,
10 percent ash,  and 2.4 percent sulfur.   If 95 percent of the  sulfur  in the
cleaned  coal  is  emitted as  S02 when it is burned, emissions  would be  3.8  Ib
S02 per  million Btu.

     If  the  power  plant were constrained to emit no more  than 15 percent  of
the  raw-coal  sulfur into the atmosphere on a 30-day average, the equivalent
emission standard  would  be  0.98 Ib S02  per  million Btu.   This constraint
could  be met with  raw coal  by use of  an FGD  system  with  a  nominal  84.2
percent  control efficiency.   If an 85 percent efficient FGO system were used
in  conjunction  with  the cleaned  coal,  87 percent  of  the stack  gas  would
still  have  to  be  scrubbed to  comply with  the  limit of 0.98  Ib S02  per
million  Btu.   The  other  13 percent  of  the  stack gas  could  bypass  the
scrubber.

     Given  the  opportunity,  a  utility  using  raw coal  probably would  not
bother to bypass a small percentage of  its  stack  gas  around  an FGD system
because  the  bypass  gas would not  be  sufficient to provide stack gas reheat
for  the system.  Most scrubber systems reheat  stack  gas to about 175°F  in
order  to minimize corrosion  and  to suppress formation of  exhaust  gas conden-
sate plumes.   A bypass ratio of approximately 30 percent would  be  needed  to
provide  this degree of reheat  without auxiliary heaters.  Moreover, because
the  quality  of raw coal  is  highly variable,  most  utilities would  scrub all
the  exhaust gas  to help ensure compliance with the emission standard on a
required 30-day  average.

     A  utility  burning cleaned coal,  however,  might  take advantage of  the
opportunity  to bypass  13 percent  of  the  flue gas around  the scrubber.  Coal
variability  and  the  design of  an  FGD  system  to ensure  compliance with
emission regulations are issues of particular interest at present.  With a
fixed  emission ceiling, an  FGD  system  should be designed to control  to that
limit   when  the   worst  expected  coal   is   being burned.    Reducing   the
variability  of coal quality  by  PCC would reduce the  need  for  overdesign or
conservatism in FGD design  and  thus reduce the total  FGD system costs.   One
report indicates that  PCC reduces  the relative sulfur  variability in  coal  by
approximately  half,   an estimate  based  on data from  58 different  coal
sources (Versar 1979).

     Values  for our example  raw and cleaned coals were used in computerized
cost  programs  for  FGD  and  PCC systems  to estimate the costs  of two stra-
tegies to attain the S02 emission requirements described above:


                                      45

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    Use  of raw coal and  a  lime FGD system to scrub  100 percent  of  the
    boiler flue gas.
    Use of cleaned coal and a lime FGO system to scrub 87 percent of  the.
    boiler  flue gas,  bypassing 13 percent  of  the flue gas  to  aid  in
    meeting reheat requirements.

supporting calculations  appear in Appendix B; Table  14 shows  salient  data.

            TABLE 14.  FGD COSTS FOR RAW AND CLEANED COAL SYSTEMS

Coal HHV, Btu/lb
Coal ash, percent
Coal sulfur, percent
Flue gas bypass, percent
Total capital cost, $/kW
Total annual cost, mills/kWh
Raw coal
system
10,670
20
3.5
0
123
7.6
Cleaned coal
system
12,000
10
2.4
13
102
5.9
     The principal savings with the cleaned coal system result from a reduc-
tion in the size of the required FGD system, and from lower requirements for
reheat,  reagents,  and  sludge  handling  and disposal.   The PCC benefit  is
estimated  to  be  the difference  between annual  costs of  the  two systems:

        7.6 -  5.9 = 1.7 mills/kWh

which is equivalent to about $4.08 per ton of cleaned coal.

     The PCC  benefit is  a  function of  the allowable bypass ratio;  as the
ratio  increases,  PCC becomes  increasingly cost-effective.   Figure  8 shows
the  interrelationships  among S02  emission  regulations,  PCC  sulfur  removal
efficiency, FGD efficiency,  and the allowable bypass percentage.   At an S02
emission control  level  of   90  percent,  the  allowable bypass  ratio cannot
exceed 16 percent and  approaches  that value only as  PCC  removal  efficiency
exceeds 40 percent  and  FGD  efficiency approaches 95  percent.   At  lower S02
control levels,  the allowable bypass fraction  becomes progressively higher
as  other  parameters  remain  constant.   For example,  at an  S02  regulation
level  of 80 percent, FGD efficiency  of 95 percent,  and PCC  sulfur  removal
efficiency  of  30  percent, the  allowable  bypass  ratio is  about 25 percent.

     The bypass ratio  at  which auxiliary reheat requirements are eliminated
completely  is  mainly a  function  of the boiler exhaust  gas temperature and
the required reheat temperature.  After leaving the boiler, gases are cooled
to  about 125°F in the  FGD  system.   At  a boiler  exhaust gas  temperature of
275°F and a required reheat temperature of 175°F, the required bypass  ratio
is  about 33 percent.   Figure 8 shows that when S02 emission regulations are
higher than about the 70 percent level,  the allowable bypass ratio cannot be
as  high  as 33 percent  and  that some auxiliary reheat will  be  needed.   The
potential  elimination  of auxiliary  reheat  is  an important benefit  of PCC
                                     46

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c
QJ
u
i-
O)
Q.
I/O
«£
O-
     100 H
      90-
                                                   EACH ENVELOPE BOUNDS
                                                   SCRUBBER EFFICIENCIES
                                                   FROM 85 TO 95 PERCENT,
       30
       20
       10
          0        10       20       30       40       50

                     SULFUR REMOVED BY PCC, percent

          Figure 8.  Effect of PCC sulfur  removal  efficiency on
          allowable  FGD bypass under  various  S02  removal regulations
                                    47

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both  because  of economics  and because the maintenance of  reheat  equipment
has been particularly troublesome at many FGD installations.

     In  conclusion,  the typical  PCC  benefit  associated  with  lower  FGD
requirements may be on  the  order of $4.00 per  ton  of cleaned coal.   Parti-
cularly restrictive  S02  regulations  could reduce this benefit to  near-zero,
whereas less  restrictive regulations  could  increase the benefit  enough  to
offset  the  total  cost  of  PCC  in some cases.   At very  low  levels of  S02
regulation  the  use  of  PCC  could eliminate the  need for FGD.   Appendix F
shows that  the  annual cost  of FGD to remove 85 percent of the sulfur is  7.6
mills/kWh,  equivalent to $18.00 per ton  of cleaned  coal.   The use  of  PCC
alone could not  ensure  compliance with an 85 percent  regulation,  but  could
ensure  compliance  at the level  of about 40 percent.  Therefore,  the  upper
limit  of  the  benefit  is  estimated to be  about  half  of the $18.00,   or
$9.00 per ton  of cleaned coal.
                                     48

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                                  SECTION  5

               CONCLUSIONS  AND RECOMMENDATIONS FOR FURTHER .WORK
5.1  CONCLUSIONS

     The available  data  show that  increased use of  PCC has potential for
producing great benefits in  terms  of reduced costs of power production and
environmental control.

     Potential benefits are greatest where maximum reductions  in  ash  and py-
ritic sulfur  contents  can  be attained without excessive  loss of  coal  in the
rejected refuse.---In this  study  we assume  relatively modest reductions  of
10 percent in ash  and  1.1  percent  in pyritic sulfur.   The estimated  savings
exceed  projected  costs of  coal  cleaning  in  six of eight  coal  preparation
plants  used   as  a  basis  for comparison (Table 4).   For  all  six of  these
plants,  Btu   recovery  equals  or  exceeds  90 percent.    Because  total  coal
cleaning costs are highly dependent on Btu recovery,  it is vitally important
to consider this factor in any analysis.

     One  of   the  most important  potential  savings  is associated with  the
reductions in the  cost  of FGD that can be realized by  partial  removal  of
sulfur  by  PCC before  combustion.   At the PCC  sulfur  removal  level  assumed
for  this  study,  about  32 pounds of  sulfur per  ton  of raw coal,  the savings
in  FGD  costs  achieved  by  burning  clean rather  than   raw  coal is  about
$4.00 per  ton  of  cleaned  coal.   This  is  the most   significant  typical
benefit;  the total  of  all  of  the  typical  benefits is $7.02  per  ton  of
cleaned coal.   For five  of the eight coal preparation plants considered in
this  study,  sulfur reductions ranged from 18 to 55 pounds of sulfur per ton
of raw  coal.   Reductions of  this magnitude would produce  significant savings
in an  FGD  system designed for  a  boiler  burning cleaned  coal instead of raw
coal.

     PCC can  lead  to important  savings in  boiler operation, especially where
increases  in boiler availability or  boiler  operability  can offset shortages
of productive capacity in  the system.  All of the potential boiler operation
benefits  appear to be associated  with reductions in ash  and sulfur  content.
Typical boiler-related savings,  based on cleaning  the  example  raw coal to
achieve a 12 percent  reduction in  A+S,  are $2.40  per ton of cleaned  coal.
Among  the  eight coal cleaning  plants used as  a basis  for comparison,  reduc-
tions  of A+S ranged from  8 to 33 percent.   For  the  five showing  greatest
reductions,  the values were  20 to 33 percent.   These findings  suggest  that
savings related to  boiler operability  can  be  very  important where  boiler
output  is  lost  because of  poor  coal  quality.


                                      49

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     Transportation  savings  appear to  be  the most certain  benefit,  except
for  mine-mouth  power  plants;  savings  are  proportional  to  transportation
costs, but  even  for relatively long hauls (e.g., transport of western coal)
the  transportation  benefit is  not sufficient to  offset  the total cost  of
coal cleaning.

     Although the benefits that might be realized through Increased  use  of
coal cleaning are apparently great, the data with which to define the  extent
of the potential  savings  are  admittedly weak.  Additional work  to  quantify
the potential benefits appears to be much needed.


5.2  RECOMMENDATIONS FOR FURTHER WORK

5.2.1  Calculation of Benefits Based on Published Data

     Basic  coal  washability  data can  be  used to  quantify  several  of  the
benefit parameters  discussed  in this report.  Washability data  compiled  by
the U.S.  Bureau  of  Mines  in  Report RI 8118 can be  used  in evaluating those
benefit parameters.   Several  scenarios  should be defined to reflect current
and  proposed new  source  performance  standards (NSPS)  and  best  available
control technology  (BACT)  regulations.  Analyses  would compare  the  use  of
FGD with  the combined  use of FGD  and  coal  cleaning so as to  determine  the
relative  effectiveness  of the  two control strategies at  plants  subject  to
specified restrictions.   This  study would consist of:

    0    Definition of an evaluation methodology
    0    Definition of a scenario or scenarios to be evaluated

    0    Reduction of 8118 data for evaluation
    0    Quantification of benefits for each coal
    0    Tabulation and presentation of results and conclusions
    0    Extrapolation of potential  economic costs and benefits achiev-
         able by use of PCC.

5.2.2  Coal Appraisal Research

     Research should  be directed  toward an  accurate  economic appraisal  of
coal, i.e., the evaluation of  coal based on the cost impacts of firing it in
a  boiler.   Bonus-penalty evaluations  would be based  on  such parameters as
ash content, other coal constituents, boiler design, and environmental regu-
lations.   Such  evaluations would  enable a  buyer  to  select  the most cost-
effective  fuel  from among  two or  more coals.  At  present most  coals  are
selected   on the  basis of  meeting  certain minimum  specifications  at  the
lowest price  per Btu,  or even worse,  at the lowest price per ton.   Adverse
or  beneficial  effects  on boiler  operation  generally are  not considered.
Following would be the principal tasks of the evaluation:
                                     50

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    0    Develop a model  that  relates boiler operating and maintenance
         costs to fuel  quality.

    0    Develop a formula  for  calculating  net fuel cost in mills/kWh.

    0    Project  the  potential  economic  effects  of such  a selection
         procedure.

5.2.3  Research to Verify Effects of Coal  Quality on Boiler  Operation

     Research should be carried out to verify the effects  of coal quality on
boiler operation that  are  discussed in this study.   Significantly  different
coals  would  be burned  in  several  carefully  selected  boilers considered
identical or  nearly identical  in construction,  condition,  and  performance.
Extensive tests  would  be  run to allow documentation of  coal quality effects
over a relatively  long term (3 years).  Participation by the boiler  owners
would be necessary.

     Following are potential program tasks:

    0    Attempt to locate  substantially  similar boilers firing coal  of
         different  quality.   This  would  entail  contacts  with  boiler
         manufacturers and boiler owners.

    0    Obtain  data  from  boiler  operators  concerning coal  quality,
         boiler  duty,  maintenance  practices,  performance,  and  other
         aspects of boiler  operation.

5.2.4  Boiler  Derating Study

     Field  methods  being  used  to derate boilers to accommodate  poor coal
quality  or particular coal  idiosyncrasies   should  be investigated.   We are
relatively  certain  that  many  boilers  are  derated because  of  pulverizer
limitations  or  are being  operated in a  special  manner  for firing of sub-
standard coals.   A survey  to determine the  extent of these  practices and the
economic or  capacity  penalties  associated with such  off-design operation
would  be extremely beneficial   in  further  quantification of potential coal
cleaning benefits.   Among  PEDCo's  utility contacts  are   several  that  we
believe  would  be willing  to  discuss their  coal-related  boiler operating
problems and their attempts to  use coal  that the  boilers  were not designed
to burn.   The study would  consist of:

     0    An estimate  of the proportion of  utility boilers  that are  de-
         rated to accommodate  variable or inferior coal  quality

     0    An  estimate  of  the  number of  boilers  that  are  pulverizer-
          limited

     0    A determination of the economic consequences  of off-specifica-
          tion operation  and a  projection  of capacity  improvements  and
          other  economic  benefits  that could be achieved  by  upgrading
          coal
     0     Establishment of  relationships  of these factors and the poten-
          tial use of coal cleaning


                                      51

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                                 REFERENCES
Babcock  &  Wilcox.   Steam - Its Generation and Use.   37th  Edition,  B&W,
New York, 1960, pp. 17-19.

Buder.M. K. ,  et  al.    The  Effects  of  Coal  Cleaning  On  Power  Generation
Economics, American Power Conference, 1979.

Cavallaro,  J.  A., et  al.   Sulfur  Reduction  Potential  of  the  Coals  of the
United States.  U.S.  Bureau of Mines, RI 8118, 1976.

DeLorenzi,   0.     Combustion Engineering.    Combustion   Engineering,   Inc,
New York, 1957.

EEI.  Report on Equipment Availability for the Ten-Year Period 1968-1977.  A
report of the equipment availability task force of the Prime Mover's Commit-
tee, of the Edison Electric Institute.  New York, December 1977.

Foster Associates, Energy Division.  Tennessee Valley Authority's S02Compli-
ance  Plan:    Coal   Availability.    U.S.  Environmental   Protection  Agency,
Region VI, September 22, 1977.

Hall,  E.  H.,  et  al.   The  Use of  Coal   Cleaning  For Compliance  With SCL
Emission
Regulations.  Draft  report  from Battelle Columbus Laboratories to U.S. EPA.
1979.

Hoffman, L., S. J. Aresco, and E. C. Holt, Jr.  Engineering/Economic
Analyses of Coal   Preparation  with S02Cleanup Processes  for Keeping Higher
Sulfur Coals  in  the  Energy Market.  U.S.  Department of Energy, Washington,
D.C., November 1976,  pp. 236-241.

Holt, E. C., Jr.   An Engineering/Economic Analysis of Coal Preparation  Plant
Operation and Costs.   Final report to U.S. DOE by the Hoffman-Muntner Corp.,
Contract No. ET-75-C-01-0925, Silver Springs, Md., February  1978

Kilgroe, J.  D.   Combined  Coal  Cleaning and FGD.   U.S. Environmental Protec-
tion Agency, 1979.

McGraw,  R.   W. , and J.  G.  Janik.   MCCS--Implementation  at Homer City.  Pro-
ceedings,  Third   Symposium  on  Coal  Preparation,  NCA/BCR  Coal  Conference,
Louisville, KY.,   October 1977.  pp. 107-122.

Phillips, P.  J. ,  and  R.  M. Cole.    Economic  Penalties Attributable  to Ash
Content of  Steam Coals.   AIME Annual Meeting,  New Orleans, February  1979.

Sarikas, R.  H.  Procedure for Converting Utility Investment  and Expense Into
Annual   Revenue  Requirements.    Foster  Associates,  Inc.,  Decatur,   111.,
February 1975.
                                     52

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                            REFERENCES (continued)


Spaite, P. W.,  et  al.   Environmental Assessment of Coal Cleaning Processes:
Technology Overview.   Draft report  from  Battelle Columbus  Laboratories  to
U.S. EPA, 1979.
Strauss, W.  Industrial Gas Cleaning.  Pergamon Press, Oxford, 1966.
Versar,  Inc.   Special  Technical  Report:   Effect  of  Physical  Coal  Cleaning
Upon   Sulfur   Variability.    Draft   report,   EPA  contract No.  68-01-2199,
Task 600,  U.S.  Environmental  Protection  Agency, IERL,  Research  Triangle
Park, N.C., January 1979.
Zimmerman, O.T., and I. Lavine.  Psychrometric Tables and Charts. Industrial
Research Service, Inc., Dover, N.H., 1964.

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   APPENDIX A
LITERATURE REVIEW
    54

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Anson,  D.   Availability of Fossil-Fired Steam Power Plants.  EPRI  FP-422  SR,
Palo Alto,  California, June 1977.

The  availability of 600  MW and larger generating units is  compared  with  the
availability of  smaller plants.   The annual present worth of the outage costs
is estimated.  The  annual present worth of increasing the availability of  the
600  MW and greater generating  units to  that of the  smaller  units  is also
estimated.   The  report concludes  that increasing the availability of 600 MW
and greater units from 73 percent to 80 percent has an annual present worth of
$150 to 200 million.
Babcock and Wilcox.  Steam - Its Generation and Use.  37th ed, New York, 1960.

This  standard  reference on  boilers  and steam generation was  first  issued in
1879  and has  been  revised  numerous  times.   The  book contains  chapters  on
subjects  as  diverse  as fuels,  principles of  combustion,  stacks and  ducts,
fans, heat transfer, fluid dynamics,  energy cycles, boilers and related equip-
ment,  coal preparation and storage,  stokers, pulverizer  equipment,  fuel  ash,
metallurgy, and nuclear power.

This book is  prepared and published by B&W, one of the largest boiler manufac-
turers  in the  United States.   Until  recently the  book  was  distributed gratis
to  senior mechanical  engineering students at universities across the country.
Bechtel  Corporation.   Environmental Control  Implications  of Generating Elec-
tric  Power from  Coal.    1977  Technical  Status  Report.   Appendix A,  Parts 1
and 2.   Coal  Preparation  and  Cleaning  Assessment  Study.    Prepared  for U.S.
Department of Energy,  Division of Environmental Control, Technical Assistance
Section for the Environment.

This  report  is  a  state-of-the-art and  effectiveness  study of  physical coal
cleaning for S02 control.  The report discusses how PCC changes the properties
of coal, and  how  these changes affect  coal  utilization.   Additionally, wash-
ability  data  and  coal  reserves  data are integrated into  a common data base.
Bogot,  A.,  and R.  P.  Hensel.   Considerations  in Blending  Coals  to Meet S02
Emission  Standards.   Presented at the NCA/BCR  Coal  Conference and Expo. Ill,
October 19-21, 1976.

The  coal  parameters that  must be considered for  effective  coal  blending are
discussed.  The significance of the coal properties and examples of the  chang-
es that result  from coal blending are presented.  The possible impacts  on the
boiler  resulting  from  the  important coal properties are given.  A significant
conclusion of  the  report  is  that  the  properties of  blended coals are  often
worse than those of the individual coals used in the blend.
                                     55

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Buder, M. K., et al.   The Effects of Coal  Cleaning on Power Generation Econom-
ics.  Presented at the American Power Conference, 1979.

This  paper  describes the  results  of seven  hypothetical  case studies  of  the
effects  of  coal cleaning  upon various components of electric generating  sy-
stems.   A  representative  coal  along  with  the  costs to  clean  the  coal  are
described for  each of the seven cases, and  three different levels are devel-
oped  for  each.   The  benefits of coal cleaning are estimated in  the following
areas in each case:

     Coal transportation
     Power  generation
     Coal handling
     Pulverizers
     Steam  generator
     Ash  handling
     Particulate removal system
     Flue gas desulfurization
     Sludge handling  and disposal

The  paper concludes  that the  results of  this  study cannot be broadly  applied
because  of  the heterogeneity  of  coal.   The  paper also  indicates  that some
pertinent data  are not available.
Burbach,  H.  E. ,  et al.  Compatibility Between Furnaces and  Fuels Conducive to
High  Boiler Availability.  Power, December 1977, pp. 41-46.

The  report discusses  the  more important fuel properties and their impact on
boiler  design.   The relative size of  the  furnace for various  fuels  is  shown.
The  report supports the theory that boiler  manufacturers have the ability to
design  a universal boiler capable of  burning any fuel.   It is  impractical to
do  so,  however,  because of  the widely varying fuel properties  and the  degree
of overdesign and/or  inability to optimize the boiler  design.

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Cavallaro,  J.   A.,  et  al.   Sulfur  Reduction Potential of  the Coals  of  the
United States.  U.S. Bureau of Mines Research Investigation 8118, 1976.

This  report gives  results  of  a  washability study  of 455 raw  coal  channel
samples with special emphasis on sulfur reduction.  These raw coals contained,
on  the  average, 14.0 percent ash,  1.91 percent  pyritic sulfur,  and 3.02 per-
cent  total  sulfur.   Complete washability data are presented  for each  sample
processed.  A statistical evaluation is included for coal beds from which more
than  10  samples were collected  and for  the  geographical  coal  producing  re-
gions.   A  graphical  summation  is  given  for the  coal  producing  regions  and
selected  coalbeds.   A  similar  statistical evaluation is included showing com-
posited  data  interpolated at Btu  recovery  levels  of 50, 60,  70,  80,  90,  and
100 percent.  Graphical  summations are given for the  various coal producing
regions.   Generally, significant sulfur reduction is achieved if the coals are
crushed  to  a finer  size and the  higher  specific gravity  increments  are re-
moved.   If  a  50 percent Btu recovery  were  acceptable,  then 32 percent of the
samples tested  could be upgraded to meet the current EPA standard of 1.2 Ib of
S02  emission  per million  Btu when crushed to 14-mesh  top  size and separated
gravimetrically.
Cole,  R.  M.   Economics of Coal Cleaning and Flue Gas Desulfurization for Com-
pliance with Revised NSPS for Utility Boilers.   Presented at the U.S. Environ-
mental  Protection Agency  Symposium  on  Coal  Cleaning  to Achieve  Energy and
Environmental Goals, Hollywood, Florida, September 11-15, 1978.

The  report  presents three  comparative case studies.   Each  case compares the
economics of  a  combined PCC-FGD system to an FGD system for S02 control.  The
benefits of PCC identified are:

     Transportation cost savings
     Maintenance cost  savings
     Ash disposal cost savings
     Peaking capacity  improvement
     Rated capacity improvement
     Availability improvement


The  report  concludes  that  PCC is a  cost-effective  S02 control strategy, re-
gardless of S02 emission requirements.
Colving,  T. ,  and V. P.  Smith.   A Survey of Econometric  Models of the  Supply
and  Cost  Structure  of Electricity.   EPRI  EA-517-SR,  Palo  Alto, California,
March 1978.

The  report  reviews  a  large number  of economic models of the electric  power
industry.    A commentary  and  summary  of  each  of  the models  reviewed in  the
report are given.

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De Lorenzi,  0.   Combustion  Engineering.   Combustion  Engineering,  Inc., New
York, 1957.

This  reference  book  on combustion  and steam  generation  is  published by a
leading U.S. manufacturer  of boiler equipment.   The book covers a  variety of
topics such as coal production, stokers, pulverizers, pulverized fuel  burners,
furnaces, burners, fluid cycles, A.S.M.E. boiler construction code,  steam gen-
erators, superheaters and desuperheaters, steam purification, feedwater, test-
ing  of  steam generating units, fans and chimneys, instruments, fly  ash drying
and  incineration, and operation and maintenance of equipment.
DeRienzo,  P.  P.,  et al.  Comparative Economics of Sulfur Removal from Coal in
Electric  Power  Generation.   Presented at the 4th Annual International Confer-
ence  on   Coal  Gasification,  Liquefaction,  and Conversion  to  Electricity,
August  2-4, 1977.

This  report identifies  the following  coal cleaning benefits:

      Transportation  savings
      Reduced  pulverizer and boiler O&M cost
      Reduced  ash  handling.

The report concludes that, for  the case  studies  presented, nominal washing  in
combination  with  FGD  was  consistently  more  economical than  FGD alone.   No
evaluation of the coal  cleaning  benefits  is  presented.
 PeRienzo, P.  P.,  et al.   Is Coal  Preparation Cost Effective for Sulfur Removal
 in Electric Power  Generation?  Presented  at the 85th National  Meeting of the
 American Institute of Chemical  Engineers,  June 4-8,  1979.

 The benefits of coal cleaning identified in this report are:

      Transportation
      Reduced pulverizer and boiler O&M cost
      Reduced ash handling and disposal

 Ho specific methodology  for evaluating the benefits is presented.  The report
 concludes that "...washed coal in conjunction with FGD can be a cost-effective
 fuel option for  meeting  various  S02  emission  levels,  but this depends on the
 coal and the S02 emission level to be achieved."
                                       58

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DeRienzo,  P.  P.,  et  al.   The  Cost of  Sulfur  Removal  from Coal  in Electric
Power  Generation.   Presented at the Miami  International  Conference  on Alter-
nate Energy Sources, December 5-7,  1977.

This report presents  a specific case  study  that evaluates the Impact of .coal
cleaning  on  the cost  of  power generation.   An  eastern coal and  a Midwestern
coal are  examined.   Two levels of  coal cleaning are included in the analysis.
Benefits  for  transportation, boiler  O&M cost,  and  ash handling  and disposal
are considered.  No specific methods  or data on the benefits  are identified.
It is concluded that PCC in combination with FGD is a cost-effective method of
achieving various S02 emission  levels.
Duzy,  A.  F.  and  D.  W.  Pacer.   Low-grade  Fuel  Influence on  Boiler  Design.
Presented at  the  1978  Joint Power Generation  Conference,  Session 3,  Septem-
ber 10-13, 1978.

The  major coal  properties  that influence  boiler  design are  identified,  and
their  influences  on  the boiler design are  discussed.   The proper use of coal
property  data,  toge-ther with emphasis on past experience in boiler design and
operation, are  considered necessary for successful boiler design.  The report
stresses  that  proper  consideration  must be  given  to  coal  beneficiation.   En-
richment  of  one  coal  property  can  cause   degradation  of others, which  can
adversely affect the boiler design.
Edison Electric Institute.  The Equipment Availability Task Force of the Prime
Mover's Committee.   Equipment  Availability for the Ten-Year Period 1968-1977.
The Edison Electric Institute, New York, 1977.

This  report  compiles current  data on component and  generating system avail-
ability for  member utility  participants  according to  various fuel  and  unit
size classifications.
Foster  Associates.   Tennessee Valley  Authority's S02  Compliance  Plan:   Coal
Availability.  Draft Report.  U.S. Environmental Protection Agency, Region VI,
1977.

This  report  describes the  findings of  a study of the  availabilty of coal  to
TVA within the context of TVA's plan to comply with S02 regulations at each of
its  fossil-fired power  plants.   The report includes  a  description of the TVA
coal  transportation  system and indicates  certain applicable freight tariffs.
                                     59

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Gibbs  & Hill, Inc.   Coal  Preparation for  Combustion  and Conversion.   Final
Report.  EPR1 AF-791, Project 466-1, Palo Alto, California, May 1978.

This  report  is  primarily concerned with the direct  cost  of coal cleaning and
its impact on the cost of utilization.  The benefits of coal cleaning examined
are:

      Coal taxes
      United  mine workers (UMW) contributions
      Transportation
      Coal blending
      Handling and storage
      Grinding and pulverizing
      Ash disposal
      Precipitators
      Flue gas desulfurization
      Unit availability

The coal taxes,  UMW contribution,  transportation,  grinding and pulverizing,
and ash disposal benefits are  quantified.   Only  the transportation  benefit  is
discussed  thoroug-'y.  No formulation or  methodology  is  presented that  showed
tne net effect  of  the benefits  on  the cost of  utilization.
 Gluskoster, H. J. , et  al.   Trace Elements in Coal:   Occurrence  and Distribu-
 tion.  Illinois State Geological Survey Circular 499, 1977.

 This circular presents  a  very thorough analysis of 172 coal samples.  Most of
 the  samples  were from  the  Illinois Basin.   Each sample was  analyzed for 60
 elements.  Most  of the  samples were face-channel samples.   There were usually
 multiple  samples taken in  the various mines.   Additionally,  the  coal  seams
 were frequently  sampled in more than one mine.  Some bench samples showing the
 vertical variation of the coal were also taken.

 Of  several conclusions from  the data,  the  most  significant  one is that the
 coal varies radically throughout its matrix.
                                       60

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Hall, E. H., et al.  The use of Coal Cleaning for Compliance with S02  Emission
Regulations.   Draft  Report written  for  Battelle's Columbus  Laboratories  for
the U.S. Environmental Protection Agency, Columbus, Ohio,  1979.

Results of an overall  evaluation  of the  possible use of coal  cleaning as  a
means of  controlling S02  emissions  are presented.   Data presented  show  PCC
economically superior, even when supplemented with flue gas cleaning for final
sulfur removal, to alternative strategies involving the use of low sulfur coal
or the use of flue gas desulfurization alone.

Barriers  (technical,  institutional,  economic,  etc.)  tending to prevent  the
application of physical  coal  cleaning as a pollution control method are iden-
tified,  and programs needed to overcome them are recommended.
Hoffman,  L. ,  et al.   Engineering/Economic  Analyses of  Coal  Preparation  with
S02 Cleanup  Processes for  Keeping  Higher Sulfur Coals  in  the  Energy Market.
U.S. Department  of  Energy,  Washington,  D.C.,  November 1976.    pp.  236-241.

For purposes  of  this  study, higher sulfur coals from the Northern Appalachian
and Eastern  Interior  Regions  were selected since they have been shown to have
reasonable physical cleaning  potential.   Possible users of these coals in the
electric power generating industry are established,  along with the environmen-
tal constraints  in  their  respective  localities.   This provided  a  framework
within which to study and compare the economics associated with meeting sulfur
emission standards in two alternative ways.   Specifically, the study considers
both new and existing plants using either combined physical cleaning and stack
gas scrubbing or sulfur cleanup exclusively by stack gas scrubbing.

The results  of the  study  indicate that  many higher  sulfur  coals physically
cleaned to  a weight yield  of 90 percent begin to  approach environmental ac-
ceptability.    This permits  the  installation of  an  economically attractive
partial stack gas scrubbing system to bring the power generating facility into
compliance with existing emissions standards.   The economics associated with a
combined approach  when  compared with the exclusive use of stack gas scrubbing
demonstrate a definite advantage.
                                     61

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Holmes, J.  G.,  Jr.   The Effect of  Coal  Quality on the Operation and Mainte-
nance of Large Central  Station Boilers.   Presented at the  Annual AIME Meeting,
Washington, D.C., February 16-20,  1969.

The  various aspects of  the effect of  coal  quality  on  boiler operation  are
discussed.  Most of  the  paper relates to general trends  and/or discussions of
cause-and-effect  relationships of  coal  quality and  boiler  operation.   The
section on operating and  maintenance costs  (O&M) provides some  specific  in-
formation  on  cost   penalties  associated with  variability in coal quality.
Specific cost information is absent in the other sections of the paper.

Data on the O&M costs at Kingston and John Sevier, two similar TVA plants,  are
compared.   The fuel  data are the average proximate analyses of all fuel  burned
at each plant.  The  O&M costs are an average of the yearly O&M cost per ton of
fuel.

The  paper  points  out  that the  plants had significantly  different  capacity
factors  and that the capacity factors  could cause significant differences in
plant  O&M  cost.   Such  differences  are difficult to  quantify  and are  not in-
cluded  in  the  analysis.   The paper  concludes  that  as  coal  quality deterio-
rates, O&M costs'increase.
 Holt,  E.  C. , Jr.  An  Engineering/Economic  Analysis  of Coal Preparation Plant
 Operation and Costs.  Report to  U.S. DOE  by the Hoffman-Munter Corp., Silver
 Springs,  Maryland, February  1978.

 This  report  presents a  discussion  of  the  major physical  coal   preparation
 processes currently  available and the equipment  used  by each process  to effect
 a separation  of the coal from the  undesirable  constituents (such as  ash  and
 pyritic sulfur).  Eight  specific  examples  of a wide  range  of  actual prepara-
 tion  plants  are examined  from  the  standpoint  of capital  and operating  and
 maintenance costs to  develop a  total  cost  of  coal   cleaning  for  each plant.
 The preparation plants examined  were all  operating as  of  mid-1977 and span a
 spectrum of cleaning processes  from a relatively simple jig plant  to sophisti-
 cated  circuits  utilizing dense  medium,  froth  flotation,  and  thermal  drying.

 For the  particular  plants  considered by this study,  cleaning costs range from
 over  $3.00 to  nearly $5.00 per  ton  of  clean coal produced.   These  costs  are
 especially sensitive  to  the makeup and performance of the cleaning circuit in
 addition to  the manner  in which it is  being operated.  In this latter regard,
 plant  utilization can be a significant factor  since  it influences the output
 over which the  fixed costs are amortized.   As evidenced by most of the prepar-
 ation  plants  examined, many coal cleaning  facilities operate  only 30 percent
 of  the time,  thereby experiencing a relatively high  capital burden per ton of
 clean  product.   To  alleviate  this  problem, one of  the  example preparation
 plants was designed  to  include  parallel  cleaning  circuitry  with significant
 amounts  of  redundant  equipment.   Such a  plant configuration  permits  main-
 tenance without shutting down the entire facility.
                                       62

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Honea, F.  I.,  et al.   The Effects  of  Overfire Air and Low Excess Air  on  NO
Emissions  and  Ash  Fouling Potential for a Lignite-Fired Boiler.   Presented a£
the American Power Conference, April 24-26, 1978.

Test  runs  at  Hoot  Lake Station of  Ottertail  Power Company are reported.   The
lowest possible  NO  levels  at a given  boiler  load  are  determined.   Various
burner configurations are studied to determine burner influence on the fouling
potential  of  the coals (lignite).   The report concludes that burner selection
appears to influence  ash fouling potential and that reducing NO  emissions by
varying  the burner  configuration  increases  the  potential  for  ash  fouling.
Isaacs, G. A.   Physical  Coal  Cleaning for Sulfur  and  Ash Removal.   Presented
at  the  Twelfth Air  Pollution and Industrial Hygiene  Conference,  Air Quality
Management in the Electric Power Industry, January 28-30, 1976.

TVA coals and  their  washability are discussed.   Boiler availability is repre-
sented  as a  benefit of  coal  cleaning.   The report  states that  the boiler
availability benefit is intuitive.
Isaacs, G. A.,  et  al.   Studies to Define  the  Role of Coal Cleaning in an S02
Control  Strategy  for  TVA.   APCA  Paper No.  77-14.4.   Presented at  the  APCA
Annual Meeting, June 20-24, 1977.

The  report  gives  a brief  discussion  of  the  various physical  coal  cleaning
processes.  Specific TVA  washability data and appropriate emission limits for
the TVA plants  are  cited.   The relationship of the cleaned coal to the appro-
priate TVA plants are  discussed.   The report concludes that possible applica-
tion of PCC to meet S02 emission  requirements  are limited,  but the number of
applications may be significant.
                                     63

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Kilgroe, J. D.  Combined Coal  Cleaning and FGD.   U.S.  Environmental  Protection
Agency, 1979.

physical coal  cleaning  (PCC)  can  be used to attain moderate reductions  in the
ash  and sulfur levels  of the U.S.  coals.   PCC can thus be used to  generate
compliance fuel for  the less  stringent State and  Federal  standards governing
fossil  fuel   fired  steam generators.  The  sulfur reduction requirements  and
emission  levels that are likely to  be  specified in  the revised  New  Source
Performance  Standards (NSPS)  for electric  utility boilers will  preclude the
USe  of coal  cleaning as  a sole method of complying with these flue gas  desul-
•furization (FGD) regulations.

The  combined  use  of   physical  coal  cleaning  and  flue  gas  desulfurization
(PCC + FGD)  will  be the  most cost-effective method of complying with emission
regulations,  if the reduction in FGD and non-FGD  costs that result from using
cleaned coal  are greater than  the  costs of PCC.  Reductions  in FGD costs by
PCC  can result  from a  reduction  in the volume  of  flue gas treated (partial
scrubbing)  or the amount of  sulfur removed from the flue  gas stream.  Reduc-
tions  in  fuel  sulfur variability by PCC  can lower  design  safety  margins needed
to ensure compliance  for all fuel  sulfur  values.  Non-FGD cost benefits can
result from reduced boiler operation  and maintenance  costs, reduced  transpor-
tation costs,  reduced  disposal  costs,  and reduced coal pulverization costs.

Utility boilers  that  use high sulfur coals and  require sulfur  removals  less
than  75 percent are likely candidates for  PCC + FGD.   If the  revised NSPS for
 utility boilers require  90 percent sulfur  removal and do not  specify an  emis-
 sion  floor,  then PCC +  FGD may not  be  competitive  with FGD  unless  there are
 substantial  non-FGD cost benefits associated with cleaning.

 The  range  of applications  for PCC  +  FGD in  small  non-base-loaded  utility
 boilers and  industrial  boilers may  be  different from those cited  for  base-
 loaded utility boilers.  The  differentials between PCC and FGD costs for these
 smaller units  may  result in  different optimal  solutions  for  the  range of al-
 ternative control strategies.
 Kohn,  H.    Capacity  Factor  Evaluation of  Fossil  Fired  Power  Plants.   Power
 Engineering, October 1978.  pp. 56-58.

 This  article  presents  EEI data on  capacity factors, availability, and  forced
 outages  of selected units.   From  various  analyses the  capacity factors  and
 capacity  factor  distributions  are nearly the  same  for  fossil-fired and  nuclear
 units.  The article concludes  that,  "the single  most effective  way to decrease
              down  time would  be to institute  a  coal benefication program."

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 Leung,  P.,  and L.  E. Booth.  Power System Economics:  On Evaluation of Avail-
 ability.  ASME Paper No. 78-JPGC-Pwr-3.  Presented at the Joint ASME/IEEE/ASCE
 Power Generation Conference, September 10-11, 1978.

 A  number of methods  for economic evaluation of power  plant availability and
 productivity are presented in this report.  Numerical examples are given with
 assumed  values.  Each  of the methods used  in  the  report is discussed and the
 areas where more  study  or information is needed  are  identified.   The report
 concludes  that "system  generation planning analysis  should be conducted  to
 establish all pertinent economic factors, criteria, and values."
Librizzi,  F.  P.  and H.  S. Arnold.  Outage Factors - An Aid to Analyzing Elec-
tric  Generating Unit  Reliability.    Combustion,  September 1978.   pp.  29-30.

This article describes a proposed monthly Outage Analysis Report and discusses
its usefulness.  The various items in the report are:

     Forced outage factor
     Maintenance outage factor
     Planned outage factor
     Reserve shutdown factor
     Reserve spinning factor
     Capacity factor
     Number of outages and causes

The report  provides  a means of quickly  determining  operating trends and aids
in  determining  the cost-effectiveness of remedial action.   The various items
in  the  report  are  defined, and their  significance  given;   an example is pro-
vided.
Long,  R.   L.   Engineering  for  Availability.   Power Engineering,  July 1978.
pp. 68-71.

A  brief  discussion  of  the various  aspects of  availability  engineering  is
given.  Four basic steps of availability engineering are cited, and an example
of  their  application  is shown.   The article  concludes  that  the  most cost-
effective changes can be made through application of availability engineering.
Lowell, P. S.   Influence of the Mineral Content of Coal on Ash Properties and
How This  May Be Modified  by Physical Coal Cleaning.   Prepared  for PEDCo En-
vironmental,  Inc.,  October 1978.

The report states  that different minerals are  removed at different efficien-
cies in a  physical  coal cleaning plant.   An  example is presented  that  illus-
trates the influence  on the ash fusion temperature of  varying mineral removal
efficiencies; other coal properties are also discussed.  The report recommends
a program to quantify the selective mineral removal efficiencies.
                                      65

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McGraw, R. W.,  and  G.  Janik.   MCCS—Implementation at Homer City.   Presented
at the  Proceedings  of  the  Third Symposium on Coal Preparation, NCA/BCR  Coal
Conference, Louisville, Kentucky, October 1976.   pp.  107-122.

This paper describes  the  use  of a coal cleaning plant at the Homer City Power
Plant, operated by  Penelec  in Homer City, Pennsylvania.  The  cleaning  plant,
which costs  52  million dollars,  is sized to clean 1000 tons of coal per hour,
processing the  coal  into  two  product streams to meet two separate S02 regula-
tions.
Morgan,  M.  G.,  et al.   Sulfur  Control  in Coal Fired Power  Plants:   A Proba-
bilistic  Approach to  Policy Analysis.   Journal  of APCA,  28(10):   993-997,
October 1978.

This  article presents a methodology  that can be used to  minimize  the sum of
societal  and pollution  control  costs.   The  article demonstrates a technique
for using subjective mortality elements to develop an estimate of the level to
which  sulfur  emissions should be controlled.
 Niebo,  R.  J-   Power  Plant  Productivity
 Combustion,  January  1979.  pp. 12-21.
Trends and  Improvement Possibility.
 The  available  data bases  on power plant  productivity with  respect to  unit
 size,  age,  and fuel type  are reviewed.   The major causes  of  lost power plant
 productivity  and manufacturers'  and governmental programs  for improving power
 plant  productivity  are  also identified.   The  causes  identified are:

      Plant  design and equipment  procurement
      Maintenance and operations  management
      Coal  quality
      Government regulations

 The  report concludes that deteriorating coal  quality results in higher quanti-
 ties of coal  having to be supplied to  the boiler  at higher rates  in order to
 produce necessary   steam.    Such  increases  result  in  boiler tube  slagging,
 precipitator overloading, pulverizer wear,  and other problems.  To  compensate,
 utilities  have derated  units and  increased shutdown time  for maintenance and
 modification.
 O'Brien, E.  J.   Coal and Its Physical Preparation.  Presented at the Technical
 Conference on Coal Utilization and Air Pollution Control, Western Pennsylvania
 Section, APCA,  April 1976.

 The meaning  of  coal  preparation is discussed in this paper, and various types
 of  coal  cleaning  are  mentioned.   The  significance of  washability  data  is
 discussed.
                                      66

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Pacer, D. W., and A. F. Duzy.  Impact of Fuel on Furnace Design for Pulverized
Coal Fired Boilers.  Power, September 1978.  pp. 82-83.

The  burner  zone surface  heat release  rate  is discussed,  and typical  design
values are given.  A discussion of the mass gas flow effect on fly ash distri-
bution  and   the  tightness  of the  furnace are  presented.   The  slagging  and
fouling factors are defined, and average values for an eastern coal are given.
The  article  concludes:   "It is evident that much more coal  data and operating
experience will  be required to improve evaluation  of upper-furnace slagging.
In the  meantime  a  conservative approach to design  appears  to be the only al-
ternative. "
Palomino, G. E. and J. L. Shapiro.  The Impact on Power Plant Design of Sulfur
Distribution  in  Coal.   ASME Paper No. 78-JPGCPwr-13.  Presented  at  the Joint
ASME/IEEE/ASCE Power Generation Conference September 10-14, 1978.

The variability  of  sulfur in the Navajo mine is studied.   The relation of the
sulfur variability  in  the mine to the ambient concentration around the Navajo
generating  station  of  S02 is also studied.  A model of the sulfur variability
was derived.  From the model the principal findings are:

     The  frequency  of  occurrence of  sulfur in core  samples obeyed  a Gamma
     distribution.

     The  frequency  of occurrence  of  sulfur  in  the three-hour nonoverlapping
     samples obeyed an inverted Gamma distribution.

     The  harmonic mean of  the sulfur distribution in the  core  samples is a
     predictor of the mean of the delivered coal sulfur distribution.

     The  variance  in  going  from mine  core distribution  to delivered coal
     distribution was reduced by a factor of 11.
PEDCo  Environmental  Specialists, Inc.   Analysis  of the  Use  of Physical Coal
Cleaning in  Combination  with FGD for SO   Control.   Draft Report prepared for
the  U.S.  Environmental   Protection  Agency,  Energy  Strategies  Branch,  under
Contract No. 68-02-1452.   1976.

This report  uses  linear  programming techniques to  evaluate  the cost of three
S02 control strategies.   The report illustrates an approach to obtain a  least-
cost solution to  S02  control.    In the example given, order of magnitude esti-
mates are made for various cost  elements.  The report concludes:

     The cost coefficients are critical

     Emission regulations are critical

     Nonlinear costs can be solved using an iterative technique

     Linear  programming  techniques  can be used to  determine least-cost solu-
     tions


                                     67

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Phillips, P.  J.,  and  P.  DeRienzo.   Steam Coal  Preparation Economics.  Pre-
sented  at the  NCA/BCR Coal  Conference and  Expo  III, Louisville,  Kentucky,
October 19-21, 1976.

This  paper  attempts  to  fill  existing information  gaps  in coal  preparation
economics.  No specific  information  on the benefits of coal cleaning are pre-
sented.   The  report  distinguishes  various  degrees  or  levels of  coal  cleaning
that  represent the complex  technology of coal cleaning.   Relative cost of  the
cleaning  technologies  are presented.   The report  concludes that generalized
costs  will  have little  validity in  specific  situations  because  of  the many
variables involved.
Phillips,  P.  J.  and R.  M. Cole.   Economic  Penalties  Attributable to Ash Con-
tent  of  Steam  Coals.    Presented  at  the AIME  Annual  Meeting,  New Orleans,
February  1979.

A  methodology is presented that quantifies six  coal  utilization cost compon-
ents, each proportional to a coal's mineral content.  These are:

     Ash  disposal costs
     Coal  transporation costs
     Plant maintenance costs
     Reduction  in plant peaking capacity
     Reduction  in plant rated capacity
     Reduction  in plant availability

Cost effects  on flue gas  cleanup systems  are not considered here.

Numerical examples  illustrate  that  coal  containing  between  12.5  and  25.0
percent ash-plus-sulfur  can cause incremental  utilization costs ranging  from
less than $1.00 to  more  than $8.00 per ton  of coal  when combusted in a  pulver-
ized  coal-fired power plant.   Estimated  costs  are  then compared to historical
data  and the  conclusion  is drawn that steam coal beneficiation may  have broad-
er economic  justification than  sometimes  realized.   It is  noted  that  TVA,
which  first  proposed the  methodology and parameters used here,  is continuing
research on this aspect  of coal  utilization.
 Sarikas, R. H.   Procedure  for  Converting Utility Investment  and  Expense Into
 Annual Revenue Requirements, Foster  Associates,  Inc., Decatur, Illnois, 1975.

 This  report describes  the  development of a procedure  for  translating utility
 investment and expense into annual revenue requirements.  It is based upon the
 practices  followed by  regulatory authorities  in the United States and statute
 law  with  respect  to  income  tax  and the deductability  of  various  items of
 expense  in calculating the amount of such taxes.  The  important variations in
 methodology between  jurisdictions are  pointed out.   Typical  parameters  have
 been  selected to illustrate the procedure with a quantitative example.
                                      66

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Sondreal,  E.  A., et  al.   Correlation  of  Fireside Boiler Fouling with  North
Dakota  Lignite  Ash  Characteristics  and  Power  Plant Operating  Conditions.
Presented at the American Power Conference, April 19, 1977.

Two approaches  that  identify  the causes  of  ash fouling are  described,  fine
involves acquisition  of  a large number of data  sets  on operating units.  The
data  sets  would then  be statistically treated and insights to  the  relation-
ships  would be  drawn.  The  second approach  uses  direct measurement of the
fouling  potential via probes inserted  into operating  boilers.   This  approach
provides a  more accurate measure  of  the fouling potential in a shorter more
easily controllable fashion.   The report concludes that each method  has  merit
and  that both  should be used.   An alternate method  involving  a small  test
furnace  is  suggested.  The  alternate  method would provide more general  infor-
mation in a more easily controlled environment.
Sondreal, E.  A.,  et  al.   Ash Fouling  in the "Combustion of  Low  Rank Western
United  States  Coals.   Combustion  Science  and  Technology,  Vol. 16,  1976.
pp.  95-110.

The report  states  that no effective  means of preventing ash  fouling of high
sodium content coals has been found.   Washing can reduce sodium content by ion
exchange; however,  reaction  rates are  slow,  and  dewatering and  waste  water
disposal could  create serious  problems.   Cyclone burning reduces  fouling but
increases NO   emissions.   Boiler  design  radically influences  the ability to
correlate da1?a for one boiler with another.
                                     69

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Spaite, P.  W.,  et  al.   Environmental  Assessment  of  Coal Cleaning  Processes
Draft Report written  by  Battelle's  Columbus Laboratory for the  U.S.  Environ-
mental Protection Agency, 1979.

This  research task  was  initiated with the overall  objective  of reviewing U.S.
coal  cleaning process technologies  and related technologies  for environmental
control.   The  report provides   a  background  against  which requirements  for
further developments  of coal cleaning technology and control  techniques  for
the associated pollutants can be established.

The state  of the art of physical coal  cleaning is summarized.  The status of
coal  cleaning  technology  is summarized  with  respect  to cost,  energy  effi-
ciency, applicabilty, extent of development, and commercialization prospects.
Current technologies are described.   The various physical coal  cleaning opera-
tions,  such as  coal pretreatment,  coal separation, product  conditioning,  and
auxiliary processes are combined to product  systems capable of producing mini-
mum,  intermediate,  and  maximum effectiveness  of coal  cleaning.   The physical
and chemical properties of coal are described, and the pertinent literature on
washability of many U.S.  coals  is  cited.   Technological descriptions are pre-
sented  for coal   cleaning  processes,   i.e.,  size  reduction,  sizing, desliming
screens,  fine  coal  separation, jigs,  dense-medium  vessels,  air  tables,  wet
concentrating tables, etc.   Potential  pollutants evolved from theses processes
and their  control are identified.

This  report was   submitted by Battelle's  Columbus  Laboratories  in  fulfillment
of  Subtask 212   for a Technology Overview under U.S.  Environmental  Protection
Agency  Contract   No. 68-02-2163  for Environmental  Assessment of Coal Cleaning
Processes.  This report covers the period  from July 1, 1976,  to May 31, 1979,
and work was completed as of May 31, 1979.
 Strauss,  W.   Industrial  Gas  Cleaning,  Pergamon  Press,  Oxford,  1966.

 This  textbook covers  a  range of  subjects  including:

      Absorption,  adsorption, and combustion
      Fluid mechanics
      Gravity and  momentum separation of  particles
      Centrifugal  separation  of particles
      Aerodynamic  capture of  particles
      Filtration
      Electrostatic precipitation

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Suydam,  C.  D.,  Jr.   Economic Evaluation of Washed Coal for  the  Four Corners
Generating Station Final Report, April 1977.

The  report is  a summary of various studies conducted by  Arizona Public .Ser-
vice.  The report concludes that washing the Navajo Mine coal  used at the Four
Corners  plant would  not be economical.  The conclusion  is based  on the judg-
ment  that washing the  Navajo Mine coal would  cause  severe furnace slagging,
fouling,  and  coal  handling (freezing) problems.  The only benefits Identified
in
the  report are  reduced pulverizer wear and  maintenance.  The  benefits  are
reported  to be 30 percent less than the penalties for use of washed coal.  The
report does not present the specifics of how  the penalties and benefits were
determined.
Suydam, C. D., Jr., and H. F. Duzy.  An Economic Evaluation of Washed Coal for
the  Four  Corners  Generating  Station.   Presented at  the  Winter Annual  Meeting
of the ASME, November 27 to December 2, 1977.

The  relative economics  of burning washed and  ROM  Navajo mine coal are evalu-
ated  in  this report.   The method  by  which the penalties  and  benefits  of the
two coal strategies are determined is reported.

The report considered only the following items as being significant:

     The O&M cost differential

     Coal handling  problems  (based on an estimate of plant derating caused by
      coal freezing)

     Pulverizer wear (based on fuel properties and industry experience)

     Pulverizer curtailment  (based on an assumed 17 percent reduction in cur-
      tailment)

     Erosion caused tube  leaks  (based on assuming that 1/10 of all tube fail-
      ures were  tube  leaks  and  that  washing the coal would  eliminate 2/3 of
      the tube leaks)

     Fouling (based on  test  firing of washed coal in a small test furnace and
      assuming that the  coal  sodium oxide content will  exceed 2.7 percent 30
      days per year and cause a 15 percent derating  for those 30 days)
Tuppeny, W. H. , Jr.  Effect of Changing Coal Supply on Steam Generator Design.
Presented at the American Power Conference, April 24-26, 1978.

The  physical   differences   among  furnaces  and  pulverizers  are  shown   in
relation to the major  types of coal used by utilities.  Historical experience
of  the  Combustion  Engineering Company  with  various  coal types  and furnace
sizes is described.  Trends toward lower quality coal require a corresponding
increase in the physical size of furnaces and furnace components.

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Tennessee  Valley  Authority Annual  Report,  Vols.  1 and 2.  Years  1972,  1973,
1974, 1975, 1976.

The  annual reports  present  a breakdown  of the  costs  of generation  and  net
Icilowatthours generated at each TVA plant.
Tennessee  Valley  Authority.   Coal Analysis Control:  TVA Plants.  Coal Proxi-
mate Analysis and Tonnage Used at All TVA Plants from First Burn through 1978.

The monthly and fiscal year proximate coal analyses and tons burned are given
for each TVA plant.  The data are  complete from initial startup of the plant
through  1978  for  all TVA plants.
 Tennessee  Valley  Authority.   Division  of Power  Production Availability  Im-
 provement  Program.   1978.

 This  report  describes  a repair  program for various  portions of  several  TVA
 plants.   The estimated costs  and repair schedules are presented.   The  report
 attributes boiler failures  and decreased availability/reliability to poor fuel
 quality.
                                       72

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Tennessee Valley  Authority.   Miscellaneous  data on TVA coal-fired plants  sup-
plied by unidentified TVA personnel to Larry Yerino of PEDCo.   1975.

The  data for  each  plant cover  the time from  Initial  plant  startup  through
1975.  Major data categories are:

Average capacity factors by unit and plant

     TVA total and forced outage rates, arranged by plant size for:
          Complete unit
          Reactor-boiler
          Turbogenerator

     TVA outage rates by unit size for calendar year 1974

     Unit availability factors from commercial operation to 1975

     Steam plant maintenance cost comparison for selected accounts:
          Boiler
          Soot blower
          Pulverizers, mills, and primary air
          Burners, lighters, and cyclones
          Gas reci-culating fans
          Air preheaters
          Forced draft fans
          Induced draft fans
          Induced draft fans
          Bottom ash hoppers
          Fly ash collectors
          Other ash disposal facilities

     Fuel analysis from 1963 to 1976 for TVA plants
     Generating plant statistics for 1975
Tennessee Valley Authority Organization Statement - Form 4121.  Taken from TVA
Division of Power Production Monthly Report.)

The  organization statement  is  a  monthly  report  that indicates  monthly and
annual  expenditures  for several cost  categories.   Fuel-related costs include
coal  handling  and  storage,  coal burning  equipment,  ash  handling equipment,
etc.
U.S.  Department of  Energy.   Construction Cost and Annual Production Expenses.
1974, 1975, 1976,  1977.   DOE/EIA-033/X.  Federal Power Commission.

Data on all privately and publicly owned utilities from FERC Forms 1 and 2 for
plants with  25 MW or greater capacity and  a brief discussion  of each of the
data items is  included  along with summaries  and  trends for much of the data.
                                     73

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U.S.  Environmental  Protection  Agency.   Combined Coal Cleaning and FGD.   Pre-
sented at the EPA FGD Symposium, Las Vegas, Nevada,  March 5-8,  1979.

The report identifies the following benefits of physical  coal  cleaning:

     Reduced transportation costs
     Reduced boiler O&M costs

     Increased peaking capacity

     Increased availability

     Reduced stack reheat

     Reduced design safety margin for FGD design

     Reduced pulverizer costs

     Reduced mine labor costs

     Reduced ash disposal costs

The  range  of required coal cleaning benefit for a breakeven S02 control stra-
tegy  for four coals  and  three levels of  cleaning  is  determined.   The report
concludes,  "the  use of PCC plus FGD will be the most cost-effective method of
complying  with emission regulations if reduction in FGD costs and cost bene-
fits  not related to S02 emission controls are greater than the costs of clean-
ing."
Versar,  Inc.   S02  Emission  Reduction Data From Commercial Physical Coal Clean-
ing  Plants  and Analysis  of  Product Sulfur Variability.   Final Draft.   Contract
No.  68-02-21,  Task 600.   Prepared for EPA  Fuel  Process  Branch,  IERL,  Research
Triangle Park,  North  Carolina.  October  1979.

The  report presents data that  have  been collected from several  coal  cleaning
plants.   A  statistical  analysis  was  performed  on  the data,  and the report
present  the following conclusions:

      The variability  of  the sulfur content  of  the coal  is  reduced by  cleaning

      PCC is an effective S02 control technology

      The deeper the cleaning the  greater the sulfur  reduction

      The RSD reductions and values  determined are only valid for the particu-
      lar coal  and plant  for which they were determined
                                      74

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Wilson,  E.  B. ,  et al.   Reducing the Corrosive  Properties  of Utility  Coals
through  Modifications  of Current  Coal  Cleaning Practices.  Presented at  the
ASME-IEEE Joint Power Generation Conference, September 25-27,  1967.

The report  describes  attempts  to modify the corrosive properties of  coal  via
physical coal cleaning.  It states that reductions in the corrosive  properties
of  coal  can  be obtained  without  significant  modification  in  current coal
cleaning  practices or  changes  in  coal  cleaning  performance.   The  report
stresses that  coal cleaning schemes  must be developed from a detailed  know-
ledge of the  coal  seam to be mined.  The report concludes that some coals  may
be  less  corrosive  in  their  raw  state than if they  were  cleaned.   Successful
application of  the measures  described, however, could reduce  boiler  mainten-
ance.
Winegartner, E.  C.  and B. T.  Rhodes.   An Empirical Study of  the  Relation  of
Chemical Properties  to Ash  Fusion  Temperatures.   Journal of  Engineering  for
Power, July 1975.   pp.  395-406.

The report descrri-es a correlation study using a multiple regression analysis.
The  data  base  includes  626 midwest  and 586 western  coal  samples.   The  ash
fusion temperature are correlated with 51 coal properties.   A resulting empir-
ical  equation  predicts ash  fusion  temperature from  ash composition  with  an
accuracy that  approaches  or  exceeds the accuracy of the laboratory determina-
tion of the ash properties.
Yoder, L. W.   Fuel  Influence on Boiler Operation  and  Maintenance,  an undated
report, Babcock and Wilcox, Alliance, Ohio.

The important  coal  properties  that are required for proper design  of various
boiler components  are shown.   A  brief discussion on  the  importance  of mois-
ture,  volatile matter, ash,  slagging and fouling,  and ash viscosity indicates
that  coal  properties have  significant effects on  boiler  performance.   Addi-
tionally,  several  graphs  show historical  trends  for several  boiler  design
factors,  i.e.  heat  input  to furnace plan area, heat  input per burner,  burner
zone  heat  release  rate,   gas  temperature  entering pendant  superheater,  and
maximum gas velocity.  The conclusions reached are:


     Coal and ash analysis are needed for boiler design

     Ash  properties can be used to predict slagging and fouling

     Ash  melts,  sticks  to walls,  affects  boiler  design,  and  is  related to
      corrosion and erosion

     Furnace design must  keep ash away from furnace surfaces, solidify
      the ash before it leaves the furnace,  and provide for cleaning of
      surfaces
                                     75

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Zimmerman, 0. T.  and I.  Lavine.  Psychrometric Tables  and  Charts,  Industrial
Research Service, Inc. , Dover, New Hampshire.  1964.

This is a reference book of psychrometric data, mostly in tabular form.

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                                  APPENDIX B

                        COST ESTIMATES FOR FGD AND PCC
INTRODUCTION

     The  costs  and  benefits of  the  combined use  of physical coal  cleaning
(PCC)  and  partial  flue  gas desulfurization (FGD)  for sulfur  dioxide (SO;,)
removal are  compared  to the costs for  sole  use  of  FGD.  A 500-MW power plant
with a 65 percent capacity factor is assumed in the  cases presented.

     The raw coal  to  be fired directly or to be physically cleaned is a typi-
cal  Eastern  bituminous coal;  in  various portions  of this Appendix, 2.5 per-
cent sulfur, 3.5 percent  sulfur,  and  5 percent sulfur coals are  used in cost
estimation cases.   The raw coal cost is $1.00 per million Btu.

     The cost basis is August 1979 for all cases.

     In the  first  example,  some of the effects of the use of physical cleaned
coal on capital  and annual costs are examined.   In the second example, the use
of  coal  that can  be cleaned to allow  an untreated  flue gas bypass  stream to
provide reheat  is  examined.   The  washability data  for  the coal  used in Exam-
ples 1 and 2 are shown in Table B-l.

     In Example 3,  a  different 3.5 percent sulfur bituminous coal is examined
for  a  case  where  reheat is  required.    The  washability  data for this coal are
shown  in Table B-2.
  TABLE B-l.   WASHABILITY DATA FOR AN EASTERN BITUMINOUS HIGH SULFUR COAL1
Washing
gravity
1.3
1.3-1.4
1.4-1.6
1.6-1.9
Raw coal
Weight
yield, %
21.9
62.5
82.4
85.9
100.0
Btu
recovery, %
26.3
73.1
93.4
96.3
100.0
Heating value,
Btu/lb
14,100
13,700
13,300
13,100
12.100
Sulfur,
%
1.32
1.66
1.97
2.09
3.48
Ash,
%
2.6
5.3
8.2
9.2
14.0
aThe coal  washing data  are  selected from Sulfur  Reduction  Potential of U.S.
Coals:   A  Revised  Report of  Investigations EPA 600/2-76-091.  pp. 71 and 164.
                                       77

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         TABLE B-2.   WASHABILITY  DATA  FOR AN EASTERN HIGH SULFUR COAL
Washing
gravity
1.4-1.6
Raw coal
Weight
yield, %
80
100
Heating value
recovery, %
90
100
Heating value,
Btu/lb
12,000
10.670
Sulfur,
%
2.4
3.5
Ash,
%
10
20
     Example 4  examines  the  capital  and  annual  costs for  three  coals with
different sulfur  contents,  fired raw  or at any  of three levels of physical
coal cleaning  (30,  40,  and  50 percent sulfur  removal),  and subject to three
different control  regulations.


Comments On The Coals Used

     The coal  in  Table  B-l  is examined at the  1.4 specific gravity  cut and  in
its  raw  state.  The washed  coal loses less  than  7 percent of the  heat value,
while  the weight  is reduced almost 18 percent.   The sulfur content  is  reduced
43 percent, and the ash content is reduced 41  percent in physical  coal clean-
ing.

     The  coal   in  Table B-2  loses  only  10 percent of  its heat value during
physical cleaning,  while  it loses 20 percent of  its  weight.   The  sulfur con-
tent is  reduced 31  percent and the ash content is reduced 50 percent in clean-
ing.


EXAMPLE  1

     Several positive effects of physical coal  cleaning are:

     PCC reduces  the volume of gas  that must  be treated  by an FGD system and
     the amount of  sludge generated.

     PCC reduces  or  eliminates  the heat  energy that  reheat  the cleaned gas
     stream.

     PCC reduces  the  S02  variability by half or more,  which reduces the FGD
     system size,  since the FGD  system  must be designed  to  handle the maximum
     S02 load.  An  example  of coal  sulfur  variability  is  shown for three coals
     in  Table  B-3.

     To  demonstrate the effect  of  physical  coal  cleaning,  consider a 3.48 per-
 cent sulfur,  Eastern bituminous coal  with the washability shown  in Table B-l.
 The raw coal  would  liberate  5.75  pounds of S02/million Btu heat  input  if  100
 percent  of  the sulfur were  liberated as  S02.   If  the  boiler in which  this coal
 is burned  must meet a requirement  of 1.2 pounds  of S02/million Btu  heat input,
 79 percent  of the  S02  must be removed  by  the  FGD system.  If the FGD  system
 were 85 percent efficient  in removing S02, 93 percent of the gas  stream must
 be treated  1n the FGO system.   Conversely, if  the coal were cleaned to a wash-
 ing gravity of 1.4,  the  cleaned coal  would have a 1.97 percent sulfur content
 and would  release  2.96 pounds of  S02/million  Btu.  To meet  a requirement of
 1.2 pounds  of  S02/million  Btu  requirement,  59 percent  of  the  S02  must  be
                                      78

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removed;  assuming  the  85 percent efficient FGD system, only 70 percent  of  the
gas  stream must be  treated.   It is assumed  that  the coal  is fired in a  new
500-MW power boiler in a midwestern location.
             TABLE B-3.  COAL ANALYSES AND SULFUR VARIABILITY OVER
                           VARIOUS AVERAGING TIMES
Coal type
Eastern bituminous,
14% ash,
12,000 Btu/lb
Eastern bituminous,
14% ash,
12,000 Btu/lb
Western subbituminous
8% ash,
10,000 Btu/lb
Plant size,
MW
25
500
1000
25
500
1000
25
500
1000
Maximum averag
Longterm
7.00
7.00
7.00
3.50
3.50
3.50
0.80
0.80
0.80
Annual
7.36
7.23
7.22
3.68
3.62
a. 6i
0.84
0.83
0.83
e sulfur content, %
30 days
8.27
7.79
7.75
4.13
3.89
3.87
0.96
0.90
0.89
1 day
9.36
8.88
8.78
4.68
4.44
4.39
1.12
1.05
1.03
3 hours
9.73
9.23
9.19
4.86
4.61
4.59
1.18
1.10
1.09
 Distribution from unit train sampling.

     The comparative costs are as follows:

Capital cost
FGD system, $/kW
Sludge pond, $/kW
Total
Annual cost
Operation and mainten-
ance cost, mills/kWh
Fixed costs, mills/kWh
Total
3.48% S Raw Coal

107.50
5.38
112.88

2.58
3.17
5.75
1.97% S Cleaned Coal

81.70
2.58
84.28

1.59
2.37
3.96
     For a 500-MW  boiler,  cleaned coal reduces the  cost  of the FGD system by
$14.3 million.   Assuming  a  65 percent capacity factor for  the  500-MW boiler,
the annual cost of the cleaned coal  system  is  $5.10 million less per year of
operation.

     Regarding the reduced energy requirement for a system operating on physi-
cally cleaned coal,  a  lime  FGD system that  treats  only  70 percent of the gas
stream can  reheat the cleaned  flue  gas  stream with  the  untreated gas bypass
stream without the  use of additional reheat.   The  energy requirements of the
two cases are as follows:
                                     79

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Annual cost
Energy cost,
Energy cost,
mllls/kWh
$106/yr
3.48% S Raw Coal
1.02
2.90
1.97% S Cleaned Coal
0.52
1.48
With  the  physically cleaned  coal,  the annual  cost is reduced $1.42  million.
The  capital  cost reduction  as a  result  of reheat elimination  has  not  been
estimated; although the cost reduction exists,  its capital  cost impact here  is
small.

      As shown  in  Table B-3,  a nominal 3.5 percent sulfur  coal  is  expected  to
have  a maximum  30-day  sulfur content of  3.89 percent,  or 11.14  percent  in
excess of the long-term value.  On the other hand, the sulfur variability in a
cleaned coal  is  typically about half  of  that  of a raw coal.  Thus a cleaned
coal  with a nominal sulfur content of 1.97 percent would be expected to have a
maximum 30-day average sulfur  content of 2.08 percent.  This will be reflected
in  reduced  capital  and annual costs  for  a  lime FGD  system on  a 500-MW power
boiler operating on physically cleaned coal.  If the FGD systems were designed
to  accommodate the  maximum  S02  values  anticipated,  the capital  and annual
costs would be as follows:

Capital cost
FGD system, $/kW
Sludge pond, $/kW
Total, $/kW
Total, $106
Increase attributed
to sulfur variation,
$10f'
Annual cost
O&M, mills/kWh
Fixed charges,
mills/kWh
Total, mills/kWh
Total, $106/yr
Increase attributed
to sulfur variation
$106/yr
Raw coal
3.48%S

107.50
5.38
112.88
56.440


3.60
3.17
6.77
19.274

3.89%S

111.80
6.13
117.93
58.965
+2.525

3.93
3.28
7.21
20.527
+1.253
Cleaned coal
1.97%S

81.70
2.58
84.28
42.140


2.11
2.37
4.48
12.755

2.08%S

83.85
2.74
86.59
43.295
+1.155

2.15
2.45
4.60
13.096
+0.341
      This shows that the effect of reduced sulfur variation as a result of PCC
 on the design  of  a lime FGD  system  for a 500-MW boiler is a capital cost re-
 duction of $1.37 million  (2.525 minus 1.155) and  an annual  cost reduction of
                                      80

-------
$0.912 million,  (1.253 minus  0.341)  representing about 0.5 percent of  total'
annual costs.

EXAMPLE 2

     When the coal  shown  in Table B-l is fired  in the  500-MW  power plant,  it
is assumed that  the S02  emission regulations require reduction to  1.2 pounds
of S02/million  Btu.  A 3.48 percent  sulfur  coal with a heat  value  of 12,100
Btu/lb will  liberate  5.46 pounds  of S02/million Btu  if  95  percent of the sul-
fur is volatilized  as  S02.   The allowable S02 emission  level can be met  using
either FGD  only  or physical  coal  cleaning  and a  partial  FGD system.   The
500-MW power plant is assumed to have  a 65 percent capacity factor.

     One   item  not  considered   in  Example 1   is  considered in  Examples  2,  3,
and 4.  It is an FGD capacity  penalty which  is  an  incremental requirement  to
supply power to  run an FGD system.

Combined  PCC and Partial  FGD

     The  design  bases for PCC are as follows:
     The  PCC facility operates  4000  hours per year.

     To determine the  coal  utilization and coal cleaning  rate, a boiler heat
     rate of 10,000 Btu/kWh  is  used.

     Coal cleaning Btu recovery is 93.4 percent (see  Table  B-l).

     Two-stage  crushing   is  utilized  to  reduce  the  raw coal top size  to
     1 1/2 inches.

     Processing  in three  circuits is as follows:

          For the 1 1/2-in.   x  3/8-in.  cut, a single-stage  dense medium vessel
          is used.  The coal is washed at a specific  gravity of 1.4.

          For the 3/8 in.  x  35  mesh  cut,  Deister tables  are used.   The  coal  is
          washed at a specific  gravity of 1.6.

          The fine coal is dried in  a  thermal drier.

          The output products from all three  circuits are combined  to form the
          cleaned boiler  fuel.

     The  design  bases  for the  partial  FGD system are  basically the same for
the FGD system  only for  reducing S02  emissions  (presented later),  except for
the following:

     The  bypassed,  untreated flue gas stream is used partially  or  totally to
     provide the required reheat.

     Up to three  150 MW absorbers may be used partially or totally to provide
     the  required reheat.

     An additional  complete spare  absorber  is  provided  to increase  the FGD
     system availability.   The  availability of a system having three operating
     absorbers and one spare is about 95 percent.
                                     61

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Impacts of Combined PCC and Partial  FGD

     The impacts of combined PCC and the subsequent partial  FGD system use  are
as follows:

     The  FGD  system can be  designed  to meet a less  stringent  continuous  S02
     removal  requirement  than  is  required  of a  system depending  upon  FGD
     alone.   The S02  evolved  by  combustion  of  the raw coal  will   be  about
     95 percent  of  the maximum  because some  sulfur  is lost with the  ash or
     slag.  The  actual  S02 emission will be about  5.46 pounds  of S02/million
     Btu  when the raw coal  is  fired,  and  the  FGD system will  be required to
     remove 4.26 Ib  S02/million Btu.   If the S02  absorber is 85 percent effi-
     cient, 92 percent  of  the flue gas stream must be treated in the raw coal
     case  to  remove the required amount of S02.

     With  the PCC case, the actual S02 emission is estimated to be 2.81 pounds
     of  S02/mil1ion  Btu.   The S02 removal required is 1.61 pounds of S02/mil-
     lion  Btu; therefore an 85 percent efficient FGD system must treat 67 per-
     cent  of  the flue gas stream.  The  remaining  33 percent is  sufficient to
     provide  necessary  reheat.

     The  flue gas bypass will provide the 50°F reheat required and will reduce
     the  FGD  system operating cost.

     A mine-mouth unit  is  assumed in this case.  Disposal of the  coal cleaning
     waste occurs in the area  of the  PCC  unit and the  mine,  where  it is as-
     sumed that  ample  space  exists.

     The 82 percent  PCC weight  yield and 93 percent Btu  recovery  combine for a
     net  effect  of reducing  the  weight  of  coal  transported  to the 500-MW
     boiler by  over  13 percent.   The  freight savings  are  discussed in  Sec-
     tion 3.11  of this  report.

      If  sludge ponding or disposal area  is  a  problem or concern at  a particu-
      lar FGD  installation,  PCC  can  greatly  reduce  the effective sludge genera-
     tion.   In  "Controlling S02  Emissions  from  Coal-Fired  Steam -  Electric
     Generators:  Solid Waste Impact"  (EPA-600/7-78-044a),  a 48 percent reduc-
     tion in  sludge generation  is reported  for a  coal very  similar to the  coal
      used in  this example.   This may  be a  critical  item at  some specific  sites
     where space is limited.

      Because  a  cleaner fuel is  being fired  in  the boiler,  boiler  operation
      should  improve,  power  output capacity  should  increase,  and maintenance
      costs related to boiler operation should  decrease.

      Annual  coal  cleaning costs are  sensitive to plant capacity,  plant  com-
      plexity, and coal  replacement costs.   Coal  replacement costs are defined
      as the costs of coal  energy that must be  discarded with the plant residue
      (carbon and mineral  matter).   Plant complexity increases with the number
      of different process operations involved.

 FGD System (Sole S02 Removal System)

      Approximately 94  percent  of the utility FGD systems currently  in use are
 lime and  limestone systems.   Lime  is assumed  in this example,  the design  bases
 for the lime FGD system are as follows:


                                       82

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     A two-stage turbulent contact S02 absorber Is used.
     The liquid-to-gas ratio in the absorber is 40 gal/1000 cu ft.
     The gas velocity in the absorber is 10 ft/sec.
     The flue gas temperature at the absorber outlet is 125°F.
     Reheat of 50°F is required for the cleaned flue gas.
     The absorber hold tank is sized for a 10-minute retention time.
     There are four, 425-MW absorber modules required.
     One spare absorber  module  is provided to attain  FGD  system availability
     in excess of  90  percent.   This increases capital costs by  about 19 per-
     cent.
     Although  lime-based  systems  have  been  demonstrated  at  90 percent  S02
     removal efficiency, a  more  conservative  85 percent removal  of S02 in the
     absorbers is assumed.
     The stoichiometric ratio is 1.18 for lime.
Discussion of Cost;.
     The capital  and  annual  costs  of the two cases studied are presented in
Table B-4.   The physical coal cleaning system costs for several size units are
presented in Table B-5.
             TABLE B-4.   COST COMPARISON FOR A 500-MW BOILER SYSTEM
                          (Cost basis:   August 1979)

Option 1
Lime
FGD only
Capacity
penalty
Total
Option 2
Partial FGD
Capacity
penalty
Physical
coal
cleaning
Jotal
Capital cost
FGD system,
SAW

107.50
20.86
128.36

81.70
15.13
19.30
111.83
Sludge
pond
and land,
SAW

5.38


2.58
Total ,
$Aw

112.88
20.85
133.74

84.28
15.13
19.30
118.71
Annual cost
O&M,
millsAWh

3.60


2.11
Fixed,
millsAWh

3.17


2.37
Total,
mills/kWh

6.77


4.48
1.84
6.3?
                                     83

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               TABLE  B-5.   PHYSICAL  COAL CLEANING SYSTEM COSTS
                         (Cost  basis:  August 1979)

Capacity,
tons raw
coal/h
300
1200
1500
2100
3000
Capital cost

Total ,
$106
16.490
39.384
46.997
61.164
80.550


$/kW
32.32
19.30
18.42
17.13
15.79
Annual cost

Total ,
$106/yr
5.833
13.705
16.139
20.733
27.148


$/ton
4.858
2.853
2.688
2.466
2.261

Mills/
kWh
2.67
1.84
1.77
1.68
1.59
     The total  capital  costs are  essentially the same  for both cases.  The
combined PCC and  partial  FGD case is 8 to 13 percent less  expensive  depending
on whether the capacity penalty  is considered.

     Largely, because  no additional  reheat  is required for  the partial FGD
unit, the combine.-case annual cost is about 7 percent less expensive than FGD
alone.   The  effect  of  the required quantity of reheat  is  shown in  Example  3.

     As can be seen from Table B-5, the annual PCC cost is  greatly affected  by
the  PCC  unit size.   The PCC unit assumed in Option 2 of Table B-4 is sized  to
clean  the  coal  for  four 500-MW power plants (1200 tons/h).   If  the PCC unit
supplies  coal  to only  one  500-MW  plant  (300 tons/h),  the capital  costs are
almost  identical, and  the  annual  costs  are less expensive  for  FGD alone  by
about  6 percent.   If  the PCC unit is 1200 tons/h or greater,  the combined op-
tion is less expensive  than FGD alone.

     Various items, alluded to  in the body of the report and  in the  impacts of
the  combined PCC  and partial FGD discussion of this example, may tip the bal-
ance for  specific cases.  The  absence  of the reheat requirement for the par-
tial FGD  unit was the deciding  factor  in  this case.


EXAMPLE  3

     When  the  coal  shown in  Table  B-2  is fired in the  500-MW power plant,  it
is  assumed  that  there   is  an 85 percent S02  emission reduction requirement.
Coal with 3.5 percent  sulfur and  a heat value of 10,670  Btu/lb  will  liberate
6.56 pounds  of  S02/million Btu.  An  85 percent S02  emission  reduction  equates
to   an allowable  emission  of  0.98 pound  of  S02/million  Btu  heat input  to
achieve  compliance.   Either FGD  alone  or  combined PCC  and partial  FGD  can
attain the required emission reduction.

Combined PCC and  Partial FGD

     The information given  in  Example 2 applies  here with one exception, coal
 cleaning reduces  the  total  heat  available from the coal  by 10 percent (from
 100 percent for the raw coal to 90 percent for the cleaned coal).
                                      84

-------
Impacts of PCC and Partial FGD

     The data  in  Example  2 generally apply here also.   Several  changes are as
follows:
     The actual S02 evolution is about 6.23 pounds of S02/million Btu,  and the
     FGD system  must  remove 5.25 pounds of S02/million  Btu.   Essentially 100
     percent of  the  flue gas stream must  be  treated in the raw  coal  case if
     the FGD system is 85 percent efficient.

     With the PCC case, the actual S02 emission is 3.80 pounds of S02/  million
     Btu.   An 85 percent  efficient  FGD system needs to  treat  only 87  percent
     of the  flue gas  stream.   The  remaining  13 percent of the  flue gas  pro-
     vides   partial  reheat  for  the  cleaned  flue gas  stream  and  reduces  FGD
     system operating costs.

     A 20 percent weight  reduction  in PCC reduces the  coal heat content only
     10 percent,  reducing the weight of coal  transported to  the 500 MW power
     plant   by  11 percent.   Freight  savings are  discussed  separately  in the
     body of this report.
                  •
FGD SYSTEM

     The comments in Example 2 hold true here also.

DISCUSSION  OF COSTS

     The capital  and annual  costs of the two options investigated are present-
ed  in  Table B-6.   The  physical  coal  cleaning  system costs  for several  size
units are presented in Table B-7.

             TABLE B-6.  COST COMPARISON FOR A 500-MW BOILER SYSTEM
                          (Cost basis:   August 1979)

Option 1
Lime
FGD only
Capacity
penalty
Total
Capital cost
FGD system,
$/kW

117.18
22.30
139.48
Sludge
pond
and land,
$/kW

6.24
6.24
Total ,
$/kW

123.42
22.30
145.72
Annual cost
O&M,
mills/kWh

4.11

Fixed,
mills/kWh

3.44

Total ,
mills/kWh

7.55

                                     85

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TABLE 6 (continued)





Option 2
Partial FGD
Capacity
penalty
Physical
coal
cleaning
Total
Capital cost


FGD system,
$/kW

97.83

19.31


25.48
142.62
Sludge
pond
and land,
SAW

3.76





3.76


Total ,
$/kW

101.59

19.31


25.48
146.38
Annual cost


O&M,
mills/kWh

2.99








Fixed,
mills/kWh

2.90








Total ,
mills/kWh

5.89




2.51
8.40
                    TABLE B-7.  PHYSICAL COAL CLEANING SYSTEM COSTS
                              (Cost basis:  August 1979)
                      Capital cost
Annual cost
L,apai_ i \,y ,
tons raw
coal/h
400
1200
1600
2000
3200
Total ,
$106
19.367
41.314
51.542
60.737
91.583
$/kW
35.83
25.48
23.84
22.47
21.18
Total,
$106/yr
6.606
13.947
17.163
20.116
29.809
$/ton
4.126
2.903
2.680
2.513
2.327
Mills/
KWh
3.15
2.51
2.31
2.21
2.21
      The total  capital costs are  essentially  the same for both  options.   The
 capacity penalty estimates cause  the  results  of capital cost to  be  so close.

      The annual costs of  the combined case are  about  11 percent  greater than
 FGD alone.   The  PCC cost is greater  than the difference between  partial  and
 full  scrubbing.

      As may  be  gleaned  from Table B-7, the size of  the PCC unit  has  a great
 effect  on  the  economics.   A  1200 ton/h  PCC  unit,  capable of  handling three
 500 MW power plants, is  assumed in Table B-6.   As the PCC unit size increases,
 the annual cost differential  decreases.


 EXAMPLE 4

      Table  B-8 presents  the  summarized  results of Tables B-9  through B-ll.
 Capacity penalties are included in Table B-8 capital costs.
                                      86

-------
     As a general  trend,  the percentage of coal cleaning  increases  for these
"cleanable"   coals  causing   the  combined  options  capital  costs  decrease  to
levels very  near  the  FGD  alone annual costs.   Almost the only cases  where the
"combined" option annual costs dip below the costs  of FGD alone are where coal
cleaning alone allows the 500 MW power plant to meet the applicable regulatory
levels.  The  annual costs  for the combined cases reach about  5  percent over
those of FGD alone in the 50 percent coal washing.

     Only in one case does 50 percent coal cleaning become less expensive than
FGD  alone.   That is  for  an emission  limit of 2.6 pounds  of  SOz/million Btu
using  a  5 percent  sulfur coal.   This should affect  relatively few  operating
power boilers.

     Since  the  costs  are  so  close,  any one of  a number  of   items  that are
site-specific may tilt  the  balance in favor of the combined option.   One case
is translating the  energy penalty into a fixed annual cost which  was not done
here because  the  applicability of the capacity penalty is largely site-speci-
fic.   As shown in Example 1, S02 variability design can influence  up  to 1 per-
cent of the  annual  costs.   All of the other  factors  discussed in the body of
this report  strongly  influence the  economic comparisons  of  the  two options.
                                     87

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           TABLE B-8.  SUMMARY OF THE 2.5% S, 3.5% S, AND 5.0% S FGD
                    AND PARTIAL FGD PLUS PHYSICAL COAL CLEANING
                         CASES FOR A 500-MW BOILER SYSTEM
                             (Cost basis:  August 1979)

85% Removal
Raw coal
(FGD only)
30% coal
cleaning
40% coal
cleaning
50% coal
cleaning
1.2 lb S02
per 106 Btu
Raw coal
(FGD only)
30% coal
cleaning
40% coal
cleaning
50% coal
cleaning
2.6% lb S02
per 106 Btu
Raw coal
(FGD only)
30% coal
cleaning
40% coal
cleaning
50% coal
cleaning
2.5%S
Capital ,
$/kW

141.30
146.16
143.87
141.74

121.40
119.59
114.91
107.52

78.71
24.29b
b
b
Annual ,
mills/kWh

7.09
8.22
7.95
7.76

5.89
6.74
6.53
6.27

3.53
2.48b
b
b
3.5%S
Capital,
$/kW

145.71
147.98
145.05
142.17

136.73.
137.41
135.41
131.95

102.29
90.75
79.58
36.51b
Annual ,
mills/kWh

7.55
8.43
8.19
7.89

7.02
7.86
7.59
7.34

4.62
5.55
4.01
3.08b
5%S
Capital ,
$/kW

a
a
a
a

148.61
157.28
149.28
151.88
Annual ,
mills/kWh

a
a
a
a

8.25
9.24
8.94
8.52
1
123.69 6.41
118.90
111.30
103.44
6.94
6.47
6.12
Emissions with 85 percent removal exceed 1.2 lb S02/million Btu; thus,
costs were not calculated.

 Partial FGD is not required to meet the S02 emission limit; only physical
coal cleaning is needed.

-------
               TABLE B-9.   COST COMPARISON FOR  A 500-MW
                   BOILER - 2.5% S BITUMINOUS COAL
                      (Cost basis:   August 1979)

85% Removal
Raw Coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital ,
$/kW

119.00
22.30
141.30
Annual Cost
O&M,
mills/kWh

3.76

1
102.13
19.74
24.29
146.16

95.68
18.61
29.58
143.87

88.26
16.97
36.51
141.74
2.84


2.54


2.23

Fixed,
mills/kWh

3.33


2.90


2.69


2.45

Total,
mills/kWh

7.09


5.74
2.48
8.22

5.23
2.72
7.95

4.68
3.08
7.76
(continued)
                            89

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Table B-9.   (continued)

1.2 Ib S02
per 106 Btu
Raw Coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
2.6 Ib S02
per 106 Btu
Raw coal
FGD only
FGD capacity
penalty
Total
Total
capital ,
$/kW

102.07
19.33
121.40

80.17
15.13
24.29
119.59

72.24
13.09
29.58
114.91
Annual Cost
O&M,
mills/kWh

3.01


2.00


1.77
i

60.47
10.54
36.51
107.52

66.65
12.06
78.71
1.47
1

1.65

Fixed,
mills/kWh

2.88

i
2.26


2.04
Total ,
mills/kWh

5.89


4.26
2.48
6.74

3.81
2.72
6.53

1.72

1.88

3.19
3.08
6.27

3.53

 (continued)
                              90

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Table B-9.  (continued)

30% Clean
coal3
PCC
Total
capital ,
$/kW
24.29
Annual Cost
O&M,
mills/kWh

Fixed,
mills/kWh

Total,
mills/kWh
2.48
 With cleaned coal (30, 40, or 50%),  FGD is not required to meet  a
2.6 S02/million Btu limit.
                             91

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             TABLE B-10.   COST COMPARISON FOR A 500-MW
              BOILER SYSTEM - 3.5% S BITUMINOUS COAL
                    (Cost basis:  August 1979)

85% Removal
Raw coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital,
$/kW

123.41
22.30
145.71

103.95
19.74
24.29
147.98

96.86
18.61
29.58
145.05

88.69
16.97
36.51
142.17
Annual Cost
O&M,
mills/kWh

4.11


3.05


2.73


2.34

Fixed,
mills/kWh

3.44


2.90


2.74


2.47

Total ,
mills/kWh

7.55


5.95
2.48
8.43

5.47
2.72
8.19
1
4.81
3.08
7.89
(continued)
                            92

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Table B-10.   (continued)

1.2 lb S02
per 106 Btu
Raw Coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning:
Partial FGD
FGD capacity
penalty
PCC
Total
2.6 lb S02
per 106 Btu
Raw Coal
FGD only
FGD capacity
penalty
Total
Total
capital ,
$/kW


115.46
21.27
136.73

Annual Cost
O&M,
mills/kWh


3.79


Fixed,
mills/kWh


3.23


1
94.92 2.69 2.69
18.20
24.29
137.41


88.90
16.97
29.58
135.45


80.30
15.14
36.51
131.95


86.75
15.54
102.29




2.37


Total ,
mills/kWh


7.02



5.38
2.48
7.86


2.50





4.87
2.72
7.59


2.00 2.26


i


2.20



2.42

4.26
3.08
7.34


4.62

(continued)
                            93

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Table B-10.   (continued)

30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
PCC
Total
Total
capital ,
$/kW

57.46
9.00
24.29
90.75

43.86
6.14
29.58
79.58

36.51
36.51
Annual Cost
O&M,
mills/kWh

1.40


1.03




Fixed,
mills/kWh

1.67


1.26




Total,
mills/kWh

3.07
2.48
5.55

1.29
2.72
4.01

3.08
3.08
  With 50% cleaned coal,  FGD is  not required to meet the 2.6 Ib
 emission requirement.
                             94

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              TABLE B-ll.  COST COMPARISON FOR A 500 MW
                BOILER SYSTEM - 5% S BITUMINOUS COAL
                     (Cost basis:  August 1979)

85% Removal
(Not calculate
1.2 Ib S02
per 106 Btu
Raw coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital ,
$/kW

d. Emissi

126.31
22.30
148.61

112.12
20.87
24.29
157.28

99.87
19.83
29.58
149.28

96.97
18.40
36.51
151.88
Annual Cost
O&M,
mills/kWh

ons exceed

4.70


3.59


3.21


2.75

Fixed,
mills/kWh

1.2 Ib S02/

3.55


3.17


3.01


2.69

Total ,
mllls/kWh

nil lion Btu. )

8.25


6.76
2.48
9.24

6.22
2.72
8.94

5.44
3.08
8.52
(continued)
                            95

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Table B-ll.   (continued)

2.6 Ib S02
per 106 Btu
Raw coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD cap;;ity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital,
$/kW

105.08
18.61
123.69

80.30
14.31
24.29
118.90

69.66
12.06
29.58
111.30

57.73
9.20
36.51
103.44
Annual Cost
O&M,
mills/kWh

3.48


2.20


1.79


1.37

Fixed,
mills/kWh

2.93


2.26


1.96


1.67

Total ,
mills/kWh

6.41


4.46
2.48
6.94

3.75
2.72
6.47

3.04
3.08
6.12
                             96

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                                  APPENDIX C

 CALCULATION OF  REVENUE  REQUIREMENTS TO CAPITALIZE ADDITIONAL BOILER CAPACITY

     Foster Associates has prepared a procedure for converting utility invest-
ment into annual revenue requirements.  Using that procedure, revenue require-
ments were calculated for use in Section 3.3.1 of this report.

     Data in Table  C-l  represent the costs associated with 50 kW of new capa-
city, at a capital cost of $1000/kW, including land.


                  TABLE C-l.   REVENUE REQUIREMENTS - 100 MW
Input Paramet' rs
Total plant investment
Plant life estimate
Physical life
Book depreciation
Construction time
Interest rate during construction
Debt fraction
Preferred stock fraction
Common stock fraction
Interest rate on debt
Dividend yield on preferred stock
Percent return on common equity
Income tax rate
Plant life estimate for tax
depreciation
Tax guideline plant life
Property Tax rate
Gross receipts tax rate
Insurance rate
Total land cost
Working capital
Startup expenses
Symbol
P
LP
Lb
N
d
P
c
r
r
t
Lt
L9
A
G
U
B
W
S
Value
$47.5 x 106
25 years
25 years
2 years
0.12
0.50
0.15
0.35
0.10
0.10
0.15
0.50
25 years
28 years
0.015
0.04
0.001
$2.5 x 106
$750,000
$1.5 x 106
(continued)
                                     97

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Table C-l.   (continued)
Input Parameters
Percent return on rate
base
Interest during
construction
Total capital
requirement
Plant
Land
Depreciation annuity
Income tax annuity
assuming straight-
line depreciation for
books and taxes
Investment tax
credit annuity

Levelized annual
revenue requirements
Plant
Land
Total
Symbol
r = dic * prp * crc
1C NP
C=P+I+W+S
D - r
(1 t- r)Lp - 1
t 1 l ~ dic
T - t >r ( r + n A v c\~\
c. *i . * 'L^r » u i M - ) J
sit Lb r
" (l"g " ^
T - / t ,r0.07r (1 + r)(Lg " X)
c 1 * tH ,, ,L , ]
(1 + r)ug - 1
+ °-07
(r 4 D + T T + A + u)
X ~ 5 C -
(1 - G) Cp
(r + D + T - T + A)
Y _ s c r
(1 - G) LB
Z = X + Y
Value
0.1275
$5.7xl06
$55.5xl06
$2.5xl06
0.00668
0.05415

.01143
$ll.lxl06
$0.5xl06
$11.6 x 106
                                       98

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              APPENDIX D
REGRESSION STUDY - TVA FORCED OUTAGES
                  99

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                PEDCo-ENVIRONMENTAL SPECIALISTS, INC.
                          MEMORANDUM

TO:   File                                     DATE:  November  6, 1975
SUBJECT:
FILE:
*

Report on Conclusions to Boiler
Reliability Study - Stepwise
Multiple Linear Regression Program
3155-W and 3179


FROM:
R.
J.
eet C .
J.
L.
T.
Gerald A. Isa
Cunningham J
Wilburn '"
Fussel
Elkins
Yerino
Devitt
       TVA has provided a large quantity of operating data
  that may be relatable to boiler outage rates.  Several of
  the variables were investigated statistically using a step-
  wise, multiple linear regression analysis program in con-
  junction with a time-shared Honeywell 6000 computer.  The
  following data have been processed for the entire TVA system
  for specific TVA plants and for certain individual boilers
  within those plants:
       1)   Total yearly tube failure outages.
       2)   Yearly outages due to flyash and sootblower
            erosion.
       3)   Yearly outages due to slag erosion.
       4)   Total erosion outages.
       5)   Annual capacity factor.
       6)   Lifetime accumulated kWh.
       7)   Yearly average coal Btu content.
       8}   Yearly average coal ash content.
       9)   Yearly average coal sulfur content.
  For the various systems investigated several significant
  correlations were determined.  Generally correlation of the
                               100

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first four variables with the latter five were sought.   A
minimum confidence level of 0.9 was used.  This mean* that
there is 90 percent certainty that each reported correlation
is significant enough that it could not have occurred merely
by chance.
     Data for the TVA system as a whole, for three indi-
vidual plants, and for two boilers within each of those
plants were investigated.  The following functional rela-
tionships were significant at a 90 percent confidence level:
     TVA System Composite
          Total failures = f  (heat content)
          Flyas'h and sootblower erosion failures = f (ash
          content, heat content)
          Slag erosion failures « f  (ash content, heat
          content)
          Erosion failures *  f  (ash content, heat content)
     Paradise Plant
          Total failures = f  (capacity  factor)
          Slag erosion failures « f  (heat  content)
          Erosion failures =  f  (heat content)
     Paradise Unit  1
          Total failures - f  (capacity  factor)
          Slag erosion failures «=  f  (capacity  factor)
          Erosion failures *  f  (capacity factor)
     Paradise Unit  3
          Slag erosion  failures e  f  (ash,  capacity factor)
          Erosion  failures B  f  (capacity factor)
                             101

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     Gallatin Unit 1
          Erosion failures « f (ash -f sulfur)
     Gallatin Unit 2
          Flyash and sootblower erosion failures * f (sul-
          fur)
          Slag erosion failures = f (sulfur)
          Erosion failures = f (sulfur)
     Kingston Plant
          Flyash and sootblower erosion failures = f (ash +
          sultur)
          Flyash and sootJblower erosion failure = f (heat
          content)
          Slag erosion failures = f (sulfur
          Erosion failures « f (sulfur)
     Kingston Unit 2
          Total failures = f (sulfur)
          Erosion failures = f (sulfur)
          Erosion failures = f (heat content, ash + sulfur)
Thus in an attempt to predict 40 specific dependent vari-
ables, 23 were predictable at a 90 percent confidence level
as a function of one or a combination of the five basic
independent variables.  Most of the five "independent"
variables are actually related.  Since only about eight
observations were available per data set the significant
independent variable was not consistent from one data set  to
the next.  The principal conclusion is that the various
failures are probably related to the Btu, ash, and  sulfur
contents of the coal and to the boiler capacity factor.
                             10?

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Since the true underlying relationship is  probably not
linear and since the data base is so limited,  the result
that most of the data were correlatable at a  90 percent
confidence level is encouraging.
     Logic would dictate that failures should vary directly
with ash and sulfur, and inversely with Btu content  since
Btu content correlates inversely with ash  and sulfur.  The
expected relationship with capacity factor is not entirely
clear.  It is possible that a boiler with  a high capacity
factor would tend to exhibit a high failure rate since
failures are the result of strenuous operation.  It  is
apparent that failures approach zero as capacity  factor
approaches zero, but it is also evident that failures must
also approach zero as capacity factor approaches  100 per-
cent.  The question remains whether failure rates  are in-
creased as capacity factors are increased or whether the
failure rates exert a limiting effect on the capacity
factor.  The situation may vary from boiler to boiler.,  For
example a relatively new boiler may be run at a high capa-
city  factor with few operating problems whereas an older
boiler may show high failure  rates at  a high capacity
factor, due to the  stress of  overwork  and at a low capacity
factor due to the  fatigue of  cyclic or off-and-on operation.
      Most of the derived regression coefficients were con-
sistent in sign with expected influences  of  ash, Btu and
sulfur variations,  but  notable exceptions occurred, espe-
cially where multiple regression relationships were sig-
nificant.  As an example,  for the TVA system as a whole,  ash
appeared  to have a subtractive effect on  flyash and soot-
blower erosion  failures.   Such a relationship is contrary to
expectations  and observations.  A closer  look at the  data
explains  the  anomaly.   The derived regression equation  chows
                            103

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flyash and sootblower erosion failures to be a function of
the ash and Btu contents of the coal supply.  The equation
indicates that failures decrease as either the Btu content
or the ash content increases.  However, the Btu and ash
contents for coal are strongly correlated.  TVA data in-
dicate that historically each one percent increase in ash
content has reduced coal heating values by about 205 Btu/lb.
If this relationship is used to eliminate Btu content fron
the regression equation it can be calculated that a one
percent ash increase in the overall coal supply will predict
that 24 additional flyash and sootblower erosion failures
vill occur annually.
     This predicted increase is about 20 percent of the
current flyash and sootblower erosion failure rate  (116 per
year).  Observed and predicted failures are plotted vs. ash
content in Figure 1.  Two items should be noted.  First, it
is apparent that A significant correlation exists between
failures and ash content, and a reasonable straight-line fit
to the data could be made.  Second, the plotted data fit
does not result in a straight-line relationship with ash,
owing to the fact that there are two underlying variables in
the regression equation.
     All of the significant  (confidence level, 0.9) rela-
tionships that were found appear in Figures 2 through 24.
In each case observed and predicted failure levels were
plotted against time.
     It is likely that there are other parameters which can
be used to predict failures more accurately than the param-
eters which were used in this preliminary study.  For ex-
ample, the indices for ash slagging and fouling nay be more
significant than ash content in predicting  failure  rates.
These indices are as follows:
                             104

-------
    120
    TOO
   UJ
   ex
     80
   o
   ct
o 60
00
I
o
?40
     20
       14
               O
               D
          D
          O
              15
                              O
                              D
                                         6
                                         o
                                         D
                                           D OBSERVED
                                           O PREDICTED
16        17
   ASH, %
16
19
Figure 1.  TVA  system annual fly ash  and soot blower erosion
     failure  observations and  predictions plotted against
              overall yearly ash content of coal.
                               1Q5

-------
       500i
      400
   er
   ,-  300;
   IS)
   UJ
   a:
      200
      100
                     INDEPENDENT VARIABLES
                      COAL HEAT CONTENT
                                         OBSERVED
                                      —  PREDICTED
                    _L
J
I
             1967  T96B  1969   1970  1971   1972  1973  1974

                                YEAR
Figure 2.   Total  failures - TVA  composite -  11  plants
                             106

-------
                  INDEPENDENT VARIABLES
                    COAL ASH CONTENT
                    COAL HEAT CONTENT
                OBSERVED
                PREDICTED
           1967  1968 1969  1970  1971  1972^973  1974
                            YEAR
Figure 3.  Fly  ash and  soot blower  erosion  failures

              TVA composite - 11 plants.
                           107

-------
                       INDEPENDENT VARIABLES
                         COAL  ASH CONTENT
                         COAL  HEAT CONTENT
                       OBSERVED
                 	 PREDICTED
                1967   1966  1969  1970  1971  1972   1973  1974
                                   YEAR
Figure  4.   Slag  erosion  failures  - TVA  composite  - 11 plants.
                               108

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                    INDEPENDENT VARIABLES
                      COAL ASH CONTENT
                      COAL HEAT CONTENT
                  OBSERVED
                  PREDICTED
             1967   1968  1969  1970  1971   1972  1973 1974
                              YEAR
Figure 5.  Erosion failures -  TVA composite  - 11 plants
                             109

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                                  APPENDIX E

       CALCULATIONS OF BOILER EFFICIENCY IMPROVEMENT  AS A RESULT  OF  PCC

     The following  calculations  show the  efficiency improvement that can be
obtained by  burning  a cleaned  coal  if  the exhaust  gas  temperature can be
lowered by  the same amount that the acid dew  point is lowered  as  a result  of  coal
cleaning.

     The following raw coal composition  is assumed, based on a typical Western
Kentucky coal.


                    •   TABLE E-l.   RAW COAL COMPOSITION
Constituent
C
H2
02
N2
S
H20
Ash
Total
Percent
60.790
4.068
6.510
1.287
3.325
5.000
19.000
100.000
Ib-moles
5.066
2.044
0.203
0.046
0.104
0.278


     It  is  assumed that  3 percent of  the  coal  sulfur  is converted  to S03;
the  balance  to  S02.    It  is  assumed that  1 percent of  the coal  carbon is
converted  to  CO;  the  balance  to C02.  Combustion  air with  3  percent mois-
ture is taken on a molar basis to be

     02 * 3.750 N2 + 0.238 H20

Excess air is  assumed to be 20 percent.  The resulting combustion equation is

     5.066 C * 2.044 H2 + 0.203 02 * 0.046 N2 «• 0.104 S + 0.278 H20 +  19 Ib ash

     «• 7.187 (02 + 3.750 N2 + 0.238 H20)

     -» 5.015 C02 + 0.051 CO + 4.033 H20 + 0.101 S02
     «• 0.00312 S03 + 26.997 N2 + 1.22202 + 19 Ib  ash
                                     110

-------
     Ib H20/lb  dry  gas =  0.088
     H20 dew point  =  122°F  (Zimmerman 1964)
     p S03/p H20 =  7.7 x  10"4
     dew point  elevation  =  126°F  (Strauss 1966)
     acid dew point = 122°F + 126°F = 248°F
     Similar calculations are made for  the  cleaned  coal,  which is assumed to
have the characteristics  in Table E-2.

                     TABLE  E-2.   CLEANED COAL  COMPOSITION
Constituent
C
H2
0.
N2
S
H20
Ash
Total
Percent
69.610
4.681
7.455
1.474
2.280
5.000
9.500
100.000
Ib-moles
5.801
2.341
0.233
0.053
0.071
0.278


     5.801 C + 2.341 H2 * 0.233 02 + 0.053 N2 + 0.071 S «• 0.278 H20
      + 9.5 Ib ash
     + 8.171 (02 + 3.750 N2 + 0.238 H20)
     •» 5.743 C02 * 0.058 CO + 4.564 H20 + 0.069 S02
     + 0.00213 S03 + 30.694 Nj, + 9.5 Ib ash
     Ib H20/lb dry gas = 0.075
     H20 dew point = 118°F (Zimmerman 1964)
     p S03/p H20 = 4.7 x 10~4
     dew point elevation = 121°F (Strauss 1966)
     acid dew point = 118°F + 121°F = 239°F
      Since 100  Ib  of  coal  produces  about  1185  Ib  of  moist  exhaust  gas,  the dew
point change  is equivalent to
      1185  Ib  x  9°F x  0.25  Btu/lb°F  =  2666 Btu
                                     111

-------
In each 100 Ib of coal there is now an additional  2666 Btu available,  which  is
equivalent to  an  additional  0.3 kWh  per 100 Ib  of  coal.  This  effectively
changes the  heat rate  from 10,000 to 9972; system efficiency  increases  from
34.13 to 34.23 percent, improving by 0.1 percent.
                                     112

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                                 APPENDIX  F

        SAMPLE CALCULATIONS  ON  ESP  PERFORMANCE FOR RAW AND WASHED COAL


     ESP requirements in conjunction with raw and cleaned coal were calculated
using Deutsch and Matts-Ohnfeldt  equations  for specific collecting area (SCA).

EXAMPLE 1 - UNCLEANED COAL
     3.5% S
     20% ash
     10,600 Btu/lb

Assuming that 85 percent  of  the  coal  ash is emitted as  fly  ash, uncontrolled
emissions are


     0.85 x 0.20 Ib/lb coal  . 1E>  Q7 1h/in6  Rtll
       10,670 Btu/lb coal	15'93 1b/1°  Btu

To meet a regulation of 0.1 lb/106  Btu, required ESP efficiency is

     100 x 15.83/15.93 = 99.37 percent.

To meet a regulation of 0.03 lb/106 Btu, required ESP efficiency is

     100 x (15.93 - 0.03)715.93 = 99.81 percent.

At  300°F,  estimated resistivity is 4.1 x  106  ohm  cm.   Migration  velocity is
31.2 ft/min.

     SCA = "100° 1" (1 " ")  (Deutsch)
                  w

where:  SCA = ft2/1000 acfm

        w = migration velocity, ft/min
        n = efficiency required (decimal)


g 0.10 lb/106 Btu, SCA = '100° ln3^12"-9938) =  163 Deutsch (207 Matts-Ohnfeldt)


3 0.03 lb/106 Btu, SCA = "I000 ln^(l -.9981? =  200 Deutsch (314 Matts-Ohnfeldt)
                                     113

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EXAMPLE 2 - WASHED COAL
     2.4% S
     10% ash
     17,000 Btu/lb
Required ESP efficiency is 98.59% for 0.10 lb/106 Btu
Required ESP efficiency is 99.58% for 0.03 lb/106 Btu

Assume 300°F
Estimated resistivity = 1.6 x 1010 ohm cm
Migration velocity = 28.8 ft/min.
For 0.10 lb/10c Btu, SCA = 148 Deutsch (158 Matts-Ohnfeldt)
For 0.03 lb/10c Btu, SCA = 190 Deutsch (260 Matts-Ohnfeldt)

     Coal cleaning  reduces  as  content by 10 to 70 percent and sulfur  by  up  to
     35 percent.    Heating  value  was  upgraded  by  one-third to  26  percent.

     Changes in as* composition and fusion properties,  decreases  in coal  vari-
     ability, and shifts in coal grindability as a result of coal  cleaning can
     affect power generation costs.

     Cleaning  plant  capital costs  are  less than five percent of  the capital
     cost  for  a  1000-MW power  plant that  the  cleaning plant would  serve.

     Cleaned coal costs exceed raw coal  costs by approximately one to  two mills
     per kWh.

     Coal cleaning  can reduce  coal  transportation costs by  0.1  to 1.8 mills
     per kWh.

     Coal cleaning can reduce power plant capital costs by 0.2 to 0.9  mill/kWh.
     Savings occur for ash handling, particulate removal, FGD, boiler, pulver-
     izer, and maintenance.

     The  cost  of  coal cleaning  can  be  offset  by savings  in transportation
     costs,  capital costs, and operating and maintenance costs.
                                     1J4

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                               TECHNICAL REPORT DATA
                         (Please read Inunctions on the reverse before completing)
 . REPORT NO
 EPA-600/7- 80-105
                          2.
                                                      . RECIPIENT'S ACCESSION NO.
 . TITLE ANDSUBTITLE
 ?ost Benefits Associated with the Use of Physically
 Cleaned Coal
                                REPORT DATE
                               May 1980
                                . PERFORMING ORGANIZATION CODE
 AUTHORIS)
 i.A.  Isaacs,  R.A. Ressl, and P.W.Spaite (Consultant!
                                                     B. PERFORMING ORGANIZATION REPORT NO.
 . PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
P.O.  Box 20337
Dallas, Texas  75220
                               10. PROGRAM ELEMENT NO.
                               EHE623A
                               11. CONTRACT/GRANT NO.

                               68-02-2603, Task 31
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC  27711
                               13. TYPE OF REPORT AND PERIOD COVERED
                               Task Final; 5/78-11/79
                               14. SPONSORING AGENCY CODE
                                 EPA/600/13
is SUPPLEMENTARY NOTES n;RL..RTP project officer is James D. Kilgroe, Mail Drop 61,
919/541-2851.
16. ABSTRACT
              repor|. identifies and quantifies several benefits associated with the
use of physically cleaned coal in the operation of utility electric power plants. The
benefits occur in: coal and ash handling, boiler operation, and gas handling and
cleaning.  Cleaning removes sulfur from the coal, thus reducing the emission of SO2
into the atmosphere. In most cases, however, the power plant must install supple-
mental control equipment to reduce emissions enough for compliance with environ-
mental regulations. The cost of this supplemental equipment is less than  the cost of
a control system for use with uncleaned coal, but the cost decrement is usually insuf
ficient to offset coal cleaning costs. Typically, however, the total of all benefits ad-
dressed in the report exceeds the cost of cleaning the coal.  In a typical case , the
cost of coal cleaning is #4. 85 per ton of cleaned  coal; whereas , total benefits asso-
ciated with cleaning the coal are $7. 20  per ton of cleaned coal. The report recom-
mends additional projects aimed at quantifying coal cleaning benefits , and presents
an annotated bibliography of related studies .
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.IDENTIFIERS/OPEN ENDED TERMS
                                             .  COSATi Field/Grour
Pollution
Coal
Coal Preparation
Desulfurization
Cost Effectiveness
Electric Power Plants
Utilities
Coal Handling
Ashes
Materials Handling
Gas Scrubbing
Pollution Control
Stationary Sources
Physical Coal Cleaning
13B
21D,08G   15E
081        21B
07A.07D   13H
14A
10B
IS. DISTRIBUTION STATEMENT

 Release to Public
                    19. SECURITY CLASS (This Rtpon)
                    Unclassified
                         21. NO OF PAGES
                             124
                    20 SECURITY CLASS (This page I
                    Unclassified
                         22. PRICE
EPA Form 2220-1 («-73)
                                        115

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