EPA-450/3-78-OO7
PARTICULATE AND SULFUR DIOXIDE
        EMISSION CONTROL COSTS
   FOR LARGE  COAL-FIRED BOILERS
                            by

                  PEDCo. Environmental, Incorporated
                       11499 Chester Road
                      Cincinnati, Ohio 45246
                      Contract No. 68-02-2535
                  EPA Project Officer: Richard Jenkins

                  Strategies and Air Standards Division




                         Prepared for

              U.S. ENVIRONMENTAL PROTECTION AGENCY
                  Office of Air and Waste Management
                Office of Air Quality Planning and Standards
                Research Triangle Park, North Carolina 27711

                         February 1978

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This report is issued by the Environmental Protection.Agency to report
technical data of interest to a limited number of readers.  Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organisations - in limited quantities - from the
Library Services Office (MD-35) , U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; or,  for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22161.
This report was furnished to the Environmental Protection Agency by
PEDCo Environmental, Inc.,  11499 Chester Road, Cincinnati, Ohio 45246,
in fulfillment of Contract No. 68-02-2535.  The contents of this report
are reproduced herein as received from PEDCo Environmental, Inc.
The opinions, findings, and  conclusions expressed are those of the
author and not necessarily those of the Environmental Protection Agency.
Mention of company or product names is not to be considered as an endorse-
ment by the Environmental Protection Agency.
                     Publication No. EPA-450/3-78-007
                                11

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                       TABLE  OF  CONTENTS





                                                        Page


EXECUTIVE  SUMMARY                                        . .
                                                        Vll


1.0   INTRODUCTION   -,.        -                            !_!



2.0   EMISSION CONTROL  ALTERNATIVES TO MEET REVISED      2-1

      NSPS



      2.1   Particulate  Emission  Control Alternatives     2-1



      2.2   Sulfur Dioxide Emission Control               2-4

           Alternatives



3.0   PARTICULATE CONTROL SYSTEM COSTS                   3-1



      3.1   Cost Elements                                 3_i



      3.2   Cost Estimating Approach                      3-7



      3.3   Model Plant Costs                             3-11



      3.4  Energy Penalties                              3-13



     3.5  Cost Comparison                               3-17



4.0  SO2 EMISSION CONTROL SYSTEM COSTS                 4-1



     4.1  Cost Elements                                4_1



     4.2  Cost Estimating Approach                     4-7



     4.3  Model  Plant  Costs                            4_15



     4.4  Energy Penalties                              4_18



     4.5  Sludge Disposal Alternatives                  4-24



     4,6  Cost Comparisons  For FGD Systems              4-31
                              1X1

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                 TABLE OF CONTENTS  (continued)




                                                         Page

 5.0   IMPACT OF EMISSION AVERAGING TIMES ON THE  COSTS    5-1
      OF FGD


 6.0   SINGLE PLANT APPLICATIONS OF COMBINED PHYSICAL     6-1
      COAL CLEANING AND FLUE GAS DESULFURIZATION


APPENDIX A  DETAILED COST BREAKDOWNS FOR PARTICIPATE   A-l
             CONTROL DEVICES


APPENDIX B  COST  IMPLICATIONS OF ADDING SPARE MODULES  B-l
             TO  FLUE GAS  DESULFURIZATION SYSTEMS


APPENDIX  C  DETAILED COST BREAKDOWNS FOR FGD SYSTEMS   C-l
                              IV

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                           TABLES
NO.
     Model Plant Parameters and Assumptions Used in
     the Particulate Control Analysis

     Model Plant Parameters and Assumptions Used in
     the Sulfur Dioxide Control Analysis

     Analyses of Coals Used as the Cost Estimating
     Basis

     Particulate Emission Control Device Design
     Parameters
Page

xiii


xiv


xv i


xvii
 5   Design Parameters for the FGD Systems             xviii

 6   Coal Analyses and Sulfur Variability Over         xxi
     Various Averaging Times

 7   Costs of a Lime FGD System Designed for 90        xxii
     Percent SO2 Removal Over an Annual Percentage
     Period

 8   Costs of a Lime FGD System Designed for 90        xxiii
     Percent SO- Removal Over a 30-Day Averaging
     Period

 9   Costs of a Lime FGD System Designed for 90        xxiv
     Percent SO, Removal Over a 24-Hour Averaging
     Period

10   Costs of a Lime FGD System Designed for 90        xxv
     Percent SO2 Removal Over a 3-Hour Averaging
     Period

11   Costs of Particulate Control Alternatives         xxvii

12   Costs of SO- Control Alternatives                 xxxi

3-1  Model Plant Parameters and Assumptions Used in    3-8
     the Particulate Control Analyses
                              v

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                     Tables (continued)

No.                                                    Page

3-2  Coal Analyses Used in Calculating Particulate     3-9
     Control Costs

3-3  Particulate Emission Control Device Design        3-10
     Parameters

3-4  Costs of Particulate Control Alternatives         3-12

3-5  Capacity and Energy Penalties Associated With     3-16
     Particulate Control Alternatives Expressed as
     a Percentage of Gross Output

3-6  Energy Penalties Associated With Particulate      3-18
     Control Alternatives Expressed in Mills Per
     Kilowatt Hour

3-7  Comparative Capital Costs For a Cold-Side ESP     3-19
     on a 500 MW Boiler

4-1  Model Plant Parameters and Assumptions Used in    4-8
     The Sulfur Dioxide Control Analyses

4-2  Analyses of Coals Used as The Cost Estimating     4-10
     Basis

4-3  Summary of Options Costed                         4-12

4-4  Design Parameters For the FGD Systems             4-13

4-5  Costs of SO2 Control Alternatives                 4-16

4-6  Capacity and Energy Penalties Associated With     4-21
     S02 Control Alternatives Expressed as a Percent-
     age of Gross Output

4-7  Energy Penalties Associated with SO2 Control      4-25
     Alternatives Expressed in Mills Per Kilowatt
     Hour

4-8  Impact of Various Subset Sludge Disposal Options  4-32
     on the Annualized Cost of Sludge Disposal
                               VI

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                     TABLES (continued)

No.                                                    Page

4-9  Comparison of Costs For a Lime FGD System on a    4-33
     1000 Mw New, Coal-Fired Generating Unit, 3.5%
     S Coal, and 90% SO2 Removal

4-10 Comparison of Costs For a Limestone FGD System    4-37
     on a 500 MW New, Coal-Fired Generating Unit,
     3.5% S Coal, and 1.2 Lbs/Million Btu Allowable
     Emissions

5-1  Coal Analyses and Sulfur Variability Over         5-2
     Various Averaging Times

5-2  Relative Standard Deviation of Sulfur Content     5-3
     in Coal

5-3  Costs of a Lime FGD System Designed For 90        5-4
     Percent S02 Removal Over an Annual Averaging
     Period

5-4  Costs of a Lime FGD System Designed For 90        5-5
     Percent SO, Removal Over a 30-Day Averaging
     Period

5-5  Costs of a Lime FGD System Designed for 90        5-6
     Percent SO2 Removal Over a 24-Hour Averaging
     Period
5-6  Costs of a Lime FGD System Designed For 90        5-7
     Percent SO2 Removal Aver a 3-Hour Averaging
     Period

6-1  Washability Data For High Sulfur Coals            6-2
                               vii

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                      EXECUTIVE SUMMARY





Introduction



     In support of a program to review New Source Perform-



ance Standards (NSPS) for particulate and sulfur dioxide



(SO2) emissions from coal-fired steam generators, the U.S.



Environmental Protection Agency (EPA) is preparing estimates



of the costs of air pollution control equipment.  The pro-



gram includes estimating costs of the various control alter-



natives available to meet the present NSPS of 43 nanograms



particulate per joule of heat input  (0.1 lb/106 Btu) and 516



nanograms SO^ per joule of heat input (1.2 lb/10  Btu), with



comparative cost estimates of control options to meet alter-



native emission levels of 22 nanograms particulate per joule



heat input (0.05 lb/10*5 Btu) , 13 nanograms particulate per



joule heat input (0.03 lb/10  Btu), 215 nanograms SO, per



joule heat input (0.5 lb/10  Btu), and 90 percent reduction



of potential SO2 emissions.  EPA has contracted with PEDCo



Environmental, Inc. to develop cost estimates for flue gas



desulfurization (FGD) systems, physical coal cleaning facili-



ties, electrostatic precipitators (ESP), fabric filters,



venturi scrubbers,  cost differentials of boilers designed
                               IX

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for western subbituminous coals versus Eastern coals, and



costs of transporting coal from the west to eastern markets



for each of the alternative emission levels.  Model steam-



electric generating plants of various sizes were used as a



basis for estimating these costs.



Emission Control Alternatives to Meet Revised NSPS



     The revisions to the NSPS for particulate emissions



being considered in this study are 22 ng/J  (0.05 lb/10  Btu)



and 13 ng/J (0.03 lb/10  Btu).  Control devices available to



attain these emission levels are ESP's and  fabric filters.



Wet venturi scrubbers may be utilized to attain the present



NSPS level of 43 ng/J (0.1 lb/10  Btu) particulate emission



and the alternative level of 22 ng/J  (0.05  lb/10  Btu) par-



ticulate emission.



     The alternative NSPS levels being considered for SO-



emissions are 215 ng/J  (0.5 lb/10  Btu) and 90 percent



control regardless of potential SO2 emissions.  Control



techniques available to meet these alternative standards are



FGD, combination physical coal cleaning and FGD, and low



sulfur coal and FGD.



Control System Cost Components



     The costs of a control system consist of the capital



costs of purchasing and installing the system and the annual



costs of ownership, operation and maintenance of the system.

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Capital costs are further categorized as direct ar)d indirect
costs.  Direct costs are those for purchase of the items of
equipment and the labor and material required to install the
equipment and interconnect it.  Indirect costs are those not
attributed to specific equipment items such as freight,
interest, taxes, spare parts, engineering, overhead, shake-
down, and contingencies.  Annual costs are categorized as
operation and maintenance costs and fixed costs.  Operation
and maintenance costs include those expenditures for raw
materials, utilities, and maintenance and supervising labor.
Fixed costs include depreciation, taxes, insurance, and
costs of borrowed capital.
Co s t E s t ima t i ng Approac h
     The control system costs were determined based on a
typical new coal-fired plant model.  Three sizes were
selected for analysis of particulate control system costs
and five sizes for analysis of SO2 control system costs.  A
midwest location is assumed for the model plants.  For
particulate control systems, three control levels were
examined:  43 ng/J (0.1 lb/106 Btu), 22 ng/J (0.05 lb/106
Btu) and 13 ng/J (0.03 lb/106 Btu).  For SO2 control alter-
natives, three control levels were also analyzed:  516 ng/J
                                          >2
(1.2  lb/10  Btu),  90 percent removal  of  SO,  regardless  of
                                                  6
potential emission levels, and 215 ng/J (0.5 lb/10  Btu).
                               XI

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      Table 1 presents a summary of the model plant char-                '


 actoristics and assumptions used for the cost analysis of
                                                                     .    *•

 particulate control options.  Table 2 presents assumptions              ,
                                                                         i

 and characteristics used in the S02 control option analysis.             I

                                                                   •    • * 1'
      In the analysis several types of coal are considered               '
                                                                        . ji

 including three Eastern coals,  two Western coals,  and an

                                                                      '  ' i"
 Eastern anthracite coal.   Analyses of these coals  are given             i


 in  Table 3.                                                              [
                                                                        1 i

      Parameters used for the .particulate control systems                :


 cost estimates  are given in Table 4.   Parameters used for


 the FGD systems cost estimates  are given in Table  5.                     [


      Computer programs  developed by PEDCo were then used to'             :

                                                                       • ' £
 calculate costs for each  control alternative based on the               '


 model plant  parameters.   The computer program uses mid-1976            .}


 costs as  a basis with an  escalation rate of 7.5  percent  per             I
                                                                         i'

 year  through project completion.   Results of the cost esti-             I
                                                                         i

 mates are expressed in  mid-1980  dollars.                                 f

                                                                       '
 Averaging Times                                                          f
  •  j                                                                     i,

     The  average time period over  which  an emission regula-             \


 Lion must be met has a  significant  impact on the design  and             |


 applicability of various control techniques.  Averaging            .  '  '  \


 times will have  the most impact on  SO0 emission  regulations.             I'

                                      2       ,  .       	I
 Factors affecting averaging  times include  the sulfur vari-              •!
                                                                        • . .(•
                                                                         ^

ability in fuel, the reliability of the pollution control               ••
                               XII

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                                        XIX
-------
system, variations in system load, and the efficiency and



flexibility of emission control equipment.  If the SO,,



control method is an FGD system, the system must be designed



to cope with a higher average sulfur content in the fuel for



shorter averaging periods.



     For purposes of evaluating the impacts of various



averaging times on the costs of compliance, a lime FGD



system was costed for plants of three sizes, three types of



coal, and for four averaging periods.  Coals chosen for



analysis are listed in Table 6.  Also presented in the table



are average sulfur contents for each size plant over the



various averaging times.  For each size plant, a lime FGD



system was costed designed for 90 percent SO2 removal on the



average sulfur content indicated in Table 6.  Results of the



cost analysis are presented in Tables 7, 8, 9, and 10.



     As the results indicate, costs will increase as the



averaging time is shortened.  The effect is also more sig-



nificant for smaller units due to the increased variability



of sulfur as the quantity used during the averaging time



decreases.  For instance, in the 3.5 percent sulfur case,



reducing the averaging time from 1 year to 3 hours increases



capital costs by 4.5 percent for the 500 MW case com-



pared to 4.0 percent for the 1000 MW case.  Also as the coal



sulfur content decreases, the cost impacts of shorter
                              xx
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                                                  XXV
-------
averaging times decrease.  For  the  0.8 percent sulfur case
the differential capital costs  between 1 year and  3 hour
averaging times varies  from  3.9 percent for the  500 MW case
to 1.7 percent for the  1000  MW  case.  Impacts on annual
operating costs are not significant since their costs
reflect the average annual sulfur content of the coal.
     For this cost study, an averaging time of 3 hours was
used as a basis for determining FGD system costs.
Redundancy
     In reviewing air pollutant limitations and their cost
implications, another consideration is the required opera-
tional availability of  the control method.  The major impli-
cation for this study is the availability required of an FGD
system meeting a 3-hour average emission limitation.  The
availability of an FGD  system is directly affected by the
redundancy built into the system via use of spare components.
For purposes of the cost analysis a single spare module was
assumed to be required  for each boiler with a capacity above
25 MW.  This will assure a high level of availability for
the system.
Particulate Emission Control Cost Estimates
     To analyze the potential cost impact of revisions to
particulate emission regulations,  three particulate control
systems were costed for various size plants sit various
                               xxvi
-------
regulation levels for two coals  (specified in Table 3 as
Eastern 3.48% S and Western 0.8% S coals).  Fabric filters
were costed for a regulation level of 13.4 ng/J  (0.033
lb/10  Btu).  Cold-side electrostatic precipitators were
costed for Eastern high sulfur coal to meet levels of 13
ng/J (0.03 lb/106 Btu), 22 ng/J  (0.05 lb/106 Btu), and 43
ng/J (0.1 lb/10  Btu).  Hot-side electrostatic precipitators
were costed on the Western low sulfur coal to meet these
same regulation levels.  Venturi scrubbers were costed to
meet the present regulation of 43 ng/J and 22 ng/J level.
Results of these cost estimates are presented in Table 11.
     As the results indicate, the costs of control devices
increase as the required emission reduction is increased.
Reducing the NSPS from 43 ng/J to 22 ng/J would increase
capital costs about 5 percent for a cold side ESP on a 500
MW unit burning Eastern high sulfur coal.  For a 500 MW unit
on Western low sulfur coal, the capital costs for a hot-side
ESP would increase about 30 percent.  The annual costs would
increase about 5 percent for the high sulfur case and 30
percent for the low sulfur case.
     If the regulation were reduced to 13 ng/J, the capital
cost of an ESP for the low sulfur case would increase by 54
percent and by 19 percent for the high sulfur case.  Annual
costs would increase by 53 percent for the low sulfur case
                              xxvii
-------
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                                         XXVI11
-------
 and by 19 percent for the high sulfur case.   At a regulation



 level of 22 ng/J, fabric filters appear to be more economi-



 cal for low sulfur coal application than hot side ESP's.



 For the 500 MW case,  capital costs are 28 percent less for



 the fabric filter and annual costs are 48 percent less.



 Sulfur Dioxide Control Cost Estimates




      To analyze the potential economic impact of revisions



 to  the NSPS for SO2 emissions,  various control systems we're



 costed for each of 3  alternative emission levels.   The first



 level examined was the present  NSPS of 516 ng/J (1.2  lb/10^



 Btu).   For Eastern 3.5 percent  sulfur coal,  the cases costed



 included lime,  limestone, magnesium oxide, double  alkali,



 and Wellman Lord FGD  systems  for the 25,  100,  200,  500, and



 1000  MW  boilers,  combined coal  cleaning with lime  FGD for  a



 500 MW boiler,  and combined coal  cleaning  with limestone FGD



 for a  500  MW boiler.   For Eastern 7.0  percent sulfur  coal,



 cases  costed were  lime  and limestone FGD systems for  25,



 100,  200,  500,  and 1000 MW boilers.  A lime  FGD system was



 costed for  a 500 MW boiler for both  anthracite and lignite.



 Incremental boiler costs were estimated for  boilers designed



 for Eastern  low  sulfur, Western  subbituminous, and lignitic



coals versus boilers designed for Eastern high sulfur coal.



Costs were also estimated for the transportation of Western



coal to the Eastern seaboard  (i.e. Boston).
                                xxix
-------
      The  second  SO-  control  level  examined was  a requirement




 for  90  percent removal  regardless  of sulfur content  of  the



 coal burned.   For the Eastern 3.5  percent  sulfur and 7.0



 percent sulfur coals, options costed included lime,  lime-



 stone,  magnesium oxide,  double alkali,  and Wellman Lord FGD



 systems for the  25,  100,  200,  500  and 1000 MW boilers.



 Cases costed  for Western  subbituminous  coal were lime and



 limestone FGD for 25, 200, and 500 MW boilers.   A lime FGD



 system  was also  costed  for anthracite and  lignite for a 500



 MW boiler.




      The third SO2 emission  limitation  examined  was  215 ng/J




 (0.5  lb/10  Btu).  Options evaluated included lime and



 limestone FGD on Western  subbituminous  coal.  Other  options



 evaluated included combined  coal cleaning  and lime FGD and



 combined coal cleaning and limestone FGD on Eastern  7.0



 percent, sulfur coal.




      The costs estimated  for each  of the options  are pre-



 sented  in Table  12.




      The incremental cost of going from the  516  nanograms



 per joule (1.2 lb/106 Btu) to  the  90  percent control case



varied  in capital cost from 10-12 percent  for 3.5 percent



Eastern coal to  less than one percent for  7.0 percent Eastern



coal.  Annualized costs show approximately  the same percentage



 increases.   Assuming that power plants currently using
                               xxx
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-------
Western low sulfur coal do not have to use flue gas desul-
furization under the present NSPS, the cost impact of a
revised NSPS amounts to the entire investment and annualized
cost of control.
     It should be noted that while the investment cost of
the combination of FGD and coal cleaning is close to that
of the 90 percent FGD alone the total annualized costs are
60 percent greater for both the base case and the 215 ng/J
(0.5 lb/106 Btu) case.
                              xxxni
-------
-------
                       1.0   INTRODUCTION





      In  support of a program  to review New Source Perform-



 ance  Standards  (NSPS)  for particulate and sulfur dioxide



 (SO2) emissions from coal-fired steam generators, the U.S.



 Environmental Protection Agency (EPA) is preparing estimates



 of the costs of air pollution control equipment.  The pro-



 gram  includes cost estimates  of the various control alterna-



 tives available to meet the present NSPS of 43 ng particu-



 late per joule of heat input  (0.1 lb/106 Btu) and 516 ng SO2



 per joule of heat input (1.2  lb/106 Btu), with comparative



 cost estimates to meet alternative emission levels of 22 ng



 particulate per joule heat input (0.05 lb/106 Btu), 13 ng



 particulate per joule heat input (0.03 lb/106 Btu), 215 ng



 S02 per joule heat input (0.5 lb/106 Btu), and 90 percent



 reduction of potential SQ2 emissions.  EPA has contracted



 with PEDCo Environmental,  Inc. to develop cost estimates for



 flue gas desulfurization (FGD) systems, physical coal clean-



 ing facilities, electrostatic precipitators (ESP), fabric



 filters, venturi scrubbers,  cost differentials of boilers



designed for western subbituminous coals, and transportation



of coal from the west to eastern markets for each of the
                            1-1
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alternative emission levels.  Model steam-electric generating
plants of various sizes were used as a basis for estimating
these costs.
     In Section 2 the various emission control alternatives
considered in the study are described.  Section 3 presents
the cost estimates for the particulate emission control
devices.  SO2 emission control alternatives cost estimates
are presented in Section 4.  In Section 5, the concept of
averaging time and its effect on emission control require-
ments is presented.  Section 6 describes the combination of
physical coal cleaning and FGD as an SO2 emission control
alternative.
                            1-2
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         2.0  EMISSION CONTROL ALTERNATIVES TO MEET



                        REVISED NSPS





     The revisions to the NSPS for particulate emissions



being considered in this study are 22 ng/J  (0.05  lb/10  Btu)



and 13 ng/J  (0.03 lb/10  Btu).  Control devices available to



attain these emission levels are electrostatic precipitators



(ESP) and fabric filters.  Wet venturi scrubbers  may be



utilized to attain the present NSPS level of 43 ng/J  (0.1



lb/106 Btu)  and also  the 22 ng/J  (0.05  lb/106 Btu) particu-



late emission level.



     The alternative NSPS being considered for SO- emissions



are 215 ng/J (0.5 lb/106 Btu)  and 90 percent control.



     Control techniques available to meet these alternative



standards are FGD and combined physical coal cleaning and



FGD.  To meet the present NSPS of 1.2 Ib SO2/106  Btu, low



sulfur coal alone may meet the standard.  But any new



standard based on a percentage reduction precludes the use



of low sulfur coal without FGD.



2.1  PARTICULATE EMISSION CONTROL ALTERNATIVES



     This study considers 3 particulate control devices:



ESP's,  fabric filters, and venturi scrubbers.  The following



sections describe these control devices and their capa-



bilities.
                             2-1
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2.1.1  Electrostatic Precipitators



     Electrostatic precipitation is a physical process for



the removal of suspended particulates from a gas stream.



The particles are charged electrically and separated from



the gas streams by contact with collecting surfaces having



the opposite electrical charge.  The agglomerated dust is



periodically removed from the collecting surface by vibrat-



ing or rapping the surface.  This dust drops from the



electrical zone to hoppers for ultimate disposal.  Com-



mercially available precipitators include sections of



collecting plates, discharge electrodes, rapping devices,



dust hoppers, enveloping insulation and casing, and the



appropriate electrical energizing equipment.



     Current ESP units, both those treating flue gas from a



heat source and those collecting particulates emitted from



processes are greatly improved from those designed as



recently as the middle 1960's.  This can be attributed to



stringent regulations, more accurate techniques for per-



formance prediction, utilization of computers for calcula-



tions, superior construction materials, high quality auxiliary



components and the availability of a useful base of recent



ESP performance experience.



     On utility coal-fired boiler applications, ESP's can



achieve emission levels as low as 13 ng of  particulate per



joule of heat input  (0.03 lbs/106 Btu).
                             2-2
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 2.1.2  Fabric Filters
      Fabric filters may be used for the removal of suspended
 particles from gas streams.  The particles are removed by
 passage of the gas stream through woven cloth or fiberglass
 which prevent particles from passing through.  The agglo-
 merated dust is periodically removed from the fabric by
 mechanically shaking the fabric or by blowing air in a
 reverse direction through the fabric.   The dust is collected
 in hoppers at the bottom of the filter for ultimate dis-
 posal.   The system consists of bags,  shaking devices or a
 reverse air system,  dust hoppers,  and  enveloping casing and
 insulation.
      On utility coal-fired  boiler  applications,  fabric
 filters can  achieve  emission levels of  about 13  ng particu-
 late  per joule  of  heat  input (0.03 lb/106  Btu).
 2.1.3  Venturi  Scrubbers
      Venturi scrubbers  are effective in removal of  suspended
 particles  from  gas streams.  The particles are removed by
 contact with atomized water droplets and subsequent removal
 of the water droplets and wetted particles.  The collected
water and particulate matter must be treated to prevent
water pollution.  Generally the efficiency of a venturi
scrubber increases with pressure drop.
     The system consists of the scrubber,  pumps, an entrain-
                             2-3
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ment separator and a fan to overcome the pressure drop.



     On utility coal-fired boiler applications, venturi



scrubbers can achieve emission levels of about 43 ng/J  (0.1



Ibs per million Btu) of particulate at moderate pressure



drops  (10-20 inches H2O).  At greater pressure drops  (20-30



inches H0O) , venturi scrubbers can achieve esmission levels
        f,t


Of 22 ng/J  (0.05 lb/106 Btu).



2.2  SULFUR DIOXIDE EMISSION CONTROL ALTERNATIVES



     Several methods exist by which SO0 emissions may be
                                      £•


reduced to  levels required to comply with NSPS.  In this



study the following control technologies were considered:



flue gas desulfurization  (PGD) and coal cleaning in combina-



tion with FGD.  The following sections describe these con-



trol technologies and their capabilities.




2.2.1  Flue Gas Desulfurization  (FGD)



     Several FGD processes have  been developed for the



removal of  sulfur dioxide from flue gases before the  gases



are discharged to the atmosphere.  Flue gases are brought



into contact with a chemical absorbent in a  unit described



as an  absorber.  The absorbent reacts chemically with SO2 to



produce a  slurry containing dissolved or solidified  sulfur



compounds.  FGD processes are classified as  regenerable or



nonregenerable, based on whether the SO2 is  separated from




the  absorbent  as a  by-product or discarded  along with the



absorbent  as waste.  Nonregenerable processes  produce a



sludge that requires disposal  in an environmentally  sound





                               2-4
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 manner.   Regenerable processes include additional steps to
 process  the sulfur into liquid SC>2,  sulfuric acid,  or
 elemental sulfur.
      Most FGD processes in use in the United States are
 nonregenerable,  using lime or limestone for scrubbing.   A
 recirculating alkaline slurry of lime or limestone  in water
 is  contacted with  SO2 in the  gas stream.   The slurry reacts
 with  the SO2 to  form various  sulfite and sulfate  salts.   The
 salts are removed  from the water by  means of settlers,
 clarifiers,  or filters.   The  sludge  produced is either
 chemically stabilized and disposed of as  an inert landfill
 material or stored as an unstabilized sludge in a clay-
 lined pond.
      The regenerable  processes offer certain advantages  over
 the nonregenerable ones.   No  solid waste  is accumulated,  and
 resulting by-products may have a market value.  Also, total
 waste  stream quantities  are significantly reduced.  Among
 the regenerable processes the most common are the sodium
 solution scrubbing (Wellman-Lord), magnesium oxide  slurry
 scrubbing  (Mag-Ox), and  catalytic oxidation (Cat-Ox) pro-
 cesses.  The Wellman-Lord process absorbs  SO, in a  sodium
 sulfite/bisulfite  solution, which is  then  heated in a
 separate vessel to liberate a gas containing SO2 in a high
concentration, which  is  further processed  into commercial
grade SO2, sulfuric acid, or elemental sulfur.  In the Mag-
                             2-5
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Ox process, dilute magnesium oxide slurry is used as the

scrubbing absorbent.  The spent slurry is regenerated, and

the SO,, is converted into commercial-grade sulfuric acid.

The regenerated solids are recycled for reuse.  In the Cat-

Ox process SO- is directly removed by converting it cat-

alytically into sulfuric acid.  Regenerable processes

require the utilities to enter the chemical manufacturing

business, and the utilities must then be staffed with people

who are able to compete with established chemical producers.

     FGD systems can generally be designed to provide SO~

removal efficiencies of 80 to 95 percent under most condi-

tions of practical operation.

2.2.2  Combined Physical Coal Cleaning and Flue Gas
       Desulfurization

     Physical coal cleaning entails the use of specially

designed equipment that separates coal from associated

minerals, clay, slate, and other impurities.  These separa-

tions are based on differences in the physical properties of

coal and its impurities, such as density, surface charac-

teristics, and size and shape of the particles to some

extent.  Sulfur occurs in coal in three forms:  mineral

sulfur (pyrite),  organically bound sulfur, and sulfate

sulfur.  The pyritic form of sulfur is the only form remov-

able by coal washing techniques.
                             2-6
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     As much as 80 percent of the pyritic sulfur can be
removed by coal washing.  The pyrite content of coal accounts
for 20 to 80 percent of the total sulfur content, depending
on the particular coal analysis.
     The first step in coal preparation is size reduction.
In a conventional coal preparation plant, incoming coal is
coarsely crushed to a top (largest) size of about 1-1/2
inches.  Coarse grinding minimizes the quantity of fine
coal.  The degree of size reduction depends on the type of
coal cleaning operation and the hardness of the coal.
Grinding liberates mineral impurities associated with the
coal.  The ground coal is passed over screens for separation
into various size fractions.
     The coarse fractions of the ground coal (down to 1/4
inch) can be cleaned in jigs, heavy-media equipment, air
tables, and depending on the top size, Deister tables.
Although these coarse coal cleaning processes operate on
different principles, all are designed to remove mineral
matter (ash) from coal.
     The fine coal circuit uses heavy-media cyclones,
Deister tables, and froth flotation equipment for cleaning.
Cyclones and tables are effective for sizes down to 100 mesh;
froth flotation systems are required for cleaning finer
particles.
                            .2-7
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     The design of coal preparation circuitry must be based



on expert analysis of detailed coal washability data and on



practical experience with the various unit operations.  The



key factor in satisfactory performance of a coal preparation



plant is the degree to which the coal samples used in the



washability test are representative of the total coal seam.



     Physical coal cleaning alone is unlikely to produce



coal complying with NSPS.  Further reduction in SO2 is



usually necessary to attain levels of 1.2 Ib SO2/10" Btu or



lower.  This can be achieved by using an FGD system on the



boiler using cleaned coal.
                            2-8
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             3.0   PARTICULATE CONTROL  SYSTEM COSTS

     The  capital  and  annualized costs of particulate control
 systems can  vary  depending on several factors.  Factors of
 major cost impact are boiler size and capacity factor; type
 of particulate control system; ash content and heating value
 of the coal; maximum  allowable particulate emission rate;
 boiler status  (new or retrofit installation); and replace-
 ment power requirements.
     To present unencumbered cost estimates and illustrate
 the impact of site and process factors on total capital and
 annualized costs  of particulate control systems, a model
 plant approach was used.  The following sections define the
 model plants, the cost methodology, and present the results
 of the cost estimates.
 3.1  COST ELEMENTS
     The capital cost of a particulate control system is
 composed of direct and indirect costs incurred up to the
 successful commissioning date of the facility.  Direct costs
 include the cost of various equipment items and the labor
and material required for installing the equipment items and
 interconnecting the system.   Indirect costs are costs  that
                            3-1
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are necessary  for the overall facility but cannot be attri-



buted to a specific equipment item.  Indirect costs include



such items as  freight, spares, interest, taxes, etc.



     Operating costs of a facility include labor, raw mate-



rials, and utilities required to operate the system on a



day-to-day basis.  These costs include such items as elec-



tricity, water, operating labor, etc.



     A brief description of the capital and annual operating



cost components and the procedure used to obtain their



values is presented in this section.



3.1.1  Capital Costs



     A discussion of capital costs for partieulate control



systems follows under the headings "Direct Costs" and "In-



direct Costs."



Direct Costs



     The "bought-out" cost of the equipment and the cost of



installing it are considered direct costs.   Installation



costs also include the interconnection of the system,  which



involves piping,  electrical, and other work for commis-



sioning the system.   Installation of the equipment includes



foundations,  supporting structures, enclosures,  piping,



ducting,  control panels,  instrumentation,  insulation,  paint-



ing and other similar items.  Costs for interconnection of



the various partieulate control equipment involve site
                             3-2
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 development,  construction of access roads and walkways,  and
 the establishment of rail, barge,  or truck facilities.   The
 cost of administrative facilities  is also considered as  a
 part of the direct costs.
      Various  procedures for estimating the direct costs  are
 available,  each using a different  route to obtain an in-
 stalled cost  of a facility.   In  this study,  the  installa-
 tion-factor technique is used to estimate total  direct
 costs.
      The bought-out cost of each equipment item  is multi-
 plied by an individual  installation factor to  obtain the
 installed cost.   This installed  cost also includes the
 proportional  cost of  interconnecting the  equipment into  the
 system.  The  installation  factors are based on the com-
 plexity  of  the equipment and  the cost of  the material and
 labor required.   The  installed costs of all the equipment
 are added together  to obtain  the total direct cost of the
 facility.
     Direct capital costs for an electrostatic precipitator
include  the purchase and installation of the ESP, the duct-
ing connecting the ESP to the unit, and the ash handling
 and disposal  system.  The ESP includes the housing, dis-
 charge electrodes, collecting plates, distribution plates,
rappers, transformer-rectifiers insulators, bracing,  sup-
ports, hoppers, and foundations.
                             3-3
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     The direct capital costs of a venturi scrubber include

the purchase and installation of equipment including the

scrubber, pumps, circulation tanks, tie-in ducting, founda-

tions and support, and an ash disposal system.

     The direct capital cost for a fabric filter includes

the purchase and installation of the fabric filter, ducting

connecting the fabric filter to the unit, and the ash

handling system.  The fabric filter includes the housing,

bag supports, bags, shakers or reverse air system, insula-

tion, bracing, supports, hoppers, and foundations.

Indirect Costs

     The indirect costs of particulate control systems

include the following:

     Interest accrued during construction on borrowed
     capital.

     Engineering costs; includes administrative, process,
     project, and general; design and related functions for
     specifications; bid analysis; special studies; cost
     analysis; accounting; reports; purchasing; procurement;
     travel expenses; living expenses; expediting; inspec-
     tion; safety; communications; modeling; pilot plant
     studies; royalty payments during construction; training
     of plant personnel; field engineering; safety engineer-
     ing; and consultant services.

     Field overhead; includes the cost of securing permits,
     and right-of-way sections, and the cost of insurance
     for the equipment and personnel on site.

     Freight: includes delivery costs on process and related.
     equipment shipped f.o.b. point of origin.

     Off-site expenditures: includes those for powerhouse
     modifications; interruption to power generation; and
                              3-4
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      service facilities added to the existing plant facil-
      ities.

      Taxesi includes sales, franchise, property, and excise
      taxes.

      Spare parts; (stocked to permit maximum process avail-
      ability) :  includes pumps, valves, controls, special
      piping and fittings, instruments, and similar items.

      Shakedown; includes the costs associated with the
      system start-up.

      Contractor's fee  and expenses; includes costs for field
      labor payroll;  supervision field office; administrative
      personnel;  construction offices; temporary roadways;
      railroad trackage;  maintenance and welding shops;
      parking lot;  communications;  temporary piping and
      electrical and  sanitary facilities;  rental equipment;
      unloading  and storage of materials;  travel expenses;
      permits; licenses;  taxes; insurance;  overhead;  legal
      liabilities;  field-testing of equipment; start-up;
      labor relations.

      Contingency costs;  includes those resulting from mal-
      functions,  equipment design alterations, and similar
      unforeseen  sources.

      Land  cost;  includes  only the  cost of  the land required
      for sludge  disposal.   The cost of land for installing
      equipment  items is accounted  for in the installation
      factors.

      All the indirect cost components,  except the land cost,

are estimated by multiplying  the direct costs by a indirect

cost  factor; the land cost is  based  on  land  rate and the

disposal area required.

3.1.2  Annual Operating Costs

     Generally calculated on an annual basis, the operating

costs of a particulate control system are comprised of:
                              3-5
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     Utilities; includes water for slurries; and electricity
     for pumps, fans, valves, charging electrodes, rappers,
     compressed air systems, lighting, and controls.

     Operating labor: includes supervision and the skilled
     and unskilled labor required to operate, monitor and
     control the system.

     Maintenance and repairs: consists of both manpower and
     materials to keep the units operating efficiently.  The
     function of maintenance is both preventive and correc-
     tive, to keep outages to a minimum.

     Overhead; represents a business expense that is not
     charged directly to a particular part of a process but
     is allocated to it.  Overhead costs include administra-
     tive, safety, engineering, legal, and medical services;
     payroll; employee benefits; recreation; and public
     relations.

3.1.3  Annual Revenue Requirements

     The capital investment of a pollution control system is

generally translated into annual fixed charges.  These

charges, along with the annual operating costs, represent

the total revenue requirement of a particulate control

system.

     The annual fixed charges are classified under four cost

components:  depreciation, taxes, insurance, and capital

costs.  The component costs are summed to obtain the total

fixed changes.

     Depreciation:  The value of the depreciation component
     is obtained by using a straight-line depreciation over
     the life period of the pollution control system.  A 20-
     year life is assumed for depreciation purposes.  The
     annual cost is calculated by dividing the total capital
     investment by the assumed years of life.
                              3-6
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     Taxes:  The value of the tax component is calculated by
     multiplying the total capital cost by the input tax
     rate.  The tax rate can vary for different plants.

     Insurance;  The value of the insurance component is
     obtained by multiplying the total capital cost by the
     insurance rate for the pollution control system.  A
     constant insurance rate of 0.3 percent is assumed.

     Capital charges;  The value of capital charges repre-
     sent the interest paid per year for the usage of
     capital.  The value of this component depends on the
     applicable rate of interest for the borrowed capital.
     The value is obtained by multiplying the total capital
     cost by the input interest rate.

     The total annual fixed charges are obtained by adding

the values of the above four components.  The total annual

revenue required can then be obtained by adding the annual

operating costs to the total annual fixed charges.

3.2  COST ESTIMATING APPROACH

     A model plant approach was used in estimating the costs

of particulate control on new coal-fired boilers.  Typical

plants were defined with characteristics intended to be

representative of the electric utility industry.  Charac-

teristics of the model plants are presented in Table 3-1.

Analyses of the coals used in the calculation of costs are

given in Table 3-2.
                             3-7
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        Table  3-2.   COAL ANALYSES  USED IN CALCULATING
                  PARTICULATE CONTROL COSTS
Coal type
Eastern bituminous
Western subbituminous
% Sulfur,
by wt.
3.5
0.8
Ash, %
by wt.
14
8
Heating value,
10 joules/kg (Btu/lb)
5,737 (12,000)
4,781 (10,000)
     The model plants were selected to incorporate four
varying cost factors:  plant size (capacity), particulate
control system type, coal analysis, and degree of particu-
late control required.  Boiler sizes of 25, 100, 200, 500,
and 1000 MW were selected to cover the range of new coal-
fired utility boilers.
     These regulation levels were chosen for the analysis in
order to determine  the economic impact of tightening the
NSPS for particulate emissions from utility coal-fired
boilers.  Levels examined were 43 ng/J  (0.1 lb/10  Btu),  22
ng/J  (0.05 lb/106 Btu),  and 13 ng/J  (0.03 lb/106 Btu).
Three types of control devices were costed according to  the
capabilities  of the control device.
     Electrostatic  precipitators were costed  to meet all
three  regulation  levels. Design parameters  used  for the
ESP's  are presented in Table  3-3.   These  parameters were
specified by  EPA  based on typical  design  for the  particular
coal types.
                              3-9
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      Fabric filters were costed only to meet the 13 ng/J
 regulation level.   Design parameters for the fabric filters
 are also presented in Table 3-3.   These are based on data
 obtained from fabric filter vendors.   Venturi scrubbers were
 costed  to meet the 43 ng/J level  and the 22 ng/J level with
 the costs reflective of Venturis  used conjunction with a
 flue gas desulfurization system.   Design parameters for the
 venturi  scrubbers  are presented in Table 3-3.   These .are
 based on data from vendors and  designs used at utility
 plants.   The  two coal types presented in Table 3-2 were used
 in  each  case.
 3.3   MODEL  PLANT COSTS
      A summary of  the results of  the  cost analysis for par-
 ticulate  control is  presented in  Table 3-4.  The  costs are
 in August 1980 dollars  and include  escalation  through  pro-
 ject  completion.   The escalation  rate  used was  7.5 percent
per year.
      The  results indicate  that  for  a particular control
device,  costs increase  as  the emission  limit is lowered.  At
the 43 ng/J limit,  ESP's are more economical on high sulfur
coal  than venturi  scrubbers, while Venturis are more eco-
nomical on low sulfur coal applications.
      If the emission limitation were 22 ng/J, the capital
costs of a cold-side ESP on high sulfur coal would increase
about 5  percent for a 500 MW unit, while the capital costs

                            3-11
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 of a hot-side ESP on Western low sulfur coal would increase
 about 30 percent.  Annual costs would be similarly affected,
 with increases of 5 percent and 30 percent for the cold-side
 and hot-side applications respectively.
      If the regulation level were reduced from 43 ng/J to 13
 ng/J, the capital cost of a hot-side ESP on low sulfur coal
 would increase by 54 percent for the 500 MW case while the
 cost of a cold-side ESP on high sulfur coal would increase
 by 19 percent.   Annual costs would be increased by 53 per-
 cent for the low sulfur case and by 19 percent for the high
 sulfur case.  For this case, the most economical option on
 low sulfur  coal  is a fabric filter.   Compared to a hot-side
 ESP,  a fabric filter on a 500 MW boiler burning Western low
 sulfur coal costs 28 percent less  with respect to capital
 posts,  and  48 percent less with respect to  annual costs.
      Samples of detailed cost breakdowns are  included  in
 Appendix A.
 3.4  ENERGY PENALTIES
     The energy penalty  must be  considered when calculating
 the costs of  emission control systems.  Electrical power
 consumption by the emission  control process reduces the net
 amount of power generated and additional Btu's are required
 to produce a net kilowatt-hour of electricity.
     The additional power-generating capacity required to
compensate for the power used by the emission control system
                             3-13
-------
evaluated is listed as a capacity penalty.  This penalty is

discussed in Subsection 3.4.1.  Subsection 3.4.2 discusses

the energy penalty which represents the increased number of

Btu's required to produce a net kilowatt-hour of electricity.

These penalties are expressed both as a percentage and as

an additional operating cost in mills/kWh.

3.4.1  Emission Control Capacity Penalties

     Particulate emission control methods cause losses in

net generation by a power plant that sometimes require the

addition of generation capacity.  Factors that affect the

cost of diverting a portion of a utility's electric genera-

ting capacity to supply the energy requirements of environ-

mental control equipment or to replace lost capacity are

listed below:

     A.   Percentage of unit capacity needed to supply the
          electrical energy requirements of environmental
          control equipment.

     B.   Percentage of the total system capacity to be
          equipped with environmental control equipment.

     C.   System capacity in MW.

     D.   Annual load growth of the system.

     E.   Size of reserve capacity in the year that the
          environmental control equipment is added.

     F.   Reserve capacity requirement:

          1.    Unit reliability by type of unit
          2.    Unit reliability by size of unit
          3.    Shape of load curve
          4.    Mix of generating capacity
          5.    Maintenance and overhaul
                              3-14
-------
      G.    Capability of interconnections.
      H.    Potential for interchange purchases and sales:
           1.    Short-term firm
           2.    Economy  transactions
      I.    Availability  of unit participation.
      J.    Cost  per  kW of added generating  capacity:
           1.    For  each type  of capacity  (i.e.,  nuclear,
                fossil steam,  gas turbine)
           2.    Economics of scale
           3.    Price escalation
      K.    Cost  and  availability of  fuels.
      L.    Load  characteristics:
           1.    Load factor
           2.    Relative magnitude of monthly  peak  loads
      M.    Mix of generating plant capacity, present and
           future.
      N.    Financing cost parameters, including cost of
           capital,  depreciation,  tax rates, and  insurance.
      The costs  presented in Section  3.3 do not include the
costs of replacement  capacity but do include  the costs of
purchased power which reflects  the recovery of capital costs
of generating units  supplying the power.  Values of the
capacity losses due to  the control options evaluated are
presented in Table  3-5  expressed  as  a percentage of the
plants gross generating  capacity.
3.4.2  Emission Control Energy Penalty
     The energy penalties associated with particulate emis-
sion control devices vary depending upon the control method
                              3-15
-------
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 used.   Energy is consumed by fans, motors, pumps, and in the



 case of an ESP,  the electrical energization of the collecting



 surfaces.   The energy penalty associated with particulate



 control methods  is identical to the capacity penalty since



 no external energy is required for reheat.  Table 3-5



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 3.5 COST  COMPARISON




     The costs developed by PEDCo in this study were based



 on information obtained from vendors of ESP1s  and from



 utilities  having ESP's installed on coal-fired boilers.   In



 a  report entitled "Electrostatic Precipitator  Costs for



 Large  Coal-fired Steam Generators"  the  Industrial Gas



 Cleaning Institute  (IGCI)  has  published costs  for ESP's on



 coal-fired boilers.   The  IGCI  costs will  be  compared with



 those  obtained in this  study for purposes  of clarifying any



 differences in the cost estimating  procedure.



     Table 3-7 presents a  detailed  breakdown of  costs



 developed by PEDCo and  by  IGCI  for  a cold-side ESP  on  a 500



MW boiler burning high  sulfur  (3.5%) coal.  The ESP's  are



designed to meet a 13 ng/J  (0.03  lb/106 Btu) regulation



 level.   The IGCI costs  are interpolated from costs  for a 200



MW unit and a  700 MW unit or a straight-line basis.
                              3-17
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-------
 Table 3-7.  COMPARATIVE CAPITAL COSTS FOR A COLD-SIDE ESP

                     ON A 500 MW BOILER


Cost Item                PEDCo               IGCI*

ESP                   $ 4,669,285         $ 8,247,863

Ash Handling          $ 1,755,274         $   153,530

Ducting               $ 1,234,321           ___^__

Direct Total          $ 7,658,880         $ 8,401,393

Indirect Costs        $ 2,584,872         $   659,070

Contingency           $ 2,048,751         $   190,804

Turnkey Cost          $12,292,503         $9,251,267


* Totals interpolated on straight line basis from IGCI
  fxgures for 200 and 700 MW boilers.
                             3-19
-------
     As seen in the table, the main difference between the



cost estimates is in the indirect charges and the contin-



gency.  These charges are calculated as a fixed percentage



of direct capital costs based on assumptions made by the



organization making the estimate.  PEDCo's cost estimating



procedure is designed to predict costs in the +20 percent



accuracy range based on non-site-specific information.  For



this type of estimate, indirect costs are calculated as



33.75 percent of the direct costs and the contingency is



calculated as 20 percent of the sum of direct and indirect



costs.  IGCI uses about 8 percent of direct costs for in-



direct costs and about 2 percent of direct and indirect



costs for a contingency.  These values appear to be very low



for non-site-specific estimates.



     The difference in the ESP costs as shown is about 10



percent which could be accounted for by the interpolation



used to obtain the IGCI costs.  A straight-line interpola-



tion would produce higher costs than actual since costs do



vary exponentially with size.  It should also be noted that



IGCI does not break out their cost estimates the same as



PEDCo, so the most meaningful number for comparison is the



total direct costs.
                             3-20
-------
            4.0  SO2 EMISSION CONTROL SYSTEM COSTS

      The capital and annualized costs of sulfur dioxide
 control systems can vary depending on several factors.
 Factors of major cost impact are boiler size and capacity
 factor; type of SO2 control system; sulfur content and
 heating value of the coal; maximum allowable SO2 emission
 rate; boiler status (new or retrofit installation);  replace-
 ment power requirements and byproduct disposal requirements.
      To present unencumbered cost estimates and illustrate
 the impact of site  and  process  factors  on total capital  and
 annualized costs of SO2  control systems,  a  model plant
 approach was  used.   The  following  sections  define the  model
 Plants,  the cost methodology, and  present the  results  of  the
 cost  estimates.
 4 .1   COST ELEMENTS
      The capital cost of a SO2  control system is composed of
direct and  indirect costs incurred up to the successful
commissioning date of the facility.  Direct costs include
the cost of various equipment items and the labor and mate-
rial required for installing the equipment items and  inter-
connecting the system.   Indirect costs are costs that are
                           4-1
-------
necessary for the overall facility but cannot be attri-



buted to a specific equipment item.  Indirect costs include



such items as freight, spares, interest, taxes, etc.



     Operating costs of a facility include labor, raw mate-



rials, and utilities required to operate the system on a



day-to-day basis.  These costs include such items as elec-



tricity, water, operating labor, etc.



     A brief description of the capital and annual operating



cost components and the procedure, used to obtain their



values is presented in this section.,



4.1.1  Capital Costs



     A discussion of capital costs for SO2 control systems



follows under the headings "Direct Costs" arid "Indirect



Costs."



Direct Costs



     The "bought-out" cost of the equipment and the cost of



installing it are considered direct costs.  Installation



costs also include the interconnection of the system, which



involves piping, electrical, and other work for commis-



sioning the system.  Installation of the equipment includes



foundations, supporting structures, enclosures, piping,



ducting, control panels, instrumentation, insulation, paint-



ing and other similar items.  Costs for interconnection of



the various SO2 control equipment involve site development,
                           4-2
-------
 construction of access roads and walkways,  and the estab-
 lishment of rail,  barge,  or truck facilities.   The cost of
 administrative facilities is also considered as a part of
 the direct costs.
      Various procedures for estimating the  direct costs are
 available,  each using a different route to  obtain an  in-
 stalled cost of a  facility.   In this  study,  the installa-
 tion-factor technique is  used to estimate total direct
 costs.
      The bought-out  cost  of each equipment  item is multi-
 plied by an individual installation factor  to  obtain  the
 installed cost.  This installed cost  also includes the
 proportional cost  of interconnecting  the equipment into the
 system.   The installation factors  are based  on the com-
 plexity  of  the equipment  and the cost of the material  and
 labor required.  The installed  costs  of all  the  equipment
 are added together to obtain  the total direct  cost  of  the
 facility.
      Direct  capital  costs  for an FGD  system  include the
 purchase  and  installation  of equipment including absorbers,
 fans  and motors, reheaters, soot blowers, pumps, tanks,
 agitators, raw material preparation and storage equipment,
byproduct dewatering equipment, sludge disposal or byproduct
 recovery  facilities,  foundations, and support.   The com-
                            4-3
-------
ponents vary depending on the type of absorbent used in the

system.

     Direct capital costs for a physical coal cleaning

facility include the purchase and installation of equipment

including crushers, conveyors, tanks, vessels, cyclones,

screens, centrifuges, sieves, classifiers, bins, filters,

and a thermal dryer.

Indirect Costs

     The indirect costs of SO2 control systems include the

following:

   •  Interest accrued during construction on borrowed
     capital.

     Engineering costs; includes administrative, process,
     project,  and general;  design and related functions for
     specifications; bid analysis; special studies;  cost
     analysis;  accounting;  reports;  purchasing;  procurement;
     travel expenses; living expenses; expediting;  inspec-
     tion;  safety;  communications; modeling;  pilot  plant
     studies;  royalty payments during construction;  training
     of plant personnel;  field engineering;  safety  engineer-
     ing;  and consultant services.

     Field overhead; includes the cost of securing  permits,
     and right-of-way sections,  and the cost of  insurance
     for the equipment and  personnel on site.

     Freight:  includes delivery costs on process and related
     equipment shipped f.o.b. point of origin.

     Off-site  expenditures:  includes those for powerhouse
     modifications;  interruption to power generation;  and
     service facilities added to the existing plant  facil-
     ities.

     Taxes:  includes sales,  franchise, property,  and excise
     taxes.
                             4-4
-------
      Spare parts; (stocked to permit high process avail-
      ability): includes pumps, valves, controls, special
      piping and fittings, instruments, and similar items.

      Shakedown; includes the costs associated with the
      system start-up.

      Contractor's fee and expenses; includes costs for field
      labor payroll;  supervision field office; administrative
      personnel; construction offices; temporary roadways;
      railroad trackage;  maintenance and welding shops;
      parking lot;  communications;  temporary piping and
      electrical and  sanitary facilities;  rental equipment;
      unloading and storage of materials;  travel expenses;
      P6™^8'*  ii-censes;  taxes;  insurance;  overhead;  legal
      liabilities;  field-testing of equipment; start-up;
      labor relations.

      Contingency costs;  includes those resulting from mal-
      functions,  equipment design alterations, and similar
      unforeseen sources.

      Land  cost;  includes  only the  cost of  the land required
      for sludge  disposal.   The  cost of land  for installing
      equipment  items  is accounted  for in the  installation
      factors.

      All the indirect cost  components,  except the land cost,

are estimated by multiplying  the direct costs by a indirect

cost  factor; the land cost  is based  on  land rate and  the

disposal area required.

4.1.2  Annual Operating Costs

     Generally calculated on an annual  basis,  the operating

costs of an SO2 control system are comprised of:

     Utilities; includes water for slurries, cooling, and
     process use; electricity for pumps, fans, valves,
     lighting,  and controls; and fuel or steam for reheat if
     required.
                             4-5
-------
     Operating labor: includes supervision and the skilled
     and unskilled labor required to operate, monitor and
     control the system.

     Maintenance and repairs; consists of both manpower and
     materials to keep the units operating efficiently.  The
     function of maintenance is both preventive and correc-
     tive , to keep outages to a minimum.

     Overhead; represents a business expense that is not
     charged directly to a particular part of a process but
     is allocated to it.  Overhead costs include administra-
     tive, safety, engineering, legal, and medical services;
     payroll; employee benefits; recreation; and public
     relations.

4.1.3  Annual Revenue Requirements

     The capital investment of a pollution control system is

generally translated into annual fixed charges.  These

charges, along with the annual operating costs, represent

the total revenue requirement of an SO2 control system.

     The annual fixed charges are classified under four cost

components:  depreciation, taxes, insurance, and capital

costs.  The component costs are as follows:

     Depreciation;  The value of the depreciation component
     is obtained by using a straight-line depreciation over
     the life period of the pollution control system.  A 20-
     year life is assumed for depreciation purposes.  The
     annual cost is calculated by dividing the total capital
     investment by the assumed years of life.

     Taxes:  The value of the tax component is calculated by
     multiplying the total capital cost by the input tax
     rate.  The tax rate varies for different plants.

     Insurance;  The value of the insurance component is
     obtained by multiplying the total capital cost by the
     insurance rate for the pollution control system.  A
     constant insurance rate of 0.3 percent is assumed.
                             4-6
-------
     Capital charges;  The value of capital charges repre-
     sent the interest paid per year for the usage of
     capital.  The value of this component depends on the
     applicable rate of interest for the borrowed capital.
     The value is obtained by multiplying the total capital
     cost by the input interest rate.

     The total annual fixed changes are obtained by adding

the values of the above four components.  The total annual

revenue required can then be obtained by adding the annual

operating costs to the total annual fixed charges.

4.2  COST ESTIMATING APPROACH

     A model plant approach was used in estimating the costs

of SO2 control on new coal-fired boilers.  Typical plants

were defined with characteristics intended to bfe representa-

tive of the electric utility industry.  Characteristics of

the model plants are presented in Table 4-1.  Analyses of

the coals used in the calculation of costs are given in

Table 4-2.

     The model plants were selected to incorporate four

varying cost factors:  plant size (capacity), SO_ control

system type, coal analysis, and degree of SO- control re-

quired.  Boiler sizes of 25, 100,  200, 500, and 1000 MW were

selected to cover the range of new coal-fired utility

boilers.

     Three regulation levels were examined in the analysis

in order to determine the economic effects of more stringent
                            4-7
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NSPS
for SO2 emissions for coal-fired utility boilers,
Levels examined were 516 ng/J  (1.2 lb/10  Btu), 215 ng/J



(0.5 lb/10  Btu), and 90 percent reduction of SO_ emissions
                                                £•


regardless of the level of the uncontrolled emissions.



Control technologies evaluated varied by control level and



by coal type.  Table 4-3 presents a summary of the cases



costed in this analysis.



     Other important considerations in control system costs



are redundancy in the control system and the averaging time



over which a particular emission level must be attained.



For purposes of this study, FGD systems on units larger than



25 MW were assumed to require a single spare module includ-



ing pumps, tanks, and associated equipment.  The cost impli-



cations of requiring a spare module are presented in Ap-



pendix B.



     The averaging time over which an FGD system must meet



the required SO, limitation was assumed as 3 hours for this



cost study.  Section 5 of this report discusses the implica-



tions of averaging time.



     The design parameters used for FGD systems in the



analysis are presented in Table 4-4.   The parameters were



developed based on review of existing FGD installations and



by contacts with the manufacturers of the various FGD sys-



tems.
                             4-11
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4.3  MODEL PLANT COSTS



     A summary of the results of the cost analysis are



presented in Table 4-5.  These costs are in August 1980



dollars and include escalation through project completion.



The escalation rate used was 7.5 percent per year.



     The incremental cost of reducing the SO2 emission



standard from 516 ng/J  (1.2 lbs/106 Btu) to 90 percent con-



trol varies with the sulfur content of the coal.  For higher



sulfur contents the impact is much less than for lower sul-



fur contents.  For instance, the capital costs of a lime FGD



system on a 500 MW boiler increases by only $0.83/kW for the



7 percent sulfur coal case, by $14.53/kW for the 3.5 percent



sulfur case, and by $119.42/kW for the 0.8 percent sulfur



case (assuming no FGD is required to meet the 516 ng/J



level).   Annual costs are similarly affected with costs



increased by 0.19 mills/kWh for the 7.0 percent sulfur case,



by 0.96 mills/kWh for the 3.5 percent sulfur case, and by



7.69 mills/kWh for the 0.8 percent sulfur case.  The results



also indicate the single plant application of combined coal



cleaning and FGD is not economical.  The only application



where such a combination is feasible is when the use of FGD



alone cannot produce compliance.



     Comparing the 90 percent control case with the 215 ng/J



(0.5 lb/10  Btu)  case the capital costs of a lime FGD for a
                              4-15
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 500 MW boiler burning 0.8 percent sulfur coal decrease by
 $13.98/kW for the 215 ng/J case and annual costs decrease by
 0.83 mills/kWh.
      Appendix C presents sample detailed breakdowns  of costs
 for the options evaluated.
      The costs do not include SO2 monitors that would  be
 required for the revised NSPS.   Based on EPA estimates such
 monitors would have  a capital cost of about $40,000  and an
 annualized cost of about $12,000.   The impacts  of  these
 costs are insignificant  with  the capital cost corresponding
 to  $1.60/kW on a 25  MW boiler down to $0.04/kW  on  a  1000 MW
 boiler,  and the annual costs  corresponding to 0.08 mills/kWh
 on  a  25  MW boiler down to 0.002  mills/kwh on  a  1000  MW
 boiler.
 4.4   ENERGY PENALTIES
      Two  types  of energy penalties  must  be  considered  when
emission  control  systems costs are  calculated.  Electrical
power consumption by the emission control process reduces
the net amount  of power  generated;  and the  control system's
flue gas  reheat and process heat requirements, depending
upon plant  design and  operating characteristics, may reduce
the plants  net  power production.
     The  additional power-generating capacity required to
compensate  for  the power used by the emission control system
                              4-18
-------
evaluated  is listed as a capacity penalty.  This penalty is

discussed  in Subsection 4.4.1.  Subsection 4.4.2 discusses

the energy penalty which represents the increased number of

Btu's required to produce a net kilowatt-hour of electricity,

These penalties are expressed both as a percentage and as

an additional operating cost in mills/kWh.

4.4.1  Emission System Capacity Penalties

     Flue  gas desulfurization systems cause losses in net

generation by a power plant that sometimes require the

addition of generation capacity.  Factors that affect the

cost of diverting a portion of a utility's electric genera-

ting capacity to supply the energy requirements of environ-

mental control equipment or to replace lost capacity are

listed below:

     A.    Percentage of unit capacity needed to supply the
          electrical energy requirements of environmental
          control equipment.

     B.    Percentage of the total  system capacity to be
          equipped with environmental control  equipment.

     C.    System capacity in MW.

     D.    Annual load growth of  the  system.

     E.    Size  of reserve  capacity in the  year that  the
          environmental control  equipment  is added.

     F.    Reserve capacity requirement:

          1.    Unit reliability  by type  of unit
          2.    Unit reliability  by size  of unit
          3.    Shape  of load  curve
          4.    Mix of  generating capacity
          5.    Maintenance  and overhaul
                             4-19
-------
      G.   Capability of interconnections.

      H.   Potential for interchange purchases and sales:

           1.    Short-term firm
           2.    Economy transactions

      I.   Availability of unit participation.

      J.   Cost per kW of added generating capacity:

           1.    For each type of capacity (i.e.,  nuclear,
                fossil steam, gas turbine)
           2.    Economics of scale
           3.    Price escalation

      K.   Cost and availability of  fuels.

      L.   Load characteristics:

           1.    Load factor
           2.    Relative magnitude of monthly peak loads

      M.    Mix  of generating plant capacity, present and
           future.

      N.    Financing cost parameters, including cost of
           capital,  depreciation,  tax rates, and  insurance.

      The costs  presented in Section 4.3  do not include the

costs of replacement capacity but do include the costs of

purchased  power which reflects the recovery of capital

costs of generating  units  supplying the power.  Values of

the capacity losses  due  to  the control options evaluated are

presented  in Table 4-6 expressed as a percentage of the

plants gross generating capacity.

4.4.2  Emission System Energy Penalties

     The energy penalties associated with flue gas desul-

furization systems can very widely with the process and
                              4-20
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-------
 vendor.   In  a  sulfur  dioxide  scrubbing  system,  the  scrubbing
 recurculation  pumps and  booster  fans  are  the  primary  energy
 consumers.   Different processes  also  require  varying  degrees
 of energy for  scrubbing  liquor makeup,  scrubbing  liquor re-
 generation,  and  sludge disposal.  Additional  penalties are
 caused by use  of fuel or steam to reheat  flue gases and
 steam to  provide process steam in some  of the regenerative
 systems.   For  this study, energy consumption  by the elec-
 trical equipment, reheat system, and  process  heat is  esti-
 mated for each of the cases evaluated.  Table 4-6 also pre-
 sents the energy penalty for  each case  as a percentage of
 gross electrical generation.  Table 4-7 presents the  energy
 penalty as an  annualized charge in mills/kWh.
 4.5  SLUDGE  DISPOSAL  ALTERNATIVES
     Several methods  are now  used for disposal of scrubber
 sludge.   The most common are  ponding of untreated sludge and
 landfilling of treated and untreated sludge.  An alternative
 to disposing of  scrubber sludge is commercial utilization.
 This technique is practiced extensively in Japan, where
 scrubber  sludges  are  oxidized to form the long fiber gypsum
necessary for wallboard  production.   Although such tech-
niques could be  applicable in the United  States if the
economic  incentives were adequate,  at best they would
account for only a minor fraction of sludge requiring dis-
posal.
                              4-24
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Ponding



     Sludge disposal in a pond without providing environ-



mental protection  (such as chemical fixation or impervious



liners) against seepage to water supplies constitutes a



potential water quality hazard.  The degree of hazard depends



upon such site specific characteristics as topography,



weather, soil characteristics, and proximity of ground and



surface waters to the disposal site.  In addition, there



exist a significant number of other disposal variables



(e.g., chemical constituents of the sludge and the condition



of sludge disposal) that may impact the potential hazard



posed by such a sludge pond.



     Pond linings have been finding greater favor in recent



years.  Lining is an effective method to prevent groundwater



contamination.  On many areas, clay, concrete, wood or metal



have been used as liners.  Synthetic materials are finding



increased use.  These synthetic materials include polyvinyl



chloride, rubber, synthetic rubber, polyethylene, propylene,



and nylon.  Since economics is a major factor, clay and



synthetics will be the primary materials used for sludge



liners.  To be useful, liners must have long-life, endure



temperature variations, and remain flexible..   Several manu-



facturers offer acceptable liner materials.
                             4-28
-------
 Landfilling
      The second method for disposal of scrubber sludges  is
 use  of  either  a dewatered or a stabilized ("fixed")  sludge
 for  landfill.   Sludges can be dewatered by vacuum filtration
 or centrifugation  to  form a solid  material that can  be used
 for  landfill.   Since  these dewatered sludges  can reabsorb
 moisture and regain their original water content if  un-
 treated,  chemical  and physical stabilization  or fixation
 processes are  increasingly being used.
      Chemical  fixation of scrubber sludge is  currently
 offered  by  several commercial  groups including  Dravo Corpora-
 tion, I.U.C.S.,  Inc.,  Chicago  Fly  Ash,  and The  Chemfix
 Corporation.   These commercial  systems  use fly  ash,  lime,
 silicates,  and polyvalent metal ions (usually about  5 per-
 cent  of  the amount of  sludge on a  dry weight  basis)  to form
 a low-grade concrete.   The  product  is a  stable,  inert mate-
 rial  that will  not release  toxic metal  ions or  soluble
 species.  It has sufficient strength to  support  buildings
 and will  support vegetation.
     The  following factors affect the capital and annualized
operating costs of sludge disposal:
     1.    Capital Cost
          a.   Pond location
          b.   Lining requirement
          c.   Leachate monitoring
                              4-29
-------
          d.   Overall size
          e.   Dewatering method
     2.   Annualized Operating Cost
          a.   Fixation chemicals
          b.   Utilities
          c.   Trucking
The split between capital and annual costs is not clearcut.
For example, several firms will operate sludge disposal
systems on a per ton basis.  The utility will not be re-
quired to invest capital in the system.  However, these
contracts normally have "take or pay" clauses to protect the
sludge disposal firm's capital investment.  In essence, turn
key disposal merely shifts the fixed charges of sludge
disposal to direct operating expenses.  In addition, pumping
sludge instead of trucking sludge increases capital but
reduces annual costs.  Sluice lines and pumps are part of
the capital costs borne by utility, while trucks to haul
sludge are normally borne by trucking contreictors.  Another
area which affects capital and annualized operating costs is
dewatering.  Horsepower requirements are reduced if ponding
is used to dewater sludge instead of vacuum filtration or
centrifugation.  Capital costs increase however, since the
pond must be larger and more complicated.
     In this study, it was assumed that all sludge-gen-
erating FGD processes would dispose of the sludge in an on-
site pond, lined with clay with the sludge stabilized by
addition of fly ash and lime.
                              4-30
-------
     Table 4-8 identifies the annualized cost impact of



various alternative subset conditions for sludge dipsosal



for a new 500 MW plant burning high sulfur coal.



4.6  COST COMPARISONS FOR FGD SYSTEMS



     The FGD system costs developed by PEDCo in this study



were based on system parameters used at existing and planned



installations and from control system manufacturers.  The



items of equipment required for each size and type of system



were specified and vendor quotes obtained for these items.



The quotes were obtained in mid-1976 and escalated using a



7-5 percent factor to future years.



     In a report entitled "Detailed Costs Estimates for



Advanced Effluent Desulfurization Processes" (EPA-600/2-75-



006, Jan. 1975) costs for various FGD systems developed by



the Tennessee Valley Authority (TVA) are presented.  The



costs presented in the document for a lime FGD system are



compared to the estimates developed in this study.



     The TVA costs reflect August 1974 prices and are esca-



lated at 7.5 percent per year to 1980 to provide a common



year for comparison.  Table 4-9 presents a breakdown of the



costs for a lime system on a 1000 MW boiler burning 3.5 per-



cent sulfur coal and designed for 90 percent SO_ removal.



     As seen in the Table,  the main areas of difference are



the costs for the absorbers,  reheaters,  fans,  and the indi-
                             4-31
-------
  Table 4-8.  IMPACT OF VARIOUS SUBSET SLUDGE DISPOSAL

   OPTIONS ON THE ANNUALIZED COST OF SLUDGE DISPOSAL3

Base Case
Synthetic Lining
Proprietary fixa-
ation
Trucking - 5 miles
Trucking -10 miles
Trucking -15 miles
Pumping - 5 miles
Pumping -10 miles
Pumping -15 miles
Mills/kWh
1.15
0.37
0.15
1.023
2.046
3.069
0.224
0.336
0.448
$/Dry Ton
18.73
6.03
2.44
16.67
33.33
50.00
3.65
5.47
7.30
$/Wet Ton
11.25
3.62
1.46
10.00
20.00
30.00
2.19
3.28
4.38
The various costs shown are additive to the  "Base Case"
cost which is a clay lined pond with fixation by addition
of fly ash and lime.
                            4-32
-------
Table 4-9.  COMPARISON OF COSTS FOR A LIME FGD SYSTEM ON A
   1000 MW NEW, COAL-FIRED GENERATING UNIT, 3.5% S COAL,
                    AND 90% SO2 REMOVAL
                           (4)
TVA ($ million)
  1974     1980
$ 1.228  $ 1.895
   .586    0.904
 10.638   16.417
                                                 PEDCo ($ million)
                                                       1980
                                                     $ 1.684
                                                       1.140

.955
1.161
5.018


1.474
1.792
7.744

45.444
6.212
3.604
4.626
2.046
                                  5.021
           7.749
                                                       5.489
     Capital Investment
 Cost item
 Lime receiving & storage
 Feed preparation
 Particulate & SO2 scrubbers
 SO2  absorbers (8)(1 redun.)
 Stack gas reheat
 Fans
 Calcium solids disposal
 Vacuum filters,  fixation
  chemical storage
 Utilities,  service  facilities,
  construction facilities &
  field expense,  & contractor
  fee
 Raw  material  inventory
 Engineering design  & supervision
 Contingency
 Start  up
 Interest  during construction(8%)
 Field  overhead
 Freight
 Offsite expenses
Taxes
Spares
La,nd cost
Total capital investment
  Detailed Cost Estimates for Advanced Effluent Desulfuriza-
  tion Processes, prepared for Control System Laboratory,
  Office of Research and Development, U.S. Environmental Pro-
  tection Agency, under Interagency Agreement EPA IAG-134(d),
  nS  >ai  LS-C'TMGGlame^4cet al" ^nnessee Valley Authority,
  pp. 244, 245.  January 1975.

1.
1.
2.
2.






$32.

712
926
260
260






765

2
2
3
3






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.972
.488
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6
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.433
.142
.296
.296
.476(9%)
.476
.768
.943
.921
.307
.219
.485
                           4-33
-------
                   Table 4-9  (continued).
Annual Operating Costs

Raw Materials
  Lime
  Fixation chemicals
Utilities
  Steam
  Process water
  Electricity
Labor
  Operating labor &
   supervision
Maintenance
  Labor & material
  Supplies
Analyses
Overhead
  Plant
  Administrative
Sludge Handling
  Average capital costs
  Depreciation
  Taxes
  Insurance
Total Operating Costs
  TVA ($ million)
   1974     1980
 $3.2185  $4.9671
  0.5684
  0.0374
  1.2895

  0.2381
0.8772
0.0577
1.9901

0.3675
  1.4978   2.3116

  0.0595   0.0918

  0.7381   1.1391
  0.0238   0.0367

  4.8820   7.5344
$12.5531 $19.373
PEDCo ($ million)
      1980
    $ 6.223
      1.020

      1.020
       .063
      3.704

      0.453
               5.024
               0.754
               3.116
               0.091

              16.418
               1.993
               7.780
               0.419
             $49.098
                             4-34
-------
 rect charges and contingency.   The reasons for the differ-

 entials are as follows:

      1.    TVA uses  only  4  scrubbing trains to handle  1000  MW
           (250 MW per  train).   PEDCo uses  8 scrubbing trains
           (1 redundant module)  to  handle 1000 MW at 143  MW
           per train.   The  largest  operational modules at the
           present time carry the equivalent of 150 to 160  MW
           of gas flow.

      2.    The TVA document specifies the year that base
           costs were obtained  for  absorbers,  fans,  and re-
           heaters as 1971.   These  costs  were then escalated
           to reflect 1974  costs.   PEDCo  base costs were
           obtained  in  1976  and  should therefore be more
           accurate.

      3.    TVA costs reflect minimum in-process storage with
           only pumps being  spared.   PEDCo  costs include  a
           spare scrubbing module with associated equipment,
           spare pumps, and  excess  inprocess storage capacity
           to obtain optimum operation.

      4.    TVA costs reflect disposal  of  untreated sludge in
           an on-site clay-lined pond.  PEDCo*s costs  reflect
           the disposal of stabilized  sludge in a clay-lined
           pond.

      5.    TVA costs reflect the use of venturi absorbers
           while PEDCo costs are for a Turbulent Contact
           Absorber  (TCA).

      6.    TVA costs reflect an annual capacity factor  of 80
           percent for the boiler while PEDCo  uses a 65
           percent capacity  factor.  Over the  20  year  life of
           an  FGD, the 65 percent capacity  factor would be
           more realistic.

      7.    TVA uses a contingency of 9 percent  of direct
           costs while PEDCo uses 20 percent of direct  and
           indirect costs.   For the level of accuracy of the
           PEDCo estimates  (+ 20%),  a 20 percent contingency
           adheres to standard estimating criteria.

     The nature of other  variations in the cost estimates

can not be determined based on available information.   It
                             4-35
-------
should be noted that TVA is in the process of revising their
cost estimates and preliminary results are much higher than
in the 1975 document.  Results were presented in a paper
entitled "Economic Evaluation Techniques, Results, and
Computer Modeling for Flue Gas Desulfurization," presented
at the FGD Symposium sponsored by EPA in November, 1977.
Comparative results for a limestone FGD on 3.5 percent
sulfur coal meeting a 1.2 Ib SO2/10  Btu regulation for a
500 MW plant are presented in Table 4-10.
                             4-36
-------
       Table  4-10. COMPARISON  OF COSTS  FOR A LIMESTONE


    FGD SYSTEM ON A 500 MW NEW, COAL-FIRED GENERATING UNIT,


   3.5% S COAL, AND 1.2 LBS/MILLION BTU ALLOWABLE EMISSIONS



     Capital  Investment          TVA  ($ million)  PEDCo  ($ million)

 Cost item                              1979           1980

 Limestone receiving & storage       $  1.76         $ 1  22

 Feed preparation                       1.74           i  88

 S02 scrubbers (4)                       8<92          19"84

 Stack gas reheat                      1.28           3  10

 Fans & ductwork                       4 ->?           _  ,_
                                       *•J^           J.33
 Calcium solids disposal               6.81           9  04

 Utilities,  service facilities,        6 20           ^  71
  construction facilities &              ".
  field expense,  &  contractor
  fee

 Raw material  inventory                                0 15

 Engineering design &  supervision       1.21           3.08

 Contingency                           6>45          ^^

 Start  UP                               3.35           1.93

 Interest during construction          4.65           3  84

 Field overhead                                        _  n.
                                                      3.84
 Freight                                               Q>39

 Offsite expenses
                                                     •L • JL 3
 Taxes
                                                     0.46
 Spares
                                                     0.15
Land cost                             i m           « -, .
                                      1.03           0.14
Total capital investment            $47.71         $67 43
                            4-37
-------
                   Table 4-lQ (continued) .
Annual Operating Costs

Raw Materials
  Limestone
  Fixation chemicals
Utilities
  Steam
  Process water
  Electricity
Labor
  Operating labor &
   Supervision
Maintenance
  Labor & material
  Supplies

Overhead
  Plant
  Administrative
Sludge Handling
Average Capital Costs
Depreciation
Taxes
Insurance
Total Operating Costs
TVA ($ million)
      1979
    $ 1.11
      0.98
      0.03
      1.64

      0.33


      1.82
      1.11
      0.03

      7.00
    $14.11
PEDCo ($ million)
        1980
      $ 1.08
        0.67

        0.52
        0.03
        1.90

        0.34
        2.93
        0.44


        1.86
        0.07
        0.67
        9.47
        4.49
        1.15
        0.24
      $25.86
                            4-38
-------
            5.0  IMPACT OF EMISSION AVERAGING TIMES
                      ON THE COSTS OF FGD

      The specific time period over which emission test
 results are averaged to determine compliance has a signifi-
 cant impact on the selection and design of the control
 process.   This is especially true in the case of SO2 emis-
 sion limitations.   Coal is inherently variable when looking
 at  the  sulfur  content.   The sulfur occurs in veins as pyrites
 thus producing a  nonhomogeneous condition when sulfur con-
 tent is considered.   This variability in sulfur content  is
 very significant  when looking at shorter averaging times
 over which a regulation must be met.   The effect of shorter
 averaging  times is  an increase in the maximum sulfur content
 for  which  an FGD  system must be designed.
      Table 5-1 presents the  sulfur variability in various
 coals over different  averaging times  for various size boilers.
 As can  be  seen the maximum sulfur  content varies more for
 the  smaller  unit due  to the  smaller total  amount of  coal
 based over  the averaging period.   These  values  reflect a
 normal distribution of  values  as obtained  by  the  sampling of
 unit trains.  The relative standard deviations  (RDS)  are
presented in Table 5-2.
                            5-1
-------
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-------
         Table 5-2.   RELATIVE STANDARD DEVIATION OF
                   SULFUR CONTENT IN COAL
Averaging Time
3 hr
24 hr
30 day
1 year
long term
Boiler size
25 MW
0.237
0.205
0.110
0.031
0
500 MW
0.194
0.163
0.069
0.020
0
1000 MW
0.190
0.155
0.065
0.019
0
     The values in Table 5-1 were obtained by assuming a
normal distribution of the values for the 7.0 and 3.5 per-
cent sulfur coals and a log normal distribution for the 0.8
percent sulfur coal for a 95 percent confidence level.
     For purposes of evaluating the cost impacts of various
averaging times, a lime FGD system was costed for each of
the maximum sulfur contents in Table 5-1.  The FGD was
designed for 90 percent SO* removal using design parameters
as presented in Tables 4-1 and 4-4.
     The results of this cost analysis are presented in
Tables 5-3 through 5-6.
     The results indicate that costs will increase as the
averaging time is shortened.  The effect is also more sig-
nificant for smaller units due to the increased variability
of sulfur as the quantity used during the averaging time
                             5-3
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decreases.  For instance, reducing the averaging time for a



3.5 percent sulfur case from 1 year to 3 hours increases



capital costs by 4.5 percent for the 500 MW case com-



pared to 4.0 percent for the 1000 MW case.  Also as the coal



sulfur content decreases, the cost impacts of shorter averaging



times increase.  For the 0.8 percent sulfur case the differen-



tial capital costs between the 1 year and 3 hour averaging



times varies from 3.9 percent for the 500 MW case to 1.7 for



the 1000 MW case.  Impacts on annual operating costs are not



significant as annual operating costs reflect the annual



average coal sulfur content.
                             5-8
-------
          6.0  SINGLE PLANT APPLICATIONS OF COMBINED



      PHYSICAL COAL CLEANING AND FLUE GAS DESULFURIZATION





      Coal cleaning has the potential of being an economic



 method of reducing sulfur in coal by significant amounts.



 However the maximum removal obtainable with most coals with



 physical cleaning is around 40 percent.  To meet stringent



 S02 emission levels on high sulfur coal would require addi-



 tional S02  removal by an FGD system.   In this analysis



 several cases were examined in order  to evaluate any possi-



 ble economic benefits obtainable  by the use of coal  cleaning



 in  combination with FGD versus FGD alone.   A single  plant



 scenario was examined in which a  single boiler is  served  by



 a coal  cleaning plant and a lime  or limestone FGD  system  is



 installed to meet  the regulation  level.  In  the  first  case,



 a 500 MW unit burning 3.5  percent sulfur coal and  required



 to  meet  the  1.2 Ib  SO2/106  Btu  regulation was considered.



 Considered in the second  case were  boilers of 25,  200, and



 500 MW burning 7.0  percent  sulfur coal  and required  to meet



 a 215 ng/J (0.5 lb/106 Btu) regulation  level.  Table 6-1



 presents the washability data for the two coals.  The washa-



bility data were selected from  "Sulfur Reduction Potential
                             6-1
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 of U.S. Coals:  A Revised Report of Investigations (EPA-
 600/2-76-091)," pages 71 and 164 as examples to use in the
 study cases.
      Case 1 involves 40 percent removal of sulfur by coal
 washing of a 3.5 percent sulfur coal.   Conventional coal
 preparation can be applied to many U.S. coals to achieve a
 40 percent reduction in sulfur.   In this situation, the
 model coal selected was an Illinois coal with a raw coal
 sulfur content of 3.48  percent.   USBM  washability data
 indicate that cleaning  at 1.8 specific gravity (s.g.)  would
 reduce the sulfur content by  about 50  percent with a  Btu
 yield of 93.4 percent;  the data  also indicate a 45 percent
 reduction in  sulfur at  1.9 s.g.  with a 96.3  percent Btu
 yield.   Assuming  that the higher cleaning gravity can  be
 used,  and that  a  grass  roots  cleaning  plant  is  built,  the
 capital  costs of  cleaning should be  in the range  of $10,000
 to  $30,000/ton  per  hour of raw coal  processed.  For a  state
 of  the art  cleaning  plant,  operating 4000  hours/year and
 processing  approximately  1,600,000 tons per year  of raw
 coal, the capital investment  is  estimated  to be approxi-
mately $3,500,000 to $8,300,000.  Since the size of this
cleaning plant  is small, the cost is estimated on the high
side of the range at $7,750,000  ($15.5/kW).  Operating costs
are estimated to be 2.85 to 4.30 mills/kwh.  Additional coal
                               6-3
-------
required, due to Btu losses in the refuse, are estimated to
be about 100,000 tons annually.  At an assumed cost of
$1.20/10^ Btu, the additional costs for coal would be
$2,800,000  (0.98 mills/kWh).
     Case 2 was evaluated in exactly the same manner as Case
1 using washability data for the 7.0 percent sulfur coal.
Costs do not differ appreciably from those obtained for Case
1.
     For the 1.2 Ib SO2/10  Btu regulation case, combined
coal cleaning and lime or limestone FGD are more expensive
than either lime or limestone FGD alone.  Capital costs are
about 1.5 percent higher, while annual costs are about 36
percent higher.
     It appears that the only possible benefit from the use
of combined coal cleaning and FGD is in cases where FGD
alone cannot attain the level of control required.
                            6-4
-------
          APPENDIX A




   DETAILED COST BREAKDOWNS




FOR PARTICULATE CONTROL DEVICES
            A-l
-------
     The following sheets present detailed breakdowns for



the cost estimates for ESP's, fabric filters, and venturi



scrubbers.  It should be noted however that the fixed costs



shown in the breakdowns were not used in the cost estimates.



Fixed costs in the estimates reflect 15.75 percent of the



total capital investment.
                           A-2
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            CAPITAL INVESTMENT FOR FABRIC FILTERS

Regulation  13.4 ng/J
Coal        0.8% S
Size        500 MW
Direct Costs
 Fabric Filter                          10,890,628
 Ash handling                            2,095,152
 Ducting                                   651,738
          Sub-total,  Direct Costs                 13,637,518
Indirect Costs

 @ 33'75%                                          4,602,662
 Contingency             20% of  Direct &  Indirect  3,648,036
          Grand Total                              21,889,216
                                             $/KW      43.78
                          A-7
-------
           ANNUAL OPERATING COSTS - FABRIC FILTERS


Utilities

  Electricity                               225,216

  Water                                      16>617

Operating labor                             616,455
 maintenance and bags

Overhead and administration                 122,713

Fixed Cost @  15.58%of total              4,979,569
 capital costs

               Total Annual Costs
                             A-8
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-------
                APPENDIX B




     COST IMPLICATIONS  OF ADDING SPARE




MODULES TO FLUE GAS DESULFURIZATION SYSTEMS
                    B-l
-------
              COST IMPLICATIONS OF ADDING SPARE

         MODULES TO FLUE GAS DESULFURIZATION SYSTEMS


     In reviewing air pollutant emission limitations, an

important consideration is the time period over which a cer-

tain limitation must be attained.  This directly affects the

required operational availability of pollutant control sys-

tems.  One system of major concern is flue gas desulfuriza-

tion (FGD).  The basic approach to increasing the avail-

ability of FGD systems is to install a spare scrubbing

module, but this will have a definite cost impact on the

system.

     The purpose of installing a spare module is to increase

the availability of the FGD system.  The percent avail-

ability is a ratio of scrubber operating time divided by

boiler operating time.  The availability for small boilers

with one original module and one spare module is 99%,

assuming an availability of 90% for each module.  As boiler
                                                            , i1
size increases to a point where it is necessary to have two

or more original modules, availability decreases.  This is

explained by the fact that there is only one spare module

that can operate while two or more original modules are out
                            B-2
-------
 of operation.  Table 1 presents the effect on availability

 of adding a spare module to various size FGD systems based

 on assumed availabilities of 0.90 for a single module and

 100 percent availability of a boiler.


                Table 1.   PERCENT AVAILABILITY

                                   Availability
      Mw                  Limestone           Wellman-Lord

       25                    0.99                  0.99
       50                    0.99                  0.99
      100                    0.99                  0  99
      200                    0.97                  0^97
      350                    0.95                  0.95
      500                    0.92                  0.92
      750                    0.89                  0.89
     1000                    0.82                  0.82

      In order to  determine  the  additional  cost incurred by

 adding a  spare module  to  a  new  lime or  Wellman-Lord  FGD

 system, PEDCo's cost estimating procedure  was  utilized.

      First, capital and annual  costs were  estimated  for both

 FGD  systems applied to seven predetermined boiler sizes.

 Input for all the boilers was kept the  same except for size-

 related factors such as ACFM and fuel consumption.   The

 costs are based on burning a typical high  sulfur coal  (10%

 ash,  3.5% S, and 11,000 Btu/lb).  In each  case, the  allow-

 able  S02 emission level is 1.2  lb/106 Btu.  All input data

and assumptions are listed in Table 2.

     Costs were then estimated  for each size boiler for each

type FGD system with one spare scrubbing module.  All other
                            B-3
-------
               Table  2.  DATA AND ASSUMPTIONS

          Rate data                FGD chemical cost, dollars/ton
Escalation factor - 1.335a
Electricity, mills/kWh - 20.00
Water, dollars/1000 gal - 0.20
Labor, dollars/man-hr - 10.00
Capital charge, percent - 9.00
Land, dollars/acre - 2000.00
                   Lime - 40.00
                   Soda ash - 65.00
                   Salt cake - 30.00
                   Sulfur acid - 20.06
          Boiler data

Life, years - 35
Duct factor - .17
Allowable SO2/ lb/10b Btu
- 1.2
          Fuel analysis

Ash content of coal,  % - 11.0
Coal sulfur content,  % - 3.5
Coal heating value, lb/10^ Btu -
                              11,000
  August 1980.
                              B-4
-------
 factors  were kept constant.   It  was  assumed  that  the  spare



 module is  of the  same  size as the  required modules  (i.e.,



 for  a  50 MW boiler with  one  FGD  module  the spare  is sized to



 handle 50  MW;  for a  500  MW boiler  with  four  FGD modules,



 corresponding to  125 MW  each,  the  spare is sized  to handle



 125  MW).   Costs obtained for the system with a spare  module



 were then  compared to  the base case  costs.



     Table 3  presents the percent increase  in capital cost



 that can be expected when a  spare  module is  installed.



 Figures  1  through 4  graphically  illustrate capital cost



 trends with and without  spare  modules.   Generally speaking,



 the  percent increase for a small boiler  is high compared to



 a larger one.  This  is because a small boiler only needs one



 module to  operate properly.   By  adding another module, the



 capital cost will almost double, whereas a larger boiler



 with more  than one module to begin with would not experience



 such a drastic increase.  Table  4 presents the percent



 increase in  annual costs  that  results from installation of a



 spare module.  Figures 5 and 6 illustrate the added operat-



 ing expense per kWh when a spare module is incorporated into



 a Wellman-Lord process or a lime scrubbing FGD.   Operating



costs per kWh is calculated by dividing the total annual



cost by kWh's of electricity generated per year.   The  annual



cost itself is the sum of fixed charges which are a certain
                           B-5
-------
Table  3.  CAPITAL COST EFFECTS OF ADDING A REDUNDANT




   ABSORBER TO A LIME AND WELLMAN-LORD  FGD SYSTEM
Boiler capacity,
MW
25
50
100
200
350
500
750
Lime,
percent increase
56.3
60.9
65.3
36.4
25.7
19.6
16.1
Wei Ima n- Lo r d ,
percent increase
50.6
55.7
61.8
37.8
24.6
20.4
15.8
                         B-6
-------
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B-10
-------
Table 4.  ANNUAL COST EFFECTS OF ADDING A REDUNDANT MODULE

           TO LIME AND WELLMAN-LORD FGD SYSTEMS


 Boiler capacity,          Lime,           Wellman-kord,
        MW              % increase          % increase

        25                 40.0                42.3
        50                 53.7                47.1
       100                 55.5                52.5
       200                 32,7                35.0
       350                 23.7                23.0
       500                 18.0                20.1
       750                 14.3                12.5
                          B-ll
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             B-13
-------
percentage of total capital cost, plus operation and main-



tenance cost.  For the Wellman-Lord process another factor



considered in the operating cost per kWh is the by product



credit since substances are produced.  Comparing effects  of



spare modules on capital cost versus effects on annual



costs, it can be seen that there is less of an impact on



annual costs.
                            B-14
-------
         APPENDIX C




DETAILED COST BREAKDOWNS FOR




         FGD SYSTEMS
           C-l
-------
     The following sheets present example breakdowns of
costs for the FGD systems evaluated in this study.  Samples
included are a lime FGD on a 500 MW boiler burning 3.5
percent sulfur coal and having 90 percent efficiency, a lime
FGD on a 500 MW boiler burning low sulfur (0.8%)  coal and
having 90 percent efficiency, and a magnesium oxide FGD on a
500 MW boiler burning 3.5 percent sulfur coal and having 90
percent efficiency.
                              C-2
-------
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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
1. REPORT NO.
  EPA-450/3-78-007
4. TITLE AND SUBTITLE
  Particulate  and Sulfur Dioxide  Emission Control  Costs
  for Large  Coal-Fired Boilers
                                                            3. RECIPIENT'S ACCESSION-NO.
             5. REPORT DATE

               Issued  2/78	•_
             6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
  Larry L. Gibbs,  Duane S. Forste,
  Yatendra M.  Shah
                                                            8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
                                                            10. PROGRAM ELEMENT NO.
  PEDCo Environmental
  11499 Chester Road
  Cincinnati,  Ohio  45246
             11. CONTRACT/GRANT NO.

                68-02-2535
12. SPONSORING AGENCY NAME AND ADDRESS
  U.S. Environmental Protection  Agency
  Office of Air  Quality Planning and Standards
  Research Triangle Park, North  Carolina 27711
             13. TYPE OF REPORT AND PERIOD COVERED
                Final	___^__
             14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
  Cost cases  developed include  five processes,  lime,  limestone, mag-ox,  double alkali,
  and Wellman-Lord; five plant  sizes from 25-1000  MW;  three S02 control  levels, current,
  90% efficiency,  0.5 Ibs S02/mil.lion Btu; three particulate levels5current (43 ng/j),
  22 ng/j,  and  13  ng/j; and coals  of varying sulfur,  heating value,  and  ash content.
  Averaging times, redundancy,  sludge disposal, and  energy penalties are also studied.
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
  Air Pollution
  Cost Comparison
  Electric  Utilities
  Sulfur Oxides
  Dust Control
                                              b.lDENTIFIERS/OPEN ENDED TERMS
 Air Pollution Control
 Stationary Sources
 Coal-fired Boilers
 Emission Standards
                           c. COSATI I;ioltl/Group
 13B
18. DISTRIBUTION STATEMENT
  Unlimited
19. SECURITY CLASS (This Report)
 Unclassified
                                                                          21. NO. OF PAGES
168
                                               20. SECURITY CLASS (Thispage)

                                               Unclassified
                                                                          22. PRICE
EPA Form 2220-1 (9-73)
                                           C-23
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