Tennessee
Valley
Authority
Office of Power
Energy Research
Chattanooga, Tennessee 37401
PRS-23
                                         EPA-600/7-77-126
Industrial Environmental Research       EPA-600/7-77-"l<
Laboratory                . .     .   . £*-*•*
Research Triangle Park, North Carolina 27711  NOVeiTlDGr l9f /
        UTILITY BOILER
        DESIGN/COST COMPARISON:
        FLUIDIZED-BED COMBUSTION
        VERSUS FLUE GAS
        DESULFURIZATION
        Interagency
        Energy-Environment
        Research and Development
        Program  Report

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                   RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into seven series. These sever, broad categories
were established to facilitate further development and application dTenvironmental
technology. Elimination of traditional grouping was consciously ptennod to foster
technology transfer and a maximum interface in related fields. The seven series
are:

     1.  Environmental Health Effects Research
     2,  Environmental Protection Technology
     3.  Ecological Research
     4.  Environmental Monitoring
     5.  Sociqeconomic Environmental Studies
     6.  Scientific and Technical Assessment  Reports (STAR)
     7.  Interagency Energy-Environment Research and Development

This report has been assigned to the  INTERAGENCY  ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series Reports in this series result from the effort
funded under the 17-agency Federal Energy/EnvironmentResearcffand Development
Program. These studies relate to EPA's mission to protect the public health and welfare
from adverse effects of pollutants associated  with energy systems.  The goal of the
Program is to assure the rapid development of dome-stic ene/gy Supplies in an environ-
mentally-compatible manner  by  providing the necessary environmental data and
control technology. Investigations include analyses of the transport of energy-related
pollutants and their health and ecofogjcal effects; assessments of, and development
of* control technologies for energy system^; and integrated assessments of a wide
range of energy-related environmental issues.
                           REVIEW NOTICE

This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect the
views and policies of the Government, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.

This document is available to the pubiic through the National Technical Information
Service, Springfield. Virginia 22161.

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                                TECHNICAL REPORT DATA
                         (Plccse nail liinruclitau on Ilic tr.vrtf tfforc coninietinf;)
 . REPORT NO.
 EPA- 600/7-77-126^
 i.T,TLEAN0soBT,ruEutmty Boiler Design/Cost Comparison:
 Fluidized-bed Combustion vs.  Flue Gas Desulfurization
 . AUTHOR(S)      '      "	

John T.  Reese, TVA Project Officer
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Tennessee Valley Authority
Office of Power
1360 Commerce Union Bank Building
Chattanooga, Tennessee  37401
12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC 27711
                                0. HtPO
                                 November 1977
                                                     6. PERFORMING ORGANIZATION CODE
                                3. PERFORMING ORGANIZATION REPORT NO.
                                 PRS-23
                                10. PROGRAM ELEMENT NO.
                                 EHE623A
                                11. CONTRACT/GRANT NO.
                                 EPA Interagency Agreement
                                  EPA-IAG-D5-E721	
                                13. TYPE OF REPORT AND PERIOD COVERED
                                 Final; 8/75-3/77
                                 4. SPONSORING AGENCY CODE

                                  EPA/600/13
15.SUPPLEMENTARY NOTES IERL-RTP project officer for this report is D. .Bruce Henschel,
Mail Drop 61, 919/541-2825.                       	—	
                             Reproduced from
                             best available copy.
  .ABSTRACT Tne report gives rosults of a conceptual design, performance, and cost
comparison of utility scale (750-925 MWe) coal-burning power plants employing three
alternative technologies: conventional boiler with a stack gas scrubber (CWS), atmos-
pheric-pressure fluidized-bed combustion (AFB), and pressurized fluidized-bed com-
bustion/combined cycle  (PFB). The AFB and PFB designs/estimates v.sed were com-
pleted by the General Electric Co. as  part of the Energy Conversion Alternatives
Study (EGAS), funded by NASA, ERDA, a»4NSF. The CWS designs /estimates were
developed by GE for this study, using  the same basis as for the EGAS.  TVA-modified
the GE results to: reflect TVA costing experience, consider  alternate wet scrubbing
techniques for the CWS, and include comparable  solid waste  disposal costs for all
three plants, considering alternative disposal options. Results suggest that AFB
offers a possible savings of 9-14% in the cost of electricity (COE) in comparison with
CWS, and PFB offers a savings of up to 7%.  The estimated COE for the three alter-
natives is  so close that all are considered to be within the competitive range for
further consideration.
17.
                             Kt v WORDS AND DOCUMENT ANALYSIS
                 DESCRIPTORS
Air Pollution
Cost Comparison
Fluidized Bed
  Processing
Flue Gases
Desulfurization
Waste Disposal.
is. DisTR;eunoN STATEMENT
Scrubbers
Coal
Boilers
Utilities
Calcium Oxides
Limestone
Magnesium Oxides
 Unlimited
                                          b.lDENTIRERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Fluid-Bed Combustion
Flue Gas Desulfurization
                     19. SECUH;T > CLASS fiiut Kcponi
                     Unclassified
                    20. ELCUHirY CLAS
                     Unclassified
                                                                  c. COSATI I idd/Group
13B
14 A      2 ID
         13A
13H,07A
21B      07B
07D      08G
                        2i. NO. Of PAGtS

                        -  - -3*7
                        22. PRICt
EPA frtrm 2220-1 (3-73)

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ATTENTION





AS NOTED IN THE NTIS ANNOUNCEMENT,


PORTIONS OF THIS REPORT-ARE NOT LEGIBLE,


HOWEVER, IT IS THE BEST REPRODUCTION
                      •4- •

AVAILABLE FROM THE COPY SENT TO NTIS.

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                                                   PRS-23
                                        EPA-600/7-77-123
                                           November 1977
           UTILITY BOILER
DESIGN/COST COMPARISON:
         VERSUS FLUE  GAS
                    John T. Reese
                   (TVA Project Officer)

                 Tennessee Valley Authority
                    Office of Power
                Chattanooga, Tennessee 37401
            Interagency Agreement No. EPA-IAG-D5-E721
                Program Element No. EHE623A
              EPA Project Officer: D. Bruce Henschel

            Industrial Environmental Research Laboratory
              Office of Energy, Minerals, and Industry
               Research Triangle Parn, N.C. 27711

                     Prepared for

            U.S. ENVIRONMENTAL PROTECTION AGENCY
              Office of Research and Development
                  Washington, D.C. 20460

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                                   ABSTRACT


     A conceptual design, performance and cost  comparison was completed for
utility-scale (750-925 MWe) coal-burning power  plants employing three alter-
native technologies:  (1) conventional boiler with a stack gas scrubber (CWS);
(2) atmospheric-pressure fluidized-bed combustion  (AFB); and  (3) pressurized
fluidized-bed combustion; combined cycle (PFB). The AFB and PFB designs;
estimates used were those completed by the General Electric Company team as
part of the Energy Conversion Alternatives Study  (EGAS), funded by NASA, ERDA
and NSF,  The CWS designs/estimates were developed by the HE team for the study
reported hers, using the same basis as was used for ECAS.  TVA modified and
expanded the GE results to:  (1) reflect TVA costing experience and include
an uncertainty allowance for undemonstrated technology;  (2) consider alternate
wet scrubbing techniques for the CWS, including lime scrubbing, limestone
scrubbing and magnesium oxide scrubbing; and (3) include solid waste disposal
costs for all three plants for a 30-year lifetime, and assess alternative dis-
posal options.  The results suggest that:   (1)  AKB offers a possible savings
of 9 to 14 percent in the cost of electricity  (COF.) in comparison with G-JS,
and PFB offers a savings of 0 to 7 percent,  depending on whether or not an
uncertainty allowance is applied; (?) hot gas cleaning and pressurized polids
handling in the PFB are major contributors to the COE (the cost of these items
can vary significantly if different design conditions are assumed), offsetting
the savings resulting from PFB's greater energy efficiency; and (3) application
of alternate scrubbing techniques does not affect the economics of CWS enough
to significantly change its position relative to AFB AND PFB.  When uncertainties
are included, the estimated COE for T;he three alternatives is so close that
all are considered to be within the competitive range for further consideration.
                                   111

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                               CONTENTS

                                                                        Page

Acknowledgements ......... .......... .........   vil

Introduction ......... .......  ......  .......      1

Executive Summary. ........ ..........  ...• .....      5

     A.  Scope ....... ....... .........  .....      5
     B.  Common System Parameters. . . *  ......  .........      5
  *"  C.  Economic Evaluation Criteria. ................      6
     D.  Results ........... .........  -  .  .  ....      6

         1.  Comparison of Results Prepared by -3E  ..........      6
         2.  Studies by TVA. . ... .... ^  .....  .....  .  .  .     11
Conclusions and Recommendations
     A.  Conclusions ............  .  ........  .  .  . . .     19
     B.  Recommendations ..... ........  ..........     20
                                          '
GE Conceptual Designs and Cost Estimates

     A.  Study Ground Rules ....... T ........  ......     21
     B.  Conventional/Wet Scrubber Power Plant ............     25

         1.  Introduction ...... . .....  .  ..........     25
         2.  Cycle Description ........ ......  .......     29

             Steam Turbine-Generator Cycle .  . ............     29
             Conventional Steam Generator. ..............     29
             Wet Gas Scrubbers ....................     31
             Lime and Sludge Systems .......  ..........     31
             Stack and Reheat System .................     31
             Overview ......... ..........  ......     31

         3.  Major Cycle Components. ..........  .  ......     32

             Conventional Furnace-Steam Generator ...........     32
             Steam Turbine-Generator ......  ...........     32
             Stack Gas Scrubber System ..............  .  .     37
             Scrubber Costs ............ ......  .....     40

         4.  Plant Arrangement ..............  .  .  .  i  .  .     46

             Plot Plan ......... .. .  .............     46
             General Arrangement . . . ; . ..........  ....     46
             Electrical Schematic. ..............  ....     50
                                       iv

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                           CONTENTS

                          (Continued)

             '                                                     Page

    5.  System Performance and Cost	     52

        Performance Integration	     52
        System Output	     52
        Costs-General	     52
        Major Component Characteristics.	     52
        Major Component and Subsystem  Capital  Cost	     55
        Balance of Plant Equipment List	     55
        Balance of Plant Capital Costs .	     55
        Plant Cost Estimate	     70

    6.  Natural Resources and Environmental  Intrusions .....     73

        Sensitivity to Emission Targets	     73

    7.  Summary Performance and Cost .	     76

    8.  Alternative Plant Considerations  	     79

        Stack Gas Reheat to 175eF	     79
        Performance and Costs—175°F Stack 	     79
        No Scrubber, 250°F Stack Alternative 	    101

C.  Atmospheric Fluidized Bed Power Plant	    105

    1.  Introduction ,	    105
    2.  Cycle Description	    108

        Steam Turbine-Generator Cycle	    108
        Atmospheric Fluidized Beds	    108
        Flue Gas and Air Supply.	/	    110
        Spent Solids Systems	    110
        Coa! and Liitestone Systems	    Ill
        OvervLiw . .	    Ill

    3.  Major Cycle Components ....... 	    112

        Atmospheric Fluidized Bed Modules. 	    112
        Prime Cycle	    116
        Materials of Construction	    125

    4.  Plant Arrangement.  ..... 	    127

        Plot Plan	    127
        General Arrangement	    127
        Plan;  Elevation. .  ,	    127
        Electrical Schematic 	    131

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                          CONTENTS

            1             (Continued)


                                                                  Page

    .5.  System Performance and Costs	    133

        Performance and Costs	    133
        Costs-General	;	    133
        Major Component Characteristics	    133
        Equipment List-Balance of Plant	    138
        Capital Costs-Balance of Plant  	 ....    138
        Plant Cost Estimates .	    138

    6.  Natural Resources and Environmental  Intrusions 	    154

        Sensitivity to Emissions Targets  	 . ....    154
        Trace Element Emissions	    154

    7.  Summary Performance and Cost	    159

D.  Pressurized FluiJized Bed Power Plant	    163

    1.  Introduction	    163
    2.  Cycle Description	    166

        Pressured Fluidized Beds	    166
        Gas Turbine Air Supply	    168
        Spant Solids System	    168
        Coal and Dolomite Systems.	    168
        Overview	    168

    3.  Major Cycle Components	    169

        Heat Input System-PFB	    169
        PFB Gas Turbine and Heat Balance	    174
        Prime Cycle	    174
        Materials Considerations 	  . 	    174

    4.  Plant Arrangement	    180

        Plot Plan	    180
        Coal and Dolomite Handling	    180
        Solid Wastes Handling	    180
        General Arrangement.  ........  	    182
        Plant Elevation	    182
        Electrical Schematic  	    182
                              vi

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                      CONTENTS

                     (Continued)


                                                               Page

5.  System Performance and Cost".- „•	    186

    Performance ...........  	  .    186
    Auxiliary Losses. ...............".....    186
    Costs-Gereral . ,	    186
    Costs-Majcr Components.	  .......    186
    PFB Major Component Characteristics (1650)	  .  „    186
    Equipment List-Balance of Plant  (1650).  ......  .  .  ,    192
    Capital Costs-Bailee of Plant. (1650 F)  ......  ;.  .    192
    Plant Cost Estimate?. ..................    192

6.  Natural Resources and Environmental Intrusions.  ......    209

    Natural Resources	    209
    Environmental Intrusion .,.•	    209
    Trace Element Emissions	•  *•	.,.'.  .    209

7.  Summary Performance and Cost.	    211
                                    ^4*..
8.  PFB Alternative //I (1-750 F)	    214

    PFB Tower Costs	-.    214
    Hot Gas Cleanup Costs .	    214
    Gas Turbine Costs	    214
    Steam Turbine-Generator Cost. .	  .    214
    Gas Turbine Economizers	    217
    Balance of Plant Costs	    217
    PFB Net Generation (1750 F)	    217
    PFB Net Plant Cost (1750 F)	    217
    Cost of Electricity Comparison.  .............    217

9.  PFB Alternative i?2-High Efficiency (1750 F)  .......    222

    Steam Turbine Cycle and Heat Balance. .	    222
    Gas Tubine Economizer Cost	    222
    Balance of Plant Adjustments	    225
    Auxiliary Loss and Net Generation	    225
    Net Plant Cost	    225
    Cost of Electricity Comparison	    225
                          vii

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                               CONTENTS

                              (Continued)

                                                                      Page

Plant Conceptual Designs and Balance of Plant Costs	233

Introduction	,	233

Balance of Plsnt Subsystems. 	  235

     A.  Coal and Sorbent Receiving, Handling,  and Storage  	  235
     B.  Water Treatment and Disposal.	237
     C.  Solid Wastes Handling and Disposal	241
     D.  Heat Exchangers . . .	241
     E.  Piping	,	242
     F.  Copling Towers and Circulating Water Systems	243
     G.  Exhaust Stacks. ...».'	247
     H.  Auxiliary'Loa;'-.	  -	247
     I.  Electrical Systems	  248

Cost Engineering Methods .*.....	  .  249

     A.  Cost Engineering Objectives 	  .......  249
     B.  Capital Cost Estimates Approach 	  249
     C.  Common Balance of Plant Components	    	258
     D.  Construction Time Estimates 	  260

Operating and Maintenance Costs. 	  	  265

     1.  Introduction	,	  .	265
     2.  Maintenance Costs	266
     3.  Operating Cost Estimates	269
     4.  O&M Summary	,	271

GE Comparison of Alternatives,	  275

TVA Modification and Expansion of GE Study	281

     A.  Introduction.	281
     B.  Modification of GE Estimates by TVA	282
     C.  Alternative Wet Scrubber Cases	  .  .  ,  .  .  .  291
     D.  Alternative Disposal Methods	305
     E.  Cost of Electricity  (C.O.E.) Based on TVA Modifications  .  .  .  309
                                   viii

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                               CONVERSION TABLE
     EPA policy is to express all measurements in Agency  documents in metric
units.  When implementing this policy results in undue  cost or difficulty in
clarity, the Industrial Environmental Research Laboratory-Research Triangle
Park (IERL-RTP) provides conversion factors tor the particular rsonmetric
units used in the document.  For this report these factors a-re:.
British
Multiply
feet
feet2
feet/sec.
3
feet /min.
gallon
inch
micron
ounce (troy)
pound
pound /in.
quart
tons/hr.
Temperature Conversion -
-•
.-, '. "& ~
3.0480 x 10"1
9.29 x 10~2
. 3.0480 x lO'1^
4^.720 x 10""1
3.785
2.5400xlO~2
1.0 x 10~6
3,1103 x 101
4.536 x Iff1
7.03 x 10~2
9.463 x 10"1
2.520 x 10"1
Farenheit (°F) to Kelvin (°K)
Metric
To. Obtain
meters
* 2 •
meters
feet/sec.
liters /sec.
liters
meters
meters
grams '
kilograms
kg/cm
liters
kg/sec.

     Temp--ature
I (Tf - 32°) + .273°
                                    IX

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                            ACKNOWLEDGEMENTS


     This report Includes technical work performed by the General Electric
Company (GE) and the Tennessee Valley Authority (TVA).  The "GE Conceptual
Design and Cost Estimates" information was developed by a GE team composed
of the following organizations:

     (a)  General Electric Company

               Electric Utility Systems Engineering Department
               Cotporate Research and Development
               targe Steam Turbine - Generator Department
               Technical Resources Planning, Turbine Operations
               Technical Resources Staff

     (b)  Be.chtel Corporation

     (c)  Foster Wheeler Energy Corporation

     This effort utilized fluidized bed combustion power plant  designs developed
in Phase II of the Energy Conversion Alternatives Study (ECAS)  (Ref. 5).  The
conventional plant information was developed by the GE team under NASA contract
NAS 3-19406 on a basis consistent with the ECAS Phase II effort.

     The Environmental Protection Agency (EPA) provided funding for the GE
conventional plant effort and for additional work by TVA under  TV-41967A and
interagency agreement EPA-IAG-D5-E721.

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                                INTRODUCTION


     The increasing demand for electrical power coupled with the  growing concern
for environmental effects of coal-fired power plants create a special problem in
the utility industry.

     The goal of near-term energy.independence requires that new  fossil-fired
plants utilize our Nation'a vast coal resources.  The majority of our coal,
however, is unsuitable as a conventional power plant fuel.   High  sulfur oxide
emissions *rora coal-fired plants have been evaluated as environmentally unacept-
able.  Limitations on these emissions have been imposed requiring either removal
of coal sulfur before burning or reduction of sulfuric oxide concentration in
the stack gas.  Much of the coal is unsuitable for economic sulfur removal by
conventional methods.  Utilizing high sulfur coals in conventional coal-fired
plants requires stack gas cleanup.  The only existing technology  for adequate
sulfur oxide reduction is wet scrubbing.

     Wet scrubbers are expensive, however, and have posed some operational
problems.  A near term alternative to conventional/wet scrubber power plants
(CWS) is fluidized bed combustion power plants.  Atmospheric fluidized bed
combustion power plants  (AFB) are basically similar to conventional power plants
with the substitution of fluidized bed modules for the conventional stesm gen-
erator.  Pressurized fluidized bed power plants (PFB) add an extra dimension
through utilization of a coal-fired gas turbine.

     The U.S. Environmental Protection Agency (EPA) recognized the need to
evaluate the economics of near term alternatives to conventional/wet scrubber
plants.  TVA, at the request of EPA, undertook the assignment of  comparing the
costs of fluidized bed combustion power plants (AFB and PFB) to the costs of
conventional/wet scrubber plants (CWS).  In an effort to accomplish this
economically and expeditiously, information developed in the Energy Conversion
Alternatives Study (ECAS) was utilized as a data base.

     EGAS has studied viable concepts for advanced power plants fired by coal
or ccal-derived fuel.  This effort combined resources of three U., S. agencies.
National Science Foundation, Energy Research and Development Administration,
and National Aeronautics and Space Administration (NSF,  ERDA,  and NASA),
and the contracted expertise and experience of contractor teams led by the
General Electric Company (GE) and the Westinghouse Electric Company.

     ECAS included three primary tasks:  parametric analysis (Task 1),
conceptual  design and cost estimation (Task 2),  and implementation assessment
Task 3).  In Task 1, ten categories of power plant were analyzed  parametrically.
On the basis of the results from that analyses,  11 -specific advanced plant

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types were selected for the Task 2 and Task 3 effort.  GE was responsible for
seven of these including atmospheri. fluidized bed combustion  ^AFB) and pres-
surized fluidized bed combustion (PFB) power plants.  The GE portion of the
ECAS work was done by a GE Corporate Research and. Development team which
included the Foster Wheeler Energy Corporation and the Bechtel Corporation.
In order to facilitate a cost comparison of fluidized bed combustion to con-
ventional pulverized coal-fired power plants utilizing wet stack gas scrubbers
(CWS) it was necessary to develop comparative conceptual designs and cost
estimates for the conventional plant.

     EPA provided the funding necessary for this  additional CWS plant study
which was performed on the same design and economic premises as the ECAS
sJtudy.

     Included in the GE study results used in this report" ^re the following
items:                                                    •*-."'

       1.  Study ground rules  ~

       2.  Conventional/wet scrubber power plant  (CWS) design  (lime scrubber)

       3.  Atmospheric fluidized bed power plant  (AFB) design            :
                                       -  ^                 v      :
       4.  Pressurized fluidized bed power plant  (PFB) design           ^..

       5.  Balance of plant equipment necessary for the CWS, AFB, and PFB
           plants           n                                                •

       6.  Operating and maintenance costs for the CWS, AFB, and PFB plants

       7.  Comparison of alternatives

     The conceptual designs and cost estimates developed by the GE team pro-
Vide cost data based on common ground rules for the CWS, AFB, and PFB systems.
All three systems were assumed to be developed to a commercially available
state of art and received common treatment in the generation of design and
cost information.  TVA feels that although the GE effort was guided by a
consistent evaluation basis, there are areas where modification would provide
a more comprehensive and utility representative study.

     The capitcl and operating costs obtained by  GE for the CWS, AFB and PFB
were modified by TVA to take into consideration a number of factors felt to be
significant.  Three major factors were addressed:

     1.  Modification of the estimates to Include an uncertainty allowance for
         those plant components not felt to be demonstrated technology; and
         modification of the GE estimates for various components where such
         revision is felt to be warranted based upon TVA design experience.

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     2.   Expansion of the GE estimates to take into consideration:

         a.  Adequate provisions  for residue disposal over the full 30-year
             plant lifetime, for  all cases  (previously GE included  only 5-year
             disposal provisions  for the CWS case, and none for AFB and PFB).

         b.  Alternate disposal options.

     The TVA estimates are only modifications of the GE cost figures and should
not be construed as an estimate of  costs for which TVA believes these plants
could be constructed for today.

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                               EXECUTIVE SUMMARY -


A.  SCOPE

     This report presents the results from a study  that has been conducted to
compare the economic and performance characteristics of three power plants,
each of which generates electricity at approximately the same net capacity and
each of which employs a different scheme for controlling the emissions of air
polluting constituents in its flue gases.  The difference between the three
plants are essentially identified by the type of steam generator and the
associated provision for removal of sulfur dioxide  from the products of com-
bustion.  The three plants are designated as follows:

     1.  Conventional pulverized coal-fired steam plant with stack gas
         scrubber ('JWS);

     2.  Atmospheric fluidized bed combustion power plant (AFB);

     3.  Pressurized fluidized bed combustion power plant (PFB).

     The evaluation of the CWS was performed for two values of gas temperature,
namely, 250 F and 175 F to which the combustion gases were reheated after leav-
ing the wet gas scrubbers and prior to entering the stack.  Also included for
comparison was the condition that assumed low sulfur coal was burned and the
scrubber system eliminated from the plant.

     The study of the PFB plant included consideration of main bed operating
temperature of 1650 F and 1750 F and an alternate high-efficiency cycle for the
1750 F case that utilized a high temperature feedwater heater in addition to
those provided in the base cycle of the PFB plant.

     As an extension of the performance and economic analyses performed for the
plants and conditions described above, several alternate scrubbing systems were
analyzed as were various schemes for disposal of scrubber sludge from the CWS
and disposal of solid waste from the fluidized bed  plants.


B.  COMMON SYSTEM PARAMETERS

     As nearly as was feasible, the basic system parameters in each of the three
power plants were taken to be th>.- same.   Likewise,  the provisions for onsite
storage and handling of fuel and sorbent as well as requirements for the balance-
of-plant components were maintained as similar as was practical for the three
   Preceding page blank

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plants.  Consistent ground ruler and costing methodology were applied  in evaluating
the plants.  Table 1 is a list of design parameters common to the  three plants.


C.  ECONOMIC EVALUATION CRITERIA

     The economic and performance evaluations for the study were first carried
out by the General Electric Company (GE) and then the results and  studies were
modified/extended by TVA to more realistically reflect utility practice and
account for the uncertainties inherent in systems undergoing various stages of
technological development.                 '

   *• The evaluations for each power plant conducted by GE were performed using
the methodology and criteria consistent with that used in the Energy Conversion
Alternatives Study (EGAS).  Each of the three types of plantsjwas  assumed to be
developed to a commercially available state-of-the-art and no consideration
was given to developmental costs.,,

     A lime slurry scrubber with onsite calcination and provisions for a
five-year storage of sludge was assumed for the CWS studies performed by GE.
The AFB and PFB plants were assumed by GE to have provisions for. hauling of• the
solid wastes to an offsite location.  The costs for disposing of the solid
wastes from the AFB and PFB plants were not Included by GE.   *
                                       -.••'"•                   *•-
     TVA's modification of .the results by General Electric included the
following:                                *"
                              r;
     1.  Revision of some items in GE's cost estimates to more reasonably
         reflect current utility practice;

     2.  Application of an uncertainty allowance to the cost of those items of
         equipment in which unceftaincies of design and scale up of components
         were not accounted for in the GE studies.  These uncertainty allowances
         do not take into account costs to develop the components  or to start
         up the process.

     The previously mentioned extension of the study to include investigation
of additional scrubber systems and alternative methods of disposing of sludge
and -solid wastes was also performed by TVA.  The alternative methods of scrub-
bing considered by TVA were lime w/onsite calcination, lime w/offsite calcina-
tion, limestone, and regenerable magnesium oxide.  Estimates for 30-year
disposal were made for each scrubbing alternative as well as for the AFB and
PFB plants.


D.  RESULTS

    1.  Comparison of Results Prepared by. GE

     A comparison of performance and corresponding cost of electricity for the
several plants and alternatives considered is presented in Table 107 which is
reproduced here for convenience.  The entries are arranged in Table 107 in
decreasing order of overall efficiency.

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Fuel
Steam Conditions
                                   TABLE 1

                            Key Design Parameters
                             Illinois No. 6 Coal
                             Cost:   Sl.00/106 Btu
                             HHV:    10,788 Btr./lb
                             3.9%  Sulfur
                             9.6%  Ash
                          3515 psia  i'nlet pressure
                          1000°F  inlet temperature
                          1000°F  reheat temperature
Heat Rejection
                     Mechanical draft cooling towers
            Ambient  Air Temperatures:  59" dry bulb, 51.5°F wet bulb
Economic Factors
                    Base  Ixtad  Plant  (capacity factor = 65 percent)
                          30 year plant  lifetime
                          90 percent availability
                          Cost basis:  Mid-l975$
                    Interest during construction:  lOTi per year
                    Escalation during, construction:  6.5°' per year
                         Fixed charp.e rate:  18^ per year
                           Construction  time:  5.5 years
                            Sorbent cost:   $5.00/ton
 Plnnt Capacity

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                                   Table 107

                       EFFICIENCY ORDER OF STEAM PLANTS**
TYPE
PLANT          CONDITIONS

PFB           1750F Beds

PFB           1650F Beds

CF            No Scrubber

AFB           1550F Beds

CF            No Scrubber

CWS           Wet Scrubber***

CWS           Wet Scrubber***
  *3.9% S in Coal Not Permitted.  These costs  do not include a premium for
   low—sulfur coal.
 **English units are employed in tables and figures in this report, in
   accordance with engineering design practice.  A table of English to
   metric conversion factors is given on page  vi.
***Lime slurry w/onsite calcination.
STACK
3 OOF
3 OOF
250F
250F
3 OOF
175F
250F
OVERALL
EFFICIENCY
40.0%
39.2%
36.2%
35.8%
35.7%
33.8%
31.8%
ELECTRICITY
MILLS/kWh
34.1
34.1
30.5*
31.7
31.6*
37.0
39.8

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     The overall efficiency is defined as the net  station output divided by the
higher heating value of the coal fired.

     The high efficiency configurations for the  PFB plant with beds at 1750 F
yields the highest overall efficiency of all .the plants  evaluated;
however, the combustor and gas clean up and solids handling systems for this
power plant, that includes a gas turbine, would  need considerable farther develop-
ment before it could, in fact, become a reality.   The AFB plant also needs
further development although its development is  advanced compared to the PFB
plant.  Based on available technology, the conventional furnace with wet scrubber
and 175 F stack gas is the best current solution for combustion of h,igh sulfur
fuels.  There is, however, an economic incentive to develop AFB and PFB as well.

     The two "no scrubber" cases would require a coal of less than 0.65 percent
sulfur for a 10,788 Btu/lb higher heating value  if they are to, meet the emission
standard of 1.2 lbS02/M Btu emission standards common to all of the plants.
Premium costs for this higher quality coal were  not included in the comparison
in Table 107.

     Note in Table 107 that the increase in bed  temperatures and the addition
of the high temperature feedwater heater for the.,PFB with beds at 1750 F
resulted in only a slight increase in the overall  efficiency and no difference
in the cost of electricity when-compared with the  PFB plant with 1650 F beds.
                                              TV-                  f      •      > ,
     The change in the stack temperatures from 250°F to 175 F, in the case of*^
the CWS, yielded improvements in both the overall  efficiency and the cost of
electricity.                                •*
                                 C;
     Some insight into tine relative costs in dollars for kilowatt ($/kW) for
heat release and sulfur and particulate capture  for the three plants may be
gained by considering the combination of the costs in S/kW for the furnace
modules, hot gas filtering, solids handling and  stack gas scrubber are appro-
priate for each plant.  This is depicted in Table  106 which is included here
for convenience.  These combinations of components total S67/kW for the A^B,
$!23/kW for the PFB and $147/kW for the CWS.  Data also included in this table
reveal that the total capital costs and the costs  of electricity follow a
similar progression for the respective plants.  As shown in Table 106, a major
contributor to the PFB capital cost is the hot gas filtering system.  Estimates
of hot gas cleanup costs vary from estimator to  estimator, depending.on design
assumptions (such as gas velocity thru granular  bed filters).  Design assumptions
different from GE's could.result in lowering the PFB plant cost.

     Summaries of the environmental intrusions anticipated from operation of
the CWS, AFB, and PFB plants are presented, respectively, in Tables 22, 56, and
78.  These tables have been duplicated from other  portions of the report.

     SOX emissions are comfortably under the current limit of 1.2 lbS02/MBtu
(0.52 kg/GJ) of heat release for all three plants, as a result of the selected
design conditions, with the PFB showing the greatest margin.  In designing for
these different degrees of S02 removal (85% for  AFB, 88% for CWS and 90% for
PFB), GE was attempting to ensure compliance with  its emission standard (83%)
for each system.  The greater degrees of control designed into each system
were to reflect GE's estimation of the uncertainty in system performance.
                         0         O
                                       9

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                                 Table  106

                    CAPITAL COST DISTRIBUTIONS AS $/kU
              FOR 3600 PSI, 1000 F,  1000 F  STEAM POWER PLANTS
 Major Components

   Steam Turbine-Generator
   Furnace Modules
   Gas Turbines
   Hot Gas Filtering
   Economizer
   Solids Handling

     Subtotal
                                            AFB
                                           1550 F
 33.2
 55.8
 11.4

100.3
               PFB
              1650 F
 27.7
 16.3
 28.3
 71.4*
  2.5
 35.6**
               CF
              175 F
 33.6
 57.7
182.0
 91.3
 Balance of Plant

   Stack Gas Scrubbers
   Site Labor
   All Other

     Subtotal
117.8
122.1

239.9
108.4
_9_8._7

207.1
 89.2
126.8
107.5

323.5
 Contingency

 Escalation and Interest

 Total Capital Cost ($/kU)

 COE (mills/kWh)
 68.0

223.8

632.

 31.7
 77.8          84.2

255.8         273.0

723.          771.

 3/..1          37.0
 *Approximately two-thirds of this cost  represents the high temperature/
  pressure granular bed filter for particle removal from the flue gas.  For
  comparison, an esimate for hot gas  filtering for PFB use made by Westinghouse
  for the EGAS program (ref. 6 ) using diffenr-ent design assumptions amounted to
  about $15/kW.
**The Westinghouse estimate for PFB solids handling was about $8/kW (ref.6 ).
                                    10

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     The AFB and PFB with combustion in the beds at  1550 F and 1650 F, respec-
tively, indicate low levels of NC^ in comparison with the current limit of
0.7 Ib NOx/MBtu of heat release.  The CWS requires a well balanced, staged
combustion system in order to meet the current NO* limitations.

     In regard to emissions of particulates, each of the plants has little or
no margin in comparison with the current limit of 0.1 Ib/MBtu of heat release.

     The stack gas heaters in the case of the CWS, Table 22, place a greater
fraction of the heat rejection at the stack as compared with the corresponding
values for the AFB and PFB in Table 56 and 78, respectively.

     Water usage is greatest for the CWS and smallest for the PFB plant.  The
coal requirement would follow the same progression as does water conservation.

     The solid waste produced is least for the CWS (on a dry basis) and greatest
for the PFB.  The PFB plant uses dolomite which has only half the concentration
of available lime found in limestone.  Since solid wastes from AFB arid PFB are
dry, some ease in handling may result in comparison with CWS sludge.

     The above comparisons have been made using the  CWS with 250 F stack gas
temperature (Table 22).  The environmental intrusions for the CWS with 175 F
stack gases would be comparable to tlv values in Table 22, but these would
be a 6 percent reduction where the basis was kilowatt-hours.  The vequirements
for stack gas reheat would be reduced by a factor of 2.5 for the CWS with
175 F stack gas temperature.

     The implications of the impact of the sludge and solid wastes produced from
the plants can be put in better perspective by considering the quantities of waste
resulting from the burning of a ton of coal in each  tyoe of plant.  Calculations
show that the burning of 2000 Ib of coal would yield 1540 Ib of wet sludge fo.r
the CWS, 740 Ib of dry product for the AFB plant, and 1060 Ib of dry product
for the PFB plant.

     Fjctrapolating the above quantity of sludge for  the case of CVS of 1000
MU(e) capacity operating over a period of 30 years, a requirement of 800 acres
of land would be required for dispoal of sludge.  Iti view of such disposal
requirements, there is a strong need to develop regenerabla systems to reduce
the volume of waste from all of the plants.

2.  Studies by TVA

     In order to account for uncertainties in the state of technolop. • of come
components of the AFB and PFB power plants and to better reflect sctral utility
practice regarding the costing of certain subsystems of convent- onai pnwer
plants, TVA has prepared some modified estimates for comparison vif'i the capi-
tal costs and costs of electricity obtained by GE.  These results are shown in
Table 108.  Shown in this table are the total capital costs in 1975 dollars
and corresponding costs accounting for escalation through the construction
period.
                                      11

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                               Table 22
                       ENVIRONMENTAL INSTRUSION
        CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-250 F STACK
              EMISSIONS

S0x

N°x
HC  „

Partulates


         THERMAL POLLUTION

Heat, Rejected Cooling Towers, Btu/kWh

Heat, Rejected Stack, Btu/kWh****

Heat, Rejected Total, Btu/kWh


               WASTES            "

Water Discharge

Dry Fly Ash

Sludge (Dry Basis)
LB/MBtu
 INPUT

 0.867*

 0.65**



 0.092***
   LB/kWh
   OUTPUT

   0.0093

   0.0070



.  0;00099
.*-


LB/kWh
1.59
0.07
0.19
4188
3130
7318
M LB/DAY
28.4
1.30
3.46
   *Based on lime scrubber w/8.5 ft/sec gas velocity  thru scrubber,
    Ca/S ratio =1.10.
  **Based on balanced staged combustion system in conventional boiler.
 ***Based on electrostatic precipitator upstream of the scrubber.
****Includes all system heat losses except heat rejected in the cooling
    towers.

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                                   Table 56

                            ENVIRONMENTAL INTRUSION
                ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
              EMISSIONS
S0x

NO
  X

HC

CO

ParticMlates
LB/MBtu
INPUT
1.028*
0.270**
LB/kWh
OUTPUT
0.0098
0.00253
 0.040

 0.099***
  0.00038

  0.00094
          THERMAL POLLUTION  ,        :,

Heat, Rejected Coaxing Towers,  Btv/kWh

Heat, Rejected Stack, Btu/kWh

Heat, Rejected Total, Btu/kWh
                    4729

                     909

                    5636
                WASTES

Spent Solids Congolomerate

  42% Calcium Sulfate
  31% Ash
  24% Unreacted Lime
   3% Carbon

Water Discharge
LB/kWh
 0.292
 1.32
M LB/OAY
  5.70
 25.8
  *This is based on the Ca/S ratio of 2 selected for this s';udy.  Data
   available to EPA suggests that a Ca/S ratio of 2.5 to 3-5  may be required
   to routinely achieve S02 emissions compliance.
 **BaseJ apon available data, EPA Relieves that the NOX  emission level will
   more typically be in the range of 0.3 to 0.6 Ib/MBtu.
***Assuiaes use of EUctrostatic Precipitat.or as the final stage of flue gas
   particle removal.
                                   13

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                                   Table 78
                            ENVIRONMENTAL INTRUSION
                ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED  BED
              EMISSIONS
so2

Uo
  x
HC

CO

Particulates
LB/MBtu
INPUT
0.688*
0.152**
LB/kWh
OUTPUT
0.0060
0;0013
0.020

0.100***
                                                                  0..0002

                                                                  0.0009
          THERMAL POLLUTION

Heat, Rejected Cooling Towers, Btu/kWh

.Heat, Rejected Stack, Btu/kWh

Heat, Rejected Total, Btu/kWh


               WASTES

Spent Solids Conglomerate

  42% Ash Compounds
  26% Calcium Sulfate
  16% Magnesium Oxide
  13% Unreacted Lime
   4% Unburned Carbon

Water Discharge


LB/kWh
0.34-24
951
5300
M LB/DAY
7.43
                                                 1.19
                25.9
  *Based upon dolomite injection into the PFB at a Ca/S ratio of 2.
 **Based upon available data, EPA believes that the NOK emission level
   will typically be in the range of 0.1-0.4 Ib/KEtu.
***Assumes use of high temperature/pressure granular bed filter as final
   stage of flue gas particulate removal.
                                  14.

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                               Table 108

              COST COMPARISON OF GF. STUDY VS. TVA  REVIEW

                  Total Capital Costs (1975 dollars)
PLANT
TYPE
*CWS (? 175 F
AFB
PFB
PLANT
OUTPUT
MW
795.5
814.3
903.8
GE STUDY
TOTAL COST
($000,000)
395.96
332.45
A 21. 00
COST/KW
($)
497.75
408.26
465.81
TVA REVIEW**
TOTAL COST
($000,000)
398.03
363.14
479.45
COST/KW
($)
500.35
445.95
530.48
Total Capital Co'st Escalated (5.5 year construction to mid-1981)

CWS @ 175 F     795.5        613.74    771.5        616.95    775.6

AFB             814.3        514.70    632.0        562.87    691.2

PFB             903.8        653.10    722.8        743.15    822.3
 *Scrubber is lime slurry w/8.5 ft/s Ras velocity through scrubber, onsiro
  calcination.
**Estimates by TVA include an uncertainty allowance  for components not-yet
  demonstrated, and revision for some components based upon TVA's experience.
                                   15

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     For the CWS, the differences between the costs obtained by GE and the
corresponding costs prepared by TVA are small.  The major  differences result
from differing costs assigned to the electrical subsystem  by the two
organizations.

     The cost estimates prepared by TVA for the AFB and PFB plants show signi-
ficant variance from the corresponding values prepared by  GE.  In these cases,
TVA has assigned an "uncertainty factor" to selected components of the plant
that are assumed to have reached a mature level of technology, but have not
been applied commercially at full scale.  The uncertainty  factor was applied
as an added percentage of the cost of an item of equipment or system and was
assigned a value on the basis of how close to commercialization the item was
judged to be.

     The allowances accounted for through application of the uncertainty factor
are to take care of design changes, addition of equipment, and technological
advances.  The modifications do not incorporate development and startup costs
associated with obtaining a state-of-the-art process.

     The specific items to which an uncertainty factor was applied in the
fluidized bed plants were the steam generators, fuel injection systems, spent
solids and dust coolers, and portions of the hot gas cleanup systems.

     As a further extension of the study, TVA developed cost estimates for the
alternative scrubbing systems for the CWS and alternate schemes for disposal
of the sludge from the CWS and solid wastes from the AFB and PFB plants.   In
conjunction with these studies, TVA took into account the  cost associated
with sludge and waste disposed over a period of 30 years.

     The scrubbing systens considered were as follows:

     a.  Lime scrubbing with onsite calcination

     b.  Lime scrubbing without onsite calcination

     c.  Limestone scrubbing

     d.  Magnesium oxide regenerable scrubbing (production of sulfuric acid)

     The variety of disposal schemes involved combinations of treatment and
nontreatment of the -wastes from scrubbers and fluidized combustion plants in
combination with choices of clay-lined ponds or clay-lined, diked impoundments
that were located either onsite or offsite.

     The total capital costs, expressed in dollars per kilowatt and the cost
of electricity expressed in mills per kilowatthour are summarized in Table 127.
Among the scrubber alternatives the cost of electricity is the lowest for the
magnesium oxide regenerable scrubbing system.  This prediction, coupled with the
alleviations of waste disposal problems provides incentive for commercialization
of regenerable systems.  The alternate scrubber systems with 30-year sludge
disposal showed little variation in cost of electricity.
                                   16

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                                                       Table  127

                            COMPARISONS OF COSTS CONSIDERING  VARIOUS TYPES OF SCRUBBERS AND
                                           ALTERNATE METHODS  OF WASTE DISPOSAL
Conventional With Scrubber

     GE/CWS/250F/5 yr. disp./lime w/calcination/747 MW
     GE/CWS/175F/5 yr. disp./lime w/calcination/795 MW
     TVA/CWS/175/30 yr. disp./lime w/calcination/795 MW
     TVA7CWS/175F/30 yr. disp./lime (purchased)/795 MW
     TVA/CWS/175F/30 yr. disp./limestone/795 MW
     TVA/CWS/175F/MgO/Regenerable/795 MW W/^SO*,  credit
     TVA/CWS/175F/MgO/Regenerable/795 MW NO H2S04 credit
                                                                TOTAL CAPITAL
                                                                     $/kW
835.4
111.3
782.3
758.9
773.9
728.0
728.0
                   COST OF ELECTRICITY (Mills/kWh)

              CAPITAL     O&M     FUEL     TOTAL
26.40
24.38
24.73
23.99
24.47
23.01
23.01
2.61
2.45
3.74
3.92
3.41
2.37
3.55
10.73
10.10
10.10
10.10
10.10
10.10
10.1
39.83
36.93
38.57
38.00
37.99
35.48
36.66
Fluidized Bed Power Plants                                              i

     GE/AFB/onsite disposal (30 yr.) 814 MW                         654.0
     GE/AFB/offsit-j disposal (30 yr.) 814 MW                        648.5
     GE/PFB/onsite disposal (30 yr.) 904 MW                         745.0
     GE/PFB/offsite disposal (30 yr.) 904 MW   •                     739.6
     TVA/AFB/uncertainties added/onsite disposal (30 yr.)  814 MW    71.2.4
     TVA/AFB/uncertainties added/offsite disposal (30 yr.) 814 MW   706.4
     TVA/PFB/uncertainties added/onsite disposal (30 yr.)  904 MW   * 845.1
     TVA/PFB/uncertainties added/offsite disposal. (30 yr.) 904 MW   839.7
     GE/AFE/nb disposal/SlU MW                                      632
     CE/PFB/no disposal/90^ KW                                     ..723
20.67
20.50
23.55
23.38
22.52
22.33
26.72
26.55
20.00
22.90
2.61
2.77
2.98
3.16
2.61
2.77
2.98
3.16
9.50
3.70
9.53
9.53
8.71
8.71
9.53
9.53
8.71
8.71
2.20:.
2.50
32.81
32.80
35.24
35.25
34.66
34.63
38.41
38.42
31-7
3^.1

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     The results in Table 127 also indicate that  the economics of the AFB plant
are favorable in comparison with the ?FB plant.   The uncertainties are greater
for PFB plants, plus additional capital outlays are reouired.  These factors
contribute significantly to higher capital costs  and cost of electricity in
comparison with AFB plants.  Comparison of the estimated costs of electricity
indicate that AFB offers the pttential for a savings in comparison with all
of the CWS options.  PFB also offers potential savings if uncertainties are
not included; if uncertainties are included, the  estimated cost of electricity
is about the same for PFB and CWS.  However, the  estimated COE for the CWS
alternatives and the AFB and PFB alternatives (with uncertainty) are so close
(within 12%) that all are considered within the competitive range for further
consideration.
                                   18

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                        CONCLUSIONS AMD RECOMMENDATIONS


A.  Conclusions

     Several observations become evident upon examination arid comparison of the
performance and economic results that have been  generated from the study of
CWS, AFB, and PFB plants.  It is important to keep in mind that developmental
and startup costs associated with obtaining a state-of-the-art process have
not been incorporated in the results.  The salient conclusions are itemized
as follows:

     1.  The AFB power plant offers a near-term  promising alternative to the
         CWS.  The comparison on the basis of the costs of electricity indi-
         cate an approximate savings of 9 to 14  percent (depending on whether
         or not an uncertainty allowance is applied) in favor of the AFB as
         opposed to the CWS using lime or limestone for capture of sulfur.

     2.  The economics of the PFB plant fay be severely affected by stringent
         hot gas cleanup requirements and high pressure (10 atmospheres)
         solids handling requirements.  The comparisons on the basis of cost
         of electricity between the CWS using lime or limestone and a PFB
         plant using dolomite for capture of sulfur indicate no savings in
         using the PFB if allowances for uncertainties are considered in
         evaluating the PFB plant.  On the other hand, if no uncertainty
         allowance is applied, the PFB plant offers a 7 percent savings in
         cost of electricity in comparison with  the CWS.

         The superiority of the overall efficiency of 39.2 percent for the
         PFB plant in comparison with, typically, 35.8 percent and 33.8 per-
         cent for the AFB plant and the CWS, respectively, is offset by
         large capital requirements for gas cleanup equipment for the PFB
         plant.  Estimates for hot gas cleanup costs vary from estimator
         to estimator, depending on the design assumptions used *, use of
         different assumptions from those used by GE could increase the
         apparent savings for PFB.

     3.  The performance of the CWS is penalized by additional power require-
         ments for operation of the scrubber and (much greater) by stack gas
         reheat requirements.  For example, the  difference in the cost of
         electricity for a CWS in which the gases existing from the scrubber
         are reheated to 250 F instead of to 175 F amounts to a penalty of
         approximately 8 percent.  Thus, there are significant differences
         in the economics of the CWS for different reheat temperatures of
         the stack gases.

                                   19

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     4.   Application of alternative scrubber systems now developed do not
         affect the economics of the CWS enough to change its position
         relative to AFB and PFB plants.

         Estimates for the CWS utilizing a magnesia slurry scrubber suggest
         that a reduction in the cost of electricity may be attained rela-
         tive to the scrubber using lime and limestone.  However,  the
         magnesia scrubber remains to be fully developed and regeneration
         of the sorbent is unproven.


B.  Recommendations

  f.  The following recommendations are made for extending the studies reported
herein:

     1.   It is recoir,mended that the study be extended i o include, intermediate
         load duty since most utility power systems will in all likelihood
         require this type of service from all three types of plants.

     2.   In view of the fact that such extensive areas of land will be required
         for disposal of sludge/soliu wastes over the life of either of the
         types of plant studied, it is recommended that development of systems
         for sorbent regeneration be.accelerated.             '
                                   20

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                   GE CONCEPTUAL DESIGNS AND COST ESTIMATES
A.  STUDY GROUND RULES

     The methodology and ground rules used in the evaluation of a conventional
steam plant with stack gas scrubbers,for sulfur removal are identical with
those applied to steam power plants in the Energy Conversion Alternative? Study.
Those elements that are not dealt with in,the detailed text will be briefly
reviewed here.

     The focus was on baseload plants with 30 years useful life and 90 percent
plant availability,.  The capital costs were evaluated for mid-1975 costs, as if
all elements were fully developed.  All plants were treated as mature and no
development costs were included.  During construction, prices would escalate
,6.5 percent per year.  Interest during construction would be at 10 percent per
year; the fixed charge rate per year of operation would be 18 percent of plant
final cost.  The time for construction, 5.5 years, was determined on the basis
of the  total man-hours of field labor content.  The S-curve for expenditures
resulted in escalation and interest during construction 0.548 times the total
plant cost without those factors.

     The fuel was a high-sulfur Illinois coal  (No. 6) with the characteristics
defined in Table 1.  The emission standards for flue gas are presented in
Table 2.

     Several efficiencies are reported for each type of plant.  The thermodynamic
efficiency was the generator output divided by the heat  input to the steam cycle.
The power plant efficiency and the overall efficiency were both equal to net
station output divided by the higher heating value of the coal fired.

     The heat rejection from condensers was to mechanical draft evaporative
cooling towers.  Power plant operation was evaluated for a 59 F air ambient
with 60 percent relative humidity.  The resulting wet-bulb temperature was
51.5 F.

     Uniformity of treatment of all  steam plants was assured by use of the same
team as contributors.  The heat input for combustion and heat exchange to steam
were studiec by the Foster Wheeler Energy Corporation.   The pressurising gas
turbines  for the PFB were evaluated  by the General Electric Gas Turbine Products
Division    Investigations of the  steam turbine and its cycle specifications were
done by the General  Electric Large Steam Turbine Department.  The  wet lime
scrubber  system, the heat rejection  equipment, and all balance of  plant  labor
and equipment were evaluated by the  Bechtel Corporation.   Bechtel  also provided
architect-engineer layouts of the plant site and plant arrangement.  The  systems
integration was done by the General  Electric project tea*

                                   21

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     Operating and maintenance costs were assessed to each plant on the basis
of estimates provided by the boiler manufacturer,  Foster-Wheeler, the steam
turbine manufacturer, GE, and the architect-engineer, Bechtel, for the scrubber
system and consumables such as limestone.  The operation manning requirement
was evaluated by the Installation and Service Engineering Staff of General
Electric.
                                   22

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                     Table 2




                EMISSION STANDARDS






                                       Standard

Pollutant                        (Lbs/MRtu Heat Input)




   SO                                     1.2
     A.                                 •


   NO                                     0.7




Particulates                              0.1
                     23

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B.  CONVENTIONAL/WET SCRUBBER POWER PLANT


1.  INTRODUCTION

     A steam power plant with wet gas scrubber  to reduce stack gas emissions  is
a distinct advance over the numerous conventional coal-burning steam power
plants that cannot meet ioday's emission standards except by burning low-sulfur
coal or converting to oil firing.  There will be a direct competition between
plants with conventional furnaces with stack gas cleanup, and alternatives
such as fluidized bed furnaces that capture sulfur products during the
combustion process.
                     >
     The simplified cycle schematic presented as Figure 1 shows the major
pieces of equipment.  The coal and air are fired with staged combustion of
the pulverized coal to limit generation of thermal NOX products.  The furnace
and its elements (steam turbine, condenser, and cooling towers) are all proven
conventional elements.  Gas leaves the unit at  300 F after passing through
electrostatic precipitators that reduce the burden of fly ash in the flue gas.
The gas enters the scrubber and is quenched to  125 F with lime slurry sprays.
Sulfur is removed as calcium sulfite and calcium sulfate, which precipitates  out
in the sludge pond.  Lime is continually replenished, using an onsite calciner
for limestone.

     The water-vapor-saturated flue gas at 125  F Is next reheated to either
175 F or 250 F.  The means is a blending with a large quantity of air that has
been preheated above that temperature by steam  extracted from the steam turbine
cycle.

     The system parameters are presented in Table 3.  The Illinois No. 6 coal
contains 3.9 percent sulfur.  Eighty-three percent of the sulfur must be cap-
tured to meet the environmental emission limit  of 1.2 pounds of sulfur dioxide
per rail lion Btu of fuel heat release.  The wet  scrubbers are specified to cap-
ture 90 percent of the flue gas sulfur burden when 4.5 percent sulfur was pre-
sent in the coal.  With the specified margin of performance capability, the
plant operation is assured of meeting current standards for flue ga,~ emissions.
The consumption of lime is minimized by the intimate mixing in the wet scrubbers.
In addition the recirculating system provides for reuse of lime in solution in
Che-clarified water recirculated from the sludge pond.

     The steam cycle uses conventional conditions for a supercritical reheat
unit with seven feedwater heaters.  The large extraction of steam at the turbine
crossover pressure for stack gas reheat approaches the limit set for conven-
tional practice.  The condenser back pressure was chosen to optimize the total
 Preceding page blank
                                   25

-------
ro
<7\
                         Coal
                         Air
                    Air

                   1
                         ^ Steam
                 Reheaters k-
                                     CF
         Sludge Pond
Reheat
                                               Steam
   HP
IP
                                               Feedwater
                                                             Feed Heaters
                                                                                  LP
                           Condenser
f-
                              Limestone


                      Figure  1.   Conventional Steam  Plant—with Wet Gas Scrubbing

-------
                                Table 3

                          SYSTEM PARAMETERS
                CONVENTIONAL STEAM—WET GAS SCRUBBERS
              PARAMETER

Fuel

  Illinois No. 6


  Limestone
    '*-

Furnace

  Radiant Section
  Convection Section

Prime Cycle—Steam Plant

  Working Fluid
  Tuibine Inlet
    Reheat
  Condenser
  Final Teedwater

Heat Rejection

  Wet Mechanical
  Draft Cooling
  Towers
  Stack Gas Temperature
       VALUE OR DESCRIPTION
10788 Btu/LB Higher Heating Value
             ,l$/MBtu

        For Sulfur Capture
         0.16 LB/LB Coal
       Pulverized Coal  Fired
       Superheat  and- Reheat
              Steam?
              3500 PSI,  1000 F
              659  PSI,  1000 F
              2.3" Hga,. 106  F
              4378 PSI,  505  F
              20 Cells
               ?50 F
                                  27

-------
cost of electricity with respect  to  turbine output and cost, heat rejection
system cost, and auxiliary power  consumption.

     The first case set stack gas temperature at 250 F in conformance with
forner conventional steam power plant practice.  The influence of stack
gas temperature is far greater than  normal for this steam plant configuration.
In an additional case the corrosive  component dew points in the flue gas are
assumed to be at or below 125 F by the  scrubbing process.  As a result a lower
stack temperature was deemed to be permissible.  A subsequent evaluation was
made for 175 F stack temperature.  Details o:" this case will only be presented
after a complete appraisal of the 250 F stack case.

     The net power from the 250 F stack plant would be 747 MW, representing a
32 percent conversion efficiency  from-coal to dispatched power.  The net power
from the 175 F stack plant would  be  795'MW, vith a 34 percent conversion
efficiency.
                                  28

-------
2.  CYCLE DESCRIPTION

     A more detailed plant schematic is presented in Figure  2.  State points
and stream flows are shown wherein the enthalpy values are referenced to
32 F water for steam and water and to an 80 F zero reference for air, combustion
gases, and solids.  The advanced feature of this power system is the use of wet
flue gas scrubbers with a conventional boiler to generate  steam from high-sulf'iv
coal for a conventional steam turbine cycle with a single  reheat of the stean.


Steam Turbine-Generator Cycle

     The steam turbine is contained in four shells connected in t.andem with a
single 820 MW generator.  The low pressure stages have four  parallel flows
exhausting downward into a common condenser.  The condenser  coolant is wati»r
recirculated in a closed circuit to evaporative cooling towers.  The regenera-
tive feedwater heating cycle has four low-pressure feedwater heaters, a deaera-
ting feedwater heater, and two high-pressure feedwater heaters.  Part of the
steam exhausted from the high-pressure turbine is used in  feedwater heating,
while the rest is returned to the boiler to be reheated to 1000 F.  Part of the
steam from the reheat turbine exhaust is used ^f or driving  the boiler feed pump.
The exhausts from those drive turbines are routed to the main condenser.  All
other pump drives are electric motor driven and appear in  the detailed account
of auxiliary losses.  The boiler feed pump and its drive arc sn integral part of
the steam cycle and are fully accounted for in the heat balance for the steam
turbine-generator.
                                          ^ •                            •        '
     The final feedwater wouldrbe 505 F for the 100 percent  operation.  All
major components were specified for continuous performance capability at a
flow margin of 5 percent above the intended plant operating  flow.   The steam
cycle at the valves wide open (TOO) point would pass the intended flow with
margin, and the designated 510 F feed temperature would then exist.  It is
important in conventional steam systems that the operations  be evaluated at the
100 percent operating point, where performance is guaranteed, and not at the
specification condition for design with margin.


Conventional Steam Generator

     The coal to be fired is dried by the primary air-flow at the eight ball
mill pulverizers.  Between 15 and 20 percent of the total  air is heated to
633 F in the hottest sector of the air preheater as primary  air.  This air
serves to dry the coal, to convey the pulverized coal  to the burners, and to
consummate the initial combustion process.  The Remainder  of the air is
preheated to 585 F and delivered to the burners as secondary air.

     The water circuitry in the steam generator provides water walls, radiant
energy absorption surfaces, convection and radiant surfaces  for superheat!, ig
and reheating of steam, and an economizer to bring the flue  gas to 740 F
as it leaves the boiler and enters the air" preheater .   Slag  is removed from the-.
boiler furnace beneath the firing zone,  fly ash from a hopper just before the
air preheater.  These solids,  representing 15 and 10 percent of the total ash,
                                  29

-------
UJ
o
                SitOffl Turbine Generator (!)

3415/1000/6 O/I42I.7 ~
                                                                                                                                         Generated 6I9.9MW
                                                                                                                                        • Auguries  72 7MW
                                                                                                                                         Mel Output747 2 MW
                                                                                                                low Pressure reed Heaters


                                                                                                   Boiler Feeo Kimp 13)
                                                                                                                                                       Tower?
                                                                                                                                                       20 Ceils
                       3600'X 3600'X 22'
                                                                                                                                       fit-re-:-17 oooil
                                                            LEGEND'  Prsssjre/TemperoIure/FlowRate/tnlhoipy
                                                                      PSIA/"F/Mi(lion Pounds Per Hour/BTU Per Pound
                                                                      "Million Fcwntfi Per Houf
                                               Figure 2.  Conventional Steam Cycle with Wet Gas Scrubbers

-------
respectively, are sluiced to the sludge pond.  The electrostatic  precipitators,
with an efficiency o£ 98.6 percent, collect another 75 percent  of the total ash,
leaving only 0.75 percent in the gas flow to the wet scrubbers.   The collected
fly ash is stored in dry silos for shipment offtiite.  Induced draft fans follow
the electrostatic pre.cipitators.


Wet Gas Scrubbers

     The w*?t r,as scrubbers apply a spray of recirculated hot  water that is
rich in liwo in order to capture sulfur compounds.  The remaining fly ash will
be washed out of the flue gas also.  Following the main reactive  spray there
is a demisting, spray that recirculatrs a makeup warer and captured drift
mixture.  Carry ever of the slurry and lime are avoided by this means.


Lime And Sludge Systejns

     A continual removal of sludge and a continual replenishment  of lime and
water is required.  The sludge is flushed to the sludge settling  ponds in a
stream comprising 10 percent undissolved solids.  The return  water from the
pond is enriched with lime produced la the coal-fired calcinator  from limestone
feedstock.

     The makeup water moves in a counterflow mode.  It is first applied iii the
mist eliminator recycle wash bleedoff replenishing the S02 absorber recycle
liquids, and ultimately becomes part of the sludge and water  mixture that
accumulates in the settled portion of the sludge pond.
Stack And Reheat System

     The flue gas at 125 F leaves the wet scrubber saturated with water vapor
and with many constituents at or near their dew point  temperatures,  It has been
determined that normal gas heaters cannot have suitable  service lives when
heating such a corrosive gas mixture.  The alternative to direct heating is to
blend into the flue gas a large flow of air that has been separately heated.
Figure 2 shows that 14 Mlb/h of air heated to 334 F blend with 8 Mlb/h of flue
gas to produce a 250 F stack temperature.  The stack air heaters u.-,e steam
withdrawn fron the steam cycle as their heating medium.  The stack and flues ire
lined, to wltttstand attack from the flue gases.
Overview

     The major components of this system are conventional ami of proven relia-
bility in utility service.  The wet scrubber system introduces an added need
for maintenance asid for the avoidance of corrosive attack bv Iirce and cool
flue gas.  The subdivision into six parallel scrubbers and the subdivision of
critical pumping functions in the scrubber system should assure that at most
one-sixth of the capacity would be down at any time.
                                  31

-------
3.  MAJOR CYCLE COMPONENTS

     Components for conventional steam plants are specified for continuous
operation with flows 5 percent greater than required for normal operation.
Insofar as Figure 2 depicts 100 percent plant operation on a 59 F day,  the
individual specifications for the boiler, turbine, and scrubber will require
greater capacities at their design points.  The exact matching has been
accomplished on the basis of an exact steam-turbine heat balance, which
dictates the heat to steam for the boiler, and the boiler efficiency,
which in turn dictates the fuel requirement.

     This section will consider the specified performance for the steam
turbine-generator, the boiler, the scrubber system, and the heat rejection
syjstera.  The latter two are furnished as balance-of-plant equipmont. All
other balance-of-plant items will be specified in a subsequent section.


Conventional Furnace-Steam Generator

     The general layout of the conventional supercritical once-through
steam generator is shown in Figure 3. .Eight .jjall mill coal pulverizers
are located at the base elevation.  The burners are arrayed about the radi-
ant furnace section.  The combustion gas flows upward over superheater
sections, then downward in parallel paths through the reheater and tl;e
primary superheater, and finally emerges from the economizer.   Figure 4   ^
presents a preliminary heat-
-------
           T
            4-     -\>   J-  su»c«miTc« o^tift
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         'sS^'^^HITtor"17^^^
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 ,;.  .f*-^"-'      •'  :       T^—
 LiT-Tfc.4610''«j!.«C€ DEPTH ptT~
Figure  3.   Conventional  Boi ler—Supercritical Once-Through Coal
            Firing
                                33

-------
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-------
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-------
     The heat to the steam cycle at 100 percent operating conditions would
be 6867.4 MBtu/hr.  The heat input would be 8375.54 Btu/kWh at the generator.


Stack Gas Scrubber System

     Although all elements of the wet gas scrubber system would be furnished
as balance-of-plant equipment, the unique aspects of this system command
that it rank as a major cycle component and that it receive detailed attention.

     The entire scrubber system is illustrated in Figure  7 along with process
flow charts appropriate for operation at the specified 5  percent flow margin,
using 4.5 percent sulfur coal.  The sulfur capture would  be 90 percent.  The
two process flow charts do not differ in respect to the sulfur capture system;
only the reheating of stack gas to 250 F in the upper chart and 175 F in the
lower chart are different.

     The lime requirement is met by calcining limestone in a rotary kiln fired
with coal.  There would be onsite a 60 day supply of limestone.  The coal
would be stacked in a four-day storage bin by front-end loaders.  The emission
requirements for the calciner aro met by the use of a baghouse dust collector
and a separate stack.  No reduction in sulfur gases is expected for the coal
fired in the calciner.

     The lime product is expected to be in excess of 95 percent available
lime.  It is stored in silos with a capacity sufficient for five days' opera-
tion.  With the 1500 tons-per day of limestone calcining  capacity, this part of
the plant need not operate continuously to support plant  operations.   There
should be sufficient time to accomplish all usual maintenance and refurbishment
on a scheduled basis.  The entire left half of Figure 7 represents onsite capital
investment and operations that would be eliminated if lime rather than limestone
were available for purchase in suitable quantities at a suitable price.

     The right half of Figure 7 is the scrubbing system that causes lime to
react with sulfur in the flue gas to fora solids that accumulate in the sludge
ponds.  The lime replenishment is slaked with pond recycle water to a 16 hour
storage tank.  The slaked lime and remaining pond recycle water are discharged
to the S02 absorber effluent holding tanks.  Table 4 presents the major
parameters of the limestone/lime system considered to this point.

     The 3-stage S02 absorbers operate on flue gas that has been quenched
from 300 F and saturated with water vapor at 125 F by the presacuracion sprays
at each absorber gas inlet.  The flue gas then flows upward through the three
absorber stages, each of which comprises a 6-inch bed of  spheres.  The liquid-
to-gas ratio maintains 110 percent of lime-to-sulfur stoichiometric ratio.   The
effluent wet gas is further washed in the mist eliminator sprays.  These sprays
receive all of the fresh makeup water intended for all replenishment of the
scrubber system.  This final wash captures carryover or large droplets of drift
of recycle wash liquids.  Table 5 indentifies the parameters of the wet absorber
system and keys the stream functions to Figure 7.
                                  37

-------
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-------
                         Table 4

             LIMESTONE/LIME SYSTEM PARAMETERS
             CONVENTIONAL FURNACE-STEAM CYCLE
    Lime Product Quality
    Limestone/Lime Product
    Limestone Storage

    Limestone Calciner
      (Traveling Grate Kiln)
      Nominal Production
      Capacity
    Fuel Requirements (111.
    Lime Storage Capacity
    Lime Slaker Capacity
    Slaking Temperature
    Slaked Lime Slurry Solids
      (After Dilution)
    Lime Slurry Surge Capacity
95% Available CaO
2 Tons/Ton
60-Day Supply
90,000 Tons
650 Tons/Day
880 Tons/Day
5 MBtu/Ton Lime
5-Day Supply
800 Tons/Day
H90 F
20% WT

16 Hours
                         Table 5

           WET LIME ABSORBER SYSTEM PARAMETERS
             CONVENTIONAL FURNACE-STEAM CYCLE
      (BASIS:  90% SOX REMOVAL FOR 4.5% SULFUR COAL)
S02 ABSORBERS (6)
Ho. of Stages
Superficial Gas Velocity
Total Pressure Drop
Liquid/Gas Ratio 8
Presaturation Sprays 7
Mist Eliminator Wash Sprays 9
Lime:  S02 Stoic. Ratio
Absorber Hold Tank
  Residence Time
Recycle Slurry Solids 1587
Lime Makeup Slurry Solids 13
Spent Slurry Pond Solids 17

      Stream Identification, Figure 7
   TCA-Type
   3 (6" of Spheres/Stage)
   8 FT/S
   9-IN. H20
   72 GAL/MSCF
   2.5 GAL/MSCF
   2 GPM/FT2
   110%
   5 Min.

   10% WT
   20% WT
   40% WT
                            39

-------
     The flue gas at 125 F and saturated with water vapor is highly corrosive
and chemically active.  Normal heat exchangers that would reheat the flue gas
to an appropriate stack temperature would not withstand the chemical attack
of the flue gas.  Even the flues and stack must be lined to avoid attack.
The necessary stack temperature is achieved by steam-heating additional air
and blending the heated air with the flue gas.  This requires six low head
fans and six heaters.  Two alternatives of stack temperature were examined:
250 F and  175 F.  Table 6 presents the parameters of the blend air and its
heat requirements for these alternatives at their 100 percent operating
point.  The blending means of gas heating is increasingly inefficient as the
stack temperature is increased toward the air temperature of 333 F, account-
ing for the great differences between these two alternatives.

     The wet gas scrubber arrangement shown in Figure 8 connects these several
elements with the four Induced draft fans that service the four electrostatic
precipitators.  There is a total of six absorber and stack reheater trains.
The induced draft fans feed a cross-duct that is normally Isolated by dampers
from the startup bypass path.  Connecting in a downward fan-like duct are the
presaturation spray ducts to each absorber.  The redundancy dictated by the
size of the absorbers should produce a high level of availability for the
scrubber system.

     The sludge ponds are the remaining element of the wet scrubber system.
Each pond  would measure 3600 feet by 3600 feet by 22 feet deep.  Six ponds
would accommodate 30 years of plant operatitns.  Only one pond was accounted
for in the capital cost presentation.  The accumulation rate of solids would
equal the  solids delivery rate of 150,000 Ib/h of calcium sul^lce ?^u excess
unreacted  lime.  Because water would accumulate at a rate 50 percent greater,
 in jSitti solids concentration would be 40 percent.  It is important to recog-
'nize these two accumulations, because the tables on Figure 7 represent steady-
, state balances for the absorbers but nonsteady states for lime, makeup water,
and sludge accumulation.
 Scrubber Costs

      The direct  costs  for the  scrubber  system comprise material costs and
 direct field labor costs  as detailed  in Table 7 for a 250 F stack and in
 Table 8 for a 175 F stack.  These costs are insufficient insofar as balance
 of plant construction  must bear a prorated share of the indirect field
 expenses and additional electrical, civil, process, and yardwork must be
 done.  Tables 9  and 10 present the complete costs, with the first two items
 on line 1.0 carried over  from  Tables  7  and 8.  The allocations for indirect
 labor, fees,  contingency, and  escalation will be discussed in the subsection
 concerned with balance of plant in Section 5, "System Performance and Cost."
 All of these items of  expense  will also be included in the comprehensive list
 of balance-of-plant accounts.  Presentation here with all elements of costing
 is done to facilitate  identification  of the incremental cost due to the wet
 scrubber system.   For  the 250  F stack case, a total of $51.9 million for this
 major system is  comparable to  a steam turbine-generator cost of $26 million,
 and a boiler component cost of $39.7  million.  The wet scrubber is a major
 addition.

-------
        Table 6

    FLUE GAS HEATERS
FOR WET SCRUBBER SYSTEMS
PARAMETER

Heat Duty, MBtu/HR

Steam
Air Velocity, FT/MIN

Air Rate, M LB/HR

Pressure Drop, IN. H20

Heat Transfer Rate,
Btu/ (HR SQ FT °F)

Finned Surface, SQ FT
                  STACK GAS REHEAT TEMPERATURE
                      250 F          175 F

                       971            217

                   620 -> 356 F    620 -»• 356 F

                    333 •*• 59 F     333 * 59 F

                       900            900

                      14.586         ?.267

                       1.5            J..O
                                          5.5

                                        645,000
                                    86,5'00
             41

-------

        GROUND FUOOS PLAN FL.0'
A!


T^r
_ M
— • • i
t
t
1 i
1 i


i _^_
i i •
zwrs-v '/ t
? " — t*
1 1
HT

,'>1-U

T ...-!• -. _.^ — *f1>11-1C5
BEOBTEL
GE/NASA
aD/ft^CED EN'EPGYCC'JVEaS'CN
STUDY
r^o-.c-ji. v-«. /--.^'^-•ci'd «-••(•

M •»*«» : M*n*»
7 iu07
P-6C4
M*
0
Figure 8. Wet Gas Scrubber Arrangement—Conventional Steam Plant

-------
                                   TABLE 7

                    SCRUBBER EQUIPMENT DIRECT FIELD COSTS
                              (250 STACK TEMP.)
Major Mechanical
Equipment
Limestone Handling
Limestone/Lime System
S0~ Scrubber Vessels
Scrubber System Pumps
Scrubber Systfo. Tanks
Scrubber Ductwork
Scrubber Flue Gas Equipment
TOTAL


SCRUBBER
Major Mechanical
Equipment
Limestone Handling
Limestone/Lime System
S02 Scrubber Vessels
Scrubber System Pumps
Scrubber System Tanks
Scrubber Ductwork
Scrubber Flue Gas Equipment
TOTAL
Materials
M$
1.25
3.66
6.93
1.08
2.18
3.27
3.09
21.46

TABLE
Direct Labor
M$
0.25
0.73
1.01
0.12
0.05
2.43
•*• 0.3?
4.96
**•••
8
Total
M?
1.50
4 . 4<
7.94
3.20
2.23
5.70
3.41
26.42


EQUIPMENT DIRECT FIELD COSTS
(3.75 STACK TEMP.)
Materials
M$
1.25
3.66
6.93
1.08
2.18
* 1.95
* 0.90
* 17.95
Direct Labor
MS
0.25
0.73
1.01
0.12
0.05
1.41
O.OS
3.70
Total
M$
1.50
4.44
7.94
1.20
2.23
3.36
0.98
21.65
                     O         c>

*Changed From 250 Stack Case

-------
                                   TABLE 9

                   WET LIME SCRUBBER CAPITAL COST BREAKDOWN
                      CONVENTIONAL FURNAC2 - STEAM CYCLE
                             (250 F STACK TEMP.)
                                              Direct    Indirect
                                  Materials   Labor    Field     Total
        Categories                   M$         M$       M$       H$

1.0 Process Mechanical Equipment    21.5        5.0      4.5      31.0
      (Limestone Handling,
      Line System, Absorbers,
      Tanks, Pumps, Air Heaters,
      F.D. Fans, Ductwork)

2.0 Electrical              .         0.7        0.9      0.8       2.4

3.0 Civil and, Structural             3.7        2.1      1.8       7.6

4.0 Process Piping and
    Instrumentation                  4.3        2.6      2.3       9.2

5.0 Yardwork and Miscellaneous        -	     0.9      0.8       1.7

                                                                  51.9

              A/E Engineering, Home Office & Fee @ 15%              7.8

              Total Plant Cost                                    59.7

              Contingency @ 20%                                   11.9

              Total Capital Cost                                  71.6

              Escalation & Interest During Construction           39.2

              Total Plant Investment                             110.8
                                   44

-------
                                   TABLE 10

                   WET LIME SCRUBBER CAPITAL COST BREAKDOWN
                      CONVENTIONAL FURNACE - STEAM CYCLE
                             (175 F STACK TEMP.)
                                             Direct   Indirect
                                  Materials   Labor     Field     Total
        Categories                   M$        M$        M$       M$

1.0 Process Mechanical Equipment    17.95      3.7       3.3      25.0
      (Limestone Handling,  Lime
      System, Absorbers, Tanks,
      Pumps, Air Heaters, F.D.
      Fans, Ductwork)

2.0 Electrical                       0.7       0.9       0.8       2.4

3.0 Civil and Structural             3.7       2.1       1.8       7.6

4.0 Process Piping and
    Instrumentation                  3.8       2.5       2.2       8.5

5.0 Yardwork and Miscellaneous         -        0.9       0.8       1.7

                                                                  45.2

              A/E Engineering,  Home Office & Fee  @ 15%              6.8

              Total Plant Cost                                     52.0

              Contingency @ 20%                                   10.4

              Total Capital Cost                                  62.4

              Escalation & Interest During Construction            34.2

              Total Plant Investment                              96.6

-------
 4.   PLANT ARRANGEMENT    ^

      A group of plant arrangement drawings were prepared by the architect-
 engineer as a preliminary step to evaluating  constryction costs.


 Plot Plan

      The plant plot arrangement is based on receiving coal and limestone by
 rail and shipping fly ash off site by rail.  A 60 day pile of coal and lime-
 stone is provided.   Silos to hold 15 days' accumulation of dry fly ash are
 provided adjacent to the rail  terminal.  A series of small ponds catch runoff
 water from the site and provide for treatment of all water returned to the
 North River.

      Figure 9 shows the plot arrangement.  The smaller overall plot layout
 indicates the dominant aspect  of one 3600 f ot by 360Q foot sludge pond.  The
 upper detail shows that at the active  site naif the area will be used for coal
 storage and for cooling towers. The boiler house abuts the turbine building.    :
 The electrostatic precipitators are of substantial size in order to achieve  98.6
 percent particle removal,  A single stack serves the entire plant.  The land
 area for the power generation  plant is.92 acres; the sludge ponds must agregate
 an additional 1785 acres in close proximity to the main plant.  A total area of
 3 square miles will be required.  This requirement will severely constrain
 the siting opportunities for these plants.^                  ,.      :
                                                                         •*•
      The coal feed system provides transportation by belt conveyor from the
 line storage pile to the transfer tower. .-s-Tramp iron is removed and large
 size frozen coal is crushed te small size.  Next, the coal is conveyed to the
 surge bin in the boiler house,  where vibrating feeders and two conveyor belts
 feed eight coal silos disposed on opposite sides of the building.  The filled
•silos guarantee 8 hours of boiler output.  Each silo feeds a single coal
 pulverizer by a gravimetric feed.  Coal drying and conveyance to the burners
 is by hot primary air.  For startup and warmup an oil system firing No, 2
 fuel oil is provided, along with 100,000 gallons of fuel storage in two tanks.


 General Arrangement

      A more detailed general arrangement plan for the turbine hall and boiler
 is presented in Figure 10.  The eight  silos on either side of the boiler each
 hold an 8 hour coal supply,  and all feed to one coal pulverizer.  The air
 preheater* and flues to the electrostatic precipitators of Figure 8 dominate
 the leftside.  The ground level of the turbine hall on the right indicates the
 arrangement of the many support functions for the steam turbine cycle.

      The general arrangement elevation view shown in Figure 11 combines the
 boiler details of Figures 3  and 4 in a proper orientation to the turbine hall
 and the flue gas exhaust system detailed in Figure 8.  The arrangement provides
 short steam lines and liberal  access space for all apparatus.  At the extreme
 left, the gas enters the flue  gas system of Figure 8 at the electrostatic
 precipitators.

-------
Figure 9.  Plot Plan for Conventional Steam Plant
                                                                             CtCIIEl

-------
                                                       IEC1TEI
                                                       Gt/NASA
                                                *PV*NCtD C«HEV COWCflSKX 5TUOT

                                                    OEKEftAL AAfUNGEI«M1
                                                        PLAN
                                                     IMQ7 |   P-603   |0
Figure 10. Turbine and Boiler Buildings

-------
i  (
;;d
                 I]
                     o
                                 Jj«*C»>
-------
     The four electrostatic precipitators shown in Figure 8 are especially
voluminous, to provide the low gas velocities essential to the capture of
98.6 percent of the entrained fly ash.   Each unit is  54 feet high, 93 feet
vide, and 44 feet deep.  The entry and exits are divided in two to retain normal
flue connections.  Each unit is serviced by one induced draft fan working in the
cleaned gas leaving the unit.  The six wet gas scrubbers and reheaters then
deliver the flue gas to a single 500 foot stack.


Electrical Schematic

     Figure 12 is a single-line diagram showing major electrical equipment.
The single steam turbine-generator at. 24 kV feeds two main transformers to
500 kV and two auxiliary transformers to 13.8 kV.  A  startup transformer may
also feed the 13.8 kV bus from the 500 kV transmission line.  Major and
subsidiary buses are identified, as.well as major auxiliary electrical loads.
                                     50

-------
01
                                      Figure 12.  Major Electrical Equipment
                                                                                                       S''.:L£ LINE
                                                                                                    Reproduced from
                                                                                                    best available copy.

-------
5.  SYSTEM PERFORMANCE AND COST
Performance Integration

     Evaluation was made of plant performance on the average 59 F day with all
equipment operating at 100 percent condition with respect to its design and
specification point.  To adjust performance data so that a perfect integration
results, a detailed steam turbine heat balance had been made at the 100 percent
operating point, as presented in Figure 3,   The required 6867.4 MBtu/h from the
boiler were deemed to be provided at the exact boiler efficiency (87.1346) that
prevails with the 5 percent margin condition detailed in the boiler heat balance
(Figure 4).  Typically, boiler efficiency improves slightly at reduced firing
rates .

     In addition to the coal fired at the boiler, the rate of -coal usage for
calcining was evaluated, on the basis that  the mass flows of the wet gas
scrubber process flow diagram (Figure 7) represent operation at a 5 percent
margin above the required 100 percent level.   Table 11 presents the basis
and results for the integration into the steam cycle of boiler and wet gas
scrubber operating flow rates.                •* • '


System Output                                                            ^

     For the 100 percent operating point Tgble 12 shows that the 820 MW of
generator output was reduced to 747 MW net  plant output by the 73 MW required
for auxiliaries.  The auxiliary loss breakdown is presented in Table 13.   The
induced fan power requirement was 4 MW greater than normal as a result of the
additional 9 inch drop in water pressure in the wet gas scrubbers;  the scrubber
system itself consumes 10 MW.  All other values are typical of steam plants.
These auxiliary loads consume 8.9 percent of  the generator output in the plant.
Costs-General

     Costs were synthesized from the costs of major components, balance of
plant materials, and balance of plant labor.  An equipment list of major items
in the balance of plant was made tu assure completeness and to assure that  the
selected equipment ratings would match the extreme requirements for continuous
operation.  A detailed breakdown of balance of  plant direct labor in man-hours
and of material costs completes the identification of all items of construction
and installation costs.  To these are added indirect field labor costs and
major component costs.  An architect-engineering fee is added in proportion to
the engineering effort.  To the sum total a contingency is applied, to be
expanded on items not counted in a preliminary  appraisal such as this.  Finally,
a factor of 0.548 is added to the total for escalation and interest during
construction for the 5.5 year period.


Major Component Characteristics

     The steam generator characteristics are listed in Table 14.  The heat-
delivered efficiency of°87.1 percent would improve approximately 1.2 percent

                                    52

-------
                          Table 11

        ENERGY BALANCE—100 PERCENT RATING, 59 F DAY
    CONVENTIONAL STEAM PLANT—WET SCRUBBERS--250 F  STACK
    PARAMETER                                     VALUE

Generated Power                               819938    kW

Heat-to-Steam Cycle1                            6867.4  MBtu/Hr

HHV of Fuel Fired2                              7881.4  MBtu/Hr

Coal Fired at Boiler                          730570    pph

Coal Fired at Calciner        ,                 13810    pph

Total Coal Rate         .                      744380    pph
             t             •
Effective Boiler Efficiency                      85.52 percent
                   4
Limestone Feed Rate                           119050    pph

Scrubber Makeup Water Rate                       917 .   gpm
Notes:  1  From 100 percent steam cycle heat  balance, Figure 5

        2  Boiler Efficiency 0.871346 from heat  balance, Figure 4

        3  Based on 10788 Btu/pound higher heating value  (HHV)

        4  Rates proportioned 1/1.05 for wet  scrubber, Figure 7



                          Table 12

                       SYSTEM OUTPUT
     CONVENTIONAL STEAM PLANT-WET SCRUBBERS-250  F STACK


            Steam Cycle Output             819.9 MW

            Total Auxiliary Losses           72.7 MW

            Net Power Plant Output         747.2 MW
              (60 Hz AC-500kV)
                              53

-------
                                              Table  13

                                      AUXILIARY LOSS BREAKDOWN
                       CONVENTIONAL STEAM PLANT-WET  CIAS  SCRUBBERS-250 F STACK
ITEM
Furnace
FD Fans
PA Fans
ID Fans
ESP
Pulverizers
ASSUMPTIONS

19"
A 2"
23"
695


A P, 0.82 EFF
A P, 0.82 EFF
A P, 0.78 EFF
,000 CFM, 300 F, 0.986 EFF

NO. OF
UNITS

A
4
A
A
8
Turbine Auxiliary

Wet Scrubber

Major Pumps

  Booster
  Condensate
  Circ. Water


Water Intake

Solids Handling

"Hotel" Loads

Cooling Tower Fans

Transformers
0.33% of Gross kW
600 PSI, 6 Million #,  757, x  90%
185 PSI, 3.9 Million #,  70%  x  90%
Proportion to Cooling Heat Duty
A/E Estimate

Based on Rates and Lifts

A/E Estimate 1% of Generation

Proportional to Heat Duty

0.5% of Gross Generation
 2

 1

 1

20

 A
                                                                                                TOTAL
                                                                                                 MW
                                                                                                 7.3
                                                                                                 2.9
                                                                                                 8.8
                                                                                                 5.2
                                                                                                 7.6
                                                                                                   31.8
                                   2.8
                                                                          10.0
                                3.7
                                1.0
                                A.8
9.5

0.9

3.0

8.3

2.3

A.I
                                                                   TOTAL AUXILIARY POWER
                                                                          72.7

-------
if the flue gas were reduced iir temperature  to  250 F rather than the 300 F
level dictated by the high level of sulfur in the fuel.  The radiant surfaces in
the furnace experience a heat flux four  tints the average, while the more exten-
sive convection surfaces experience two-thirds  the average heat flux.

     The cost of $39.73 million (mid 1975) includes the air preheater, flues
and ducts,  coal pulverizers, and supporting  steel and platforms.  Exclided are
the cost of the fans which appear as balance of plant, and the 6.15 million
dollar cost of the electrostatic precipltators  with their support steel.

     Table  15 shows the cost of the steam turbine-generator at $26 million
and expresses the cost per pound and per unit of energy concerned.


Major Component and Subsystem Capital Cost

     A more detailed comparison of ultimate  costs can be made by including
the balance of plant materials and direct and indirect labor costs.  Table 16
shows such  a comparison.  The conventional steam generator with the coal ard
solids handling aggregate $85 million; the gas  cleanup comprising electrosta-
tic precipitators and wet lime scrubber  subsystem total $60 million.  The
steam turbine generator is of the order  of $30  million.

     It is  evident that comparisons based on component costs alone would.give
proportions totally different from that  for  theTtotally installed*item.  Balance
of plant equipment and costs merit a detailed evaluation.                    tr~

                                             •H--
Balance of  Plant Equipment List  °

     Specifications for balance of plant equipment are presented in Table 17
as prepared by thp architect-engineer (Bechtcl).  The specifications are based
on continuous opev ition at the valves wide open (VWO) condition for the steam
turbine flow rates.  The boiler and'wet  scrubbers have comparable margins.

     The electric motor drives for pumps and fans are sized for additional
margins of  10 percent on flow, 20 percent on static pressure rise, and approxi-
mately 30 percent on power.  All of these specifications are for equipment more
than sufficient to match the 100 percent operating condition.
Balance of Plant Capital Costs

     Table 18 presents the architect-engineer's detailed breakdown of the
direct manual field labor in thousands  of man-hours  (MH 1000' s), and of
balance of plant material cost in thousands of dollars ($1000' s) for each
major catpgory of the balance of plant.  For  the reading of these data, an
average hourly field labor rate of $11.75 in  mid-1975 dollars is used to
convert man-hours to dollars.  Where indirect field  labor is allocated to
individual items rather than the total  labor  for the job, it will be appor-
tioned as 90 percent of the direct field labor, which is equivalent to $10.58
per hour.
                                    55

-------
                                              Table  14



                                   HEAT EXCHANGER CHARACTERISTICS

                          CONVENTIONAL STEAM-WET GAS SCRUBBERS-250 F STACK

VESSEL
NO. OF SIZE OR
HEAT EXCHANGER UNITS TYPE
Steam Generator 1 130' x 90' x 282'


OUTPUT OR UNIT
DUTY PER WEIGHT
UNIT (FOB)
MBtu EFFICIENCY M LB
6867 87.1% 40.35


UNIT •
COST
(FOB)
MS
39.73



SURFACE
AREA
FT2
610,000
72,000*
538,000t

HEAT FLUX
AVERAGE
Btu/CHR FT2)
11,670
44,745*
7,247t
*Radiant Furnace Surfaces

tConvection Surfaces
                                             Table 15               .    •



              MAJOR CWS COMPONENT AND SUBSYSTEM WEIGHTS AND COSTS SUMMARY-2bO F STACK
MAJOR COMPONENT

  OR SUBSYSTEM



Prime Cycle



  Steam Turbine-Generator



    (Gener<":or Alone)



  Steam Generator
COMPONENT OR

WEIGHT
(FOB)
M LBS
SUBSYSTEM
COSTS
(FOB)
MS

OUTPUT
OR
DUTY
COST PER
UNIT
OUTPUT
OR DUTY

COST
PER
LB
  6.5



(0.940)



 40.35
26.0
39.73
819.9 MW   31.7 S/kW
        e           e


819.9 MW
4.0 $/LB
2013 MW    19.74 $/kW .   0.98$/LB
       tn            tn

-------
                                              Table 16
                         MAJOR COMPONENT AND SUBSYSTEM CAPITAL COST SUMMARY

                         CONVENTIONAL STEAM PLANT-WET SCRIJBBERS-250 F STACK
Ul

~J
MAJOR COMPONENT OR SUBSYSTEM
                       —


Fuel Handling & Preparation



  Coal an4 Solids Handling



Prime Cycle



  Steam Turbine-Generator



  Conventional Steam Generator



  Electrostatic Precipitators



  Cooling Towers



  Pumps, Heat Exchangers, Stacks



  Pipirr,, Etc.



Gas Cleanup Syste,"



  Wet Lime Scrubber"
NO. OF
UNITS
—
1
1
4
20

—
COST/UNIT
(FOB)
M$
: 	 ^
26.0
39.73 t
1.54
--
—
—
COMPONENT OR
SUBSYSTEM
COSTS
(FOB)
M$
I
26.0
39.73
6.1§
__.
r~
• . --
BOP
MATERIALS
MS
10.47
0.10
8.48
0.22
3.61
11.32
14.00
SITE
LABOR
(DIRECT -f
INDIRECT)
M$
3.21
2.68
23.1
2.34
3.17
3,48
22.33
TOTAL
INSTALLED
COST
M$
13.68
28.78
71.31
8.71
6.78
.14.80
36.33
                                                                            30.36
21.54
51.90

-------
                            Table 17 (page 1 of 4)

                       BALANCE-QF-PLANT EQUIPMENT LIST
               CONVENTIONAL STEAM PLANT WITH WET LIME SCRUBBERS
                        250 F EXHAUST GAS TEMPERATURE
Eqpt.
No.
Service Descrintion
1.0 Coal & Limestone Handling Systems
0-1
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-ll
C-12
C-13
Coal Conveyor Belt 60 in wide,
n n n M ii n
n ii ii - it n n
' " " . 42 in "
n n it n n n
ti ti n • it ti n
1! II II It II It
" " " (2 required) 30 in "
Limestone Conveyor Belt • 60 in "
i, „ .. 24 in "
n n it n it it
Limestone Bucket Conveyor " " "
Traveling Grate-Kiln 650 ton/day
340 ft long,
760 ft "
190 ft "
980 ft "
540 ft "
170 ft "
110 ft "
160 ft "
500 ft "
630 ft "
420 ft "
120 ft "
nominal lime
3000 tph
ii n
„ „
500 tph
ii n
ti it
„ „
300 tph
3000 tph
65 tph
II II
100 tph
producti<
C-14

C-15

C-16
          Syste.T. (Package)
Coal Conveyor Belt

Lime,Bucket Conveyor (2 required)

Fly Xsh Silos (2 required)
(880 ton/day design capacity),
12 ft wide x 48 ft long traveling
grate, 13 ft I.D.  x 180 ft  long
rotary kiln with Niems-type cooler.
Includes coal grinding/firing equip-
ment, control panel/inscrumentation,
all refractories and drives,  induced
draft fan, baghouse dust collector
and ducting.

18 in wide,  60 ft long, 20 tph

24 in wide, 140 ft long, 40 tph

Total Volume 833,184 ft, 80 ft
dia x 85 ft high
                                     58

-------
                            Table 17 (page 2 of 4)
Eqpt.
 No.
E-l

E-2


E-3

E-4


E-5


E-6


E-7


E-8
            Service
                                                         Description
                           2.0 Electrical Systems
Main Transformers  (2 required)

Unit Auxiliary Transformers
(2 required)

Emergency Diesel Generator

Start-up Transformer
Miscellaneous 480V
LCC Transformers  (14 required)

Boiler Auxiliary  Transformers
(2 required)

LCC Transformers  (2 required)
Scrubber Transformers
(2 required)
468 MVA, FOA, 65 C,  24/500 kV

40/54/67 MVA, 65 C,  OA/FA/FOA,
23/13.8 kV,  30,  60Hz

1000 kW, 30, 60 Hz,  480 V,  0.8  PF

28/37.5/47 MVA,  OA/FA/FOA,
500/13.8 kV, FOA, 65C,  30,  60 Hz

1689 kVA, OA, 65 C,  13.8kV/
489V/277V, 30, 60 Hz

5500 kVA, OA, 65 C,  13.8/4.16 kV,
30, 60 Hz

7000 kVA, OA, 65 C,  13.8/4.16 kV,
30, 60 Hz

5000 kVA,,OA, 65 C,  13.8/4.16 kV,
30, 60 Hz
                            3.0 Main Fluid Systems
F-l
F-2
Main  Condenser
Piping:

Circulating Water

Main Steam

Boiler Feed Water

Coal Reheat

Hot  Reheat
3.31 x 10 ft of Heat Transfer Area
Std. material.  In other respects
same as AFB but with # of tubes
scaled down in proportion to heat
transfer area.
                                              I.D. = 114    in

                                              I.D. =  15.3  in, tm = 3.97  in

                                              I.D. =  26.53 in, tm = 0.675 in

                                              I.D. =  32.54 in, tm = 1.57  in

                                              I.D. =  18.1  in, tm - 2.23  in
                                      59

-------
                          s- Table 17 (page 3 of 4)
                      Service
                                                         Description
F-3
F-4


F-5


F-6


F-7


F-8

F-9
F-10
F-ll
          LP #1
          LP #2
          LP #3
          LP #4
          IP
          H.P.
          DFT
Caters: Shell
Press/Terap.
psia/ F
5/163
11/195
20/228
67/300
29&/416
745/510
Tube
Press/Temp.
psia/ F
210/158
210/190
210/223
210/295
1040/416
5,700/519
Flow
(100%)
Ib/hr
4.05 x 10
4.05 x 10
4.05 x 10
4.05 x 10
6.22 x 10
6.22 x 10
Heat Transfer
Area
ft
14,330
13,550
13,720
18,770
45,660
49,700
                    6.22x10 Ib/hr @ 353 F
Main Condensate Pumps and.
Motors (2 required)

Feedwater Booster Pumps and   ,
Motors (2 required)

Main Boiler Feed Pumps and
Turbine Drivers (3 required)  •

Main Circulating Pumps and
Motors (3 required)  n

Cooling Towers (20 Cells)

Forced Draft Fans (2 required)
Primary Air Fans  (2 requried)
Electrostatic Precipitators
(4 required)
Vertical Ccnterline,  4250 gpm,
600 hp motor, 410 ft  TDH

7,,300 gpm, 3850 hp, 1510 ft TDH
4900 gpm, 12,600,hp, 8,300 ff TDH
82,000 gpm, 2250 hp, 75 ft TDH
246,000 gpm

Operating   971,000 cfm @ 80°F,
            S.P. = 19 in wg
Test Block.  1,165,000 cfm I? 105eF,
            S.P. - 24.7 in wg
Motor       6500 hp

Operating   161,750 cfm 
-------
                            Table 17 (page 4 of 4)
Eqpt.
 No.

F-12
F-13


F-14
 F-15
 F-16
           Service

Scrubber - Turbulent
Contact Absorber
(6 required)

Air Heater (6 required)
Induced Draft Fans
(4 required)
Forced Craft Fans for
Reheater, Air  (6 required)
Exhaust  Stack
                 Description

Each 60 ft high x 40 ft wide x 18 ft  long,
316L-S.S., neoprene lined,  3 stages,
450,000 acfra @ 312°F & 13.9 psii..

Each 4.5 ft high x 21.5 ft  wide x
37.5 ft long.

Operating   660,000 cfm @ 3CO°F,
            Total S.P. = 23 in wg
Test Block  800,000 cfm 
-------
                            Table 18 (page 1  of 8)

                     BALANCE OF PLANT ESTIMATE DETAIL FOR
                  CONVENTIONAL STEAM CYCLE-WET GAS  SCRUBBER
                                 250 F STACK
                                                 Direct Manual    Balance of
                                                  Field Labor   Plant Material
                                                  MH 1000' s       $ lOOQ's
1.0  STEAM GENERATOR (3)

     1.1  Steam Generator Erection

          Erect only (supply by others):
          includes heat transfer surface  and
          pressure parts; buckstays,  braces and
          hangers; fuel-burning equipment;  acces-
          sories; soot and ash equipment; control
          systems; brickwork, refractory  and
          insulation

     —    Supply and erec.:
          includes support steel and  access steel
          for above; miscellaneous materials and
          labor operations

     1.2  Steam Generator Auxiliaries
     Erect only  (sopply by others):
     includes fans; air preheater;  flues and
     ducts to 'jrecipitators; insulation for
     flues aid ducts; pulverizers,  feeders
     and hoppers

     Supply and erect:
     includes F.D. Fans (2 @ $390,000 ea*);
     I.D. Fans (4 @ $220,000 ea*)

1.3  Electrostatic Precipitators

     Erect only  (supply by others):
     includes electrostatic precipitat'oTs

-    Supply and erect:
     includes support steel for precipitators
*based on suppliers' verbal budgetary quotations
                                                       544
                                                  296
                                                                    6,800
                                                       185
                                                                    1,680
                                                       99
                                                1,140
                                                                      220
                                                                    __

                                                                    8,700
                                     62

-------
                            "Table 18 (page 2 of 8)
2.0  TURBINE GENERATOR (3)
                                                 Direct Manual    Balance of
                                                  Field Labor   Plant Material
                                                   MH lOOO's    	$ inoO's
          Install only (supply'by others):
          includes 835 raWe steam turbine; generator;
          exciter; auxiliary equipment; integral
          steair. and auxiliary piping; insulation;
          miscellaneous labor operations
120
                100
3.0  PROCESS MECHANICAL EQUIPMENT

     3.1  Boiler Feedwater Pumps (3)

          includes turbine-driven nain feedwater        10
          pumps and drivers (3 @ $940,000 ea.*)^
          feedwater booster pumps and motors
          (2 I? $125,000 ea.*)           '     ^

     3.2  Main Circ. Water Pumps (3)

          includes main circ. water pumps and            3
          motors (3 @ $220,000 ea.*)

     3.3  Other Pumps (3)

          includes condensate pumps and motors           5
          (2 @ $85,000 ea.*); and other pumps
          and drivers not listed elsewhere

     3.4  Main Condenser* (3)

          includes shells; tubes; air ejectors          16

     3.5  Heaters, Exchangers, Tanks and Vessels (3)

          includes l.p. feedwater heaters (4):           9
          i.p. feedwater heater; h.p. feedwater
          heater; deaerating heater and storage
          tank; miscellaneous heaters and
          exchangers; tanks and vessels

     3.6  Stack and Accessories (3)

          includes concrete stack and liner*;          113
          lights and marker painting; hoists and
          platforms; stack foundation
              3,220
                700
               650
              2,120
              3,060
              1,570
*based on suppliers' verbal budgetary quotations

                                      63

-------
                           Table 18  (page 3 of 8)
                                                       22
                                            Direct Manual
                                             Field Labor
                                              MH lOOO's

 3.7   Turbine Hall Crane  (1)

      includes crane and  accessories                 3

 3.8   Coal Handling (2)

      includes railcar dumping  equipment;           61
      dust collectors; primary  and  secon-
      dary crushing equipment;  belt scale;
      sampling station; magnetic  cleaners;
      mobile equipment; conveyors to pile;
      reclaiming feeders; conveyors to
      coal silos; coal silos

 i.9   Limestone Handling  (2)

      includes magnetic cleaners;'conveyor
      to.limestone pile;  reclaiming feeders;
      belt scale; conveyors to  calciner

3.10   Ash Handling (2)

      includes bottom ash system; fly ash           61
      handling system for precipitators and
      air preheater; ash  conveyors; ash
      storage silos (2) with  feeders,
      unloaders and foundations;  railcar
      loading equipment

3.11   Cooling Towers* (3)

      includes mechanical draft towers with         52
      fans and motors

3.12   Other Mechanical Equipment  (3)

      includes water treatment  and  chemical         30
      injection; air compressors  and auxi-
      liaries: fuel oil ignition  and warm-up;
      screenwell, miscellaneous plant equip-
      ment; equipment insulation
                                                                 Balance of
                                                               Plant Material
                                                               	$ lOOO's
                                                                      410
                                                                    5,640
1,250
                                                                    3,580
                                                                    2,230
                                                                    1,660
*based on suppliers'  verbal  budgetary quotations
                                     64

-------
                            Table 18 (page 4  of  8)
                                                 Direct Itanual    Balance of
                                                  Field Labor   Plant Material
                                                  MH lOOQ's       $ 1000's
3.13  Scrubber Ductwork (3)                        207

      includes flue gas duct outboard
      of electrostatic precipitators; duct
      lining; duct insulation; dampers and
      expansion joints

3.14  Scrubber Flue Gas Equipment (3)               27

      includes F.D. fans for flue gas reheat
      (6 @ $200,000 ea.*); air heaters for
      flue gas reheat (6 @ $280,000 ea.*)

3.15  Wet Lime SO., Scrubbers (3)                    86

 -    includes complete SO. scrubber vessels
      with presaturator ana mist eliminator
      systems (6 @ $1,000,000 ea.*)

3.16  Scrubber Lime System (3)                      66

 -    includes limestone calciner with travelling
      grate kiln ($2,700,000*); Kiln stack; coal
      conveyor, bucket elevator and storage bin
      for kiln; lime conveyor, bucket elevator
      and storage silos; lime slaker ($120,000*)

3.17  Scrubber System Pumps (3)                     10

      includes slurry recycle (18 @ $40,000 ea.*);
      mist eliminator wash (3 @ $25,000 ea.*);
      slurry storage and transfer (4 I? $4,000 ea.*);
      slurry feed (3 
-------
                            fable 18 (page 5 of 8)


                                                 Direct Manual    Balance of
                                                 Field Labor   Plant Material
                                                   MH 1000*s       $ lOOO's

4.0  ELECTRICAL (5)

     4.1  Main Transformers*                            .4           2,020

     4.2  Other Transformers* and Main Bus             17           1,280

     -    includes startup transformer; station
     *•    service transformers including those
          for scrubber system; generator main bus

     4.3  Switchf>ear and Control Centers               42           3,400

     -    includes switchgear and load centers;
          motor control centers; local control
          stations; distribution panels, relay   •**
          and meter boards

     4.4  Other Electrical Equipment           *~       363       *   2,010   ^

     -    includes, communications,,; grounding;^
          cathodic and freeze protection;
          lighting; preoperational testing

     4.5  Auxiliary Diesel Generator                     2             110

     -    includes diesel generator, batteries
          and associated d.c. equipment

     4.6  Conduit, Cable Trays, Wire and Cable        632

                                                     1,060
*based on suppliers* verbal budgetary quotation
                                    066

-------
                           Table 18  (page 6 of 8)
                                                Direct Manual    Balance of
                                                 Field Labor   Plant Material
                                                  MH lOOO's       $ 1000's
5.0  CIVIL AND  STRUCTURAL
     5.1   Concrete  Substructures and                   340           2,800
          Foundations  (1)

          includes  turbine  and  boiler building
          substructure;  coal, limestone and ash
          handling  foundations, pits and tunnels;
          miscellaneous  equipment  foundations;
          auxiliary buildings substructures;
          miscellaneous  concrete

     5.2   Superstructures  (1)                          275           7,960

    —    includes  turbine  building; auxiliary
          yard buildings; boiler enclosure

     5.3   Earthword (1)                                130          .   300

     -    includes  building excavations; coal,
          limestone and  ash handling excavations;
          circ.  water  system excavations; mis-
          cellaneous foundation excavarions;
          dewatering and piling

     5.4   Cooling Tower  Basin and  Circ. Water           90           1,380
          System (3)

     -    includes  circ. water  pump pads, riser
          and concrete envelope for pipe; cooling
          tower basin; circ. water pipe; cooling
          tower miscellaneous steel and fire
          protection

     5.5   SO- Scrubber Civil and Structural  (1)        180           3,660

          includes  foundations, earthwork and
          structures particular to scrubber
          equipment                                 	          	

                                                    1,015          16,100
                                     67

-------
                           Table 18  (page 7 of 8)


                                                Direct Manual    Balance of
          1                                       Field Labor   Plant Material
                                                  MH inOO's       $ lOOQ's

6.0  PROCESSING  PIPING AND INSTRUMENTATION

     6.1  Steam  and Feedwater Piping  (3)                81           3,850

     —    includes main s^eam; extraction steam;
          hot  reheat;  coL:i reheat;  feedwater and
          condensate large piping,  valves and
          fittings

     6.2  SO,  Grubber System Large  Piping  (3)           53           2,630

     -    includes maker-up water;  resaturation
          slurry water; mist eliminator wash;
          absorber slurry effluent  tank overflow;
          pond feed; pond recycle water; lime
          slurry piping; recycle slurry piping;
          air  heater steam supply;  air heater
          condensate return

     6.3  Other Large Piping  (3)                      231           4,050

          includes all piping, valves and fittings
          of 2-inch diameter and less

     6.5  Hangers and Misc. Labor Operations  (3)       420           1,460

          includes all hangers and  supports;
          material handling;  scaffolding; misc.
          labor operations

     6.6  Pipe Insulation (3)                          63

     6.7  Instrumentation and Ccnr-ols (5)             220

                                                     1,220
                                      68

-------
                            Table 18 (page  8 of 8)
                                                .Direct Manual    Balance of
                                                 Field Labor   Plant Material
                                                  MH IQOO's       $ 1000's
7.0  YARDWORK AND MISCELLANEOUS (1)

     7.1  Site Preparation and Improvements

     -    includes soil testing;  clearing and
          grubbing; rough grading;  finish
          grading; landscaping
   *'
     7.2  Site Utilities

     -    includes storm and sanitary sewers;
          nor.process service water-

     7.3  Roads and Railroads

     -    includes railroad spur; roads,  walks
          and parkxrg areas                 ^

     7.4  Yard Fire Protection, Fences and Gates
                                           **•-
    . 7.5  Water Treatment Pcndsr

          includes earthwork; pond lining;
          offsite pipeline

     7.6  Lab, Machine Shop and Office Equipment
 87
 27




 52

 88




	1

260
   10
   5Q




  740




  600

   20




_ 280

1,700
                                      69

-------
     The seven major categories used by the architect-engineer relate to the
principal field labor skills to be applied.  A modified subdivision of. costs
was made using the following categories:

     1.   Land improvements and structures

     .2:   Coal handling
               ;
     3.   Prime cycle plant equipment

     A..  Bottoming cycle (not applicable to this plant)

     5.   Electrical plant and instrumentation

The appropriate subdivision number for each item or major category in Table 18
is indicated after its title in parentheses.


Plant Cost Estimate               -

     The major components from Table 16 and the ttlance of plant costs appro-
priate to each of the categories of field  labor skills used in Table 18 are
combined in Table 19 to show a total of $301.62 million.

     The home office and fee of 15 percent is  applied only to the balance of
plait costs,  A contingency of 20 percent  of all prior costs is applied to
c^vc'r expected costs pot specifically included in the original estimating
process.  The tatal capital cost of $403 million represents $492/kW based on
total generation, or $540/kW on ret station output.

     A reallocation of casts according to  equipment function is presented in
Table 20.  Items 1 through 6 include everything in the preceding table.  Item 7
adds the value of escalation and interest  during the 5.5 year construction time.
This item is 55 percent of. the prior totsl.  The result is a final plant cost
of $763/KU of total generation, or SB35/.-W of  net station output.
                                  70

-------
                                              Table 19
                                    PLANT CAPITAL COST BREAKDOWN
                       CONVENTIONAL STEAM PLANT-WET H/VS SCRUBBERS-250 F STACK
                                                     COSTS  (MILLIONS OP DOLLARS)
CATEGORIES

1.0  Steam Generators

2.0  Turbina Generator

3.0  Process Mechani-.al Equipment

4.Q  Electrical

5.0  Civil and Structural

6.0  Process Piping and Instrumentation

7.0  Yardwork and Miscellaneous
COMPONENTS
45
26






71
.88'
.00

a




.88
LABOR (1) FIELD (2) MATERIALS (3) TOTAL
13.
• 1.

9.
12.
1.1.
* 14.
_3_.
65.
40
41
I
22
46
93
34
06 4
82
BOP Labor, Materials
(Sum of 1 + 2
A/E Home

Total
Office
+ 3)
& Fee
12
1

8
11
10
12
2
59
&

@
Plant Cost
Contingency C

Total
Capital
20;%
Cost
.06
.27

.30
. 21"
.73
.90
.75
.22
Indirects

15%
t
8.
0.

46.
12.
16.
18.
1.
104.
70
10

30
90
10
90
70
70
80.04
28.

63.
36.
38.
46.
7.
301.
78

82
57
76
14
51
62
229.74 .







34.
336.

50
12
67,22




403.
34

-------
                                              Table 20
                    PLANT CAPITAL COST ESTIMATE SUMMARY (APPROXIMATE-DISTRIBUTION)
                         CONVENTIONAL STEAM PLANT-WET SCRUBBERS-250  F  STACK
                                                          COSTS  (RILLIONS OF DOLLARS)
1.0  Land Improvements & Structures

2.0  Cool Handling

3.0  Prime Cycle Plant Equipment

4.0  Bottom Cycle Not Applicable

5.0  Electrical Plant 6 Inntrnmentation

       Subtotal

6.0  A-E Service d Contingency

7.0  Escalation & Interest During
       Construction
MAJOR
COMPONENTS
0
0
71.9
0
71.9





BOP
MATERIALS
. 13.2
.3.A..3'
44.3
12.9
104.7


Total
Plant
Total
SITE LABOR
(DIRECT & INDIRECT)
22.5
16.2
62.7
23.7
125.0


M$
Output MW
$/kW
TOTAL
35.7
50.5
178.9
36.6
301.6
101.7
221.0
624,3
747.2
835.4

-------
6.  NATURAL RESOURCES AND ENVIRONMENTAL INTRUSIONS

     The natural resources required for this plant are listed in Table 21.
The sorbent use is low because of the highly efficient chemical system.  The
poor coal use reflects a reduced generation due to steam diversion for
reheating and, in addition, added auxiliary power consumed in the wet gas
scrubber system and In the induced draft fans.   The water usage is mostly
for the cooling tower and is at conventional levels.

     The great land area consigned to sludge accumulation suggests that some
innovative exploitation of the sludge might reduce this  element of resource
wastage.  To a certain degree the sludge ponds  may represent an ongoing threat
to the surroundings.  Their reclamation for agriculture  or their use as a
chenical resource could offset the liability of their accumulation.

     The environmental intrusions are enumerated in Table 22.  The sulfur
emissions are three-quarters of the allowed 1,2 Ib/MBtu. This results from
90 percent capture, whereas 83 percent capture  would Just equal the limit.  The
NOjj released would be held just under the current limit  by the use of staged
combustion in firing the boiler.  The stack gas reheaters place a greater
fraction of heat rejection at the stack as compared with other plans.


Sensitivity To Emission Targets

     The chemical processes in use for wet scrubbing and for combustion do
not lend themselves to drastic changes in current emission targets.  If
the sulfur emission target were to be half the  current level  (0.6 Ib SC>2/MBtu
rather than the current 1.2 Ib S02/MBtu), the scrubbers  would increase in size
and gaseous pressure drop by a factor of 50 percent. The auxiliary power loss
in the scrubber system would tend to increase by 5 MW.   Reduction in particulate
emissions would require an increase of electrostatic precipitators of 100 percent
to reach 0.05 Ib/MBtu or half the current standard.

     The reduction of NO^. would be particularly difficult, since there is
already a burden of fuel-bound nitrogen to which the thermal  NOjj is added.
Reduction to half the current standard is not currently  deemed feasible.
                                     73

-------
                               Table 21

                    NATURAL RESOURCE REQUIREMENTS
        CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS 250 F STACK
                                                                    VALUE
Sorbent, Limestone Ib/kWh                                           0.16

Coal, Ib/kWh                                                        0.996

Water, Total (Gal/kWh)

  Cooling
  Evaporation                                                       0.56
  Slowdown                                                          0.18
  Plant General Use                                                 0.01
  Sulfur Cleanup Use                                                0.07

Total Land, Acres/100 MW

  Main Plant                                                       12.3
  Disposal Land (30 years")                                        239.0

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                               Table 22



                       ENVIRONMENTAL INTRUSION

        CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-250 P STACK
              EMISSIONS
SO
  x


NO
  x


HC



Particulates
LB/MBtu

 INPUT



 0.867



 0.65
 0.092
LB/kWh

OUTPUT



0.0093



0.0070







0.00099
         THERMAL POLLUTION  ..



He-.4:  Rejected Cooling Towers, Btu/kWh



Heat, Rejected Stack, Btu/kWh   ,



Heat, Rejected Total, Btu/kWh
               WASTES
Water Discharge



Dry Fly Ash



Sludge



LB/kWh
1.59
0.07
0.19
4188
3130
7318
M LB/DAY
28.4
1.30
3.46
                                    75

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7.  SUMMARY PERFORMANCE AND COST

     Table 23 summarizes the performance and cost for a 747 MW steam plant
using wet gas scrubbers with 250 F stack temperature.  The low overall plant
efficiency of 32 percent is due to steam diversion for stack gas reheating
and parasitic auxiliary loads imposed by the wet gas scrubbing system.  The
coal rate of 1 Ib/kVh was a typical plant value 45 years ago.  The high
plant costs are effected by the additional  costs of the scrubber system and
the reduction of net output already noted.  The net result is a cost of
electricity  (COE) of 39.8 mills/kWh, or 4 cents/kWh at the power plant
boundary.

     The sensitivity of the cost of electricity to these factors is presented
in Table 24.
                                      76

-------
                               Table 23
                     SUMMARY PE270KMANCE AMD COST
        CONVENTIONAL STEAM PLA5T-WET GAS SCRUBBERS-250 F STACK
                     ITEM


Net Power Plant Output (MW  - 6a Hz - 500 kV)


Thermodynamlc Efficiency (%)


Power Plant Efficiency (%)


Overall Energy Efficiency (%}


Coal Consumption (LB/kWh)


Total Wastes (LB/kWh)


Plant Capital Cost ($ Million)


Plant Capital Cost ($/kW )


                                          • -fr- -
Cost of Electricity, Capacity Factor = 0.65


  Capital      '                          .4,

                              n
  Fuel


•  Maintenance & Operation


  Total


Estimated Time of Construction (Years)


Approximate Date of First Comserclal Service
747.2


 40.7


 31.8


 31.8


  0.996


  0.27


624.3


835.4
(MILLS/W^h)
(MILLS/kWh)
(MILLS/kWh)
(MILLS/kWh)


26.4
10.7
2.6
39.8
5.5
1980 - 1982
                                   77

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                       Table 24

        COST OF ELECTRICITY (COE) SENSITIVITY
CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-250 F STACK
BASE
CAPACITY
FACTOR
0.65
COE,
COE,
Capital
Fuel
COE, O&M
TOTAL COE
26
10
2
39
.4
.7
.6
.8
FUEL
COST
INCREASE
50%
26.
16.
2.
45.
4
1
6
2
LABOR
COST
INCREASE
20%
28.
10.
2.
42.
7
7
6
0
MATERIALS
INCREASE
20%
2
-------
8.  ALTERNATIVE PLANT CONSIDERATIONS


SStack Gas Reheat To 175 F

     An appraisal was made for the identical  boiler and scrubber configuration
wherein the stack gas was reheated to 175 F instead of 250 F.  Table 25 indicates
those elements that were unchanged, those elements that were significantly
changed, and some details of the greatly reduced  stack gas reheat effect.   The
requirement for stack gas reheat would be reduced by a factor ef 2.5.  The reheat
energy release from air heated to 335 F would increase by a factor of 1.9.  The
combined effect reduces the heat duty on the  steam reheaters to 23 percent of
that required heretofore.

     A revised steam-turbine cycle heat balance was made to reflect these
changes.  The major changes over values found on  Figure 5 are tabulated
in Table 26.  The overall energy balance of Table 11 would be unchanged
except for the generated power.  The changes  in Table 26 and the fixed values
from Table 4 were used to reassess the auxiliary  power losses as presented
in Table 27.

     The system output as shown in Table 28 becomes 795.5 MW, an increase  of
6 percent over the previous case with 250 F stack.

     The revisions to the wet scrubber system relate entirely to the reduced
steam and air flows for the stack gas reheat.  The lower table on Figure 7
shows these details for the 175 F stack configuration.  Tables 6, 8, and 10 show
the changes in the scrubber system cost details.

     The overall plant arrangement details would  not be changed.  The increased
generation does change the size of electrical apparatus, as shown on Figure 13.

     The balance-of-plant equipment list is presented in Table 29.  The
balance-of-plant direct labor man-hours and material costs are presented in
Table 30.  These combine with the major equipment costs to determine a plant
cost of $396 million as detailed in Table 31.  Table 32 redistributes the
costs and adds on the escalation and interest during construction.  The
result is a plant capital cost of $771 per kilowatt of net plant output.


Performance And Cost—175 F Stack

     Table 33 summarizes the system performance and cost with 175 F stack  reheat,
and Table 34 compares the influence of 250 F  and  175 F stack reheat cases.  On
every measure the 175 F stack shows advantage over the 250 F stack.  The
sensitivity of the cost of electricity to the several major variables is presented
in Table 35.

     Natural resource usage and environmental intrusions would be comparable
to Table 21 and 22 values, but there would be a 6 percent reduction where
the basis was kilowatt hours.
                                    79

-------
                         fe     Table 25

        CONVENTIONAL STEAM PLANT WET GAS SCRUBBERS-175 F STACK
               FOR 175 F STACK IN PLACE OF 250 F STACK
     NOT CHANGED

       Coal Rate, Air Rate,  Gas Rate
       Scrubber Configuration
       Heat to Steam Cycle
     CHANGED

       Heat to Reheat Stack Gas
       Reheat Air Flow
       Steam to Stack Gas Reheaters
       Steam Turbine Cycle
       Generated Power
       Heat to Cooling Towers
     REHEAT EFFECTS

     Stack Gas Reheat from 125 F
     Air Heat Release fro.u 335 F
     Air and Steam Flow Ratios
       2 50 F

       125 F
        85 F
         1
                                   Table 26

                         STEAM TURBINE CYCLE CHANGES
                      FOR 175 F STACK VERSUS 250 F STACK
175JF

 50 F
160 F
0.23
RATIO

 2.5 ^
1/1.9
 4.3
        Parameter

Turbine Type

Heat to steam, cycle, MBtu/Hr

Generator output, Mv

Gross heat rate, Btu/kWh

Steara-to-gas reheater, Ib/Hr

Last stag' flow, Ib/Hr

Condersate pump flow, Ib/Hr

Heat to condenser, MBtu/Hr

Turbine cost, M$
250 F Stack

  TC4F33.5

    6867.4

    819938

   8375.54

   926,000

 2,888,123

 3,925,037

      3086

      26.0
    175 F Stack

      TC4F33.5

        6867.4

        868620

       7906.13

       213,426

     3,.472,980

     4,668,000

          3638

         2f-.75
                                 80

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                                                   Table 27

                                           AUXILIARY LOSS BREAKDOWN
                            CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-175 F  STACK
00

ITEM
Furnace
FD Fans
PA Fans
I1) Fans
ESP
Pulverizers

ASSUMPTIONS

19" A P, 0.82 EFF
42" A P, 0.82 EFF
23" A P, 0.78 EFF
695,000 CFM, 300 F, 0.986 EFF

NO. OF
UNITS

4
4
4
4
8
TOTAL
MW
e

7.3
2.9
8.8
5.2
7.6
Turbine Auxiliary

Wet Scrubber

Major Pumps

  Booster
  Condensate
  Circ. Water


Water Intake

Solids Handling

"Hotel" Loads

Cooling Tower Fans

Transformers
                              0.33% of Cross kW
                              600 PSI, 6 Million //, 75% x 902
                              135 PSI, 4.7 Million #,  70% x 90%
                              Proportion to Cooling Heat Duty
                              A/E Estimate

                              Based on Rates and Lifts

                              A/E Estimate 1% of Generation

                              Proportional to Heat Duty

                              0.5% of Cross Generation
 2

 1

 1

20

 4
                               31.8

                                2.9
                                                                                                      8.6
                             3.7
                             1.2
                             5.6
10.5

 0.9

 3.0

 8.4

 2.7

 4.3
                                                                        TOTAL AUXILIARY POWER
                                                                                                73.1

-------
                       Table 28

                    SYSTEM OUTPUT
CONVENTIONAL STEAM PLANT-WET SCRUBBERS-175 F STACK
    Steam Cycle Output                868.6 MW

    Total Auxiliary Losses             73.1 MW

    Net Powerplant Output             795.5 MW
      (60 Hz AC-500kV)
                           82

-------

OP          01

              M
                                       V
                                            fS
                                  »
1
                                                               Sea.
                                                                                     cat
                                                                                       ?EM"
-------
                            TABLE 29 (page 1 of  4)

                EQUIPMENT LIST 7OK CONVENTIONAL  STEAM CYCLE-
                          WET SLUBBERS,  175 F STACK
EQPT.
NO.

e-r
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-ll
C-12
C-13
SERVICE
1. Coal, and Limestone
DESCRIPTION
Handling Systems
Coal Conveyor Belt 60 in wide, 340 ft long,
60 in
" " " 60 in
42 in
42 in
11 42 in
" 42 in
" (2) 30 in
Limestone Conveyor Belt ' 60 in
24 in
" " " 24 in
Limestona Bucket Conveyor 24 in
Traveling Grate Kiln 650 t
" 760 ft "
" 190 ft "
" 980 ft "
" 540 ft "
" 170 ft "
' 110 ft "
" 160 ft "
11 500 ft "
" 630 ft "
" 420 ft "
" 120 ft
on/day nominal lime

3000 t, h
3000 "
3000 "
500 "
500 "
500 "
500 "
300 "
3000 "
65 "
65 "
100 "
product!'
C-14
C-15
c-ie
        System (Package)
Coal Conveyor Belt
Lime Bucket Conveyor (2;
Fly Ash Silos (2)
(880 ton; day design capacity), 12 f:_
wide x 48 ft long traveling  grate,
13 ft I.D. x 180 ft long rotary kiln
with Nieras type cooler.   Include coal
grinding/firing equipments control
panel/instrumentation, all refrac-
tories and drives, induced draft fan,
baghouse dust collector  and  ducting.
18 in wide   60 ft long    20  i ph

24 in   "   140 ft   "     40  "
Total volume 833, 184 fc3, 80  ft dia x

85 ft high
                                     84

-------
                            TABLE 29  (page 2 of 4)
EQPT.
 NO.
E-1,2

E-3,4


E-5

E-6
E-7
thru
20

E-21
& 22

E-23
& 24

E-25
& 26
          SERVICE                          DESCRIPTION

                    2.  Electrical Systems
Main Transformers  (2)
468 MVA FOA 65°C,  24/500 kV
Unit Aux. Transformers  (2)     40/54/67 MVA 65°C, OA/FA/FOA.24/13.8 kV,
                               30, 60 Hz
Emergency Diesel Gen.

Start-up Transformer
Miscellaneous 430 V
LCC Transformers  (14)
BLR. Aux. Transformers  (2)
LCC Transformers  (2)
Sci'ubber Transformers  (2)
1000 kW, 30,  60 Hz,  480 V,  0.8 PF

28/37.5/47 MVA, OA/FA/FOA,  500/13.8 kV
FOA 65CC, 3)0, 60 Hz

1689 kVA, OA, &5°C,  13.8 VV/480V/277V,
3(9, 60 HZ
5500 kVA,  OA,  65°C,  13.8/4.16 kV,
30, 60 Hz

7000 kVA,  OAS  65°C,  13.8/4,16 kV,
3d, 60 Hz

5000 kVA,  OA,  65°C,  13.8/4.16 kV,
If), 60 Hz
                            3.  Main Fluid Systems
F-l     Main Condenser

F-2     Piping

        Circ. Water
        Main Steam
        B.F.W.
        Cold R.H.
        Hot R.H.
                               3.97 :: 105 ft2 of Heat Transfer Area
                               I.D. = 123    in
                               I.D. =  15.3  in, tm = 3.97  in
                               I.D. =  26.52 in, tm = 0.675 in
                               I.D. =  32.54 in, tm = 1.57 in
                               I.D. =  18.1  in, '.m = 2.25 in
                                     85

-------
                            TABLE 29 (page 3  of  4)
EQPT.
NO.
F-3

SERVICE
Feedwater Heaters




DESCRIPTION
Shell
Tube
Press/temp Press/Temp









F-4

F-5

LP 01
LP #2
LP #3
LP #4
IP
H.P.
DFT

psia/°F
5/163
11/195
20/228
67/300
296/416
745/510 ,
6.22 x 10 .

Main Cond. Pumps and Motors
(2)
F.U. Booster Pumps

& Motors
' psia/°F
210/158
210/190
210/223
210/295
1040/416
5700/519
Ib/hr, @ 353°
•t* •
Vert. Cent.
410 ft TDH
Flow
(100?:)
Ib/hr
4.75 x
4.75 x
4.75 x
4 . 75 x
6.22 x
6.22 x
F

5100. gpm

7,300 gpm, ~3850 hp,
Heat Transfer
Area
ft
.'ID* 17,170
10^ 16,260
10° 16,600
10? 22,710
10^ 45,660
10 49,700


, 750 hp motor,

1510 ft TDH*^
        (2)

F-6     Main Boiler Feed Primps &
        Turbine Drivers (3)

F-7     Main Circ. Pumps and
        Motors (3)

F-8     Cooling Towers (23 Cells)

F-9     F.D. Fans (2)
F-10    P.A. Fans (2)
4900 gpm, 12,600 hp,  8,300 ft TDH


95,000 gpm 2500 hp, 75  ft TDH


242,058 gpm  .

Operating     971,000 cfm @ 80°F,
              S.P. =  19 in wg
Test Block  1,165,000 cfm (? 105°F,
              S.P. =  24,7 in wg
Motor           6,500 hp

Operating   161,750 cfm @ 96°F,
            S.P. inlet  in wg
            S.P. outlet = 42 in wg
Test Block  194,000 cfm @ 121°F,
            S.P. inlet  19 in wg
            S.P. outlet = 54.6 in wg
Motor       2250 hp
                                    86

-------
                            TABLE 29  (page 4 of A)
EQPT.
_NO.

F-ll
F-12



B-13


F-14
 F-15
          SERVICE

Electrostatic Precipitators
(4.)
Scrubber - Turbulent
Contact Absorber  (6)
Air Heaters  (6)
I.D.. Fans  (4)
F.D. Fans for Reheater
Air  (6)
 F-16     Exhaust  Stack (1)
             DESCRIPTION

  Each  5J  ft high x 92 ft wide x 44 ft long,
  1,262,000 Ib, 1296 kVA, 99% particulate
  removal  efficiency, 695,000 acfm 0 300°F

  Each  60  ft high x 40 ft wide x 18 ft long,
  316L-S.S,, neoprene lined, 3 stages,
  450,000  acfm @ 312°F & 13.9 psia

  Each  2.5 ft high x 18.2 ft wide x
  10.7  ft  long

  Operating   600,000 cfm I? 300°F,
             Total S.P. = 23 in wg
•  Test  Block  800,000 cfm @ 325°F,
             Total S.P. = 30 in wg
  Motor      5,000 hp

  Operating   123,000 cfm 0  80°F,
             Total S.P. = 3.5 in wg
  Test  Block  147,000 cfm @ 105°F,
             Total S.P. = 4.55 in wg
  Motor      150 hp

  27 ft I.D., 500 ft high
                                      87

-------
                            TABLE 30 (page 1 of 9)

         BALANCE OF PLANT ESTIMATE DETAIL CONVENTIONAL STEAM CYCLE—
                 WET LIME STACK GAS  SCRUBBER, 175 F STACK GAS
                                             Direct Manual    Balance of
                                              Field Labor   Plant Material
                                               MH IQOQ's       $ 1000's

1.0  STEAM GENERATOR

     1.1   Steam Generator Erection (3)

     -     Erect only (supply by others):           544
           includes heat transfer surface
           and pressure parts; buckstays,
           braces and hangers; fuel burning
           equipment; accessories; soot and
           ash equipment; control systems;
           brickwork; refractory and
           insulation

           Supply and erect:                       296          6,800
           includes support steel and
           access steel for above;
           miscellaneous materials and
           labor operations

     1.2   Steam Generator Auxiliaries (3)

           Erect only (supply by others):           185
           includes P.A. fans; air preheater;
           flues and ducts to precipitators;
           insulation for flues and ducts;
           pulverisers, feeders and hoppers

           Supply and erect:                        12          1,680
           includes F.D. Fans (?- @ $390,000
           ea*); I.D. fans (4 @$220,000 ea.*)

     1.3   Electrostatic Precipitators (3)

           Erect only (supply by others):            99
           includes electrostatic
           precipitators

           Supply and erect:                         4            220
           includes support steel for
           precipitators                         .	          	

                                                 1,140          8,700

           *based on supplier's verbal budgetary quotations

                                  88

-------
                           TABLE  30  (page 2 of 9)
2.0  TURBINE GENERATORS (3)

     -     Install only (supply by others):
           includes 835 MWe  steam turbine;
           generator;  exciter; auxiliary
           equipment;  integral steam and
           auxiliary piping;  insulation;
           miscellaneous labor operations

3.0  PROCESS MECHANICAL EQUIPMENT -

     3.1   Boiler Feedwater  Pumps (3)      :

     -     includes turbine-driven main
           feedwater pumps and drivers
           (3  @ $940,000 ea.*); feedwater
           booster pumps and motors  (2
           (? $125,000  ea.*)

     3.2   Main Circ.  Water  Pump's (3)

     -     includes main circ. water pumps
           and motors  (3 fl $235,000 ea.*)

     3.3   Other Pumps (3)

     -     includes condensaf.e pumps and
           motors (2 @ $95,000 ea.*); and
           other pumps and drivers not
           listed elsewhere

     3.4   Main Condenser* (3)

           includes shells;  tubes; air
           ejectors
                                            Direct Manual
                                              Field Labor
                                               MH 1000's
120
 10
 17
     3.5   Heaters,  Exchangers,  Tanks and
           Vessels (3)

           includes  l.p.  feedwater heaters            9
           (4):  i.p.  feed water  heater; h.p.
           feedwater heater;  deaerating
           heater and storage tank;
           miscellaneous  heaters and exchangers;
           tanks and vessels
                       &         £J

           *based on suppliers'  verbal budgetary quotations

                                  89
          Balance of
           Plant Material
            $ 1000's
  100
3,220
               750
               670
2,440
           3,160

-------
                       TABLE 30 (page 3 of 9)
                                        Direct Manual
                                         Fie?Ld Labor
                                          MH 1000's
                                               86
3.6   Stack and Accessories (3)

-   '  includes concrete stack and
      Jiner*; lights and marker
      painting; hoists and platforms;
      stack foundation
3.7   Turbine Hall Crane (1)

-     includes crane and accessories             3

3.8   Coal Handling (2)

      includes railcar dumping                 61
      equipment; dust collectors;
      primary and secondary
      crushing equipment; belt
      scale; sampling station;
      magnetic cleaners; mobile
      equipment; conveyors to pile;
      reclaiming feeders; conveyors
      to coal silos; coal silos

3.9   Limestone Handling (2)

-     includes magnetic cleaners;               22
      conveyor to limestone pile;
      reclaiming feeders; belt scale;
      conveyors to calciner

3.10  Ash Handling (2)

-     includes bottom ash system;  fly           61
      ash handling system for
      precipitators and air
      preheater; ash conveyors;
      ash storage silos (2) with
      feeders, unloaders and
     ' foundations; railcar loading
      equipment

      *based on suppliers* verbal  budgetary quotations
                                                         Balance of
                                                       Plant Material
                                                          S 1000's
1,240
                                                             410
                                                           5,640
                                                           1,250
                                                           3,580
                              90

-------
               TABLE  30  (page 4 of 9)
                                  Direct Manual     Balan^ of
                                   Field Labor   Plant Material
                                    MH 1000's
                                         60
                                         30
                                        120
3.11  Cooling Towers* (3)

-     includes mechanical draft
      towers with fans and motors

3.12  Other Mechanical Equipment (3)

-     includes water treatment and
      chemical injection; air
      compressors and auxiliaries;
      fuel oil ignition and warm-up;
      screenwell; miscellaneous
      plant equipment; equipment
      insulation
3.13  Scrubber Ductwork  (3)

-     includes flue gas duct
      outboard of electrostatic
      precipitators; duct lining;
      duct insulation; dampers and
      expansion joints

3.14  Scrubber Flue Gas Equipment (3)

      includes F.D. fans for flue gas
      reheat  (6 & $85,000 ea.*); air
      heaters for flue gas reheat
      (6 
-------
                       TABLE 30 (page 5 of 9)

                                         Direct Manual    Balance of
                                          Field Labor   Plant Material
                                           MH  lOOO's       $ JOOO's

3.16  Scrubber Lime System (3)                 66          3,660

-     includes limestone calcincr with
      travelling grate kiln ($2,700,000*);
      Kiln stack; coal conveyor, bucket
      elevator and storage bin for filn;
      lime conveyor, bucket elevator and
      storage silos; lime slaker ($120,000*)

3.17  Scrubber System Pumps, (-3)                10          1,080

-     includes slurry recycle (18 @
      $40,000 ea.*); mist eliminator    *
      wash (3 @ $25,000 ea.*); slurry
      storage and transfer (4 @ $4,000
      ea.*); slurry feed (3 @ $5,000V"
      ea.*); pond feed tank (3 @ $10,000
      ea.*); pond feed booster (21?^
      $15,000 ea.*); pond water recycle
      and booster (4 !? $f2,500 ea.*)

3.18  Scrubber System Tanks (3)                 4          2,180

      includes tanks and agitators
      for absorber effluent hold,
      pond feed, entrainment              -
      separator surge, slurry surge,
      slurry storage, slurry transfer
                                               660         43,300

      *based on suppliers' verbal budgetary quotations
                             92

-------
                           TABLE 30  (page 6 of 9)
4,0  ELECTRICAL (5)

     4,1   Main Transformers*

     4.2   Other Transformers* and Main Bus

     -    includes  startup transformer;
          station service transformers
          including those for scruhber
          system; generator main bus

     4.3   Switchgear and Control Centers
                   *
     -    includes  switchgear and load
          centers;  motor control centers;
          local control  stations; dis-
          tribution panels, relay and
          meter boards

     4.4   Other Electrical Equipment

     -    includes  communications;
          grounding; cathodic and
          freeze protection; lighting;
          pre-operational testing

     4.5   Auxiliary Diesel Generator

     -    includes  diesel generator,
          batteries and  associated
          d.c. equipment

     4.6   Conduit,  Cable Trays, Wire
          and Cable
                                             Direct Manual    Balance of
                                              Field Labor   Plant Material
                                               MH lOOO's       $ 1000's
 17
 42
363
632
2,020

1,280
3,400
2,010
              110
4,080
                                                 1,060

           *based on suppliers' verbal budgetary quotations
            12,900
                                  93

-------
                           TABLE 30  (page 7 of 9)
5.0  CIVIL AND STRUCTURAL

     5.1   Concrete Substructures and
           Foundations  (1)

     -     Includes turbine  and boiler
           building substructures; coal,
           limestone and ash handling
           foundations,  pits and tunnels;
           miscellaneous equipment
           foundations;  auxiliary buildings
           substructures; miscellaneous
           concrete

     5.2   Superstructures  (1)

     -     includes turbine  building;
           auxiliary yard buildings;
           boiler enclosure

     5.3   Earthwork (1)

           includes building excavations;
           coal,  limestone and ash
           handling excavations; circ.
           water  system excavations;
           miscellaneous foundation
           excavations;  dewatering and
           piling

     5.4   Cooling Tower Basin and Circ.
           Water  System (3)

     -     includes circ. water pump pads,
           riser  and concrete envelope for
           pipe;  cooling tower basin; circ.
           water  pipe;  cooling tower
           miscellaneous steel and fire
           protection
                                             Direct Manual
                                              Field Labor
                                               MH 1000's
340
           Balance of
         Plant Material
            $ 1000's
2,8-0
275
7,960
130
  300
105
1,680
                                  94

-------
                           TABLE 30  (page 8 of 9)
     5,5    S02  Scrubber  Civil and
           Structural  (1)

           includes  foundations, earthwork
           and  structures  particular to
           scrubber  equipment
Direct Manual
 Field Labor
  KIT lOOO's

      180
  Balance of
Pin.jt Material
   ? 1000_'.s	

    3,660
6.0  PROCESS  PIPING AND INSTRUMENTATION

     6.1   Steam and Feedwater  Piping  (3)     *

     -     includes main steam;  extiaction
           steam; hot reheat; cold  rfehtnt;
           feedwater and condensate l;:rge
           piping,  valves and fittings

     6.2   S02 Scrubber System^Large Piping  (3)

     -     includes make-up water;  resaturation
           slurry water; mist eliminator wash;
           absorber slurry affluent tank
           overflow; pond feed;  pond recycle
           water; lime slurry piping; recycle
           slurry piping; air heater steam
           supply;  air heater condensate
           return

     6.3   Other Large Piping  (3)

           includes auxiliary steam; process
           water; auxiliary systems

     6.4   Small Piping (3)

           includes all piping,  valves and
           fittings of 2-inch diameter and
           less
                                                 1,030
       81
       51
      231
      152
                 16,400
    3.S50
    2,370
     ; 050
    1,350
                                  95

-------
                           TABLE 30 (page 9 of 9}

                                             Direct Manual     Balance of
                                              Field Labor   Plant Material
                                               HH 1 OOP's    	$ 1OOP's

    6.5   Hangers and Misc. Labor                  419         1,420
          Operat'..u3 (3)

    -     includes all hangers and supports;
          material handling; scaffolding;
          misc. labor operations

    6.6   Pipe Insulation  (3)                       62           640

    6.7   Instrumentation and Controls (5)         219         4,820
                                                 1,215        18,500

7.0 YARDWORK AND MISCELLANEOUS (1) ,

    7.1   Site Preparation and Improvements         87            10

          includes soil testing; clearing
          and grubbing; rough grading;
          finish grading; landscaping

    7.2   Site Utilities                             5            50
    -     includes storm and sanitary sewers;
          nonprocess service water

    7.3   Roads and Railroads                       27           740

    -     includes railroad spur; roads,
          walks and parking areas

    7.4   Yard Fire Protection, Fences              52           600
          and Gates

    7.5   Water Treatment Ponds                     83            20

          includes earthwork; pond lining;
          offsite pipeline

    7.6   Lab, Machine Shop and Office Equipment     1           280
                                                   2tn         1,700
                                 96

-------
                                   TABLE 31

                   BALANCE OF PLANT CAPITAL COST BREAKDOWN
           CONVENTIONAL STEAM PLANT—WET GAS SCRUBBERS—175  F  STACK
                                   Costs (Millions Of  Dollars)
                                     Dirtct   Indirect
Categories

l.ft-  Steam Generators

2.0  Turbine Generator

3.0  Process Mechanical
     Equipment

4.0  Electrical

5.0  Civil and
     Structural.

6.0  l-'jocess Piping and
     Instrumentation

7.0  Yardwork and
     Miscellaneous
Components
45.88
26.75
'

-


72.63 .,
Labor(l)
13.40
1.41
7.76
12.46
12.10 ^
1«.2V
3.06
64,46
Field (2)
12.06
1.27
6.98
-11,21
10.89
12.85
2.75
58.01
Materials (3)
8.70
0,10
43.30
12.90
16.10
18.50
1.70
101.30
Total
80.04
29.53
58.04
36.57
39. M9
*^
i
45.62
7.51
296.40
                          BOP Labor, Materials & Indirects   223.2
                            (Sum of 1 +• 2 + 3)

                          A/E Home Office & Fee @ 15%      .           33.57

                            Total Plant Cost                         329.97

                            Contingency 
-------
                           Table 32

                 SUMMARY PERFORMANCE AND COST
    CONVENTIONAL STEAM PLANT—WET fiAS SCRUBBERS--175 F STACK
            ITEM

Net Power Plant Output (MW -60Hz-50QkV)               795.5

Therroodynaraic Efficiency (%,)                           A3.1

Power Plant Efficiency (%)                             33.8

Overall Energy Efficiency (%)  .    •                    33,8

Coal Consumption (Ib/kWh)                               0.936

Total Wastes (Ib/kWh)                                   0.25

Plant Capital Cost ($ Million)                        613.6

Plant Capital Cost ($/kW )                            771.3


Cost of Electricity, Capacity Factor = 0.65

     Capital                      (Mills/kWh)           24.-'>

     Fuel                         (Mills/kWh)           10.1

     Maintenance and Operation    (Mills/kWh)            2.5

     Total                        (Mills/kWh)           37.0

Estimated Time of Construction (Years)                  5.5

Approximate Date of First Commercial Service         1980-1982

-------
                               Table 33

                     SUMMARY PERFORMANCE AND COST
        CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-175 F STACK
                     ITEM

Net Power Plant Output (MW  - 60 Hz - 500 kV)

Thermodynamic Efficiency (%)

Power Plant Efficiency (%)

Overall Energy Efficiency (%)

Coal Consumption (LB/kWh)

Total Wastes (LB/kWh)

Plant Capital Cost ($ Million)
Plant Capital Cost ($/kW )
Cost of Electricity, Capacity Factor = 0.65

  Capital
  Fuel
  Maintenance & Operation

  Total

Estimated Time of Construction (Years)

Approximate Date of First Commercial Service
(MILLS/kWh)
(MILLS/kWh)
(MILLS/kWh)

(MILLS/kWh)
                    795.5

                     43.1

                     33.8

                     33.8

                      0.936

                      0.25

                    613.6

                    771.3
                                   99

-------
                           Table 34

          CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS
            INFLUENCE OF STACK REHEAT TEMPERATURE
PARAMETER

Steam to Gas Reheater, LB/HR

Generator Output, kW

Net Plant Output, kW

Ovemll Energy Efficiency, %

Capital Cost, M$

Capital Cost, $/kW

Electricity Cost, MillsVkWh

  Capital
  Fuel
  O&M

               TOTAL
250 F. STACK
926,000
819,938
747,200
31.8
624
835
26.4
10.7
2.6
175 F STACK
213,426
868,620
795,500
33.8
614
771
24.4 *7
10.1
2.5
39.8
37.0
                           Table 35

            COST OF ELECTRICITY (COE)  SENSITIVITY
    CONVENTIONAL STEAM PLANT-WET GAS SCRUBBERS-175 F STACK
BASE
CAPACITY
FACTOR

COE,
COE,
COE,

Capital
Fuel
O&M
TOTAL COE
0.
24.
10.
2.
37.
65
4
1
5
 .
42.1
LABOR
COST
INCREASE
20%
26.
10.
2.
39.
5
1
5
1
MATERIALS
CAPACITY
FACTOR
INCREASE
20%
27.
10.
2.
39.
2
1
5 .
8
0
31.
10.
2.
44.
CHANGE
.5 &
7
1
6
4'
0.8
19.8
10.1
2.5
32.4
                              100

-------
No Scrubber, 250 F Stack Alternative

     It is instructive to apply the methodology of these evaluations to a
plant In which low-sulfur coal would be burned and the wet gas scrubbing system
dispensed with.  An identical boiler would be used.   An air preheater enlarged
62 percent would bring the stack gas to 250 F as appropriate for low-sulfur
fuel.  The coal, air, and gas rates and boiler auxiliary losses would be scaled
downward 1.4 percent by the boiler efficiency improvement.  The electrostatic
precipitator would precede the air preheater, to operate on the high-temperature
low-sulfur gas stream.  The heat to the steam cycle would be unchanged.

     The steam turbine cycle would be identical with that of another system
that has been analyzed in detail as to balance-of-plant man-hour-and material
costs.  Use of the available data with the boiler and other data used with the
wet scrubber cases permitted the, synthesis of a cost breakdown and performance
on a comparable basis.

     Table 36 presents the breakdown of auxiliary losses, and Table 37 compares
the performance and costs to the wet scrubber case with 175 F stack.  The
overall efficiency would be 36,2 percent.  The cost of electricity would be
30.5 mills/kWh if the fuel cost remained at $l/MBtu.   The price of low-sulfur
coal at exact parity with the wet scrubber case (with 175 F reheat) would be
$1.68/MBtu.  A dominant plant difference would be the absence of the large
sludge ponds.  The reduced operating and maintenance cost reflects elimination
of the costs of limestone, maintenance of the wet scrubber system, and operators
for the wet scrubber system.
                                     101

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                          Table 36

                  AUXILIARY LOSS BREAKDOWN
     CONVENTIONAL STEAM PLANT-NO SCRUBBERS-250 F STACK
ITEM                              MW          SUBTOTAL MW

Furnace                                          26.S5

  FD Fans                        3.35
  PA Fans                        2.81
  ID Fans                        7.84
  ESP                            5.10
  Pulverizers                    7.45

Turbine Auxiliary                2.90

Wet Scrubbers-None               0.00

Major Pumps                                      11.07

  Booster                        3.37
  Circulating                    4.70
  Other     "                     3.00

Solids Handling                  3.00

Hotel Loads                      8.50

Cooling Tower Fans               2.80

Transformer Loss                 4.40

TOTAL AUXILIARY POWER =         59.22 MW
                             102

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                               Table 37

                            SYSTEM OUTPUT
                      CONVENTIONAL SYSTEM PI.ANTS
PARAMETER

Generator Output, MW

Auxiliary Losses, MW

Net Plant Output, MW

Output Ratio

Overall Energy EFF, %

Capital Cost, M$

Capital Cost, $/kW

Electricity Cost (COE), Mills/kWh

  Capital                     -
  Fuel
  O&M

                TOTAL
175 F :
WET SCRUBBERS
868.6
73.1
795.5
1
33.8
"•*! •
614
771
250 F
NO SCRUBBERS
883.9
59.2
8 2 A. 7
• 1.04
36.2
511
620
24.4
lO.'l
 2.5

37.0
                                                                     19.6
                                                                      9'5*
                                                                      1.4

                                                                     30.5*
*Assumes fuel cost same as for 3.9% sulfur coal ($1.00/MBtu).  Low sulfur
 coal at $1.68/MBtu would increase fuel cost such that  the total COE for
 the no-scrubber case would equal the total COE for the scrubber case with
 175 F reheat.
                                   103

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 C.  ATMOSPHERIC FLUIDIZED BSD POWER PLANT

 1.  INTRODUCTION

     The.advanced steam cycle power plant with atmospheric fluidized beds
 (AFB) achieves the functions of combustion, steam generation,  and sulfur
 capture in the four modular AFBs that replace a conventional steam boiler
 requiring wet flue gas scrubbers to remove sulfur.  A simplified cycle
 schematic is presented in Figure 14 showing the major pieces of equipment.

     The AFB corabusstor consists of four separate modules.   Each module con-
 tains seven beds stacked one on top of another as described later.  Six of
 the b';ds in each module will be primary combustion beds that burn coal.  The
 bottom bed in each .module i.s a carbon bur nup cell, fed with carbon-containing
 fly ash and bed material from the primary beds in that module.

     the system parameters are presented in Table 38.  The Illinois No. 6
 coal contains 3.9 percent sulfur.  Eighty-three percent of the sulfur must
•be captured to meet the environmental emission limit of 1.2 Ib/MBtu of fuel
 heat release.  The capture medium is limestone fed.into each of the six
 primary fluidized beds at twice the rate that would ideally capture all of
 the sulfur.*  The 1550 F main bed operating temperature was selected to
 maximize sulfur capture at 85 percent of that present in the coal.  Unburned
 carbon is conveyed from the main beds in the fly ash of the gas strean, and in
.the solids tapped from each bed.  The 95 percent of the fly ash recovered in
.cyclone separators and the tapped primary bed solids is recycled to a carbon
 burnup cell, where a higher temperature of 2000 F and increased excess air of
 30 percent produce a substantial burnup of residual combustibles.  In essence,
 the main beds release energy while capturing sulfur as calcium sulfate.  The
 carbon burnup cell releases additional energy but without  the burden of sulfur
 capture; the result is a high boiler efficiency.

     The steam ~ycle uses conventional conditions for a supercritical reheat
 steam turbine with seven feedwater heaters.  The condenser back pressure was
 chosen to optimize the total cost of electricity.

     The heat rejection system used 24 cells of mechanical draft evaporative
 cooling towers.  The net power from the plant would be 814 MW representing
 35.8 percent of the higher heating value (HHV) of the coal supplied to the
plant.
*i.e. a Ca/s ratio of 2:1.  This parameter was selected to  be consistent with
 the PFB design.  More recent data suggests that a Ca/S ratio of  2.^:1 to
 3.5:1 may be zequired for adequate sulfur capture in AFB plants,  resulting
 in increased costs.


Preceding page blank

-------
      Coal  Limestone
             L_
    Solids Handling
         FD Fans
                  Air
         ID  Fans
                  Gas
Stack
AFB
                            T
               Reheat
                                    Steam
                [HP  -HB-
                                                        IP
                                     Feedwater
                        Feed Heaters
LP
-ID-
                                                                  Condenser
                      Solids Disposal

                Figure 14. Simplified Schematic  Diagram of  Advanced Steam
                         Cycle — Atmospheric Fluidized Bed.

-------
                                   Tab.re 38

                               SYSTEM PARAMETERS
                 ADVANCED STEAM - ATMOSPHERIC FLUIDIZED BED
       PARAMETER                                     VALUE.OR DESCRIPTION

FUEL

  ILLINOIS NO.  6                                 10788 Etu/lb HIGHER HEATING VALUE
                                                       $i/MBtu 3.9% SULFUR

  LIMESTONE                                            SULFUR CAPTURE MEDIUM
                                                        0.257 Ib/lb COAL


FURNACE                                                                    .

ATMOSPHERIC  FLUIDIZED BED COM3USTOR /JJD STEAM GENERATOR (4 MODULES)

  MAIN BEDS  (6  ?ER MODULE)        ~                1550 F, COAL AND LIMESTONE
                                                 ?*- '                 *

  CARBON  BURN-UP CELL (1 PER MODULE)         '      2000 F, FLY ASH AND SOLIDS   ^
                                                              DRAIN

  EXCESS  AIR                        *                    .       20%


PRIME 'CYCLE  - STEAM PLANT

  WORKING FLUID                       '"'                 STEAM
  TURBINE INLET                                        33500 PSI, 1000 F
    REHE/.T                                               *>44  PSI, 1000 F
  CONDENSER                                              2'3" Hga. 106  F
  FINAL FEEDWATER                                        4378 PSI, 505  F


HEAT REJECTION

  WET MECHANICAL                                              2<4 CELLS
  DRAFT COOLING
  TOWERS
  STACK GAS  TEMPERATURE                                     25° F
                                     107

-------
2.  CYCLE DESCRIPTION

     A detailed plant schematic is presented in Figure  15.  State points
and stream flows are shown in which the enthalpy values are referenced to
32 F water for steam and water and to an 80 F zero  reference for air, combustion
gases, and solids.   The advanced feature of this power  system is the use of AFB
combustion to generate steam from high sulfur coal  for  a conventional steam
turbine cycle with a single reheat of the steam.


Steam Turbine-Generator Cycle

     The steam turbine is contained in four shells  connected in tandem with
a single generator.  The low-pressure stages have four  parallel flows
exhausting downward into a common condenser.  The condenser coolant is
water recirculated in a closed circuit to the evaporative cooling towers.
The regenerative feedwater heating cycle has four low-pressure feedwater
heaters, a deaereating feedwater heater, and two high-pressure feedwater
heaters.  Part of the steam exhausted from the high-pressure turbine is
used in feedwater heating, while the rest is returned to the AFB units to
be reheated to 1000 F.  Part of the steam from the  reheat turbine exhaust is
used for driving the boiler feed pump.  The exhausts from those drive turbines
are routed to the main condenser.  All other pump drives are driven by electric
motors and appear in the detailed account of auxiliary  losses.  The boiler feed
pump and its drive are an integral part of the steam cycle and are fully accounted
for in the heat balance for the steam turbine-generator.

     The final feedwater temperature is 505 F for operation at the 100 percent
point.  It is conventional practice to reference the steam and feedwater states
when a 5 percent greater steam flow exists at the valves wide open (WC)
operating point.  For that ease the feedwater would be  at 510 F.


Atmospheric Fluidized Beds

     The feedwater from the steam cycle passes first through the waterwalls
that surround the AFB cells and then in sequence through economizers located
in the gas flow above each fluidized bed.   The hot cnrbon burnup cell is last in
this sequence since, at 2000 F,  it is the hottest combustor>  Next, the fluid,
which is now steam, is Touted through primary superheaters in the gas space of
the upper three main beds and then through finishing superheaters submerged in
the upper three main beds.  Steam at 3500 psig and 1000 F is discharged to the
turbine.  Steam returned for reheat at 716 psig follows a comparable routing
through the lower three main beds.   There will be four  identical AFB modules
operating in parallel to supply the steam required to the single steam turbine.

     Each AFB module has six main beds rather than the  two shown sche-
matically in the figure.   The injection of  coal  and limestone is assisted by
the flow of primary air (PA) along with these solids.  The main airflow (A)
enters the bed in an upward flow through a  perforated distribution plate
that is the bottom  of each fluidized bed.   Most  of the  fluidized bed solids
are the residual products of the coal-air-limesrone reaction.   A continual


                                  108

-------
           14 7/59/0.7I54Z5/I0786
             Cool
                                           Cyclone ,14-63/730/698/167
                                               I (Gas 730F
                                                             Afmospher c Fluidijed
                                                             Bed Modules
                                                                                            Steam Turtint-Generolor Tandem Compound Four Flo* (I)
                                                                                                                         'Holfl' Loodl  8.8 M*
                                                                                                                         Tronslormtf Loss 4.4MW
                                                                                          Reheat  I—B—©$.
                                                                                                                                 VoleupondSefv
                                                                                                                                       19 MW
                                                                                                                    1155/106/486/745
M 7/250/8115/41
    '    i   !  Cooler   !	'	
   -intnt   •	'   (j-,    !•—   Scant
I  5e!iif»	!  !o!;3i   ;
                                                                              Ncie
            ;  s.'.o ;zi
        4.7/Z75,D 237/50
                                    'Cooler(2) i
                                     C:ol    PA
                                  Figure  15.    Schematic  Diagram  of Advanced  Steam Cycle—
                                                   Atmospheric  Fluidized  Bed

-------
tap of these solids  maintains  a  constant  bed  inventory of solids.  The bed
temperature of 1550  F results  in maximum  sulfur capture.  It is also below
the ash fusion temperature.  Most  of  the  ash  will be conveyed by the gas
stream as fly ash.   The heat exchange surfaces within the bed material
experience high overall hpac transfer rates as a result of the localized
agitation of the bed material.  In the carbon burnup cell bed the temperature
of 2000 F is too hot for use in  superheating  or reheating steam in conjunction
with the high heat transfer rates.  Only  water tubes aV_ located in the bed of
the carbon burnup cell for the purpose of in-bed fl't^d dynamic stability.

     The gases leaving the beds  must  be cooled tc 730 F for effective fly  ash
removal from the low sulfur gas  streams.   This cooling is done by heat transfer
to steam superheaters and reheaters and then  to economizer surfaces as
described above.                                                ::

     The solids fed  to the carbon  burnup  cells comprise the solids tapped
from the main beds and that portion (95 percent) of the fly ash collected
in the cyclone separators that receives the gas flowing from the main beds.
                                             •** '•

Flue Gas and Air Supply
                                           •**                 *       •
     The flue gas from the main  beds  and  from the carbon burnup cells at
730 F flow through cyclone separators that remove 95 percent of the solids
burden in the gas streams. The  hot electrostatic precipitators (ESPs) remove
the remaining fine fly ash to  rhe  level mandated by emission standards.  The hot
flue gas next passes through the air  preheater, where it is cooled to 240  F.
The induced draft (ID) fan assists in this flow and delivers .the. gas at  250 F
to the stack.

     Air tor combustion passes through the forced draft (FD) fans.   About
15 percent of that air is further  boosted in  pressure by-the primary air
fans so that it may  be used to convey solids  into the fluidized bed cells.
The main air (A) is  heated to  675  F in the air heater and is then routed to the
fluidized bed ccl^s.  The pressure rise of the forced draft fans is substan-
tially greater than  conventional practice because of the flow restrictions
imposed by the fl'iidized beds, their  perforated air distribution plates, and
the cyclone fly ash  separators.


Spent Solids Systems

     Spent solids in the form  of dry  hot  granular material are collected from
the carbon burnup cell solids  tap.  Spent solids in the form of dust are
collected from the carbon burnup cell cyclone separator and from the ESP.   The
composition of the spent solids  aggregate is  ,42 percent calcium sulfate, 24
percent unreacted lime, 31 percent  ash, and 3 percent unburnod carbon.  The
unreacted lime results from the  100 percent excess in the limestone feed rnte
as well as the fact  that the lime  is  not  100  percent effective in sulfur capture.

     Coolers are provided for  the  spent solids nnd dust to supply heated
air for the drying of c<»il and limestone.  A  small amount of coal is burned


                                   110

-------
In the  spent solids cooler to augment  this regenerative nge of the sensible
heat  in the spent  solids.
Coal and timestone  Systems

     Hot air at  750 F  from  the spent  solids system is drawn through the feed-
stock dryers and storage  silos by  the silo air  fans.  The dried coal and lime-
stone are crushed to size,  blended, and  then conveyed to the AFB main cells by
vibrating inclinod  tables.   Primary air  is use-J to assist the flow from the
tables down through the many injection needles  or  tubes in the beds.
Overview

     The fluidized main beds scavenge sulfur-,  and the  carbon burnup bed
scavenges otherwise lost combustibles from fly ash and solids discharged.
The subdivision into four modules ensures that malfunctions in a sJrgle AKB
system would not result in total plant shutdown.   The  steam turbine <:r.d its*
support systems are of proven high- reliability.
                                   Ill

-------
3.  MAJOR CYCLE COMPONENTS

     Components for steam power plants are specified for continuous operation
With flow rates 5 percent greater than the requirement for the  ICO percent
power.  Figure 15 depicts the 100 percent operating point. The major compo-
nent specifications as well as the balance-of~plant (BOP) components specifi-
cations are based on continously sustaining the 5 percent margin.  For the
steam turbine-generator this operation is at the WO condition  of the main
steam throttle control.  This customary margin in all components assures
purchasers that the entire system will not-fall below its intended pcwer
rating because of some minor inadequacy in one or more components.  The
specifications for components will generally not match exactly  the stated
performances shown in Figure 15.

     The design and performance details of the AFB modules and  the steam
turbine-generator are considered in this section.  All remaining equipment
vould be specified and supplied by an architect-engineer (AE) as BOP
materials.  Equipment lists for these itons are provided under'"System
Performance and Cost."                 •      ._.
Atmospheric Fluidized Bed Modules          '*"                *             "
                                                                         *~
     The major component of the heat input systems  is  the AFB module together
with its air supply and hot gas cleanup equipment and  the solids handling
equipment.                    <">

     In the fluidized bed combustion process, air enters a plenum at the bottom
5f the call, flows up through a grid plate that is  designed.to distribute the  :
air uniformly across the bed, passes through and fluidises the bed material
which envelops a tube bundle, exits from the bed, passes through a convection
pass tube bundle located above the bed, and exits from the cell.  Coal and
limestone are injectsd into the bed through injection  pipes that are arranged
to distribute the coal uniformly across the bed plan area.  Feeding is
continuous in order to provide steady combustion conditions.  Spent bed
material is continually drained to provide steady bed  operating levels.  The
surfaces submerged in the fluidized bed have exceptionally good heat trans-
fer characteristics.  In addition there is no coal  ash corrosion of the heat
exchange surfaces since the beds operate below the  ash fusion temperature
and provide a continuously alkaline atmosphere.  Fluidized bed combustors
require a combustion air supply syr-tem, a hot gas cleanup system for removing
particulate material entrained in the flue gas, coal and sorbent processing
and feeding systems, and a spent bed material removal  system.

     The spent bed material is alkaline and should  be  handled in a dry state.
Because of its good chemical reactiv-c/ and alkalinity, it is considered a
chemical by product of the process anu can be used  in  a number of ways.  For
example, the use of atmospheric fluidized Bed dust  has been reviewed for appli-
cation in the neutralization of acid mine runoff, the  preparation of fertilizer,
in the preparation of alkaline scrubbing solutions  for other conventional units.
Because of its concentrated iron (magnetite) and alumina ccntent it has
been considered as a fetdstock fof iron and aluminum manufacture.  Its
                                   112

-------
practical use as a feedstock for metallurgical processing will depend to some
extent on a better understanding of the chemical composition as a function of
size distribution in the solids products recovered from the fluidized bed
boiler.  Regeneration of spent bed material was not consiJered in this study
and requires further development.

     Figure 16 shows the equipment for spent bed material removal and cooling.
The spent sorbent is transported by a high-temperature  vibrating conveyer to
an air fluidized bed cooler which cools the material to disposable temperatures
of 250 to 300 F.  Heat recovered from the cooling of the spent sorbent is used
to dry the raw coal and limestone by ducting the coolers' hot discharge air to
the dryer units.  During plant startup conditions,  when hot spent sorbent is not
available, the drying units obtain their heat for drying by burning coal in
their furnace sections.

     The Hot Gas Cleanup section of Figure 16 shows the conventional cyclone
separators and ESPs that strip elutriated bed material  from the flue gases.
Solid material captured in the main bed cyclones is recycled to the 2000 F
carbon burnup cell.  Material from the carbon burnup cell that is captured in
its cyclone separator is removed and cooled by means of an air-fines cooler.
Pa.rticu.late matter captured in the ESPs is removed from the process without
cooling since the heat content of this stream is small.  It is to be noted that
"hot" precipitators at 730 F are used instead of conventional 300 F "cold"
precipitators in orde\- to ccnocusate for the low ash resistivities that are
encountered with 1ow-temperaturf, low-sulfur bearing flue gases.

     The Air Supply System utilizes forced draft (FD) and induced draft (ID)
fans to "push" and "pull" the combustion air through the system.  Primary
air boost fans are used to provide the high air pressures that are required
to inject the coal and limestone into the beds.   Regenerative air heaters are
utilized'to recover flue gas heat and preheat the combustion air; the leakage
rate was assigned as 7 percent.  This leakage rate is considered to be some-
what optimistic, but obtainable with advanced design.   If air leakage rates
of less than 10 percent cannot be economically obtained in regenerative air
heaters, the use of an extended surface tubular air heater of advanced design
is indicated for further study.

     A combustion control and safety interlock system is required.  A more
complicated control system is required with a fluidized bed boiler consisting
of four towers with seven combustion beds in each tower and the need for
blending and controlling the steam production of four towers.  Because of the
multiplicity of heat transfer circuits required in this system, a more complex
startup system and control valve arrangement is required on the water and
steam circuit,  further development is required for steam circuitry and control.
Valves and controls for the modules only are included;  items needed for a
four-tower steam blending system were omitted,

     A process flow schematic is presented as Figure 17 which summarizes the
detailed heat and mass balances made for each item of equ^ment at the design
specification point.  The schematic is for one of tour  AFB modules.
                                   113

-------
                                                 1
                                                  •    |   HOT GAS CLEANUP
                               I MATERIAL I
                               I FEEDING  I
                                                                            ,&!
                                                 \    1     «HtK»lON*1 .    l_ jf

                                               ,„,..,.>  t	1       I     | "
                                      v.«"iS t  f   —'—   i
                                      "" T  J  I          I
                                           »H  »»••««"'»«
                                          -J(H, (   «"«""•    |-
                                         SPENT BED MATERIAL
                                         REMOVAL AND COOUHG
I   AIR SUPPLY
Figure 16.  AFB Solids Handling  and Hot Gas  Cleanup Equipment
           Systems  for Two Module Trains  (Foster Wheeler)

-------
LIME
STONE
        IW
               j       J
               in ni
                                                                     Y.
             Figure 17.  Atmospheric Fluid Bed Steanf Generator — Process Flow
                      Schematic  (Foster Wheeler).

-------
     Figure 18 shows a  design concept  of  one AFB tower for steam generation.
This concept was developed to a  sufficient  level of detail to reveal all
najcr engineering problems and to permit  realistic cost evaluations.  The
unit is 12 ft x 34 ft x 180 ft tall  and weighs  800 tons in operation.  It
includes economizing, superheating,  and reheating services in the beds and in
convection spaces above the beds.  The tubes are of conventional materials, and
tube bundles were sized to be shipped  by  rail.   Fuel  is injected into the beds
through needles, each servicing  about  10  square feet  of main bed area.  The
bottom unit is the carbon burnup cell  (CBC).  There are six main cells stacked
on top of the CBC.  The air and  flue gas  duccs  taper  from bottom to top in pro-
portion to the local gas flow.  The  heat  absorption in each AFB module is
shown in Figure 19.  At the extreme  left  appear the total heat to steam for
each cell (SHS, RHS duty).  The  fluidized bed heat exchange surfaces have an
overall heat transfer coefficient of 40 Btu per hr ft^ F.  The convection
surfaces above the bed  have coefficients  one-third to one-quarter those in the
bed.  Table 39 details  the heat  exchanger surfaces shown in Figure 19.  Table 40
summarizes the basic requirement for materials  which  lead to Item 1 in Table 41
where the selling prices of the  AFB  module  are  derived from the component
weights.  The costs of  module auxiliaries are presented with the major component
equipment lists under "Plant Cost Estimates."

     The performance evaluation  for  uhe overall boiler system shows a boiler
efficiency of 87.92 percent for  he.it to steam divided by the total coal
fired.  If additional heat recovery  from  spent  solids could completely dis-
place coal burned to supplement  drying of coal  and limestone, then a boiler
efficiency of 88.46 percent would be realised.


Prime Cycle

     The major component for the prime cycle is the steam turbine-generator.
'The selected unit was a General  Electric  Tandem compound turbine with 4-flow
exhaust using 33.5-in.  last-stage buckets.   The rating wns selected to reach the
maximum allowed steam flow through the last-stage buckets at the VWO and over-
pressure condition.  This selection  is typical  of current utility purchases.
An outline drawing, Figure 20, shows the  four turbine shells and the generator
having an overall length of 173  ft.  The  performance  of the steam turbine-
generator is inseparable from many of  the BOP components that are part of the
prime cycle heat balance.  Figure 21 presents the heat balance for the 100
percent operating point for the  entire prime  cycle.   The heat-to-steam is
6286.7 MBtu/hr.  The gross efficiency  of  the prime cycle is 43.9 percent.

     The condenser back pressure of  2.3 in.  Hga resulted from an economic
optimization of the turbine and  heat rejection  system in combination.
Although the cooling tower was not a major  component, its specifications are
given in Table 42 inscfar as they impact  directly on  the steam turbine prime
cycle performance.
                                   116

-------
           h I
           9 I

Figure 18.  Advanced Steam Cycle  - Atmospheric
          Fluidized Bed  Boiler  (Foster Wheeler)
                  117

-------
 SHS  ,  RHS
 OOTY    DUTY
2M.K3
26«.l«3
212.704 |  91.439
2I2.7CH I  31.45*
 44.364 . 221.79*
 113.103
I4SI.34SO  3287170
Swp«rn«at * Riniai   •

Total Output -  1780.0820
                                                                    BTU/IB
                                                            • -Time  t
                                                            m-Ftttw milliefl !b/hf
                                                            0-m,M.3n eTU/kr
Figure  19.     Advanced Steara - PFS  Circuit  Absorption  Diagram
                                       118

-------
                                                 Table 39

                                  AFB MODULK HEAT rxCllANfiER SURFACK DATA
Cell Bank
1 El
PSII1A
PSII1B
2 E2
PS1I2A
PS112H
3 E3
PSH3A
PSK3B
4 E4
RH4
FSH4
5 E5
RH5
FSH5
6 E6
R1I6A
RH6B
7 E7A
E7B
WW

So(ftz)
12818
2136
6409
12818
2136
6409
12818
2136
6409
7477
6836
7976
7477
6836
7976
7477
6836
6409
15131
997
15209^

t)o
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
1-1/4
2
1-3/4
f
1-1/4
2
1-3/4
1-1/4
2
1-3/4
1-3/4
1-3/4
1-1/4

Ns
96
96
96
96
96
96
96
96
96
96
48
64
96
48
64
96
48
64
64
64
736

St
3
3
3
3
3
3
3
3
3
3
6
4-1/2
3
6
4-1/2
3
6
4-1/2
4-1/2
4-1/2
1-1/2

SI
1-1/2
1-1/4
1-5/8
1-1/4
1-1/4
1-5/8
1-1/4
1-1/4
1-5/8
. 1-1/4
2-1/4
2-1/4
1-1/4
2-1/4
2-1/4
1-1/4
2-1/4
2-1/4
1-3/4
2-1/4
fin

BC +
31-1/4
6-1/4
20-3/4
31-1/4
6-1/4
20-3/4
31-1/4
6-1/4
20-3/4
21-1/4
3R
37-1/4
21-1/4
38
37-1/4
21-1/4
38
28-3/4
54-1/4
4
_

Nr
12
2+
6
12
2+
6
12
2+
6
8
8
8
8
8
8
8
8
6
15+
1
1

1/1
1
2
2
1
2
2
1
2
2
1
4
4
1
4
4
1
4
6
1
1
1

Loops
6
1/2
1-1/2
6
1/2
1-1/2
6
1/2
1-1/2
4
1
1
4
1
1
4
1
1/2
7-1/2
1/2
1/2

tin/flout
(2/12
14/-
-/14
12/12
14/-
-/14
12/12
14/-
-714
12/12
1R/20
20/24
12/12
18/20
20/24
12/12
1R/20
"•4/28
12/-
-/14
14/14

0,/*I/0,
12/12/12
14/14/-
2? 10/^4/20
12/12/12
14/14/-
2fl 10/24/20
12/12/12
14/14/-
23 10/24/20
12/12/12
24/18/20/24
20/24/24
12/12/12
24/1S/20/24
20/24/24
12/12/12
24/18/20/24
24/32
12/!2/-
-/14
14/24/lf. fl 6 in
16 9 6/24/14 out
Notes:
       So  -  Installed Surface - Ft2
       to  -  Tube O.D. -  inches
       Ns  -  No. Sections wide
       St  -  Side spnclnfi - inches
       SI  -  Back spacing - inches  (staggered pitch)
       BC  -  Bundle clearance - inches  (includes one S,
       Nr  -  Number runs
       1/1-loop in loop
       Pin/Pout - header diameter inches
       0j/02/03 - Header, Tx pipe sizes - inches
extra for supports)
                                                 119

-------
                                  Table 40
HX SURFACE

El, 2,  3

E4, 5,  6

E7A, B

WW

PSH1, 2,  3

FSH4, 5

RH4, 5, 6

    E
                         AFB MODULE WEIGHT BREAKDOWN
                  RAW HEAT EXCHANGER SURFACE MATERIAL, TONS
 TONS

133.3

 77.9

 /7.8

 70.0

114.1

121.7

111.1

705.9

100
 CS

133.3

 77.9

 72.4
283.6

 40.2
                                              T2
 5.4

58.7

23.6
87.7

12.4
                                         T22
 11.3

 90.5



 77.9

179.7

 25.5
                                       T304
121.7

 33.2

154.9

 21.9
                                    120

-------
                             Table 41




              AFB MODUtE WEIGHT AliD COST BASIS MID-1975






1.  Heat Transfer Elements and Pressure Parts









2.







3.








4.









SUMMARY

1.
2.
3.
4.
5.
6.
7.



Material Tons
CS 447.6
T2/P2 183.7
T22/P22 191.5
TP304 202.1
1N601 5.2
Hast. X 1.6
1031.6
Special FBBU Items
£•
FBBU Item
Injector needles
Fluldization grilles ...;
Solids line
Solids valves

Control System

Item
Startup, steam valves 33
Combustion elements 7
Bed air dampers 7

CC & SIS (Controls, operators,

Miscellaneous Items

Item
Flues and ducts
Flue and duct insulation
Boiler lag and sheath
Backstays and braces, etc.
Misc. v-ipe, springs, joints

262.6 tons


Surfate & Pressure ?arts
FBBU Items
Control Systems and Valves
Attached Flue and Duct
Boiler Uig and Sheath
Buckstays, Braces, Hangers
1975
$/Ton
2848
3144
3774
11771
13300
24321



Tons
32.55
35.70 •*
60.00
8
135.25

1975
Rate
@ 3960
g 11000
@ 4400

etc.)


(Unit)
or Tons
330
76.5
62.5
90.0
1R.O
577.0
on botler








Miscellaneous Piping, Small Vaives,
Supports, etc.
^b &


1975
MS
1.275
.578
.723
2.379
.069
.039
5.063

1975
S/Ton
6455
6528
3300
13750



Tons
17.4
3.5
5.6


26.50

1975
$/Ton
1430
2200
080
1100
5500



'ions
1031.6
136.3
26.5
92.1
62.5
90.0

18.0
1457.0
-Controls









-
1975
M$
.210
.233
.m
.110
.751

1975
MS
.131
.077
.031
.239
.435
.724

1975
MS
.472
.168
.055
.099
.099
.893


-rl$(7S)
5.063
.751
.724
.138
.055
.099

.099
6.930
-._724
                                                       6.206
                        121

-------
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-------
                                  Table 42

                           COOLING TOWER PERFOR11ANCE
Design heat duty

Wet bulb

Condensing at 2.3 in. Kga

Hot water to  tower

Cold water return

Range

Approach

Water flow

Fan power

Pump powor

Cells
  3,$51 MBtu/hr.

     51.5  F

    105.9  F

    100,9  F

     70.2  F

     30.7  F

     18.7  F   .

250,909 gal/min

      2.78 MW

      4.73 MW
         Each cell:  36 feet long,  75 feet wide,
                     47 feet high,  1 fan
                                     124

-------
Materials of Construction

     Steam turbines operating at design steaia temperatures of 1000 F have
demonsctnted a high degree of reliability and utilize materials with
a long history of development and service.
                I

     Buckets are subjected to centrifugal forces, steam forces, vibratory
forces,.thermal stresses and erosion from wet steam.   Alloys are chosen
on the basis of strength at operating conditions, erosion and corrosion
resistanct, damping properties, and ease of machinability.  A 12 percent
Cr alloy is a typical selection.

     Turbine rotors ar.J wheels arc subjected to bucket loadings and must have
high resistance to creep ,irid rupture an! good thermal stability to resist
bowing.  The material is selected on the basis of yield,  tensile,  creep, and
rupture strenghts, translation temperature hardness and impact strength, and
its resistance to erosion and corrosion due to normal steam chemistry,  <\.i.loy
stee.ls rre typically used.

     Nozzle diaphragms must perform over a wide range of temperature and
pressure conditions and withstand steady-state thermal and pressure Jo«Hings,
differential expansion stresses, and cyclic thermal stresses.  I-  addition the
material must be fully weldable and produce sound castings.   The . tterial must
also have good creep and rupture strength and be resistant to erosicn and
corrosion.  A 12-percent Cr alloy choice ii, typical.   The high-pressure shell
or casing must contain the high-pressure steam and resist creep in longtime
•service as well as being resistant to erosion and corrosion.  Castability and
weldability are important requirements.  Alloy steels are used. Materials
for valve bodies are similar to those used for shells .ind are selected on the
same bases of creep and rupture, weldaoility, stability,  and resistance to
erosion and corrosion.

     With periodic repair and replacement of some parts,  thirty years of
operation can be expected for the turbine.  For the buckets, each  turbine
stage is analyzed for stresses and frequencies under  the specific  operating
conditions, and allowable stresses are established frori results of laboratory
testing on creep, rupture, fatigue, and erosion, corrosion resistance, and
experience.  Rotors and wheels are sized on the basis of torque, plus centri-
fugal and bending stresses, and are carefully analyzed for critical speeds.
When major parameters are established, they are analyzed in detail for
fillets, grooves, balancing provisions and contours.   Each turbine diaphragm
is analyzed for stresses, and the results of extensive laboratory  testing are
used to establish the allowable stresses.  For the shells, the analysis
starts with a pressure stress calculation and then is refined for  thermal
stresses* with stress concentrations taken into account.  The design procedure
for valves likewise analyzes for stress concentration points and provides
modifications to account for both steady-state and transient conditions.
The thermal stresses are limited by establishing allowable rates of heating
and cooling.

     In the AFB, coal combustion occurs in a bed of limestone which operates
at 1550 F.  The materials sheeted for the various temperature ranges within
                                   125

-------
the AFB at 3500 psig are carbon steel  for 850 F maximum teraperatue, 1/2 chrome-
1/2 molybdenum alloy steel (12) for  °50 F maximum  temperature, 2-1/4 chrome
alloy steel (T22)  for 980 F maximum  temperature in thick sections and 1100 F
in thin sections,  and 304 stainless  steel  (T304) for maximura temperatures of
1200 F.  At the reduced pressure of  700 psi  for reheater service T22 would be
used for 1075 F maximum and T304 for 1350 F  maximum.

     Design lifetimes are based on the ASME  Power  Boiler Code to give an esti-
mated 30-year life.   This involves assessment of tensile strength^, yield
strength, creep, and rupture strength. No detailed investigation was made
of corrosion, erosion, or fouling rates, and it was judged that conservative
procedures for selected boiler metals  would  result in the selection of metals
adequate for the projected life.  The  rationale was that internal corrosion
was not expected to  be a problem and the small amount of external oxidation,
sulfiding, and wastage would be compensated  by conservative design.  External
fouling was not considered.

     These judgnents are based on extensive  experimental data on hot corrosion
of boiler tube materials.  There is  in fact  goog reason to belie-c that corro-
sion in fiuidized bed combustion systems for the lower temperature .iteam tubes
will be rrurh less severe than 4.n conventional pulverised-coal-fired units.
However, there may be a serious corrosion problem  in the hotter components of
the system.  ._.                          •                                  *"[

     The ash particles formed at the relatively low fiuidized bed combustion
temperature are soft and friable compared with the fused ash particles
generated in the high-temperature pulverized coal  flames of a conventional
furnace.  No erosion has been reported in pilot scale tests of fiuidized bed
combustors so that this does nor appear to present a significant problem.

     Fouling on boiler tubes may become a problem,  depending on the ash com-
position of the coal, its reaction with the  bed sorbent, ana the operating
temperature.  If the problem proves  to be severe,  there may be ways of
reducing it by modifications in operating temperatures or by the use of
fuel additives.

     The steam turbine represents a  mature technology, and significant
materials problems should not be anticipated.  The fiuidized bed system
does, however, have  some potential problem areas.   The principal one is
hot corrosion, and it will be necessary to run tests for long perioc's with
a variety of coals and tube materif.Is  used over a  vide range of tempera-
tures for a more complete understanding.  There are several options to reduce
hot corrosion, including the development of  more corrosion-resistant
materials or the use of coatings.
                                    126

-------
A.  PLANT ARRANGEMENT

£lot Plan
T"    •       ,

     The plant arrangement on its \1ut is  based  on  storage of a 60-day supply
of coal and a capacity to hold ash for ]5  days.   A  series of ponds contain
runoff water from the site and provide for treatment of all water returned
to the North River.  The basic plot dimensions are  one-half mile by
three-tenths of a mile.

     Figure 22 shows the to..al plant area  of 108 acres in the small section,
and the main, area in derail.  Coal.is received by rail and is unloaded to
two conical storage piles.  .The compacted  dead storage coal pile is 60 ft
high with a base measuring about 1240 ft by 420  ft.  This stores 424,000 tons
of coal for recovery by use of dozer tractors.   Two conical live coal storage
piles are provided with a base diameter of about 315 ft.  These piles contain
a total of 114,700 tons of coal .with 27,000 ton  available by gravity feed
through under-pile vibrating feeders.  Limestone is stored in a single storage
pile of 135,000-ton total capacity with 6,7^0 tons  available as live feed by
gravity flow to the under-pile vibrating ffliers.   These feeders load a conveyor
to the coal cascade.  At that point magn tic separators remove tramp iron, ami
oversized coal is diverted to the crushers for size reduction prior to
distributioti.  The coal and the limes tor, :  are then  dried, passed through
grinders, and blended.  There are three trains of equipment from the cascade
to the delivery of dried and blende ' feedstock.   Any one of the three sets
may be out of service without disaLtin,, i.iie plant.  The feedstock is conveyed
to pairs of AFB modules on each side t..: the turbine building.  The dry and
cooled spont solids are conveyed to .the 1.5-day ash  storage bins at the lower
left for loading on railroad cars.  Tl.o 24 cells of wet cooling towers are
set apart from the rest ot" the plant in the upper right corner.


General Arrangement

     The arrangement of the four AFB modules about  the turbine building
are shown in Figure 23.  This arrangement  followed  a need to keep main
steam lines short in anticipation of use of very high steam temperatures.
The ground elevation view shows the air path through the FD fan and the air
preheater and then around the lower outside of the  AFB to the end next to
the turbine building.  The 51-ft elevation view  shows the path of the i'lue gas
through the ESP, the air preheater, and the induced draft fan, and thence to the
stack.
Plant Elevation

     The plant elevation view through the turbine building and one AFB is
presented in Figure 24.  The seven-cell stack of  fluidized beds stands
]92 ft high.  Air is fed upward from the right, and  flu.- gas flows downward
on the left side of the AFB module to the cyclone separator.  The flue gas
passes through the ESPs, the air heater, and  the  in  fan, and to the stack.
                                   127

-------
fV>
CO
                                                                     f]=:H]Tm-
                                                                       FnT^T-y. ..7~1'
                                                                                              15 ~
                                                                                              O
                                                                                              TJ
             Figure 22. riot Plan Advanced  Steam Cycle — Atmospheric Fluidj.^cd Bed  (Bechtel)

-------
vo
              •71  (•<'
                      '•  V
                      r
                    I  i
                      'I AN At M
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                                                    *-!
                                                                       --	1-- _!= -.
                                                                       iccim
                        ..^T*~-m* r "•«••>»
                        ea?|iiii./ I'H'iitf'
                 Figure 23. General Arrangement Plan Advanced Steam Cycle — Atmospheric
                         Fluidized Bed (Bechtel)

-------
HI
s:*i

           f  —
          ir-f,._
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                                                                                              t-tfjf<>t 1 U 1 IB H-l i '*IV1 T
                                                                                                iitlCLE LINf DIAGKAM
                                                                                                »l,MCH,lllAM C
                                                                          •-_J	r.
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                 Figure 24    Electrical  Diagram for Atmospheric  Fluidized  Bed System

-------
Electrical Schematic

     A single-line diagram showing major electrical equipment is presented
in Figure 25.  The steam turbine-generator  feeds two main transformers
at 25 kV, and two unit transformers  feeding the 13.8 kV buses.  A startup
transformer also may feed the 13.8 kV buses.  Major electrical loads are
indicated as well as the subsidiary  bus bars and the emergency diesel
generator.
                                   131

-------
A

f. <*.




M**»..«-.f ««
'^~P=
:2i;_-
~1r—~'



f



f
*
r



<
i



t
— c




lECITEI.
• ' . • GE'/NASA
AUVAIIUD ENfflW CONVUIGION SIUUT
Cf HI it AI.
tLtV
ADMNUO si
id
n ****
' 11107
fAMCTCit »re
w*«w^
P-.I03
MI
1
Figure 25.  General Arrangement  Ellvation — Advanced Steam
          Cycle — Atmospheric  Fluidized Bed (Bechtel)

-------
5.  SYSTEM PERFORMANCE AND COSTS

Performance

     System  performance  concerns  boiler efficiency, prime cycle efficiency,
and the fraction of  gross generation commandeered for auxiliary services.
These evaluations are made at  the 100 percent operating point and not at
the VWO specification point.   Table 43 presents the gross generation, the
auxiliary power  losses,  and the net power transmitted from the plant.  The
auxiliaries  are  7.3  percent of trie gross generation.  Table 44 gives a
detailed breakdown for the auxiliary losses.  Half of these are attributed
to the AFB module services.  The  FD fan power is four times conventional
values as a  result of the added flow path resistances for the fluidized
bed, the distribution grid plate,  and the cyclone separators.


Costs-General

     Costs were  synthesized from  major component costs, BOP material costs,
and BOP labor  costs. Items made  up of numerous smaller components are
presented by enumeration of the total cost and unit count for each of the
subcomponents.   An equipment list for, BOP components identifies all major
items.  A detailed breakdown of BOP labor man-hours and material costs com-
pletes identification of all material and construction and installation costs.
Thereafter these are combined  with major component costs to arrive at total
plant costs.

     The steam turbine-generator  is purchased at a single price of $27 million.
In contrast, the steam generator  comprises four AFB modules, .ijxiliary units
serving each AFB, conveyor and solids equipment serving pairs of AFB modules,
and solids preparation equipment  providing three units any two of which can
service the  entire plant.  Equipment lists for the AFB steam generator system
are presented  as Tables  45, 46, and 47.


Major Component  Characteristics

     Subsystem costs and weights  are presented in Table 48 for the steam
turbine-generator and for the  AFB modules exclusive of their solids
handling equipment and their ESP.

     Table 49  presents the characteristics of the AFB module heat exchange
and pressure containment parts.   The 87.92 percent efficiency represents
heat to steam divided by the HHV  of all the coal that is fired in the
plant.  The  average  heat flux  is  high compared to conventional boilers.
However, the peak heat flux is very much less than peak values for conven-
tional boilers.   As  a result of these conservative values, the AFB heat
exchange surfaces are expected to have a far longer service life than the
hottest parts of conventional  furnaces and boilers.
                                   133

-------
                               Table 43

                             SYSTEM OUTPUT
            ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
Total Gross Output (MW  - 60 Hz AC)

Total Auxiliary Losses (MW  - 60 Hz AC)
  Including Transformer Losses

Net Powerplant Output
  (MW  - 60 Hz AC - 500 kV)
                                           873.66

                                            64.40


                                           814.26
                               Table 44

                       AUXILIARY LOSS BREAKDOWN
            ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
       ITEM

Furnace
  SA Fans
  FD Fans (4)
  PA Fans (4)
  ID Fans (4)
  ESP (8)
  Solids Handling

Turbine

Auxiliaries

Major Pumps
  Service
  Booster
  Condensate
  Circ. Water
Water Intake

Solids Handling

"Hotel" Loads


Cooling Tower Fans

Transformers
          ASSUMPTIONS
       24" A P, 0.82 EFF
       65" /. P, 0.82 EFF
       16" A P, 0.82 EF7
       16" A P, 0.78 EFF
       0.33% of Gross kW
A/E Estimate
600 PSI, 5.44 Million #,  75% x 90%
185 PSI, 4.86 Million #,  70% x 90%
Proportion to Cooling
  Heat Duty

A/E Estimate

Based on Rates and Lifts

A/E Estimate 1% of
  Generation

Proportional to Heat Duty

0.5% of Gross Generation
NO. OF
UNITS
  4
  4
  4
  4
  8
  4
TOTAL
 MW
 0.8
21.1
 0.5
 5.3
 3.3
 1.4
              32.5
               2.9
2
2
2
3

2
1
1
24
4
:ARY
0.9
3.4
1.1
4.7
10.1
1.0
1.9
8.8
2.8
4.4
POWER = 64.4
                                    134

-------
                                  Table 45

               SOLIDS HANDLING FOR AFB EQUIPMENT LIST AND COSTS
               Subsystems       ,  "'

COAL DRYING & CRUSHING

1 - Dryer System - 189 TPH
1 - Coal Crusher & 2 Screens
1 - Distribution Box
2 - Vibrating Feeders @ 94-1/2 TPH
2 - Surge Bins @ 76000 ft3
2 - Bin Activators
2 - Weigh Belt Feeders 
-------
                                  Table 46

               HOT GAS AND AIR FOR AFB EQUIPMENT LIST AND COSTS


          Subsystems
                                                  Cost in     Plant Requirement
HOT GAS CLEANUP AND AIR  SUPPLY                     1975 $      Number        MS

 4 - Bed Cyclone Units                            $  392,391
12 - Cyclone Air Lock Valves                          78,000
 4 - Fines Injection  Systems                         260,000
 2 - CBC Cyclone Units                                73,060
 2 - CBC Cyclone Air  Lock Valves                      25,480
 2 - Surge Bins @ Dust Cooler                        40,404
 2 - Coolers for CBC  Dust                           260,000
 4 - Cooler Air Lock  Valves                           50,960
 4 - Electrostatic Precipitators                   2,406,103
 2 - Air Preheaters                                2,392,621
 2 - ID Fans and Motors                              881,088
 2 - FD Fans and Motors              ,                964,674
 2 - PA Fans and Motors            •                   90,813
                              Section Subtotal = $7,915,594        2       15.83


                                  Table 47

               TOWER  COMPONENTS FOR AFB EQUIPMENT LIST ANT) COSTS


          Subsystems                                           Plant Requirement
             Items                                  M|        Number        M$

Heat exchange and pressure parts                   5.063

Injector and air parts of AFB                     0.781

Control system                                    0.724

Flues, ducts, insulation, etc.                     0.893
                                                  7.461         4          29.84

Total for modules without solids handling                        4          45.67

Total above without electrostatic percipitator-                  4          40.86
                                    136

-------
                                    Table 48

             'MAJOR COMPONENT AND  SUBSYSTEM  WEIGHTS  AND COSTS SUMMARY
                    ADVANCED STEAM-AT.IOSPHERIC FLUIDTZED BED
      MAJOR COMPONENT
        OR SUBSYSTEM

 Prime Cycle

   Steam Turbine-Generator

     (Generator  Alone)

   AFB Module


WEIGHT
(FOB)
M LB
COMPONENT OR
SUBSYSTEM
COSTS
(FOB)
MS


OUTPUT
OR
DUTY

COST PER
UNIT
OUTPUT
OR DUTY


COST
PER
LB
          6.5

         (0.940)

          3.54
       27.0
       10.2
       878.66MW    30.73$/kW    4.15$/LB
                  878.66 MW
       500.3 MW
                                                            'th
20.39S/kW ,   2.88$/LB
         th
                                     Table 49

                          HEAT EXCHANGER CHARACTERISTICS
                 ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
            NO.  OF
VT EXCHANGER   UNITS

AFS Module
   VESSEL
   SIZE OR
    TYPE

76'x33'xl78'
OUTPUT OR
DUTY PER
  UNIT
  MBtu   EFFICIENCY
          UNIT    UNIT    UNIT
         SURFACE  WEIGHT   COST
          AREA    (FOB)   (FOB)
                  M LB
  1707
87.92%   160726   3.54
                 HEAT
                  FLUX
                AVERAGE
        M$   Bcu/(HR FT2)
       5.1*
10620
at exchange surfaces  and pressure parts only.   An adc* :tional  $5.1  M is required  for other
dule components  for a total of $10.2 M per module (see Table  48).
                                         137

-------
Equipment List-Balance of Plant

     The BOP equipment and its specifications are listed in Table 50.  The
specifications are based on VWO  steam  turbine flow rates.  In addition,
electric motor drives for fans and  pumps anticipate a further margin of
10 percent flow,  20 percent pressure rise, and  30 percent power.  As a
result,  the motors are sized for continuous duty  at levels well above the
100 percent plant operating.point.


Capital Costs-Balance of Plant               .

     Table 51 presents the AE's  detailed breakdown of the direct nuinual field
labo*r in thousands of man-hours, and of BOP material costs in thousands of
dollars for each major category  of  the balance  of plant.  In using :these data,
an average hourly field labor rate  of  $11.75 in mid-1975 dollars converts man-
hours to dollars.  Where field indirect labor is  allocated to individual iter.;s
rather than the total labor for  the job, it will  be apportioned as 90 percent of
the direct field labor, which is equivalent to  $10.58 per hour. .

     The seven major categories  used by the AE  relate to the principal field
labor skills to be applied.  A^modified subdivision of costs was.made using
th? following categories:                   ^

     1.  Land improvements and structures
                                          ;^--
     2.  Coal handling         r,

     3.  Prime cycle plant equipment

     4.  Bottoming cycle (not applicable to AFB plant)

     5.  Electrical plant and instrumentation

Each item or major category in Table 51 has indicated after, its title in
parentheses the appropriate secciid  category from  the preceding list.


Plant Cost Estimates

     The installed costs of major, system components are presented in Table 52.
Those elements related to heat release—th.i coal  and solids handling equipment,
the AFB furnace modules, and the ESPs^-represent  a total of $100 million.  The
steam turbine-generator along with  its feedwater  heaters and pumps is half
that amount.

     The total plant costs using the AE's categories are presented in Table 53.
The home office and fee of 15 percent  is applied  only to the BOP costs.  A
contingency of 20 percent of all prior costs, is applied to cover expected costs
not specifically included in the original estimating process.  The tolal plant
cost of $332 million represents  $378/kW based on.total generation, or $408/kW
based on net station output.
                                   138

-------
                                  Table 50
                      BALANCE-OF-PLANT EQUIPMENT LIST
              ADVANCED STEAM PLANT, ATMOSPHERIC FLUIDIZED BED
EQPT.
 NO.
_,.  • '

C-l

C-2

C-3

C-4

C-5

C-6

C-7

C-8

C-9
         SERVICE
 Coal  Conveyor Belt
 Limestone Conveyor Belt
 Feed Cascade System:

 2 Conveyor Belts

 •j    ti       it

12    "       "

18 Bucket Elevators

 2 Conveyor Belts

 3    
-------
                             Table 50 (page 2 of
EQPT.
 SO.

C-10
C-ll


C-12

C-13


C-14

C-15


C-16

C-17


C-18


C-19


C-20


C-21
            SERVICE.

Ash Residue Removal System:

2 Conveyor Belts

1    "     Belt
Six Vibrating Feeders   ~
for Car Unloading

Coal Belt Scale

Coal and Limestone Sampling
System

Coal Lump Crusher (3 req'd)

Limestone Lump Crusher
(3 req'd)
                                             DESCRTPTtON



                                24 in wide,   600  f'flcng,  64 tph

                                36 in   "   1840  ft    "   12S  "

                                 "      »    420  ft . *  "    "   "

                                Rating 0-750 tph


                                0-300t) tph,  60  in Belt

                                0-3-000 tph,  60  in Belt
                                     tph,  10  in  Lumps

                                0-10 tph,  10  in  Lumps
Magnetic Coal Cleaner (3 req'd) 500 tph

                                125 tph
Magnetic Limestone Cleaner
(3 req'd)

Coal and Limestone Dust
Control System
C0? Fire Protection Systen
Vibrating Feeders for
Limestone Pile  (4 req'd)

Vibrating Feeders for
Coal Piles  (8 req'd)
C-22   Ash Storage Silos (6 req'd)


C-23   Eight Coal Silos

C-24   Two LimestonejSilos     0
                                4-6000 cfra Bag Type Dust Collector
                                Adequate to Service  Item  C-1S
                                Bag-house

                                0-100 tph
                                0-200 tph


                                Total Volume 2,206,300  ft
                                80 ft dia x 75 ft  high

                                375 ton each

                                325 ton each
                                  140

-------
                             Table 50 (page 3 of 4)
EQPT.
 NO.
            SERVICE                          DESCRIPTION

                      2.  Electrical Svstems
E-l    Main Transformers (2 req'd)      470 MVA, FOA 65°C, 24/500 kV, 30, 60 Hz
E-2    Unit Auxiliary Transformers


E-3    Emergency Diesel Generator

E-4    Start-up Transformer
E-5    Miscellaneous 480 V
       LCC Transformers
       (17 req'd)

E-6    4.16 kV Boiler Auxiliary
       Transformers (2 req'd)

E-7    4.16 kV LCC Transformers
       (2 req'd)
                                27/36/45 MVA,  65°C, OA/FA/FOA, 24/13.8 kV,
                                30,  60 Hz

                                1000 kW, 30, 60 Hz, 480 V, 0.8 PF

                                20/26.5/33 MVA, OA/FA/FOA, 65°C,
                                500/13.8 kV, 30, 60 Hz

                                1680 kVA, OA,  65°C, 13.8 kV/4fiOV/277V,
                                30,  60 Hz
                                4000 kVA,  OA,  65°C, 13.8/4.16 kV,
                                30,  60 Hz

                                5500 kVA,  OA,  65°C, 13.8/4.16 kV,
                                30,  60 Hz
                            3.   Main Fluid Svptems
F-l
Main Condenser
F-2    Piping:
       Circulating Water
       Main Steam
       Boiler Feedwater
       Cold Reheat
       Hot Reheat
4.05 x 10  ft  heat exchange  surface.
Design conditions,  2.3 in Hg,  106°F,
3.58 x 10  Ib/hr.   Two shells;  each
25 ft wide, 20 ft  high,  and 40 ft  long
with 40,500 1-in tub s:   straight-
through, single pass u •'sign,  range of
circulating water  = 30.7 v.
                                I.D.  « 130   in
                                I.D.  =   7.5  in, tra = 1.95  in
                                I.D.  =  13.0  in, tm = 1.3   in
                                I.D.  =  13.0  in, tm = 0.345 in
                                I.D.  «  16.0  in, tm = 0.18  in
                                   141

-------
                             Table 50  (page 4 of A)
EQPT.
 NO.

F-3
                   SERVICE
                                                    DESCRIPTION
F-4


F-5


F-6


F-7


F-8

F-9
Feedwater Heaters



LP #1
LP 92
LP #3
LP #4
LP
H.P.
DFT
Shell
Press. /Temp.
psia/8F
5/163
11/195
20/228
'. 67/300
296/416
745/510 ,
6.04 x 10
Tube.
Press. /Temp.
psia/°F
210/158
210/190
210/223
210/295
1040/416
5700/519
Ib/hr, 
-------
                            Table 51 (page 1 of 7)

                    BALANCE-OF-PLANT ESTIMATE DETAIL
            ADVANCED STEAM PLANT, ATMOSPHERIC FLUIDIZED BED
                                                 Direct Manual
                                                  Field Labor
                                                   MH 1000's
        Balance of
      Plant Material
         $ 1000's
14)  AFB STEAM GENERATORS (3)

     1.1   Steam Generator Erection

     -     Evect only (supply by others):
           includes heat transfer surface, and
           pressure parts; buckstays; braces and
           hangers; attached flue and duct;   ^
           fluid bed components; control equip-
           ment and valves; miscellaneous piping
           and small valves; insulation for^above

     -     Supply and erect:
           includes support steel for abov'e;
           access steel; miscellaneous materials
           and labor'operations

     1.2   Steam Generator Auxiliaries

     -     Erect only (supply by others):
           includes P.A. fans; F.D. fans;  T.D.
           fans; air preheators; coal and lime-
           stone feed tables; pipes and air  lock
           valves

     —     Supply and erect:
           includes external flue and duct;  sup-
           port steel for ductwork; insulation
           for external ductwork

     1.3   Stack Gas Cleanup:

           Erect only (supply by others):
           includes cyclones and electrostatic
           precipitators

     -     Supply and erect:
           includes support steel for cyclones
           and precipitators
NOTE:  ( ) Indicates NASA categories;  seo Section  3

                                   143
343
158
3,020
 70
  100
198
2,570
 82
 14
  610
                                                         865
           6,300

-------
                            Table 51 (page 2  of  7)
2.0  TURBINE GENERATOR (3)
           Install only (supply by others):
           includes 883 MWe steam turbine;
           generator; exciter; auxiliary equip-
           ment; integral steara and auxiliary
           piping; insulation; miscellaneous
           labor operations
                                                 Direct Manual    Balance of
                                                  Field Labor   Plant Material
                                                  MH 1000's        S 1000's
130
100
3.0  PROCESS MECHANICAL EQUIPMENT (3)
             t
     3.1   Boiler Feedwater Pumps

           Supply and install:  •                        10
           includes turbine-driven main feedwater
           pumps and drivers  (3 (3 $940,000 ea.);
           feedwater booster pumps and motors
           (2 @ $125,000 ea.)

     3.2   Main Circ. Water Pumps (3)

           Supply and install:                           3
           includes main circ. water pumps
           and motors (3 
-------
Table 51 (page 3 of 7)
                                            Direct Manual
                                             Field Labor
                                             MH lOOQ's

3.6   Stacks and Accessories (3)

      Supply and erect:                            110
      includes concrete stacks and liners;
      lights and marker painting;  hoists
      and platforms; stack foundations

3.7   Turbine Hall Crane (1)

      Supply and erect:                              3
      includes crane and accessories

3.8   Coal Handling (2)

      Erect only (supply by others):               22
      includes coal dryers (3); support
      and access steel f"r dryers; coal
      grinders (3); screens at grinders

      Supply and erect:                             73
      includes railcar dumping equipment; dust
      collectors; primary crushing equipment;
      belt scale; sampling station; magnetic
      cleaners, mobile equipment;  conveyors  to
      pile; reclaiming feeders; conveyors to
      cascade; coal cascade; conveyors and
      bucket elevators to dryers and grinders;
      recirculating conveyors at grinders;
      conveyors to blenders

3.9   Limestone Handling (2)

      Erect only (supply by others):               11
      includes limestone dryers (3);
      support and access steel for dryers;
      litnastone grinders (3); screens at
      grinders; limestone surge bins at
      AFB modules

-     Supply and erect:                             45
      includes magnetic cleaners;  conveyor to
      limestone pile;  reclaiming feeders; con-
      veyers to cascade; limestone cascade;
      conveyors and b-jcket elevators to dryers
      and grinders; recirculating  conveyors  at
      grinders; conveyors to blenders; pneumatic
      transport feeders, hoppers,  blowers and
      piping to AFB modules
                                      Balance of
                                    Plant Material
                                       $ 1000's
                                        1,700
                                          420
                                           10
                                        5,700
                                           10
                                        1,160

-------
                       Table 51 (page 4  of  7)
                                           Direct Manual    Balance if
                                            Field Labor   Plant Material
                                             MH  lOOO's       $ 1000's
3.10  Coal and Limestone Blend Handling (2)

      Erect only (supply by others):
      includes blenders (3); surge bins;
*•     bin unloaders and feeders

-     Supply and erect:
      includes conveyors and bucket elevators
      to AFB modules

3.11  Spent Solids Handling (2)
                                    ..'       .&
-     Erect only (supply by others):
      includes high temperature vibrating
      feeders and conveyor to solids cooler;
      solids cooler

      Supply and erect:                "*"'
      includes fly ash handling system for
      precipitators and air preheater;  solids
      cooler accessories and bucket elevator;
      ash conveyors; ash storage silos (6) with.
      feeders, unloaders and foundations; railcar
      loading equipment

3.12  Cooling Towers (3)

      Supply and erect:
      includes mechanical draft towers with
      fans and motors

3.13  Other Mechanical Equipment (3)

-     Supply and install:
      includes water treatment and chemical
      injection; air compressors and auxiliaries;
      fuel oil ignition and warm-up; screenwell;
      miscellaneous plant equipment; equipment
      insulation
13
93
63
30
               10
  920
               10
4,480
2,680
1,720
                                                              29,400
                                146

-------
                            Table  51  (page  5 of 7)


                                                Direct Manual    Balance of
                                                 Field Labor   Plant Material
          '   '                                   __Mti lOOO's       $ IQOO's

4.0  ELECTRICAL (5)

     4.1  Main Transformers                             4          2,030

     4.2  Other Transformers and  Main Bus               15          1,160

     -    includes  startup transformer;  station
          service transformers; generator  main bus

     4.3  Switchgear and Control  Centers               37          3.020

     -     includes  switchgear and load centers;
          motor control centers;  local control
           stations; distribution  panels, relay
          and meter boards       : ." '.

     4.4  Other Electrical Equipment                  428          2,400

     -     includes  communications, grounding;
           cathodic  and freeze protection;  lighting;
           preoperational testing

     4.5  Auxiliary Diesel Generator                    2            110

           includes  diesel generator,  batteries
          and associated d.c. equipment

     4.6   Conduit,  Cable Trays, Wire and Cable         564

                                                     1,050


5.0  CIVIL AND STRUCTURAL

     5.1   Concrete Substructures  and
          Foundations (1)                             350          2,890

           includes  turbine building  substructure;
          "AFB base mats; coal, limestone and  ash
           handling foundations, pits and tunnels;
          miscellaneous equipment foundations;
           auxiliary buildings substructures;
          miscellaneous concrete
                                    147

-------
                           Table 51 (page 6 of 7)
                                                Direct Manual    Balance of
                                                 Field Labor   Plant ftaterial
                                                  HH lOOO's       $ 1000's
    5.2   Superstructures  (1)

    -     includes turbine building; auxiliary
          yard buildings

    5.3   Earthwork  (1)

    -     includes building excavations; coal,
          limestone  and ash handling excavations;
          circ. water system excavations; AFB
          foundation excavations; miscellaneous
          foundation excavations; dewatering and
          piling

    5.4   Cooling Tower Basin and Circ. Water
          System  (3)

    -     includes circ* water pumps pads, riser
          and concrete envelope for pipe; cooling
          tower basin; circ. water pipe; cooling
          tcwcr miscellaneous steel and fire
          protection

    5.5   AFB Boiler Enclosures  (1)

    -     includes structural steel; noninsulated
          walls and  roofing; building services;
          elevators
230
135
6,540
  300
115
1,800
 55
2,170 '
                                                       885
            13,700
6.0  PROCESS PIPING AND INSTRUMENTATION

     6.1   Steam and  Feedwater Piping  (3)                55

           includes main steam;  extraction steam;
           hot  reheat;  cold  reheat; feedwater and
           condensate large  piping, valves and
           fittings

     6.2   Other Large  Piping (3)                       165

           includes auxiliary steam; process
           water;  auxiliary  systems
             2,680
             2,670
                                    148

-------
                           Table 51  (page 7 of 7)
                                                Direct Manual    Balance of
                                                 Field Labor   Plant Material
                                                  MH lOOO's       $ lOOO's

     6.3    Small Piping  (3)                              85            760

           includes all  piping, v.alves and
           fittings of 2-inch diameter and less

     6.4    Hangers and Misc. Labor Operations (3)       245            920

     -      includes all  hangers and supports;
           material handling; scaffolding; misc.
           labor operations      L. •         •

     6.5    Pipe Insulation  (3)                           40

     6.6    Instrumentation and Controls  (5)             115

                                                       750   '
7.0  YARDWORK AND MISCELLANEOUS  (1)

     7.1    Site Prepatation and  Improvements             38 ,           10

     -     includes  soil  testing; clearing and
           grubbing;  rough grading; finish
           grading;  landscaping

     7.2    Site Utilities                                5            50

           includes  storm and sanitary sewers;
           nonprocess service water

     7.3    Roads and Railroads                           27            750

           includes  railroad spur; roads, walks
           and  parking areas

     7.4    Yard Fire Protection, Fences, and Gates       52            600

     7.5    Water Treatment Ponds                         12        '    10

           includes  earthwork; compacted-clay
           lining; offsite pipeline

     7.6    Lab,  Machine Shop and Office Equipment	1            280

                       0,         e>                     135          1,700

                                   149

-------
                                              table 52

                         MAJOR COIfPONENT AND SUBSYSTEM  CAPITAL COST SUMMARY
                              ADVANCED STEAM-ATMOSPHbRlC FLUIDIZED BED
MAJOR COMPONENT OR SUBSYSTEM

Fuel Handling & Preparation

  Coal and Solids Handling

Prime Cycle

  Steam Turbine-Generator
  AFB Furnace Modules
  Electrostatic Precipitators
  Cooling Towers
  Pumps, Heat Exchangers, Stacks
  Piping, etc.
        COST/UNIT
NO. OF    (FOB)
 UNITS     M$
  3/2
COMPONENT OR
  SUBSYSTEM
    COSTS        BOP
    (FOB)    -MATERIALS
     M$          MS
    9.45
13.10
                                                                               SITE
                                                                               LABOR      TOTAL
                                                                              (DIRECT +  INSTALLED
                                                                              INDIRECT)    COST
            MS
5.96
            M$
28.51
1
4
8
--
—
—
27.0
10.216
1.203
—
—
—
2 7.'00 •
40.815
4.81
—
—
—
0.10
5.69
0.61
4.48
11.48
9.18
2.90
17.17
2.14
3.97
3.62
11.84
30.00
63.72
7.56
8.45
15.10
23.02

-------
                                                 Table 53
                                   BALANCE OF PLANT CAPITAL COST BREAKDOWN
                               ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
                                                        COSTS  (MILLIONS OF DOLLARS)
    CATEGORIES

    1.0  Steam Generators

    2.0  Turbine Generator

    3.0  Process Mechanical Equipment

    4.0  Electrical
M
M   5.0  Civil and Structural

    6.0  Process Piping and Instrumentation

    7.0  Yardwork and Miscellaneous
COMPONENTS LABOR (1) FIELD (2) MATERIALS (3)
45.68 10.16 9.15 6.30
27.00 1.53
9.45 6.17
12.34
10.40
8.28
1.59
82.13 50.47
BOP Labor, Materials
(Sum of 1 + 2 + 3)
A/E Home Office & Fee
Total Plant r^st
Contingency 0 20%
Total Capital Cost
1.37
5.55
11.10
9.36
7.46
1.43
45.42
& Indlrects
0 15S
0.10
29.40
12.30
13.70
10.10
1.70
73.60
169.49

TOTAL
71.29
30.00
50.57
35.74
33.46
?5.84
4.72
251.62

25.42
277.04
55.41
332.45

-------
     A reallocation of costs according  to equipment functions is presented in
Table 54.   Items 1 through 6 include everyj-hing in the preceding table.   Item
7 adds the value or escalation and  interest during the 5.5-year construction
time.  This item is 55 percent of the prior total.  The result is a final
plant cost of $586/kW of total generation or  $632/kW of net station output.
                                    152

-------
                                              Table 54

                   PLANT CAPITAL COST ESTIMATE SUMMARY (APPROXIMATE DISTRIBUTION)
                           ADVANCED TTEAM CY^LE-ATMOSPHERIC FLUIDlZED BED
1.0  Land Improvements & Structures

       (Land, Plant Area 108 Acres)
       (Land, 30-year Dispoal 0 Acres)

2.0  Coal Handling

3.0  Prime Cycle Plant Equipment

       Steam Cycle Atmospheric Fluidized Bed
       878.7 MW
               e

4.0    Bottom Cycle not Applicable

5.0  ^Electrical Plant & Instrumentation

      Subtotal

6.0  A-E Service & Contingenty

7.0  Escalation & Interest during
       Construction
MAJOR
COMPONENTS
M$
0
9.5
72.7
0.
82.2





BOP SITE LABOR
MATERIALS (DIRKCf & INDIRECT)
M$ M$
14.0 * 20.3
13.1 6.0
31.5 43.6
14.9 26.0
73.5 95.9


Total M$
Plant Output MW
Total $/kW
TOTAL
M$
34.3
28.6
147.9
40.9
251.7
80.8
182.2
514.7
814.3
632.0

-------
  6.  NATURAL RESOURCES & ENVIRONMENTAL INTRUSIONS

       The natural resourced required for this plant are presented in. Table 55.
  Total water withdrawal vould be 0.6!  gal/kWh,; with 0.16/ga.l/kWh i-eturned from
  cooling Cower b^wdown and plant' general use after appropriate waiter treatment.
  The coaJ urage r>lates directly to bc.il   efficiency, steam turbine cycle
  efficiency, and cho proportion of generated power diverted for auxiliary
  requirements.  The-coal usage ;ould be less, and the plant could be marie
  more efficient if the constraint to produce electricity at the least cost
  was removed.

       The environmental intrusions are enumerated in Table 56.  The sulfur
*• emissions assumad by GE are comfortably under the current limit, while the
  nitrogen oxide emissions are less than half the current standard.  The major
  heat rejection is from the cooling tower.  The total heat- rejected includes
  the stack loss, loss from hot spent solids, and in-plant thermal, energy from •
  motors and other auxiliaries.

       The spent solids contain appreciable amounts of unreacted lime as a     ••
  result of 100 percent excess of limestone *feed and the 15 percent of sul-
  fur that is not reacted.  There are economic incentives to consider on-site(
  recycling of the spent solids to separate the sulfur and recycle the lime.
                                                                       if-

  Sensitivity to Emissions Target.i

       The estimated emissions from the atmospheric fluid bed are within existing
  EPA New Source Performance Standard limitations for conventional coal-fired
  boilers.

       One of the features expected for fluid bed combustion is verv low. wulf-v<-
  trioxid* generation.  Coal end corrosion problems due to sulfur trioxide
  severely limit conventional furnace design and operation.  The A^B po*.'er plr.nt
  and its neighbors should experience reduced probability of acid rain and other
  aggravations associated with conventional power planns.


  Trace Element. Emissions

       The experimental work needed to determine the  .evels of trace element
  emissions from an AFB power plant has not '.en mr.-.crV ~. to datn.  Only
  qualitative comparisons to conventional \.  -er plants i in •;<> mad.\.  The
  critical factors are main bed temperature of 1550 7, the t.a.-bon burnnp cell
  temperature of 2000 r, the absorbency of the porous dry soliJs of the bed
  material, and the low solid fly ash emissions level of 0.1 lo/MBtu.

       :h; a;h in the Illinois No. 6 coal is 8.9 percent.  Therefore, trace
  elements in the coal that remain with the ash would be found at a concentra-
  tion in the ash approximately ten times that in the coal, if all the ele-
  ments recalii in the ash.  The coal feed rate is 1000 times the participate
  emission rate from the stack.  The total .solids discharged include ash, calciua
  sulfate, and unreacted lime.  The ash is 29 percent of the total solids dis-
  charged and is 100«fcimes the %tack gas particulate emissions.

                                     154

-------
                            Table 55

                  NATURAL RESOURCE REQUIREMENTS
         ADVANCED STEAM CYCLE-ATMOSPHE.IIC FLUIDIZED BED
      t, Limestone Ib/kWh

Co«>l, Ib/kWh

Water, Total (Gal/kWh)

  Cooling
    Evaporation
    Slowdown
  Plant General Use
    Condensate Makeup

Total Land, .Acres/100 MW

  Main. Plant
  Disposal Land
  VALUE

 0.2272

  . 8339
 0.453
 0.14
 0.018
 0
12.84
15
                             155

-------
                                   Table 56

                            ENVIRONMENTAL INTRUSION
                ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
              EMISSIONS
S°x
NO
  x

HC

CO

Partieulates
LB/MBtu
 INPUT

 1.028*

 0.270**



 0.040

 0.099
 LB/kWh
 OUTPUT

  0.0098

  0.00258



  0.00038

  0.00094
          THERMAL POLLUTION

Heat, Rejected Cooling Towers, Btu/kWh

Heat, Rejected Stack, Btu/kWh

Heat, Rejected Total, 3tu/kWh
                     4794

                      994

                     5946
                WASTES

Spent Solids Congolomerate

  42% Calcium Sulfate
  31% Ash
  24» Unreaeted Lime
   3% Carbon

Water Discharge
LB/kVh
 0.292
 1.32
M LB/DAY
  5.70
 25.8
 *Based upon- available data, EPA believes that li.nestone  would have to be
  injected into the AFB at a Ca/S ratio of 2.5 to 3-5  to  routinely achieve
  this emission level, rather than the ratio of 2 used in this study.
**Based upon available data, EPA believes that the NO* emissions level will
  more typically be in the range of 0.3-0.6 Ib/MBtu.
                                   156

-------
     The trace element concentrations  in Illinois No. 6 coal are indicated
in Table 58.   The three categories relate to the manner of their discharge
when fired in a slagging cyclone burner in a conventional furnace and
boiler.  It is projected that in the AFB, the Group I trace elements will
not volatilize and will maintain their original proportion to the discharge
ash content.   This would be a ten-fold concentration in ash when the coal
combustibles  are removed.  The upper limit en stack emission would be at  a
rate one one-thousandth of their rate  of introduction in the coal.

     The volatile elements in Group III will likely be volatilized in the
AFB bed.  Some of these may escape through the stack as gases, but much are
likely to be captured or to escape as  particulates formed by condensation
in the 250 F stack (Hg) or by reaction (HgO, CaF).

     The elements in Group II cannot be assigned a cistinct trajectory until
appropriate tests are made on.AFBs. The low and uniform main bed temperature
of 1550 F is below the slagging temperature.  The carbon burnup cell at 2000 F
borders on the. slagging temperature range.  However, the fluidized beds must
operate below slagging temperature to  avoid agglomeration of-the particles In
the bed.  It  is probable that the least volatile elements like nickel will
react as if they were in Group I.  Those elements that may partially tend to
volatilize will do so in the presence  of extensive dry porous granular mate-
rial which tends to absorb volatiles that^are near their dew point temperatures.
Since the most porous material with the greatest surface area is the sonbent
and the fly ash, a selectively larger  concentration should occur in spent'
sorbent and fly ash.  In addition the  cooling to 730 F as the gas stream
flows over the convection surfaces will result in these volatiles condensing
in the fly ash.  As a result some elements in Group II may be expected to be
found in the particulate emissions in  concentrations far greater than their
proportion to the ash in the coal.
                                   157

-------
                                   Table 58

              TRACE ELEMENT CONCENTRATIONS IN ILLINOIS NO. 6 COAL*
                                                       Concentration
                                                            (ppm)
Group I..     Not volatilized during
             combustion
                      Mn                                    6-181
                      Be                                  0.5-4
Group II.    Volatilize at slagginR temperature
             but condense on fly ash
                      Pb     .                               4-218
                      Sb .                                0.22-8.9
                      Cd                                  0.1-65
                      As                                  1.7-93
                      Ni   ,      -                           8-68
                      Cr                                    4-54
                      Zn                                   10-5350
                      Cn                                    5-44
                      V                                    16-78
Group III,   Volatilize and escape
             as gases
                      HR                                 0.03-1.6
                      F                                    30-167
                      Cl                                  100-5400
*Grouping selected based upon trace elements emission data from a
 conventional cyclone-fired coal furnace.
                                    158

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7.   SUMMARY  PERFORMANCE AND COST

     Table 59 conveniently summarizes  the  system performance and cost
effects.   The plant overall efficiency is  lower than the prime cycle
thermodynamic efficiency because of the boiler efficiency of 0.8792 and
the ratio of net station output to generation of 0.927.

     Capital accounts for two-thirds the cost of electricity (COE) for a
station capacity factor of 0.65 and fuel cost accounts for under one-third.
Historically, these two components of cost have been equal..  The current
ratios favor low-cost power plants and penalize high efficiency and high
capital cost plants.

     Table 60 indicates the sensitivity of the COE to changes in the base
rates of the factors that dominate electricity generating costs.
                                    159

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                                 Table 59
                       SUMMARY PERFOratANCE AND COST
             ADVANCED  STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
                     ITEM

Net Power Plant Output (MW  - 60 Hz - 500 kV)

Thermodynamic Efficiency (%)

Power Plant Efficiency (%)

Overall Energy Efficiency (%)

Coal Consumption (LB/kWh)

Total Wastes (LB/kWh)                    '

Plant Capital Cost ($ Million)-

Plant Capital Cost ($/kW )
Cost of Electricity,  Capacity Factor = 0.65

  Capital
  Fuel
  Maintenance & Operation

  Total

Estimated Time of Construction (Years)

Approximate Date of First Commercial Service
                                                (MIILS/kWh)
                                                (MILLS/kWh)
                                                (MILLS/kWh)

                                                (MILLS/kWh)
                                                                    814.3

                                                                     A3.9

                                                                     35.8

                                                                     35.8

                                                                      .0.88A

                                                                      0.292

                                                                    5U.6

                                                                    632.0
    20.0
     9.5
     2.2

    31.7

     5.5

1984 - 1986
                                   160

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                   Table 60

     COST OF ELECTRICITY (COE) SENSITIVITY
ADVANCED STEAM CYCLE-ATMOSPHERIC FLUIDIZED BED
BASE
CAPACITY
FACTOR

COE, Capital
COE, Fuel
COE, O&M
TOTAL COE
0.
20.
9.
2.
31.
65
0
5
2
7
FUEL
COST
INCREASE
50%
20.
14.
2.
36.
0
3
2.
5
LABOR
COST
INCREASE
20%
21.
9.
2.
33,.
6
5
2
3
MATERIALS
INCREASE
CAPACITY
FACTOR
CHANGE
20%
22.
9.
2.
34.
4
5
2
1
26
9
2
37
0.5 & 0.8
.0
.5
.4
.9
16.2
9.5
2.2
27.9
                    161

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D.  PRESSURIZED FLUIDIZED BEE POWER PLANT

1.  INTRODUCTION

     The advanced steam cycle power plant with pressurized fluldized beds
(FFBs) performs the functions of combustion, steam generation, and sulfur
capture in four modular PFBs that use gas turbines to achieve a substantial
supercharged pressure level.  A simplified  cycle schematic, Figure 26, indi-
cates the arrangement of the major equipment.  The gas leaving the ?FB must
be highly filtered before its expansion through the gas turbine.  The gas
turbine exhaust must be cooled in economizers to utilize its thermal poten-
tial fully.  This feature substitutes in part, or fully, for the high-
pressure feedwater heaters of the steam turbine cycle.  The steam turbine
and the heat rejection equipment are exactly comparable to units selected
for the atmospheric fluidized bed (AFB) plant evaluation.

     The system parameters are presented in Table 61.  The Illinois No. 6
coal contains 3.9 percent sulfur.  Eighty-three percent of the sulfur must
be captured to meet the environmental emission limit of 1.2 Ib/MBtu of fuel
hf>at release.  The capture medium is dolomite fed into each of the six main
fluldized beds at twice the rate that would ideally capture all of the sulfur.
The 1650 F main bed operating temperature was selected to maximize sulfur
capture at 90 percent of that present in the coal.

     Unburned carbon is conveyed from the main beds in the fly ash of the
gas stream and in the solids tapped from each bed.  Tb^ 95 percent of the
fly ash recovered in the cyclone separators and the tapped solids from the
main beds are recycled to a carbon burnup cell (CBC), where a higher tem-
perature of 2000 F and increased excess air of 30 percent produce a substantial
burnup of residual combustibles.  The net result is both a high combustion
efficiency and a high sulfur capture effectiveness.

     The pressurizing gas turbine sets provide a supercharge level of 10
for the PFB.  The inlet temperature of 1600 F is modest for contemporary
gas turbines.

     The steam conditions are conventional  and correspond to chose used for
the AFB.  The steam cycle has a low final feedwater tempera-ture of 254 F
to match the economizer outlet gas temperature of 300 F.  Only three feedwater
heaters are used.

     The net power from ,-.he plant would be  904 MW representing 39.2 percent
of the higher heating value (HHV) of the coal fired.  The steam turbine
produces 78 percent of the power and the four gas turbines 22 percent.
   Preceding page blank
163

-------
 Coal  Dolomite
_]	L
 Solids Handling
  Spent Solids
   Handling
   L
           Air-
                                                             •/   Stacks
                     Gas Turbines
                      Figure 26.  Simplified Schematic Diagram  for  Advanced
                                Steam  Cycle-—Pressurized Pluidized Bed

-------
                               Table 61

                           SYSTEM PARAMETERS
           ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED  BED
              PARAMETER
    VALUE OR DESCRIPTION
FUEL

   ILLINOIS NO. 6 COAL

   DOLOMITE
10788 Btu/LB HIGHER HEATING VALUI
$1/MILLION Btu
SULFUR CAPTURE MEDIUM
0.45 LB/LB COAL
•FURNACE

PRESSURIZED FLUIDIZED BED -  COHBUSTOR AND  STEAM GENERATORS  (4 MODULES)
   MAIN  BEDS  (6 PER MODULE)
CARBON BUttNUP BED  (1 PER MODULE) '  .
   GAS TURBINE
    EXHAUST GAS

PRIME CYCLE - STEAM PLANT

    WORRIES FLUID
    TURBINE INLET
      REHEAT
    CONDENSER
    FINAL' FEEDWATER

HEAT EXCHANGERS

    GAS  TURBINE EXHAUST
    ECONOMIZER

HEAT REJECTION
1650 F. COAL AND DOLOMITE, 20% XS AIR
2000 F. FLY ASH AND SOLIDS DRAIN, 30% XS AIR
1600 F INLET. 10 PRESSURE RATIO
ECONOMIZER HEAT TO FEEDWATER
STEAM  .
3500 psi, 1000 F
676 psi, 1000 F
2.3" Hga, 106 F
4378 psi, 254 F
GAS 850 F IN/300 F OUT
WATER 533 F OUT/254 F IN
    WET MECHANICAL DRAFT COOLING TOWERS   22 CELLS
    STACK GAS TEMPERATURE                  300 F
                                   165

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2.  CYCLE DESCRIPTION

     A more detailed plant schematic is presented in Figure 27.  State points
and stream flows are shown in which the enthalpy values are referenced to
32 F water for steam and water,  and to an 80 F zero references for air, com-
bustion gases, and solids.  This power plant uses four PFB boiler modules to
convert the energy from high sulfur coal into steam for a conventional 3515
psia/1000 F/1000 F steam turbine cycle with single reheat of steara.  One tardera
compound four-flow steam turbine-generator produces 738.63 MV gros? electric
energy output.  Incorporated with each PFB boiler is an open cycle gas turbine
that supplies the air from its compressor to the PFB boiler.  Thjs pressurized
air stream fluidizes the bed and reacts with injected coal to develop the heat
for steam generation.  The resulting hot gases return to the turbine for expan-
sion to atmospneric pressure.  This expansion in the turbine develops sufficient
shaft power to drive the compressor and an electric power generator that also
delivers 51.25 MW gross electric energy output.  Thus, the combined plant output
from the steam turbine-generator and four gas turbine-generators is 943.63 MW
gross.

     The regenerative feedwater heating cycle has two low-pressure feedwater
heaters, a deaerator, and a high-pressure feedwater economizer that extracts
heat from the gas turbine exhaust gases.  A portion of the exhaust steam
from the intermediate pressure turbine is extracted for powering con-
densing steam turbines that drive the boiler feedpumps.  All other najor
pumps are driven with Rlectric motors.

     The sulfur present in the coal combines with dolomite injected into the
PFB boilers with the coal to form calcium sulfate, which is removed along
with coal ash and dolomite residue from the PFB boilers.  Hot gases from the
PFB boilero are cleaned in cyclone separators followed by granular bed fil-
ters.  After the particulates in the flue gas are filtered and the energy
from the ho;, gases recovered in the gas turbine ano! the economizer, the flue
gas at 300 F is discharged to the atmosphere.  The clean flue gas will meet
the national standards for emissions from new coal-fired power plants.
Pressurized Fluidized Beds

     The feedwater to each PFB would  be  at 533 F after being heated in the  gas
turbine exhaust economizer.   Within the  PFB unit this water is heated to steam
turbine throttle conditions of 3500 psig, 1000 F.  After expansion in the high
pressure turbine,  the steam returns to the PFB at 767 psia, 604 F to be reheated
to 1000 F.   There are six main beds and  one carbon burnup cell in each PFB
pressure container or module.   The  heat  exchange surfaces are mainly submerged
in the fluidiztd bed and its containing  waterwalls.  Convection surfaces are
not used since the intent is to provide  a high gas turbine inlet temperature of
1600 F in conjunction with high temperatures of 1650 F in the main fluidized
beds.  The  CBC operates at 2000 F,  using recycled solids from the main bed  taps
and from the cyclone separators.
                                   166

-------
                                                   1850 F MAINBEDS
                                                                               I Stebfl> Turbine-Gtnerotor Set
                                                                               Tondem Compound Four Flow, 33.5" Ust Slog* Bucktt
                                                                                                                  'Hotel* Load 8.3 M*
                                                                                                                  TronsformtrU»*4.7UW
    Solids Handling
      2.2UW
4 Modules ol
PFB.Goi
Tin Sines,
Economizers
                                                                    Steom Turbine Au« 2.4 MW
                                                                    Cos Turbine Aui. 2.2 MW
                                                                        mCondensate
                                                                        ^ Pump
                                                                           IMW
          15.42/850/8.224/204.5

                 4200/533/4.281/526
                                                 .4393/254/4.281/231
Spent Solids
  250 F
 0.310*
  4lh
    General™    9 4 3,630 KW
    Auxiliaries     39,860 KW
    Net Station    903,770 KW
Note
                                                                                                             Makeup ond Service Pumps
                                                                                                                    1.8 MW
 Prtssurt ( psia) / Temperature i'F 1 / Flo« Rote 1 1 w'i.b/hrl / tntholpn I8»u/l b I
                                 Boiler
                                 Feed      ,    ^
                                 Pimpll!   0   ©
                                        106'.GH
                                                                                                     » Flo» WUI.on Pounds Per. How
                                                                                                   .r H, tnlholpy Btr Per Pound t
       Figure 27.    Schematic Diagram  of Advanced Steam Cycle  -  Pressurized
                         Fluidized Bed (1650  F  Main  Beds)

-------
Gas Turbine Air  Supply

     Each gas  turbine i's  of  a  basic conventional design using a pressure
ratio of  10.   A  fraction  of  the delivered  air  from the compressor is
pressurized an additional 100  psi in the Petrocarb air compressor (PAG) to
convey the coal  and dolomite into the main beds through the injection feed
pipes. The cooling '••>•• the  PAC heats air  for  coal and dolomite drying along
with heat reclaimed from  the spent solids  cooler.  The bulk of the air supply
goes directly  to the PFB  unit.  In addition 22 MBtu/hr are added to boiler
feedwater in the portion  of  the PAC cooler serving as an economizer.

     The  gas from the PFB contains fly  ash particulates.  Cyclone separators
remove 95 percent of this solid burden. Tnen  the fine filters remove the
rest to the level of cleanliness required  for  gas turbine durability.  The
fine filters are granular bed  units that are periodically backflushed vitli
fluidizing air to purge them of accumulated solids.

     The  inlet flue gas to the turbine  is  at 1600 F and 138 psia, a loss of
7.5 psi relative to the compressor discharge.  The 350 F turbine exhaust serves
a heat recovery  ecorioinizer in  the steam cycle, producing 300 F stack gas.


Spent Solids System

     The  CBC solids tap and  the cyclone filter tap for the CBC and the solids
and carryover  sand from the  granular fine  filter purge are accumulated in
the solids cooler.  Their temperature is reduced to 250 F while producing
790 F air for  drying feedstock.  These  spent solids comprise 42 percent ash,
26 percent calcium sulfate,.  13 percent  unreacted lime, 16 percent magnasiuia
oxide and 4 percent unburned carbon.


Coal and  Dolomite Systems

     Hot  air for drying is drawn through the active dryers and then the feed
storage silos.  Coal and  dolomite are crushed  to size and then pressurized
for distribution and injection using the Petrocarb high pressure solids
injection s/stera.  Recycled  fly ash and tapped solids art- fed to the CBC by
a combined gravity and air assisted transport.


Overview

     The  overall system for  using PFBs  achieves sulfur capture during com-
bustion,  and a high combustion efficiency  by recycle of air-borne solids
containing unburned carbon.  The four self-contained modules of PFB and gas
turbine assure that only  one-quarter of capacity would be lost during out-
ages of a single module.   The  plant aggregates 944 MW of generation, of
which 22  percent is from  gas turbines.   The net station output would be
904 MW.
                                   168

-------
 3.   MAJOR CYCLE COMPONENTS

      The usual spe.cificaticn for steam pqwer plants add a  5 percent margin
 of  flow and capacity to every major corapon*:u.   Sucir an approach would .upset
 the close integral ..on cf the many components of a PFB system.  To assure per-
 fect etching of ail pieces of the system,  the  fuel and air and heat absorp-
 tion Oil the PFB were fixed as the common parameters for the gas turbine,
 compressor, PfB module, and .s*u>.on turbine heat  supply.   The phyVcal tize
 limitation on the PFB tower cics-ely r.atjhed the airflow rate for current gas
 turbines.  From these considerations the sir for combustion, fuel for com-
 bustion, dolomite rate, and gas flow ' .> tr.fi £as turbine were fixed.  The
 coal rat.^ so established -was 1.4 percent. BT'er.ter than the  coal rate for the
 AFJ3 plane at its 100-percent rating p.:>ins ,

      The design and performance details nf  the  PFB modules, the pressurizing
 gas turbine and economizer, and the sterr.a turbine-generato-?. are considered
 in  this section on major components.  All remaining equipment would be speci-
 fied and supplied as balance-of-plant (BOP) materials.   Equipment lists for
 all items are provided in a subseqveTiC section, "System Performance and
 Cost."
 Heat Input System-PFB
                                                                         »~
      The PFB heat input major components comprise  the PFB tower module-,  the
 solids handling for coal, '-dolomite,  and spent solids, fie hot gas filtering
 system, the fuel and dolomite^ inject ion systems, and the ;;:ir; turh'-ne ;y* ' •• ft '
 supply with its exhaust heat economizer.  Conceptually the -functions e're
 similar to those described for the AFB.  The solids handling requires; lock
' hoppers to pressurize the  feed solids and to depressurize the spent solids.
 The hot gas filtration requires :wo  stages of cyclone f iltfers followed by
 the fine granular bed filter.  The PFB beds operate in an alkaline environ-
 mant at low-temperature levels relative to conventional boilers and at a
 very low sulfuric acid dewpoint.   The ash products are soft and dry and will
 not adhere to heat transfer surfaces.  As a result of these favorable con-
 ditions, no coal ash corrosion problems within the PFB beds are expected.
 Emissions of sulfur dioxide will  be  under the current limits as a result of
 the 90 percent sulfur capture in  the main beds.  Nitrogen oxide emissions
 will be one-third the current limits; practically  all ninrogen oxides result
 from fuel-bound nitrogen since the low bed temperatures form very little
 thermal NOX.  The effect on gas turbine nozzle and burket life will be an
 important determination for pilot and demonstration units.  The flow of mate-
 rials and the temperature  levels  throughout one" PFB module are presented in
 the process flow schematic, Figure 28.  The interior arrangement of the PFB
 tower module is shown in Figure 29.   The identity  of each heat exchange
 element i?  shown in that figure,  and the Jetailed  heat exchange and tempera-
 tures appear on the heat absorption  layout in  Figure 30.  Table 62 presents
 the resulting surface requirements and selected cubing to satisfy the
 requirements for each PFB  module.

      The heat exchange surfaces selected tend to take advantage of the great-
 est heat transfer temperature differences and thv.s minimize surface area
                                    169

-------
                                                   $fKt#M FLOWS ntfff»t
COil-
STOME
SOilC.$
d>s
Alfl"
iCTir
             /   i  5     .11
                        l»l I
_ 7

Mi»4-
7* 7B

"•»'

»»2
8 , * 10

34114
-
"'"

""'
1| (^
~ r - —
»S»| „«
*>

met
it
MIJS ~

l»_
~ii6T"

29
llttl' *



ti>»i.
ii

'
•tz


25


..", I „'.'.

I
Z6
"

27


za


" j

i
                                                       j  10  I  Jl  I   52    33  I  14  i   35  |  16

                                                       I />Jr<>4 I f^i>2*<   r«»47«  f^rtrfib] .4r«^ft&] MMJVJ [ 134^*!
                                                       J_.__L__l  _   _^y'''L  _ii;y_± • -I  s?»
                                                       III       i,»(«*»sri*>i.;i*T««t.'»» I w».»sj
                                  «rnCAH$ *MllftAU.V 5UAU,  NOT CUNSiOfNtD
                               Figure 28.  Process  Flow Schematic  (Foster  Wheeler)

-------
                                             Reproduced from
                                             besl available copy*
  d&j&syK
  SSSLCOiJVH
   ifiiT^j
Figure 29.  Advanced Steam Cycle — Pressurized Fluidized
           Bed — Boiler (Foster Wheeler)
                          171

-------
                              «45-
SMS RNS 	 1 	
OUTY DUTY . , • • ' «i M
i 3420 ' i C PSHIA 14550 *•*[? 	 tx> ,
j S4a.
1 ' " "' 	 " " ""• ~" 	 I
! 14.953 | C PSMI8 1882430 n 750*
108.073 : l».375a! ... , 	 	 	 	 _| V
|«3S- .
3.420 [ C PSHJA 14550. °P ^
• 1!«48*
- , ... Jl i
14935 i i PSH2B 1882*30 <-.[ 1
Mli.073 |I».375Q .

«25- r~ - -*>->i;

i . . 1 75^ 690,799 If/Kt
• 3420 ! C PSH3A I45SO '^
_... ..H ,u 	 — ~4i T8i'
14955 C. PSH3B I8S24JO -. »73«
206.073 18.3730 -J
t .
|tio* f -.- -* -- - r
1 1 "• vi
; - • • : Oj «7s- i . '
3.420 C FSH 4A W350 ° 1 ' "
11 880- |V | 'I •
C FSH IB SI 1170 , '°OS'»
I495S ' -li r<
•0947 127126 ' |lT?750 ^ 3H 4 !27l26fl T,XJ-.

J603' K "J
1 . V

1 3.42O f FSH 5A . i.«S3 Vj- "i
j 	 | . 	 	 	 	 	 }J - |
j C FSH5B 61.1180 . Q_J 	 1 . 	 J"
80946 12*127 JI6 3750 > '. ; ^ RH ^ 	 }27.l27q 	 Or>^-( '
590'
| , ETA 1 PSH6A ,| 750- '
| • t f' — — " — H 1 i
I7l»g 319490^1 CI03.J320 , 875* 379.929 IO/TW
172.016 i 21.7440 ! ! ' •

A^ 370- 1 ' ]' '
JO - ! EX Il9,l49!l>/tir

313.194 ECON- 315.194 f 	 S 5 C |!
1273.323 234.253 428.8130 1 	 iso^^Tsa^aB/v jt% * 1 1 j»i*
Telfll Outout -1527.5760 ' 	 • 	 ' ^« « S^ « £'•".
S| III gp
h-EntMlpy 8TU/lb ..J.. , — ! 	 1 	 1 	
- -T.mp *F .. fifW! .RHiiv RHowt. SMout
0 -fflilho* STU/hf ' f ^
— i < r-
^ V-, \" v-




















!















' "Wf
'|H
• U
H
& i
; — i
0
m
^ ^i
U
80






































«v







                                              T
                                     -  5-  I   !
                                     t  1  I   J


Figure 30.   Advanced  Steam - PFB Circuit Absorption  Diagram

-------
               Table 62




PFB MODULE HEAT KXCllANCE SlUFACE DETAILS
BANK
SERVICE
E7A
E7B
VU

PSH1.2A
PS111.2B
PSH3A
PSH3B
PSH6A
PSH6B.
FSH4. 5A
FS1I4.5B
RIM, 5
EX
EY
Size
EX
EY
Beds 1-5
6
7





Q MBcu/hr
13.992
31.949
113.619

1.455
188.243
1.455
188.243
..799
103.532
1.455
61.117
127.127
5.637
309.557
H x D
B'O x 24
_
So ft
617
463
4450

95
4539
95
4540
52
2497
95
1892
3026
5220
179326
x U
1 Lg x -

r»odn)
1-3/4
1-3/4
1-1/4"
+ Fin
1-1/4"
1-1/2"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1-1/4"
1
2" Fin



N
s
22
22
270

68
68
68
68
68
68
68
68
68
44
68



St(in)
4-1/2
4-1/2
1-1/2

3
3
3
3
3
3
3
3
3
1-1/2
4


23' x 38' x 10'
8 '-6" x 8'
4 '-8" x 8'
3'10" x 8'




-6" x 8'
-6" x 8'
-6" x 61



























2-1/4
2-1/4
Fin

1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
1-5/8
3 sq.
6
*loops
Qn
S°
0°
N
s!
-t
aT
BC
NR
L/L

1 BC(in) NR
71" 16
53" 12
270

2-7/8" I/?
77-5/8" 24
9-3/8 1/2
77-5/8 24
9-3/8 1/2
• 77-5/8 24
15-7/R" 1/2
32-1/B" 10
51-5/8" 16
64" 12
81-1/2 14

7./L Loops
2 8
2 6
270 1/2

1 1/4
1 12*
3 1/4
3 4*
3 1/4
3 4
5 1/4
5 1*
2 4*
1
1 7

«yf>2 On/In)
io-in/-
-/10-10
10-5/5-10
8 F+R
8-8/-
_/8-8
8-8 /-
-/10-10
6-6/-
-/8-8
10-10/-
-/10-10
10-10/12-12
3/3
10/10
are half IcnRth with central outlet headers.
- Duty - mm Btu/hr
- Surface - ft"
- Tube O.I), (in.)
- No. Sections
- Side spacing (in
- Back spacing (in
- Bundle clearance
- No. runs/section
- loop In loop




.)
.)
(In.)











                   173

-------
requirements.   Staggered in-bed tube pitches were selected with spacing that
promotes a good uniformity of bed fluidization.
     I

PFB Gas Turbine and Heat Balance

     Each PFB unit has a gas turbine with an exhaust economizer.  Perform-
ance specifications are presented in Figure 31 and Table  63 for the units
serving the 16jQ F PFBs.  The state points and heat duties integrate exactly
with the flow rates and heat duties of Figure 28 and of the steam turbine heat
balance Figure 32.  The basic fixed parameters were the air for combustion at
state 2 of Figure 30 and the coal rate per module of 182, 462 Ib/hr.

     The gas turbine compressor has 17 stages and the turbine has 3.  The
design, except for modification to the normal combustor section, is char-
acteristic of current 3600-rpra designs.  It is anticipated that blade coat-
ings and claddings may be required to counter any chemical or particulate
attack on the nozzles or buckets.
Prime Cycle

     The major component for the prime cycle is the steam turbine-generator.
The selected unit was a General Electric tandem compound turbine with four-
flow exhaust using 33,5-in. last-stage buckets.  The 3500 psig/1000 F
high-pressure turbine and 691 psig/1000 F reheat turbines are comparable to
units supplied for the AFB prime cycle.  The heat balance of Figure 31 was
based on exactly matching the 6.105 MBtu/hr heat to steam cycle produced by
the four FFBs, their gas turbine economizers, and their Petrocarb compressor
economizers.  The high-pressure feedwater heaters have been eliminated since
feedwater at 533.3 F will be produced by the economizers with a pinchpoint
temperature of 46.5 F.  The elimination of high-pressure steam feed heaters
in the steam cycle reduces its cycle efficiency to 41.3 percent.  The heat
rejection system is identical to that presented in Table 65 except that flows,
power, and number of cells are porportional to condenser heat duty.  (See
table 64.)
Materials Considerations
     Concern with the pressurized fluidized bed with a  bed temperature of
1650 centers mainly on the problems created by hot corrosion.  Apart from the
use of some higher temperature alloys, the problems are qualitatively similar
co those for the AFBs.  Critical temperature ranges will depend on the alloy
selected and the nature of the chemicals formed, which  in turn will depend on
the coal composition.

     There may be a severe hot corrosion problem in the pressurizing gas tur-
bine and also erosion and fouling of critical components.  The problem of hot
corrosion in the turbine can be essentially rationalized in  terms of the con-
taminant level in the gas stream.  The limits for materials  in current use
are well documented.  If these limits cannot be maintained through hot gas


                                    174

-------
                                                     Water
                                                                LI-
                                                     Boiler
                                                    Feed water
PCC
    Station
Gas flow, Ib/hr
Water flow, Ib/hr
Pressure, psia
Temperature, °F
Enthalpy, Btu/lb
Heat duty, HBtu/hr
Unit
•Gas turbine limits
    Constituent
    Sodium and pot.
    Lead
    Vanadium
    Calcium
    Trace - others
    Solids except I
    Solids over 10
    Solids over 13
1
1888924
0
14.7
59
-S
for gas
i . 3* 4 5_ £ I £ 1
1317000 1984159 2056083 2056083 0 0 ' 0 0
0 0 -0 ^,.0 105131 105131 19145 19145
145.5 138.0 15.42 14.7 4393 4200 4393 4200
59T 1600 850 300 253.5 533.3 253.5 533.5
123 426.4 204/S .54 231.2 525.65 231.2 525.65
1211.13 309.56 309.56 5.64 *"[
PFS Ey Ey Ex
stream 3 •*
Concentration opm bv Weight
issiura
IC's, total
microns
microns
Ur.der 0.02
tinder 0,02
Under 0.01
Under 0.04
Under 0.01
1
0.01
0.001

         Figure  31.  1650  F Pressurized Fluidized  Bed Module Gas
                    Turbine,  Economizer  Ey,  and Petrocarb  Com-
                    pressor  Cooler Economizer Ex
                                  175

-------
                        Table 63

GAS TURBINE SPECIFICATIONS FOR PRESSURIZED FLUIDIZED P-ELs


       Ambient   - ISO 59F, 14.7 psla

       Compressor - Stages 17

                    Pressure ratio 10:1

                    Inlet pressure, drop 4" H.O
       Combustor pressure drop - 5%

       Turbine - Stages 3

                 Inlet temperature 1600°, 1700°

            t     Turbine inlet Mach number 1.0

                 Turbine nozzle flow coefficient 1.0

                 Diffuser inlet Mach number 0.5

                 Diffuser exit Mach number 0,05

                 Diffuser pressure loss coefficient 0.46

                 Exhaust^ pressure drop 20'1 H_0
                         176

-------
                      StiiJiHSi.' •«•*»• i U/KW tin.
                                               Ill.ilJKWMj V MM. Al>(.
                                               If.1** J) V I.MI JbOOIII'M
                                                      ll HVA *• IV I^H: 111 l-Hf'.'i, K •. » ITII.K
Reproducee! from
best available copy.
                                               *>«    Id/Mm
                                             *4t III! MS
Figure 32.   Steam Turbine  Cycle Heat Balance  PFB  -  1650  F

-------
                            Table 64

                   COOLING TOWER PERFORMANCE


   Design heat duuy                               3600 MBtu/hr

   Wet bulb                                         51.5 F

   Condensing at 2.3 in. Hga                       105.9 F

   Hot water to tower                              100.9 F
*••
   Cold watsr return                                70.3 F

   Range                                            30.7 F
                              c- :
   Approach                                         18.7 F

   Water flow                             •* •     234,555 gsl/min

   Fan power                                        2.53 MW

   Pump power                                       4,40 MW

   Cells                   ^          *~             22

        Each cell:  36 feet long, 75 fefct wide,
                    47 feet high, 1 fan


                           Table 65

                        SYSTEM OUTPUT
        ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZEn.BED
                           1650 F

 STEAM CYCLE OUTPUT  (MW )
   (MW - 60 Hz AC)    e                                   738.63
 TOTAL'TRESSURIZING TURBINE OUTPUT (MW )                   205.00
 TOTAL GROSS OUTPUT  (MW )             e                    943.63
 TOTAL AUXILIARY LCCSES6(MW )
   INCLUDING TRANSFORMER LO§SES                             39.86
 NET  POWER PLANT OUTPUT (MW  -  60 Hz AC - 500 kV)          903.77
                          e
                             o
                              178

-------
cleanup or turbine design, it will be necessary to employ alloys  that are
more corrosion resistant or apply coatings to surfaces in the hot gas stream.

    The steam turbine represents a mature technology, and significant
materials problems are not anticipated.
                                179

-------
4.  PLANT ARRANGEMENT

Plot Plan

    The plant arrangement on its plot is based on storage of a 60-day sup-
ply of coal and a capacity to hold ash for 15 days.  A series of ponds con-
tain run off water from the site and provide for treatment of all water
returned to the North River.  The basic plot dimensions are one-half mile
by three-tenths of a mile.

    Figure 33 shows the total plant area of 108 acres in the small section,
and the main area in detail.
Coal and Dolomite Handling

    Coal is received by rail and is unloaded to two conical storage piles.
The compacted dead storage coal pile is 60 ft high with a base measuring about
1240 ft by 416 feet.  This stores 412,000 tons of coal for recovery by use of
dozer tractors.  The two conical live storage piles have a base diameter of
about 312 ft, and contain a total of 114,700 tons of coal, with 26,000 tons
available by gravity feed through under-pile vibrating feeders.  Dolomite is
stored in a single storage pile of 235,000-ton .total capacity with 11,800 tons
available by gravity flow through under-pile vibrating feeders.

    The coal from the active storage pile is fed at 365 tons/hr to a conveyor
belt by vibrating feeders located under the active storage pile.  Magnetic
separators at tha distribution bid remove the tramp iron.  Oversize coal is
screened out, crushed, and then fed back to the distribution bin.  The dis-
tribution bin is equipped with four coal outlets, which feed the coal to four
conveyor belts; each belt feeds the coal to two silos.  A set of four silos
feed the coal to an associated conveyor belt for the transport and distribution
of coal to any two of the three parallel sets .of half plant capacity dryers and
crushers.  This provides one redundant set of dryer and crusher for reliability
and maintenance purposes.  During startup, and under upeet operations, coal can
also be supplied to combustors for drying the coal and limestone in place of
hot air from the spent solids cooler.  Dolomite is handled similarly at a rate
of 168 tons/hr.

    The coal and dolomite are delivered separately to bins at each boiler
module.  The coa!. and dolomite are not premixed for injection to the fluid
bed.  For these PFB boilers the two materials are injected separately by
Petrocarb injection systems that are part of the PFB boiler modules.


Solid Wastes Handling

    Spant dolomite and ash are collected at the PFB boiler modules at a
noirir.ai rate of 155 tons/hr.  This residue leaves the boilers at 1600 F and
is air-cooled to 250 F prior to being conveyed to storage bins at the rail
spur.  A solid waste dry storage capacity of 55,800 tons is provided by six
storage silos.


                                   180

-------

M4MMM, I4vt*t
(Jj4.lt.LM





i |*Trt~"l
!5-ii
|Ri
in!
!o'
x!


_








Figure 33.  Plot; Plan  Advanced Steam Cycle •—" Pressurized Fluidized  Bed (Dechtel)

-------
General Arrangement

    The arrangement of the four PFB modules about  the turbine building is
shown in Figure 34.  The ground floor plant indicates  the small size of the
No.  3 PFB furnace as conpared to Its cyclones and granular bed fine filters.


Plant Elevation

    The- plant elevation View through the turbine building and cne PFB mod-
ule is presented in Figure 35.  The stack of fluidizeJ beds is contained in
the 13-ft diameter pressurized tower, which stands  130 ft high.  Four of
eight cyclone separators and eight of sixteen granular bed filters are shown.

    Ihe gas turbine is located at giv -ric1 Ir.vel between the two rows of fil-
ters.  The exhaust passep thrcugh ti.; economizer en route to a stack on each
side of the power plant.
Electrical Schematic

     A single line electric, diagram showing major  electrical equipment :* =
presented in Figure 36.  Four  51.25 J-fW gas turbine-generators feed the 25 kV
bus through step-up transformers.   The 738.6 MW steam turbine-generators
feeds the 25 kB bus directly.  Two  main  transformers feed the 500 kV
transmission ling.

     Two 13.8 kV auxiliary buses may be  connected  to the. main bus through
a transformer or to the  start-up transformer.   Subsidiary buses operate at
4.16 kV and A80 kV.  The emergency  diesel feeds the 480 kV critical service
bus.
                                    132

-------
I-1
CO
               n
                      •-*
                       "*i"
          ®
             mil -i  .
            _Jl
                  rA'i^f'-L'J.f:
                     .;... .—~,)r
               00
               o c>
                       -til,
                       L'^_,
                       ..J
 n
                                                mm
                                                 TI  ff_ i , TIM.
                                              O^:
                                                          i i i i,^,,,_,  '  '
                                                          4 ^p^lnut •»«  { ' I' ' •

                                                               7? f-,".>!t;
            .  . !  -  [C<"
      	  »•* »j 11    I
      "rf—",""-" i ii uui.9t»tt' i
](•)(•)
/JOO
'50
                                                    0.1. 4

                                                    IL
     ;^r
     c'i
r:i*4,yM,lftffr
       %,
                                SIM.
                                                           ClKHtflD MOOf^ ft AN Ci-O' ;
                                                                                  u i»r M
                   Figure 34.  General  Arrangement Plan Advanced Steam Cycle — Pressurized
                             Fluidized Bed (Bechtel)

-------
                                                             TMC PULL ftfACC
                                                           IMP n-QOH Ct-.O*
               SECTION A-A

                      «<	
                                    UECFKIO
                                        .
                                    COMfARTMlMT
                                                     —. i% if^^^c IQwt
     n
                                                             ISCBTEl
                                                             GE/NASA
                                                      AOVAHCEQ CHCRCr COH)/£fe.(ONCTUO(
                                                         CEfiHAl. A
                                                             EtCVATION
                                                       ADVANCED STEAM CTCLE PFB
                                                           11:07
P-203
Figure 35.  General Arrangement Elevation Advanced Steam
           Cycle  — Pressurized Fluidized Bed (Bechtel)

-------
                                                                                   Gt XtlASA

                                                                               -id D lufK,) crrivfVJ(V< it»
                                                                                    UNf OlACHAM
                                                                               *cv*«c»o sri *u c * citron
                                                                                       —-^--f——>
                                                                                 1 1 ;o?
Figure 36.   Electrical  Diagram  for Advanced Steam  - PFD System  (Bechtel)

-------
5.  SYSTEM PERFORMANCE ASP COSTS

Performance

     The performance margins commonly applied to steam power plants cannot
be tolerated in a closely integrated plant such as this.   The heat balances
presented for PFB, gas turbine, and steam turbine must all be guaranteed per-
formance points.  Table 65 presents the resulting gross generation, auxil-
iary power loss, and ne". station output for plant configurations with 1650
F mainbeds.  The auxiliaries are of the order of 4 percent of generation as
compared to 7 percent for AFB power plants.


Auxiliary Losses

     The detailed auxiliary losses are presented ir; Table 66.   By virture
of the gas turbines supplying the energy to force gas through the PFB and
hot gas cleanup system, there is no electrical auxiliary  loss attributed to
that service; this factor accounts for the markedly reduced electrical   ':
auxiliary loads for PFBs as compared to the AFB power plant.
                                         ^-                 *
                                                                       »~
Costs—General
                                        .*••
     Costs were synthesized €rom major components costs,  BOP material costs,
and BOP labor costs.  Items made up of numerous smaller components are pre-
sented by enumeration of the total cost and unit count for each of the sub-
components.  An equipment list for BOP components identifies all..major items.
A detailed breakdown of BOP labor man-hours and material  costs completes
identification of all material'-and construction and installation costs.
Thereafter these costs were combined with major component costs to arrive
at total plant costs.
Costs—Major Components

     The steam turbine-generator would be purchased at a price of $25 mil-
lion, and each gas turbine would be purchased as  a  complete unit for $6.41
million.  In contrast, the steam generator comprises four PFB modules, auxil-
iary units serving each PFB,  conveyor and solids  equipment serving pairs of
PFB modules, and solids preparation equipment providing three units where
any two can service the entire plant.  Equipment  lists for the PFB steam
generator system are presented as Tables 67,  68,  and 69.


PFB Major Component Characteristics (1650)

     Subsystems costs and weights are presented in  Table 70 for the steam
turbine-generator and for the PFB modules exclusive of their solids handling
equipment.  The gas turbine,  its economizer,  and  the hot gas filtering
system are also enumerated.      o
                                   186

-------
                                  Table 66

                          AUXILIARY LOSS BR&.KDOWN
               ADVANCED  STEAM CYCLE-PRESSURIZED FLUIDIZED BED
                                   1650 F
ITEM


FURNACE
   FANS FOR DRYERS
     (COAL DOLOMITE,  SOLIDS)
 .  COAL CRUSHER
   DOLOMITE CRUSHER
   INJECTOR COMPRESSOR
   FILTER       -

TURBINES
    ASSUMPTIONS
PUMPS

   CONDENSATE
   CIRC. WATER
   SERVICE WATER
   INTAKE WATER

SOLIDS HANDLING

"HOTEL" LOAD

COOLING TOWER FANS

TRANSFORMER LOSS
0.33% OF STEAM TURBINE,  kW
1% OF CAS TURBINE,  kW
A P = 185 PSIA
PROPORTION TO COOLING DUTY
A/E ESTIMATE
A/E ESTIMATE.

BASED ON RATES AND LIFTS

0.88% OF GENERATED kW

VENDORS VALUE

0.5% OF GENERATED kW

         TOTAL AUXILIARY POWER =
NO. OF
UNITS
2
2
2
8
8
1
4
2
3
2
2
1
1
22
.2
TOTAL
MW
e
4.18
0.74
0.33
4.03
1.11
2.37
2.16
9.95
4.40
0.89
0.94
2.17
8.34
2.53
4.72
                                                                      39.86
                                    187

-------
                                   Table 67

                SOLIDS HANDLING  EQUIPMENT LIST AND COSTS--PFB
             Subsystems

COAL PROCESSING  & FEEDING

1 - Dryer System @  182-1/2  TPH
1 - Crusher  & 2  Screens
1 - Distribution Bin @ Crusher
2 - Vibrating Feeders ®  92  TPH
2 - Surge Bins @ 7600 ft3
2 - Bin Activators
2 - Feeders  (Vibrating)  (§365  TPH
2 - Coal Distribution Boxes
2 - Petrocarb Coal  Injector System
                    Section Subtotal =

DOLOMITE PROCESSING & FEEDING

1 - Dryer System @  84 TPH
1 - Crusher  & 2  Screens
1 - Distribution Bin @ Crusher
2 - Vibrating Feeders @  42  TPH
2 - Surge Bins 
-------
                                  Table 68

           HOT GAS CLEANUP AND AIR EQUIPMENT LIST AND COSTS—PFB
HOT GAS CLEANUP

16 -  Two in One Cyclones for Beds
 4 -145 ft3 Collecting Hoppers
32 -  Trickle Valves & Dip Legs
 8 -  Lock Hopper Seal Valves
 4 -  290 ft3 Lock Hoppers
 4 -  Fines Injection Systems
 4 -  Injection System Valves
 2 -  Two in One Cyclones for CBC
 2 -  290 ft3  Collecting Hoppers
 4 -  Trickle Valves & Dip Legs
 4 -  Lock Hopper Seal Valves
 2 -  580 ft3 Lock Hoppers
 2 -  High Temp. Feeders  (Vibrating)
 2 -  Surge Bins for Dust Coolers
 4 -  Airlock Valves for Dust Coolers
 2 -  CBC Dust Coolers
32 -  Granular Bed Filters
 4.-  Fines Letdown & Removal Systems
      for Granular Beds
                        Section Subtotal =
                                                    Cost in    Plant Requirement
                                                     1975 $    Number       M$
$ 8,127,592
    106,781
    228,880
    137,278  -
    173,161
    519,999
     68,639
    532,011
     86,579
     i8,860
     68,639
    170,301   '            '-.
     31,200               >
     40,404
     57,200
    260,000
 20,893,579

    721,499    _
$32,252,522    2        64.51
HIGH PRESSURE AIR

2 - Air  Dryer Precoolers
4 - Air  Dryers
4 - Booster  Compressors
4 - 400  ft3  Receivers 300#
4 - Air  Compressors  for Granular Beds
2 - 400  ft3  Receivers 400//
1 - Booster  Compressor Spare
1 - Air  Compressor Spare
                         Section Subtotal =
174,200
349,80.3
416,000
50,897
193,533
28,628
104,000
48,383
2
2
2
2
2
2
1
1
  1,365,444
2.58
                                   189

-------
                                 Table 69



             ,  HEAT EXCHANGE EQUIPMENT LIST AND COSTS - PFB





                                            M$ per Module         MS Plant



PFB heat  exchange and pressure parts             2.213



PFB containment shell and nozzles                0.566



PFB fuel  Injection  and air  parts                 0.237



PFB controls                      .              0.567



PFB petrocarb cooler economizer E                0.089
                                X


PFB module       '       .                       3.67               14.68



.Gas turbine economizers                         0.627               2.51
                                   190

-------
                                                  Table 70

                                MAJOR COMPONENT AND  SUBSYSTEM WEIGHTS AND COSTS
                                                  SUMMARY
                                 ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
Major Component or Subsystem

PRIME CYCLE

   STEAM TURBINE-GENERATOR
   (GENERATOR ALONE)

   PFB MODULE

   ECONOMIZER


PRESSURIZING SYSTEM

   GAS TURBINE-GENERATOR
     (GENERATOR ALONE)


Weight
(FOB)
M LB
6.5
(0.94)
0.57

0.44
0.49
(0.18)
Component or
Subsystem
Costs
(FOB)
M$
25
-
3.67

0.63
6.41



Output
Or
Duty
738.6 MW
e
244.1 MW,.
th
90.9 MW.,
th
51.25 MW
e

Cost Per
Unit
Output
Or Duty
33.85 $/kW
e
15.03 $/kW^.
tn
6.9 $/kW ,
125 $/kW
_ e


Cost
Per
LB
3.85
-
6.44

1.43
13.22
-
    HOT GAS FILTERING
16.13

-------
     Table 71 presents the characteristics of the PFB module heat exchange
and pressure containment parts and the gas turbine exhaust  economizer.  The
average heat flux is high compared to conventional boilers  and  is three times
the average for the AFB unit.   However,  the peak heat flux  is very much less
than peak values for conventional boilers.  As a result  of  these conserva-
tive values the PFB heat exchange surfaces are expected  to  have service life
far greater than the hottest parts of conventional furnaces and boilers-;.
The economizer operates with low heat exchange temperature  differences
that require very great surface area because of the low  heat flux.


Equipment List-Balance of Plant (1650)

     The specifications for the BOP equipment are listed in Table 72.  Elec-
tric motor drives for fans and pumps anticipate a margin of 10 percent flow,
20 percent pressure rise, and 30 percent power.   As a result these motors
are sized for continuous duty at levels above the 100 percent plant operating
point.
                                       .'      •** -

Capital Costs-Balance of Plant (1650 ?)      ^.
                                                                          tr~
     Table 73 presents the AE's detailed breakdown of the direct manual field
labor in thousands of man-hours, and of BOR.material cost in thousands of
dollars for each major category of the balance of plant.  In using these data
an average hourly field labor rate of $11.75 in mid-1975 dollars converts
man-hours to dollars.  Where field indirect labor is allocated to individual
items r.  ..sr than the total labor for the job,  it will be apportioned as 90
percent of the direct field labor cost or at a rate of $10.58 per direct
labor hour.  All material and labor costs are based on mid-1975 costs.

     The seven major categories used by the AE relate to the principal field
labor skills to be applied.  A modified subdivision of costs was made using
the following categories:

     1.  Land improvements and structures
     2.  Coal handling
     3.  Prime cycle plant equipment
     4.  Bottoming cycle (not  applicable to PFB plant)
     5.  Electrical plant and  instrumentation

     After the title of each item or major category in Table 73^ the
appropriate second category is given in parenthesis.
Plant Cost Estimates

     The installed costs of major system components are presented in Table
74.  Those elements related to  heat  release cost a total of $75 million.
They are the coal and solids  handling  equipment, the PFB furnace modules,
and the economizers.  TU,e steam turbine-generator along with its feedwater
heaters and pumps costs half  that amount.  The gas turbines with hot gas
filter system cost $95 million.

                                  192

-------
                                                        Table 71

                                             HEAT EXCHANGER CHARACTERISTICS
                                     ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
Heat Exchanger
PFB MODULE
ECONOMIZER
Output or Unit Unit Unit Heat .
Vessel Duty Per Efficiency 'Surface Weight Cost Flux
No. of Size or Unit or Area (FOB) (FOB) Average
Units Type M Btu Effectiveness Ft2 LB x 10~3 M$ Btu HE^Ft"2
4 13' dia x 116' 833 -, 22361 568.6 2.213* 37252
4 23' x 38' x 10' 310 0.92 179326 440 0.627 1726
    *HEAT  EXCHANGE AND PRESSURE PARTS ONLY
vo

-------
                            Tabli-,72  (page 1 of 4)

                      BALANCE OF PLANT EQUIPMENT LIST
           ADVAl,'CEi) STEAK PLANT, PRESSURIZED FLUIDIZED BED, 1650 F
EQPT.
 NO.
01

C-2

C-3

C-4

C-5

C-6

C-7

C-c

C-ll


C-12

C-13


C-14

C-15


C-16


C-17


C-18


O19
         SERVICE
          DESCRIPTION
                 1,  Coal, Dolomite and Ash Handling Systems
Coal Conveyor Belt
Dolomite Conveyor Belt
Vibrating Feeders for Car
Unloading (6 req'd)

Coal Belt Scale

Coal and Dolomite
Sampling System

Coal Lump Crusher (3 req'd)

Dolomite Lump Crusher
(3 req'd)

Magnetic Coal Cleaner
(3 req'd)

Magnetic Dolomite Cleaner
(3 req'd)

Coal and Dolomite Dust
Control System
C0? Fire Protection System
60 in wide,  344 ft long,  3000 tph,  365  hp

 "  "   "    575 ft   "     "   "    642  hp

 "  "   "    190 ft   "     "   "    420  hp

42 in   "   1000 ft   "    500 tph,  144  hp

 "  "   "    610 fr   "     "   "    ill  hp

60 in   "    375 ft   "   3000 tph,  163  hp

36 in   "   1035 ft   "    220 tph,   46  hp

             830 ft   "     "   "     36  hp
                                 it  ii   ii
Rating 0-750 tph
Dimension from Layout

0-3000 tph, 60 in Belt

0-3000 tph, 60 In Belt


0-10 tph, 10 in Lumps

0-10 tph, 10 in Lumps


500 tph


125 tph


4-6000 cfra Bag Type Dust Collector


Adequate to Service Item C-18 Bag-houses
                                    194

-------
                             Table 72 (page 2 of 4)
EQPT.
 NO.
         SERVICE
C-20   Vibrating Feeders for
       Dolomite Pile (4 req'd)

C-21   Vibrating Feeders for
       Coal Piles (8 req'd)

C-22   Coal Silos (8 req'd)

C-23   DoloTBite Silos (2 req'd)

C-24   Ash Storage Silos
       (6 req'd)
                                          DESCRIPTION

                                0-220 tph


                                0-200 tph


                                375 ton each

                                650 ton each

                                Total Volume 2,800,800 ft:
                                80 ft dia., 95 ft high
                            2..  Electrical Systems
E-l


E-2


E-3


E-4


E-5


E-6


E-7
Main Transformers
(2 req'd)
Unit Aux Transformer


Start-up Transformer


Auxiliary Diesel Generator
Miscellaneous 480/277 V
LCC Transformers (14 req'd)

4.16 kV LCC Transformers
(2 req'd)

Gas-Turbine Output
Transformers (4 req'd)
510 MVA, FOA 65°C
24/500 kV, 30, 60 Hz

24/13.8 kV, 30, 60 Hz
Double Secondary 24/24 MVA,  FOA 65°C

500/13.8 kV, 30, 60 Hz Split Secondary
Tertiary Winding at 24 MVA,  FOA 65°C

1000 kW, 30, 60 Hz,
480 V, 0.8PF, 1250 kVA

13.8 kV / 480/277 V, 30,  60
1680 kVA, FOA, 65°C

13.8 / 4.16 kV, 30, 60 Hz
8,000 kVA, 65°C

13.8 / 25 kV, 30, 60 Hz,  60  MVA,
FOA, 65°C, 54 MW
                                    195

-------
                             Table 72 (page 3 of  4)
EQPT.
 NO.
F-l
         SERVICE
Main Condenser
                                          DESCRIPTION
                            3.   Main Fluid Systems
F-2    Piping:
       Circulating Water
       Main Steam*
       Boiler Feedwater*
       Cold Reheater RHI*
       Hot Reheater RHO*
         5   2
3.81 x 10  ft  of heat  transfer area:
Std Materials in other  respects same as
AFB but with 9 of tubes scaled down in
proportion to heat transfer area.
                                I.D. = 123    in
                                I.D. =   6.31 in,  tm = 1.628 in
                                I.D. =   6.73 in,  tm = 1.077 in
                                I.D. =  11.59 in,  tm = 0.29 in
                                I.D. =  14.2  in,  tm = 0.631 in
F-3


F-4
F-5
F-6
F-7
Shell
Feedwater Heaters psia/°F
L.P. #1 6/171
UP. #2 13/205
D.F.T. 4.3 x
Main Condenser Pumps and
Motors (2 req'd)
Boiler Feed Pumps (3 req'd)
Turbine Driven
Main Circulation Pumps
and Motors (3 req'd)
Cooling Towers (22 cells)
Tube
psia/°F
160/166
160/200
106 Ibs/hr
640 hp,
9,850 hp
1920 hp,
234,200
Flow
Ib/hr
4. 06x1 O6
4. 06x1 O6
@ 250°F
Heat Tranj
Area ft4
17,315
13,928

jfer



4,300 gpm, 410 ft TDK
, 3,450 gpm,
90,000 gpm,
gpm
10,070 ft TDH
75 ft TDH



*Size based on flow at each boiler
                                    196

-------
                             Table 72 (page 4  of
EQPT.
 SO.
F-8


F-9
         SERVICE

Air Duct, Compressor to
PFB combustor, (one/PFB)
                                                 DESCRIPTION
30 In I.D.
Gas Duccs                       Steel Pipe with 9  in Refractory lining

  Manifold to PFB (one/PFB)     36 in I.D.

  Manifold to Cyclone (8/PFB)   20 in I.D.
         Cyclones to Granular
         B. F. (8/PFB)

         Granular Bed Filter
         to Turbine  (16/PFB)
                     (20/PFB)
                     ( 2/PFB)

F-10   Exhaust Stacks (2 req'd)
                                20 in I.D.
                                14 in I.D.
                                10 in I.D.
                                28 in I.D.

                              ;+17.5 ft  dia x  400 ft high
                                    197

-------
                            Table 7.3 (page 1 of 7)

                        BALANCE OF PLANT ESTIMATE DETAIL
           ADVANCED STEAM PLANT, PRESSURIZED FLUIDIZED BED, 1650 F
                                                Direct Manual
                                                 Field Labor
                                                  MH  1000's
           Balance of
         Plant Material
            $ 1000's
1.0  PFB STEAM GENERATORS C3)

     1.1   Steam Generator Erection

           Erect only (supply  by others):
           includes PFB tower  skirt;  PFB towers;
           piping connections  at tower; insulation

           Supply and erect: .
           includes tower access steel; miscel-
           laneous materials and labor operations

     1.2   Steam Generator Auxiliaries

     -     Erect only (supply  by others):
           includes coal and dolomite Petrocarb
           injection systems with injection air
           compressors and auxiliaries

     -     Supply and erect:
           includes support steel for Petrocarb
           systems; coal and dolomite piping
           from Petrocarb systems to  PFB towers

     1.3   Hot Gas Cleanup

     -     Erect only (supply  by others):
           includes cyclones;  hoppers and  surge
           bins; valves;  feeders and  injection
           systems; dust coolers;  granular bed
           filters; granular bed blowback  air
           compressors and auxiliaries

    --     Supply and erect:
           includes support steel for hot  gas
           cleanup equipment;  access  steel
 22
                 70
 22
221
  100
  890
 38
  100
 61
                                                      370
1,940
              3,100
                                    198

-------
                            Table 73 (page 2 of 7)
2.0  TURBINE GENERATORS (3)

     2.1   Steam Turbine Generator

     -     Erect only (supply by others):
           includes 732 MWe  steam turbine:
           generator; exciter; auxiliary  equip-
           ment; integral steam and auxiliary
           piping;  insulation; miscellaneous
           labor operations

     2.2   Gas Turbine/Compressor/Geno.rators

     -     Erect only (supply by others):
           includes gas turbine compressors
           with 50 MWe generators (4)
                                                 Direct Manual    Balance of
                                                  Field Labor   Plant Material
                                                  MH 1000's       $ 1000's
105
100
 40
100
                                                       145
                200
3.0  PROCESS MECHANICAL EQUIPMENT

     3.1   Boiler Feedwater Pumps (3)

     -     Supply and install:
           includes turbine-driven main feed-
           water pumps and drivers
           (3 9 $770,000 ea.)

     3.2   Main Circ. Water Pumps (3)

           Supply and install:
           includes main circ.  water pumps
           and motors (3 @ $265,000  ea.)

     3.3   Other Pumps (3)

           Supply and install:
           includes condensate  pumps and motors
           (2 @ $100,000 ea.);  and other pumps
           and drivers not listed elsewhere
              2,430
               830
                590
                                    199

-------
                       Table 73 (page 3 of 7}
                                            Direct Manual    Balance of
                                             Field Labor   Plant Material
                                              MH. 1.000'a       $ 1000's
3.8   Coal Handling
      Supply and erect:                            80           6,150
      includes railcar dumping equipment;
      dust collectors; primary crushing
      equipment; belt scale; sampling station;
      magnetic cleaners; mobile equipment;
      conveyors to pile; reclaiming feeders;
      conveyors and bucket elevators to dryers
      and grinders; recirculating conveyors at
      grinders; conveyors to Petrocarb; bucket
      elevators at Petrocarb            •*

3.10  Dolomite Handling (2)           *-                 ,
                                                                    tf
      Erect only (supply by others):               13             10
      includes dolomite dryers (3); support
      and access steel for dryers;  dolomite
      grinders (3); screens at grinders

      Supply and erect:                            43           2,240
      includes magnetic cleaners; conveyor  to
      dolomite pile; reclaiming feeders;  con-
      veyors to cascade; dolomite cascade;  con-
      veyors and bucket elevators to dryers;
      conveyors and bucket elevators to
      grinders; conveyors and bucket elevators
      to Petrocarb                                   :

3.11  Spent Solids Handling (2)

      Erect only (supply by others):               11             30
      includes spent solids valves; hoppers;
      feeders; fans; cyclones; conveyor to
      coolers; ash coolers (2)

-     Supply and erect:                            85           3,540
      includes ash cooler accessories and
      bucket elevators; ash conveyors;  ash
      storage silos (6) with feeders; unloaders
      and foundations; railcar loading equipment
                               200

-------
                            Table 73 (page 4 of 7)
                                                 Direct Manual    Balance of
                                                  Field Labor   Plant Material
                                                   MH lOOO's       $ 1000's
     3.12  Cooling Towers (3)
           Supply and erect:                             57           2,450
           includes mechanical  draft  towers
           with fans and motors

     3.13  Other Mechanical Equipment (3)

           Supply and install:                           34           1,820
           iijcludes water treatment and chemical
           injection; air compressors and auxi-
           liaries; fuel oil ignition and warm-up;
           screenwell; miscellaneous  plant equip-
           ment; equipment ins.ulation               	          	

                                                      535          26,200


4,0  ELECTRICAL (5)

     4.1   Main Transformers                            11           2,960

     -     includes main power  transformers and
           transformers at gas  turbine generators

     4.2   Other Transformers and Main Bus               18           1,240

           includes startup transformer; station
           service transformers; generator main bus

     4.3   Switchgear and Control Centers                25           2,050

     -     includes switchgear  and load centers;
           motor control centers; local control
           stations; distribution panels, relay
           and meter boards

     4.4   Other Electrical Equipment                 373           2,140

           includes communications; grounding;
           cathodic and freeze  protection; light-
           ing;  preoperational  testing
                                       201

-------
                            Table 73 (page 5 of  7)
                                                Direct Manual    Balance of
                                                 Field Labor   Plant Material
                                                  MH lOOO's       $ IQOO's

     4.5   Auxiliary Diesel Generator                   2             110

     -     includes  diesel generator,  batteries
           and associated d.c.  equipment

     4.6   Conduit,  Cable Trays,  Wire and  Cable
5.0  CIVIL AND STRUCTURAL

     5.1   Concrete Substructures  and
           and Foundations  (1)                         395           3,260

           includes turbine building substructure;
           PFB base mats; coal,  dolomite and ash
           handling foundations, pits  and tunnels;
           miscellaneous  equipment foundations;
           auxiliary buildings  substructures;
           miscellaneous  concrete

     5.2   Superstructures  (1)                         220           6,"130

     -     includes turbine building;  auxiliary
           yard buildings

     5.3   Earthwork (1)                               135             300

           includes building excavations; coal,
           dolomite and ash handling excavations;
           circ.  water system excavations; PFB
           foundation excavations;  miscellaneous
           foundtion excavations;  dewatering and
           piling

     5.4   Cooling  Tower  Basin  and Circ.
           Water System (3)                            100           1,510

           includes circ. water pump pads, riser and
           concrete envelope for pipe; cooling tower
           basin; circ. water pipe; cooling tower
           miscellaneous  steel  and fire protection   	          	
                                                      850          11.20P

                                    202

-------
                           Table 73  (page 6 of 7)
                                                Direct Manual    Balance of
                                                 Field Labor   Plant Material
                                                  MR lOOO's       $ lOOO's

6.0  PROCESS PIPING AND INSTRUMENTATION

     6.1    Steam and Feedwater Piping  (3)               50           2,400

  *•  -     includes main  steam; extraction steam;
           hot  reheat; cold  reheat; feedwater and
           condensate large  piping, valves and
           fittings

     6.2    Hot  Gas Large  Pipe  (3)                      120           .5,700

     -     includes PFB compressed air feed; PFB
           hot  gas discharge; cyclone  and granular
           bed  filter piping;" gas turbine inlet
           piping                      .                                   ^

     6.3    Other Large Piping  (3)         ^            195           3,350

     -     includes auxiliary steam; process water;
           auxiliary systems; spent solids piping

     6.4    Small Piping  (3)                            125           1,100

           includes all piping, valves and fittings
           of 2-inch diameter and less

     6.5    Hangers and Misc. Labor Operations  (3)      390           1,000

           includes all hangers and supports;
           materials handling; scaffolding;
           misc. labor operations

     6.6    Pipe Insulation  (3)                          40

     6.7    Instrumentation and Controls  (5)            230

                                                    1,150
                                    203

-------
                           Table 73  (page 7 of 7)
                                                Direct Manual    Balance of
                                                 Field Labor   Plant Material
7.0  YARDWORK AND MISCELLANEOUS  (1)

     7.1   Site Preparation and  Improvements

     -     includes  soil  testing; clearing and
           grubbing;  rough grading;  finish
           grading;  landscaping

     7.2   Site Utilities

     -     includes  storm and  sanitary  sewers;
           nonprocess service  water

     7.3   Roads and Railroads

           include railroad spur; roads, walks,
           and  parking areas

     7.4   Yard Fire Protection, Fences and Gates

     7.5   Water Treatment Ponds

     -     includes  earthwork; compacted-clay
           lining; offsite pipeline

     7.6   Lab, Machine Shop and Office Equipment
                                                  MH 1000's
  38
             $  1000's
  27




  52

  12




	1

 135
   10
   50




  750




  600

   10




  280

1,700
                                    204

-------
                     Table 74

MAJOR COMPONENT AND SUBSYSTEM CAPITAL COST SUMMARY
  ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
                      1650 F

Major Component or Subsystem
• FUEL HANDLING & PREPARATION
COAL AND SOLIDS HANDLING
PRIME CYCLE
S3
01 STEAM TURBINE-GENERATOR
PFB MODULES
ECONOMIZER
PRESSURIZING SYSTEM
HOT GAS FILTERING
GAS TURBINE

No. of
Units
3/2
1
4
4
4
4
Cost/Unit
(FOB)
M3

25.00
3.67
0.63
16.13
6.41
Component or
Subsystem
Costs
• (FOB)
M$
32.23
25.00
14.68
2.51
64.51
25.62
BOP+
Materials
M$
11.98
0.10
1.06
0.18
2.04
0.10
Site+
Labor
(Direct +
Indirect
MS
5.67
2.34
6.05
0.45
2.21
0.89
Total
Installed
Cost
M$
49.88
27.44
21.79
3.14
68.76
26.61

-------
     The  total costs using t:he AE's categories ate presented In Table 75.
The home  office and fee of 15 percent is applied only to the BOP costs.
A contingency of  20 percent of all prior costs is applied to coyer
expected  costs not specifically included in the original estimating pro-
cess.  The total  plant cost of $421 million represents $446/kW based on
total generation, or S466/kW based on net station output.

     A reconstruction of'costs according to equipment function is pre-
sented in Table  76.  Items 1 through 6 include everything in the preced-
ing table.  I:em 7 adds the value of escalation and interest during the
5.5-year  construction time.  This iteis. is 54.8 percent of the prior total.
The result is a  final plant cost of $693/kW of total generation or $723/kW
of net station output.
                         6         e

                                    206

-------
                                                        Table 75
                                        BALANCE OF PLANT CAPITAL COST.BREAKDOWN
                                    ADVANCED STEAM CYCLE-PRESSURIZED FLIUDIZED BED
                                                         1650 F
Categories*                                   Components

1.0  PFB STEAM GENERATORS & HOT GAS FILTERS

2.0  TURBINE GENERATORS

3.0  PROCESS MECHANICAL EQUIPMENT

4.0  ELECTRICAL

5.0  CIVIL AND STRUCTURAL

6.0  PROCESS PIPING AND INSTRUMENTATION

7.0  YARDWORK AND MISCELLANEOUS
                Costs (Millions  of Dollars)

Direct Labor (1)   Indirect  Field  (2)   Materials  (3)   Total
to
o
79.19
50.62
34.74




164.55





4.35 . 3.91
1.70 1.53
6.29 ' 5.66
9.52 8. :7
9.99 . 8.99
13.51 12.16
1.59 1.43
46.95 42.25
B.O.P. LABOR, MATERIALS & INDIRECTS 162.70
(SUM OF 1 -f 2 + 3)
A/E HOME OFFICE & FEE @ 15%
TOTAL PLANT COST
CONTINGENCY @ 20%
TOTAL CAPITAL COST
3.10
.20
26.20
11.00
11.30
20.10
1.70
73.50





90.55
54.05
72.89
29.09
30.18
45.77
4.72
327.25

24.41
351.66
70.33
421.00

-------
                                        Table 76

                           PLANT CAPITAL COST ESTIMATE SUMMARY
                               (APPROXIMATE DISTRIBUTION)
                    ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
                                         1650 F
                                         Major
                                      Components
                                       Materials
                                          M$

1.0  LAND IMPROVEMENTS & STRUCTURES
     (LAND,  PLANT AREA 108 ACRES)
     (LAND,  30-YEAR DISPOSAL 0 ACRES)

2.0  COAL HANDLING                         32.2

3.0  PRIME CYCLE PLANT EQUIPMENT          132.3
     STEAM CYCLE/PRESSURIZED FLUIDIZED
      BED
     738.6 MWe
     PRESSURIZING GAS TURBINE  -
     205.0 MWg

4.0  BOTTOM CYCLE NOT APPLICABLE

5.0  ELECTRICAL PLANT & INSTRUMENTATION     0
        SUBTOTAL                        164.5

6.0  A-E SERVICE & CONTINGENCY

7.0  ESCALATION & INTEREST DURING
     CONSTRUCTION
Balance
Of Plant       Site Labor
Materials   (Direct & Indirect)   Total
                                  H$
 M$

11.8



12.0

33.4
  16.2
  74.4
 M$

19.8



 5.7

39.6
                23.2
                88.3
                                                                 TOTAL M$
                                                                 PLANT OUTPUT MW
                                                                 TOTAL $/kW
                                  31.6



                                  49.9

                                 205.4
                39.4
               327.2

                94.7


               231.2

               653.1

               903.3

               722.S
                                           208

-------
6.  NATURAL RESOURCES AND ENVIRONMENTAL INTRUSIONS

Natural Resources

     Table 77 shows the natural resource requirements for the PFB plant.  The
consumption of coal for the PFB advanced steam power plant was 10 percent
less than that for the AFB power plant, but the substitution of dolomite for
limestone increased the sorber.t requirement by 63 percent.  The PFB requires
6 percent more pounds of material than the AFB per kilowatthour delivered
when fuel and sorbent are totaled.

     Water usage would be reduced for the PFB by 10 percent as compared to
the AFB.  This results from the procuction of gas turbine power that
requires no coolant.  Land area was comparable for the plants.


Environmental Intrusion
              t
     Table 78 enumerates the environmental intrusions of the PFB power plant.
The sulfur emission is well below the mandated new Source Performance Standards
for coal-fired boilers limit of 1.2 Ib/MBtu of heat input; the nitrogen
oxides are one-third of current- limits.  The major heat rejection is from the
cooling tower.  The stack heat rejection is greater than that for the AFB
because the stack temperature was 300 F rather than 250 F.

     The composition of the dry granular spent solids shows the effect of
use of twice the ideal requirement for dolomite.
Trace Elements

     To data experimental determination of trace element emissions from PFB
combustion has not been made.  Critical factors  are the low bed temperature
of  1650 F in the main beds and 2000 F in the CBC.    These  temperatures are
below slagging temperature and are close to those found in the AFB.  The dis-
cussion of trace elements for the AFB would be fully applicable to expectations
for the PFB.  Some differentiation should be expected when appropriate tests
are made on each type.

     One important differentiation is that the gases from  the PFB are held
at  high temperature and then abruptly dropped to 912 F by  expansion through
the gas turbine followed by cooling to 300 F in  the gas turbine economizer.
Volatile trace elements with dewpoints above 300 F should  condense out in the
gas turbina and its economizer.
                                   209

-------
                        Table 77

            NATURAL RESOURCE REQUIREMENTS
  ADVANCED STEAM CYCLE - PRESSURIZED FLUIDIZED BED
     SORBENT OR SEED, LB/kWh
       DOLOMITE

     COAL, LB/kWh

     WATER, TOTAL (GAL/kWh)
       COOLING
          EVAPORATION
          BLOVDOWN
       PLANT GENERAL USE
       CONDCNSATE MAKEUP

     TOTAL LAND, ACRES/100 MW
       MAIN PLANT            e
       DISPOSAL LAND
                         Table 78
                                                VALUE

                                                0.3715

                                                0.8076
                                                0.405
                                                0.127
                                                0.016
                                                0
                                                12
                                                14
               ENVIRONMENTAL INTRUSION
   ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED  BED
EMISSIONS

S02
 Ox
1C
CO
PARTICULATES

THERMAL POLLUTION
                                                    LB/MBtu
                                                     INPUT

                                                     0.688
                                                     0.152*

                                                     0.020
                                                     0.100
         HEAT REJECTED, COOLING TOWERS,  Btu/kWh
         HEAT REJECTED, STACK, Btu/kWh
         HEAT REJECTED, TOTAL, Btu/kWh

         WASTED

         SPENT SOLIDS CONGLOMERATE
             42% ASH COMPOUNDS
             26% CALCIUM SULFVT.
             16% MAGNESIUM 0X1' /
             13% UNREACTED LIME
              4% UNBURNED CARBON

         WATER DISCHARGE'                             l.lq

*3ased upon available data, EPA believes that  the  NOX emission
 more typically be in the range of 0.1-0.4  LB/MBtu.
LB/kWh
OUTPUT

0.0060
0.0013

0.0002
0.0009
                                                          951
                                                         5300

                                                       MLR,/DAY

                                                         7.43
                                                        25.9

                                                     level will
                         210

-------
7.  SUMMARY PERFORMANCE AND COST

     Table 79 summarizes the system performance and cost for the PFB—
Advanced Steam plant with 1650 F main beds.  The overall energy efficiency
of 39.2 percent is appreciably above the  level of 35.8 percent for the AFB
plant.  However, the plant cost per kilowatt of $723 is $100 greater than
the AFB value.  It should be noted  that major contributors to the PFB capital
cost are the granular bed filters for cleaning the hot pressurized flue gas
($64.5 M uninstalled) and the high  pressure solids handling system ($32.2 M
uninstalled).  The resulting increase in  the capital portion of the cost of
electricity (COE) is greater than the reduction in the fuel portion.  The
total result is an increase of 2 mills/kWh over the COE for the AFB.

     The sensitivity of the cost of electricity to variation of major cost
factors is presented in Table 80.
                                   211

-------
                    Table 79



         SUMMARY PERFORMANCE AND COST

ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED

                     1650 F
                  ITEM



NET POWER PLANT OUTPUT (MW  - 60Hz - 500 kV)           903.8
                          e


THERMODYNAMIC EFFICIENCY (%)                            41.3



POWER PLANT EFFICIENCY (%)                              39.2



OVERALL ENERGY EFFICIENCY (%)                           39.2



COAL CONSUMPTION  (LB/UWH)                                o.sos



TOTAL WASTES (LB'/kWH)                                    0.343



PLANT CAPITAL COST ($ MILLION)                        6653.3



PLANT CAPITAL COST ($/kW )                             722.9
                        e




COST CF ELECTRICITY, CAPACITY FACTOR = 0.65



     CAPITAL                          (MILLS/kWH)       22.9



     FUEL                             (MILLS/kWH)        8.7



     MAINTENANCE  & OPERATION          (MILLS/kWH)        2.5



     TOTAL                            (MILLS/kWH)       34.1



ESTIMATED TIME OF CONSTRUCTION (YEARS)                   5.5



APPROXIMATE DATE  OF FIRST COMMERCIAL SERVICE          1987  - 1989
                        212

-------
                    Table 80

     COST OF ELECTRICITY (COE) SENSITIVITY
ADVANCED STEAM CYCLE-PRESSURIZED FLUIDIZED BED
COE,
COE,
CAPITAL
FUEL
COE, O&M
TOTAL COE
Base
Capacity
Factor
0.65
22.9
8.7
2.5
34. 1
Fuel
Cot*;
Increase
50%
22.9
13.1
2.5
38.4
Labor
Cost
Increase
20%
24.2
8.7
2.5
35.5
Materials
Increase
20%
26.1
8.7
2.5
37.3
Capacity
Factor
Change
0.5 & 0.8
29.7 18.6
8.7 8.7
2.6 2.4
41.0 29.7
                       213

-------
 8.  PFB ALTERNATIVE ffl  (1750 F)

      In addition to the basic plant of Figure 27 with 1650 F beds, a PFB
 power plant with 1750 F main beds was evaluated.  The intent was to minimize
 the changes from the basic plant concept so that the differences in performance
 and cost could  be  sharply defined.  The PFB, gas turbines, hot gas filters,
 feedwater heaters  and economizers, and steam turbine cycle were components
 subject to major variations.

      The specifications for the PFB module retained the identical fuel rate
 and the identical  air flow for combustion at the PFB as in the base case.
*Ihe gas flow  into  the gas turbine was identical to the former cise; only
 the inlet temperature was increased from 1600"F to 1700 F. •.
 PFB Tower  Costs               ,_. ••

      The PFB tower would increase from 13 ft diameter to 13.5 ft diameter;
 The height of 116 ft would be unchanged.  T-fee bed dimensions would  increase
 from 8.5 ft on each side to 8.75 ft on each side.  These changes would  .
 increase the cost of the FFB towers by $250,000 for the total plant.
 Hot Gas Cleanup  Costs
               *                        AC

      The ducting and cyclonfe separators for the hot gas flow would  be
 unchanged.   The  granular bed filters must increase in size and cost to
 experience  the same face velocity with the greater volume of gas flow.
 This ratio  is  1.0485.  As a result the granular bed filters and the air
 compressors that service them will have an added cost of $2,040,000.  An
 audit of pressure loss from compressor outlet to gas turbine inlet  shows
 that the 7.5 psi loss would then become 7.35 psi.
 Gas Turbine  Cost

      The gas turbine  flows and power were derived by scaling up the  1700 F
 gas turbine  applicable to the PFB for the ECAS potassium topping cycle  so
 as to match  exactly the air required by the PFB in this instance.  The  gas
 turbine  generation became 55.682 MW.  The cost for the gas turbines  was
 scaled at $125/kW to  arrive at an added cost of $2,216,000 for the four gas
 turbines required by  each plant.  Table 81 gives a comparison of gas turbine
 characteristics.  The configurations would have the same general dimensions
 as the base  case.  Pressures at each station would be identical, as  would
 the air  delivery temperature of 597 F to the PFB.
 Steam Turbine-Generator Cost

      A heat balance on the PFB towers, the Petrocarb cooler economizers,
 and  the gas turbine economizers shows a total heat input to the steam cycle
 of 5984 MBtu/hr; th
-------
                           Table 81




         GAS TURBINE PERFORMANCE AND COST  COMPARISON






PFB main bed temperature                    1650 F       1750 F




Gas turbine inlet temperature               1600 F       1700 F




Compressor inlet air flow,  Ib/s             525.75       530.19




Air flow to PFB, J.b/s                       504.72       504.72




Gas flow back to turbine,  Ib/s              551.16       551.16




Exhaust gas flow, Ib/s                      571.13       576.58




Exhaust temperature                         849.9 F      912.4 F




Generator output, MW                         51.25        55.682




Unit cost, M$                                 6.41         6.74




Number per plant                              4            4




Exhaust heat to 300 F, MBtu/hr              309.56       335.33
                                 215

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 i                         Table 82



               PFB HEAT SOURCES FOR STEAM CYCLE





          Source	MBtu/hr	



PFB main bad temperature                    1650 F       175Q F



4 Petrocarb cooler economizers, E              22           22
                                A


4 Gas turbine economizers, E                1238         1341



4 PFB towers                                4844         4621



Total heat to steam cycle                   6105         5984



Total heat ratio to 1650 F case                 1.0          0.980
                           216

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     For a 1750 F PFB cycle as described by Figure 27,  the steam turbine
output would become 723,960 kW.   The difference of 14,673 kW less would
reduce steam turbine~generator cost by $210,000 at the  rate of $14.3/kW.


Gas Turbine Economizers

     The gas turbine economizers will receive  hotter  gas and deliver hotter
water.  A heat balance was made to determine these resulting temperatures
and to arrive at the log mean temperature difference  for.heat exchange.
The heat exchanger cost was then proportioned  directly  with heat duty and
inversely with log mean temperature difference.  The  assumption of the same
heat transfer coefficient and a constant ratio of  cost  per unit area are
justified for such a modest change in conditions.   Table 83 details this
evaluation.

     The cost difference for the total plant for gas  turbine economizers
would be an increase of $145,000.
Balance-of-Plant Costs
                                            >*"
     BOP cost items may be affected by any of the  following ratios:

          Hot gas cleanup size ratio      *••              1.0485
          Steam turbine size ratio                        0.980135
          Total and net generation ratio                  1.0034
          Economizer size ratio                           1.0581

     The BOP items were adjusted by these ratios as shown in Table 84.


PFB Net Generation (1750 F)

     A detailed auxiliary loss breakdown was made  with no change it: PFB
auxiliary losses, steam turbine and heat rejection elenents'scaled by a 0.98
factor, and generation-related factors scaled by 1.00V' relative to losses
shown in Table 31.  The total loss was 39.87 as compared to 39.86 formerly.
Net station output could then be evaluated as indicated in Tabl1? 85.


PFB Net Plant Cost (1750 F)

     Table 86 summarizes the several changes in major component and BOP
costs,  applied fee, contingency, and other factors to arrive at the net
station dollars per kilowatt.
Cost of Electricity Comparison

     Table 87 compares the COE for the two  cases.  The efficiency, coal
consumption,  and fuel cost of electricity will  be virtually the same.  The
major change  was due to increased capital cost.

                                   217

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                               Table 83

                    ECONOMIZER DESIGN AND COST BASIS
     Bed temperature

     Heat duty^ MBtu/hr

     Gas T in/T out

     Water T in/T out

     Difference in temperatures

     Log means temperature difference

     Cost per unit, M$
      1650 F       1750  F

       309.56       335.25

    865 F/300 F  912.4 F/300  F

    537 F/250 F  559.2 F/253.5 F

    328 F/50 F   353.2 F/46.5 F

      H7.79 F     151.26 F

        0.627        0.66346
                                Table 84

          BOP ADJUSTMENTS FOR 1750' PFB FROM 1650 PFB BASE CASE
             BOP Items


1.3  Hot gas cleanup (a)
                     (b)
3.2  Main circulating pumps
3.4  Main condensers
3.5  Heaters, Exchangers
3.12 Cooling towers
4.0  Electrical
5.4  Cooling tower basins
6.1  Steam and feedwater  piping
6.3  Other large pipes

Total difference in MH 1000's

Total difference BOP Mat

Direct labor at 11.75 $/hr

Indirect labor at 10.58 $/hr

Total BOP change

Former BOP cost

New BOP cost
     Changes
-1
             -149

             - 12

             - 10

             -171

          162 700

          162 529
Factor
MH 1000's
+1.84
+2.96
_
-0.54
-
-1.13
+2.73
-1.99
-0.99
-3.87
Mat. $1000's
+ 4.85
+94.09
-16.49
-47.08
-28.80
-48.67
+37.16
-30.00
-47.68
-66.53

1.0485
1.0485
0.9801
0.9801
0.9801
0.9801
1.0034
0.9801
0.9801
0.9801
                                   218

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                           Table  85

             POWER GENERATED BY PFB POWER PLANTS
Gas turbine generation

Steam turbine generation

Gross generation

Auxiliary power loss

Net station output
                                            Power Generated at
                                        2 Main Bed Temperatures (HW)
1650 F

 205.0

 738.6

 943.6

  39.9

 903.8
1750 F

 222.7

 724.0

 946.7

  39.9

 906.8
                              219

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                                Table 86

                      SUMMARY COSTS FOR 1750 F PFB



               Item Changed

Balance-of-plant cost

Steam turbine generator

Gas turbine generators

PFB towers

Hot gas filters

Gas turbine economizers

Subtotal, all changes

1650 F Case total
                                        *~
1750 F Case total

AE home office & fee 
-------
                               Table 87


                COMPARISON OF COST OF ELECTRICITY - PFB
            I



    Main be
-------
9.   PFB ALTERNATIVE //2-HIGH EFFICIENCY  (1750 F)

     A greater  efficiency may be gained from the PFB cycle If the steam tur-
bine cycle has  high-temperature £eedwater heaters that operate on part of
the feedwater flow.   The balance of the flow would be heated by a gas feed
heater (GFH) which is truly the low-temperature portion of the gas turbine
economizer.  Then the total feedwater flow would enter the high-temperature
portion of the  gas turbine economizer.  This arrangement is Identical to
that used for the EGAS potassium topping steam PFB and gas turbine cycle.
The economizers must  have increased surface area and cost as a result of
their lowered mean effective temperature difference.  The total heat avail-
able to the  steam cycle is unchanged.  The PFB would have altered propor-
tions of heat exchange surfaces because of increased feedwater temperature
of 640 F.  The  PFB configuration,  size, and cost are not expected to differ
from the 1750 F case  discussed previously.  Major changes are found in the
economizers, the  steam turbine cycle, and parts of the balance of plant.  These
changes are  most  readily understood by examining the steam turbine cycle first
and then the gas  turbine economizers.
Steam Turbine Cycle and Heat  Balance

     The steam curbine heat balance presented in Figure 37 is more nearly
like the APB turbine cycle than  it is like the PFB turbine cycle of Figures
26, 27,  and 31.   The feedwater flow is split after the third low-temperature
heater.   Four high-pressure feedwater heaters pass 56.5 percent of the total
feed-water flow.   The Petrocarb  compressor cooler (PCC) h°fts 1.6 percent of
the total feedwater flow.  The gas feedwater heater  (GFH) cools the gis tu>--
bine exhaust from 560 F to 300 F while heating 41.9  percent of the total
feedwater flow.   All of these heaters deliver feedwater at 505 F.  The total
feedwater flow then passes through the gas turbine economizer where the gas
cools from 912.4  F tc 560 F as the feedwater is heated from 505 F to 640 F.
The distribution  of feedvater flow and heat duty are detailed in Table 88.

     The increase in steam turbine output results in an increased component
cost of  $22,000 at $14.28/kW.

     The cost of  the feedheater  train must be derived from the AFB steam
cycle, which was  similar.  It was determined that feed-heater surface aiea
varied linearly with heat duty for both high-pressure and low-pressure
units.  The heat  duty for the seven-feedwater heaters using extraction
steam in Figure 37 is 0.5534  of  the heat duty for the A7B steam turbine
cycle.  The. flows and duties  of  the low-pressure feedwater heaters of the
steam cycle bear  a ratio of 0.9027 to the AFB cycle.  The cooling duty is
a ratio  of 0.945  to the base  PFB steam turbine cycle.  Other significant
ratios were derived from the  appropriate flows, powers, and heat duties
of the steam cycles.
Gas Turbine Economizer Cost

     Economizer size and cost were  estimated on a preliminary basis by the
Foster Wheeler Energy Company,   When  final values for heat duty and log

                                     222

-------
ro
U)
                                                                                                  If. li - Kn*l.*l|ir •
                                                                                                       vBiir*. PiU

                                                                                                  F - Temperature. F d«|r«at
                                                                                                               GKNERAIOII OUTPUT

                                                                                                                  740,153 M

                                                                                                                 Tl PSIC II2 PR CSS.

                                                                                                                      0. It PF
                                                                                         1 |(W I. 2. )•• llc. AI.>. 0% MU

                                                                                     TC-IK. »*. '/' I.SH  luuu ttl'M


                                                                                     IMIO I'.'illi lUUU/IOUil-r'
                        Figure 37.   High  Efficiency  1750  F  PFB Plant Steam  Turbine  Cycle Heat Balance

-------
                                Table  88

                    HEATING DUTY FOR HIGH EFFICIENCY
                          PFB PLANT STEAM CYCLE
                                                Heat Duty       Flow
            Heat Exchanger                      (MEtu/hr)   (% of feed)

PFB to reheater                                  1071.0          94.1

PFB to superheat                                 3549.73        100.0

Gas turbine economizer                            787.8         100.0

Gas turbine gas feed heater                       535.55         41.90

Petrocarb compressor cooler     .                   21.65          1.64

Steam turbine high-pressure feed heaters             -           56.46

Total heat to steam cycle                        5983.73
                                   224

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mean temperature difference (LMTD) were available,  the preliminary size
and cost were scaled up or down appropriately,  as shown in Table 89.

     The plant economizer component cost difference would be $4.41 million
which is four times the per unit difference of  Table 4,2-29.  The erection
man-hours and BOP materials related to the economizers were scaled'from the
1650 F PFB case using the total heat exchange surface area ratio of 2.58 as
the scaling factor..


Balance of Plant Adjustments

     BOP cost items were proportioned to comparable heat duty, flow rate,
or power level for the 1650 F PFB or the 1550 F AFB as was deemed most
appropriate.  The comparison source, AFB or PFB, and the ratio used are
indicated in Table 90 along with the changes in man-hours of .direct labor
and materials cost.  Item 6.3, "Other large pipe,"  was scaled to the steam
turbine cycle flows after the reheat turbine at pressure levels below 200
psia.  Item 3.5, "Heaters, exchangers; Economizer erection,11 was subdivided
into economizer-related costs, and steam turbine cycle steam-heated feedwater
costs.  The scaling factor for the latter was 0.553 based on the ratio of the
heat duty of the feedheater trains.
                                        T*~                *'      •
                                                                     <>~

Auxiliary Loss and Net Generation
-                                      ^i* •

     The auxiliary losses of Table 66 were reapportioned using the same
basic ratios as were used- for the BOP adjustments.  Since all ratios must
be referred to the 1650 F PFB case and not to an AFB, items related to flows
or condenser heat duty in the low-pressure portion  of the plant used the ratio
0.945.  The furnace items have been grouped in  Table 91 sirce they are identical
to the values of Table 66.  The closeness of the final results is due to the
offsetting effects of the many changes.

     The net generation and efficiency improvement  shown in Table 92 result
from the increased steam turbine output resulting from the more elaborate
feedwater heating system.


Net Plant Cost

     Table 93 summarizes the several changes in major component and BOP
costs.  The fee and contingency and escalation  and  interest during construc-
tion are added to find the total expenditure for the plant.  Division by
the net station output gives the cost of $728/kW.


Cost of Electricity Comparison

     Table 94 summarizes the effect on the cost of  electricity for the sev-
eral alternatives of PFB power plants.  The 1750 F  cases entail greater cost
for the gas turbine and the hot gas filters.  The output change is minimal for
                   e          o

                                    225

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                                Table  89

                 PFB GAS TURBINE ECONOMIZERS  COST BASIS
                                      Heat  Duty     LMTD       Area       Cost
     Heat Exchanger                   (MBtu/hr)      (°F)       (ft2)
1650 F PFB economizer                   309.6       147.8     179,326    0.627

1750 F PFB economizer preliminary       197.5       145.3     135,946
                                                                        1.724
       GFH preliminary                  138.8       135.8     304,357

1750 F PFB economizer         "• -       197.0        57.0     145,080
                                                                        1.730
       GFH final                        '138.4        58.4     296,230
                                   226

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                                     Table 90

               BOP ADJUSTMENTS FOR 1750 F PFB HIGH  EFFICIENCY PLANT
                             FROM 1650 F PFB BASE CASE
                                                              Labor      Material
Source                  Item             Ratio              (MH:lOOP's)   ($ 1OOP's)

PFB      1.3   Hot gas cleanup           1.0485  (a)            4- 1.84     +     4.85
                                                (b)            + 2.96     +    94.09

AFB      3.1   Boiler feedpumps          0.786                   -       -f   100

AFB      3.2   Main circulating punips    0.903                   -       -   117

AFB      3.4   Main condenser            0.903                - 3        -    95

AFB      3.5   Heaters, exchangers       0.553 (Part only)        -            22

PFB      3.12  Cooling towers            0.945                - 3        -   134

PFB      5.4   Cooling tower basins      0.945                - 5.5      -    83

PFB      4.0   Electrical                1.020                +16.5      +   224

PFB      6.1   Steam & feed piping       1.091                +4.6      +   217

PFB      6.3   Other large pipe          0.945                -10.7      -   184

PFB      6.5   Economizer erection       2.58 (Part only)      +31.6      +   284.4

    Total difference, MH 1000's                               +35.3

    Total difference, BOP materials                                      +   289

    Direct labor at $11.75/hr                                            +   415

    Indirect labor at $10.58/hr of direct labor                           +   373

    Total BOP change from 1650 F to 1750 F,  high efficiency               + 1,078

    Former BOP cost                                                      162,700

    New BOP cost, 1750 PFB, high efficiency                               163,778
                                        227

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                                Table 91
               ADVANCED STEAM—PRESSURIZED FLUTDIZED BEDS
     Plant Configuration

Furnace auxiliaries
**
Solids handling
Steam turbine auxiliaries
Gas turbine auxiliaries
Pumps
     Condensate
     Circulating water
     Service water
     Intake water
"Hotel" loads
Cooling tower fans
Transformer loss        :,

Total auxiliary power
   Auxiliary Loads at 3
Main Bed Temperatures (MW)
1650 F    1750 F    1750 F
 Base      Base   High eff
10.39
 2.17
 2.37
 2.16
 0.95
 4.40
 0.89
 0.94
 8.34
 2.53
 4.72
39.86
10.39     10.39
 2.17      2,17
,.2.32      2.37
 2.35

 0.93
 4.31
 0.89
 0.92
 8.37
 2.48
 4.73
39.87
 2.35

 0.90
 4.16
 0.89
   *~
 0.88
 8.51
 2.39
 4.82

39.83
                                    228

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                                Table 92
             POWER GENERATED BY PFB POWER PLANTS—SUMMARY
     Plant Configuration

Gas.turbine generation
Steam turbine generation
Gross generation
Auxiliary power consumption
Net station output
Overall tnergy efficiency
     Power Generated at  3
Main PFB Bed Temperatures (MW)
 1650 F    1750 F     1750 F
  Rase      Base     High eff
  205.0     222.7     222.7
  738.6     724.0     740.2
  943.6     946.7     962.9
   39.9      39.9     39.8
  903.8     906.8     923.1
   39.2%
39.3%
40.0%
                                   229

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                           Table 93




     SUMMARY COSTS FOR 1750 F PFB HIGH EFFICIENCY PLANT






        Item Changed                             Change (M$)




Balance of plant cost                              +1.078




Steam turbine-generators                           +0.022




Gas turbine-generators                              2.216




PFB towers                                           .25




Hot gas filters                                     2.04




Gas turbine economizers                             4.41





Subtotal all changes                               10.02




1650 F case total                                 327.25
1750 F high efficiency total                      337.3




AE office and fee @ 0.15 x 163,8                   24.6





Total plant cost without contingency               361.8




Contingency at 20%                                 72.4





Total capital cost                                434.2




Escalation and interest during construction        237.9





Total expenditure for plant                       672.1 M$




Plant net output                                  923   MW




Specific cost                                     728   $/kW
                              230

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                                Table 94



      COMPARISON OF COST OF ELECTRICITY FOR PFB PLANT ALTERNATIVES





                                                   Cost of Electricity at 3

                                                   Main Bed Temperatures


     PFB Plant Configuration                      !Lf ° F   "^ F    ™ !f
     	°	!—                       Base     Base    High eft



Plant capital cost $kW                            723      729       728



Overall energy efficiency                          39.2     ,39.3      40,0



Cost of electricity, mills/kWh

     Capital                                       22.3     23.1      23.0



     Fuel                            ,..:      .«-     8.7      8.7       8.6



     Operation and maintenance                     2.5      2.5       2.5
                                          7*-                 *•      :      ' '


     Total                                        34.1      34.3      34.T[



   Basis:  5.5 Years to Construct; 0.65 Capacity Factor
                                   231

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a fixed steam turbine cycle configuration.  The more complex plant cycle with a
gas feedheater operating in parallel with steam feedheaters gains in efficiency
and reduces the total cost of electricity at 1750 F.  A similar finding would
be expected at 1650 F.  The differences  in cost of electricity are small as is
.the 2-percent savings in fuel at the extreme.  Other factors should dictate the
plant configuration and design specifications vhen the impact of appreciable
changes in temperature level and complexity bring such small changes in
efficiency and cost of electricity.
                                    232

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E.  PLANT CONCEPTUAL DESIGN AND BALANCE-OF~PLANT COST

1.  TOTRODUCTION

     The primary objective of the balance of plant portion was the achieve-
ment of a consistent level of detail and the development of compatible
capital cost projections.   In order to achieve this objective, similar
subsystems were employed for the common cycle elements and consistent ground-
rules and costing methodology were used.

     In an attempt to itemize balance-of-plant capital costs, symmetrical
arrangements were used for the major components.  This permitted employment
of the shortest runs of high-temperature piping.  To the greatest possible
extent, existing technology was utilized for the common subsystems.

     The groundrule criterion which had a significant influence on the plant
layout was a requirement for a 60 day on-site storage of fuel.  The fuel was
assumed to be delivered.to the plant site by unit train.

     Off-site solid waste disposal was assumed with removal fro™, the plant
site by train or track.  A 15-day interim on-site storage was provided for
the solid waste.

     The "North River" was available for obtaining the plant makeup water
supply.  Waste w?ter was treated before returning to the river for discharge.
There was no thermal rejection into the river.

     In most respects, the balance-of-plant requirements for the fluidized
bed plant concepts are similar to those for conventional power plants.  The
balance-of-plant items which were considered were:

     ' Fuel storage and handling involves the receiving, storage, and
       delivery to the combustion system of coal and limestone additives.

     * Equipment installation includes installation of the combustion and
       primary energy conversion equipment as well as erection of the entire
       plant facility.

     " Thermal cycle heat  rejection includes cooling towers, circulating
       water pumps, and piping.

     • Plant enclosure includes buildings for plant administration, control,
       turbomachinery, and furnace systems.  (The geographic location of
       the plants in this  study necessitates enclosure of most of the plant
       equipment.)


                                   233

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     * Electric  energy  output  provisions  include bus bar, switchgear,
      transformers,  and wira  to conduct  the generated electric energy to
      the plant high voltage  switchyard.                 -;,.-

     " Plant  control  includes  instruments,  recorders, computers, and all
      other  equipment  necessary to monitor and control  the power.plant:.

      Site preparation includes excavation, roads, fences, and landscaping.

     The variety of energy conversion systems  included in this study resulted
in many  plant support subsystems which required definition.and cost.esti-
mate!?.   The subsystems  unique  to the  individual energy conversion systems
are described in each individual conversion system section end plant layout
drawings, equipment lists  and  cost breakdowns  are  presented.  The balance-
of-plant subsystems which  are  common  to several conversions systems are
discussed in  this section.  These subsystems were  appropriately scaled to.
adjust  for difficult capacity  requirements.
                                    234

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2.  BALANCE-OF-PLANT SUBSYSTEMS


   Coal and Sorbent Receiving, Handling, and Storage

     •   All coal is delivered by unit trains to the plant.  The plant coal-
   handling .system must unload the trains, move the coal to outside storage
   piles, reclaim the coal from storage as needed by the plant, and deliver
   the reclaimed coal to hoppers at the combustor feed system.   Coal storage
   capacity of each plant is 60 days at rated energy output.

        For the AFB and PFB plants dolomite or limestoi;° sorbent material  is
   mixed and injected with the coal.  Thus a receiving, storage, and handling
   system similar to that for coal is provided for this material.   This also
   requires provision for 60-days of storage capacity.

        Plant requirements that significantly influence the selection, sizing,
   and arrangement of equipment for receiving, handling, and storage of coal
   and solid sorbent material are the following:
                  »
          Live storage of sufficient fuel to supply the plant for  3 days nt
          rated capacity.

          Dormant storage of sufficient fuel to supply the plant for 60 days
          at rated capacity.

          Rail delivery by unit train of coal and/or sorbent material with
          motor truck access as an alternate.

   Coal

        Figure 38 shows the general arrangement of coal receiving,  handling,
   and storage facilities for all plants.  This concept includes two conLcal
   active storage coal piles and a 60-ft high dead storage.

        Coal will be transported from the mine in unit trains consisting of
   bottom discharge cars.  Cars will discharge the coal into under-track
   hoppers; the coal from these hoppers vlll be fed to two horizontal collecting
   belts for feeding thr coal to the main 60-in.t 3000 ton/hr belt  conveyor.
   This high capacity belt will rapidly unload the unit train contents to the
   active storage piles.  Train unloading time is less than four hours.  To
   account for the coal received at the plant, the coal vill be weighed in the
   scale house and representative samples of "as received" coal will be collected
   In the sampling station.  The sampling station tower, houses  the  coal sampling
   equipment, transfer hoppers, and drive equipment for the Inclined conveyor to
   the active storage piles.

        The two active, storage conical piles are formed by discharging the coal
   into the lowering wells at each pile.  The lowering well tubes also serve as
   support structures for the conveyor belts.  Coal from the active storage is
   fed to a 500-ton/hr conveyor by hopper feeders under the coal pile.  A tunnel
   has been provided for personnel emergency exit from the Installation under the
   coal pile.

                                      235

-------
ro
      iv*w o'a*  ^—.-r.
	T'-^'U^' 1
 .  j-  I -»^ 3;    >*!>—V -
S~^T"~"^r*T
                                                                   | • »S.>tV-0"
                                                                              A
                                                                              A_
                                                                              A
                                                                              A	
                                                                                    REC1TEI
                                                                           GE/NASA
                                                                       ADVANCED CYCLES STUDY
                                                                                     PHASE!
                                                                                 COAL HANDLING SYSTEM
                                                                                        SK-OM1
                                Figure 38.  Coal-Handling System  (Bechtel)

-------
     Dead storage of coal for each of the plants  is based on the 60-day
full-load requirement; and the active storage is  for three days, without the
need for bulldozing.  In an emergency,  coal  can be bulldozed from the dead
storage pile and transported by the emergency reclaim conveyor to meet the
plant requirements.

     In anticipation of probable future needs to  thaw frozen incoming coal,
space has been provided for the thaw and soak sheds for railroad cars.  Coal
lump crushers have been provided between the active and the emergency coal
reclaim systems and the boiler plant, to break up the oversize frozen coal.
It is expected that coal falling on the grizzly will also aid in breaking
up the frozen coal lumps.

     The coal handling, storage and processing capacities as required for
each plant are included in the discussion of each plant.

Sorbent Material

     The sorben? material will be delivered  in bottom discharge railroad
cars.  The general arrangement of the limestone or dolomite receiving,
handling, and storage equipment is similar to the corresponding coal systems.

     Sorbent material is unloaded into the same under-track hoopers as the
coal,-and discharged to the main coal conveyor belt for transport up to the
first lowering well structure of the coal pile.   At this point the sorbent
material is diverted to the 3000-ton/hr conveyor  supplying the lovpvin^ woil
of the active sorbent material storage pile.  Sorhent material is weighed in
the scale house and samples o.btained using the coal sampling equipment, after
taking necessary precautions not to contaminate the sample with coal remains.

     Sorbent material from the active pile is transported to the distribu-
tion bin by a 36-in., 125-ton/hr conveyor.   The dead storage is adjacent to
the active'^storage and is built up by moving material from the active storage
with mobile equipment such as 3 bulldozer or a scraper.


Water Treatment and Disposal

     Water for each plant will be withdrawn  from  the North River (Middletown,
U.S.A.) and treated for distribution to the  plant water systems.  It is
assumed that the river water is of moderate  hardness, is somewhat turbid,
and has a total dissolved solids (TDS)  level of about 250 mg/1.  A raw water
Storage pond is provided to settle out  suspended  solids and to serve as a
surge volume during period of high turbidity or  low flow in the river.

     The-river intake pumps supply water to  maintain a sufficient level in
the storage pond for about 3 days' makeup requirements/  Suspended solids in
the river water settle out in the pond, which will be dredged periodically
to remove accumulated silt.

     Water is treated to meet the various water use quality requirements.
Wastewaters are treated to meet EPA new source standards for the steam


                                  237

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electric power generating category.  There will be no waatewater discharge
from ash handling.
Water Treatment

     Figure 39 presents a generalized water treatment  flow diagram.  Raw
water from the storage pond is used directly for water makeup where appli-
cable.  Water is pumped from the pond into the supply  header and distributed
to the plant water systems.

     Makeup to the recirculating cooling water system  replaces evaporation,
drift, and blowdown losses.  The recirculating water is  treated with sulfuric
acid for scale control and, periodically, with chlorine  for control of
fouling organises.

     Raw water used in the potable, utility, and boiler  feedwater systems
(general plant use) is cold lime softened and filtered.  A storage tank
provides an assured source of fire water in the process  area.  Sludges from
softening and filtration are pumped to the sludge handling system.

     The potable water supply is disinfected with sodium hypochlorite using
a conventional contact system.  Utility water is usually used without
further treatment for such purposes as bearing, gland  and  sample cooling,
fire extinguishing water, and general washdowns.   Special  uses include fuel
gas cleanup (combined cycle gas turbine-air cooled) and  liquid fuel washing
and NOX suppression (combined cycle gas turbine-water  cooled).

     Boiler feedwater is demineralined in SA ion-exchange  system consisting
of parallel trains, each having a cation (H) bed, an anion (OH) bed, and a
mixed resin bed in series.  The ion-exchange beds are  regenerated periodi-
cally with sulfuric acid and caustic.  Spent regenerates and rinse waters
are routed to waste treatment facilities.  Demineralized water from the
storage tank and polished condensate are deaerated before  being pumped to
the boiler drum.  Chemicals are added to t.he water in  the  deaerator to
control scaling and corrosion in the boiler system (ammonia, hydrazine, and
trisodium phosphate).   Water treatment equipment, except for the storage
ponds, is treated as a package unit for cost estimating.


Wastewater Treatment and Disposal

     In general, wastewater from various sources are segregated and treated
to meet the applicable discharge limitations.   Treated wastewaters are then
combined in a final holding pond for gravity discharge to  the North River
downstream of the plant intake system.  Figure 39 illustrates generalized
wastewater treatment systems, sense or all of which are applicable to each
power plant cycle.

     Wastewaters are treated to innet the EPA new source  standards for the
steam electric power generating category.
                                   238

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                                         Figure  39.  Water  and Wastewater Management

-------
     Cooling Tower Blowdown.  Corrosion resistant materials are  used  In  the
recirculating water system to eliminate the need for corrosion inhibitors.
Blowdown is taken from the cool side of the recirculating water  system to
meet the thermal discharge requirement.  The pH of the recirculating  water
is maintained above 6.0 so that no adjustment is needed.   The. available
chlorine specification limit in the blowdown stream is met by careful
control of the residual chlorine in the recirculating water and  by tempo-
rarily shutting off the blowdown if the chlorine residual is too high.   The
blowdown, therefore, is discharged directly to the final  effluent pond
without any need for treatment.  The final holding pond provides holding
time for decay of any residual chlorine.

     Boiler Blowdown.  Blowdown from the boiler drums is  moderately alkaline
and of very high quality, oil-free, and low in TDS and TSS.   No  treatment
is needed other than blending this otream with other wastewaters to lower
its pH before discharge.

     Metal Cleaning Wastes.  Wastewaters are generated periodically by
routine maintenance cleaning-of heat transfer surfaces and cleaning of
miscellaneous equipment.  Cleaning wastes, both acidic and basicr contain
dissolved chemicals and metals.  The wastes from cleanouts are collected in
storage tanks and worked off at a low rate over several weeks in a reactor-
clarifier system in which lime is used to maintain a moderately  alkaline pH
of 8.5-9.0.  Metal hydroxides -are precipitated and removed as an underflow
sludge stream.  Clarifier overflow is routed for final pH adjustment  to  the
surge basin that accepts other process wastes.

     Low Volume Wastes.  Low volume wastes include demineralizer brines  and
rinses, lab end sample wastewaters, floor drainage, and other utility water
blowdowns.  These are collected in a surge pond, skimmed  of oil, neutralized,
and settled before discharge to the final holding pond.

     Area Runoff.  Yard drainage and runoff from material storage areas  are
collected in settling basins sized to impound the runoff  from a  worst case
10-year storm of 24-hr duration (4-in. rainfall assumed).

     Provisions are included to neutralize the runoff prior to discharge to
the final holding pond.  Settled runoff is expected to meet the  50 mg/1  TSS
discharge limitation.

     Sanitary Wastewater.  Sanitary wastewater is treated in a conventional
extended aeration biological system to meet biochemical oxygen demand (BOD)
and TSS discharge requirements.  Treated effluent is disinfected with
chlorine.

     Fina . Holding Pond.  This pond receives treated wastewater  from  all
sources and provides about a 2-day holding capacity.  Wastewater is dis-
charged through a gravity line to the North River downstream of  the intake
pumphouse.  Final effluent quality is expected to be:
                                   240

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                         PH                 6.0-9.0
                         Temperature, K         294
                         TSS, mg/1               30
      i                   0 & G, mg/1             15
                         Copper, mp,/l             I
                         Iron, mg/1               i


C.  SOLID WASTES HANDLING AND DISPOSAL

     The various power plants produce a variety of solid vaste residues
that must be collected and removed from the combustion systems.  These
residues range from slag and fly ash from the direct  coal-fired MHD system
to the mixed ash and calcium sulfates from the fluid  bed combustion systems.
The nature of the collected residue is a function of  the combustion system
that generates the residue or of the equipment that separates the residue
from a flow stream.  Likewise the residue transport means employed in a
plant design will be dependent on the combustion process and/or separation
equipment.
Fluidized Bed Combustion Systems

     The approach to collecting the fluidized bed combustion systems resi-
dues is to consider them as being dry and relatively cool for transport by
covered conveyor belt.to surge bins at the rail spur.  These surge bins
unload normally into covered rail cars, or alternatively into motor trucks,
for residue removal off site for disposal.  In order to allow for plant
operation in event of temporary transportation disruptions, on-site residue
storage silos are also provided near the rail spur.   These storage silos
are sized to hold up to 15 days of plant residue production at plant rated
operating conditions.  The silo storage system would be used intermittently
and is not part of the active conveyor system that continuously removes
solid residues from the plant's combustion system equipment.

     Maintaining the fluidized bed residues in a dry condition while trans-
porting to a final disposal area is most important.   These residues are
mixtures of ash, noncombusted particles from the feed coal and calcined
lime.  Should the mixture become wet, it will harden.  Therefore, the
fluidized bed residues must be kept dry until final  disposal.
D.  HEAT EXCHANGERS

Condenser

     All steam condensers are sized to provide a condensing pressure of
2.3-in. Hga under standard day design conditions in which circulating water
temperatures are 70.5 F at the condenser inlet and 100.5 F at the outlet.
Tubes in all steam condensers are assumed to be 1-in.  outside diameter BWG
#18 a wall thickness of 0.049-in.  Tubes are assumed  to occupy 22.5 percent
of the tube sheet cross-sectional area.  The overall  heat transfer coefficient
for these condensers is assumed to be 600 Btu/hr ft^°F.


                                   241

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                        c.
Deaerating Heater and Tank

     The deaerating feedwater heaters are assumed to have an overall heat
transfer coefficient of 600 Btu/hr ft2°F,  The storage tank capacity is sized
to contain five minutes of the total boiler feedwater flow.


Feedwater Heaters             ;

     Heat transfer tube surface requirements for closed feedwater heaters
in the study are calculated by assuming an overall heat transfer coefficient
of 600 Btu/hr ft2°F.                     •
E.  PIPING

Pipe Siring

     Piping diameters were selected on the basis 01   'von mass flow rates
and velocities v;hich are representatively selected from power plant design
experience for the classes of flows under consideration.  Approximate
velocities assumed in the study for conventional flows  are:

                      Fuel oil           "-        5  ft/s
                      Service water               8  ft/s               *7
                      Boiler feedwater           20  ft/s
                      Saturated steam  *""       150  ft/s
                      Superheated steam         300  ft/s

     Once the internal pipe diameter is determined,  pipe wall thickness is
calculated based upon the ANSI B 31.1 Power Piping Code for minimum wall
thickness.

     The allowable material stress, is taken from the-ASME Code for
pressure piping and depends on both the pipe material and the design
temperature.
Pipe Materials

     Following conventional steam-electric plant practice, pipe material is
A106 carbon steel for water and steam lines under 850 F  (for example, boiler
feedwater, cold reheat, condensate, process water) and 1-1/4 chromium — 1/2
molybdenum for steam lines from 850 F to 1100 F (for example, main steam and
reheat).  Mid-1975 costs for fabricated carbon steel and  chrome-moly piping
are estimated at $1.10/lb and $2.00/lb, respectively.  Additional allowances
for fittings, hangers and supports, installation labor operations, and
insulation were developed from power plant construction cost reports and are
included in the piping estimates.

     For the PFB, hot gas piping is carbon steel with internal refractory
lining.  Refractories were selected on the basis of temperatures and fluid
                                   242

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conditions at the hot surface.  Double-layer linings are employed in very
high temperature applications and use a high-temperature refractory at the
hot surface backed up by a more highly insulating low-temperature refractory
adjacent to the carbon steel shell.  Characteristics of refractories used
in hot gas piping are given in Table 95.

     An internal liner of Incoloy 800 is included in the PFB gas turbine
inlet piping to prevent refractory particles from entering the turbine £as
path.  The fabricated liner (usually 0.125 in.  thick)  is estimated at
$16.00/lb.

     As in the conventional piping estimates, additional allowances are
included in the unconventional piping estimates for fittings, hangers and
supports, installation labor operations, and anchors for refractory linings
where applicable.


F.  COOLING TOWERS AND CIRCULATING WATER SYSTEMS
                 f
     All plants used cooling systems employing  evaporative, mechanical draft
cooling towers.  This type of tower was selected because of its minimum
capital cost features and its ease of application to a wide range of thermal
load requirements by use of multiple tower cells operating in parallel.

     The Middletown, U.S.A., site is near a river which can supply suffi-
cient quantities of cooling water makeup as well as receive treated blow-
down water.  The following atmospheric conditions at Middletown have been
used as the design conditions:

                  Wet bulb temperature - 51.5 F
                  Dry bulb temperature - 59 F
                  Relative Humidity    - 60%

     Design Conditions.  To achieve an absolute pressure of 2.3 in. Hga
in the steam condensers requires that the equilibrium condensing temperature
be maintained at 105.85 F.  This is the heat source design temperature for the
cooling water system.

     The heat sink design temperature is the design wet bulb temperature
of 51.5 F.  An approximate minimum cost cooling system is achieved by using the
following working temperature differences for the cooling system components:

     a.  Terminal Temperature Difference (TTD)  is the  difference between
         steam condensing temperature and the hot cooling water temperature
         leaving the condenser.  The TTD used was 5.35 F.

     b.  Range is the temperature difference between the hot cooling water
         to the cooling towers and the evaporatively cooled water in the
         cooling tower basins.  The Range used  was 30 F.

     c«  Approach is the temperature difference between cooling tower basin
         water and the ambient wet bulb temperature.  The approach used was
         19 F.
                                   243

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                               Table 95




                         REFRACTORY MATERIALS
Type
Brick
Cas table
Cas table
Brick
Cas table
Brick
Block*
Cas table
Max. Temp.
at Hot Surface
3300 F
3300 F
2800 F
2600 F
2300 F
2000 F
1900 F
1800 F
Thermal Conductivity
(Btu in /hr ft2 °F)
5.3 @ 2500 F
5.5 @ 2500 F
4.9 @ 2000 F
2.8 @ 2000 F
2.1 @ 1500 F
2.1 @ 1500 F
0.7 @ 1000 F
1.7 @ 1000 F
Cost per
Linear Ft
$41.80
41.00
40.00
11.20
9.55
8.60
6.00
7.00
*For second-layer,  backup insulation use only
                                   244

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     These temperature relationships for the cooling system are  Illustrated
by the Figure 40.

     Applying the Reference cooling tower design techniques with the above
conditions of wet bulb temperature, range, and approach provides a tower
unit raring factor (RF) of 1.473.  Under these service conditions, large
mechanical draft cooling tower cells are rated at a recommended  15,750 tower
units (TU) per cell,  and each cooling tower cell has a rated water flow
capacity of 10,692 gpm.

     The standard dimension of each cooling tower cell was  75 ft (6.97 ra)
wide by 36 ft long by 47 ft high.  Each cell contains one circulating fan and
motor of 150 fan horsepower which induces the air draft through  the two opposite
sides"of the cell.

     The heat dissipation capacity per cell is 1.6 x 108 Btu/hr-cell.

     Fan motor power per cell, assuming 97.5 percent motor  efficiency, is
115 kWe/cell.

     Water consumption rate per cell consists oft wo components:  (1) water
evaporation to the atmosphere and (2) basin blowdown water  to prevent an
excess accumulation of dissolved solids in the*cooling-water system.  The
water evaporation rate, based on prior experience, is approximately 2.1
percent of the rated water circulating rate.  Water loss allowance for
blowdown is 0.5 percent of the water circulating rate.
                                 f>
     Water Consumption Allowance is therefore*

   .  Evaporation                   220 gpm/cell
     Blowdown                       53 gpm/cell
               Total Consumption   273 gpra/cell


Circulating Water System Design

     Circulating water systems serve to pump water from the  cooling tower
basins through condensers and other heat exchangers and back to  the cooling
towers.   Water quantity is determined by each plant's requirements but is
related linearly to the number of cooling tower cells required for each
plant.  Large diameter underground piping from the cooling towers to the
pumps and on to the plant, as well as from the plant back to the cooling
towers,  is required to achieve a nominal water velocity in the piping
system of 7 ft/s.  This velocity minimizes the net cost of the circulating
water system considering installed capital costs and ongoing pumping costs
associated with velocity-sensitive line pressure losses.

     Pump sizing for  the circulating water systems is based on using a
minimum of three pumps at one-third of plant water flow requirements.  This
use of parallel pumps ensures that in the event  of a single pump failure,
sufficient cooling water flow is available to permit near normal plant load
adjustment followed by continued part load operation,  if needed.  The
redundancy also facilitates pump and^motor servicing.   Circulating water

                                  245

-------
Heat Source Temperature = I05.85F (2.3inHga)
Available
Temperature
Difference
54.35F
                    5.35 F Condenser TTD
                              t
49 F
          30 F Range
                           19 F Approach
100.5 F Hot Water


    Cooling
    Towers

 70.5 F Cold Water
Heat Sink  Wet Bulb Temperature = 51.5 F

        Figure 40. Cooling Tower Temperature Differences
                             2U6

-------
system capacity  ±3 related  to  the number of cooling towers installed in
each plant;  thus pump and pipe design parameters are defined per unit
cooling  tower  cell.  Each cooling tower rell requires a nominal water flow
of 10,692  gpra.   Pump motor  power  required per cell is based on these assumptions:

     * 15  percent additional capacity allowance

     * 80  percent pump  efficiency

      97.5  percent motor efficiency

     * 62  ft of  total pressure head

These criteria result in per cell pump power requirements 240 hp/cell
and a motor  capacity of 184 kW/cell.


G.  EXHAUST  STACKS

     The exhaust stacks were assumed to be concrete, tapered at 4 percent
with an  acid resistant  steel liner and stainless steel rain hood.  The
liner is insulated on the outer surface.  The top 25 feet of the liner and
the rain hood  are stainless steel.

     Stack foundations  are  site sensitive depending on local wind loading,
soil conditions, and so on. For  cost estimating purposes, all stack
foundations  are  assumed to  be  concrete pads 8 ft deep, which exceed the stack
base diameter  by 40 feet.

     Stack liner diameters  are sized by assuming a gas velocity of 90 ft/s
at the exit  of all stacks.  Stack heights are determined as a function of tons
per day  of sulfur dioxide emission per stack.  The sizing of stack heights
depends  on specific site conditions including prevailing weather patterns, soil
conditions,  composition of  emissions, and so on.


H.  AUXILIARY  LOADS

     For each  plant two basic  types of electrical loads are involved.  The
first type is  associated with  major power cycle equipment and is generated
by the equipment suppliers.  These loads include furnace auxiliaries and
gas and/or steam turbine auxiliaries.

     The second  type of electrical load includes all specific equipment
loads and  general plant loads  associated with balance-of-plant systems.
Electrical loads included in this category and estimating methods for these
loads are:

     1.  Fan loads, based on required flow rates and pressure differences.
        The fan efficiency range is 75 to 82 percent, and the motor
        efficiency is  90 percent.
                                  247

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     2.   Pump loads,  also based on required flow rates and pressure
         differences.  The pump efficiency  range is 75 to 82 percent and
         the motor efficiency is 90 percent.
I.  ELECTRICAL SYSTEMS

Systems Description          ,

     The electrical system for  each of the  plants is defined by the study
groundrules to include all electrical equipment and associated bulk mate-
rials for both in-plant auxiliary loads and plant output power up to the
500 kV transmission voltage terminals of the main power transformers.
Switchyards are excluded from the plant scope,

     The electrical system concepts are illustrated in the form of single-
line diagrams included with the drawings for each energy conversion system.
Specifications for all significant transformers  (for example, main,
startup, auxiliary, station service) and the standby diesel generator, sets
are given in the equipment list for each of these systems.
Transformers
     •                                      7"*- '                 *
                                                                         »
     The main transformer capacity provided  for each plant is based on the
total power generating capacity of the station less the in-plant auxiliary
load.  Two one-half capacity transformers are provided.

     The capacities of the startup and auxiliary transformers are based on
the expected in—plant startup and operating  loads, respectively.  Station
service transformers are provided as required so that 13.8 kV power is
supplied to motors greater than 10,000 hp  (7457 kWe), 4.16 kV power is
supplied to motors between 250 hp (186 kWe), and 10,000 hp (7457 kWe), and
840 V power is supplied to motors less than  250 hp (186 fcWe).
Standby Power                                             :

     Uninterruptible electric power systems for critical a-c and il--c loads
are provided for each plant.   A 1,000-kWe  diesel generator supplies emer-
gency a-c power to a 480-V critical equipment bus.  A 125-V d-c system
consisting of storage batteries and battery chargers are also provided to
supply emergency power through an inverter circuit for a limited time.
This will supply critical loads which may  receive emergency power and
include turbine lube oil equipment, lighting, instrumentation, and control
equipment.
                                 Ci
                                   248

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COST ENGINEERING METHODS
A.  COST ENGINEERING OBJECTIVES
              f
     The cost engineering objectives for the balance of plant are defined
as providing the following:

       Conceptual balance-of-plant construction cost estimates

       Balance-of-plant maintenance cost estimates

       Estimates of time required for construction

     Balance-of-plant costs include:  installation costs for major compo-
nents; both purchase and installation costs for all balance-of-plant
material; arid indirect field costs, engineering, home office costs, fees,
and a contingency allowance.  Escalation and interest during construction
are excluded from ,the balance-of-plant construction cost estimates.


B.  CAPITAL COST ESTIMATE APPROACH

Basis of Estimates

     The balance-of-plant construction cost estimates are based on the
following inputs:

       Energy conversion system data (for example,  cycle diagrams, working
       fluids, flow rates, temperatures, pressures, and power ratings).

     * Specifications for major components (for example, descriptions.
       dimensions, weights,  extent of field assembly required, and ancillary
       equipment requirements).

     " Balance-of-plant data generated in the stut'y (for example, plant
       subsystems descriptions, solids-handling daLa, effluents, and water
       requirements).

     * Balance-of-plant equipment lists generated in the study  (for
       example, specifications for major pumps, transformers, condenser,
       feedwater heaters, main pipe sizes, fans, and stack dimensions) .

     " Conceptual plant layout drawings generated in the study including
       a plot plan, equipment arrangement plan and elevation, and a
       single-line electrical diagram.

     An information flow diagram is shown in Figure 41 which indicates
the above inputs, subsequent cost engineering activities working from
these inputs to develop plant estimates, and reference items which were
employed.
                                   249

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        4.
ro
\ji
o
               CYCLE
               DATA
                (GO
               MAJOR
             COMPONENTS
            SPECIFICATIONS
               PLANT
                DATA
             EQUIPMENT
                LISTS
               PLANT
              DRAWINGS
COORDINATE
ADDITIONAL
  DETAIL
                    B.O.P
                c MATERIAL
                o LABOR
                • SUBCONTRACTS'
1 T
  I
  I
                                                                    MAJOR
                                                                  COMPONENTS
                                                                 INSTALLATION


ADO
•arrvftFfT
COSTS







--.- ,. . !-. . -...-..-..I *.j
Rrtf>
COST
ESTIMATES

                                                   TIME FOU
                                                ENGINEERING AND
                                                 CONSTRUCTION
                               REFERENCES
                                                             PROCUREMENT
                                                             DEPARTMENT
                                                                DATA
                              VENDORS
                              « EQUIPMENT
                              » SUBCONTRACTS
     COMPUTERIZED
      REGRESSION
       ANALYSES
                                                              MANHOUR
                                                              STANDARDS
                                                           CONSULTATIONS
                                                           « CONSTRUCTION
                                                           • FIELD COSTS
                                                           « INDIRECT COSTS
                               COMPUTERIZED
                                ESTIMATING
                                 PROGRAMS
                                  CODE OF
                                 ACCOUNTS
        PROJECT
       FIELD COST
        REPORTS
        REVIEWS
                                    Figure 41.  Cost Engineering Task Flow Diagram

-------
Direct Field Costs

     Balance-of-plant (BOP) cost estimate; summaries are presented according
to the format shown in Table 96 and are accompanied by detailed  itemized
breakdowns of each direct field cost account.  Seven direct  field cost
accounts are utilized.  The use of the^e accounts facilitated  the develop-
ment and cross-checking of results with tecent construction  experience in
fossil-fired power plants.

     Two of the seven direct field cost accounts (1.0 Steam  Generators/
Furnaces and 2.0 Turbine Generators) include major components  for which
BOP estimates include only installation labor costs.  One account (3.0
Mechanical Equipment) includes both major components in which  BOP installa-
tion costs are supplied and BOP items that include component costs and
installations.  The remaining four accounts  (4.0 Electrical, 5.0 Civil and
Structural, 6.0 Piping and Instrumentation, and 7.0 Yardwork and
Miscellaneous) include primarily BOP items — both component costs and
installation costs.  Details of . these direct costs pertaining  to particular
energy conversion systems are presented In Section 4 of this report.
Details of direct costs pertaining to BOP items that are common  to all
plants are discussed below under "Common Balance-of-Plant Components."

     Table 97 gives an approximate division of items which are included
in each account.

     The BOP direct field costs are developed on the following basis:

     1.  All prices are at mid-1975 dollar value.

     2.  A composite labor rate of $11. 75/MH is applied to all manual
         field labor.
     3.  Material and equipment costs are determined from L-urr^nt data,
         from vendors' oral budgetary quotations, and Ciom recent power
         plant construction field cost reports.

     4.  Manuel field labor man-hours are determined from man-hour stan-
         dards, from computerized estimating programs,  and from recent
         power plant construction field labor cost reports.

     5.  Productivity of manual field labor is assuned  to be  equivalent
         to the current national average for fos «=i.'-f ired power plants.

     6.  Availability of manual field labor if. i ssiar.ed  to be  sufficient
         at the Middletown, U.S.A., site for construction of  each plant.
 Subcontracts
     Subcontracts are not included P.O -uch in the cost estimates.   BOP
components that normally would be estimated as single subcontract  cost
entries  (for example, cooling towers, stacks, and pipe insulation)  are
divided  into, and entered as, direct material and direct labor  costs.
                                   251

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                                  Table 96

                   6ALANCE-OF-PLANT COST SUMMARY FORMAT
   l

                                    Labor            Material          Total
                                    (MHs)               ($)              ($)

1...0 ^Steam Generators/furnaces       XX                 XX

2.0  Turbine Generators              XX                 XX

3.0  Mechanical Equipment            XX                 XX

4.0  Electrical                      XX                 XX

5.0  Civil and Structural            XX                 XX

6.0  Piping and Instrumentation      XX                 XX

7.0  Yardwork and Miscellaneous      XX                 XX


Direct Materials                                        XX             XX

Direct Labor                        XX 
-------
                              Table 97

                      ACCOUNT CATEGORY DIVISIONS


1.0  STEAM GENERATORS/FURNACES

       Steara Generators* and Economizers*

       Coal Injection Systems*

       Combustion Air Preheaters*

 »•     FD, PA,  and ID Fans*

       Flues and Ductwork

       Precipitators,* Cyclones,* and
         Granular Bed Filters*

2.0  TURBINE-GENERATORS

       Steam Turbine Generators*

       Gas Turbine Generators*

3.0  MECHANICAL EQUIPMENT
                            f.
       Pumps and Drivers**

       Condensers**

       Heaters, Exchangers, Tanks, and
         Vessels**

       Compressors and Drivers**

       Stacks and Draft Ducts

       Turbine Hall Cranes

       Coal, Other Solids, and Ash
         Handling**

       Cooling Towers

       Water Treatment

       Fuel Oil Ignition

       Screenwell

       Miscellaneous Plant Equipment
                    «         a  ,
       Equipment Insulation

                                   253

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                           Table 97 (continued)


4.0  ELECTRICAL

       Transformers

       Generator Main Bus

       Switchgear and Control Centers

       Communications and Lighting

       Grounding, Cathodic, and Freeze
         Protection

       Auxiliary Diesel Generator

       Conduit,(Trays, Wire, and Cable

5.0  CIVIL AND STRUCTURAL.

       Concrete Substructures and foundations

       Superstructures and Building Services

       Earthwork, Dewatering, and Iiling

       Cooling Tower Basin  „

       Circulating Water Pipe and Pump Pads

6.0  PIPING AND INSTRUMENTATION

       Steam and Feedwater Piping

       Hot Gas Piping

       Auxiliary Piping

       All Small Piping (2 in. and under)

       Hangers and Supports

       Miscellaneous Labor Operations

       Pipe Insulation

       Instrumentation and Controls
                                   254

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                           Table 97 (continued)


7.0 ;YARDWORK AND MISCELLANEOUS

       Site Preparation an<\ Improvements

       Site Utilities

       Railroad Spurs

       Roads, Walks, and Parking Areas

       Yard Fire Protection

       Fences and Gates

       Ponds and Dikes

       Lab, Shop, and Office Equipment
 *Install only
**Some installed only
                                   255

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                       -•
 This procedure is adopted to ensure a  comprehensive accounting of all field
 labor man-hours.   In effect, this method assumes that all field labor is
 performed by the  prime contractor's work forces,


 Distributable Field Costs

      Distributable, that  is, indirect, costs  include field costs thac can-
 not be directly identified with any specific  direct account item.  In a.
 sense, the coats  are "distributed"  over all direct items.  Construction
 experience demonstrates that distributable field costs can be estimated as
 a percentage of direct field labor  costs.  For each system, distributable
 costs are estimated at 90 percent of direct field labor cost—a percentage
^that is consistent with recent fossil-fired power plant construction
 experience.  The items included in  the distributable account and the typical
 percentages are given in  Table 98.
 Engineering, Home Office Costs',  and Fees

      Recent fossil-fired power plant Construction experience demonstrates
 that engineering, home office costs, and  fees  are equal to approximately 15
 percent of total (that isr direct plus indirect) field costs.  Included in
 these costs are:                        "                 >
                                                                       n-^
        Design engineering
                                       ^f-
      ' Estimating, scheduling, and cost control

      " Purchasing, expediting, and inspection                 '

      " Construction management and administration

      * Engineering, procurement, and construction management fees

      Fees typically amount to about 2 percent  of total field costs.  About
 two-thirds of the remaining 13 percent ara for engineering services and the
 remaining third is for other home office  costs.


 Contingency

      Estimates predict the cost of a project but predictions contain
 uncertainties.  Contingency is the amount of money  that construction experi-
 ence has demonstrated must be added to an estimate  to provide for uncertain-
 ties within the design detail in quantity, pricing, and productivity.

      Contingency minimizes the risk of these uncertainties and reflects a
 selected risk of overrun.  The contingency is  expected to be spent during
 the construction and is selected to yield the  most  probable total project
 cost.  Contingency does not provide for changes in  the defined scope of a
 project or for unforeseeable circumstances beyond the contractor's normal
 experience or control.
                    «          o
                                    256

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                        Table 98

               DISTRIBUTABLE FIELD COSTS
Temporary construction facilities including sheds,
temporary fences and paving, temporary utility
connections                                                 12%

.Miscellaneous construction services including
surveying, material handling, watchmen and clean up         12%

Construction equipment and tools                            10%

Consumables including fuel, oxygen, acetylene and
welding  rod                                                  5%

Field office costs including field supervision, field
engineering, field administration, medical and field
office overhead expenses                                     20%

Preliminary operations and testing including alignment,
balancing,  tasting and adjusting of all equipment to
ensure that warranties are met and that all subsystems
function properly prior to customer acceptance and
plant startup                                                11%

Payroll  expenses including federal and state payroll
taxes and workmen's compensation                             14%

Project  insurance                                             4%

State and local sales and use taxes                           2%
                                                             90%
                           257

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     A contingency of 20 percent applied to all costs has  been selected
with consideration of the conceptual nature of the designs.  The limited
conceptual level of detail in these plant designs increases the risk of
underestimating costs.  To compensate, a contingency is  selected that is
near the high end of the range of values currently used  in the construction
industry.

     A common contingency factor (20 percent)  is applied to all three plant
types studied.  A common percentage is justified because,  by definition, con-
tingency reflects a level of uncertainty consistent with the design detail, and
all plants are estimated at a common conceptual level of available detail.  By
definition, contingency does not reflect technological risks which may be
associated with the more advanced systems.


Design Allowances

     Design allowances are also built into estimates to  cover costs that
experience indicates are expected but not explicitly identifiable.  However,
unlike contingency, which is an indirect cost  applied to a total estimate,
design allowances are direct costs applied to  specific equipment or bulk
material items.  For example a 5-percent design allowance  may be added to
the purchase price of a pump to cover expected miscellaneous field purchases
required to facilitate installation of that pump.   Design  allowances typical
to current fossil-fired power plant estimates  are included in the estimates.


C.  COMMON BALANCE-OF-PLANT COMPONENTS

     Certain significant BOP components are common to all  or many of the
energy conversion systems.


Stacks and Accessories

     In actual plant construction,  stacks are  usually subcontracted.
Budgetary direct material costs and labor requirements were estimated
through consultation with a stack contractor.   An additional allowance for
accessories, including lifts, marker lights, and paint is  estimatad from
recent construction experience.  Budgetary direct  material coses for a
stack with accessories (excluding stack foundation)  are  estimated from the
relation:

                    1.05                        0.55
  Stack height (ft)      x  Liner diameter (ft)       x  $1>000>000  + Sl5>00f)
         470                        40


Corresponding direct labor man-hour requirements are:

                     1.35                         0.75
  Stack height (ft)       x  Liner diameter (ft)       x 48,000 MH  +1,100
         470                        40


                                  258

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     Concrete for stack foundations is estimated  using reinforcing bar,
formwork,  and embedded metal quantities per cubic yard as experienced in
recent field construction.
Cooling Towers

     Cooling towers are defined as wood, mechanical draft, wet towers
operating at the design conditions detailed earlier in this Section.

     Cooling towers are usually subcontracted,  though, budgetary estimates
on direct material costs and labor requirements were estimated through
consultation with a cooling tower contractor.   Cooling tower costs are
estimated on the basis of tower units (TU)  which,  for the tower design
specified are:

     At raid-1975 dollar values, direct material costs for the towers are
          $6.13/TU.

     The corresponding direct field labor requirements are 0.14 man/hours/TU.
                                                "Sft
     Concrete for the cooling tower basin and foundations is estimated using
275 cubic yards (210 ra^) per cell and using reinforcing bar, formwork, and
embedded metal quantities per cubic yard as experienced in recent fijld
construction.

     An allowance of $6,000/cell and 100 MH/cell is also estimated for
miscellaneous structural steel and fire-protection equipment based on recent
construction experience.
Dewatering and Piling

     Dewatering and piling requirements  are site  sensitive-and dependent on
soil conditions, groundwater,  rainfall,  and so on.  For all plants, an
allowance of $300,000 for material costs and 100,000 man-hours is included
for dewatering and piling based on recent field construction experience.
Auxiliary Buildings

     Administration,  warehouse,  and minor  yard buildings are, in large part,
dependent upon the plant owner's particular needs.   Based on typical costs
for these buildings extracted from recent  coal-fired power plant construc-
tion projects, the following allowances  are included for auxiliary buildings
in all plants:
                             Direct Field      Direct Field
                                Labor        Material Cost

     Earthwork                    600 MH
     Substructures              5,400 MH     $    36,000
     Building Services        84,000 MH     $-1,250,000
                       O          o

                                   259

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Railroad Spur

     All plants Include four miles of railroad trackage for unit-train
delivery of coal and sorbent material and for removal of solid waste.  Based
on recent construction experience, $632,000 for material costs and 21,500
man-hours are allocated for the railroad spurs.


Other Common Equipment

     All plants include costs for the following equipment items:

       Laboratory and office equipment (@ $285,000 equipment cost and 1,000
       man-hours allowed for handling and installation)

       Mobile coal-handling equipment including two bulldozers with coal
       blades and two scraper? (@ $908,000 for the lot)

       1,000 kW, 480 V, 3-phase auxiliary diesel generator with startup
       batteries and associated equipment (@ $115,000 equipment cost and
       1,500 man-hours for installation)

     Several additional balance-of-plant components are common to all plants
but vary in cost according to capacity or other scaling parameters.  These
components are listed in Table 99 along with the scaling parameter used in
deriving their costs.

     Plant equipment and material not discussed in this section are parti-
cular components required by specific energy conversion systems.  These
components (for example, boilers, corabustors, turbine generators;, feedwater
heaters, pumps, fans, large piping, and boiler enclosures) are r»* imated on
an item-by-item basis and discussed in the CVS, AFB, and PFB p-   ^ons of
the report.
D.  CONSTRUCTION TIME ESTIMATES

     For large fossil-fired power plants of the type included in this study,
a relationship exists between the total number of field manual man-hours and
the number of months required from start of plant engineering to construc-
tion completion.  This relationship is presented in Figure  3-6, which is
plotted using data from actual power plant construction experience.  Data
points represent coal- and oil-fired, single- and double-unit plants of
500 MWe and 800 MWe unit-capacity.  The line drawn between  points is the
result of a least-squares regression analysis and indicates the following
exponential relation:
                                   260

-------
     Construction Time*  (Months) - 47.5 x  Manual Labor (MH)  °'20

        i
     Using the above relationship, a construction time is estimated for
each of the plants  included in this study and presented in Table 3-6.
*From start  of  engineering to commercial plant operation
                                 261

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                                 Table 99

                    COMMON BAL>.NCE-OF-PtANT COST ITEMS
       Balance-of-Plant Item

 Turbine hall crane

 Solids-handling equipment  (Includes
 rallcar dumping, dust collectors,
 primary crushing, belc scale, sampling
 station, magnetic cleaners,, conveyors,
 hoppers, feeders, foundations, pits,
"and tunnels)

 Water treatment and chemical Injection

 Instrument air compressors and auxiliaries

 Fuel oil ignition and warmup

 Screen well

 Miscellaneous mechanical equipment

 Equipment insult eit ion

 Mala transformer and generator main bus

 Station service transformers

 Startup transformer

 Plant electrical equipment (includes
 Evitchgear and load centers, motor
 control centers, local control stations.
 distribution panels, relay and meter
 boards, communications, grounding, cathodlc
 and freeze protection, preoperational
 testing)

 Plant lighting

 Electrical bulk, materials  (Includes
 conduit, cable trays, wire, and cable)

 Turbine halls (Include substructure
 and building services)

 Circulating vtter system (includes
 concrete and pipe)

 Miscellaneous equip*asnt foundations
 and other concrete

 Common large piping (includes auxiliary
 steam, condensate, process water, fuel
 and Ignition oil, water treatment,
 compressed air, lube oil, H-, CO.,
 miscellaneous)

 Snail piping, valves,  and fittings
 2 Inches or less in dianater

 All pipe hangers and supports         &

 Miscellaneous piping labor
 operations (Includes material
 handling, scaffolding, clean up)
                                        262
Cost Scaling Parameter(a)

Turbine rating (MWe)

Solids-flow (TPH) and
  conveyor lengths
Cross plant rating (MWe)

Cross plant rating (MWe)

•Cross plant rating (MWe)

Cross plant rating (MWe)
     ••*
Cross plant rating (MWe)

Cress plaut rating (MUe)  .

Voltages  (kV) and capacity (MVA)

Voltages  (kV) and capacity (MVA)

Valtages  (kV) and capacity (MVA)

Section service transformer cost
Lighted plant area (ft )

Station service transformer cost


Building plant area (ft )


Circulating water flow
   (gal/mln)

Cross plant rating (MUe)


Cross plant rating (MVA)





Linear feet of large pipe (ft)


Piping cost (S)

Piping man-hours (MH)

-------
 100
X
H


O



tlT
  90-
  80
  70
z
2  60
o
D
oc

£

O
o
   50
   40
                   3          456


                    106 FIELD MANUAL MANHOURS
                                                            10
     Figure 42.  Construction Time  (from Start  of  Engineering)

               to Commercial Operation) Variation  with  Field

               Manual Labor Man-Hours
                              263

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                               Table 100

                  ESTIMATED PLANT CONSTRUCTION TIMES

                                       Manual Labor    Construction
                                          (MHs)        Time  (Months)

Convertional/Wet Scrubber               5,602,000           66

Atmospheric Fluidized Bed               4,295,000           64

Pressurized Fluidized Bed               3,995,000           64
                                   264

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F.  OPERATING AND MAINTENANCE COSTS

1.  INTRODUCTION

     The analysis of operating and maint nance (O&M) costs was a joint  effort
of several organizations.

     General Electric Installation and Service Engineering Business Division
was responsible for bringing together estimates on tri maintenance costs  asso-
ciated with conventional types of- power plant equipment and for estimates of
the operating labor costs associated with each system.  This Division also
played a major role in the study of operating consumable costs.  Foster
Wheeler Energy Corporation supplied n..jir.tenance data and information on the
atmospheric and pressurized fluidizeu b-^d concepts.  The Bechtel Corporation
supplied listings of balance-of-plant equipment which have served as the  basis
for maintenance estimates on this equipment.

     General Electric Corporate Research and Development performed the  following
activities:

     Provided detailed information on the characteristics of the
          energy conversion ct-acepts.

     Investigated maintenance requirements associated with advanced
          components.

     Carried out analyses of operating consumables costs for the
          advanced concepts.

     Integrated the several efforts into a single analytic package.

     O&M costs have beet, estimated for the CWS, AFB, and Prr> power pl.-Uits.  For
each of these plants, total operating and maintenance costs are computed  in
mills per kilowatt hour.  Each total is the sum of estimated maintenance  costs
on cycle equipment, the operating labor required for the plant, and the cost of
operating consumables.

     All costs are based on raid-1975 cost estimates, without provision  for
inflation in costs over system life.  Differential costs of "makeup" purchases
of power-are not included.

     Costs of such items as auxiliary power purchases, outside steam purchap .-s,
other utilities, taxes, and insurance are not estimated in O&M cot;ts.   Iteais
usually handled by applying a fixed charge rate to the total capitil invest-
ment (for example, cost of working capital and capital charges) are not
included in O&M costs.

                                  265

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2.  MAINTENANCE COSTS

     The maintenance costs include the costs during planned outages  (preventive
maintenance, inspections), and forced outages (breakdowns,  repairs).  The costs
include any unusual supplies, replacement parts, equipment  rentals, outside
maintenance consultants, and the salaried of the employees  required in provid-
ing the necessary maintenance.  The salaries of these maintenance men are the
major component of the maintenance costs of power plant equipment.  No costs
are estimated to provide a contingency for major repairs that might be required
in the event of a long forced outage caused by severe parts failure damage.
Plant maintenance is broken down into the following areas for cost estimation:

     a.  Turbine-generator

     b.  Steam generator

     c.  Makeup water treatment

     d.  Electrostatic precipitator

     e.  Water intake structure

     f.  Balance of plant (BOP)

This cost breakdown is shown in Table 101.


a.  Turbine-Generator Units

     The estimated maintenance cost for an entire steam turbine generating unit
included supervision and engineering as well as maintenance of structures, boiler
plant and electric plant.

     The PFB plant required maintenance of a gas turbine generator as well as
an addition to it also.

     Gas turbine-generator maintenance costs include the maintenance of an
industrial continuous service baseloaded gas turbine-generator only and
excludes any associated equipment.


b.  Steam Generators

     The Foster Wheeler Energy Corporation has supplied estimates for the
atmospheric (AFB) and pressurized (PFB) Eluidized bed systems,  Each system
has been broken down in terms of four maintenance-sensitive areas:  pressure
parts, special fluidized bed items, control components,  and auxiliary equip-
ment.  Separate maintenance burdens were then applied to each of the four,
these burdens ranging from 0.2 percent to 5.0 percent annual maintenance
costs as a percentage of equipment  cost.  These analyses have resulted in
the estimation of annual maintenance costs of roughly $l,kW for the AFB to
about $1.70/kU for the PFB.

                                   266

-------
     Foster Wheeler also supplied estimates for the conventional pulverized
 coal-fired furnace for the Conventional/Wet Scrubber plant design.


 c.  Makeup Water Treatment System              ;                 ;

     Makeup water treatment costs were based on makeup water flow.  The system
 was assumed to be two stage:   CD pretreatment solids removal incorporating
 flocculation  and filtration using carbon and sand aad  (2) a deraineralization
 stage  composed of a dual-bed demineralizer, atmospheric degasifier, and a dual
 mixed-bed demineralizer as major components.

     The maintenance cost for water treatment does not include Chemicals costs,
'"which  are treated as consumables.


 d.  Electrostatic Precipitator

     The CWS  and AFB plants utilized electrostatic precipitators.   The ESP
 efficiencies  for the plants were 95 percent for the AFB and 98.5 for the CVS.
 On the basis  of these efficiencies maintenance costs were calculated based
 on gas flow.                                                            .
 e.   Water Intake Structures
      Water intake  structures were assumed to be a bar screen and traveling
 screen system.   Maintenance~costs ware based on equipment replacement costs
 with magnitudes  proportionally determined by makeup water flows.


 f .   Balance-of-Plant Maintenance Cost.^

      Maintenance costs, as well as being estimates for conventional and advanced
 cycle equipment, have  been separately calculated for balance-of~plant,  (BOP)
 equipment .

      The rationale for these calculations may be briefly described as follows:
 Bechtel Corporation has supplied detailed estimates of BOP material costs
 associated with  major  equipment categories for each cycle:  that is, .steam
 generators, turbine generators, process- mechanical equipment, electrical,
 civil and structural,  process piping and instrumentation, and yard work and
 miscellaneous.   Within each category, maintenance costs as a fraction of
 the material costs per year have been estimated.  For example, the mainte-
 nance burden on  miscellaneous support steel is taken to be 0.2 percent
 per annum, whereas those  for forced draft fans, pu^ips, etc., are taken at 5
 percent per year.   Other  categories of equipment have been similarly assigned
 maintenance burdens in accordance with good engineering judgment and field
 experience.

      These maintenance burden factors are then multiplied by the associated
 BOP materials costs for each equipment class, with all su;h products then

                    0         to
                                   267

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summed to create a maintenance cost for the entire cycle In $M/yr.   These
cost figures are in turn (based upon  the cycle's net output In MW and a  65%
capacity factor) converted to BOP maintenance costs in mills/kVh for each cycle.
                                    268

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3.  OPERATING COST ESTIMATES

     The operating cost estimates for the three plants studied are broken
down into operational labor costs and Into costs of consumables and supplies.
a.  Operational Labor Costs

     Estimates of the manpower required to operate the three power plants were
based upon available information contained in the references and upon extra-
polations of such estimates to cover the advanced technology aspects of the
various plants.  Basic categories of labor considered as operating personnel
include supervisors, engineers, operators, technicians,  fuel handling specialists,
chemical technicians, clerical workers, laborers, guards,  and others.  These
categories were consolidated into:

     a.  Supervisors
     b.  Operators
     c.  Technicians
     d.  Laborers, clerks, guards, others

     Once the number of employees for each power plant was established, the
annual payroll including fringe benefits and overhead was calculated assuming
an average salary of $20,000/year:

                   Composed of:      14,286 base salary
                                      4,285 fringe benefits
                                      1,429 overhead
                                    $20,000 Total

     The estimated manpower requirements and associated  costs are found in
Table 102.
b.  Consumables and Supplies

     The major portion of consumable costs is that required  for the purchase
of sulfur dioxide sorbents.  The AFB and CWS plants both require llaestone
while the PFB utilizes dolomite.  A charge of $5.00/ton is assumed for both
limestone and dolomite.  An average cost for water,  lubricants, and supplies
was calculated from existing coal-fired plant data resulting in an average
1975 cost of 0.20 mill/kWh.  It was then assumed that  these  consumables apply
to that portion of the plants which is considered conventional equipment.  The
cost for consumable is assumed to cover the cost of  water where it must be
purchased for makeup, and for the necessary water treatment  chemicals; water
treatment was estimated to cost $2.11/1000 gal of water treated.
c.  Solids Disposal

     No disposal costs are included in the  GE estimates  for AFB and PFB.  CWS
solids disposal costs are included in the form of disposal pond and sludge
handling costs.

                                   269

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                             Table 101

                         MAINTENANCE COSTS
 CWS  (747 MW)
   Steam Turbine-Generator
   Conventional Furnace
   Makeup Water Treatment
   Electrostatic Precipitators
   Water Intake Structure
   BOP
   Wet Scrubber System
 AFB  (814 MW)

   Steam Turbine Generator
   AFB Units
   Makeup Water Treatment
   ESP
   Water Intake Structure
   BOP
PFB (904 MW)

   Steam Turbine Generator
   Gas Turbine Generator
   PFB Units
   Makeup Water Treatment
   Water Intake Structure
   BOP
       $M/Yr.
                                                     Total
        1.20
        0.88
        0.04
        0.11
        0.04
        l^.Sj
Total   4.12
                                                     Total
Plant

 AFB
 CWS
 PFB


Super-
vision
17
14
17


Opera-
tors
50
42
50
Table
OPERATING
Fuel Syst
Tech Chera
Tech
18
15
18
102
LABOR
Laborers,
Clerks,
Guards,
etc.
25
20 -
25


Total
Operating
Personnel
110
91
110
    M$/Yr

     2.20
     1.82
     2.20
                                                                Net   Mills/
                                                               Output  kWh
814
747
904
0.47
 .43
0.43
                                 270

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     Table 103 contains  costs associated with consumables and supplies for
each of  the three power  plants.


4.  O&M:  SUMMARY

     The number of personnel required  to operate and maintain a power plant
will be  partly dependent on the  staffing practices of the particular utility
operating the plant.   Some utilities account for those employees not directly
applicable to power plant O&M, while others Hire some of their services from
outside  subcontractors.

     If  the utility operating a  plant  had  several other large plants nearby
so that  certain of the maintenance personnel, engineers, and technicians could
be shared, their staffing would  be accounted in a different way.  Our manpower
estimates represent judgment as  to the average  number of employees for each of
the plant types.  Other  factors  influencing staff sizes are site-related or
region-related or effects, such  as specific anion negotiated manpower requirements
by job classifications and labor productivity..
                    >
     The values selected for maintenance costs  on the major equipment items
also depend on the specific practices  for  routine preventative maintenance
and on the forced outage experience on each equipment item.  Maintenance costs
will depend on achieved  equipment reliability.  An additional complication
causing a range of values for maintenance  costs in varioi'c survey reports is
that of accounting practices, by which one may  keep track of maintenance expenses
on each individual item of equipment while others may group the expenses by sys-
tems or other categories.  The estimated values for maintenance costs are to be
taken as representative of a wide range of data reported by the various utilities.

     Table 104 gives  a detailed  breakdown  of all G&M costs.  These costs are
summarized in Table 105.
                                   271

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                               Table 103

       1                  OPERATING CONSUMABLES

   cws

   Convent- ional;   0.91 x 10  $/yr.

                      a    $5b                         ft
   Limestone;  125,000  x -j~j x 8760 x .65 = 1.78 x  10°  $/yr.
   Total!   0.91 + 1.78 = 2.69 x 106 $/yr.

           $2.69 x 106 x 1000 raills/dol        ,„   ,..,  „ ,.
           747 MW x 1000 kW/MW x 8760 x .65 ~ *63  mllls'kwh
   AFB


   Conventional;  1.05 x 106 $/yr

   Limestone;  (48,564.8 x 4 x 1..0626 lb/hr)a x ~jfi x 8760 x  .65

               = 2.94 x 106 $/yr

   Total;  2.94 -f 1.05"= 3.99 x 106 $/yr


             $3.99 x 106 x 1000 mills/dol   _  .,  .,,,,,-
           814 MW x 1000 kW/Minr8760TT65   -86mills/kwh
   PFB

   Conventional :  .82 x 10  $/yr


   Dolomite;  (83,963 x 4)a x-     - x 8760 x .65 = 4.78 x 106  $/yr
   Total;  .82 + 4.78 = $5.60 x 106 $/yr

              $5.60 x 106 x 1000     - I OQ
          904 MW x 1000 x 8760 x .65 ~ 1'-°-9
a.  Hourly throughout, total plant
b.  Cost of .loloiitite or limestone per pound
                                   272

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                                 Table 104

                             DETAILED O&M COSTS
1.  CWS (747 MW)
      Maintenance Costs

           Steam turbine generator
           Conventional boiler
           Makeup water treatment
           Electrostatic precipitators
           Water intake structure
           Scrubber system
           Balance of plant (BOP)
      Operational Coats

           Labor (91 Men)
           Consumables
      Total O&M Costs      n

2.  AFB (814 MW)

      Maintenance Costs

           Steam turbine generator
           AFB
           Makeup water treatment
           Electrostatic precipitators
           Water intake structure
           BOP


      Operational Costs

           Labor (110 Hen)
           Consumables


      Total O&M Costs
                                                   Total
                                                   Total
Total
Total
       (Mills/kWh)
          0.43
          0.63
          1.06
          2.61
       (Mills/kWh)
0.47
0.86
1.33
          2.22
                                    273

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                             Table 104 (continued)


3,  PFB (904 MW)

      Maintenance Costs                                   (Mills/kWh)

          Steam turbine generator                            0.19
          Gas turbine generator                              0.14
          PFB                                                0.29
          Makeup water treatment                             0.01
          Water intake structure                             0.01
          BOP                                                0.37
                                                Total        1.01

      Operational Costs      ,         . '

          LaboE (110 Men)
          Consumables -
                           ..   -                 Total
    .. Total O&H Costs           '                             2.53
                                 Table 105

                      OPERATING AND MAINTENANCE COSTS
                                SUMMARY TABLE
                 Plant     Maintenance     Operation

                   CWS          1.55           1.06
                   AFB          0.89           1.33
                   PFB          1.01           1.52
                                    274

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G.  GE COMPARISON OF ALTERNATIVES

     Future steam power plants may use atmospheric  fluidized beds (AFB) for
burning coal in the presence of limestone,  to  provide  sulfur capture during
combustion,  A more advanced concept would  be  the use  of pressurized fluidized
beds (PFB) with dolomite for sulfur capture and gas turbines for pressurizing.
Such plants have been evaluated in the Energy  Conversion Alternatives Study
(ECAS)3 on the identical basis and to the same degree  of detail as the steam
plants of this evaluation.

     Table 106 compares these alternatives  to  the conventional steam plants
with 175 F stack temperature (CWS 175).  The basis  for all table entries is
$/kW of net plant output.  The combination  of  Furnace  Modules, Hot Gas Filtering,
Solids Handling, and Stack Gas Scrubbers expresses  much of the cost of heat
release and sulfur and particulate capture. These  accounts aggregate S67/kW
for the AFB, $123/kW for the PFB, and $147/kW  for the  CWS.  The total capital
cost and the cost of electricity (COE) follow  a similar progression.

     The consumption of coal relates directly  to the overall efficiency of a
power plant.  A number of alternatives were evaluated  and are presented in
Table 107 in the order of decreasing efficiency.  The  two "no scrubber" cases
would require a coal with less than 0.65 percent sulfur for a 10,788 Btu/lb
(25.1 MJ/kg) higher heating value if they were to meet the emission standards
common to all of these plants.   The boiler  efficiency  follows the same pro-.
gression as the overall efficiency.  The steam turbine cycle efficiency equal
to 3412 divided by the heat rate also decreases toward the bottom of the table.
The conventional furnace with wet scrubber  and 175  F is the best current solu-
tion for combustion of high-sulfur fuels.  The penalty in efficiency and cost
of electricity are direct results of the environmental constraints, which
are fully met.

     The comparative amounts of sorbent required for sulfure capture are pre-
sented in Figure 43.  Both the conventional steam plant with wet scrubbers
and the AFB plant use limestone.  The excess applied is 10 percent for the
former and 100 percent for the latter.  The PFB plant  uses dolomite, which
has only half the concentration of available lime found in limestone.  The
conventional plant consumes the least sorbent  material.  The solid wastes
combine the ash and the solid products from sorbent reactions.

     The major water usage is evaporation from the  cooling towers.  The major
water waste that must be treated would be the  cooling  tower blowdown.  Figure 44
shows the same progression in water conservation that  would be found in coal
requirement.
                                 275

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                                Table 106

                   CAPITAL COST DISTRIBUTIONS AS  $/kW
            FOR 3500 PSI, 1000 F,  1000 F STEAM POWER PLANTS


                                            AFB      PFB       CWS       CWS
                                  :         1550 F   1650 F    175 F     250F
Major Components

     Steam Turbine-Generator                33.2      27.7      33.6      34.8
     Furnace Modules                        55.8      16.3      57.7      61.A
     Gas Turbines                                    28.3
    J3ot Gas Filtering                               71.4*
     Economizer                                       2.5
     Solids Handling                        11.4      35.6     JL5.Q      15.9

       Subtotal                            100.3     182.0     106.2     112.2

Balance of Plant
                                               ••*••
     Stack Gas Scrubbers                      -        -       56.8      69.5
     Site Labor                -           117.8     108.4     126.8     134.9
     All Other                             122/1      98.7     107.5     133.3

       Subtotal                            239.9     207.1     307.5     337.7
           - •                                J-ii •
Contingency                     n           68.0      77.8      82.9      90.0

Escalation and Interest                    223.8     255.8     273.0     295.8
Total Capital Cost                         632.      723       770       835
COE Mills/kWh                               31.7      34.1.     3/.0      39.8

*Estimate of hot gas filtering costs for PFB, prepared by Westinghouse for EGAS
 was approximately $15/kW.

                                Table 107

                    EFFICIENCY ORDER OF STEAM PLANTS
Type
Plant
PFB
PFB
CF
AFB
CF
CWS
CWS

Conditions
1750 F Beds
1650 F Beds
No Scrubber
1550 F Beds
No Scrubber
Wet Scrubber
Wet Scrubber

Stack
3 OOF
3 OOF
250F
250F
3 OOF
175F
250F
Overall
Efficiency
40.0%
39.2%
36.2%
35.8%
35.7%
33.8%
31.8%
Electricity
Mills/kWh
34.1
34.1
30.5*
31.7
31.6*
37.0
39.8
*3.9% in coal not permitted


                                   276

-------
Sorbent Required 1/kWh                                        Solid Waste f/KWh
0.4 0.3 0.2 0.1
i i i i
i i i _ . |. .. .. - 	 	


I1?-'. '.-..',;•-•; Conventional
Ste
(:;;:>•:::• :••;.:•: -.'.'V.--: .-.-. AfmrKp^pr
Be
am
ic Fluid
d
I:':'.'. :. -V;.V: ::'.•:•:•:•::..•••':•';:'::•.'•:••:•'.:•.•.•:•:•:'-•.: Prp
-------
         Water "Waste" Gal/kWh           Total Water Requirement GalfrWh
0.6         0.4         0.2                     0.2          0.4         0.6         0.8
 1	H	1	1	1	1	1	1
                               Conventional
                                  Sleam
                            Atmospheric Fluid
                            Pressurheu Fluid
                           Figure 44.  Water Requirement
                                        278

-------
      The gaseous emissions of  SOX and Nfl^ are compared in Figure 45.  The AFB
 and PFB, with combustion  in beds at 1550 F and 1650 F respectively, have
 produced notably low levels of NOx.  The conventional furnace requires a well
 balanced, staged combustion system in order to meet current NOX limitations.
•All plants satisfy the SOX limits, with the PFB showing the greatest raarg:'T.
                                      279

-------
ro

8
          Cycles





Advanced Steam -- AFB







Conventional Steam








Advanced Steam — PFB
                                                            Caseous Emissions (ib'10  Btu Input)
) .2 .4 .6
1 i I
/ZS//////S///////J2'j////'//y/St'/////'//±
,'
.".••-•••-• •.-.••: ::::.-:\ :.

&////////// ////./////////// ' ////s
•:•
y.'.'v^ •'-••;.- ••:;'. .•.-•' ..••* ••:•,".••."••.'"•-,-"." | ;

'.•////////s/////'////'//^////.-'////}
"
I:--.":-. \ :•

.8 1.0 1.2 1.
1 1 1 - - -r. 1
1 1. * 1
S

8
X
1

•§
^v

^
V-
\
1
                                                     Code:
                                                       NOX Solid Fuel Spec
                                                                        so


                                                                        'NO
                                                                                                             o
                                                                                                             01
                                                                                                            o
                                                                                                            3
SO  Solid Fuel Spec
                         Fiaure 45.   Gaseous Emission Characteristics (Lb/10  Btii  Input)

-------
               TVA MODIFICATION AND EXPANSION OF'GE STUDY
A.   INTRODUCTION    .                                :

     The capital and operating costs prepared by GE for the  CWS,: AFB, and PFB
were modified by TVA to take into consideration a number of  factors felt by
TVA to be significant.  Three major factors were addressed:

     1.   Modification of the estimates to include an uncertainty allow-i.ire
          allowance for plant components considered to  be  undembnstrated
          technology; and modification of the GE estimates for .various com-
          ponents where such revision is felt to be warranted based ;.pon TVA
          experience.

     2.   Expansion of the GE estimates to take into consideration alternate
          wet scrubbing techniques for the CWS case, in addition to the lime
          scrubber with on-site calcination used by GE.
                                          •fir-                 *
     3.   Modification and expansion of the GE esti-ntes of  residue disposal
          costs, to take into consideration:  (a) adequate provision for dis-
          posal over the full 30 year plstit lifetime for all cases and (b)
          alternate disposalcoptions.  Previously, GE included only 5-year
          disposal provisions for the CWS case, and none for AFB and PFB.
                                  281

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B.   MODIFICATION OF GE ESTIMATES BY TVA

     Shovn in Table 108 are the GE study cost  comparison and TVA's modified
cost estimates of the three types of steam plants.   Both the GE and the TVA
figures in Table 108 are based on the assumption  that all three type plants
are of a mature technology; they attempt to compare  the costs of the three
types of plants after they have been developed to a  point of commercially
acceptable risk for construction and operation^  The TVA estimates include
uncertainty allowances reflecting the fact that some of the plant components
are not truly "mature technology" today.  These allowanr.es include items such
as design changes, addition of equipment, and  technological changes, and are
an attempt to reflect what the costs for as yet underaonsLrated components may
actually turn out to be.  These cost modifications do not incorporate develop-
ment costs or startup costs associated with obtaining a state-of-art process.

     TVA estimates in Table 108 also include increases in equipment costs and
associated labor and material costs because the GE costs differed greatly
from cost estimates based on quotations received  by  TVA.  TVA cost figures
for equipment were obtained from data presently on file,  tost of the com-
ponents presently in an 800-MW and a 1200-MW coal-fired unit on the TVA system
was escalated to mid 1975 dollars.  Information from a recent cost estimate
for three 867-MW coal-fired units was also used.  These values were used to
modify the GI study estimates.

     These estimates should not be construed as an estimate of costs for which
TVA believes these plants could be constructed today.  TVA cost figures are
only modifications of the GE study cost figures.


Uncertainty Allowance

     TVA has assigned an uncertainty factor (unc.) to  those items in the
two fluidized bed concepts which are considered mature technology but on
which  full-scale development has not taken place. Those  items are stean
generators, fuel injection systems, spent solids  and dust coolers, and
portions of hot gas cleanup systems.  This factor was  applied for uncer-
tainties of design and  scale-up of components and not  for costs to develop
the components or to start up the process.

     The amount of contingency added by  EN DES was  based  on the following
conditions:

          Uncertainty

              20%         Development is  currently at a point  to provide
                         reasonable confidence of commercial  success.

              40%         Development is  currently at a point  of reasonable
                         definition of detailed technical problems  to  be
                          solved.
                                    282

-------
                              Table 108

              COST COMPARISON OF GE STUDY VS. TVA REVIEW

                  Total Capital  Costs  (1975 dollars)
PLA1
-------
             60%         Major technical breakthrough required to demon-
                         strate acceptability of a system for commercial
                         operation.

     These uncertainty factors are in addition to the 20 percent contingency
adf'.ed to the total plant costs of each plant evaluated by General Electric.
These factors were considered in the evaluation of the GK study cost estimates
and the estimates were adjusted accordingly.  The resulting estimates for the
items of equipment that pertain to the above categories are as follows:

          Atmospheric fluidized bed
          (Process mechanical equipment)
                                                          Equipment     BOP
          1.  Spent bed coolers
                Solids Cooler & Cyclones
                (add 20 percent unc.)

                  Equipment cost:  $312,000 x 2 x 1.2                  .749M
                  Other equipment of spent bed cooling =     '          .276
                                                                      1.025M

          2.  Coal and limestone blending & feeding
              (add 20 percent unc.)      '*••

                All equipment $2.74M x 1.2                =  3.288
                BOP materials   .930 x l*-2                =           1.116
                             r,
                Other process mechanical equipment
                Cost                                     '•*
                Other BOP material costs                  = 	u     28.394
                                               Subtotal    $10.1211   $29.51M

           (Component)

           3.  Hot gas cleanup air supply
                Most items state of art except
                fines injection (add 20 percent unc.)

                Equipment cost
                 $260,000 x 2 x 1.20                      =   .624M
                Other hot gas cleanup equipment           = 15.31

                Total equipment                           * 15.93M

                  BOP materials                                  -      0.61M

           4.  AFB module
               (add 20 percent unc.)

                Tower components, controls, ducts
                 29.72 x 1.2                              = 35-66
                BOP materials 5.%9 x 1.2                  = 	     6.83.

                                               Subtotal    $51.59M    $7.44M
                                   284

-------
     These are capital cost adjustments only.   TVA cost estimates also adjusted
labor as needed for both AFB and PFB.

                                                         Equipment     BOP

          Pressurized fluidized bed

          Process Mechanical Equipment

          1.  Coal processing and feeding

                2 Petrocarb coal injection system
                (add 20 percent unc.)

                  Equipment cost
                  7*198,354 x 2 x 1.20                   = 17.28
                  Remaining equipment                     =  3.64

                  Total coal process                       20.92M
                 »
          2.  Dolomite processing and  feeding

                2 petrocarb injection  system
                (add 20 percent unc.)

                Equipment cost
                 3,851,375 x 2 x 1.20                     =  9.24
                Remaining equipment                      =  2.03

                Total dolomite process                     11.27M

          3.  Spent bed material (add  40 percent  unc.)
              to equipment, 20 percent to labor and
              materials)

                Equipment 1.58 x 1.40                     =  2.21M
                BOP materials 3.57 x 1.2                              4.28

                Other process mechanical
                 equipment component costs               =  5.39
                       i
                Other process mechanical
                 equipment BOP material costs             = 	     22.63
                                               Subtotal    $39.79M   $26.91M

          Components     '

          4.  Hot gas cleanup (add 20 percent  unc.)

                Equipment 64.51 x 1.20                   =77.41
                BOP material 2.04 x 1.20                 =            2.45
                                  285

-------
                                                         Equipment     BOP

    1      5.  PFB module cost (add 40 percent unc.)

                Equipment 14.68 x  1.40                    = 20.55
                BOP material 1.06  x 1.40                  = 	      1.48

                       '                      Subtotal    $9/.96M    $3.91M
                       f
     In addition to the uncertainty factors, modification of the following
areas was involved in arriving at  the TVA estimates.
                       i
                       i

Boiler Enclosure for PIB

     To be consistent with the other to plants and TVA's practice to enclose
its boilers, the following boiler  enclosure costs were added to the pressurized
fluidized bed costs.

                   Direct manual field labor - 41,000 MH
                   Material costs            - $1.63M
Electrical Subsystems

     TVA feels that the GE study estimate did not provide enough manpower and
money for electrical subsystems.  The largest difference in electrical costs
between the GE study and TVA cost estimate is the cost of materials and labor
for instrumentation and controls with TVA costs  being much greater than allo-
cated by the GE study estimate.  The estimate for the remaining electrical
equipment by TVA was actually less than the GE study.  Although TVA uses an
elaborate instrumentation and control system for its plants, this would only
account for a small amount of the cost difference between EN DES and the GE
study estimate.

     Tables 109, 110, and 111 show the capital cost breakdown as modified
by TVA for the CWS, AFB, and PFB plants.

     The GE study estimate was reviewed for technical accuracy and suggested
modifications were made for good utility design. The GE designs were con-
sidered technically accurate for equipment sizing, auxiliary losses, conditions
of operation, and overall efficiencies.

     The uncertainty factor had a major impact on the AFB and PFB cost
estimates with very little impact on the conventional plant  (CWS).  In a
cost comparison of CWS prime cycle and electrical equipment, the GE cost
figures and TVA's recent cost figures for the  867-MW units were
approximately the same.

     There is no information available on utility wide accounting methods;
therefore, no efforts to recommend changes in  defining indirect cost is
included.  Therefore, the GE cost estimate for the  conventional plant with
scrubber is assumed to be reasonable and certainly  attainable.


                                   286

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                                                       Table  109


                                              TVA -  CAPITAL COST BREAKDOWN

                             CONVENTIONAL STEAM PLANT - WET CAS SCRUBBERS - 175 F STACK  (CWS 175)
           CATEGORIES


1.0  Steam Generators


2.0  Turbine Generator


3.0  Proces§ Mechanical Equipment


4.0  Electrical(a)


5.0  Civil and Structural

           t>
6,0  Process Piping and Instrumentation


7.0  Yardwork and Miscellaneous
                                                            COSTS  (MILLIONS OF DOLLARS)
COMPONENTS DIRECT LABOR(l) INDIRECT FIELD(2)
45.88 13.40 •
26.75 1.41
7.76
: 8.59
12. If?
(3) 16.40
3.06
72.63 63.12 f ^
BOP LABOR, MATERIALS
(SUM OF 1+2+3)
A/E HOME OFFICE & FEE
12.06
1.27
6.98
8.09
10.89
14.76
2.75
56.80
1, INDIRECTS
(9.15%.
MATERIALS (3) TOTAL
8.70
0.10
43:30
11.77
16.10,.
23.68
1.70
• 105.35
225.27

TOTAL PLANT COST
. CONTINGENCY @ 20%
TOTAL CAPITAL COST (BOP) >
ESCALATION & INTEREST ''
TOTAL COST
80.04
29.53
58.04
28.85
39.09
54.84
7.51
297.90

33.79
331.69
66 54
398.03
218; 92
616.95
 (a)  Revised by TVA to reflect reasonableness
On

-------
                                                     TABLE 110 - AFB

                                         TVA - EN DES - CAPITAL COST BREAKDOWN
                                   ADVANCED STEAM CYCLE - ATMOSPHERIC FLUIDIZED BED
                                                                COSTS (MILLIONS OF DOLLARS)
           CATEGORIES

1.0  Steam Generators

2.0  Turbine Generator

3.0  Process Mechanical Equipment

               (0
(b)
4.0  Electrical

5.0  Civil and Structural

6.0  Process Piping and Instrumentation

7.0  Yardwork and Miscellaneous
COMPONENTS DIRECT LABOR(l) INDIRECT FIELD (2)
51.74 11.97
27.00 1.53
10.12 6.27
10.90
10.40
(C) 11.63
1.59
88.86 54.29
ROP LABOR, MATERIALS &
(SUM OF 1 + 2 + 3)
A/E HOME OFFICE & FEE 
-------
                                                     Table 111 - PFB

                                          TVA -  EN DES - CAPITAL COST"BREAKDOWN
                                     ADVANCED STEAM CYCLE - PRESSURIZED FUHDIZED BED
                                                        1650 F
                                                                COSTS (MILLIONS OF DOLLARS)
           CATEGORIES

1.0  PFB Steam Generators

2.0  Turbine Generators
(b)
                                 (b)
3.0  Process Mechanical Equipment
               (el
4.0  Electrical^ '

5.0  Civil and Structural

6.0  Process Piping and Instrumentation

7.0  Yardwork and Miscellaneous
COMPONENTS DIRECT LABOR(l) INDIRECT FIELD(2)
97.96 5.86
50.62 1.70
39.79 6.51
10.14
10.48
(C) 16.10
1.59
18S.37 52.38
BOP LABOR, MATERIALS &
(SUM OF 1 + 2 -*- 3)
A/E HOME OFFICE & FEE @
5.27
1.53
5.86
9.12
9.42
14.49
1.41
47.12
INDIRECTS
157.
MATERIALS (3) TOTAL
2.93
0.20
26.91
11.66
12.83
26.90
1.70
84.13
183.63

TOTAL PLANT COST
CONTINGENCY £ 20%
TOTAL CAPITAL COST (BOP)
ESCALATION i, INTEREST
TOTAL COST
113.02
54.05
79.07
30.92
32.73
57.49
4.72
372.00

27.54
399.54
79.91
479.45
263.70
743.15
 (b)  Contingency added by EN DES.
 (c)  Revised for reasonableness by EN DES.
 (d)  Boiler enclosure addition.
 CD

-------
     Ir. the TVA review of rhe plant plans providsd  with the study, it was
apparent that all plants were compacted into a small area.  Some areas
would be iracsessible for maintenance of heavy equipment if required.  It
should be a utility's obligation to determine its own  site layouts in accor-
dance with their own design, land use, and equipment requirements.

     Although modification to some equipment and  to the site layout may be
desirable, these changes were not added to the cost comparisons since they
had negligible p'r^t on costs.

     TVA selected the GE 175BF stack gas. temperature design as the CWS "base
case."  Considering lime scrubbers for 100 MW and larger units in the United
States, none of the nine in operation reheat to ovr 175°F.  Information
available to TVA indicates that there are no benefits  derived frcro: reheating
above 175°F.  As added assurance of .corrosion prevention at I75°F, budget
cost figures for fiberglass ductwork and chimney  liner are presented fot
information although not included In the TVA estimate  for CWS.

     Scrubbers with 175°F stack gas temperature could  cause corrosion of
the duct after the reheater and the steel chimney liners if the.mist ells
tors do not operate with maximum eff.-ciency.  To  combat corrosion, the u'&e
of fiberglass ductwork and chimney liters capable of continuous, 3°5SF stack-
temperature is proposed.  The cost of fiberglass  chimney liners 30 feet in »~
diameter, 500 feet high is $1,100,000 for materials and installation.  The
cost of fiberglass ductwork llrora the mist eliminators  to the stack is esti-^
mated at $1,700,000 for materials and installation. These cost figures
should ba substituted in the GE study for the respective chimney liner and
ductwork, but, as stated above, these iigures have  not been included in the
TVA estimates presented in this report.
                                   290

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C.  ALTKRTATIVEJWET SCRUBBER CASES

     The scrubber costs of the GE study were deemed reasonable for the six
train lime scrubber using TVA Widows Creek unit  No, 8 retrofit as a reference.
However, cost estimates of a new plant indicate  lower scruM.er cost may
be achieved when included in a total project cost.  Costs could be reduced
if the unit had four scrubber trains instead of  six as provided by the fiE
study.  Technology developments which permit an  increase in scrubber thru-
gas velocity from 8 ft/s to 12.5 ft/s make this  possible.

     Summarized in Table 112 are estimates of direct capital investment
and direct operating costs in mid-1975 dollars for the following scrubbing
systems:

            • Lime scrubbing with onsite calcination
            • Lime scrubbing without onsite calcination
            • Limestone scrubbing
            • Magnesium oxide regenerable scrubbing (production of sulfuric acid)

     The scrubbers are preceded by a 99 percent  efficient electrostatic pre-
cipitator.  Onsite untreated ponding of scrubber we -.tes for a 30-year period
is included in the lime and limestone scrubbing  syrterns.

     The estimates were prepared on the same general ground rules and assump-
tions as the GE study.  The major design and economic premises are Us ted in
Table 113.  The operating conditions for the lime and limestone scrubbers are
based on test results at Shawnee.  The operating conditions for the m;u;nesla
process are essentially the same as reported by  McGlsmery, et al.—  with some
adjustments r;ade based on the operating experience of Koehler and Burns ..I'' The
hot air injection reheat used for all processors is based on the Widows Creek
limestone process design.

     Sucmaries of the direct investment by process area are shown for the four
scrubbing systems in Tables 114 through 117.  To obtain the total cnntt.tl
cost (in raid-1975 dollars) of the scru'^ber system, it is necessary to add
indirect construction costs, A&E service costs,  and a contingency for expendi-
tures expected though not accounted for.  These  costs are accounted for in the
following manner:

        Total direct investment                            1.00
        Indirect construction costs @ 25%                  0. 25
                                             Subtotal       1.25
        A&E services 
-------
                                Table 112
                        SUMMARY OF DIRECT COSTS
    SCRUBBING SYSTEM

Lime slurry process with
 onsite calcination

Line slurry process without
 onsite calcination

Limestone slurry process

Magnesia slurry-regeneration
 process
DIRECT CAPITAL    DIRECT OPERATING
INVESTMENT. $      COSTS, $/YR.
  39,157,000


  32,190,000


  36,745,000

  32,899,000
5,409,700


5,971,000


4,267,500

6,271,900
a.  Basis:
     865* MM gross new coal-fir'id power tfnit, 3.9% S in fuel;  83% S02
     removal.  Stack gas reheat: to 175°F by heated air injection.
     Disposal pond  (if required) located one mile from power  plant.
     Pond sized for 30 year operation-at 65% capacity.
     Coat basis:  mid-1975=;
     Minisaum in-process storage; only pumps are spared.
                                    292

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                               Table 113

                  GENERAL DESIGN AND ECONOMIC PREMISES
                FOR TVA ESTIMATE OF WET SCRUBBING SYSTEMS

         f
  I.  Design Premises

      A.  The power plant has a gross generating capacity of 869 MW.  It has
          a 30 year life, operating at  0.65 capacity or 5694 hr/yr.

      B.  Coal composition is the same  as ECAS.

      C.  Flue gas rate and composition are the same as ECAS.

      D.  Reheat is hy heated air injection to reheat flue gas to 175°F.

      E.  83% of the S0_ is to be removed.

      F.  Bypass ducts are provided.  No redundant scrubbers are present.

      G.  99% of the particulates are removed with an ESP.  The costs for
          particulate removal:and ash handling are not included in this
          estimate.

      H.  Chevron vane mist eliiranators with intermittent wash are included.

      I.  Raw material storage is provided for 30 days operation.

      J.  Cnsite untreated ponding of solids wastes is provided.


 II.  Economic Premises

      A.  All investment and operating  costs are in mid-3975 dollars.
          Investment costs are scaled to mid-1975 by using Chemical
          Engineering material and labor indicts.

      B.  Working capital is not considered.

      C.  Capital -narges are at 18%/yr.


Til.'"'Additional Design Premises for Wet Lime Scrubbing

      A.  Four S0_ absorber units are required.

      B.  3 stage TCA type is required.

      C.  Superficial gas velocity is 12.5 ft/sec.
                                   293

-------
                         Table 113 (continued)






     D-  Total pressure drop is 6" HjO in the scrubber.




     E.  Liquid/gas ratio is 50 gal/MSCF.




     F.  Presaturation spray is 2.5 gal/MSCF.




     G.  Lime/S02 absorbed stoichiometry is 1.05.




     H.  Absorber hold tank residence time is 10 min.




     I.  Recycle slurry solids is 8% by weight.




     J.  Lime makeup slurry solids are 20% by weight.




     K.  Spent slurry pond solids is 40% by weight.




     L.  Calcination offgas meets S0_ emission requirements.






TV.  Additional Design Premises for Wet Limestone  Scrubbing




     A.  Four SO- .absorber units are required.




     B.  3 stage TCA type is required.




     C.  Superficial gas velocity is 12.5 ft/sec.




     D.  Total pressure drop is 7" H-0 in the scrubber.




     E.  Liquid/gas ratio is 40 gal/MSCF.




     F.  Presaturation spray is 2.5 gal/MSCF.




     G.  Limestone/S07 absorbed stoichiometry is 1.50.




     H.  Absorber hold tank residence time is 10 min.




     I.  Recycle slurry solids is 10% by weight.




     J.  Limestone makeup slurry solids are 60%  by weight.




     K.  Spent slurry pond solids is 402 by weight.
                                   294

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                       Table 113 (continued)






V.  Additional Design Premises for Magnesium Oxide Scrubbing




    A.  Four S02 absorber units are provided.




    B.  One stage venturi is provided.




    C.  Superficial gas velocity is 75 ft/sec.




    D.  Total pressure drop is 6" H20 in the scrubber.




    E.  Liquid/gas ratio is 20 gal/MSCF.




    F.  Presaturation spray is 2.5 gal/MSCF.




    G.  Magnesia/S02 absorbed stoichiometry is 1.05.
                                 295

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          Table 114 - Lime slurry (onsite calcination)
          Table 115 - Lime slurry (offsite calcination)
          T.ible 116 - Limestone slurry
          Table 11? - Magnesia slurry (regenerable MgO)

     Direct annual operating costs for these systems were estimated and are
included in the following tables:

          Table 118 - Lime slurry (onsit°. calcination)
          Table 119 - Lime slurry (offsite calcination)
          Table 120 - Limestone slurry
          Table 121 - Magnesia slurry (regenerable MgO)

     To obtain total operating costs, it is necessary to add overhead charges.
TVA feels that an appropriate factor for scrubber O&M overhead is 50 percent
of total direct costs.

     The magnesia slurry process makes a saleable product, 37.5 tons/h of
sulfuric acid.  To obtain the net revenue required for this process a credit
for byproduct sales needs to be considered.  A conservative estimate for sales
revenue is $25/ton of sulfuric acid.  Table 321 does not include any acid
sales credit.

     The GE cost estimate provides for only 5 years of ponding at a direct
cost of $490,000 for an unlined pond.  Additional ponds will be required over
the life of the plant but provision is not made for them in the GE cost
estimate.  It is granted that in actual practice disposal ponds may be con-
structed at intervals as required.  However, in comparing alternatives these
future expenditures need to be recognized.  The TVA estimate does this by
providing for a clay-lined disposal pond adequate for 30-year operation at a
cost of $7,099,000.

     The difference  ($4.2 million) between the GE and TVA estimates of direct
costs of the lime scrubbing systems, excluding the disposal pond, is concen-
trated in the scrubbing area costs.  This is because the GE design premises
specify 8 ft/s superficial gas velocity with rix scrubbers, while the TVA
design premises specify 12.5 ft/s superficial gas velocity with four scrubbers.

     The sludge disposal pond requirement specified in the EGAS report,
39,270 acre ft (1780 acres x 22 ft deep) for 5 years, is excessive.  The GE
material balance shows a settled used slurry rate of 573 gpm, which corresponds
to a settling pond requirement of about 20,000 acre ft. for 5 years.  This
difference in disposal pond requirements is significant when the cost of
disposal ponds and land is considered.
                                  296

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                                    Table 114

                   LIME SLURRY PROCESS WITH ONSITE CALCINATION
                          ONSITE UNTREATED POND STORAGE
                       SUMMARY OF TOTAL DIRECT INVESTMENT3
              (869 MW gross new coal-fired power unit,  3.9%  S  in  fuel;
                                 83% S02 removal)
                                                    Direct         Percent of
                                                 investment,  $  direct investment
Materials handling  (limestone receiving area,
  coal receiving area, hoppers, feeders, con-
  veyors, elevators, bins, front-end loader
  and lime storage  bin)
Limestone calcination  (complete rotary kiln
  including coal grinding, control system,
  drives, fans, baghouse dust collector,
  ducting and stack)
Feed preparation (feeders, conveyors, slakers
  pumps, tank and agitator)
Sulfur dioxide scruobers (4 mobile bed
  scrubbers, including feed plenum, pumps, mist
  eliminators, soot blowers, and tanks)
Stack gas reheat (4 heated air injection
  raheaters, fans and ductwork)
Gas handling (fans, and flue ductwork)
Calcium solids disposal (onsite disposal
  pond, clsy liner, tank, and pumps)
Utilities (instrument air generation and
  supply, system, distribution systen for
  process steam, water and electricity)
Service facilities  (buildings, shops, stores,
  site development, roads, railroads, and
  walkways)
Construction facilities
     Subtotal direct investment excluding land

Lend (622 acres)

Total direct investment
 1,242,000



 6,644,000

   778,000


 8,794,000

 1,313,000
 6,786,000

 8,097,000


   129,000


 1,232,000
 1,776,000
37,291,000

 1,866,000

39,157,000
  3.17



 16.97

  1.97


 22.46

  4.63
 17.33

 20.68


  0.33


  3.15
  4.54
 95.23

  4.77

100.00
a.  Basis:
     869 MW gro.'js new coal-fired power unit, 3.9% S in fuel;  83%  SO- removal.
     Stack gas reheat to 175°F by heated air injection.
     Disposal pond located one mile from power plant.   Pond sized for 30 yr
      operation at 65% capacity.
     Cost basis:  mid-1975.
     Minimum in-process storage; only pumps are spared.
                                      297

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                                    Table 115

                               LIME SLURRY PROCESS
                          ONSITE UNTREATED POND STORAGE
                       SUMMARY OF TOTAL DIRECT INVESTMENT3
             (869 MW gross new coal-fired pover unit,  3.9%  5  in fuel;
                                 83% S02 removal)
                                                    Direct         Percent of
                                                 investment,  $  direct -investment
Materials handling (lime bins, feeders,
conveyors, elevators)
Feed preparation (feeders, conveyors, slakers,
pumps, tank and agitator) ~'
Sulfur dioxide scrubbers (4 mobile bed
scrubbers, including feed plenum, pumps, mis£
eliminators, soot blowers, and tanks)
Stack gas reheat (4 heated air injection
reheaters, fans and ductwork) *
Gas handling (fans, and flue ductwork)
Calcium solids disposal (onsite disposal
pond, cla.y liner, tank, and pumps) «•••
Utilities (instrument air generation and
supply system, distribution system for
process steam, water and electricity)
Service facilities (buildings, shops, stores,
site development, roads, railroads, and
walkways)
Construction facilities
Subtotal direct investment excluding land
Land (616 acres)
Total direct investment

1,529,000

778,000


8,794,000

1,813,000 >
6,786,000

8,097,000


118,000


969,000
1,458,000
30,342,000
1,848,000
32,190,000

4.75

2.42


27.32

5.63
21.08*:

25.15


0.37


3.01
4.53
94.26
5.74
, 100.00
a.  Basis:
     869 MW gross new coal-fired power unit,  3.9% S in fuel;  83%  S02 removal.
     Stack gas reheat to 175°F by heated air  injection.
     Disposal pond located one mile from power plant.   Pond  sized Cor  30 yr
      operation at 65% capacity.
     Cost basis:  mid-1975.
     Minimum in-process storage; only pumps are spared.
                                    298

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                                    Table 116

                            LIMESTONE SLURRY PROCESS
                          ONSITE UNTREATED POND STORAGE
    .         '          SUMMARY OF TOTAL DIRECT INVESTMENT3


             (869 MW gross new coal-fired power unit,  3.9%  S in fuel;
                                 83% S02 removal)


                                                    Direct         Percent of
                                                 investment, $  direct investment

Materials handling (limestone receiving area,
  hoppers, feeders, conveyors, elevators,
  and bins)                                        1,139,000          3.10
Feed preparation (feeders, crushers, eleva-
  tors, ball mills, tanks, and pumps)              2,362,000          6.43
Sulfur dioxide scrubbers (4 mobile bed
  scrubbers, including feed plenum, pumps, mist
  eliminators, soot blowers, and tanks)            9,140,000         24.87
Stack gas reheat (4 heated air injection
  reheaters, fans and ductwork)                    1,813,000          4.93
Gas handling (fans, and flue ductwork)             6,913,000         18.82
Calcium solids disposal (onsite disposal
  pond, clay liner, tank, and pumps)              10,156,000         27.64
Utilities  (instrument air generation and
  supply system, distribution system for
  process steam, water and electricity)             118,000          0.32
Service racilities (buildings, shops, stores,
  site development, roads, railroads, and
  walkways)                                        1,120,000          3.05
Construction facilities                            1,638,000          4.46
    Subtotal direct investment excluding land     34,399,000         93.62

Land (782 acres)                                   2,346,000

Total direct investment                           36,745,000
a.  Basis:
     869 MW gross new coa.r-fired power unit,  3.9% S  in fuel; 83% S02 removal.
     Stack gas reheat to 175°F by heated air  injection.
     Disposal pond located one mile from power plant.  Pond sized for 30 yr
      operation at 65% capacity.
     Cost basis:  mid-1975.
     Minimum in-process storage; only pumps are spared.
                                      299

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                                        Table 117

                          MAGNESIA SLURRY—REGENERATION PROCESS
                            SUMMARY OF TOTAL DIRECT INVESTMENT3
                 (869 MW gross new coal-fired power unit,  3.9% S  in fuel;
                         83% S02 removal; 37.5 tons/hr 100% H-SO.)


                                                       Direct        Percent of
                                                     investment ,  $  direct investment

    Magnesium oxide and coke receiving and storage
      (pneumatic  conveyor and blower, hoppers, con-
     veyors, elevators, and storage silos)               427,000          1.30
    Feed preparation  (feeders, conveyors, eleva-
     tors, tank, agitator and pump)                      505,000          1.54
    Sulfur dioxide scrubbers! (4 ^anturi scrubbers
     including feed plenum, pumps, mist eliminators,
     soot blowers, and tanks)                          5,102,000         15.51
    Stack gas reheat  (4 heated air injection
     reheaters,  fans and ductwork)                     1,687,000          5.13
    Gas handling (fans, ?nd flue ductwork)             8,276,000         25.15
    Slurry processing (screens, tanks, pumps,
     agitators and heating coils, centrifuges,
     conveyors,  and elevators                          1,580,000          4.80
    Drying (fluid bed dryer, fans, combustion
     chamber, dust collectors, conveyors, eleva-
     tors, and MgSO  storage silo)                     2,182,000          6.63
    Calcining (fluid bed calciner, fans, feeders,
     conveyors,  elevators, waste heat boiler,
     dust collectors, and recycle MgO storage silo)    2,466,000          7.50
    Sulfuric acid plant (complete contact unit
     for sulfuric acid production including dry
     gas purification system)                          6,666,000         20.26
    Sulf'iric acid storage (storage and shipping
     facilities  for 30 days production of H-SO^)         585,000          1.78
    Utilities (instrument air generation ana
     supply system, fuel oil storage and supply
     system, and distribution system for obtain-
     ing process steam, water and electricity
     from power plant)                                   472,000          1.43
    Service facilities (buildings, shops, stores,
     site development, roa;(s, railroads, and
     walkways)                                         1,350,000          4.10
    Construction facilities                            1,565,000          4.76
        Subtotal direct investment excluding land     32,863,000         99.89

    Land (12 acres)                                      36,000          0.11
    Total direct investment                           32,899,000         100.00


    a.  Basis:
         869 MW gross new coal-fired power unit,  3.9%  S  in fuel; 83% S02 removal.
         Stack gss reheat to 175°F by heated air  injection.
300      cost basis:  mid-1975.
         Minimum in-process storage; only pumps are spared.

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                                             Table 118

                             LIME  SLURRY PROCESS WITH ONSITE CALCINATION
                                   ONSITE UNTREATED POND SlOKAfili
                              AVERAGE ANNUAL ntRECT OrERAflNf. COS^S*
(869 1HW gross coal-fired power unit, 3.'K S In fuel;
83Z S02 removal)
Total annual
Anmi.il quantity Unit cost, S cost, 5 o
Delivered raw material
Lines tone
Coal
Subtotal taw material
Conversion costs
Operating labor and supervision
Utilities
Process water
Maintenance
tabor and material - .06 x 37,291,000
Analyses
Subtotal conversion costs
Total direct costs
Equivalent unit direct operating cost
267.4 M ton 5.00/ton 1.337.000
31.3 M ton 21.58/ton 675,300
2,012/500
88,570 man-hr 11.75/nan-hr 1.0407700
282,900 M gal 0.10/M gal 28,300
2,237,500
6.045 man-hr 15.00/man-hr 90,700
Percent of
total direct
peratinp. cost
24.71
12.49
37.20
19.24
Q.52
41.36
1 . 68
* 3,397,200 62.80
5,049.700 .100.00
Dollars/ton b Cents/million Dollars/ton
coal hurried .' Mllls'/kKh Btu he.it input sulfur re-moved
2.5). 1.19 11.63 77
••f •
.49
a.  Basis:
     Life of power plant, 30 yr. at 651 capacity or  5694 hrs/yr.
     Coal burned 2,156,550 tons/yr, 9404 Btu/kWh (f?ross>.
     Stack gas 1 cheat to 175'F.
     Direct investment, $39,157,000.
     Investment and o|crating cost for removal and disposal of fly ash excluded.
     Steam required from power plant 112,860 !i Ib (620'F, 130.3 psig).
b.  Net electricity generated:
     Steaa cycle output                                868.6 MW
     less:  Scrubber                           5.9 MW
            ID fan                             8-8
            Other (from EGAS Fhase II, p. 7*!> 5J>.J	
     Total auxiliary losses                            _70.4 tW
     Net output                                        798.2'WW
                                        301

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                                              Table 119

                                          L1MF. SLURRY PROCESS
                                     ONSITE I'NTRFATED I'OS'I) STOW/IE
                               AVERAGE ASNL'AL DIRECT OPERATING COSTS3
                          (869 MK gross  coal-fired j>owr unit, 3.9" 3 In fuel;
                                            832  SO  removal)
 Delivered raw material
   Line
      Subtotal raw material

 Conversion costs
  'Operating labor and supervision
   Utilities
     Process water
   Maintenance
     tabor and material - .06 x 30,342,000
   Analyses               ,
      Subtotal conversion costs

        Total direct costs
                                                                                           Percent  of
                                                                           Total  annual   total  direct
                                             Annu.il quantity  Unit cost, $     cost,  S    op?ratlm!  cost
  134.9 M tons   28.03/ton



 24,210 nan-hr   11.75/wan-lir

282,900 M gal      0.10/M gal


  4,030 raan-hr   15.00/raan-hr
3,777,200
3,777,200
                                                 3. 26
63.26
284,500
28,300
1,820,500
60,500
2,193,800
5,971,000
4.76
0.48
30.* 9
1.01
36.74
100.00
 Equivalent unit, direct operating cost
                                           Dollars/ton              Cents/million    Dollars/ton
                                           coal  burned  Mtlls/kMi   Btn heat Input   sulfur rrnovod
                                              2.77        1.31          12.83      '     85.53
 a.  Basis:
      Life of power plant, 30 yr. at 65% capacity or 5694 hrs/yr*
:-'•:    Coal burned 2,156,550 tons/yr, 9404 Btu/kUh (gross).  .
      Stack g^s reheat to 175°F.
      Direct investment, 532,190,000.
      Investment and operating cost for rcinoval and disposal of fly ash excluded.
      Steam required frorc powur plant 112,860 M Ib (620°F,  130.3 psip).
 b.  Net electricity genorated:
      Steam cycle output                                868.6 MU
      less:   Scrubber                           5.2 HH
             ID fan                             8.8
             Other (from EGAS Phase II, p.  72) 55.7
      Total auxiliary losses                             69.7 W.3
      Ket cutpot                                        798.9 MW
                                       302

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                                             Table 120

                                      LIMESTONE SLURRY PROCESS
                                    ONSITE UNTREATED t'OSD STORAGE
                               AVERAttE ANNUAL DIRECT OPERATING COSTS3
                         (869 KM gross coal-fired  power unit, 3.9," S in fuel;
                                           83X S02  removal)
Delivered raw material
  Llrccs tone
     Subtotal raw material

Conversion costs
  Operating labor and supervision
  Utilities
    Process water
  Maintenance
    La.^or and material - .06 x 34,399,000
  Analyses
     Subtotal conversion costs

      Total direct costs
Equivalent unit direct operating cost
                                                                                         Percent of
                                                                          Total  annual   total direct
                                                                             cost,  $    opfr.-itlnp. cost
336.8 M tons
35,040 tnan-hr
403,200 H gal
5,040 tnan-hr

5.00'i.on
11.75/nan-hr
0.08/K gal
15.00/roan-hr

Dollars/'-on . Cents/mil
ccal burned Mllls/kWh Btu heat
1,684,000 39.46
1.6K4.000 39.46
411,700 9.65
32,300 P. 76
2,063,900 48.36
75,600 1.77
2,583,500 60.54
4,267,500 100.00
Mon Dollars/con
input sulfur renewed
a.  Basis:
     Life of power plant, 30 yr. at 65% capacity or 5694 hrs/yr.
     Coal burned 2,156,550 tons/yr, 9404 Btu/kVh (Rross).
     Stack gas reheat to 175°F.
     Direct investment, $36,745,000.
     Investment and operating cost for removal and disposal of fly ash excluded.
     StcjiD required from power plant 112,860 M Ib (620°F,  130.3 pslfi).
b.  Net electricity Reneratcd:
     Stcara cycle output                                868.6 MW
     less:  Scrubber                           5.6 HW
            ID fan                             9.2
            Other (from EGAS Phnse II, p. 72) 55.7
     Total aaxlllary losses                             70.5 MW
     Net output                                        798.1 >!W
                                            303

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                                           Table 121
                                     MAT.HESIA SLURRY PROCESS
                              AVERAGE ANNUAL DIRKCT OPERATING COSTS"
(669 IIU' gross coal-flrod power un;
83X S02reraovai; 37.5 tons/hr
Annual quantity
Delivered raw material
Haf.nc=Ium oxide (9£2)
Coke,.,
Catalyst
Subtotal raw material
Converrion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process vater
Maintenance
Labor and material - .06 x 32,863,000
Analyses
Subtotal conversion costs
Total direct costs
Dollars/ton
100% H2SO,,
Equivalent unit direct
operating cost 29.37

2,075 tons
1,473 tons
4,137 liters


?9,000 man-hr

10,340 M gal
4,118,900 H gal


11,390 raan-hr


Dollars/ton
coal burned Ml^l
r
2.91 ;
t, 3.92 S in fuel;
.:o-ir. • n2so4>
Percent jf
Total annjul total d'rect
I'nlt cost, $ cost^ 5 oi>«ratlrr cost

155.00/ton
2 j.SiVton
1.65/litcr


11.75/man-hr

0.30/M gal
0.05/M gal.

•<•
15.00/man-hr



.321,600
34,600
6,800
36i,000
•"•
458.300

3.102.0T.O
205,900

1,971,800
1 70^900
5,908,900
6,271,900
Cents/million Dollars
p/kWi Btu heat

.36 13.
input sulfur, r

48 . 89.

5.13
0.55
O.li
5.79

7.31
-
49.46
" 3.28

31.44
2.72
•94.21
100.00 j~
tr.n
i-r.aved

85
a.  Basis:
     life of power plar.t, 30 yr. at 65% capacity or 5694 hrs/yr.
     Coal burned 2,156,550 tons/yr, 9404 Btu/kV.1i {gross).
     Stack gas reheat to 175°F.
     Direct investment, 532,£99, "X)!).
     Investment and operatinj cost for removal and disposal of fly ash excluded.
     Stean required froa povcr plant, 967,980 M Ib (620"F, 130.3 psig).
     Sttam credit to power plant, 42,840 Ib (366°F, 165 psig).
b.  Set electricity generated:
     Steam cycle output
     less:  Scrubber                           8.2
            ID fan                             8.8
            Other (from EGAS Phase II, p. 72) 55.7
     Total auxiliary losses
     Kct output
868.6 KW

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D.  ALTERNATIVE DISPOSAL METHODS

     Alternative solids disposal methods wore considered for the CWS, AFB,
and PFB plants.  The AFB and PFB plants were desip,ned under EGAS premises
which provided only for facilities to haul all solid wastes offsite.  The
CWS plants costs included a pond for 5-year storage of sludge.   To place
the three plants on a more comparable basis, capital and O&M costs were
examined for alternative methods for 30-year disposal.


Scrubber Sludge

     Fling, et al.,—  compares three sludge fixation systems:   Chemfix,
Dravo, and IUCS.  In the present study, the Drnvo process has been selected
for estimating the cost of sludge fixation because Fling reports Chemfix
is more expensive and IUCS requires fly ash.  The following methods of
disposal were considered for cost estimation:

          1.  Store untreated in clay-lined pond.

              The spent scrubber slurry is pumped to a clay-lined
              settling pond located one mile from the power plant.
              The supernatant is recycled to the scrubbing area.
              It was assumed that the sludge would settle to
              40 percent solids.

         2a.  Store ''ixed in clay-lined pond.

              Spent slurry id concentrated to about 32-38 percent
              solids in a thickener, then mixed with a fixing agent.
              The sli^jge is then pumped to .1 settling pond where
              it settles to about A3 percent solids and cures under
              water.  The supernatant is recycled to the scrubbing
              area.  This design is based on the system that Dravo
              is installing for Pennsylvania Power Company's Bruce-
              Mansfield station.  The cost per ton of scrubber
              sl-irry solids is significantly higher, primarily
              because the disposal pond is more expensive than
              damming a ravine.

         2b.  Fix, store onsite in clay-lined diked impoundment.

              Spent slurry is concentrated to about 32-38 percent
              solids in a thickener, then mixed with a fixing
              agent.  The sludge IB pumped to one of three 30-day
              capacity settling ponds.  The sludge settles to about
              40 percent solids and cures in 30 days.  The super-
              natant is drained from the pond and the fixed sludge
              is dredged and conveyed to a diked impoundment.  A
              collecting basin is included in the diked impoundment
              to catch any runoff.  The fixed sludge is piled to an
              average depth of 30 ft.


                                  305

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          3.  Haul offsite, store fixed in clay-lined diked impoundment

              This is similar to the previous case, 2b.,  except
              the conveyor is eliminated and instead the  fixed
              solids are trucked offsite to the impoundment.

The cost estimates for these waste disposal systems arc shown in  Table 122.


Fluidized Bed Combustion Solid Wastes

     General Electrici' states that the fluidized bed combustion  solid wastes
have the following components:

          a.  Atmospheric fluidized bed.
              42% calcium sulfate
              31% ash
              24% unreacted linie
               3% carbon

          b.  Pressurized fluidized bed
              42% ash
              26% calcium sulfate         *
              16% magnesium oxide                          :
              13% unreacted lime        ,».                 ,
               4% unburned carbon                                     *~

     The costs for disposinp of these wastes are not included in  the GE study.
In making an objective evaluation of fluidized bed combustion the disposal
costs must  be considered.  The following three methods have  been  identified as
viable options in disposing of AFB and FFB wastes:

          1.  Store untreated in clay-lined pond.

              The solids are slurried ?nd sluiced to a clay-lined pond
              where the solids are allowed to settle and  the supernatant
              is recycled.  The solids as received are water free.  When
              they are slurried, some of the constituents will take on
              water of hydration.  It was assumed that after hydrating,
              the sludge fron the atmospheric fluidized bed  process
              would settle to 45 percent solids and the sludge from
              the pressr.rizec. fluidized bed process woult* settle  to
              43 percent solids.

          2.  Store onsite, treated in clay-lined diked impoundment.

              The solids are transported to the disposal  sire with a
              mile-long enclosed conveyor.  Tr  fix this material  all
              that is needed is a moderat-. f i nrt (10 kWh/ton) and
              addition of water (10 percent _•>  weight).  The lime
              present should earner.* .he. solids into a dense  concrete-
              like material.  A clay-lined diked impoundment with a
              collection basin to catch any runoff is included

                    A         o    306

-------
              al'-hough the need for  an  impoundment is questionable.
              The treated solids are piled to an average depth of
              30 ft.

          3.  Haul offsite, store treated in clay-lined diked
              impoundment.
        /
              This is similar to the previous case except the conveyor
              is eliminated and instead the solids are trucked offsite
              to the impoundment.

The cost estimates for these waste disposal systems are shown along with the
CWS disposal systems in Table 122.
                                   307

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E.  COST OF ELECTRICITY (C.O.E.) BASED ON TVA MODIFICATIONS

     The GE study modifications suggested by TVA may be  used to calculate the
C.O.E. associated with the plant types studied.   The C.O.E. for the PFB and
AFB plants reflect the increase in capital costs due to  uncertainty allowances
in equipment estimates and to solids disposal costs.  The C.O.E. for different
CWS .alternatives reflects similar influences with additional sensitivity to
the type of wet scrubber used.

     The GE study cost estimates included capital and O&M charges for a lime
slurry scrubber with onsite calcination.  To determine the sensitivity of
the CWS plants to the alternative scrubber cases, it  is  necessary to substi-
tute the TVA scrubber estimates for the costs estimated  for the GE scrubber.
Table 123 is a calculation breakdown of alternative  scrubber costs.  Utiliza-
tion of these results with the TVA modifications previously discussed yield
the breakdown as seen in Table 124.  The GE plane costs  are identical tc
those presented in the GE study with no TVA modifications.  The 1VA alterna-
tive scrubber estimates shown include TVA modifications  to the GE conventional
plant and reflect both capital and O&M differences due to the different scrubber
types.

     The C.O.E. for the AFB and PFB plants includes differences in solids
disposal requirements.  Table 125 presents calculations  for both onsite and
offsite disposal costs for tha two plant types.   The  result of these, calcula-
tions incorporated with estimates discussed in previous  sections yields the
C.O.E. calculations found in Table 126.  Both the GE  study estimates and
those estimates as modified by TVA include the additional solids disposal
requirements to calculate C.O.E. for the AFB and PFB  plant types.

     Combination of the results found in Tables  123 through 126 yields Table
127.  Table 127 gives a C.O.E. breakdown for the plants  utilizing both the GE
and the TVA estimates.  All estimates in Table 127 incorporate solids disposal
costs.  Changes in the C.O.E. calculated by GE for the CVS, AFR, and PFR are
reflected in the capital and O&M requirements, but not in fuel requitements
as no change in plant efficiency resulted from TVA modifications.


Cost of Electricity Sensitivity

     The costs of electricity presented in Table 127  are based on the guide-
lines set forth in EGAS.  Certain parameters were selected to reflect utility
practice.  Among these parameters are cost of fuel, fixed charge rate, and
capacity factor.  The costs of electricity for all power plants are sensitive
to changes in these parameters.  The cost of fuel was assumed to be $1.00/
106Btu.  Variations in this parameter directly affect the fuel portion of
C.O.E.  The capacity factor was set at 65 percent.  This is reasonable but
actual utility practice may find the capacity factor  much different, changing
both the O&M and capital portions of C.O.E.  The fixed charge rate, set at
18 percent per year, also varies within the utility industry and relates
directly to the capital portion of C.O.E.

     The C.O.E. for CWS, AFB, and PFB are all affected by the parameter
changes mentioned.  Representative plant estimates as modified by TVA were

                                  309
                                                     Preceding page blank

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                         Table 122

SOLIDS DISPOSAL D KECT INVESTMENT AXD:OPERATING COSTS3
                           Direct Investment   Cost of     Annual direct     Dry solid'
                           excluding land,  S   land, $   oper.it ins costs, S   . ton; -'hr
I.












II.














a.
Fluldir.ed bed combustion
A. Atmospheric fluidized bed combustion
1. Store untreated in 'clay-lined pond
2. Store onslte, treated in clay-lined,
diked impoundment
*" 3, Haul off site, store treated in clay-
lined diked impoundment
R. Pressurized fluidized bed combustion
1. Store untreated In clay-lined pond
2. Store onsitc treated in clay-lined,
diked Impoundment
3. Haul of. site, store treated in 'clay-
lined, (.iked impoundment
Scrubber sludge
A. Lime vet scrubber
1. Store untreated in clay-lined pond
2. a. Store fixed in clay-lined"" pond
b. Fix, store onsite Jn clay-lined,
diked impoundment
3. Fix, haul offsite, store in clay-
lliic-it, diked impoundment
B. Limestone wet scrubber
1. Store untreated In clay-lined pond
2. a. Store fixed in -clay-1 ined pond
b. Fix. itore, onsite in clay-lined,
diked impoundment
3. Fix, haul offsite, store in clay-
lined, diked impoundment
Basis:
Ke« coal-fired power unit, onstream time 5694


IU.545,000

3,785,000

2,686,000

17,673,000

4,612,400

3,420,000

.-. ! -*•*
8,097,000
8,969,000
-,•*•
5,322,000

4,364,000
A -
10,156,000
11. 156,001

6,722,900

5,694,400


3,348,400

1,104,000

1,114,000

4,101,000 .: .
"*•
1,425,000

1,425,000


1,806,000
1, 806,000
*•
1,359,001

1,359,000

2,104,000
2,304,000

1,845,900-

1,845,900


983.400

1,191,200

1,729,600

1,157,600

1,524,900

2,174,500


564.100
2,149.400

2,010.400C
•>• (^
2,294,900

694,700 •
2,840;900
X
2,727.100
ft
3.131.000


119

11?

11?

1.54

154

.154


5-1.6
•• 54.6

54.6

54.6

74.9
74.9

74; 9

74.9
hr/yr 1975, operating costs.
3.9? S in fuel, S02 emitted <1.2 lb/106 Btu heat input.
b.






c.
A.
Dry solids composition:
I. A. Atmospheric I.B. Pressurized
42Z CaSOu «* Ash
31* Ash 267. CaSO,,
24% CaO 16? MgO
3Z C 13Z CaO
«Z C
Included is raw material costing SI ,078,800/yr.
Included is raw material costing Sl,478,700/yr.

II. A. Lime
76% CaS03
18% CaSO^
5X CaO


•1/2 H^O
•2 H20'

1% Insolubles







U.K. Limestone
46i CaSOi-
26Z CaSCV
261 CaCOj


1/2 R. •
2 H;0'

2Z Insolubles






                       310a

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                                                       Table 123

                                     ALTERNATE SCRUBBER COSTS  (EXCLUDING DISPOSAL)
CAPITAL AND O&M COSTS,FOR SCRUBBER ALTERNATIVES
	(NO DISPOSAL COSTS ARE INCLUDED)	
    LIME WITH
ONSITE CALCINATION
     LIME WITH
OFFSITE CALCINATION
CAPITAL COSTS ($M)                       ..
          Direct investment  for  scrubber
          Less direct investment for disposal
          Less land costs for disposal(b)
          Net scrubber directs
          Indirect  field costs @ 25%
          Total direct construction
          A&E (? 15%
          Contingency @ 20%
          Total 1975 1/2 Cost ($M)

O&M COSTS (MILLS/kWh)
          Direct operating costs
          Direct nonfixed disposal costs
          Net O&M directs
          Overhead @ 50%
          Total O&M
                                             (b)
                                                          36.57
                                                           5.49
                                                           R. 41
                                                          50.47
                           27.85
                            4.18
                            6.41
                           38.44
                                                                                 1.31
                                                                                -0.12
                                                                                                LIMESTONE
                                             36.75
                                            -10.16
                                             -2.30
                                                           1.60
                                             0.94
                                             -Q.15
                                             0.69
                                             0.34
                                             1.03
   MAGNESIA
W/REGENERATIOB
                                       9.46
                                      56.75
                                       2.07*
 *Sale  of  sulfuric acid would yield additional credit of 1.18 mill/kWh.

 (a)  From Table 112.
 (b)  From Table 122.
 o
 cr

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                                                                        UaMe 124

                                                             CONVENTIONAL/WET SCRUBBER PLAMTS
CAPITAL
  CE
  TVA (1975)  '
  CE Scrubber & Disp.
  TVA Scrubber^)
  TVA Disposal

  Total 1975
  ESC & I.D.C.
  Total 1980  (SM)
  Cast/Ml (S/kW)
Total Capital

CE CWS
250 F/LIME
5 YR. DISPOSAL
8 FT/SEC
747.2 MU
331.7

71.6


403.3
221.0
624.3
835.4

CE CWS
175 F/LIME
5 YR, DISPOSAL
8 FT/ SEC
795.5 HH
334.0

62.4


396.4
217.2
613.5
771.3

TVA CMS
175 F/LIKE
30 YR. DISPOSAL
12.5 FT/SEC
W/CALCINATION

398.03
-62.40
50.47
15.91
402.0
220.3
622.3
782.3
TVA CBS
175 F/LIME
30 YR. DISPOSAL
12.5 FT/SEC
OFFSITE
CALCINATION

398.03
-62.40
38.45
' 15.91
390.0
213.7
603.7
758.9


TVA CWS
175 F/L1MF.STOME
30 YR. DISPOSAL
12.5 FT/SEC

398.03
-62.40
41.89
20.18
397.7
217.9
615.6
771.9

TVA CWS
175 F/MRO
REfiEKERABLE 12.5 Fl/SEC
W/H,SO, CREDIT
£, **

398.03
-62.40
56.75
0.00
392.4
215.0
607.4
763.6

TVA rws
175 F/MfcO
REGENERABLE 12.5 FT/SEC
NO H,S04 CREDIT
•

398.03
-62.40
56.75
0.00
391.4
215.0
607.4
736.6
                              26.40
                                              24.38
                                                               24.73
                                                                               23.99
                                                                                                24.47
                                                                                                                     24.15
                                                                               24.15
04M
  GE
  CE Scrubber
  TVA Scrubber
  TVA IH3pos.il
 Total O&M
                               2.61
                               2.61
                                               2.45
                                               2.45
 2.45
-0.97
 1.60
 0.66

 3.74
 2.45
-0.97
 1.78
 0.66

 3.92
 2.45
-0.97
 1.03
 C.90

 3.41
 2.45
-0.97
 0.89
 0.00

 2.37
 2.45
-0.97
 2.07
 0.00

 3.55
 FUEL
 •n    *  v,,f*
 Total  FUEL
                              10.10
                                              10.10
                                                               10.10
                                                                               10.10
                                 10.10
                                                                                                                    10.10
                                                                                                                                             10.10
 C.O.E._
                              39.83
                                              36.93
                                                               38.57
                                                                               38.00
                                                                                                37.99
                                                                                                                    36.62
                                                                                                                                             37.80
 (a)   rxchitii-n  scrubber  and dinpo>,al cone.
 (t>)   Includes  GE'a  scrubber and disposal cost.
 (c)   CE estimate  of  tin* scrubber and '. /ear disposal cost.
 (d)   Fron Table 123.

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                                               table 125
                                                                      AFB
PFB
      SOLIDS DISPOSAL COSTS FOR FLUIDIZED BED
  COMBUSTION PLANTS (ADDITIONAL TO GE  ESTIMATES)

  CAPITAL COSTS ($M)
            Direct investment
            Indirect field expense @ 90%
            Land
            Total direct construction
            A&E @ 15%
©           Contingency @ 20%
            Total 1975 1/2 cost ($M)
  O&M COSTS
            Direct operating costs
            Overheads @ 50%
            Total operating costs
ONSITE
3.78
3.41
1.10
8.29
1.24
1.91
11.44
0.26
0.13
0.39
OFFSITE
2.69
2.42
1.10
6.21
0.93
1.41
8.57
0.37
0.18
0.55
OMSITE
4.61
4.15
1.43
10.19
1.53
2.34
14.06
0.30
0.15
0.45
OFF SITE
3.42
3.08
1.42
7.92
1.19
1.82
10.93
0.42
0.21
0.63

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                                                   Table 126
     FLUIDIZED BED COMBUSTION POWERPLANTS
     TOTAL COST OF ELECTRICITY (C.O.E.)
      (INCLUDING SOLIDS DISPOSAL COSTS)
     CAPITAL
                Powerplant cost
                Disposal cost
                Total 1975 cost
                ESC & I.D.C.
                Total 1981 cost  ($M)
                Cost/kW  ($/kW)
                 Capital C.O.E. (

           AFB

    GE             TVA
                                                                                              PFB
                                          TVA
ON
332.5
11.4*
343.9
188.5
5 32. A
654.0
OFF
332.5
8.6*
341.1
186.8
527. C
648.5
ON
363.1
11.4
374.5
205.3
579.9
.712.4
OFF
363.1
8.6
371.7
203.3
575.0
.706.4
ON
421.0
14.1
435.1
238.4
673.5
745.0
OFF
421.0
10.9
431.9
236.7
668.6
739.6
ON
479.5
14.1
493.5
270.4
793.9
845.1
OFF
479.5
10.9
490.4
268.73
759.1
839.7
20.67   20.50   22.52    22.33   23.55   23.38    26.72    26.55
CO
I-1
to
      O&M
                 Plant  O&M
                 Disposal
                 O&M C.O.E.  (;
(GE)

 .Mills,
                             kWh
 2.22
 0.39
 2.61
2.22
0.55
2.77
2.22
0.39
2.61
2.22
0.55
2.77
2.53
0.45
2,98
2.53
0.63
3.16
                                                                                     2.53
                                                                                     0.45
                                                                                     2.98
2.53
0.63
3.16
      FUEL
FUEL C.O.E.
                             .Hills.
                             * kWh  '
 9.53
9.53    9.53
        9.53
        8.71
        8.71
        8.71
                                                        8.71
      *From TVA estimates.

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                                                         Table  127

                              COMPARISONS OF COSTS CONSIDERING  VARIOUS TYPES OF  SCRUBBERS AND
                                             ALTERNATE METHODS  OF WASTE DISPOSAL
u>
cr
                                                                TOTAL CAPITAL
                                                                     $/kW

Conventional With Scrubber

     GE/CWS/250F/5 yr. disp./lime w/calcination/747 KW               835.4
     GE/CWS/175F/5 yr. disp./lime w/calcination/795 MW               771.3
     TVA/CWS/175/30 yr. disp./lime w/calcination/795 MW      •        782.3
     TVA/CWS/175F/30 yr. disp./lime (purchased)/795 MW               753,9
     TVA/CWS/175F/30 yr. disp./limestone/795 MW                      773.9
     TVA/CWS/175F/MgO/Regenerable/795 MW W/l^SO^  credit              728.0
     TVA/CWS/175F/MgO/Regenerable/795 MW NO H2S04 credit              728.0


Fluidized Bed Power Plants

     GE/AFB/onsite disposal (30 yr.)  814 MW                          654.0
     GE/AFB/offsite disposal (30 yr.) 814 MW                         648.5
     GE/PFB/onsite disposal (30 yr.)  904 MW                          745.0
     GE/PFB/offsite disposal (30 yr.) 904 MW                         739.6
     TVA/AFB/uncertainties added/onsite disposal  (30 yr.) 814 MW      712.4
     TVA/AFB/uncertainties added/offsite disposal (30  yr.) 814 MW     706.4
     TVA/PFB/uncertainties added/onsite disposal  (30 yr.) 904 MW      845.1
     TVA/PFB/uncertainties added/offsite disposal (30  yr.) 904 MW     839.7
     GE/AFB/no disposal/Si^ MW                                       632
     GE/PFE/no disposal/9Ck MW                                        723
                                                                                           COST OF ELECTRICITY (Mills/kWhJ

                                                                                      CAPITAL      O&M     FUEL     TOTAL
26.40
24.38
24.73
23.99
24.47
23.01
2.3.01
2.61
2.45
3.74
3.92
3.41
2.37
3.55
10.73
10.10
10.10
10.10
10.10
10.10
10.1 ;
39.83
36.93
38.57
38,00
37.99
35.48
36.66
20.67
20.50
23.55
23.38
22.52
22.3'J
26.72
26.55
20.00
22.90
2.61
2.77
2.98
3.16
2.61
2.77
2.98
3.16
9.50
8.70
9.53
9.53
8.71
8.71
9.53
9.53
8.71
8.71
2.20
2.50
32.81
32.80
35.24
35.25
34.66
34.63
38.41
38.42
31.7
3^.1

-------
                           '~
used to develop the C.O.E. sensitivity plots as seen in Figures 46 through AS.
These plants are:

          (1)  CWS - CWS with TVA modifications
                     (Lime w/offsite calcination)

          (2)  AFB - AFB with TVA modifications (including solids disposal)

          (3)  PFB - PFB with TVA modifications (including solids disposal)

The sensitivity of C.O.E. to cost of fuel is seen in Figure 46.  The attractive-
ness of PFB is seen to  increase with rising fuel costs due to  its higher
efficiency.  Figure 47  shows the sensitivity of" the three plant types to
changes in the fixed charge rate.  Here the PFB becomes less attractive with
increasing fixed charge rate because of its higher capital cost.  Changes in
capacity factor affect  C.O.E. as shown in Figure 48.  Increasing the
capacity factor makes the cost of PFB lower relative to the CWS, again
reflecting higher PFB efficiency.

      In all three plots of C.O.E. sensitivity, the AFB shows lower C.O.E.
than  the CWS and PFB.
                                   §14

-------
    80J.
    40
.as
>%
V,
lu
q
6
2 30.
    35.

                            4-
                                                     PFB
                                                    AFB
                                                   EC. RATE =18%

                                                   CAR FAC. =.65
                .90         1.00        1.50       2.00

                 COST  OF  FUEL   (S/IO6 Btu)
2.50
        Figure 46.  Effect of Fuel Cost on Total Cost of
                   Electricity
                               315

-------
  49..
   40.,
3
uj
o
d
39..
o   ••
   30..
                                        RC.RATE« 18%
                                        FUEL COST*$l.OO/lO* Btu
                                                 PWS
                                                AFB

                           -f-
                                              -f-
               .50
                       .60         .70        .80
                       CAPACITY FACTOR
        Figure 47.  Effect of Capacity  Factor on Total Cost
                   of Electricity
                             316

-------
   454.
                                             PFE
   40..
CO
2
  30..
                                                 AFB
                                    FUEL COST =31.00/10* Btu
                                    CARFAC.».65
                                                 -4-
                12          13          tS         21
                     FIXED  CHARGE  RATE  (%)
         Figure 48.  Effect of Fixed Charge Rate  on Total Cost
                    of Electricity
                               o
                             317

-------
                                  References
1.  General Electric Company.  "Study of Advanced Steam Cycles for Utility
    Application."  Oral briefing, March 24, 1976, updated April 8, 1976,
    Knoxville, Tennessee.

2.  McGiamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson,
    L. J. Henson, S. V. Tomlinson, and J. F. Young.  "Detailed Cost
    Estimates for Advanced Effluent Desuifurization Processes."  Prepared
    for the U.S. Environmental Protection Agency.  TVA Bulletin Y-90,
    January 1975.

3.  Koehler, George, and James A. Burns.  "The Magnesia Scrubbing Process
    as Applied to an Oil-Fired Power Plant."  Prepared for the U.S.
    Environmental Protection Agency.  October 1975.

4.  Fling, 'A. B., W. M. Graven, F. D. Hess, P. P. Leo, R. C. Rossi, and
    J. Rossoff.  "Disposal of Flue Gas Cleaning Wastes:  EPA Shawnee Field
    Evaluation—Initial Report."  Prepared for the U.S. Environmental
    Protection Agency.  March 1976.

5.  Connan, J. C., et al., Energy Conversion Alternatives Study (EGAS),
    General Electric Phase II Final Report, NASA CR-134949, 3 vols., NASA
    Lewis Research Center Contract NAS3-19406, GE Corporate Research and
    Development, Schenectady, N.Y., December 1976.

6.  Beecher, D. T., et al., Energy Conversion Alternatives g'tudy  (FCAP),
    Westinghouse Phase II Final Report, NAL-A CR-13^9^, vol. Ill, KAt'A
  '"'• Lewis -Research Center Contract HAS3-19^06, Westinghouse Electric.
    Corporation, Pittsburgh, PA, November 1976.-
                                      313

-------